Computalog - Drilling Service Fundamentals

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Training CurriculumCRCM_130_revA_0204

Drilling Services FundamentalsDrilling Services Fundamentals

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DRILLING SERVICES FUNDAMENTALS

Petroleum Geology Fundamentals .......................................................Chapter 1

Sedimentary Transport & Depositional Environments ................................................6

Sedimentary Rock Classifications ..........................................................................15

Origin of Hydrocarbons ..........................................................................................20

Hydrocarbon Migration ..........................................................................................24

Hydrocarbon Accumulation ....................................................................................27

Directional Surveying Fundamentals....................................................Chapter 2

Survey Accuracy and Quality Control ...................................................Chapter 3

Directional Drilling Fundamentals .......................................................Chapter 4

Optional Topics...................................................................................Chapter 5

State of the Art in MWD......................................................................Chapter 6

April 2002 Table of Contents

April 2002 Table of Contents

1

PETROLEUM GEOLOGY PRIMERPETROLEUM GEOLOGY PRIMER

Spring 2002

Calgary

Rocks and MineralsRocks and Minerals

• Igneous• Sedimentary• Metamorphic

Two Basic Kinds of TextureTwo Basic Kinds of Texture

• Clastic Texture

• Crystalline Texture

2

The Rock CycleThe Rock Cycle

Igneous RockIgneous Rock

• Igneous rocks are formed from magma. • Two principal types of igneous rock

• Intrusive (plutonic), those that have solidified below the surface

Granite

• Extrusive (volcanic), those that have formed on the surface

Lava

Sedimentary RockSedimentary Rock

• Exposed surface rock is subject to weathering and erosion

• Weathering breaks down the structure• Erosion is the removal of weathered rock

3

Sedimentary RockSedimentary Rock

• Sedimentary rocks cover 75% of the land surface.

• Because sedimentary rocks are capable of containing fluids they are of prime interest to the petroleum geologists

Shale

Metamorphic RockMetamorphic Rock

• Rock changed by pressure and heat• Shale can become slate

• Limestone can become marble

• Metamorphism results in a crystalline texture which has little or no porosity.

• About 27% of the earth’s crust is composed of metamorphic rocks.

Sedimentary Transport & Depositional Environments

Sedimentary Transport & Depositional Environments

4

Sedimentary TransportSedimentary Transport

• Gravity works through water, wind, or ice• A river flows sediments downstream while

undercutting its banks• Tectonic forces raise lowlands above sea level,

ensuring a continuing supply of exposed rock for producing sediments

• Gravity ultimately pulls sediments to sea level

Mass MovementMass Movement

• In high elevations • Severe weathering • Instability of steep slopes

• A large block of bedrockmay separate along deepfractures or bedding planes• Rockslide or avalanche

Stream TransportStream Transport

• The distance a sedimentary particle can be carried depends on:• Available stream energy• Size• Shape• Density

5

Continental EnvironmentsContinental Environments

• Fluvial deposits• Desert environment

Continental EnvironmentsContinental Environments

• Glacial deposits• Aeolian deposits

Transitional EnvironmentsTransitional Environments• Marine deltas

• Beaches

6

Sedimentary Rock Classifications Sedimentary Rock Classifications

Sedimentary Rock ClassificationsSedimentary Rock Classifications

• Lithification• Deposited beyond the reach of erosion• Diagenesis (physical and chemical changes)

• Compaction• Sediments accumulate over time in the ocean• Weight is increased by thousands of feet of more sediment

layers• Pore space is reduced as water is squeezed out

• Cementation• The crystallization or precipitation of soluble minerals in the

pore spaces between clastic particles.

ClasticsClastics

• Conglomerates

• Sandstones

• Shales

7

EvaporitesEvaporites

• Gypsum

• Halite

CarbonatesCarbonates

• Limestone

• Coal

• Chert

Origin of Hydrocarbons Origin of Hydrocarbons

utalog

8

HydrocarbonsHydrocarbons

• Originally oil seemed to come from solid rock deep beneath the surface

• Scientists showed oil-rocks were once loose sediment piling up in shallow coastal waters

• Advances in microscopy revealed fossilized creatures• Chemists discovered certain complex molecules in

petroleum known to occur only in living cells• That source rocks were shown to originate in an

environment rich with life clinched the “organic theory”

Chemical Composition of AverageCrude Oil & Natural GasChemical Composition of AverageCrude Oil & Natural Gas

ElementElement Crude OilCrude Oil Natural GasNatural Gas

Carbon 82 – 87% 65 – 80%

Hydrogen 12 – 15% 1 – 25%

Sulphur 0.1 – 5.5% 0 – 0.2%

Nitrogen 0.1 – 1.5% 1 – 15%

Oxygen 0.1 – 4.5% 0%

Chemical FactorsChemical Factors

• Petroleum is only slightly soluble in salt water• It floats but is often found in an oil-water emulsion• Some petroleum contains hydrocarbon molecules with

60-70 carbon atoms• Molecules with up to four carbon atoms occur as gases• Molecules having five to fifteen carbon atoms are liquids• Heavier molecules occur as solids

• Methane, the simplest hydrocarbon, has the chemical formula CH4. • Four is the maximum number of hydrogen atoms that can

attach to a single carbon atom

9

Biological FactorsBiological Factors• The food chain contributes waste products, and

every organism that is not eaten eventually dies • Bacteria plays an important role in recycling

• Aerobic (oxygenated) oxidizes organic matter• Anaerobic (reducing) takes oxygen from dissolved sulfates

and organic fatty acids producing sulfides and hydrocarbons

• Aerobic decay liberates certain hydrocarbons that some small organisms accumulate within their bodies, the anaerobics are more important in oil formation

Biological FactorsBiological Factors• Organic waste materials and dead organisms sink to

the bottom, preserved in an anaerobic environment• Accumulation and compaction help seal the organic

matter off from dissolved oxygen • Transformation into petroleum is accomplished by

the heat and pressure of deeper burial• Examples of where anaerobic environments exist:

• Deep offshore• Salt marshes• River deltas• Tidal lagoons

The Petroleum WindowThe Petroleum Window• The set of conditions under

which petroleum will form• Temperatures between

100°F-350°F • The higher the temperature,

the greater the gas proportion • Above 350°F almost all of the

hydrocarbon is changed into methane and graphite

• Source beds (or reservoirs) deeper than about 20,000 feet usually produce only gas

10

Source RocksSource Rocks• Source Rock

• Organic material that has been converted into petroleum

• Reservoir Rock• Rock in which petroleum accumulates

• The best source rocks are shales• Other source beds are limestone, evaporites, and rocks

formed from freshwater sedimentary deposition• Petroleum is found in a variety of forms and chemical

complexities

Hydrocarbon Migration Hydrocarbon Migration

MigrationMigration• Primary migration

• Movement of hydrocarbons out of the source rock

• Secondary migration• Subsequent movement through porous, permeable

reservoir rock by which oil and gas become concentrated in one locality

11

Primary MigrationPrimary Migration

• Involves compaction and the flow of water• Petroleum comes from source beds deposited

mostly on the seafloor• As shale gets compressed into less space, it is

not the solid mineral grains that are compressed but the pore spaces

• Interstitial water is squeezed out, carrying droplets of oil in suspension and other hydrocarbons in solution


• Effective porosity is the ratio of the volume of all the interconnected pores to the total volume of a rock unit

• Only the pores that are connected with other pores are capable of accumulating petroleum

• Effective porosity depends upon how the rock particles were deposited and cemented


• A rock's permeability is a measure of how easily fluids can pass through it

• The basic unit is the Darcy; l/1000 of a Darcy is a millidarcy (md)

• The permeability of sandstones commonly ranges between 0.01 and 10,000 md. 100-1000 md

10-100 md1-10 md<1 md

Very GoodGoodFairPoor

12

PermeabilityPermeability• Permeability can vary with direction of flow• Pore connections may be less numerous, narrower, or less

well aligned in one direction than another• In rocks formed from well-sorted beach sands, grains that

are not spherical are often aligned perpendicular to the beach

• Stream channel sands are aligned in the direction of stream flow and often contain horizontal sheets or stringers of less permeable clay

• Fluids move more easily through such rocks parallel to grain alignment or clay stringers than across them

Secondary MigrationSecondary Migration• Hydrocarbons are moved through permeable

rock by gravity• Compressing pore spaces containing fluid • Causing water containing hydrocarbons to flow • Causing water to displace less dense petroleum

fluids upward

• Flow can mean movement of a few inches a year, which can add up to many miles in a geologically short time

Hydrocarbon Accumulation Hydrocarbon Accumulation

13

AccumulationAccumulation• Oil collects in places it cannot readily flow out of

• a structural high point • a zone of reduced permeability

• As accumulation occurs, distinct zones of gas, oil, and water appear

Effective PermeabilityEffective Permeability• Rock permeability to a given fluid when

another fluid is also present• Water has seven times the ability of oil to cling

to the grains of porous rock• Interstitial water reduces the space available

for oil• narrows the passages between pores• lowers the rock's effective permeability to oil

Relative PermeabilityRelative Permeability• The ratio of effective to absolute permeability

• 1.0 = rock with oil but no water • 0.0 = rock with water but no oil

• Encountering higher fluid pressure • may overcome the water's resistance to the passage

of oil • may increase the effective permeability of the

formation by opening tiny fractures

14

Horizontal MovementHorizontal Movement• Interstitial water with oil droplets moves slowly

through horizontal sandstone beneath a layer of relatively impermeable shale

• The oil droplets tend to concentrate in the upper levels of the sandstone because of their buoyancy

Diagonal MovementDiagonal Movement• If the tilt is upward in the direction of flow

• The oil tends to rise updip with the flow of water

• If the oil rises against the flow of water• The water flows downdip

Movement Within an AnticlineMovement Within an Anticline• Water flows updip into the anticline, then downdip• Oil rises with the incoming water and moves

preferentially toward the crest• Concentration is near the highest point • To accumulate oil, the anticline must be closed

• Plunge in both directions along its axis• Dip toward both flanks

15

Differentiation Differentiation • Petroleum reservoirs are water-wet

• Oil is not in contact with the rock grains because they are coated with a film of water

• Most oil fields have 50-80% maximum oil saturation

• Above 80%, the oil can be produced with very little water mixed in

• Below 10%, the oil is not recoverable

Hydrocarbon Reservoirs Hydrocarbon Reservoirs • Hydrocarbon reservoirs divide into

two or more zones• With oil and water, oil will occupy

the upper zone• This zone has maximum oil saturation• The oil-water contact is not a sharp line

but a transition zone

• Oil saturation increases gradually from near 0% at the base to 50%-80% at the top

Hydrocarbon Reservoirs Hydrocarbon Reservoirs • Natural gas is dissolved in the oil

and to some extent in the water • Reservoir conditions sometimes

allow undissolved gas to create a gas cap above the oil zone

• The wetting fluid in a gas cap is usually water but occasionally oil

• The transition zone between oil-gas is thinner than the oil-water

16

Hydrocarbon Reservoirs Hydrocarbon Reservoirs • Some reservoirs contain gas but not oil

• This gas is called non-associated gas• The transition zone is a gas-water contact• The water contains gas in solution

• Free methane remains in a gaseous state even under great pressure

• Ethane, propane, and butane, are gases at the surface are often found in a liquid state under reservoir conditions

Types of TrapsTypes of Traps• The basic requirements for a petroleum reservoir are

• A source of hydrocarbons• Porous and permeable rock enabling migration• Something to arrest the migration and cause accumulation

• Anticlines are not the only geologic situations for hydrocarbon accumulation

• Two major groups of hydrocarbon traps • structural, the result of deformation of the rock strata• stratigraphic, a direct consequence of depositional variations• *hydrodynamic, trapped by the force of moving water

• Most reservoirs have characteristics of multiple types

StructuralStructural• Anticlines

• Created by tectonic deformation of flat and parallel rock strata

• A short anticline plunging in both directions along its strike is classified as a dome

• Faults• Most faults trap oil and gas by

interrupting the lateral continuity of a permeable formation

Anticline Structure

Impermeable Bed

Sealing Fault

17

StratigraphicStratigraphic• Lateral discontinuity or changes in permeability are

difficult to detect• Stratigraphic traps were not studied until after most of the

world's structural oil field discoveries • They still account for only a minor part of the world's

known petroleum reserves

• Stratigraphic traps are unrelated to surface features• Many stratigraphic traps have been discovered

accidentally while drilling structural traps

StratigraphicStratigraphic• Shoestring Sand

• An overlapping series of coarser stream sediments buried by clay

• A sinuous string of sandstone winding through impermeable shales

• Form complex branching networks• Give no hint of the underlying channel• Tracing the course is difficult• Clues such as direction of greatest

permeability and general slope of the buried land surface help find the next productive location

Stream Channel

LensLens• Isolated body of permeable rock enclosed within less

permeable rock • Edges taper out in all directions

• Formed by turbidity underwater slides • Isolated beach or streams sand deposits • Alluvial fans, and other deposits

Lens Traps

18

PinchoutPinchout

• Occurs where a porous and permeable sand body is isolated above, below, and at its updip edge

• Oil or gas migrates updip to the low-permeability zone where the reservoir "pinches out"

PinchoutTraps

Combination TrapsCombination Traps

Timing and Preservation of TrapsTiming and Preservation of Traps

19

ConclusionsConclusions

• The petroleum geologist's job is finding oil and gas that can be produced for commercial profit

• Most of what he needs to know is hidden beneath the surface

• Powerful tools and techniques exist for revealing the secrets of the earth's crust

• To the geologist's trained eye and mind, the same rocks that hide the resource also provide subtle clues about its location


April 2002 1 Chapter 1

PETROLEUM GEOLOGY What comes into your mind when you hear the word geology? If you’re like most of us, chances are you get a vivid picture – such as the May 1980 eruption of Mount St. Helens. We tend to think of geology in terms of landscapes too vast to fully comprehend – volcanoes, mountain ranges, and canyons – created by forces beyond our comprehension.

Perhaps, then, you will be surprised to learn that most geological changes occur so slowly that you cannot see them happening; that our understanding of those changes has enabled us to find the fossil fuels that power our civilization; and that the scope of our insight into the geological phenomenon of oil includes both the large and the small – mountains and sand grains, oceans and water droplets, sunlight and bacteria.

Within this wide range of things and ideas, the story of how, where, and when petroleum accumulates underground can be made very complicated – or very simple. A scientist can describe precisely how heat and pressure affect complex organic molecules, but he may do so in a language hard to understand. The average motorist, on the other hand, may fill up at the gas pump; comfortable with the notion that oil comes from dinosaur-shaped caverns. For those curious about the phenomenon of nature’s liquid fuels but lacking a rigorous scientific education, the simple picture does not satisfy, but the exact answer (insofar as scientists know it) baffles.

Explaining the occurrence of petroleum in rock formations is very similar to explaining why it rains, with one fundamental difference – we can watch clouds forming and rain falling, but no one has ever watched oil form and accumulate underground. To figure out what happens, we must first answer some basic questions: Does oil start out as oil or as something else? Does it change over time? Does it form where it is found, or does it come from somewhere else? Why is it found in some places but not in others? These questions can be answered; but to answer them we have to look at petroleum on many levels – global, regional, local, microscopic, and molecular. In the search for petroleum, the area of greatest interest to us is geology – the science of the earth.

Rocks and Minerals A mineral is a naturally occurring inorganic crystalline element or compound. Although some rocks, such as rock salt, are made up of grains of a single mineral, most rocks are assemblages of different minerals. A mineral has a definite chemical composition and characteristic physical properties such as crystal shape, melting point, color, and hardness. However, most minerals, as found in rocks, are not pure. Quartz, a form of silica, has a definite chemical


formula (SiO2), but usually contains impurities that give it color. Feldspar, on the other hand, includes within its chemical range a wide variety of potassium, sodium, and calcium aluminum silicates. One common variety is orthoclase, which is mostly KAlSi3O8. Varieties of feldspar make up about half the rocks of the earth’s surface.

If you examine a typical rock, you will see that it is composed of individual mineral grains of various types. In some rocks the grains are so small that they can be seen only under a microscope; in others, they are quite large. Texture, the size and arrangement of these mineral particles, is one of the principal descriptive properties geologists use to classify rocks.

Two basic kinds of texture are crystalline and clastic. In rocks with clastic texture, the grains, which are broken fragments of rocks, minerals, or organic debris, may touch each other but are mostly surrounded and held together by cement such as calcite. Often the spaces between the grains are not completely filled, leaving openings or voids that can contain water or other fluids. In crystalline texture, the grains form and grow from the molten rock material as it solidifies, and so they interlock or touch each other on all faces. Minerals can also crystallize from ground water solutions within existing rocks. Rocks with crystalline texture usually have very low porosity.

Clastic Texture Crystalline Texture

Primary rock classification is by origin: igneous, sedimentary, and metamorphic. Rock in any one of these categories can be transformed by natural processes into its counterpart in another category. The relationships of these rock types and processes are shown as the Rock Cycle


Igneous Rock Igneous rocks are those formed directly from molten rock material, or magma. When the planet was formed, the original crust was entirely igneous; today the percentage is 65%. Two principal types of igneous rock are intrusive (plutonic), those that have solidified below the surface, and extrusive (volcanic), those that have formed on the surface. Granite, the most common intrusive igneous rock, has crystals that are easily seen by the unaided eye. Magma that reaches the surface is called lava; extrusive igneous rock is hardened lava from volcanic eruptions. Because it has lost its heat rapidly to the atmosphere, its grains are usually smaller than those of intrusive rock and may be visible only under magnification.

Lava Granite

Some lava cools so rapidly that it does not form crystals at all; the result is a volcanic glass known as obsidian. Another common extrusive rock is basalt. Since igneous rocks form from a cooling body of magma or lava, they are usually crystalline and non-porous. However, pyroclastics, composed of fragments of ash from volcanic explosions, have clastic texture and are porous. Gas-filled lava that has cooled rapidly may form a vesicular type of obsidian called pumice, the rock that floats on water.

Obsidian Pumice

Sedimentary Rock When any type of rock is exposed at the surface, it becomes subject to weathering and erosion. Weathering processes are those that break down the structure of the rock by chemical and physical attack. Erosion is the removal of weathered rock or soil particles by flowing water, wind, moving ice, or other agents. When weathering has proceeded far enough, the erosion process may complete the job of separating the particles from the parent rock.

The rock and soil particles carried away by erosion eventually come to rest in a sedimentary deposit, often far from their source. The largest and heaviest particles, requiring the most energy to transport,

Cooling Hardening


are the first to settle out, followed by particles of decreasing size. As a result, fine silt and clay particles are carried farthest from their origin and deposited where the moving water loses the last of its flow energy. Eroded particles may eventually be consolidated as sedimentary rocks.

Although they comprise only 8% of the volume of the earth’s crust, sedimentary rocks cover 75% of the land surface. Most sedimentary rocks are porous and therefore capable of containing fluids. The fact that most petroleum accumulates in sedimentary rocks makes them of prime interest to the petroleum geologists.

Sedimentary Rocks Shale

Metamorphic Rock Any rock that has been changed by pressure and heat while in the solid phase is termed metamorphic. When shale, a common sedimentary rock, undergoes deep burial, heat and pressure fuse individual mineral grains into a metamorphic rock known as slate; more intense metamorphism produces schist. Similarly, limestone becomes marble. One type of low-grade metamorphism, the alteration of limestone to dolomite, involves chemical replacement of calcium by magnesium in solution.

Metamorphism always results in crystalline texture; either new crystals are formed from the elements present in the original rock, or the existing grains are deformed and molded into an interlocking structure. Metamorphic rocks usually have little or no porosity. The final form and appearance of any metamorphic rock is a product of its original composition and the type and intensity of the metamorphic forces involved. About 27% of the earth’s crust is composed of metamorphic rocks.


Metamorphic Rock

It is the crust, of course, that most concerns us as human beings and as finders and users of oil and gas. The crust is different from the molten interior of the earth; it is the cool skin where life exists. Its heights are worn down by the constant wash of weather; its basins are with water and rock particles and the remains of once-living organisms. In the search for oil, the petroleum geologist concentrates on these basins, where sediments and organic matter accumulate in a sort of giant pressure cooker.


SEDIMENTARY TRANSPORT & DEPOSITIONAL ENVIRONMENTS

Sedimentary Transport Gravity causes sediments to move from high places to low. Sometimes gravity is the only agent involved, as in a landslide. More often, however, gravity works through another medium - water, wind, or ice - to transport sedimentary particles from one location to another.

The flow of a river moves the sediments in its bed downstream, but it also undercuts its banks. When material is continually removed from the lower part of a slope, the slope eventually becomes too steep to support its own weight. It collapses, either gradually or suddenly, into the streambed and is carried away. Thus, although the stream acts directly only on the sediments in its bed, the valley becomes wider at the top because of undercutting.

The inexorable pull of gravity ensures that sediments are carried downhill - ultimately to sea level. However, tectonic forces often raise lowlands high above sea level, ensuring a continuing supply of raw material for producing sediments. Thus any type of rock can become source material for future sedimentary rocks by being uplifted and exposed to weathering and erosion.

Mass Movement In high mountains, severe weathering and the instability of steep slopes often result in the sudden movement of large masses of rock and sediment. A large block of bedrock may separate along deep fractures or bedding planes, causing a rockslide or avalanche. In seconds, a single rock mass weighing millions of tons can come crashing down, shattering itself and everything it hits into boulders and dust.

Even though gravity is the principal agent in mass movement, water plays a key part. Besides the destructive effects of repeated freezing and thawing, water adds mobility to weathered rock debris, making it respond more readily to the pull of gravity. Excess water makes clay especially unstable. Under prolonged soaking by rainfall, a clay hillside may suddenly slump.

Rock & Snow Avalanche, Mt. Huascaran, Peru

Did You Know? In 1970, an earthquake-induced rock and snow avalanche on Mt. Huascaran, Peru, buried the towns of Yungay and Ranrahirca. The total death toll was 66,000. The avalanche started as a sliding mass of glacial ice and rock about 3,000 feet wide and one mile long. The avalanche swept about 11 miles to the village of Yungay at an average speed of more that 100 miles an hour. The fast-moving mass picked up glacial deposits and by the time it reached Yungay, it is estimated to have consisted of about 80 million cubic yards of water, mud, and rocks.


Stream Transport Most sediments, even those involved in mass movement, are at some time transported by flowing water. The distance a sedimentary particle is carried depends both upon the size, shape, and density of the particle and upon the available stream energy.

The steeper a stream, the more gravitational energy it has - and the faster it flows. If the water flows smoothly, like a formation of marching soldiers, the flow is said to be laminar. However, if this orderly, parallel movement is disrupted, the flow becomes turbulent, tumbling and swirling chaotically. Such a change can be seen where a quiet stretch of river enters a section of shallow, uneven streambed and breaks into turbulent rapids.

It is this turbulent type of flow that makes available most of the energy a stream uses in transporting solid particles. Some of the swirling is directed upward with enough energy to pick up and carry rock particles that are heavier than the water -the same way a high wind can pluck a sheet of tin off a roof. In general, the turbulence of a stream increases with its velocity and with the narrowness and roughness of its channel. Steep, narrow mountain streams have a greater proportion of turbulent energy than sluggish lowland streams, so they are noisier.

Some sedimentary particles are more easily picked up and carried than others. Density is important, of course, but less so than size and shape. All else being equal, a large particle will settle out of still water faster than a small particle. The frictional force that resists the particle's fall (and supports it in moving water) acts only on the surface of the particle; the smaller the particle, the greater its ratio of surface area to volume and weight. The larger particle, with more weight per unit surface, needs more force per unit surface to move it.

The shape of a particle also affects ease of transport. A perfect sphere has more volume and weight per unit surface than any other shape. The less spherical a particle, the more easily a stream can carry it. A flat pebble of quartz will settle like a leaf; a spherical quartz pebble of equal weight will sink more quickly. The difference in shape is like the difference between an open umbrella and a closed one. Opening an umbrella in a high wind does not change its weight, but does make it more likely to be blown away.

For any given shape and size, a denser particle will settle out faster than a less dense particle because its weight-to-surface ratio is higher. For this reason, small particles of gold (S.G. 16 to 19) collect on the bottom of a streambed, while silt (S.G. 2.5 to 3.0) is swept downstream.

Streams move only minor amounts of sediment. High winds can carry clay, silt, and sand much as a river does. In arid climates, wind may even act as the primary weathering and transporting agent, carving exposed rock into fantastic shapes by abrading it with airborne particles. A glacier moves slowly but with great weight, grinding rocks into powder and carrying jumbles of unsorted rock material to its snout. Both wind-driven and glacial sediments are often reworked and redeposited by flowing water.


DEPOSITIONAL ENVIRONMENTS When sedimentary particles arriving at a location outnumber those being carried away, the location can be thought of as a depositional environment. Depositional environments are of many different types. Wind, waves, temperatures, flow patterns, seasonal variations, and biotic communities are a few of the many factors that influence the character of the sedimentary deposits in a given environment.

Continental Environments Because most areas above sea level are subject to erosion, depositional conditions tend to be more localized onshore than offshore. They are also more affected by rapid changes in weather. At certain places and times a river deposits more sediment in its valley than it carries off. However, the sediments deposited during months of slack water may be carried downstream in a single day of heavy runoff.

Fluvial Deposits Sediments deposited by flowing water are called fluvial deposits. Local variations in flow determine where particular types of sediments accumulate. Stream velocity is greatest on the outside of a bend, where the stream undercuts the bank and increases its sedimentary load. On the inside of the bend, where the water slows and eddies, the stream has less energy. Here is left much of the suspended sediment - first the sand, which takes the most energy to move; then higher on the sloping bar, silt; and farthest from the swift main current, clay. Bed load materials such as cobbles and gravel collect in deeper water near the base of the sand.

A river in flood uses much of its increased energy to augment its suspended load. Adding silt and clay from its channel to the materials coming from upstream, the river spreads out over its floodplain. Here friction absorbs much of the flow energy. Silt and clay settle out, raising the level of the floodplain (and enriching the soil for plant life). Some of the heavier sediments accumulate atop the banks nearest the river, forming natural levees that help contain the river at lower flow stages.

Sandbars and other stream deposits over- lap one another in characteristic ways. A cross section of such overlapping deposits reveals their characteristic lens shape - thick in the middle and tapering toward either edge. Bar deposits are long and curved in the direction parallel to the stream but narrow and lens-shaped in section across the stream. Evidence of flow direction and volume is preserved in the form of ripple marks, scour marks, and other structures.

A meandering river creates an even more complex system of overlapping and undercut deposits. Meandering occurs when a river with excess energy and a flat floodplain erodes one of its banks more than the other and begins shifting in a gentle curve toward that bank. Since a curved line connecting two points is longer than a straight line, a meander reduces the river's gradient: the river travels farther to descend 1 foot in elevation. As the curve deepens, the opposite bank is eroded at its beginning and end.

With continued erosion and deposition, the meander takes the


form of a narrow-necked loop that the river may eventually erode through to form a cutoff. In the oxbow lake thus formed in the abandoned loop, sediments and life forms differ from those of the river.

Lacustrine Environments The still waters of a lake absorb all the flow energy of inflowing rivers, causing the rivers to deposit their sediments near their entry points. In addition to the inflow of mineral sediments, dissolved nutrients flow in and feed the growth of a biotic community of plants and animals. The remains of these organisms accumulate in the sediments of the lake bottom rather than being flushed downstream as in a river. Eventually the lake fills with sediments and ceases to exist, leaving behind a deposit from which fossil fuels such as coal or oil may be born.

Desert Environments In arid climates, infrequent downpours and flash floods leave sheets of gravel and sand in large, sloping deposits at the mouths of canyons. This type of deposit is called an alluvial fan. Such fanglomerates (some of which are termed molasse) are thin, overlapping, poorly sorted sheets of angular gravels, boulders, and mud. A line of fans may eventually coalesce into an apron that grows broader and higher as the slopes above are eroded.

In enclosed desert basins, scarce runoff may create intermittent playa lakes, also known as sebkhas (or sabkhas). Coarser sediments are deposited around the margins of a sebkha in alluvial fans and aprons; silt and clay are carried into the central parts, where they settle out more slowly. When the water evaporates, dissolved salts crystallize out to form thin crusts of halite (rock salt), gypsum (hydrous calcium sulfate), or other evaporites. A sebkha thus develops a characteristic pattern of alternating thin beds of mud and evaporites.

Glacial Deposits Sediments deposited by moving ice sheets are much rarer than other types, principally because deposits created by geologically infrequent ice ages are subject to erosion and reworking by other agents. Retreating glaciers and ice sheets leave behind accumulations of unsorted sediments called till. Glaciers grind bedrock into flour and carry along great boulders that a river would simply flow around. Glacial till is thus recognizable by its chaotic jumble of mud, gravel, and large rocks. When a glacier retreats, meltwater usually reworks and redistributes the till. Glacial till and outwash sediments from the last ice advance cover much of the north-

eastern United States. Buried sediments from older glacial periods can be found worldwide, often in locations now too far from the poles to have been affected by more recent ice ages.


Aeolian deposits Sediments deposited by wind (aeolian deposits) range from loess (thick beds of silt carried by winds from the outwash plains of glaciers) to sand dunes. Large desert dunes that migrate downwind because of prevailing winds develop a pattern of cross-bedding that may be preserved beneath younger sediments. Examples of cross-bedded dune structure can be seen in canyons of the southwestern United States.

Erosion, Transportation, and Depositional Environments

TRANSITIONAL ENVIRONMENTS Most of the sediment produced by the weathering of rock is carried by flowing water to the sea. Here the fresh water of the river quickly becomes dispersed in the much larger volume of salt water-as does flow energy. Sediments are deposited throughout this transition zone, where the river gradually gives up its energy; they are sorted by size, shape, and density according to the energy distribution of their environment, as they were in upstream depositional environments.

Marine deltas The mouths of rivers fall into two general categories. A river with a low sediment load may reach the sea in an estuary, where the effect of current, waves, and tides keeps sediment from accumulating. A heavily laden river, however, usually creates a marine delta, a seaward extension of land at or near sea level caused by the accumulation of sediments at the river's mouth. A delta is composed mostly of sediments brought down by the river, but mixed with them are fine wave-borne sediments brought in by currents and tides.


A growing (prograding) delta is a complex structure of interbedded sediments with three more or less distinct zones of deposition. The zone nearest to the shore is occupied by topset beds, complexes of heavier, coarser particles. Depending upon flow energy and sediment load, these are typically overlapping sand and gravel bodies forming seaward extensions of the stream's natural channel and levees. They often show ripple marks, erosion surfaces, and other evidence of flow. Shallow bays between diverging (distributary) channels contain finer sediments from both the river and the sea, and often shelter abundant plant and animal life.

Some of the finer sediments carried beyond the topset beds settle out in foreset beds on the steep seaward face of the delta. In the upper foreset zone, where wave action suspends the finer sediments, the foreset beds may consist of clean sand; below the wave base, muddy sand and silt; and near the toe of the delta, thinner beds of silt and mud. As the delta grows seaward, the foreset beds are overlain by extensions of the topset beds.

Bottomset beds are tapering layers of silt and clay extending seaward from the face of the delta. Beyond reach of river and waves, these sediments accumulate slowly and sometimes support considerable seafloor life.

Marine Delta

The delta described above is an idealized model that is rarely found in nature, where conditions vary widely. Distinct topset, foreset, and bottomset beds are more often seen in lacustrine deltas in sheltered continental environments.

Beaches The transition zone also includes beaches, coastal depositional environments unrelated to the mouths of rivers. Sand and finer sediments are redistributed by longshore currents (the movement of seawater parallel to the coast). The growth and shrinkage of non-delta coastal deposits are related to the energy of longshore currents, waves, and tides.

A cross section of a typical beach shows how the sediments brought in by long shore currents are sorted and redistributed by wave and tidal energy. Differences in energy levels divide the beach profile into the shoreface (the wave action zone up to the low-tide mark), the foreshore (between low- and high-tide levels), the backshore (from high tide to storm-flood level), and the dunefield (above storm-


flood level). Because these zones are continually affected by wind and waves, their sediments are usually clean, well-sorted mineral grains and shell fragments. A cross section of a beach dune may show the same excellent sorting and cross-bedding found in desert dunes. Coarser gravels are deposited in deeper water, and finer sediments are carried seaward by wave action or inland by wind.

As the shoreface slopes upward toward the land, ocean waves begin to "feel" the bottom-that is, friction retards the movement of water near the bottom of a wave. The top of the wave goes ahead of the bottom, causing the wave to topple, or "break." While at the seashore you may have noticed a line of breakers some distance offshore. A breaker line marks an underwater bar where the concentration of wave and back- wash energy causes an accumulation of coarser sediments, such as gravel and seashells. One or more bars may form on the shoreface, depending upon the energy of incoming waves and the availability of sediments.

Beach Profile

Another high-energy zone occurs where the incoming wave laps up onto the foreshore. This action sorts the beach sediments, washing the sand clean of filler sediments and leaving particles of similar size together in distinct zones. Sediments fine enough to be suspended in the turbulent waves are carried offshore and deposited in quiet water beyond the breaker line.

If the beach is on an offshore barrier (spit or island), the transition zone may also include a shallow lagoon where sediments accumulate in a backbarrier complex. Such depositional environments are highly variable and may include tidal channels, salt marshes, shell reefs, and mangrove swamps, among other features.

Deposition in the backshore zone is intermittent. Coarser sediments may be deposited here when storm waves surge over the highest beach bars and run back into the sea in shallow channels parallel to the shore. Dry sand in the backshore zone may migrate inland in desert-like dunes driven by onshore winds.

If the lagoon behind the barrier is relatively isolated from the sea, the backbarrier complex may include such disparate features as sebkhas, thin-bedded deposits of salt or other evaporites formed where intermittent, landlocked pools dry out; peat, formed from heavy deposition of plant debris (as in mangrove swamps), which may, if buried deeply, become coal; and organic muds rich in carbonates and other skeletal debris. On the other hand, strong currents behind the barrier island or spit may flush out these deposits, leaving sediments in configurations much like those in stream deposits.


MARINE ENVIRONMENTS Marine depositional environments are those seaward of the beach - that is, beyond the zone normally affected by wave action or fluvial deposition. Associated with low-energy environments, marine sediments are mostly finer than those in the transition zone.

Shelf Environments A typical continental shelf is an underwater plain sloping 10 feet per horizontal mile seaward. It extends from the transition zone (beach or delta) to the edge of the continental mass. Most of the energy in this zone comes from shallow ocean currents and tides. Sediments are mostly silt and clay mixed with fecal pellets, skeletal debris, and shell fragments, with local deposits of coarser sediments brought in by infrequent tidal and flood cur rents. In warm tropical oceans, the clay of the shelf often grades into carbonate mud made up of undissolved shell and skeletal debris.

An epeiric sea is a broad, shallow arm of the ocean extending well inland upon the continental platform. An epeiric sea accumulates sediments from the land and organic matter from marine life, like the continental shelf, but is isolated from oceanic currents and tides. The only known modern examples, Hudson Bay and the Baltic Sea, are both cold epeiric seas. In the geologic past, however, great warm, shallow seas covered most of North America. Sediments accumulated to thicknesses of several miles as their weight gradually depressed the continental bedrock beneath. , Some of these sediments were later thrust high above sea level, where they are visible today in the Rocky Mountains and the Grand Canyon.

A reef is a wave-resistant deposit consisting of the calcareous remnants of marine organisms in or near the locations where they grew. A coral reef is a familiar example; however, the term reef is also applied to algal and oyster mounds. A reef dissipates wave energy like an offshore sandbar. Calcareous debris and organic matter may accumulate in the relatively quiet water between the reef and the shore. The deeper water seaward serves as a basin for detritus broken off the reef by wave action.

Late in the Permian era the reef was buried beneath more than a mile of clay, sand, and evaporites. El Capitan, in the Guadalupe Mountains of West Texas, is an example of such a reef that has been uplifted and exposed by erosion.

El Capitan


Outer continental environments Beginning at the edge of the continental shelf, typically in 600 to 800 feet of water (although, sometimes much more or much less), is the continental slope. Unlike the smooth continental shelf, the continental slope is a zone of steep, variable topography forming a transition from the shelf edge to the continental rise. Its average slope is around 4°, a drop of 350 feet per horizontal mile. It is also dissected, near the mouths of rivers, by rugged submarine canyons. Sediments deposited on the slope, like the foreset beds of deltas and dunes, are relatively unstable and tend to migrate toward its base.

Continental Slope

The transition zone between the continental slope and the oceanic abyss is the continental rise. A major mover of sediments on the continental rise is the turbidity current - a dense mass of sediment-laden water that flows down the continental slope, typically through a submarine canyon. Fed by a flooding river, underwater debris slide, or other source, a turbidity current is a sort of underwater flash flood carrying clay, silt, and gravel rapidly downslope in a narrow tongue. Its energy is quickly dissipated by friction upon the more gradual slope of the continental rise, where its sediments settle largest particles first, to form a turbidite - a thick, graded bed topped by clay.

A succession of turbidites forms a flysch deposit. Submarine debris fans along the base of the continental slope coalesce into an apron that is interbedded with a continuous fallout of fine sediments. Extensive flysch deposits in a geologic column tell the geologist that the environment was once the outer margin of a continent.


SEDIMENTARY ROCK CLASSIFICATIONS The sediments deposited in a continuous sheet across a broad area differ from one location to another. At the edge of an epeiric sea, for instance, the layer being deposited at any given time may grade continuously from beach sand, through a zone of silt and clay, and into a lime mud and reef complex some distance offshore. Salt may accumulate on the bottom in restricted areas. These deposits will form, respectively, sandstone, siltstone, shale, limestone, and halite. The transition from one rock type to another within the layer is continuous and gradual; a geologist tracing the layer from one area to another might find it hard to determine where limestone ends and shale begins. These changes in rock character are called facies changes. Facies changes often occur within a single formation, which is a lithologically distinctive rock body, with an upper and a lower boundary, that is large enough to be mapped.

If sea level rises relative to the land, each depositional environment will follow the retreating shoreline inland. Each type of rock thus formed will grow laterally toward the coast. Instead of a vertical column, the limestone will form a continuous, near-horizontal sheet stretching shoreward. This layer might be treated, and even named, as a distinct formation. In reality, however, it is merely one facies of a larger unit and was formed over a long period of time concurrently with the facies above and below it. The geologist must distinguish between a rock stratigraphic unit, such as the limestone in this example, and a time stratigraphic unit, the concurrently deposited layer with all its lateral facies variations.

Lithification Rivers flow in only one direction - down to the sea. Unless the land subsides or sea level rises, sediments deposited in fluvial environments above sea level are eventually carried away by the unrelenting erosive force of the river. However, sediments that reach the sea eventually come to rest in a relatively stable environment, beyond the influence of most wind, weather, and current, and become buried beneath other sediments. For this reason most sedimentary rocks originate in marine environments.

Once deposited, sediments are not necessarily lithified (transformed into stone). In order for lithification to occur, unconsolidated sediments must remain beyond the reach of erosion, and they must be compacted and cemented. The physical and chemical changes that sedimentary deposits undergo during and after lithification are known collectively as diagenesis. (Diagenesis does not, however, include the more radical changes associated with the heat and pressure of metamorphosis).

Compaction If the accumulation of sediments continues over a long period, as it usually does in the ocean, great thicknesses of material may be placed on top of the original layers. Burial beneath thousands of feet of other sediments is what begins to turn sediments into rock. The weight of overlying layers squeezes particles together into the tightest arrangement possible; under extreme conditions, it may crush some or all of the grains. As the water that originally filled the pore spaces between particles is squeezed out, the volume occupied by the sediments is reduced. This process is called compaction. Different clastic materials pack differently.

A dune sand composed entirely of rounded grains of similar size may be compacted very little. In a poorly sorted sand, however, smaller particles can be rearranged to fill the spaces between the larger grains, thus reducing the pore space. Plate-like clay particles, however, become aligned with one another when compacted, fitting together like bricks with very little space between. Some clays become compacted to less than half their original volume under the pressure of deep burial.


Cementation As compaction brings individual particles into closer contact, the process of lithification is completed by cementation. Minerals in solution - mainly calcite (CaCO3), the basic constituent of limestone - crystallize out of solution to coat the grains. Other common cementing agents include silica (SiO2), which is less soluble and therefore less abundant in groundwater; and iron oxide (Fe2O3), which colors the rock yellow or red. These coatings grow together and may eventually fill the pore spaces. Clean sand may be transformed into limey sandstone, losing most of its original pore space. Because of its low permeability, compacted clay can take on only a small amount of cement in the process of becoming shale; but wet clay is cohesive to begin with, sticking together by its own internal electrostatic forces, and so requires less cementing to become rock.

Cementation is the crystallization or precipitation of soluble minerals in the pore spaces between clastic particles. A defining characteristic of clastic texture is that individual particles touch each other at various points without conforming to the shape of other particles. In crystalline texture the grain structure originates in the rock itself as the crystals of various minerals grow in close contact with each other. Igneous and metamorphic rocks are crystalline and therefore have little or no pore space.

The texture of cemented sedimentary rock is part clastic and part crystalline. Clastic sedimentary rock can range from lightly cemented porous sandstone to well-cemented limey sandstone. Some sandstone contains so much calcite that it may be considered a sandy limestone rather than a limey sandstone.

Carbonate sedimentary rocks display an even wider range of textures because calcite particles can be created in a variety of ways. They can be the products of the mechanical breakdown of corals, shells, and skeletons, or they can form as oolites, the egg-shaped rounded grains created by the deposition of layers of calcite on other particles. As they collect in sedimentary basins, these particles can become cemented together in the same way as other grains- by crystallized calcite. The result is a limestone consisting of calcite fragments in crystallized calcite. Depending upon the admixture of other particles, limestone can grade through sandy, silty, or shaly limestone into limey sandstone, siltstone, or shale.

The deposition of sediments occurs in the earth's biosphere - the thin zone of air, water, and soil where all terrestrial life exists. For this reason, sedimentary rock often contains fossils - animal or plant parts, entire organisms, or such evidence of their former presence as tracks or burrows. Limestone, in particular, is formed partly from the remains of calcareous organisms and often contains an abundance of their shells.

Once an accumulation of sediment has become compacted and cemented into the durable form of true rock, it can undergo further changes in its chemical and physical environment that alter its structure and composition. These diagenetic alterations can involve the leaching of soluble minerals (increasing porosity), the addition of minerals by crystallization (decreasing porosity), or the recrystallization of the minerals present in the rock itself, as in the formation of chert in siliceous shale.

Diagenesis can also involve the chemical replacement of one element or mineral by another. Limestone, for example, is changed to dolomite {or more properly, dolomitic limestone) by replacement of half or more of its calcium with magnesium. Dolomitization may occur when limestone is saturated with magnesium-rich groundwater, especially at higher temperatures.


SEDIMENTARY ROCKS Geologists often divide sedimentary rocks into three main groups: clastics, evaporites, and carbonates. However, due to the many chemical and physical processes that affect sediments during lithification and diagenesis, most sedimentary rocks have features of more than one of these types.

CLASTICS Clastics are rocks such as conglomerates, sandstones, and shales that are composed mostly of fragments of other rocks. The principal distinction among clastics is grain size.

Conglomerates Conglomerates are rocks most of whose volume consists of particles more than 2 mm in diameter. They are formed from the sediments found in alluvial fans, debris flows, glacial outwash, and other high-energy depositional environments. Most conglomerates occur in thin, isolated layers; they are not very abundant.

In common usage, the term conglomerate is restricted to coarse sedimentary rock with rounded grains; conglomerates made up of sharp, angular fragments are called breccia. The rounding of fragments usually indicates transport by flowing water, which tumbles and polishes the grains and breaks off sharp projections. The rounder a pebble, the farther it has been transported. Stream gravel deposits often show imbrication - the arrangement of pebbles in a flat, overlapping pattern like bricks in a wall. Conglomerates formed from debris slides and alluvial fans have more angular fragments and poorer sorting than those in stream deposits. Tillite, a breccia deposited by glaciers, is a chaotic jumble of grains ranging from clay particles to angular boulders; it shows little or no grading or sorting.

Sandstones Sandstone is clastic sedimentary rock more than half of whose grains are 1/16 mm to 2 mm in diameter. About one-fourth of all sedimentary rock is sandstone. The sand particles are of three principal types: quartz (SiO2); feldspar grains, derived from granite or other rocks; and lithic particles, each of which is a mixture of various minerals. Sandstones are of particular interest to petroleum geologists because they "are usually more permeable to formation fluids than other rocks and therefore able to accumulate oil and gas. Many of the world's richest petroleum deposits are found in sandstone reservoirs.

Quartz Sandstone

Conglomerate


Sandstone can remain mostly open and porous or become filled with cement, silt, or clay. Sandstones in which less than 15% of the total volume is silt and clay are called arenites. Quartz arenites tend to develop from deposits of clean sand in high-energy environments such as deserts and beaches. Their grains are rounded and well-sorted, indicating much reworking by wind and water. Arkose is a feldspathic arenite derived from granite and lithified in small deposits (granite wash) near its source.

Graywackes are sandstones that contain more than 15% silt and clay. Their grains tend to be angular and poorly sorted. In some cases, their clay/silt matrix is believed to have been deposited along with the larger grains, as in the heterogeneous mixture of particles found in turbidity currents; in others, clay and silt appear to have been added to the rock by physical or chemical alteration of the original minerals or by infiltration. Most graywackes are thought to be marine in origin.

Shales An estimated one-half to three-fourths of the world's sedimentary rock is shale - a distinctive, fine-grained, evenly bedded rock composed of silt and clay. Silt grains are similar to sand grains, but much smaller – 1/256 mm to 1/16 mm - and mostly invisible to the unaided eye. Clay particles are quite different in composition and shape; they are microscopic, flat, plate-like crystals less than 1/256 mm across. During compaction and lithification, these plates tend to become aligned in horizontal sheets. As a result, most shale splits along well-developed planes parallel to, but not necessarily coinciding with, bedding planes. One variety, mudstone, is an exception; it breaks into chunks or blocks.

Formed from fine sediments that settle out of suspension in still waters, shale and mudstone occur in thick deposits over broad areas, often interbedded with siltstone, sandstone, or limestone. They vary widely in color, with the darker colors often indicating higher proportions of organic materials from the remains of plant and animal life. Petroleum geologists believe organic shales to be the source of most of the world's petroleum and natural gas. Shales also make excellent barriers to the migration of fluids and therefore tend to trap pools of petroleum in adjacent porous rock.

Black & Gray Shale

EVAPORITES Rocks formed by the precipitation of chemicals from solution are called evaporites. Deposits of evaporites can form as the result of either the drying up of a body of water, such as a desert playa lake, or continuous evaporation from a confined body of water that is continually replenished by inflowing

water. In the latter case, dissolved minerals become supersaturated (so concentrated that they can no longer stay in solution) and precipitate out to form deposits on the bottom. Evaporites usually form in a distinct sequence, the least soluble minerals precipitating first, the most soluble last. A typical deposit would have gypsum (CaSO4.2H2O) and anhydrite (CaSO4) at the bottom, followed by halite or rock salt (NaCl), sodium bromide (NaBr), and potash (KCl).

Gypsum


Evaporites are indicators of former dry climates or enclosed drainage basins. They comprise only a small fraction of all sedimentary rocks but play a significant part in the formation of certain types of petroleum reservoirs - those associated with salt domes.

Halite

Did You Know? Gypsum, one of the most widely used minerals in the world, literally surrounds us every day. Most gypsum in the United States is used to make wallboard for homes, offices, and commercial buildings; a typical new American home contains more than 7 metric tons of gypsum alone. Moreover, gypsum is used worldwide in concrete for highways, bridges, buildings, and many other structures that are part of our everyday life. Gypsum also is used extensively as a soil conditioner on large tracts of land in suburban areas, as well as in agricultural regions.

CARBONATES Most carbonate rocks are organically deposited - that is, formed as a direct result of biological activity. Limestone and dolomite are the most common of these, making up about one-fourth of all sedimentary rocks. Carbonate rocks are important to the petroleum industry; many of the giant reservoirs in the Middle East are in limestone.

Limestone forms in warm, shallow seas. Most seawater is nearly saturated with dissolved calcite (CaCO3); many marine organisms use this calcite to build their shells and skeletons. In shallow tropical oceans, two factors favor the formation of limestone: (1) as water gets warmer, it loses some of its ability to hold dissolved carbon dioxide, and (2) photosynthetic algae and other plants remove CO2 from the water to produce carbohydrates. This loss of CO2 reduces the water's ability to hold calcite in solution. Thus the calcareous remains of dead organisms do not dissolve as they would in colder water. Instead, they accumulate in thick layers of lime mud and sand on the bottom, cemented by additional calcite precipitated from solution. If coral is present, the skeletons of large colonies may be engulfed in other calcareous debris.

Great sheets of limestone formed in past epeiric seas {most notably those of the Cretaceous period) now extend across much of the world's land area. Their structures vary from mostly clastic to mostly crystalline and from very porous (with many large openings) to very tight, depending upon where and how they were formed and what has happened since. Most of the limestone has undergone extensive alteration; diagenesis is especially common in limestone because it is more soluble than other sedimentary rocks.

Some other rocks of biochemical origin are diatomite, an accumulation of the siliceous (glassy shells of certain microscopic algae, which sometimes recrystallizes as flinty nodules of chert; phosphorite,


composed largely of calcium phosphate from bird droppings and vertebrate skeletal remains; coal, the mildly to strongly metamorphosed remnants of undecayed plants; and oil shale, consisting partly of unoxidized plant and animal remains. Oil shale and other organic shales are primarily clastic rocks, but they contain enough preserved organic matter to be of interest to the petroleum geologist.

Limestone Coal Chert

ORIGIN OF HYDROCARBONS For most of their history, oil and natural gas were thought of as minerals, substances formed out of nonliving rock, just as gold, sulfur, and salt were part of the rock. There was little reason to assume otherwise. Although petroleum smelled like something that had died, and although natural gas burned like swamp gas, most of the gas and oil escaping from the ground seemed to come from solid rock deep beneath the surface, where, as everyone knew, nothing lived.

Beginning two centuries ago, however, the geologic insights of Hutton, Lyell, and other scientists showed that the rocks in which oil was found were once loose sediment piling up in shallow coastal waters where fish and algae and plankton and corals lived. Now it seemed possible that oil and gas had something to do with the decay of dead organisms, just as coal, with its leaf and stem imprints, seemed to be the fossilized remains of swamp plants.

Later advances in microscopy revealed that oil-producing and oil-bearing rocks often contain fossilized creatures too small to be seen with the unaided eye. Chemists discovered that the carbon-hydrogen ratios in petroleum are much like those in marine organisms and that certain complex molecules are found in petroleum that are otherwise known to occur only in living cells. But it was the fact that most source rocks could be shown to have originated in an environment rich with life that clinched the organic theory of the origin of petroleum.

Unanswered questions about the occurrence of petroleum remain, and men of science still debate the evidence of its organic origin. Because of the weight of that evidence, however, few scientists doubt that most petroleum originates in the life and death of living things.

Chemical Factors Petroleum is both simple and complex. It is composed almost entirely of carbon and hydrogen; but the number of ways that carbon and hydrogen can combine is astronomical, and most petroleum contains


hundreds of different kinds of hydrocarbons. It occurs in forms as diverse as thick black asphalt or pitch, oily black heavy crude, clear yellow light crude, and petroleum gas. These variations are due mainly to differences in molecular weight - that is, the sizes of the molecules - and the types of impurities. Despite the differences in molecular weights, however, the proportions of carbon and hydrogen do not vary appreciably among the different varieties of petroleum; carbon comprises 82 to 87 percent and hydrogen, 12 to 15 percent.

Element Crude Oil Natural Gas

Carbon 82 – 87% 65 – 80% Hydrogen 12 – 15% 1 – 25% Sulfur 0.1 – 5.5% 0 – 0.2% Nitrogen 0.1 – 1.5% 1 – 15% Oxygen 0.1 – 4.5% 0%

Chemical Composition of Average Crude Oil & Natural Gas

Petroleum is almost insoluble in pure water and only slightly soluble in salt water or water containing other organic substances. It is lighter than, and therefore floats on, water; but it is often found in an oil-water emulsion - that is, dispersed in small droplets suspended in water. A hydrocarbon molecule is a chain of one or more carbon atoms with hydrogen atoms chemically bound to them. Some petroleum contains hydrocarbon molecules with up to sixty or seventy carbon atoms. At room temperature and pressure, molecules with up to four carbon atoms occur as gases; molecules having five to fifteen carbon atoms are liquids; and heavier molecules occur as solids.

Methane, the simplest hydrocarbon, has the chemical formula CH4. Four is the maximum number of hydrogen atoms that can attach to a single carbon atom; thus methane is classified as a saturated hydrocarbon - a paraffin, or alkane. Other paraffins include ethane (C2H6), a chain of two carbon atoms with six hydrogen atoms; butane (C4H10); and octane (C8H18).

putalog

Hydrocarbon Chains


Unsaturated hydrocarbons also occur naturally in petroleum. The most common of these are the aromatics, compounds based on the distinctive benzene ring (C6H6). Other ring-shaped compounds include the naphthenes, or cycloparaffins, which vary in number of carbon atoms and bonding pattern. Naphthenic crudes produce less fuel and more lubricating oils than paraffinic crudes. The residue left when these crudes are refined is high in semisolid or solid asphaltic wastes; therefore, naphthenic oils are sometimes called asphaltic crudes.

Biological Factors Petroleum contains solar energy stored as chemical energy. Many steps are involved in the conversion from the simple radiant energy of the sun to the complex molecules of hydrocarbons. Coastal waters, rich with nutrients brought in by rivers and upwelling deep-sea currents, support an elaborate community of organisms ranging from microscopic, single-celled plants and animals to large predatory fish and mammals. Some of the smallest and simplest of these organisms perform the first capture and conversion of the sun's radiant energy.

The bulk of the living matter in such biotic communities is in the form of microscopic or near-microscopic simple organisms: protozoa (animals) and algae (plants). The algae are photosynthetic: they can synthesize their own food, simple sugars and starches, out of water and car bon dioxide, using the energy of sunlight. Other organisms consume the algae and convert the simple carbohydrates into more complex foods, such as proteins and fats; still larger organisms, in turn, eat these.

Each level of the food chain contributes waste products, and every organism that is not eaten eventually dies. In recycling this organic material, an important role is played by a diversity of bacteria. The two principal types are those that live in aerobic (oxygenated) environments and derive their energy by oxidizing organic matter and those that live in anaerobic (reducing) environments by taking the oxygen from dissolved sulfates and organic fatty acids to produce sulfides (such as hydrogen sulfide) and hydrocarbons. Although aerobic decay liberates certain hydrocarbons that some small organisms accumulate within their bodies, the anaerobics are more important in the formation of oil.

If the process of aerobic decomposition continues indefinitely, all organic matter, including hydrocarbons, is converted into heat, water, and carbon dioxide - the raw materials that photosynthetic plants use to make their carbohydrate food. For an accumulation of petroleum to be formed, the supply of oxygen must be cut off. Most areas along the coast are well aerated by circulation, wind, and wave action. In some areas, however, physical barriers such as reefs or shoals hinder aeration; and in deeper waters far offshore, the water below a certain depth is similarly depleted of oxygen. Here organic waste materials and dead organisms can sink to the bottom and be preserved in an anaerobic environment instead of being decomposed by oxidizing bacteria. The accumulation and compaction of impermeable clay along with the organic matter help seal it off from dissolved oxygen. Thus isolated, it becomes the raw material that is transformed into petroleum by the heat and pressure of deeper burial.

Even in areas with appreciable circulation and oxygenation, organic debris can accumulate so fast that it is quickly buried beyond the reach of aerobic organisms. Locations where this is likely to occur include salt marshes, tidal lagoons, river deltas, and parts of the continental shelf. Epeiric seas such as those that covered much of North America during the Permian and other periods offered broad stretches of warm, shallow water where, unstirred by ocean currents and tides, abundant organic debris could accumulate in an anaerobic environment.


Physical Factors The clay that settles out of suspension in quiet waters is buried and transformed into shale. Organic matter trapped within is subjected to pressure that increases at slightly less than the geostatic pressure gradient, which is about 1 pound per square inch (psi) per foot of depth. The temperature increases gradually, both from compression and by heating from the earth's interior. (Below a thin zone that is affected by climate, the temperature rises about 1.5°F for every 100 feet of depth.)

At 120° to 150°F, certain chemical reactions that ordinarily proceed very slowly begin to occur much more quickly. The organic matter trapped within the rock begins to change. Long-chain molecules are broken into shorter chains; other molecules are reformed, gaining or losing hydrogen; and some short-chain hydrocarbons are combined into longer chains and rings. The net result is that solid hydrocarbons are converted into liquid and gas hydrocarbons. Thus the energy of the sun, converted to chemical energy by plants, redistributed among all the creatures of the food chain, and preserved by burial, is transformed into petroleum.

The petroleum window - the set of conditions under which petroleum will form - includes temperatures between the extremes of 100°F and 350°F. The higher the temperature, the greater is the proportion of gas. Above 350°F almost all of the hydrocarbon is changed into methane and graphite (pure carbon). Source beds (or reservoirs) deeper than about 20,000 feet usually produce only gas.

The Petroleum Window

Source Rocks Rock in which organic material has been converted into petroleum is called source rock. (Rock in which petroleum accumulates is called reservoir rock). Generally, the best source rocks are shales rich in organic matter deposited in an anaerobic marine environment. Often these are dark shales, although the dark color can be caused by other substances. However, limestone, evaporites, and rocks formed from freshwater sedimentary deposition also become source beds.

Some petroleum geologists think that heat and pressure alone can convert organic detritus to petroleum; others disagree on the relative importance of algae, plankton, foraminifera, and larger organisms in providing source organic material. It seems likely that petroleum is formed by a range of processes from a supermarket of raw materials under a variety of conditions; this fact would help account for the great chemical complexity of most petroleum and the variety of forms in which it occurs.


It takes time for petroleum to form and accumulate. Little petroleum has been found in Pleistocene formations or potential reservoir rocks associated with source beds less than a million years old.

HYDROCARBON MIGRATION Like other formation fluids, oil and gas migrate. In some situations, they accumulate near where they originate, sometimes within a few inches or feet of the source bed. In other places, the migration covers many miles. Because it is lighter than water and does not readily stay mixed with it, oil tends to separate from water and float on top. Usually it moves as a diffuse scattering of suspended droplets, but it may reach higher concentrations when its movement is impeded. Gas is usually present as well, either dissolved in the oil or as a separate, distinct accumulation. The term migration is used in two senses. Primary migration is the movement of hydrocarbons out of the source rock - a journey of a fraction of an inch to several feet, rarely more. Secondary migration is the subsequent movement through porous, permeable reservoir rock by which oil and gas become concentrated in one locality.

Primary Migration How does petroleum leave its source rock? Apparently both compaction and the flow of water are involved. Petroleum comes from source beds deposited mostly on the seafloor, so it usually begins and ends its travels in company with interstitial water-water found in the interstices, or pores, of the rock. (Connate water, a more exact term, is water that was "born with" the rock-present when the rock was formed.) Much more water than oil and gas is present underground.

As deposition continues at the surface, the growing weight of the overburden compresses the shale into less and less space. However, it is not the solid mineral grains that are compressed, but the pore spaces. Interstitial water is squeezed out, carrying droplets of oil in suspension and other hydrocarbons in solution. Although the solubility of oil in water is negligible compared to that of gas, both are more soluble under pressure.

Under compression, some rocks maintain their porosity and permeability better than others. Imagine two adjacent rock layers, a clean arenite sandstone and a silty shale, gradually being buried beneath thousands of feet of overburden. The sandstone will lose very little of its porosity because its relatively spherical grains were closely packed when deposited as sediments and its pores are not clogged with silt or clay. Such a sandstone might have an initial porosity of 35%, which would be reduced to 30% at depth. Clay particles, on the other hand, are relatively irregular in shape and lithified in a loosely packed arrangement. Under pressure these particles become better aligned and more closely packed, like a pile of bricks rearranged to form a brick wall. Under the same compressive force as that on the sandstone, shale porosity might decrease 60% to 35%. Fluids squeezed out of shale will therefore collect in the adjacent sandstone, which retains more of its original porosity.


Secondary Migration Hydrocarbons are moved through permeable rock by gravity. This force works in several ways: by compressing pore spaces containing fluid, by causing water containing hydrocarbons to flow, and by causing water to displace less dense petroleum fluids upward.

Saying that water flows through formations does not mean that it flows in underground rivers. Flow can mean movement of a few inches a year, which can add up to many miles in a geologically short time. What causes water to flow is a difference in fluid potential (which in some cases coincides with fluid pressure). Just as a difference in electrical potential causes electricity to flow from a high-voltage region to one of lower voltage, a difference in fluid potential causes water to move from a region of high fluid potential to one of lower potential.

On the surface, unconfined water moving from a high-potential to a low-potential zone simply flows downhill. In a municipal water system, however, water flows down from a high water tower, travels horizontally through a water main, and rises again into hilltop houses and the upper stories of high buildings. As long as its outlet is below the level of the water tower, water will flow uphill or down.

Potentiometric Example

Water confined in a porous, permeable formation behaves much the same as water in a pipeline. In the figure below, water enters the formation at point A and exits at point E. A line drawn between these two points defines the potentiometric surface. (This is not the same as the water table, which is the upper surface of the underground water). A well drilled into the aquifer at B will fill to point F on the potentiometric surface; an artesian well drilled to D will seek level H above ground. Water flowing from A to E is flowing uphill from B to C and from D to E. It is not always flowing from high-pressure to low-pressure areas. Although it is doing so from B to C, the flow from C to D is toward greater hydrostatic pressure. The rate and direction of flow are the result of the difference in elevation between points A and E.

Suspended oil droplets and dissolved gas are carried along in the flowing water. As oil saturation increases, however, small droplets coalesce into larger ones, and the accumulating oil begins to behave differently. Because of their buoyancy, large oil droplets tend to rise through water, often against a moderate flow, and accumulate at the top.


In secondary migration, the effective porosity and permeability of the reservoir rock are more important than total porosity. These factors control how easily the reservoir can accumulate fluids as well as how much it can hold.

Effective porosity is the ratio of the volume of all the interconnected pores to the total volume of a rock unit, expressed as a percentage. Only the pores that are connected with other pores (the effective porosity) are capable of accumulating petroleum. Effective porosity depends upon how the rock particles were deposited and cemented as well as upon later diagenetic changes. The structure of the rock may change in such a way that some of the pore spaces become isolated.

A rock's permeability is a measure of how easily fluids can pass through it. The basic unit of permeability is the Darcy; l/1000 of a Darcy is a millidarcy (md). Permeability is difficult to measure in the field because it varies greatly with pressure, fluid viscosity,

oil saturation (the percentage of oil in the formation fluids), direction, and other factors. Depending upon sorting, compaction, cementation, and diagenesis, permeability can vary widely within a given type of rock. The permeability of sandstones commonly ranges between 0.01 and 10,000 md. Reservoir rock permeability of less than 1 md is considered poor, 1-10 md is fair, 10-100 md is good, and 100-1,000 md is very good. For comparison, a piece of writing chalk has a permeability of about 1 md.

Although often closely related, permeability and effective porosity are not the same. A rock with few isolated pore spaces may have a very high effective porosity and yet be nearly impermeable because of the narrowness of the connections between pores. Differences in capillarity (the ability of fluid to cling to the grains) may make the permeability of a given rock relatively high for gas, lower for water, and near zero for viscous oils. Permeability can vary with direction of flow. Pore connections may be less numerous, narrower, or less well aligned in one direction than another. In rocks formed from well-sorted beach sands, grains that are not spherical are often aligned perpendicular to the beach. Stream channel sands are aligned in the direction of stream flow and often contain horizontal sheets or stringers of less permeable clay. Fluids move more easily through such rocks parallel to grain alignment or clay stringers than across them (see figure below).

Matrix

Isolated Pore Fluid

Matrix


Preferential Fluid Flow in the Horizontal Direction

HYDROCARBON ACCUMULATION Like water in a puddle, oil collects in places it cannot readily flow out of. Its movement ceases upon reaching a structural high point or a zone of reduced permeability. As it accumulates, the mixture of hydrocarbons and water differentiates into distinct zones of gas, oil, and water.

Fluid Separation by Density

Trapping The permeability of the formation that seals off a petroleum reservoir is never absolutely zero, but just low enough to reduce the flow rate effectively to zero under reservoir conditions. Given enough pressure and fluidity (as opposed to viscosity), hydrocarbons may seep into a tight formation that under less extreme conditions would totally exclude them.

Effective permeability is the rock's permeability to a given fluid when another fluid is also present. Water has seven times the ability of oil to cling to the grains of porous rock, so it tends to fill small pores and keep oil out. In a petroleum reservoir, interstitial water is nearly always present. Clinging to

Matrix


the grains, it reduces the space available for oil and narrows the passages between pores, lowering the rock's effective permeability to oil.

Relative permeability is the ratio of effective to absolute permeability. A rock that contains oil but no water has a relative permeability of 1.0 for oil. Relative permeability of 0.0 means that water has filled enough of the pore space to keep the oil from flowing. Higher fluid pressure may overcome the water's resistance to the passage of oil and may increase the effective permeability of the formation by opening tiny fractures across and along bedding planes.

A tight formation may keep fluids from leaving an underlying reservoir bed by preventing their vertical migration. However, fluids may still migrate horizontally beneath the seal. For an accumulation to form, petroleum fluids must encounter a trap, a geologic combination of impermeability and structure that stops any further migration. The basic mechanisms involved can be illustrated using as an example the anticline, the type of trap from which petroleum was first produced in commercial quantities and in which most of the world's presently known reserves are located.

In the figure above, interstitial water with a small concentration of oil droplets and dissolved hydrocarbons courses slowly through an undeformed horizontal sandstone beneath a layer of relatively impermeable shale. The oil droplets, although swept along by the movement of the water, tend to concentrate in the upper levels of the sandstone because of their buoyancy.

Suppose tectonic forces tilt these horizontal layers. If the tilt is upward in the direction of flow, the situation is little changed; oil tends to rise updip, the same direction in which the water flows. However, if the water flows downdip, the oil tends to rise against the flow of water.

IMPERMEABLE SHALE


Now suppose this sedimentary rock assemblage is bent into an anticline. Water flows through the permeable sandstone as before - updip into the anticline and downdip out of it. Oil rises with the water entering the anticline - but rises against the flow on the downdip side. If the water is not flowing too fast, the oil droplets brought in by the flowing water move preferentially toward the crest of the anticline. They concentrate and coalesce near the highest point. As the water brings in more oil, the pool grows.

To accumulate oil, the anticline must be closed: it must dip toward both flanks and plunge in both directions along its axis. Otherwise the oil will continue to migrate updip. An anticline is like an upside-down trough (or cup) out of which oil spills upward rather than downward. If the cup is tilted too much, the accumulated hydrocarbons will pour out of the cup and continue rising.

Differentiation With few exceptions, petroleum reservoirs are water-wet - that is, the oil is not in contact with the rock grains because they are coated with a film of water. Most oil fields have 50% to 80% maximum oil saturation. Above 80% oil saturation, the oil can be produced with very little water mixed in; below 10%, the oil is not recoverable.

A hydrocarbon reservoir is divided into two or more zones. If only oil and water are present, the oil occupies the upper zone. Although water still lines the pores, this is the zone in which maximum oil saturation occurs. The oil zone is underlain by water along the oil-water contact, which is not a sharp line but a transition zone usually many feet thick. Oil saturation increases gradually from near 0% at the base of this zone to 50% to 80% at the top. The region of maximum oil saturation extends from the top of the transition to the top of the reservoir.

Natural gas is present in nearly all hydrocarbon reservoirs, dissolved in the oil (as solution gas) and to some extent in the water. In many situations, however, reservoir conditions and gas saturation allow undissolved gas (associated free gas) to accumulate above the oil zone as a gas cap. The wetting fluid in a gas cap is usually water but occasionally oil. The transition zone between oil and gas (the gas-oil contact) is thinner than the oil-water contact zone because of the greater difference in density and surface tension between gas and oil.


Some reservoirs contain gas but not oil. This gas is called non-associated gas. The transition zone is a gas-water contact. The water almost always contains gas in solution, and water lines the pores in the gas zone.

Free methane, the lightest hydrocarbon, remains in a gaseous state even under great pressure. Ethane, propane, and butane, which are gases at surface pressure and temperature, are often found in a liquid state under reservoir conditions.

TYPES OF TRAPS The basic requirements for a petroleum reservoir are a source of hydrocarbons, a porous and permeable rock formation through which hydrocarbons can migrate, and something to arrest the migration and cause an accumulation. Although most of the known reservoirs are anticlinal, many other geologic situations can cause hydrocarbons to accumulate.

Petroleum geologists have, for convenience, lumped hydrocarbon traps into two major groups: structural, in which the trap is primarily the result of deformation of the rock strata; and stratigraphic, in which the trap is a direct consequence of depositional variations that affect the reservoir formation itself. Some geologists also include a third type - hydrodynamic traps, in which the major trapping mechanism is the force of moving water. Most reservoirs have characteristics of more than one type.

STRUCTURAL TRAPS

Anticlines Anticlinal reservoirs are created by tectonic deformation of flat-lying and parallel rock strata. The basic anticlinal trap has already been described, and the syncline is not a noteworthy type of trap because only under rare circumstances does it cause petroleum to accumulate.

A short anticline plunging in both directions along its strike is classified as a dome. A dome is distinguished on structural maps by its nearly circular shape. Many domes are the result of diapirism, the penetration of overlying layers by a rising column of salt or other light, mineral. Salt domes are common along the U.S. Gulf Coast and in the Middle East, northern Germany, and the Caspian Volga area of Russia.

Anticline Structure


Faults When deformational forces exceed the breaking strength of rock, the result is a fault. Faults can affect the migration and accumulation of petroleum in various ways. They can act as conduits for and gas, allowing or forcing these fluids into formations at other levels or even to the surface. Conversely, the movement of an active fault may grind rock into a fine-grained substance called gouge, which may be nearly impermeable to fluids. Shale strata cut by a fault may be smeared along the fault zone, creating a low-permeability barrier. A fault containing material of low permeability is called a sealing fault.

Most faults trap oil and gas by interrupting the lateral continuity of a permeable formation. Fault displacement places an impermeable formation opposite the reservoir rock, and updip hydrocarbon migration is stopped as suddenly and effectively as though a dam had been erected. Faults and folds are often closely associated, and each can affect how the other causes fluids to accumulate. The upper parts of anticlines are commonly faulted. Such faults, which often occur as the anticline is forming, may not change the total volume of the reservoir but may divide it into separate compartments.

Sealing faults may isolate the compartments from one another; non-sealing faults may allow reservoir fluids to redistribute themselves or even migrate out. The dip of a growth fault approaches the horizontal at depth; deposition is faster on the downthrown side, which tends to "roll over" or curl downward. The result is a rollover anticline, where oil and gas can accumulate. Although not trapped by the fault itself, the petroleum may be trapped as an indirect result of it.

Great horizontal stresses, such as those caused by the collision of two continental masses, may be relieved through overthrust faulting. Blocks of the crust are shoved horizontally, sometimes many miles, atop their counterparts, creating a double thickness (or more, in complex cases) of sedimentary strata. The resulting flexures and faults can trap hydrocarbons in several ways. The crest of an overthrust anticline, sometimes called a drag fold, can become a reservoir, as can the sheared-off permeable rocks bent upward against the lower side of the fault. The Rocky Mountain Overthrust Belt contains many such reservoirs.

STRATIGRAPHIC TRAPS

Compared to anticlines and faults, traps that are the result of lateral discontinuity or changes in permeability are difficult to detect. For this reason, stratigraphic traps were not well represented or studied until long after many of the world's most productive structural oil fields had been discovered. The search for stratigraphic traps has intensified in recent decades, but they still account for only a minor part of the world's known petroleum reserves.

Impermeable Bed

Sealing Fault


Many structural traps, especially those near the surface, can be located by careful study of the surface geology. Stratigraphic traps, however, are usually unrelated to surface features. Their elusiveness has stimulated the development of more and more sophisticated exploration techniques and devices. Many stratigraphic traps have been discovered accidentally while drilling structural traps.

Shoestring Sand

A good example of why stratigraphic traps are hard to find is the shoestring sand. This type of reservoir is often an overlapping series of coarser stream sediments that were inundated and buried beneath thick deposits of clay. It appears as a sinuous string of sandstone winding erratically through impermeable shales. Multiple shoestring sands sometimes form complex branching networks. The overlying land surface, whether flat or cut by deep valleys, gives no hint of the underlying buried channel. Tracing the course of a shoestring is almost as difficult as finding it. The petroleum geologist uses such clues as direction of greatest permeability and general

slope of the buried land surface to find the next productive location. Lining up two or three productive wells helps narrow the search.

Beach sand The linear zone of sediments marking a former coastline may form a series of sandstone reservoirs. Unlike river sandbars, grain orientation and direction of maximum permeability are across the trend. Information on facies changes is especially useful in locating this type of reservoir. Knowing that limestone and shale usually form some distance offshore, the geologist can determine the direction in which the sediments become coarser and more permeable. The coarsest, best-sorted, most permeable sand is found in the shoreline zone that was affected by wave action. It is the most likely place to find oil, both because of its porosity and permeability and because, if tectonically undeformed, it is structurally the highest part of the stratigraphic unit.

mputalog

Stream Channel

Barrier Island

Lagoon


Lens A lens is an isolated body of sandstone or other permeable rock enclosed within shale or other less permeable rock. Its’ edges taper out in all directions and can be formed by turbidity underwater slides, isolated beach or streams sand deposits, alluvial fans, and other deposits. They are tapered in cross section, like shoestring and beach sand - but not extended in length.

Bioherm Another type of stratigraphic trap is the reef. A wave-resistant accumulation of coral or shells serves as an anchor for calcareous debris that forms limestone. If deeply submerged faster than it can accrete it may become buried beneath marine shales. Such an isolated reef is called a bioherm. It may be porous enough to hold large accumulations of hydrocarbons, especially if it has been dolomitized. Limestone is especially vulnerable to dissolution by groundwater, particularly if raised above the water table. Leaching by weak solutions of atmospheric carbon dioxide may form vugs (small voids) or caverns (large voids) capable of containing hydrocarbons. Overlying deposits may be laid down in such a way as to form a draped anticline, or compaction anticline - a structural feature that may also trap oil and gas. Atolls (rings of coral islands), coral pinnacles, and other reef features are prolific oil producers. The Horseshoe Atoll, a buried shell reef system in West Texas, contains one of the world's largest and most prolific oil reservoirs.

Lens Traps


Pinchout A pinchout trap occurs where a porous and permeable sand body is isolated above, below, and at it’s up dip edge by shale or other less permeable sediments. Oil or gas enters the sand body and migrates updip until it reaches the low-permeability zone where the reservoir "pinches out".

Permeability changes Diagenetic changes can create traps within formerly permeable rocks or can create reservoir areas within formerly impermeable rocks. Minerals crystallizing out of circulating water between the grains of a porous sandstone may reduce local permeability enough to form a barrier to hydrocarbon migration. Alternatively, circulating water may increase permeability by leaching out cement or by enlarging fissures and vugs in limestone, thereby increasing the potential for hydrocarbon accumulation.

Fine-grained rocks such as the Austin Chalk in Texas may be unsuitable as reservoirs because of their relative impermeability. When cut by a fault, however, they may become locally fractured (brecciated) and accumulate small but productive pools in areas that are not structurally high.

Petroleum itself can seal permeable rock. If exposed to oxygen or altered by bacteria, an oil seep often loses its more volatile components and becomes thick and tar-like. It may plug the rock pores so tightly that no further migration toward the surface can occur. Below the affected zone, however, recoverable petroleum may still accumulate.

Pinchout Traps


UNCONFORMITIES A major subcategory of stratigraphic traps includes those associated with unconformities. Permeable outcrops overlain by impermeable layers can accumulate hydrocarbons from sources both above and below the unconformity. A buried anticlinal outcrop may trap petroleum in both flanks, downdip from the eroded crest. Locations that would have seeps on the former landscape surface become traps beneath an unconformity. A porous, permeable formation lapping out on an unconformity can also become a trap. Further subcategories of unconformities are the disconformity, angular unconformity, and the nonconformity.

Disconformity An unconformity along which the layers above and below are parallel is called a disconformity. The disconformity may be parallel to the layers, representing a period during which deposition simply ceased; or it may be irregular, indicating an episode of erosion. In the former case, the disconformity may be difficult or impossible to distinguish from an ordinary bedding plane. Unless revealed by correlation with nearby strata, a gap of thousands or millions of years of deposition may go undetected.

Angular Unconformity In an angular unconformity, the upper layers are not parallel with the lower ones. Older layers have been tilted or folded, eroded, then submerged for further deposition. An angular unconformity separates Precambrian sedimentary rocks from Paleozoic strata in parts of the Grand Canyon.

Nonconformity A nonconformity is an unconformity in which sediments were deposited on an eroded surface of igneous or metamorphic rock. In this situation, the fundamental difference in character of the rocks above and below is obvious. However, if the formation below is of banded metamorphic rock, the nonconformity may superficially resemble an angular unconformity.

Granite


HYDRODYNAMIC TRAPS Movement of water through reservoir rock affects not only the amount but also the distribution of oil. An oil-water contact is usually tilted downward in the direction of flow. The pool can be displaced so far that a well drilled into the crest of an anticline might produce only water. The slope of the oil-water interface, and therefore the location of the pool, is related in a predictable way to the slope of the potentiometric surface (which is always in the direction of flow) and to the difference in density between the oil and the water. The denser the oil, the more it is displaced. Gas, the lightest petroleum fraction, tends to stay near the crest of the anticline.

Oil may accumulate hydrodynamically in a structural feature that might otherwise not trap it. The flow of water through the reservoir bed causes oil to accumulate in the tilted anticline. Were water flow to cease, the buoyancy of the oil would cause it to migrate up dip.

Water flows through a confined permeable layer at a definite volumetric rate. If the cross-

sectional area varies, the volumetric flow rate remains constant, but the linear flow rate changes. In other words, to maintain the same number of gallons per hour, the water must flow faster through a narrow section than through a broad section.

In this example water flows downdip from a narrow zone into a broader section. Buoyant oil droplets can migrate upstream against the slow flow in the broad section but not against the rapid flow in the narrows. Oil therefore backs up in a pool at this bottleneck. A zone of reduced permeability can have the same effect because the cross-sectional area of the interconnected pore space is reduced.

Combination Traps Many petroleum traps have both stratigraphic and structural features. Some, in which both types of characteristics are essential in trapping petroleum, are difficult to classify as either primarily structural or primarily stratigraphic. For instance, originally horizontal formations that now pinch out updip can trap hydrocarbons that might not otherwise have accumulated. Secondary porosity in a shattered (brecciated) fault zone or anticlinal crest is a stratigraphic trapping mechanism caused by structural deformation. Most hydrodynamic trapping depends partly upon formation structural features and often upon stratigraphic variations within the reservoir formation.

Tilted Anticline


Many types of traps can be found near salt domes. Most would be considered structural, although some could be classified as combination traps. Beneath the U.S. Gulf Coast are thick beds of salt that were deposited, during the opening of the modern Atlantic Ocean, in sedimentary basins with restricted circulation and high evaporation rates. Under pressure, this rock salt, light and easily deformed, is displaced by the weight of accumulating sediments, forming huge mushroom-like columns that rise toward the surface. In each of these diapirs, the overlying rocks are pushed aside or bulged upward into a dome. The penetrated layers are dragged upward by the rising salt core and depressed downward away from it as the overlying layers subside to replace the depleted salt bed. Leaching by groundwater prevents the salt from breaking through the surface, but leaves atop the column a residue of less soluble compounds, forming a dense, impermeable caprock. Overlying sediments break in a complex series of intersecting faults. The base of the salt core may narrow, creating a mushroom-shaped overhanging column.

Many types of petroleum traps are thus formed: a multi-layered dome on top, cut by faults; upturned drag folds that terminate against impermeable salt; upturned pinchouts where compression and other diagenetic changes have reduced permeability; and faults along the flanks. Oil may also collect beneath the impermeable caprock or beneath the overhanging salt. The multiple possibilities for traps and the high likelihood of finding petroleum have made salt domes popular places to drill.

Combination Traps

Faults

Drag Fold

Flank Trap

Upturned Pinchout

Dome


TIMING AND PRESERVATION OF TRAPS The accumulation of oil underground is a dynamic phenomenon. It is a function not only of the location and configuration of source and reservoir beds but also of timing - the formation of the trap and the arrival of the resource. A potential trap may form but remain barren because all the petroleum has migrated out of the area; or it may form and be destroyed before hydrocarbons are generated. An accumulation of hydrocarbons in a perfectly suitable reservoir may eventually be lost either because of deformation and destruction of its trap or by excessive heat and pressure.

As an example of how the amount and character of hydrocarbon accumulation may change over both time and space, consider the stair-step sequence of anticlines below. Water, with entrained oil and gas, flows from left to right. At TIME 1, oil and gas are trapped in anticline A while "cleaned" water continues through B and C. As more oil and gas accumulate, the trap fills and some of the oil spills out into trap B. The gas, however, continues to accumulate in A until at TIME 2 it has displaced all the oil. The process continues, as at TIME 3. Thus, the range of fluids produced by a well in any of these structures depends upon the stage in its history.

An old trap may contain new oil - that is, oil that originated long after the trap was formed. Conversely, a new trap may contain oil that is older than itself. Suppose that anticline D forms between TIME 2 and TIME 3. The "old" oil spilling from anticlines A, B, and C can then accumulate in the new trap, D.

TIME 1

TIME 2

TIME 3


Usually there is some correspondence between the age of the trap and the age of the oil, because source and reservoir rocks tend to be fairly close together and subject to similar stresses. The stress that deforms a reservoir bed to produce a petroleum trap may also bring about the generation and primary migration of hydrocarbons from nearby source rocks.

Whether or not an accumulation of hydrocarbons is preserved depends upon many factors. Fissuring or a sealing formation under bending stress; changes in porosity and permeability of limestone due to leaching or dolomitization; excessive heat and pressure imposed on a reservoir beneath accumulating sediments - these are a few of the many circumstances in which petroleum that was generated through most of the history of the planet has failed to survive to the present. The oil and gas produced today are only remnants of a much greater resource, most of which has disappeared.

Spared the effects of excessive heat and pressure, bacterial decomposition, diagenetic destruction, and uplift and erosion, a pool of petroleum may endure for many millions of years. Most of the world's known oil reserves are found in Mesozoic formations (65 to 225 million years old); smaller amounts are found in Paleozoic rocks (up to ~ 500 million years old) or Cenozoic rocks (less than 65 million years old).

Conclusion The petroleum geologist's job is finding oil and gas that can be produced for commercial profit. Most of what he needs to know in the performance of his duties is hidden beneath the surface. But he has access to powerful tools and techniques for revealing the secrets of the earth's crust, and special ways of analyzing this information that enable him to find the best places to drill exploratory wells and to help his company make risk decisions. To the geologist's trained eye and mind, the same rocks that hide the resource also provide subtle clues about its location.


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Directional Surveying FundamentalsDirectional Surveying Fundamentals

Spring 2002Spring 2002CalgaryCalgary

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Introduction to Well ProfilesIntroduction to Well Profiles

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Vertical WellsVertical Wells

•• Inclination Below 3Inclination Below 3oo

DegreesDegrees

2

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Directional WellsDirectional Wells

•• SlantSlant•• Build and Build and

Hold Hold •• SS--CurveCurve•• Extended Extended

ReachReach•• HorizontalHorizontal

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Purpose of Directional WellsPurpose of Directional Wells

•• To obtain production from inaccessible locations, To obtain production from inaccessible locations, such as under populated areas, river beds, plants, such as under populated areas, river beds, plants, and roads.and roads.

•• To sidetrack a vertical well bore, either upTo sidetrack a vertical well bore, either up--dip or dip or downdown--dip, to seek the oil bearing formations after dip, to seek the oil bearing formations after the original well drilled into water or gas.the original well drilled into water or gas.

•• To reduce the cost of offshore drilling and To reduce the cost of offshore drilling and production by drilling a large number of directional production by drilling a large number of directional wells from one platform or island.wells from one platform or island.

•• To provide fault controlTo provide fault control•• To drill a relief well to kill a well blowing out of To drill a relief well to kill a well blowing out of

control.control.

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Surveying Measurements to Surveying Measurements to Determine Borehole Location Determine Borehole Location •• InclinationInclination

•• AzimuthAzimuth•• Gravity Gravity ToolfaceToolface•• Magnetic Magnetic ToolfaceToolface

3

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Surveying MeasurementsSurveying Measurements

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Surveying MeasurementsSurveying Measurements•• Measures Local GravityMeasures Local Gravity•• Typically TriTypically Tri--axial Packagingaxial Packaging

ACCELERATION

ACCELEROMETER

UPPER MAGNET

TORQUER COIL

CHEMICALLY MILLEDHINGE

LEAD SUPPORT POSTS

LOWER MAGNET

QUARTZ PROOF MASS

CAPACITANCEPICKOFF

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Surveying MeasurementsSurveying Measurements•• Measures Local Magnetic FieldMeasures Local Magnetic Field

•• Typically TriTypically Tri--axial Packagingaxial Packaging

4

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The EarthThe Earth’’s Gravitational Fields Gravitational Field

•• The gravitational field (G) is primarily a function of:The gravitational field (G) is primarily a function of:•• Latitude (main factor)Latitude (main factor)•• Depth/Altitude: referenced to mean sea level (MSL)Depth/Altitude: referenced to mean sea level (MSL)•• Regional fluctuations in the density of the EarthRegional fluctuations in the density of the Earth’’s crusts crust

Mathematically:Mathematically:g g == G x m x Me / rG x m x Me / r22

gg == attractive forceattractive forceGG == Universal Gravitational ConstantUniversal Gravitational Constantmm == massmassMeMe == mass of the Earthmass of the Earthrr == radius between centersradius between centers

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Magnetic FieldsMagnetic Fields

•• The Earth is a The Earth is a MagnetMagnet

•• Positive & Positive & Negative PolesNegative Poles

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Magnetic FieldsMagnetic Fields

5

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Magnetic Field StrengthMagnetic Field Strength

1 gamma 1 gamma = = 1 1 Nanotesla Nanotesla = = 1 x 101 x 10--99 TeslaTesla

1 1 microtesla microtesla = = 1 x 101 x 10--66 Tesla =Tesla = 1000 gammas1000 gammas

1 1 tesla tesla == 1 x 101 x 1099 gammasgammas

1 gauss1 gauss == 1 x 101 x 1055 gammasgammas

1 gauss1 gauss == 1 x 101 x 10--44 TeslaTesla

1 gauss1 gauss == 1 1 oerstedoersted

1 1 tesla tesla == 1 1 newtonnewton / ampere * meter/ ampere * meter

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EarthEarth’’s Magnetic Fields Magnetic Field

•• Total Magnetic FieldTotal Magnetic Field•• HorizontalHorizontal•• VerticalVertical

•• Magnetic Dip AngleMagnetic Dip Angle

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Magnetic Declination AngleMagnetic Declination Angle

•• TnTn = = MnMn + M Dec+ M Dec

•• East Dec is +East Dec is +

•• West Dec is West Dec is --

6

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Magnetic Declination AngleMagnetic Declination Angle

•• Zero DeclinationZero Declination•• Central MeridiansCentral Meridians

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Azimuth ReferencesAzimuth References

•• UTMUTM•• State PlaneState Plane

•• Grid NorthGrid North•• GnGn = = TnTn –– ConvergenceConvergence

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Grid SystemsGrid Systems

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Geographic DatumGeographic Datum

•• NADNAD•• GRSGRS•• WGSWGS•• ClarkeClarke

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Transverse Cylindrical Map ProjectionTransverse Cylindrical Map Projection

•• UTM UTM Most commonly Most commonly

usedused

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Map ProjectionsMap Projections

LambertLambert

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UTM Grid ZoneUTM Grid Zone

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Transverse Transverse MercatorMercator ProjectionProjection

•• Slight Improvement over Slight Improvement over UTM ProjectionUTM Projection

•• Seldom used in the drilling Seldom used in the drilling industryindustry

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Lambert Conformal Conic Map Lambert Conformal Conic Map ProjectionProjection

•• Used to map regions Used to map regions with vast east / west with vast east / west expanseexpanse

9

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Magnetic Declination CorrectionsMagnetic Declination Corrections

•• True North is the fixed True North is the fixed referencereference

•• Magnetic Declination Magnetic Declination Corrects from Corrects from MnMn to to Tn Tn

•• East Dec is + valueEast Dec is + value•• West Dec is West Dec is -- valuevalue

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Magnetic DeclinationMagnetic Declination

•• Magnetic North Magnetic North continues to movecontinues to move

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The Geomagnetic FieldThe Geomagnetic Field

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Global ModelsGlobal Models

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Geomagnetic SoftwareGeomagnetic Software

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Magnetic Pole MovementMagnetic Pole Movement

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Surveying DevicesSurveying Devices

•• Acid Etch InclinometerAcid Etch Inclinometer•• Compass Single ShotCompass Single Shot•• TotcoTotco –– InclinationInclination•• Electronic MWDElectronic MWD•• GyroscopesGyroscopes

•• InclinationInclination•• AzimuthAzimuth•• Gravity Gravity ToolfaceToolface•• Magnetic Magnetic ToolfaceToolface•• TemperatureTemperature

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Hole Position CalculationsHole Position Calculations

Inputs:Inputs:•• Measured DepthMeasured Depth•• InclinationInclination•• AzimuthAzimuth

Outputs:Outputs:•• True Vertical DepthTrue Vertical Depth•• LatitudeLatitude•• DepartureDeparture•• Vertical SectionVertical Section

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Average Angle Calculation MethodAverage Angle Calculation Method

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Radius of Curvature Calculation MethodRadius of Curvature Calculation Method

•• Applies a “best fit” Applies a “best fit” curve between survey curve between survey stationsstations

•• More accurately More accurately reflects the shape of reflects the shape of the borehole than the borehole than Average AngleAverage Angle

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Minimum Curvature CalculationsMinimum Curvature Calculations

•• Uses multiple points Uses multiple points between survey stations between survey stations to better reflect the to better reflect the shape of the boreholeshape of the borehole

•• More accurate than the More accurate than the Radius of Curvature Radius of Curvature method method

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Comparison of AccuracyComparison of Accuracy

•• Minimum Curvature most commonly usedMinimum Curvature most commonly used

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Vertical ProjectionVertical Projection

KOP

TVD

Vertical Section

Tangent

Build Section

Locked in Section

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Horizontal ProjectionHorizontal Projection

N

E

Latitude

Departure

Proposal Direction

Closure

Vertical Section Calculated on Proposal Direction

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Closure and Vertical SectionClosure and Vertical Section



DIRECTIONAL SURVEYING FUNDAMENTALS

Introduction to Directional Well Profiles In the early days of drilling, no one worried about hole deviation. The objective was to get the well drilled down, completed and producing as quickly as possible. Many drilling personnel assumed the wells were straight - others simply did not care.

Subsequently, wells were deliberately drilled in some unknown direction. This began as a remedial operation to solve a drilling problem - usually a fish or junk left in the hole. Today, with the advent of tighter legal spacing requirements, better reservoir engineering modelling and drilling of multiple wells from a single surface location, it has become very important to both control the wellbore position during drilling and to relate the position of existing wellbores to lease boundaries, other wells, etc.

The development of the skills and equipment necessary to direct these wellbores is the science of directional drilling. Directional Drilling is the science of directing a wellbore along a predetermined path called a trajectory to intersect a previously designated sub-surface target. Implicit in this definition is the fact that both the direction and the deviation from vertical are controlled by the directional driller from the surface.

Vertical Wells

The term straight hole loosely describes a borehole that a drilling contractor has drilled vertically, from top to bottom. In reality, practically all wellbores deviate from the vertical. It is virtually impossible to drill a perfectly straight hole. Drilling contracts recognize this fact and allow a variation from the strict term. A better description of modern drilling practices is controlled deviation drilling because industry now accepts a straight hole as one that meets two qualifications:

• The hole stays within the boundary of a cone, as designated by the operator in the deviation clause of the contract. The total hole angle is therefore restricted.

• The hole does not change direction rapidly, usually no more than 3 degrees per 100 ft (30 m) of hole. The rate of hole angle changes is therefore restricted.

Staying within these allowable parameters, the contractor’s main objective is to deliver a straight and usable hole to the specified depth. The usable borehole should be full gauge, smooth, free of doglegs, keyseats, ledges, offsets, and spirals that permit completion and production operations that are free of trouble.


DIRECTIONAL WELLS

In order to reach the required downhole target coordinates there are several main profiles used; Slant, Build and Hold, S-curve, Extended Reach, and Horizontal. These profiles may also be combined as required to reach the target or targets.

Slant Specialized drilling and completion rigs are used on these profiles. The well is spudded at an angle greater than 0o and less than or equal to 45o. This profile is typically used on shallow wells when trying to reach a target with a horizontal displacement that is 50% or more of the TVD. It is also used on multiple well pad sites to drain a large area with several wells radiating out from a central site. The most common pattern is the star-shaped layout, which allows for as many as 27 wells to be drilled from one site. The savings on reduced lease requirements and production facilities can be quite substantial.

Build and hold This is the main profile for most directional wells. It includes a build section to a predetermined terminal angle that is then held through the target and in some cases to total depth. In most cases once the target has been reached or there is no risk of missing the target the directional tools are released and the remainder of the hole is rotary drilled allowing the well path to follow a natural direction. The inclination is usually 15o or better.

S-Curve The S-curve has a build, hold and drop section that may or may not drop the inclination down to 0 degrees. This shape is for the following reasons:

• Hit multiple targets at the same horizontal displacement

• Reach a desired horizontal displacement but allow drilling through severely faulted or troublesome formations in a near vertical mode

• Avoid local faulted regions

• Minimize the inclination through a zone that will be fractured during the completion phase.


Extended Reach A modified or complex build and hold that typically has an inclination between 60 and 80 degrees with a reach that is magnitudes of the TVD (between 4 and 7 times the vertical depth). Most common location for these wells is offshore from a central drilling platform.

Horizontal with Single or Multiple Legs

A profile that consists of a build section to approximately 90o with a horizontal section through the same reservoir. Additional laterals can be drilled from the first lateral into different regions or into different zones.

GRAVITATIONAL AND MAGNETIC FIELDS

While measurement while drilling (MWD) tools are in wide use today many other types of surveying equipment are still in use on various directional projects. Before describing the different types of surveying equipment it is important to have a basic understanding of magnetics.

The Earth’s Gravitational Field

According to Newton’s Law of Gravitation, every particle of matter in the universe attracts every other particle with a force which is directly proportional to the product of the masses and inversely proportional to the square of the distance between them.

Mathematically:

g = G x m x Me / r2 g = attractive force G = Universal Gravitational Constant m = mass Me = mass of the Earth r = radius between centres

The gravitational field (G) is primarily a function of:

• Latitude (main factor).

• Depth/Altitude: referenced to mean sea level (MSL)

• Regional fluctuations in the density of the Earth’s crust.

Some of the changes in the measured value of G over the Earth are attributed to the Earth’s rotation. The rotation has given the Earth a slightly flattened shape. Therefore, the equatorial radius is larger than the polar radius. The G value changes from 0.997 at 0 degree latitude (Equator) to approximately 1.003 at 90 degree latitude (a 0.006 change).

A decrease in G can also be seen with increasing hole depth. The rate of change is approximately 0.0005 per 10,000 feet. You would have to be at 20,000 feet to see 0.001. Regional fluctuations in the density of the Earth’s crust are practically negligible.


Magnetic Fields Our understanding of earth magnetism is based on ideas about how magnets interact with one another and about how magnetism is produced. The eighteenth century French physicist Charles Coulomb described the interaction of magnets in terms of forces acting at points called magnetic poles. Every magnet possesses a positive pole and a negative pole, so named because of their opposite effects on the poles of another magnet. As the like poles of two magnets exert a repelling force on one another, the unlike poles exert a force of attraction.

The two poles of a magnet act oppositely but with equal pole strength. It is not possible to separate or extract either of these poles. To break a magnet is to immediately create two new magnets, each with a positive pole and a negative pole. For this reason, we commonly use the word dipole to describe a magnet.

Metals that are strongly attracted by magnets are said to be ferromagnetic. Such materials have magnetism induced in them when they are near a magnet. If a piece of iron is brought near the south pole of a magnet, the part of the iron nearest the magnet has a north pole induced in it, and the part farthest away has a south pole induced in it. Once the iron is removed from the vicinity of the magnet, it loses most of the induced magnetism. Some ferromagnetic metals actually retain the magnetism induce in them, that is they become permanent magnets. Regular magnets and compass needles are made of such metals. Ferromagnetism is also the basis of magnetic tape recording.

It is useful to employ the concept of a field to represent the effect of a magnet on the space around it. A magnetic field is produced by a magnet and acts as the agent of the magnetic force. The poles of a second magnet experience forces when in the magnetic field: its north pole has a force in the same direction as the magnetic field, while its south pole has a force in the opposite direction. A compass can be though of as a magnetic field detector because its needle will align itself with a magnetic field. The shape of the magnetic field produced by a magnet can be mapped by noting the orientation of a compass at various places nearby. Magnetic field lines can be drawn to show the shape of the field. The direction of a field line at a particular place is the direction that the North Pole of a compass needle will point.

There are several theories to explain the Earth’s magnetic field:

Theory #1: Rotation of the Earth’s solid exterior relative to its liquid iron core is believed to induce a slow rotation of the core. A magnetic field results from the electrical currents generated by the relative motion between the liquid core and the mantle.


Theory #2: The center portion of the Earth is largely composed of iron and has the mechanical properties of a fluid. These fluids are subjected to internal circulation currents similar to phenomena observed at the periphery of the sun. The internal circulation of these fluids acts as the source of the Earth’s magnetic field.

In any event it appears that some mechanism is stirring up the core and causing fluid motion. These motions combine in a particular pattern to give rise to the dipole field, which is observed at the earth’s surface.

The total magnetic field is the sum of two fields of different origins:

• The principal field which originates within the fluid nucleus of the Earth And

• The transitory field, which is generated outside the Earth. This field is caused by the rotation of the Earth relative to the Sun and by the cycles of the Sun’s activity.

Aspects Of The Transitory Field The transitory field is responsible for the following variations of the magnetic field.

• Secular variations of approximately 15 gammas per year - a minor effect.

• Diurnal solar variation on the order of 30 to 40 gammas per day — a minor effect.

• The cyclical “Eleven Years” variation – a minor effect.

• Magnetic storms which may reach several hundreds of gammas - a major effect.

The Earth’s own magnetic field extends out to approximately 8 times the radius of the planet. Beyond this prevails the Magneto Pause, a region in space where the Earth’s magnetic field contacts the solar wind. On its sunward side, the Earth’s magnetosphere is compressed by high- energy particles from the solar wind.

These particles collide with the Earth’s magnetic field at a speed of 640 miles per second and are slowed down at the shock front to 400 miles per second. Variations in the solar wind produce changes in the Earth’s magnetic field. Solar flare particles reach the Earth in approximately two days. The shock wave preceding the cloud of plasma from the solar flare compresses the magnetosphere and rapidly intensifies the geomagnetic field at ground level.

Fluctuations in the Earth’s magnetic field


This compression takes place over a few minutes and is called the Sudden Storm Commencement. It is followed by the Initial Phase, which lasts from 30 minutes to a few hours. The Main Phase produces a drop in the magnetic field strength due to an opposing field generated by the energized particles in the magnetosphere. This is normally not a problem for locations in the Gulf of Mexico and at lower latitudes. In Alaska and some parts of the North Sea, however, this has serious effects.

Magnetic Field Strength The total magnetic field strength may be referred to as the H value, HFH, magnetic field strength or TTL field. The Geological Society Electromagnetic Units are used for measuring the strength of the Earth’s magnetic field and are called Gammas. Some useful conversions:

1 gamma = 1 Nanotesla = 1 x 10-9 Tesla 1 microtesla = 1 x 10-6 Tesla = 1000 gammas 1 tesla = 1 x 109 gammas 1 gauss = 1 x 105 gammas 1 gauss = 1 x 10-4 Tesla 1 gauss = 1 oersted 1 tesla = 1 newton / ampere * meter

The magnetic field intensity recorded at ground level is of a much smaller magnitude than that prevailing around the Earth’s core. At the periphery of the core (approximately 3500 kilometers outward from the centre of the Earth), the field strength reaches 800,000 gammas. Extreme total field values at the surface which you are unlikely to see range from 63,000 gammas close to the North Pole to 27,000 gammas near the equator (magnetic field intensity is greater at the North Pole then the equator).

The total magnetic field intensity is the vector sum of its horizontal component and its vertical component. The vertical component of the magnetic field points toward the ground and therefore contributes nothing to the determination of the direction of magnetic north.

The horizontal component of the magnetic field strength can be calculated from the following equation:

Horizontal Component = Magnetic Field Strength (HFH) x COS(Magnetic Dip Angle)

Some common values of total magnetic field strength are:

• Gulf of Mexico = 50,000 gammas

• Eastern Canada = 54,000 gammas

• Beaufort Sea = 58,500 gammas

• North Sea = 50,000 gammas


The Magnetic Dip Angle is equal to the angle between tangent to Earth’s surface and magnetic field vector (magnetic North). Extreme values which you are not likely to see for Dip Angle range from 90 degrees close to the North Pole to almost 0 degrees at the equator. There are also several other points on the Earth’s surface where the dip is equal to 90 degrees. These are due to local anomalies and are called dip holes. Some common relative values for dip angle:

Gulf of Mexico = 59 degrees

Eastern Canada = 70 degrees

Beaufort sea = 84 degrees

North Sea = 70 degrees

Example horizontal component calculations:

For Alaska:

• 57,510 gammas x COS(80.6o) = 9392 gammas For Gulf of Mexico:

• 50,450 gammas x COS(59.70o) = 25,250 gammas

MWD instruments measure the three components of the magnetic field vector, H. The expected value can be obtained from a previous acceptable survey or from a Geomagnetic software program. Differences observed between the measured magnetic field strength value and the value from the Geomagnetic software program may be due to:

• Uncertainties in drill string magnetism.

• Uncertainties induced by temporal variations in the magnetic field.

• Uncertainty in the measured value of the magnetic field.

• Temperature sensitivity of the magnetometers.

• Errors from the tool electronics.

Magnetic Declination Angle The Earth can be thought of as having a magnetic dipole running through its center with north and south poles at either end. This dipole does not correspond with the Earth’s rotational axis (tilted approximately 12o relative to earth’s axis of rotation). The angle between magnetic north and geographic north (True North) is defined as the magnetic declination or the angle of declination (refer to illustration). The magnetic declination is dependent upon the location (latitude and longitude) and may vary in areas of high magnetic activity (such as Alaska). All magnetic surveys require a conversion to geographic direction by adding or subtracting this angle. Knowing magnetic declination, the direction of the Earth’s magnetic field relative to True North can be calculated.


Magnetic declination angle

Magnetic declination can vary and the total magnetic field strength may vary greatly during extreme sun spot activity. Also, the closer to the equator:

• the lower the total field strength

• the higher the horizontal component

• the less the dip angle

All survey systems/plots are measured relative to True North (geographic north). Survey tool measurements are made relative to Magnetic North (necessary to adjust for magnetic declination).

Magnetic Declination Correction: EAST + Correction to Azimuth

WEST - Correction to Azimuth

When dealing with magnetic survey bearing or azimuth values expressed between 0 and 360 degrees, the magnetic declination is always added since the East or West value for the declination will adjust itself. For example survey reads 120o and the magnetic declination is 20o West, corrected bearing is 120 + (-20) = 100o.


Directional Drilling Azimuth Reference Systems

This section discusses the primary azimuth reference systems currently used in directional drilling. This will include True North and Magnetic references with particular detail given to Grid Coordinate systems (i.e. UTM, Lambert, Geographic, and Local). A simple field-proven method is also presented to help avoid confusion when converting from one system to another. More than one multi-million dollar directional drilling project has missed its intended target(s) due to errors and/or misunderstandings surrounding the azimuth reference system in use.

The confusion arises primarily from the necessity to change from one system to another between the well planning phase, where most maps are drawn with respect to a local Grid North, and the drilling phase where surveying is performed with respect to a Magnetic or True North reference. The field company representative is faced with a confusing array of possible conversions, including declination corrections from Magnetic North to True North, True North to Grid North, Magnetic to Grid North, or Grid to Magnetic North. Is the correction to be added or subtracted from the survey measurement? Is

the convergence magnitude and sign correct for the grid system used?

With all these questions, it is easy to see why this seemingly simple task is often performed improperly and the mistake not realized until the target is missed. The rig foreman often passes on the responsibility for field convergence application to the service company supplying the surveys or to the directional driller. While this practice may appear sound in theory, it usually creates additional confusion as basic information is often poorly communicated or misconstrued. It is not uncommon that on projects where several service companies perform different surveys (i.e. MWD, single shots, multi-shots, and gyros) that each supplier comes up with a different convergence value.

A case in point involved a recent high visibility multi-million dollar directional drilling project. In this incident, a well known well planning company drew the well maps with respect to the local grid coordinate system, with a footnote stipulating that the directional contractor would be responsible for grid and magnetic declination convergence. When the operation began, the rig site was manned by a company representative, two consulting drilling engineers, and a directional driller all responsible for deviation control.

The directional company was not accustomed to deriving grid corrections and solicited help from the


company representative. He assumed the local grid was UTM (later learned to be state plane) and the appropriate UTM convergence was applied. He then had the directional company’s office redraw the well maps rotated by that UTM correction. The office complied and added in the magnetic declination as well. The directional driller missed this fact, however, and continued to apply a declination correction at the rig site as drilling continued. It was not until the project was completed and the target missed that the errors were realized.

This project was more closely supervised than a normal directional well, yet it serves as a classic example of how easily the relative relationships between coordinate systems can be poorly communicated and inappropriately applied. The remainder of this paper will examine methods to reduce these azimuth convergence errors by utilizing field experience and suggested communication procedures between all involved parties.

Azimuth References Azimuth, (AZ) used in directional drilling, may be defined as the direction of the wellbore (at a given point) projected into the horizontal plane measured in a clockwise direction from Magnetic North, True North or Grid North after applying a North Reference system.

Azimuth should be expressed as a value on a 0°-360o compass system. Quadrant or bearing systems (i.e. N45° 20’E) may be easier to visualize, but make the probability of convergence mistakes higher than in an azimuth system. It is therefore recommended to have all survey printouts converted to an azimuth system when making initial convergence corrections.

For directional drilling and borehole surveying, there are three primary azimuth references. They are Magnetic North (MN), True (Geographic) North (TN), and Grid North (GN).

Magnetic North is the direction of the horizontal component of the earth’s magnetic field lines at a

particular point on the earth’s surface pointing to the magnetic pole. A magnetic compass will align itself to these lines with the positive pole of the compass indicating North. Magnetic North is usually symbolized on maps by a half arrowhead or the letters MN.

True or Geographic North is the horizontal direction from a point on the earth’s surface to the geographic North Pole, which lien on the earths axis of rotation. The direction is shown on a globe by meridians of longitude. True North i.e. normally symbolized on maps by a star at the tip of the arrow or the letters TN.

Grid North is a reference system devised by map markers in “the complicated task of transferring the curved surface of the earth onto a flat sheet. The meridians of longitude on a globe converge toward the North Pole and therefore do not produce a rectangular grid system. A map can be drawn such that


the grid lines are rectangular, for some specified area of the earth, the northerly direction of which is determined by one specified meridian of longitude. This direction is called Grid North and is identical to True North only for that specified central meridian. It is normally symbolized on a map by the letters “GN” at the tip of the arrow.

Grid Systems One of the oldest systematic methods of location is based upon the geographic coordinate system. While this information is basic, a short review is included for reference. By drawing a set of east-west rings around the globe (parallel to the equator), and a set of north- south rings crossing the equator at right angles and converging at the poles, a network of reference lines is formed from which any point on the earth’s surface can be located.

The distance of a point north or south of the equator is known as latitude. The rings around the earth parallel to the equator are called parallels of latitude or simply parallels. Lines of latitude run east-west, with north-south distances measured between them. A second set of rings around the globe at

right angles to lines of latitude and passing through the poles are known as meridians of longitude or simply meridians. One meridian is designated as the prime meridian. The prime meridian accepted by the majority of the world runs through Greenwich, England, and is known as the Greenwich meridian.


The distance east or west of a prime meridian to a point is known as longitude. Lines of longitude (meridians) run north-south, with east-west distances measured between them. Geographic coordinates are expressed angular measurement. Each circle is divided into 360°, each degree into 60 minutes, and each minute into 60 seconds.

The degree is symbolized by (0), the minute by (’), and the second by (‘’). Starting with 0° at the equator, the parallels of latitude are numbered to 90° both north and south. The extremities are the North Pole at 90° north latitude and the South Pole at 90° south latitude. Latitude can have the same numerical value north or south of the equator, so the direction N or S must always be given. It can also be further defined as Geographic/Geodetic or Geocentric Latitude.

Geodetic is the angle that a line perpendicular to the surface of the earth makes with the plane of the equator. It is slightly greater in magnitude than the Geocentric latitude, except at the equator and poles where it is the same due to the earth’s ellipsoidal shape. The Geocentric latitude is the angle made by a line to the center of the earth at the equatorial plane.

Starting with 0° at the prime meridian, longitude is measured both east and west around the world. Lines east of the prime meridian are numbered to 0° to +180° and identified as east longitude: lines west of the prime meridian are numbered to 0° to -180° and identified as west longitude. The direction E (+) or W (-) must always be given. The line directly opposite the prime meridian, 180°, may be referred to as either east or west longitude.

Geographic Datum

For most atlas maps and any directional drilling map, the earth may be considered a sphere. Actually it more nearly resembles an oblate ellipsoid flattened by approximately one part in three hundred at the poles due to rotation. On small-scale maps this oblateness is negligible. However, different ellipsoids will produce slightly different coordinates for the same point on the earth and therefore warrant a brief summary.

More than a dozen principal ellipsoids have been measured in the past two hundred years, which are still in use by one or more countries. An official shape was designated in 1924 by the International Union of Geodesy and Geophysics (IUGG) and adopted a flattening ratio of exactly one part in 297. This was called the International Ellipsoid and was based on Hayford’s calculations in 1909 giving an equatorial radius of 6,378,388 meters and a polar radius of 6,356,911,9 meters. Many countries did not adopt this ellipsoid however, including those in North America. The different dimensions of the other established ellipsoids are not only the result of varying uncertainties in the Geodetic measurements that were made, but also are due to a non-uniform curvature of the earth’s surface due to irregularities in the gravity field. It is for this reason that a particular ellipsoid will be slightly more accurate in the areas it was measured, rather than using a generalized ellipsoid for the whole earth. This also includes satellite-derived ellipsoids such as WGS72. The following table illustrates some of the official ellipsoids in use today.


Equatorial Radius,a, PolarRadius Flattening Name Date Meters b, metere f Use GRS 19802 1980 6,378,137 6,356,752.3 1/298.257 Newly adopted WGS 723 1972 6,378,135 6,356,750.5 1/298.26 NASA Australian 1965 6,378,160 6,356,774.7 1/298.25 Australia Krasovaky 1940 6,378,245 6,356,863.0 1/298.25 Soviet Union Internat’1 1924 6,378,388 6,356,911.9 l/297 Remainder of the world Hayford 1909 6,378,388 6,356,911.9 1/297 Remainder of the world Clarke 1880 6,378,249.1 6,356,514.9 1/293.46 Most of Africa; France Clarke 1866 6,378,206.4 6,356,583.8 1/294.98 NA; Philippines Map Projections. A map projection is a method of transferring part or all of a round body on to a flat sheet. Since the surface of a sphere cannot be represented accurately on a flat sheet without distortion the cartographer must choose characteristics he wishes to display precisely at the expense of others. There is consequently no best method of projection for map making in general. Different applications require different projections.

Some characteristics normally considered in choosing a particular projection are: true shape of physical features, equal area, true scale and size, great circles as straight lines, rhomb (compass point)

lines as straight lines, and correct angular relationships. A map of relatively small size, such as a directional well path, will closely achieve most or all of these characteristics with any method of projection.

Map projections are generally classified with respect to their method of construction in accordance with the developable surface from which they were devised, the most common being cylindrical, conical, and planer.

An examination of these projections shows that most lines of latitude and longitude are curved. The quadrangles formed by the intersection of these curved parallels and meridians are of different sizes and shapes, complicating the location of points and the measurement of directions. To facilitate these essential operations, a rectangular grid maybe superimposed upon the projection.

Universal Transverse Mercator Grid (UTM). The most common worldwide grid system used in directional drilling is the UTM. The U.S. Army adopted this system in 1947 for designating rectangular coordinates on large


scale military maps of the entire world. The UTM is based on the Cylindrical Transverse Mercator Conformal Projection, developed by Johann Lambert in 1772, to which specific parameters have been applied, such as central meridians.

The UTM divides the world into 60 equal zones (6° wide) between latitude 84°N and latitude 80°S. Polar regions are normally covered by a separate planer projection system known as Universal Polar Stereo-graphic. Each of the 60 zones has its own origin at the intersection of its central meridian and the equator. The grid is identified in all 60 zones. Each grid is numbered, beginning with zone 1 at the 180th Meridian, International Date Line, with zone numbers increasing to the east. Most of the North America is included in Zones 10-19. Each zone is flattened and a square grid superimposed upon it.

Any point in the zone may be referenced by citing its zone number, its distance in meters from the equator (“northing”) and its distance in meters from a north-south reference line (’easting”). These three components: the zone number, easting and northing make up the complete UTM Grid Reference for any point, and distinguish it from any other point on earth. The Figure below shows a zone, its shape somewhat exaggerated, with its most important features. Note that when drawn on a flat map, its outer edges are curves, (since they follow meridian lines on the globe), which are farther apart at the equator than at the poles.

UTM zones are sometimes further divided into grid sectors although this is not essential for point identification. These sectors are bounded by quadrangles formed every 8° in latitude both north and south and are designated by letters starting with C at 80° South to X at 72° North, excluding I and O. Dallas for example is in grid zone 14s covering a quadrangle from 96° to 102°W and from 32° to 40°N. Sectors may be further divided into grid Squares of 100,000 meters on a side with double letter designations including partial squares of 10,000 meters, 1,000 meters and 100 meters designated by numbers and letters.

The two most important features of the zones are the equator, which run east and west through its center, and the central meridian. Easting and northing measurements are based on these two lines. The easting of a point represents its distance in meters from the central meridian of the zone in which it lies. The northing of a point represents its distance in meters from the equator.

By common agreement, there are no negative numbers for the castings of


points west of the central meridian. Instead of assigning a value of 0 meters to the central meridian of each zone, each is assigned an arbitrary value of 500,000 meters, increasing to the east.

Since along the equator at their widest points, the zones somewhat exceed 600,000 meters from west to east, easting values range from approximately 200,000 meters to approximately 800,000 meters at the equator, with no negative values. The range of possible casting values narrows as the zones narrow toward the poles. Northings for points north of the equator are measured directly in meters, beginning with a value of zero at the equator and increasing to the north. To avoid negative northing values for

points south of the equator, the equator is arbitrarily assigned a value of 10 million meters, and points are measured with decreasing, but positive, northing values heading southward. Some maps, particularly in the U.S., have converted UTM coordinates from meters to feet.

In utilizing the Transverse Mercator Projection, the central UTM meridian has been reduced in scale by 0.9996 of True to minimize variation in a given zone. This scale factor (grid distance/true distance) changes slightly as you move away from the central meridian and should be considered if very accurate measurements are desired. However, this error is very small in directional drilling maps and is usually ignored.

Approximately 60 countries use the UTM as the most authoritative and general use projection within the world, although some also use secondary local projections and grid references. The Russia, China and other European countries use the Transverse Mercator (Gauss-Kriiger) with 6° zones. Approximately 50 countries use other projections. Lambert Conformal Conic Projection. The Lambert System is based on a conformal conic projection and is particularly useful in mapping regions that have a predominately east-west expanse. This system has heavy use in North America and is the official U.S.


state plane coordinate system for more than half of the 48 contiguous states, including the majority of those where oil is drilled and produced (i.e. Texas, Louisiana, Oklahoma, California, Colorado, Kansas, Utah, and Michigan). The remainder of the states, including Wyoming, uses the Transverse Mercator with Alaska using a combination.

This projection was first described by Lambert in 1772, but received little use until the First World War where France revived it for battle maps. The features of this conic projection include:

• Parallels of latitude are unequally spaced arcs of concentric circles

• Meridians of longitude are equally spaced radii cutting the parallels at right angles

• Scale is normally true along two defined parallels, but can be true along one

• Pole in same hemisphere is a point, other pole is at infinity

Since there is no distortion at the parallels, it is possible to change the “standard parallels” to another pair by changing the scale applied to the existing map and recalculating standards to fit the new scale. Each state or area has it’s own standard parallels, or sets of the same depending on its size, to reduce distortion at the center. For example, Louisiana is divided into three zones as shown in the Table below.

Long. Lat. North 31° 10* N 32° 40t N 92° 301 w 30° 401 N South 29° 18’ 3C” 42* 91° 201 28° 40’ Offshore 26° 10’ 27° 501 91° 201 25° 40’ The grid origins for most states are measured in feet, with the east-west axis starting at 2,000,000 feet and the north-south axis set at 0 feet.

Local Grid systems. There are numerous local grid systems in use around the world today. These systems all have different base line coordinates and projections, covering different sizes of surface areas, but all serve the same basic purpose as outlined for UTM and Lambert. In the U.S. lease lines often are used as a convenient grid reference, as well as other privately surveyed grids. Outside the U.S., local grids are used in Holland, the U.K., Brunei, Australia, and other countries. Several countries have also shifted the starting of the UTM grid zones to fall inside their own territory.

In some situations when using standard grid coordinates, the well’s target location may lie in a different zone from the surface location. In these cases creating a nonstandard zone normally produces a special local grid. This is done by either extending the surface location zone by a few miles to include the target, or shifting the zone center, as sometimes is done with UTM, 3° to the zone boundary.

Azimuth Reference System Conversions Most well proposals are generated from rectangular coordinates derived from the UTM or local grid system. The surface location to target direction will therefore be referenced to Grid North. Since wells must be surveyed with sensors that reference direction to either Magnetic or True North, it will be necessary to convert between these references.


Magnetic Declination Correction

Magnetic declination correction converts azimuth values between the Magnetic North and True North systems. The magnetic declination correction is the angle between the horizontal component of the earth’s magnetic field lines and the lines of longitude. When Magnetic North lies to the west of True North, the magnetic declination is said to be westerly, and if to the east, easterly.

Values of magnetic declination change with time and location. Magnetic Declination

models are updated every year. Their values and rates of change can be obtained from Computer programs like GEOMAG or “world magnetic variation charts” or “isogonic charts” which are issued by all major hydrographic institutes in the world once every five years (1980, 1985, ’90, etc.). Computer programs like GEOMAG use current magnetic models and calculate up-to-date local declination figures. The most accurate method to determine local declination is to measure the magnetic field with a magnetic transit.

When magnetic results are recorded, the declination and the date must be included. Local values of magnetic declination should be stated in the well program to plus or minus 0.1O.

Grid Correction Angle. A grid correction converts azimuth readings between the True North systems and the specified grid system. The angle of correction is the angle between the meridians of longitude and the Northings of the grid system at a specified point. The magnitude of the correction

angle depends upon its location within the grid and its latitude. The closer the point is to the grid central meridian and to the equator, the smaller the correction.

The computation of the grid correction angle or angle of convergence will require special mathematical techniques depending on the type of projection of the curved earth’s surface on to the flat grid. The directional software packages will at minimum handle UTM and Lambert conformal conic convergence. The chosen sign convention displays Grid North as “x” number of degrees east or west of True North. For example, when you convert the geographic coordinates latitude N 30° 00’ 00” and longitude W 95° 00’ 00” to UTM coordinates (using the Hayford Inter-national - 1924 Ellipsoid), the computer will display the following results:

UTM Coordinates: Hemisphere = North Zone = 15 Northing = 3320517.348 Easting = 307077.096 Grid Convergence = W 1° 0’ 0”


This listing indicates a grid convergence of 1o 00’ 00”. Grid convergence as calculated by the directional software package is the angular difference in degrees between True North and UTM Grid North. UTM Grid North is said to be “X” number of degrees either east or west of True North. When working with the UTM system, the calculated direction between two UTM coordinates is referenced to Grid North. To convert this UTM Grid North direction to a True North direction, you must apply the grid convergence to the calculated UTM Grid North direction. This sign convention is not necessarily the same for all contractors and should be clearly communicated and understood before drilling begins.

System Conversions

Once accurate magnetic declination and grid convergence angles are acquired, all that is needed to change reference systems is to add or subtract these angles from one another. While this seems a simple task, misunderstandings surrounding the relationship between these references can cause a target to be missed. To avoid this confusion, declination/grid conversion polar diagrams should be drawn on all maps and clearly defined on all survey printouts. With this in mind, the following procedure is suggested:

1. Convert quadrant/bearing readings, including declination and grid convergence, to a 0-360 degrees azimuth system.

2. Draw a polar diagram showing True North at 0 degrees azimuth (12 o’clock).

3. Draw an arrow for Magnetic North using an exaggerated angle east or west of True North showing the declination angle (east declination is east of True North and west is west).

4. Draw an arrow for Grid North using an exaggerated angle east or west of True North showing the grid convergence angle (be sure of the sign convention of the grid convergence value used, for example does a west convergence angle put Grid North west of True North or visa versa?).

5. Draw an arrow pointing east (azimuth of 90°) for an arbitrary borehole azimuth reference.

6. Label the borehole azimuth with reference to each system.

True North azimuth will equal 90°; Magnetic azimuth will equal 90° plus/minus declination; Grid azimuth will equal 90° plus/minus grid convergence. With these three references it is a simple matter to determine whether declination and/or convergence need to be added or subtracted to switch from one system to the other.

Communication Accurate communication, both written and oral, is the key to avoiding convergence errors. This function can generally be divided into two or three groups depending on the size of the organization and the complexity of the project.

The initial group will normally consist of seismic crews, geophysical and geology departments, who will be responsible for developing structure maps and choosing targets with respect to a common coordinate system. The next group might be land/hydrographic survey crews, geology, drilling engineering, and a directional service company who might be responsible for developing well plans to the proposed targets from selected surface locations. At this point the grid convergence and magnetic declination angle should be computed, cross checked, and documented on the well prognosis and directional maps using a polar grid convergence diagram. All groups should be in agreement with these values before release to operations. The final group might consist of drilling engineering, operations drilling foremen, and directional drillers who will be responsible for drilling the well to


target as planned. This is the stage where most errors and miscommunication are likely to occur. Never assume the man on the rig will understand your written communications. A meeting should be held, at the rig site if necessary, to assure that all parties understand the map azimuth reference and the magnitude and sense of necessary correction angles.

Magnetic Declination Many people are surprised to learn that a magnetic compass does not normally point to true north. In fact, over most of the Earth it points at some angle east or west of true (geographic) north. The direction in which the compass needle points is referred to as magnetic north, and the angle between magnetic north and the true north direction is called magnetic declination. You will often hear the terms "variation", "magnetic variation", or "compass variation" used in place of magnetic declination, especially by mariners.

The magnetic declination does not remain constant in time. Complex fluid motion in the outer core of the Earth (the molten metallic region that lies from 2800 to 5000 km below the Earth's surface) causes the magnetic field to change slowly with time. This change is known to as secular variation. An example, the accompanying diagram shows how the magnetic declination has changed with time at Halifax. Because of secular variation, declination values shown on old topographic, marine and aeronautical charts need to be updated if they are to be used without large errors. Unfortunately, the annual change corrections given on most of these maps cannot be applied reliably if the maps are more than a few years old since the

secular variation also changes with time in an unpredictable manner. If accurate declination values are needed, and if recent editions of the charts are not available, up-to-date values for Canada may be obtained from the most recent geomagnetic reference field models produced by the Geological Survey of Canada.

The elements iron, nickel and cobalt possess electrons in their outer electron shell but none in the next inner shell. Their electron "spin" magnetic moments are not canceled, thus they are known as ferromagnetic.

Earth's core has remained molten due to heat from ongoing radioactive decay. Convection currents of molten rock containing ferromagnetic material flow in the earth’s outer core generating a magnetic field. The magnetic poles of this field do not coincide with true north and south poles (the axis of rotation of the Earth). In mid 1999, the average position of the modeled magnetic north pole (according to the IGRF-2000 geomagnetic model) is 79.8° N, and 107.0° W, 75 kilometers (45 miles) northwest of Ellef Ringnes Island in the Canadian Arctic. This position is 1140 kilometers (700 miles) from the true (geographic) north pole.


At the magnetic poles, the Earth's magnetic field is perpendicular to the Earth's surface. Consequently, the magnetic dip, or inclination (the angle between the horizontal and the direction of the earth's magnetic field), is 90°. And since the magnetic field is vertical, there is no force in a horizontal direction. Therefore, the magnetic declination, the angle between true geographic north and magnetic north, cannot be determined at the magnetic poles.

The geomagnetic field can be quantified as total intensity, vertical intensity, horizontal intensity, inclination (dip) and declination. The total intensity is the total magnetic field strength, which ranges from about 23 microteslas (equivalent to 23000 nanoteslas or gammas, or 0.23 oersteds or gauss) around Sao Paulo, Brazil to 67 microteslas near the south magnetic pole near Antarctica.


Vertical and Horizontal intensity are components of the total intensity.



The angle of the magnetic field relative to the level ground (tangent to the earth) is the inclination, or dip, which is 90° at the magnetic north pole and 0° at the magnetic equator.


Finally, the angle of the horizontal intensity with respect to the true north (geographic) pole is the declination, also called variation in mariners' and aviators' jargon. In other words, declination is the angle between where a compass needle points and the true North Pole.

If the compass needle points west of true north, this offset is designated as west declination. The world standard, including in the southern hemisphere, is in reference to the magnetic north (MN) declination.

In the context of astronomy or celestial navigation, declination has a different meaning. Along with right ascension, it describes the celestial coordinates of a star, etc.


Do compasses point to the north magnetic pole?

Most people incorrectly believe that a compass needle points to the north magnetic pole. But the Earth's magnetic field reacts to the effect of complex convection currents in the magma, which must be described as several dipoles, each with a different intensity and orientation, the compass actually points to the sum of the effects of these dipoles at your location. In other words, it aligns itself with the local magnetic field lines of force. Other factors, of local and solar origin, further complicate the resulting local magnetic field. It may be all right to say that a compass needle points "magnetic north"

If unlike poles attract, then why doesn't the north tip of a compass point magnetic south?

Should we be calling the north magnetic pole, the southern magnetic pole of the Earth, or should we be referring to the south magnetized needle of the compass as pointing magnetic north? Neither. A compass needle is a magnet and the north pole of any magnet is defined as the side which points magnetic north when the magnet is freely suspended; its correct title is "north seeking pole," but it has unfortunately been shortened to "north pole." Maps label the magnetic pole in the northern hemisphere as the "North Magnetic Pole".

The cardinal points were defined long before the discovery that freely suspended magnets align to magnetic north. When some curious person placed lodestone (magnetite) on wood floating on water, or floated it directly on mercury, it was observed to align in a consistent direction, roughly pointing north. The side of the lodestone that pointed magnetic north was called, naturally, the "north pole". But that was before it was realized that like poles of magnets repel. So we must now make the distinction that the real north pole is the Earth's north magnetic pole, and the poles of all magnets that (roughly) point to it are north seeking poles.

How do I compensate for declination and inclination?

Since magnetic observations are neither uniformly nor densely distributed over the Earth, and since the magnetic field is constantly changing in time, it is not possible to obtain up-to-date values of declination directly from a database of past observations. Instead, the data are analyzed to produce a mathematical routine called a magnetic reference field "model", from which magnetic declination can be calculated.

Global models are produced every one to five years. These constitute the series of International Geomagnetic Reference Field (IGRF) models. The World Magnetic Model Epoch 2000 (WMM-2000), models. The latest IGRF and WMM model was produced in 2000, and is valid until 2005. The Canadian Geomagnetic Reference Field (CGRF) is a model of the magnetic field over the Canadian region. It was produced using denser data over Canada than were used for the IGRF, and because the analysis was carried out over a smaller region, the CGRF can reproduce smaller spatial variations in the magnetic field than can the


IGRF. The latest CGRF was also produced in 2000 and is valid until 2005. The accompanying declination chart is based on the CGRF.

Since magnetic field models such as the WMM, IGRF and CGRF are approximations to observed data, a value of declination computed using either of them is likely to differ somewhat from the "true" value at that location. It is generally agreed that the WMM and IGRF achieves an overall accuracy of better than 1° in declination; the accuracy is better than this in densely surveyed areas such as Europe and North America, and worse in oceanic areas such as the south Pacific. The accuracy of the CGRF, in southern Canada, is about 0.5°. The accuracy of all models decreases in the Arctic near the North Magnetic Pole.

Magnetic field models are used to calculate magnetic declination by means of computer programs such as the Magnetic Information Retrieval Program (MIRP), a software package developed by the Geomagnetism Program of the Geological Survey of Canada. The user inputs the year, latitude and longitude and MIRP calculates the declination. MIRP is able to compute values for any location on the Earth in the time period 1960 to 2000. For locations within Canada, MIRP computes values using the CGRF. Outside Canada, values are calculated using the IGRF.

Below is an example of a Geomagnetic software package used to calculate many magnetic parameters. Inputs required for this example are Latitude, Longitude, Elevation, Date and Model.

Output we would normally use are Magnetic Field Strength (Incident Field), Magnetic Dip angle (Dip) and Magnetic Declination (Dec).


What factors Influence Declination? Location

Each position on the Earth has a particular declination. The change in its value as one travels is a complex function. If a navigator happens to be traveling along a rather straight line of equal declination, called an isogonic line, it can vary very little over thousands of kilometers. However; for one crossing isogonic lines at high latitudes, or near magnetic anomalies, the declination can change at over a degree per kilometer (6/10 mile).

Local magnetic anomalies

Predictive geomagnetic models such as the World Magnetic Model (WMM) and the International Geomagnetic Reference Field (IGRF) only predict the values of that portion of the field originating in the deep outer core. In this respect, they are accurate to within one degree for five years into the future, after which they need to be updated. The Definitive Geomagnetic Reference Field (DGRF) model describes how the field actually behaved.

Local anomalies originating in the upper mantle, crust, or surface, distort the WMM or IGRF predictions. Ferromagnetic ore deposits; geological features, particularly of volcanic origin, such as faults and lava beds; topographical features such as ridges, trenches, seamounts, and mountains; ground that has been hit by lightning; downhole features such as casing, stuck bottom hole assemblies, drill string and bottom hole assemblies can induce errors of three to four degrees.

Anomalous declination is the difference between the declination caused by the Earth's outer core and the declination at the surface. It is illustrated on 1:126,720 scale Canadian topographic maps published in the 1950's, which included a small inset isogonic map. On this series, it is common to observe a four-degree declination change over 10 kilometers (6 miles), clearly showing local anomalies. There exist places on Earth, where the field is completely vertical; where a compass attempts to point straight up or down. This is the case, by definition, at the magnetic dip poles, but there are other locations where extreme anomalies create the same effect. Around such a place, the needle on a standard compass will drag so badly on the top or the bottom of the capsule, that it can never be steadied; it will drift slowly and stop on inconsistent bearings. While traveling though a severely anomalous region, the needle will swing to various directions.

A few areas with magnetic anomalies (there are thousands more):

• North of Kingston, Ontario; 90° of anomalous declination.

• Kingston Harbor, Ontario; 16.3° W to 15.5° E of anomalous declination over two kilometers (1.2 miles); magnetite and ilmenite deposits.

• Near Timmins, Ontario, W of Porcupine.

• Savoff, Ontario (50.0 N, 85.0 W). Over 60° of anomalous declination.

• Michipicoten Island in Lake Superior (47.7 N, 85.8 W); iron deposits.

• Near the summit of Mt. Hale, New Hampshire (4000-foot, near the Zealand Falls hut on the Appalachian Trail) ; old AMC Guides to the White Mountains used to warn against it.

• Around Georgian Bay of Lake Huron.

• Ramapo Mountains, N. E. New Jersey; iron ore; compass rendered useless in some areas.

• Grants, NM north of Gila Wilderness area; Malpais lava flows; compass rendered useless.


The USGS declination chart of the USA (GP-1002-D) shows over a hundred anomalies. The following table lists the most extreme cases.

Anomalous (Lat. Long. Location declination degrees) 46.4 W 40.2 106.2 75 km.(45 mi.) W Boulder, Colorado 24.2 E 40.7 75.3 20 km. (12 mi.) NE Allentown, Pennsylvania 16.6 E - 12.0 W 46.7 95.4 250 km. (150 mi.) NW Minneapolis, Minnesota 14.8 E 33.9 92.4 85 km. (50 mi.) S Little Rock, Arkansas 14.2 E 45.5 82.7 In Lake Huron, Ontario 13.8 W 45.7 87.1 Escanaba, on shore of Lake Michigan 13.7 E 48.4 86.6 In Lake Superior, Ontario 13.5 E 48.5 122.5 80 km. (50 mi.) N Seattle, Washington 13.0 W 42.2 118.4 In Alvord Desert, Oregon 12.2 W 38.9 104.9 10 km. (6 mi.) W Colorado Springs, Colorado 11.5 E 47.8 92.3 120 km. (75 mi.) N Duluth, Minnesota In 1994, the average location of the north magnetic dip pole was located in the field by the Geological Survey of Canada. This surveyed north magnetic dip pole was at 78.3° N, 104.0° W, and takes local anomalies into consideration. However; the DGRF-90 modeled magnetic dip pole for 1994 was at 78.7° N, 104.7° W. The 47-kilometer (29 mile) difference illustrates the extent of the anomalous influence. In addition to surveyed dip poles and modeled dip poles, a simplification of the field yields geomagnetic dipole poles, which are where the poles would be if the field was a simple Earth-centered dipole. Solar-terrestrial and magnetospheric scientists use these. In reality, the field is the sum of several dipoles, each with a different orientation and intensity.

Distortion caused by cultural features is called deviation.

Altitude

(Negligible to 2 degrees)

This factor is normally negligible. According to the IGRF, a 20,000 meter (66,000 foot) climb even at a magnetically precarious location as Resolute, 500 kilometers (300 miles) from the north magnetic pole, would result in a two-degree reduction in declination.

North Magnetic Pole Movement 1945-2000

As convection currents churn in apparent chaos in the Earth's core, all magnetic values change erratically over the years. The north magnetic pole has wandered over 1000 kilometers (600 miles) since Sir John Ross first reached it in 1831, as shown on this map at SARBC (extend the path to north west of Ellef Ringes Island for 1999), or this map at USGS. Its rate of displacement has been accelerating in recent years and is currently moving about 24 kilometers (15 miles) per year, which is several times faster than the average of 6 kilometers (4 miles) per year since 1831. The magnetic pole positions can


be determined more precisely by using a calculator that returns magnetic inclination. Latitudes and longitudes can be entered by trial and error, until the inclination (I) is as close as possible to 90°.

South Magnetic Pole Movement 1945-2000

A given value of declination is only accurate for as long as it stays within the precision of the compass, preferably one degree. Typical secular change or variation (do not confuse with mariners' and aviators' variation) is 2-25 years per degree. A map that states: "annual change increasing 1.0' " would suggest 60 years per degree, but that rate of change just happened to be slow on the year of measurement, and will more than likely accelerate.

The magnetic field has even completely collapsed and reversed innumerable times, which have been recorded in the magnetic alignment of lava as it cooled. One theory to explain magnetic pole reversals is related to large meteorite impacts, which could trigger ice ages. The movement of water from the oceans to high latitudes would accelerate the rotation of the Earth, which would disrupt magmatic convection cells into chaos. These may reverse when a new pattern is established. Another theory is that the reversals are triggered by a slight change the angular momentum of the earth as a direct result of the impacts. These theories are challenged by the controversial Reversing Earth Theory, which proposes that the entire crust could shift and reverse the true poles in a matter of days, but that the molten core would remain stationary, resulting in apparent magnetic reversal. The Sun would then rise in the opposite direction.

Diurnal change (negligible to 9 degrees)

The stream of ionized particles and electrons emanating from the Sun, known as solar wind, distorts Earth's magnetic field. As it rotates, any location will be subject alternately to the lee side, then the windward side of this stream of charged particles. This has the effect of moving the magnetic poles around an ellipse several tens of kilometers in diameter, even during periods of steady solar wind without gusts. The Geological Survey of Canada shows a map of this daily wander or diurnal motion in 1994.

The resulting diurnal change in declination is negligible at tropical and temperate latitudes. For example, Ottawa is subject to plus or minus 0.1 degree of distortion. However; in Resolute, 500 kilometers (300 miles) from the north magnetic pole, the diurnal change cycles through at least plus or minus nine degrees of declination error. This error could conceivably be corrected, but both the time of day and the date would have to be considered, as this effect also varies with seasons.

Solar magnetic activity (negligible to wild)

The solar wind varies throughout an 11-year sunspot cycle, which itself varies from one cycle to the next. In periods of high solar magnetic activity, bursts of X-rays and charged particles are projected


chaotically into space, which creates gusts of solar wind. These magnetic storms will interfere with radio and electric services, and will produce dazzling spectacles of auroras. The varied colors are caused by oxygen and nitrogen being ionized, and then recapturing electrons at altitudes ranging from 100 to 1000 kilometers (60 to 600 miles). The term "geomagnetic storm" refers to the effect of a solar magnetic storm on the Earth (geo means Earth.

The influence of solar magnetic activity on the compass can best be described as a probability. The chance that the declination will be deflected by two degrees in southern Canada over the entire 11-year cycle is 1% per day. This implies about four disturbed days per year, but in practice these days tend to be clustered in years of solar maxima. These probabilities drop off rapidly at lower latitudes. During severe magnetic storms, compass needles at high latitudes have been observed swinging wildly.

"Bermuda Triangle" type anomalies

(very rare)

Legends of compasses spinning wildly in this area of the Atlantic, before sinking a ship, or blowing up an airplane, may be related to huge pockets of natural gas suddenly escaping from the ocean floor. As the gas bubbles up, it could induce a static charge or could ionize the gas, which would create erratic magnetic fields. The gas would cause a ship to lose buoyancy, or a plane flying through a rising pocket of natural gas could ignite it. The ionized gas may show as an eerie green glow at night. It could make people feel light headed and confused because the gas replaces the air, but it would not have the mercaptans that gas companies add to gas to give it its distinctive odor.

At enormous pressures and low temperatures (as at the bottom of the sea), water and gas molecules form gas hydrates. These compounds resemble ice but, unlike ordinary ice, the water molecules form cages that trap gas molecules such as methane. The solid hydrates retain their stability until conditions, such as higher temperatures or lower pressures, cause them to decompose. The gas may remain trapped under silt, until an earthquake triggers a release.

This phenomenon is not restricted to the "Bermuda Triangle". The insurance statistics at the Lloyds of London have not revealed an unusual number of sunken ships in the triangle.

How do I determine the Declination diagrams on maps? Most topographic maps include a small diagram with three arrows: magnetic north, true north and Universal Transverse Mercator grid north. The given value of declination, corresponding to the center of the map, does not take local anomalies into account. The value is usually out of date, since it may have drifted several degrees due to secular change, especially on maps of remote regions with several decades between updates. Some maps, such as the 1:50,000 scale topographic maps by the Canadian Department of Energy, Mines and Resources include the rate of annual change, which is useful for predicting declination, but that rate of change is erratic and reliability of the forecast decreases with time. A rate of change over five years old is unreliable for one-degree precision. The United States Geological Survey's 1:24,000 scale maps do not even mention annual change.

For example, the approximate mean declination 1969 on the Trout River, Newfoundland map was 28° 33' west with annual change decreasing 3.0'. This implies a recent (1997) value of:

28° 33' - ((1997-1969) * 3.0) = 27° 93' but IGRF 1995 for 1997 yields 23° 44', which is 3° 25' less, showing that the 28-year prediction was in significant error.


Grid north and declination diagrams

(negligible to 2 degrees)

Grid north is the direction of the north-south lines of the Universal Transverse Mercator (UTM) grid, imposed on topographic maps by the United States and NATO armed forces. UTM Provides a constant distance relationship anywhere on the map. In angular coordinate systems like latitude and longitude, the distance covered by a degree of longitude differs as you move towards the poles and only equals the distance covered by a degree of latitude at the equator. With the advent of inexpensive GPS receivers, many other map users are adopting the UTM grid system for coordinates that are simpler to use than latitude and longitude.

The problem with grid north is that is coincident with true north only at the center line of each UTM zone, known as central meridians. The difference between grid north and true north can be over two degrees. This might not be so bad if it were not for the different conventions with respect to declination diagrams adopted by different countries. A declination diagram on a topographic Canadian map or an Australian map shows magnetic north with respect to grid north, but a US map shows magnetic north with respect to true north. Therefore, if you use declination from a Canadian/Australian style declination diagram, be sure to take bearings to and from the map by making the meridian lines on the compass parallel with the UTM grid (grid north). However, if you use declination from a USGS style declination diagram or any of the other sources below, you must make the meridian lines on the compass parallel with the edges of the map (true north). Canadian maps show a blue fine-lined UTM grid, while some USGS 1:24,000 scale maps show black grid lines, but the others only show blue grid tick marks on the map margins. The choice of grid lines or tick marks on the US maps seems inconsistent by year or by region.

Printed Isogonic charts

Isogonic or declination charts are plots of equal magnetic declination on a map, yielding its value by visually situating a location, and interpolating between isogonic lines. Some isogonic charts include lines of annual change in the magnetic declination (also called isoporic lines). Again, the older, the less valid. The world charts illustrate the complexity of the field.

A Brunton 9020 compass included a 1995 isogonic chart of North America, on a sheet copyrighted in 1992

The 1:1,000,000 scale series of World Aeronautical Charts include isogonic lines.

Hydrographic charts include known magnetic anomalies.

The McGraw-Hill Encyclopedia of Science and Technology (1992 edition) provides a small world chart under "geomagnetism."

The best is the 1:39,000,000 Magnetic Variation chart of "The Earth's Magnetic Field" series published by the Defense Mapping Agency (USA). The 11th edition is based on magnetic epoch 1995.0 and includes lines of annual change and country borders. Ask for Geophysical Data Chart stock No. 42 (DMA stock No. WOBZC42) at a National (USA) Ocean Service navigation chart sales agent or order from the NOS Distribution Division, about US$10. Size: 1.26 X 0.9 meters (50" X 35"). It covers from 84° N to 70° S. North and south polar areas are on Geophysical Data Chart stock No. 43 (DMA stock No. WOBZC43).


European marine chart distributors may have better availability for the 1:45,000,000 scale "The World Magnetic Variation 1995 and Annual Rates of Change" chart published by the British Geological Survey. However; it lacks country borders. Ask for No. 5374, about US$16.

A 1:48,000,000 world declination chart of "The Magnetic Field of Earth" series is published by the United States Geological Survey's Earth Sciences Information Center. However; the most recent edition is still based on magnetic epoch 1990.0. It does include lines of annual change and country borders. Look it up at a university map library or order GP-1004-D from the United States Geological Survey. Only US$4.00 (+ US$3.50 for shipping and handling). Size 1.22 X 0.86 meters (48" X 34"). Includes polar regions at 1:68,000,000 scale. A United States declination chart is also published. Scale 1:5,000,000 (Alaska and Hawaii 1:3,500,000), epoch 1990.0, GP-1002-D, US$4.00 + US$3.50 S&H, 1.14 X 0.8 meters (45" X 34"), includes over 100 magnetic anomalies.

On-line Isogonic charts North America 1990, Others 1995: South America, Europe, Middle East, Southeast Asia, Australia/New Zealand, Global: Ricardo's Geo-Orbit Quick Look satellite dish site World, small: United States Geological Survey World, larger, color, 1995: National (USA) Geophysical Data Center or Stanford University in California World, slightly more readable, 1995: National (USA) Geophysical Data Center World, black and white, 1995, seven magnetic parameters, including polar projections: Kyoto University in Japan World, color, 1995, five magnetic parameters and their rates of secular change, click to zoom. USA Department of Defense Canada, CGRF95: Geological Survey of Canada Canada, more detailed (caution: outdated--1985): Search and Rescue Society of British Columbia United States, 1995, small, three magnetic parameters (note: longitudes are in 360° format): United States Geological Survey Mexico, IGRF95: Instituto de Geofísica, Universidad Nacional Autónoma de México. The blue lines are declination, and the red lines are annual change. Australia, AGRF95 for 1997.5: Australian Geological Survey Organization (AGSO) Finland, 1998.0: Finnish Meteorological Institute. It has wavy isogones in an attempt to include magnetic anomalies from the Earth's crust. Generate your own: Kimmo Korhonen at the Helsinki University of Technology, Finland wrote this Java applet in which you specify a region and date. Great idea, but the maps lack detail. On-line and downloadable declination data Use an atlas to find your latitude and longitude before you can use the links below. Pangolin in New Zealand features a Java applet that continuously returns magnetic variation as the pointer is moved over a map of the world. Sorry, no zooms available, but it computes great circle bearings and distances. http://www.pangolin.co.nz/magvar.html Geological Survey of Canada: declination http://www.geolab.nrcan.gc.ca/geomag/e_cgrf.html National (USA) Geophysical Data Center: seven magnetic parameters and their rates of secular change. http://www.ngdc.noaa.gov/cgi-bin/seg/gmag/fldsnth1.pl Interpex Limited: GEOMAGIX freeware can be downloaded. http://geomag.usgs.gov/Freeware/geomagix.htm Defense Mapping Agency: GEOMAG freeware can be downloaded. ftp://ftp.ngdc.noaa.gov/Solid_Earth/Mainfld_Mag/DoD_Model/Basic_Software/dmabasic.exe


Ed William's Aviation page: Geomagnetic Field and Variation Calculator freeware can be downloaded in Mac, Linux, and DOS versions and are suitable for batch processing. http://www.best.com/~williams CBU Software: MAGDEC shareware (30-day trial) provides a plot of declination vs. years, latitude or longitude and will transform bearings from one year to another. It covers USA only, from 1862 to present. http://www.datacache.com/descript.htm Declinometer/Inclinometer

A declinometer/inclinometer is sophisticated instrument makes precision measurements of declination and inclination. It is used to calibrate compasses or to periodically calibrate continuously recording variometers in magnetic observatories. The angle at which its electronic fluxgate magnetometer reads a minimum value, is compared to a sighting through its optical theodolite. True north is determined by sighting a true north reference target mounted some distance away, or is derived from celestial navigation calculations on a sighting of the sun or another star.

DIRECTIONAL SURVEYING MEASUREMENTS AND SENSORS

In order to guide a wellbore to a desired target, the position and direction of the wellbore at any particular depth must be known. Since the early days of drilling, various tools have been developed to measure the inclination and azimuth of the wellbore.

To calculate the 3D path of the wellbore, it is necessary to take measurements along the wellbore at known depths of the inclination (angle from vertical) and azimuth (direction normally relative to true north). These measurements are called surveys.

To compute the wellpath between two surveys, various mathematical constructions have been proposed. The most common modern method assumes that the wellpath forms a perfect arc between two surveys. This model is called minimum curvature. The calculations can then be done to calculate the position of the second survey if the position of the first survey is known.

There are errors inherent in these calculations-first, survey instruments are only accurate to a certain degree, and second, though a perfect arc is assumed, this is unlikely to be the case. The calculated wellpath will be more accurate if surveys are taken close together (every 20' -30') and if the well is not highly deviated.

One of the earliest tools used to document the wellpath was a bottle of acid that was lowered down the well. After half an hour, the acid would etch

a mark on a copper cylinder inside the bottle. When the bottle was pulled back to the surface, the inclination of the well at the depth where the bottle was left could be measured by measuring the angle of the etched mark.

The acid bottle could be called a type of "single shot" tool because it only takes one measurement each time it is run in the well. There are two other single shot tools that are still used today, the acid bottle having been consigned to the history books.

The first of these tools is called a totco tool. It is a mechanical tool that takes a reading showing the inclination of the wellbore, but not the azimuth. It is used in vertical wells to check that the well is within a few degrees of vertical. While drilling, the tool can be run on a wire to the BHA and recovered as soon as the survey is taken. A clockwork timer determines when the survey is taken. When the drillstring is tripped out, the totco survey tool can be dropped down the drillstring (with the timer set to give enough time to fall to the bottom) and will be recovered when the BHA is back at the surface. The survey is recorded by punching a hole in a paper disk.


The second single shot tool is the magnetic single shot (MSS). This tool measures both inclination and magnetic azimuth. The azimuth is normally converted to true north before being used in calculating the well path. For this tool to measure azimuth, it cannot be placed inside a normal steel drill collar. Normal drill collars have their own magnetic field that renders the azimuth reading magnetic compass unreliable. A special steel compound called "Monel" is used to make non-magnetic drill collars and stabilizers, which have to be placed in the BHA to allow the MSS to be used. In a directional well, MSS surveys will be taken more frequently when the well is being deviated (in the build up sections) and less frequently when the well direction is not being changed intentionally (in the tangent section) .The MSS has interchangeable measuring units that allow inclinations up to 90° to be recorded onto a film that is developed on the surface.

A MSS can also record the orientation of the tool face. When the well is kicked off using a jetting assembly or a downhole motor, the assembly can be orientated in the correct direction by running a MSS to see the tool face azimuth, then the drillstring can be turned at the surface to correctly align the tool face.

The totco and MSS surveys are routinely used while drilling with rotary assemblies. There are also survey tools that allow surveys to be taken in "real time" and display the data to the driller. These are called measurement while drilling (MWD) survey tools.

Applications of Magnetics and Gravity

In the MWD sensor package, two sets of sensors are used. One set (magnetometers) uses an XYZ system to measure orientation with respect to the earth’s magnetic field (Hx, Hy, Hz). The other set (accelerometers) uses an XY or XYZ system to measure orientation with respect to the earth’s gravitational field (Gx, Gy, Gz).

From the magnetic sensors we can learn inclination, azimuth, and tool face angles. From the gravity sensors we can learn inclination and tool face angle.

Magnetic Toolface, MTF

For hole inclinations of 0 to 5 degrees use magnetics to determine hole direction. i.e. N 65oE

i.e. MTF = Magnetic Azimuth +/- Declination + Toolface Offset

Gravity Toolface, GTF

For hole inclinations of 5+ degrees use gravity to determine the hole direction. i.e. 65o or 65 R

i.e.GTF= Tool Highside Angle +/- Declination + Toolface Offset


Directional surveying permits 1) the determination of bottom hole location relative to the surface location or another reference system; 2) the location of possible dog legs or excessive hole curvatures; 3) monitoring of the azimuth and inclination during the drilling process; and 4) the orientation of deflection tools.

The inclination and azimuth of the well bore at specific depths can be determined by one type of survey called the “single shot survey”, while “multiple shot” surveys are used to record several individual readings at required depth intervals. These magnetic survey instruments must be run inside non-magnetic drill collars or open hole.

Magnetic Single Shot The magnetic single shot instrument is used to simultaneously record the magnetic direction of the course of an uncased well bore and its inclination from vertical. It is also used, in some cases, to determine the tool-face of a deflection device when deviating the well (usually a gyro is used).

The instruments consist of four basic units; 1) a power pack or battery tube; 2) a timing device or sensor; 3) a camera unit and 4) a compass - inclinometer unit.

These four elements are assembled together and usually inserted into a carefully spaced protective barrel (running gear) before being lowered or dropped, inside the drill pipe, to bottom. The protective casing can be thermally insulated for wells where the downhole temperature exceeds the tolerance of the photographic film used or battery.

Power Pack

The size and number of batteries required varies with the instrument, as does their polarity. Care should be taken to identify the correct polarity prior to loading batteries into the battery tube. Failure to do so can lead to a “mis-run” survey, causing lost time while the survey is re-run. The battery tube may have a snubber for use with top landing running gear.

Timer or Sensor The timing device is used to operate the camera at a predetermined time. The Surveyor must estimate the time it will take for the instrument to fall to bottom, whether lowered on wire line or dropped (go devilled). The timers available today are either mechanical, or electronic. In the past, mechanical timers have been considered more robust, although less accurate than the electronic timers. With modern solid state electronics this is no longer true and mechanical timers are now rarely used. Electronic timers allow the operator to preset the time delay on the instrument before loading it into the running gear.

Problems arise when using either type of timer and are not necessarily due to instrument malfunction. The most common problem results from timer miscalculation. If the time delay expires before the instrument has seated inside the non-magnetic drill collar, the resulting survey will be invalid, affected by motion and magnetic interference from the drill string.

Since it is quite difficult to accurately predict the time involved in lowering the instrument to bottom, and anticipate problems with wire-line units or other surface equipment, the usual solution to this problem is for the operator to overestimate the time required, “just to be safe”. This then results in time lost waiting for the timer to expire with the instrument in place, as well as unnecessary risk of stuck pipe resulting from not moving the drill string. The benefit of the timer is that it can be used


when dropping or “go devilling” the survey; the operator knows exactly when the lights will come on and can minimize the length of time that the pipe is still.

For Magnetic single shot surveys taken on wireline, timing devices are being replaced with electronic sensors which detect either the lack of movement as with a motion sensor or more commonly, the presence of non magnetic materials, as with a “monel” sensor.

The motion sensor detects when all motion has stopped for a given time (usually about thirty seconds), before activating the camera unit. This system has several drawbacks; if the descent of the survey instrument is interrupted for any reason below surface, a wireline problem for example, the motion sensor will detect the loss of movement and fire the camera resulting in a mis-run. The motion sensor is to some extent mechanical: it employs a movable element to detect motion and this may stick or lose sensitivity again resulting in a mis-run. From a floating rig, the downhole movement of the drill pipe imparted by the heave of the ocean, may affect a motion sensor, particularly at shallow depths.

A “monel”, or non-magnetic collar sensor, is not subject to these limitations. It senses the change in the surrounding magnetic field as it enters the non-magnetic drill collar. Most monel sensors must be in a non-magnetic environment for a set time, as a safety factor, usually from thirty seconds to one minute before firing the camera unit. This serves to ensure that the instrument is actually seated in the non-magnetic collar and allows the compass card and inclinometer in the angle unit to settle before the picture is taken.

Timers and sensors should always be surface tested before use.

Camera The magnetic single shot camera has three main components: the film disk seat, the lens assembly, and the lamp assembly. Unlike normal cameras, the single shot camera unit has no shutter mechanism, the exposure of the film is controlled instead by the timing of the light illumination. In most instruments, the lens assembly comes pre-focussed and no field adjustments are necessary.

Angle Unit or Compass

This is the measurement device. The inclinometer measures the inclination of the wellbore, and the compass measures the direction or azimuth of the well. These devices are normally designed for a specific application and vary in design and principle. They may measure inclination only, high side (for use with mud motors), a combination of inclination and direction, they may use pendulums, weighted floats or air bubbles.

Perhaps the simplest inclinometer is one which that is used for measuring very low inclinations, the bubble inclinometer. Somewhat like a round carpenter’s level, it is very sensitive to low inclinations and is often used to survey vertical holes such as those drilled for conductor pipe where absolute verticality can be critical. Just as simple, and using the same principle, is the “low ball” type inclinometer, used not to measure inclination, but to identify the “low side” of the hole with a small metal ball enabling the gravity tool-face of a deflection tool, such as a mud motor, to be measured in an environment where magnetic interference precludes the use of conventional angle units. These are the simplest but least used inclinometers as they apply only to special cases. The more commonly used angle units fall into three basic categories:


Cross-Hair Pendulum — Compass One of the most common types of angle units, for inclination and direction up to twenty degrees. The compass card is free to rotate inside the housing and maintain a reference to magnetic north. The inclinometer is an independent and free swinging pendulum cross-hair. The compass card is printed in reverse in order for the pendulum, which naturally falls to the low side, to depict the direction as it should be on the high side. The survey disk is read as correct. Care should be taken when interpreting gravity tool face using this type of angle unit.

Scale Inclinometer — Compass

Similar in principle to the pendulum cross-hair, this angle unit has an independent weighted inclinometer which appears as a scale superimposed onto the compass card on the survey photo disc. This type of angle unit is normally used for higher inclinations ( above twenty degrees). Depending on the manufacturer, gravity toolface is interpreted either “as read” or is reversed. Care should be taken to establish the correct method of determining gravity toolface, before using the single shot for downhole orientation.

Floating Ball Inclinometer — Compass

This type of angle unit utilizes a compass ball floating in fluid. The ball is inscribed with both azimuth and inclination. The cross hair sight is centered in the instrument and does not move, rather the compass ball tilts and rotates beneath it. Because the inclination and azimuth are not read independently, the angle units must be manufactured Geographically specific for the area or zone in which they will be used. This is normally identified by a stamp on the angle unit itself.

Magnetic Multishot Survey Instrument The magnetic multishot survey tool differs from the single shot tool in that the timer is programmed to take a series of readings separated by a preset time interval, and the camera unit is designed to take a series of recordings instead of just one as in the single shot. The battery tube is often lengthened in order to accommodate a greater number of batteries. The running gear used is normally the same for both types of survey, and the compass units are usually interchangeable.

The Multishot Timer Depending on the manufacturer, some tools allow the operator to specify the interval between shots, while others are fixed. This interval is commonly in the one to three shots per minute range, and in normal applications, is adequate. As the instrument is dropped or “go devilled” inside the drill pipe, and the surveys taken when the pipe is placed in the slips on tripping put of the hole, in most cases, one survey per minute would be acceptable. The capacity of the Multishot to store data depends upon the amount of photographic film that can be stored in the camera unit. In the case where the pipe is pulled extremely slowly, or reciprocated for long periods, and where the hole depth dictates a lengthy trip out of the hole, longer periods between shots can extend the running time of the instrument and allow a full survey in one run.

The Multishot Camera These also vary with manufacturer, but do not differ much in principal. Basically the camera consists of a film magazine spool, which is loaded by the operator and installed in the tool, a guide spool which passes the film across the focus of the camera lens, and the take-up spool which stores the exposed film. The photographic film is, of course, light sensitive and must be handled either in a darkroom, or


a portable developer bag (often supplied with the tool ) prior to development. In some types of tools, the film spools fit into separate cartridge-type magazines which can be preloaded and interchanged outside the darkroom without fear of exposure.

The other feature of the multi-shot camera is the drive mechanism, which turns the film spools in synchronization with the exposure-timer. The drive mechanisms are usually simple worm-drive devices or solenoid plunger-ratchet type.

The film, when developed, shows as a series of shots spaced along it. The operator, by carefully recording bit depth against time, can match individual shots with given depths, and calculate the survey using this data. Because the multi-shot takes continual surveys, some are unreadable due to pipe movement. The valid surveys are found at the points where the pipe was set in the slips for a connection and the compass was still. Because of this, the common interval between surveys is equivalent to the length of a stand of drill pipe.

Possible Problems With Reading Single Shot Records

Problem Probable Cause Record is very light Disc was improperly exposed; check

battery An irregular shaped pink or black space on the record

An air bubble was trapped below the film. Shake the tank when developing.

The entire record is black Disc was exposed to light before loading, while loading or while unloading.

Crosshair is clear but background is dark or only faint images appear.

Instrument was moving while record was being taken.

Crosshairs are not on readable scale Drift angle is greater than maximum limit of the compass being used.

To protect the magnetic single shot instrument when lowered or dropped into the wellbore a protective casing is used. This protective casing protects the instrument while being retrieved or lowered and it also prevents drilling fluid from contaminating the tool.

Gyroscopes

The industry began developing what is now most commonly referred to as “rate-gyro surveying systems” in the late 1970’s. The goal of the overall development was to adapt modem aerospace guidance techniques for oil industry applications with the following objectives:

1. Provide a significant enhancement in survey accuracy.

2. Provide a means of quality assurance.

The existing surveying methods could not provide a reliable means of quality assurance for the level of accuracy wanted by the industry. Wellbore survey technology can be classified into four groups, as follows:

1. Inclination Only Device (Totco)

2. Magnetic-Based (film-based / electronic, single I multi-shot, MWD, steering tools, dip-meter)

3. Free-Gyro Systems (film-based/electronic)

4. Rate-Gyro Systems


The Gyroscope

A Gyroscope is basically a balanced, spinning mass, which is free to rotate on one or more axis. The basic operation of a gyroscope can be compared to a spinning top. As long as the top spins fast enough, it attempts to hold its vertical orientation. If the top were propelled by a spin motor at a particular speed designated by its mass, it would stay vertical for as long as the motor ran, that is, if no external forces acted on it. This is the simple basis of all gyroscopes used in navigation, a spinning mass that through its momentum becomes resistant to external forces and attempts to maintain an orientation like the top in space. The term “resistant to external forces” is important, for a perfect gyro cannot be built, that will not be upon by external force and react by movement.

The classic example of a natural occurring gyroscope is the planet Earth - a spinning mass attempting to hold a particular orientation in space established long ago. Even the Earth is not a perfect gyro. It reacts to external forces with some movement, or drift, off its orientation. Fortunately, the drift is very small.

The next step in basic gyro understanding is the two-degree-of-freedom gyroscope, the same kind used in the oil. Free-gyros have been used in wellbore surveying since the 1930’s.

The frames supporting the gyroscope, and allowing this freedom of rotation are referred to as Gimbals. Because gyroscopes can be extremely complicated, we will look at simplified gyroscopes initially, in order to understand the forces working upon them.

The gimbals isolate the gyro from the base so the spinning mass can attempt to maintain its original orientation no matter how the bass moves. As the probe moves downhole through different directions and inclinations, the gimballing allows the gyro to attempt to maintain a horizontal orientation in space.

In performing a wellbore survey, the gyro is pointed in a known direction prior to running in the well, so throughout the survey the spin axis attempts to hold its surface orientation. Note that a compass card is aligned with the horizontal spin axis of the gyro. Survey data is collected downhole by affixing a plumb-bob assembly over the compass.

At each survey station a picture is taken of the plumb-bob direction with respect to the compass card, resulting in readings of wellbore azimuth and inclination. The plumb-bob always, as a pendulum, points down toward the Earth’s centre. When the tool is inclined off vertical, it points out the inclination of the well on the concentric rings and the azimuth by correlation with the known direction of the gyro spin axis established at surface. There are also electronic, surface read-out free-gyro systems which eliminate the plumb-bob.


Components

A gyroscope is a spinning wheel whose spin axis can move relative to some reference mount. For the sake of simplicity, the major components of the gyro are comprised of:

The Spin Motor, the main characteristic of which is “angular momentum”.

The Gyro Case which is the outer enclosure.

The Gimballing System which is the structure carrying the spin motor. The gimballing system isolates the spinning rotor from the gyro-case if the gyro-case turns around the outer gimbal axis or if the gyro-case turns around the inner gimbal axis.

The Gimbal suspension, which includes:

• the ball bearings (or gimbal bearings) between the gyro-case and the outer gimbal, and between the outer gimbal and the inner gimbal;

• the rotor bearings holding the spinning rotor in the inner gimbal.

• an Angular Pick-off which senses relative angular displacements between the gyro gimbal and the case.

• a Torquer which enables compensation for certain types of errors and precessing the gyro at desired rates.

DIRECTIONAL SENSORS The Directional Sensor is made up of electronic printed circuit boards, a Tensor Tri-Axial Magnetometer and a Tensor Tri-Axial Accelerometers, and Temperature sensor. These modules are configured into a directional probe and are run in the field mounted in a nonmagnetic drill collar. The Directional Sensor provides measurements which are used to determine the orientation of the drill string at the location of the sensor assembly.

The Directional Sensor measures three orthogonal axis of magnetic bearing, three orthogonal axis of inclination and instrument temperature. These measurements are processed and transmitted by the pulser to the surface. The surface computer then uses this data to calculate parameters such as inclination, azimuth, high-side toolface, and magnetic toolface.

The sensor axes are not perfectly orthogonal and are not perfectly aligned, therefore, compensation of the measured values for known misalignments are required in order to provide perfectly orthogonal values. The exact electronic sensitivity, scale factor and bias, for each sensor axis is uniquely a function of the local sensor temperature. Therefore, the raw sensor outputs must be adjusted for thermal effects on bias and scale factor. Orthogonal misalignment angles are used with the thermally compensated bias and scale factors to determine the compensated sensor values required for computation of precise directional parameters.


Directional Sensor Hardware The directional sensor probe is mounted to the MWD assembly and keyed into a Non-Magnetic Drill Collar. The nominal length of the sub is 30 feet. The nonmagnetic collar is usually referred to as Monel.

Directional Sensor Components Contained inside the assembly is a Single Port MPU, Triple Power Supply and a Digital Orientation Module. The Single Port MPU is a modular micro-controller assembly based on the Motorola MC68HCll microprocessor implementing Honeywell's qMIXTM communications protocol (qMIX/ll TM). The Triple Power Supply provides regulated power for the complete assembly.

The microprocessor provides the control and timing to interface the logic circuit controls the analog power switch. With the analog power switch off only the 5 volt circuits are active and the current drain from the sub bus is approximately 8 milliamps. When the logic board switches on the analog power switch, battery power is directed to the 12 volt regulator on the analog circuit. The current drain with the analog power switch on and the sensors off is approximately 80 milliamps. With the accelerometers powered up the current drain is approximately 120 milliamps. With the magnetometer powered up the current drain is approximately 140 milliamps.

Analog Circuit The Analog Circuit provides an interface with the inclinometer, magnetometer, and pressure transducer sensors. The 16 channel multiplexer on the analog circuit takes input from various sensor outputs and sends the data to the logic circuit for transmission. A sensor power switch takes power from the 12 volt regulator and selectively powers up the accelerometers and magnetometers. A 5 volt excitation supply from the 12 volt regulator is used to power the pressure transducer. The status voltages appear on the surface probe test and are defined as follows:

1. Sub Bus Voltage - battery voltage on the sub bus.

2. 5 Volt Supply - the 5 volt excitation supply from the 12 volt regulator that powers the pressure transducer.

3. Accelerometer Power Status - voltage that is currently being supplied to the inclinometer (0 or 12.5v).

4. Magnetometer power Status - voltage that is currently being supplied to the magnetometer (0 or 12.5v).

5. Steering Mode Status - 4.5 volts when steering mode is set.

Tensor Inclinometer The TENSOR Tri-axial Accelerometer measures three orthogonal axes of inclination (A, B, and C) and also includes a temperature sensor. The inclinometer has a 1g full scale output in survey mode. The sensor operates within the following parameters:

1. Input Voltage +/- 12.5 to 15.5 volts

2. Input Current < 80 ma/g

3. Accelerometer Output 3.0 ma/g


The inclinometer is made up of three accelerometers. The operation of the accelerometer is based on the movement of a quartz proof mass during acceleration. The figure above is a diagram of a accelerometer. The accelerometer consists of two magnets and a quartz disc with a coil attached to it. The quartz disc is a proof mass with a hinge that has been chemically etched to allow movement in one direction. A torquer coil is attached to the proof mass which is suspended between the two permanent magnets. The proof mass position is maintained by applying current to the torquer coil. The magnets have reference plates which measure the capacitance between the two magnets. When a force is applied to the accelerometer, movement of the proof mass changes the capacitance. A circuit detects the change in capacitance and applies current to the torquer coil to restore the proof mass to its original position.

The amount of current required to restore the proof mass to its original position is a function of the amount of force applied to the accelerometer. Force is related to acceleration by F = ma. We measure the acceleration of gravity in g's (gravity units) in three orthogonal directions relative to the Directional Sensor probe. This allows us to calculate the inclination of the tool relative to vertical.


The scaling of the A and B accelerometer channels depends on the operational mode (survey or steering), while the C channel and the temperature sensor have the same scaling for both modes. The full scale output voltage sensitivity for each mode is as follows:

CHANNEL SURVEY STEERING 1. X Accelerometer 4.5 v/g 642 mv/g 2. Y Accelerometer 4.5 v/g 642 mv/g 3. Z Accelerometer 4.5 v/g 4.5 v/g 4. Temperature 10 mv/deg K 10 mv/deg K

Tensor Magnetometer The Tensor Tri-axial Magnetometer measures three orthogonal axes of magnetic bearing (Bx, By, and Bz) as well as temperature. The Tensor Model 7002MK Magnetometer has an output operating range of plus and minus 100,000 nanotesla (the earth's field is about 50,000 nanotesla) and operates within these parameters:

1. Input voltage +/- 12 - 18 vdc

2. Input current 25 milliamps

3. Flux Gate Output 1 mv / 20 nanotesla

4. Temperature Output Voltage 10 mv / oK

The Tensor magnetometer is a saturable core device. It consists of two coils with a core between them which has a certain magnetic permeability. A magnetic field produced by one coil travels through the core and induces a current in the other coil. The core will only transmit a certain amount of magnetic field, that is , when the level of magnetic flux gets to a certain point the core will become saturated and


greater amounts of flux will not pass through the core. The point at which a substance becomes saturated is a property of that substance, ie. certain metals will saturate sooner than others. The magnetometer continually drives the core to saturation. In the presence of an external magnetic field the point that the core saturates is shifted. The signal shift is detected, amplified, and fed back as a bucking magnetic field to maintain the core at a balanced around zero magnetizing force. The servo amplifier offset caused by the signal shift is further amplified and presented as the output of the magnetometer.

In the tri-axial set of magnetometers, the three flux gate channels and temperature channel are supplied power conditioned by a common pair of internal regulators. The individual magnetometer transducers come in biaxial sets. The magnetometer package contains two biaxial magnetometers, of which only three axes are used. The sub bus around the magnetometer requires particular attention because the current through the sub bus is alternating current, any change in that current will produce a magnetic field that can affect the magnetometer.

Gyroscopic Measurement A gyroscopic compass is used when magnetic surveying instruments cannot be used because of the magnetic interference of nearby casing or when a borehole with casing already set is being surveyed.

There are various kinds of gyroscopic instruments: single- and multishot gyroscopes, the surface-recording gyroscope, the rate or north-seeking gyroscope, and the Ferranti tool (a highly precise, inertial guidance tool similar to that used on modern commercial aircraft). Of the gyroscopic instruments used for surveying cased bore- holes, the multishot is the most common.

A Cardan gyro is a suspended horizontal gyroscope. A high-frequency AC current drives a squirrel- cage rotor at a speed of 20,000 to 40,000 rpm; as long as the rotor runs at its reference speed and there are no external forces, the gyroscope stays fixed.

In a complete gyroscope assembly, the upper part of the tool holds the batteries, camera assembly, and multishot clock. The lower part of the tool contains the inclinometer, the Cardan-suspended gyroscope motor, electronic components for the gyroscope, and the shock absorber.

APPLIED DRILLING ENGINEERING Even though the gyroscope is not influenced by magnetic interference, its very design introduces unique problems associated with obtaining accurate survey information. If the gyroscope could be supported exactly at its center of gravity, it would be free of influences by external forces. However, such accuracy is practically impossible to achieve. Consequently, a slightly off-center gyroscope will tend to show a force, caused by gravity, to drift.

The gyroscope compensates for the gravitational and frictional forces caused by the bearings by rotating about its vertical axis in a direction commensurate with the right or left side of the downward force on the horizontal gimbal axis. The amount of this rotation determines the accuracy of the gyroscope. The tilt of the horizontal gimbal is corrected by a sensor that detects any departure of the gyroscope from the horizontal axis and sends a signal to a servo motor. This corrects the gyroscope by rotating the vertical axis until the horizontal axis is properly adjusted. The gyroscope is not as rugged as the magnetic instrument and must be handled more carefully. Unlike the magnetic tools, the gyroscope must be run on a wireline. When it is run, the survey stations usually are made going into the hole with a few check shots coming out; this is done mainly to make accounting for drift easier .


Drift is caused by the rotation of the earth, varying by latitude. At either pole the drift is at a maximum, and at the equator there is no apparent drift. When a gyroscopic survey is run, the effects of drift must always be determined.

The first step in running a gyroscopic survey is to orient the gyroscope. The solid triangle is always pointed at the stake or reference point. Because the bearing or direction of the reference point is known, it is relatively easy to determine the direction of the "zero" spin axis on the inner scale.

The reference direction is determined by making a sighting from some point over the wellbore, either to a stake fixed some distance from the wellbore or to a constant reference point away from the wellbore, such as a building, another drilling rig, or some other object.

When the gyroscope is referenced initially, one of two procedures, depending on the maximum inclination that is expected, is followed. If the inclination is to be less than 10°, the case index is lined up with the reference marker-i.e., in the stake direction (Ds). For example, if the stake is N20E or 20°, the gyroscope spin axis-i.e. , index setting (is)-is moved unti120° opposite the case index, thereby aligning the spin axis with north. Below 10° inclination, the 3D instrument correction is negligible. Above 10°, the 3D correction must be considered. Again, the case index must be aligned with the reference object, but the index setting is determined by a mathematical equation.

is =Ds -Odr'

where Odr is the assumed hole direction. For example, if the Ds is S17W or 197° and the Odr is N20E or 20°, the index setting is determined as follows:

197°-200=177°

When the case index is aligned with 177 °, the gyroscope north will be aligned with the Odr of 20°, and errors resulting from gyroscope tilt will be minimized. Every survey reading should be adjusted for the initial offset of 20°, as well as for drift correction and the intercardinal correction.

After the initial gyroscope orientation, or "gyro orientation" (GO), the tool case is oriented to what is called a "case orientation" (CO). From these initial checks, an initial drift is estimated. The tool is run in the wellbore, making stops for survey pictures. At 10-minute intervals, drift is checked by keeping the tool still for 3 minutes or more. Note that most of the check stops were made going into the wellbore; only two were made coming out.

Once the data are obtained, the drift correction must be made by the construction of a drift correction plot. The vertical axis, measured in degrees, is the scale for the correction values that will be applied to directional data to correct for drift during the survey. The horizontal scale is the surveying time in minutes.

The range of the vertical axis is determined by taking the correction factor, F c' which is determined from the following equation,

Fc=Ds-is

and by scaling above and below this factor in 1° increments. For example, if F c is 19.8 (the case was actually indexed at 177.2° rather than the calculated 177.0°), and the scale ranges from + 19.0 to +26.0. The horizontal scale should cover the entire survey from the gyroscope start to end; for this survey, the duration was 101.00 minutes.


SELECTION OF SURVEY EQUIPMENT

Now that we have discussed the different survey systems how does one select the correct system for the job? Many factors are included in this selection and the following are the most common:

Target Size

Small targets of 5m radius (15’) can be very difficult to reach with single shot (SS) equipment although many wells with targets of this size have been drilled with SS. The main concern lies within the estimation of the PDM’s reactive torque. An error made in this estimation can have a significant affect on the azimuth of the well and result in missing the target to the left or right. When slide drilling the tool face can change and unlike when drilling with MWD would not be known until the next survey.

Well Depth

This is very are dependent but typically in Canada once the depth exceeds 1,000m (3,000’) the ability to adjust for reactive torque is too difficult.

Drilling Motor Type

For single shot operations a high speed low torque motor is used. Drilling with medium or high torque motors and SS equipment is a crooked well path waiting to happen.

Drilling Fluid

With underbalanced drilling operations the mud pulse survey equipment can not be used since they depend upon accurate pressure pulses read at surface. The signal in two-phase fluids can not be read due to the fluid compression and noise. This can be the same problem in aerated or poorly maintained drilling fluids. Either the EM MWD or steering tools are used in these cases.

Rig Equipment Sometimes the only rig available for the job has 3 ½” or smaller drill pipe (sometimes completion rigs are used). Although SS equipment has been used to drill directional wells with this limber of equipment, it is important to have a very experienced SS directional hand (few around anymore) who can accurately estimate the reactive torque. Duplex pumps can also create many signal detection problems with the mud pulse MWD equipment due to pump noise.

Build Rate and Dogleg

When build rates exceed 5 or 6 o/30m, achieving these build rates can be very critical to reaching the target. With MWD equipment a spot check in the middle of a single can quickly be made to verify the build rate and tool-face early and modify the percentage of single slid and adjust tool-face if required. Some of the MWD and specialty logging while drilling equipment have limits on the doglegs they can be rotated through due to bending stresses.

Terminal Angle

As the inclination increases the time it takes to drop a SS survey increases. Typically with inclinations greater than 40o it becomes more cost effective to look at MWD equipment. Typically for a well that is at 40o and 300m (1,000’) deep the survey time for SS is in excess of 30 to 45 minutes. This can have a significant impact on the average ROP for the day.


Well Profile

It is not recommended to use single shot equipment on the following well profiles:

• S-curve with very short tangent sections

• Horizontal wells

• Extended reach wells

• Complex profiles with build and turn sections

Formations

In every geographical area of the world, there are certain problem formations that either don’t build as expected or will collapse if left open too long. These are not good places to use single shot equipment due to higher potential for severe doglegs and the extra time taken for surveys with the drill string in a static mode.

Required Survey Accuracy

As the required survey accuracy increases (very tight TVD or azimuth control) the equipment selection shifts from SS to MWD to Gyro to Magnetic Ranging.

Proximity of Existing Wells or Magnetic Interference

When drilling re-entry wells out of casing or passing by existing cased wells, magnetic interference becomes an important factor in equipment selection. The azimuth accuracy becomes doubtful with all survey tools except gyros. Typically magnetic interference can occur within 15m (49’) of steel but both high and low variations have been witnessed.

High Rate Drilling Horizontal Wells

In Western Canada many horizontal projects in the oil sands can drill as fast as 100m/hr (300 ft/hr). At these rates using the EM MWD system can reduce the survey cycle time. One operator estimated he saved one day per well on his horizontal well project. The horizontal wells had a TVD of 500m (1,500’) and a total measured length of 2,500m (8,200’).


SURVEY CALCULATIONS

Directional surveys are taken at specific intervals to determine the position of the wellbore relative to its surface location. The surveys are converted into a North-South, East-West and true vertical depth using one of several calculation methods. The co-ordinates are then plotted in both a vertical and horizontal plane. By plotting the survey data, the directional personnel can then compare the progress of the well to the planned wellpath and make changes as required to reach the desired target.

There are several methods that can be used to calculate the survey data, however, some are more accurate than others. Some of the most common methods are:

• Tangential • Balanced Tangential • Average Angle • Radius of Curvature and • Minimum Curvature

The tangential method is the least accurate with the radius of curvature and minimum curvature methods being the most accurate. The industry typically uses minimum curvature for these calculations but may use radius of curvature for planning.

Tangential At one time the tangential method was the most widely used because it was the easiest. The equations are relatively simple, and the calculations can be performed easily in the field. Unfortunately, the tangential method is the least accurate method and results in errors greater than all the other methods. The tangential method should not be used to calculate directional surveys. It is only presented here to prove a point.

The tangential method assumes the wellbore course is tangential to the lower survey station, and the wellbore course is a straight line. Because of the straight-line assumption, the tangential method yields a larger value of horizontal departure and a smaller value of vertical displacement when the inclination is increasing. This is graphically represented in the illustration of the Tangential Calculation Method below. Line AI2 is the assumed wellbore course. The dashed line AB is the change in true vertical depth and the dashed line BI2 is the departure in the horizontal direction. The opposite is true when the inclination is decreasing. With the tangential method, the greater the build or drop rate, the greater the error. Also, the distance between surveys has an effect on the quantity of the error. If survey intervals were 10 feet or less, the error would be acceptable. The added expense of surveying every 10 feet prohibits using the tangential method for calculating the wellbore course especially when more accurate methods are available.

Tangential Equations ∆TVD = ∆MD X CosI2 ∆North = ∆MD X SinI2 X CosA2 ∆East = ∆MD X SinI2 X SinA2


Balanced Tangential The balanced tangential method is similar to the tangential method in that the tangent to the angle determines the wellbore course. The difference between the two methods is the balanced tangential uses both the upper and lower surveys stations. The top half of the wellbore course is approximated by the upper inclination line I1A in the figure below and the lower half of the wellbore course is approximated by the lower inclination line AI2. The azimuth is approximated in the same manner.

Both the upper and lower portions of the assumed wellbore course are in error, but the errors are opposite and will nearly cancel each other. Therefore, the balanced tangential method is accurate enough for field applications. The balanced tangential equations are more difficult to perform and are more likely to result in an error because of mechanical mistakes while making the calculations.

The North-South, East-West coordinates are determined by assuming the horizontal departure of the course length is in the same direction as the azimuth recorded at the lower survey station, but this assumption is wrong. The actual wellbore course will be a function of the upper and lower survey stations. Therefore, the tangential method results in an additional error because an error already exists due to the method used to calculate the horizontal departure. The error is compounded when the North-South, East-West coordinates are calculated.

Balanced Tangential Equations ∆TVD = ∆MD X (CosI1 +CosI2) 2 ∆North = ∆MD X [(SinI1 X CosA1) + (SinI2 X CosA2)] 2 ∆East = ∆MD X [(SinI1 X SinA1) + (SinI2 X SinA2)] 2

Average Angle

When using the average angle method, the inclination and azimuth at the lower and upper survey stations are mathematically averaged, and then the wellbore course is assumed to be tangential to the average inclination and azimuth. The calculations are very similar to the tangential method and the results are as accurate as the balanced tangential method. Since the average angle method is both fairly accurate and easy to calculate, it is the method that can be used in the field if a programmable calculator or computer is not available. The error will be small and well within the accuracy needed in the field provided the distance between surveys is not too great. The average angle method is graphically illustrated in the following figure.


Illustration of the Average Angle Calculation Method Average Angle Equations ∆TVD = ∆MD X Cos[(I1 + I2)/2] ∆North = ∆MD X Sin[(I1 + I2)/2] X Cos[(A1 + A2)/2] ∆East = ∆MD X Sin[(I1 + I2)/2] X Sin[(A1 + A2)/2]

Radius of Curvature

The radius of curvature method is currently considered to be one of the most accurate methods available. The method assumes the wellbore course is a smooth curve between the upper and lower survey stations. The curvature of the arc is determined by the survey inclinations and azimuths at the upper and lower survey stations as shown below. The length of the arc between I1 and I2 is the measured depth between surveys. In the previous methods, the wellbore course was assumed to be one or two straight lines between the upper and lower survey points. The curvature of the wellbore course assumed by the radius of curvature method will more closely approximate the actual well; therefore, it is more accurate. Unfortunately, the equations are complicated and are not easily calculated in the field without a programmable calculator or computer.

A closer inspection of the radius of curvature equations show that if the inclination or azimuth are equal for both survey points, a division by zero will result in an error. In this case, the minimum curvature or average angle methods can be used to make the calculations. It is also possible to add a small number (such as 1 x 10-4) to either survey point. The resulting error will be insignificant.

Generally, the radius of curvature calculations is used when planning a well. Using one of the three previous methods to plan a well will result in substantial errors when calculating over long intervals

∆TVD = (180) X (∆MD) X (SinI 2 +SinI 1) π X (I2 – I1)

∆North = (180)2 X (∆MD) X (CosI 1 – CosI 2) X (SinA 2 – SinA 1)]

π2 X (I2 – I1) X (A2 – A1) ∆East = (180)2 X (∆MD) X (CosI 1 – CosI 2) X (CosA 1 – CosA 2)]

π2 X (I2 – I1) X (A2 – A1)


Minimum Curvature

The minimum curvature method is similar to the radius of curvature method in that it assumes that the wellbore is a curved path between the two survey points. The minimum curvature method uses the same equations as the balanced tangential multiplied by a ratio factor, which is defined by the curvature of the wellbore. Therefore, the minimum curvature provides a more accurate method of determining the position of the wellbore. Like the radius of curvature, the equations are more complicated and not easily calculated in the field without the aid of a programmable calculator or computer.

The balanced tangential calculations assume the wellbore course is along the line 11A + AI2. The calculation of the ratio factor changes the wellbore course to I1B + BI2 which is the arc of the angle B. This is mathematically equivalent to the radius of curvature for a change in inclination only.

So long as there are no changes in the wellbore azimuth, the radius of curvature and minimum curvature equations will yield the same results. If there is a change in the azimuth, there can be a difference in the calculations. The minimum curvature calculations assume a curvature that is the shortest path for the wellbore to incorporate both surveys. At low inclinations with large changes in azimuth, the shortest path may also involve dropping inclination as well as turning. The minimum curvature equations do not treat the change in inclination and azimuth separately.

The tangential and average angle methods treat the inclination and azimuth separately. Therefore, larger horizontal displacements will be calculated. The radius of curvature method assumes the well must stay within the survey inclinations and will also yield a larger horizontal displacement though not as large as the tangential and average angle.

The minimum curvature equations are more complex than the radius of curvature equations but are more tolerant. Minimum curvature has no problem with the change in azimuth or inclination being equal to zero. When the wellbore changes from the northeast quadrant to the northwest quadrant, no adjustments have to be made. The radius of curvature method requires adjustments. If the previous survey azimuth is 10o and the next survey is 355o, the well walked left 15o. The radius of curvature equations assume the well walked right 345o which is not true. One of the two survey azimuths must be changed. The lower survey can be changed from 355o to –5o, then the radius of curvature will calculate the correct coordinates.


Minimum Curvature Equations ∆TVD = ∆MD X [(CosI1 +CosI2) X FC]

2 ∆North = ∆MD X [(SinI2 X CosA2) + (SinI1 X CosA1)] X FC

2 ∆East = ∆MD X [(SinI2 X SinA2) + (SinI1 X SinA1)] X FC

2 D1 = Cos(I2 – I1) – {SinI2 X SinI1 X [1-Cos(A2 – A1)]} D2 = Tan-1 X SQRT [(1/D12) – 1] FC = 2/D2 X Tan (D2/2)

Note: Inclination and azimuth values must be in radians only.

Table 1 shows survey data used to illustrate the difference in the calculation methods. Table 2 and 3 is a summary of the results.

Table 1 Surveys for Comparison Calculations

MD (ft) Inclination (degrees)

Azimuth (degrees)

MD (ft) Inclination (degrees)

Azimuth (degrees)

0 0 0 2900 30.60 22.00 1000 0 0 3000 30.50 22.50 1100 3.00 21.70 3100 30.40 23.90 1200 6.00 26.50 3200 30.00 24.50 1300 9.00 23.30 3300 30.20 24.90 1400 12.00 20.30 3400 31.00 25.70 1500 15.00 23.30 3500 31.10 25.50 1600 18.00 23.90 3600 32.00 24.40 1700 21.00 24.40 3700 30.80 24.00 1800 24.00 23.40 3800 30.60 22.30 1900 27.00 23.70 3900 31.20 21.70 2000 30.00 23.30 4000 30.80 20.80 2100 30.20 22.80 4100 30.00 20.80 2200 30.40 22.50 4200 29.70 19.80 2300 30.30 22.10 4300 29.80 20.80 2400 30.60 22.40 4400 29.50 21.10 2500 31.00 22.50 4500 29.20 20.80 2600 31.20 21.60 4600 29.00 20.60 2700 30.70 20.80 4700 28.70 21.40 2800 31.40 20.90 4800 28.50 21.20


Table 2 Comparison of Survey Calculation Methods At Total Depth

Method TVD (ft) North (ft) East (ft)

Tangential 4364.40 1565.23 648.40

Balanced Tangential 4370.46 1542.98 639.77 Average Angle 4370.80 1543.28 639.32 Radius of Curvature 4370.69 1543.22 639.30 Minimum Curvature 4370.70 1543.05 639.80

Table 3 Relative Difference in Survey Calculation Methods at Total Depth

Method ∆ TVD ∆ North ∆ East Tangential -6.30 +22.18 +8.60 Balanced Tangential -0.24 -0.07 -0.03 Average Angle +0.10 +0.23 -0.48 Radius of Curvature -0.01 +0.17 -0.50 Minimum Curvature +0.00 +0.00 +0.00

DIRECTIONAL DRILLING TERMINOLOGY

A short glossary of the more frequently used terms for Directional Drilling is included here and is intended only as an aid in understanding directional drilling terminology and is neither a definitive work in the field nor by any means complete. The following are some of the more important and commonly used terms.

Target

The target, or objective, is the theoretical, subsurface point or points at which the wellbore is aimed. In the majority of cases it will be defined by someone other than the directional driller. Usually this will be a geologist, a reservoir engineer or a production engineer. They will often define the target in terms


of a physical limitation - i.e. a circle with a specified radius centred about a specified subsurface point. If multiple zones are to be penetrated, the multiple targets should be selected so that the planned pattern is reasonable and can be achieved without excessive drilling problems.

Some care should be taken with target definition. Any target can be reached - given enough time, money and effort but the economics of drilling dictate the use of as large a target as possible.

Each of the various targets is discussed below: 1. Circular

A horizontal circle of given radius about a fixed subsurface point.

2. Bounded

A circular, square or rectangular shape with at least one side fixed by a physical constraint e.g. a fault, a formation change (salt dome), legal boundary etc.

3. Angle at Depth

Targets may be defined as an angle limitation at depth - e. g. 2o or 5o from projected trajectory.

When targets are defined the directional driller must also know the true vertical depth at which the target applies. In some cases this depth may not be available within several hundred meters and could be specified as the wellbore intercept of a given formation top. This top of target would almost certainly preclude the use of Build and Hold wells and require use of "S" shaped wellbores.

Target Displacement

Target displacement is defined as the horizontal distance from the surface location to centre of the target in a straight line. This is also the directional summation of the departure (the due East or West displacement) and the latitude (the due North or South displacement).

The target bearings are a measure of the direction in degrees, minutes and seconds (or decimals) and typically expressed with reference to well centre.

True Vertical Depth

True Vertical Depth (TVD) is the depth of the wellbore at any point measured in a vertical plane and normally referenced from the horizontal plane of the kelly bushing of the drilling rig.

Kick Off Point

This is the point at which the first deflection tool is utilized and the increase in angle starts. The selection of both the kick off point and build up rate depend on many factors including the formation(s), wellbore trajectory, the casing program, the mud program, the required horizontal displacement, maximum allowable dogleg and inclination. This Kick Off Point (KOP) is carefully selected so the maximum angle is within economical limits. Fewer problems are faced when the angle of the hole is between 30o and 55o. The deeper the KOP is, the more angle it will be necessary to build, possibly at a more aggressive rate of build. The KOP should be at such a depth where the maximum angle to build up would be around 40o; the preferred minimum is 15o.


In practice the well trajectory may be calculated for several choices of KOP and build up rates and the results compared. The optimum choice is that which gives a safe clearance from all existing wells, keeps the maximum inclination within the desired limits, avoids unnecessarily high dogleg severity’s and is the best design from a cost point of view.

Build Rate

The change in inclination per measured length drilled (typically o/100’ or o/30 m). The build rate is achieved through the use of a deflection tool (positive displacement motor with a built in adjustable housing or purposefully designed stabilized bottomhole assembly).

Build Up Section

This is the part of the hole where the vertical angle is increased at a certain rate, depending on the formations and drilling assembly used. During the Build Up the drift angle and direction are constantly checked in order to see whether a course correction or change in build rate is required. This part of the hole is the most critical to assure the desired wellpath is maintained and the final target is reached.

Tangent

This section, also called the Hold Section, is a straight portion of the hole drilled with the maximum angle required to reach the target. Subtle course changes may be made in this section.

Many extended reach drilling projects have been successfully completed at inclinations up to 80o, exposing much more reservoir surface area and reaching multiple targets. However, inclination angles over 65o may result in excessive torque and drag on the drill string and present hole cleaning, logging, casing, cementing and production problems. These problems can all be overcome with today's technology, but should be avoided whenever there is an economic alternative.

Experience over the years has been that directional control problems are aggravated when the tangent inclination is less than 15o. This is because there is more of a tendency for bit walk to occur, i.e., change in azimuth, so more time is spent keeping the well on course. To summarise, most run-of-the-mill directional wells are still planned with inclinations in the range 15o - 60o whenever possible.

Drop Section

In S-type holes, the drop section is where the drift angle is dropped down to a lower inclination or in some cases vertical at a defined rate. Once this is accomplished the well is rotary drilled to TD with surveys taken every 50m (150’).

The optimum drop rate is between 1o- 2 ½ degree per 30m and is selected mainly with regard to the ease of running casing and the avoidance of completion and production problems.

Course Length

This course length is the actual distance drilled by the well bore from one point to the next as measured. The summation of all the course lengths is Measured Depth of the well. The term is usually used as a distance reference between survey points.

The Horizontal Projection (Plan View)

On many well plans, the horizontal projection is just a straight line drawn from the well centre or slot to the target. On multi-well platforms it is sometimes necessary to start the well off in a different direction to avoid other wells. Once clear of these, the well is turned to aim at the target. The path of


the drilled well is plotted on the horizontal projection by plotting total North/South co-ordinates (Northings) versus total East/West co-ordinates (Eastings). These co-ordinates are calculated from surveys.

Vertical Section

The Vertical Section of a well is dependent upon the bearing or azimuth of interest. It is the horizontal displacement of the well path projected at 90o to the desired bearing.

Lead Angle

Since roller cone bits used with rotary assemblies tend to "walk to the right", the wells were generally kicked off in a direction several degrees to the left of the target direction. In extreme cases the lead angles could be as large as 40o.

The greatly increased use of steerable motors, changes in conventional rock bit design and the widespread use of PDC bits for rotary drilling have drastically reduced the need for wells to be given a "lead angle". Most wells today are deliberately kicked off with no lead angle, i.e., in the target direction.

Doglegs

Doglegs or sudden changes in hole angle or hole direction were recognized as a major potential problem by the pioneers of the drilling business. When it was possible to determine that a rapid change in angle had occurred, their solution was automatic-plug back and start over. Perhaps it is well that detection procedures were not highly defined or else a hole may never have reached total depth.

Modern surveying techniques indicate that no hole is perfectly vertical. Any hole has a tendency to spiral. In fact, some holes surveyed made three complete circles in 30m (100 feet). Spiraling is reduced as the deviation from vertical increases. The maximum spiraling occurs at angles less than 30o from vertical. At angles greater than 50o from vertical, the hole may move in a wide arc, but spiraling is almost non-existent.

Doglegs are a major factor in many of our more severe drilling problems. Doglegging should be suspected when the following problems are encountered: (1) unable to log, (2) unable to run pipe, (3) key seating, (4) excessive casing wear, (5) excessive wear on drill pipe and collars, (6) excessive drag, (7) fatigue failures of drill pipe and collars, and or (8) excessive wear on production equipment.

Dogleg Severity

The previous sections have talked about some of the problems with doglegs but how do we define and calculate the value. Dogleg is a measure of the amount of change in inclination, and/or azimuth of a wellbore, usually expressed in degrees per 30m (or 100’) of course length. All directional wells have changes in the wellbore course and therefore have some doglegs. The dogleg severity is low if the changes in inclination and/or azimuth are small or occur over a long interval of course length. The severity is high when the inclination and/or azimuth changes quickly or occur over a short interval of course length.

The effect on dogleg severity with a change in azimuth is not easy to understand or calculate. A 3o change in azimuth over 30 meters will not yield a 3 o/30m dogleg severity unless the inclination is at 90o. At low inclinations a change in azimuth will have a small dogleg severity. As the inclination increases, the dogleg severity for the small azimuth change will increase. The following equation is used to calculate dogleg severity using both inclination and azimuth:


DLS = 30 X Cos–1{(SinI1 X SinI2) X [(SinA1 X SinA2) + (CosA1 X CosA2)] +(CosI1 X CosI2)} ∆MD ∆MD = course length between survey points I1 = inclination at previous survey station I2 = inclination at current survey station A1 = azimuth at previous survey station A2 = azimuth at current survey station For english calculations use 100 instead of 30

The following table compares the dogleg severity at different inclinations for similar changes in azimuth:

Comparison Of Dogleg Severity

Survey Station

Measured Depth (m)

Inclination Azimuth Dogleg (deg/30m)

1 100 2 100 2 130 2 123 0.8 1 100 15 100 2 130 15 123 6.0 1 100 45 100 2 130 45 123 16.0

Closure And Direction

The line of closure is defined as a straight line, in a horizontal plane containing the last station of the survey, drawn from the projected location to the last survey station of the survey. Simply stated, the closure is the shortest distance between the surface location and the horizontal projection of the last survey point. The closure is always a straight line since that represents the shortest distance between two points.

When defining closure, the direction or azimuth must also be given. Without indicating direction, the bottom hole location projected in a horizontal plane could be anywhere along the circumference of a circle defined by a radius equal to the closure distance. The azimuth and closure distance accurately specifies the bottom hole location relation to the surface location.

Closure Direction = Tan–1 (East/North)

Closure Distance = SQRT [(North)2 + (East)2]


Vertical Section

The vertical section is the horizontal length of a projection of the borehole onto a specific vertical plane (Azvs) and scaled with vertical depth. When the path of a wellbore is plotted, the vertical section is plotted versus TVD. The closure distance cannot be plotted accurately because the plane of closure (closure direction - Azcl) can change between surveys. The vertical plot of a wellbore is in one specific plane. The closure distance and vertical section are only equal when the closure direction is the same as the plane of the vertical section.

Vertical Section = Cos(Azvs – Azcl) X (Closure Distance)

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Survey Accuracy and Quality Control Survey Accuracy and Quality Control


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Assumptions When Taking SurveysAssumptions When Taking Surveys

• Drillstring is not moving up or down• Drillstring is not rotating• Pumps are off• No Drillstring Interference• No Casing or other Local Magnetic • Interference• Declination, Dip and Btotal are constant

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Gyro ErrorsGyro Errors

•• DriftDrift•• ShockShock•• Bearing wearBearing wear

•• TemperatureTemperature•• Expansion of materialExpansion of material

•• lntercardinallntercardinal Tilt Error or Tilt Error or GimbalGimbal ErrorError•• Angular motion vs. Actual Angular motion vs. Actual

motion as Inclination motion as Inclination IncreasesIncreases

•• DriftDrift•• North Pole North Pole –– 360360o o 24/hrs24/hrs•• Equator Equator -- 00o o 24/hrs24/hrs

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Borehole MeasurementsBorehole Measurements

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Borehole MeasurementsBorehole Measurements

•• HSTF = ATAN (HSTF = ATAN (GyGy / / --GxGx) this does not correct for quadrant) this does not correct for quadrant

•• MTF = ATAN (By/ MTF = ATAN (By/ --BxBx) this does not correct for quadrant) this does not correct for quadrant

•• INC = ATAN ((GxINC = ATAN ((Gx22 + Gy+ Gy22) ) 1/21/2 / / GzGz) this does not work above 90) this does not work above 90oo

BxBx Sin (HSTF) + By Sin (HSTF) + By CosCos (HSTF)(HSTF)•• AZ = ATAN {AZ = ATAN {--------------------------------------------------------------------------------------------------------------------------------------------}}

((Bx CosBx Cos (HSTF) (HSTF) -- By Sin (HSTF)) By Sin (HSTF)) CosCos (Inc) + (Inc) + BzBz Sin (Inc)Sin (Inc)

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Survey Quality ChecksSurvey Quality Checks

•• GtotalGtotal = (= (GxGx22 + Gy+ Gy22 +Gz+Gz22 ) ) 1/21/2

•• Btotal = (BxBtotal = (Bx22 + By+ By22 +Bz+Bz22 ) ) 1/21/2

((BxBx * * GxGx) + (By * ) + (By * GyGy) + () + (BzBz * * GzGz))•• MDIP = ASIN {MDIP = ASIN {--------------------------------------------------------------------------------------------}}

GtotalGtotal * Btotal* Btotal

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Sources of Azimuth ErrorsSources of Azimuth Errors

• Inclination is incorrect • Highside Toolface is incorrect• Mathematical Error• Magnetic Interference• Sensor Accuracy• Geographic/Directional – Small Horizontal

Magnetic Field• Wrong Declination

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MWD Survey AccuracyMWD Survey Accuracy

•• Drill Pipe AccelerationDrill Pipe Acceleration

•• Drill String Magnetic InterferenceDrill String Magnetic Interference

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Effect of Steel StabilizerEffect of Steel Stabilizer

•• Length of Non Length of Non Magnetic Collars Magnetic Collars implies a uniform, implies a uniform, nonnon--interrupted noninterrupted non--magnetic magnetic environmentenvironment

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Directional Sensor Package SpacingDirectional Sensor Package Spacing

•• NonNon--Mag Spacing is used to minimize Mag Spacing is used to minimize Drillstring Drillstring Magnetic interferenceMagnetic interference

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FluctuationsFluctuations

•• Secular Secular VariationsVariations

•• Diurnal Solar Diurnal Solar VariationsVariations

•• Magnetic StormsMagnetic Storms

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Eleven Year Cyclic VariationEleven Year Cyclic Variation

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Solar ActivitySolar Activity

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Azimuth Error Azimuth Error -- MagneticMagnetic

-5.00

-4.00

-3.00

-2.00

-1.00

0.00Degr

ees

Azim

uth

Erro

r

1 2 3 4 5 6 7 8 9

Inclination (10 - 90 Degrees)

Long Collar AZ Error @ 90 E or W

250 dBz (nT) errorBt = 59000Dip = 75

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Azimuth Error Azimuth Error -- Magnetic Magnetic

-5.00

-4.00

-3.00

-2.00

-1.00

0.00Degr

ees

Azim

uth

Erro

r

1 2 3 4 5 6 7 8 9




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-5.00

-4.00

-3.00

-2.00

-1.00

0.00Degr

ees

Azim

uth

Erro

r

1 2 3 4 5 6 7 8 9




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-5.00

-4.00

-3.00

-2.00

-1.00

0.00Degr

ees

Azim

uth

Erro

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1 2 3 4 5 6 7 8 9




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Declination Error Declination Error -- MagneticMagnetic

0.70 Dip in 2 hoursDip (Inc)

450 nT in 2 hoursBt (total Field)

Samples every minute / Major units in hours

30.0029.00

28.00

2.65 degrees in 2 hours

Declination from True North


SURVEY ACCURACY AND QUALITY CONTROL To achieve a high range of accuracy and devise a means of assuring it, is a significant, difficult, and expensive task. For simplicity’s sake, let’s say the accuracy goal is one foot per 1,000 feet of hole. This means that in a 10,000 foot wellbore survey, the operator is to be assured of bottom-hole location by plus or minus 10 feet.

Although other survey technologies (magnetic and free-gyro) may achieve this range of accuracy some percentage of the time, they have no available means of quality control to assure it. In the case of magnetics, although the technology has seen much improvement, error variables such as magnetic interference, declination corrections, northern latitudes, even sun spot activity pose difficult quality control problems. The free-gyro’s major error sources are surface orientation, gyro drift and tool misalignment.

No film-based survey device has an opportunity to achieve this level of accuracy with assurance because the film cannot be read to the accuracy required. To get in the range of one foot per l,000 feet requires azimuth and inclination accuracy’s in the range of 0.1 and 0.05 degrees, respectively. Very often, the terms accuracy and resolution of readings are confused. A survey system may be able to read survey data to 0.1 degree - that’s resolution, but providing that level of precision is a completely different matter.

Modern aerospace guidance techniques employing rate-gyros and accelerometers provide the only current means of both providing this range of survey accuracy and qualifying the information. These systems can accomplish this through extensive quality control procedures because rate-gyros and accelerometers can be calibrated for a level of performance and monitored and checked for data quality.

However, the accuracy of available systems varies. Reviewing a service company’s procedures for quality control and data verification is important to assigning a specification to a particular system. Rate-gyro and accelerometer quality also varies in its ability to achieve accuracy, and running procedures can also degrade survey quality. For example, if a survey probe is misaligned in the well, accurate readings degrade in the overall survey calculation. Rate-gyro system accuracy’s can also vary according to inclination and latitude. Some systems degrade, for example, above 75 degrees of latitude because the Earth and gravity vectors become smaller and more difficult to resolve.

GYRO ERRORS

External Forces

In the case of a free-gyro survey system, forces causing the gyro to drift off its surface orientation lead to azimuth error. Typical causes for drift include system shocks, bearing wear and the one inescapable force - Earth rotation. During a free-gyro survey, attempts are made to monitor drift and correct for it.

Drift The apparent drift of a gyro is caused by the influence of the Earth’s rotation. If a perfectly balanced gyro were located at the North Pole in a horizontal position, so that its axis of rotation would be at right angles to the earth axis, the rotation of the earth would indicate an apparent 360o turn of the axis in 24 hours, or an apparent drift of 15o per hour. At the South Pole, the same would be observed but in reversed direction.


At the Equator, the gyro axis would be parallel to the earth axis and the gyro would not show any apparent drift. The apparent drift caused by the rotation of the earth is corrected by applying a special force to the inner gimbal ring. An adjustable weight in the form of a screw is attached to the inner gimbal ring and has the effect of a vertical power on the gyro axis. Due to the phenomenon of precession, this force turns the outer gimbal ring. By adjustment of the screw, it can be set to offset the apparent drift at any geographic latitude by an identical counter acting force, to the effect that the gyro turns simultaneously with the rotation of the earth. The screw is set for the particular latitude where the gyro is used.

Temperature

Warming of the gyro can cause slight dislocations of the centre of gravity due to the varying expansion coefficients of the different materials, such as copper and steel. Possible errors caused by rising temperature are compensated by a piece of bimetal which is mounted on the inner gimbal frame and offsets sufficiently the unbalance caused by temperature through a bending effect.

lntercardinal Tilt Error or Gimbal Error The gimballing error encountered in a directional gyro is also known as intercardinal tilt error. Gimbal errors occur when the angular motions of gimbals do not correspond to the actual motion occurring about their reference axes. When a gimbal axis transducer is used, its output measures relative motion between gimbals, which is not necessarily the actual angular motion of the base. The gimbal error depends upon borehole inclination and the hole direction related to the reference direction.

In order to minimize such errors, when the surface orientation is carried out, the spin rotor axis should eventually be positioned in a plane parallel to the overall well direction anticipated, so as to result in a difference as little as possible.

SURVEY ACCURACY

The first paper that successfully dealt with this subject was prepared by Wolf and de Wardt, “ Borehole Position Uncertainty – Analysis of Measuring Methods and Derivation of Systematic Error Model”. The latest paper released is a summary of work completed by a small joint-industry group and a steering committee on wellbore survey accuracy – “Accuracy Prediction for Directional MWD”, SPE #56702. This section summaries some of the main points from these papers on sources of error with examples.

The photographic single shot instrument is the least accurate tool. The inclination error can be as great as 0.5 degrees and 2.0 degrees in azimuth and is very susceptible to human reading error. The electronic single shots have essentially the same accuracy as all other MWD equipment 0.2 degrees on inclination and 1.0 to 1.5 degrees in azimuth. The gyro tools have a significantly improved azimuth error of approximately 0.2 degrees but similar accuracy for inclination.

When considering survey accuracy for MWD tools there are several sources of error. In general all directional sensor packages have the same resolution but their accuracy is dependent upon their calibration and shift between calibrations. We have already discussed magnetic interference from BHA components or local area interference. Tool misalignment is the error caused by the tool being out-of-parallel with the wellbore axis. The value assumed for magnetic declination affects the computed azimuth, which comes from estimates on the magnetic dip and field strength. The last main source of error is drill pipe depth measurements.


Mathematical models have been generated to calculate the position uncertainty of wells based these sources of error and the type of survey tool. The numbers calculated generate an “ellipse of uncertainty” for a 2 standard deviation error. Essentially what it provides is a 3D volume that the wellbore could be within (a 95% confidence level that the actual wellbore path resides inside this ellipse).

Typical errors seen when comparing MWD to rate gyro surveys.

Case 1:

Horizontal well

TVD of 500m (1,600’)

Measured Depth to Casing Point of 700m (2,300’)

Case 2:

Horizontal well

TVD of 1,450m (4,750’)

Measured depth to casing point of 1537m (5,000’)

CASE CHANGE IN TVD LATERAL OFFSET

1 6.6’ (2m) 46’ (14m) 2 4.9’ (1.5m)

Obviously errors of this magnitude can have pronounced effects on wellbore positioning.

Potential sources of survey errors. It is important to understand the potential errors that can arise in the various surveying instruments and methods of surveying. The main sources of error are summarized below.

1. Long intervals between surveys. The calculations give some sort of averaging between surveys and so if the interval is long, the averaged path may be significantly different from the actual path. The more the wellbore path may have changed during the interval, the more significant the potential error. A deviated well would give rise to more inaccuracy than a vertical well for the same depth interval between surveys.

2. Inaccurate measured depths for the survey locations. This error can arise from a drillstring tally mistake, faulty depth counters on wireline units, or a simple error in writing down the information.

3. Reading errors. When surveys are recorded on photographic film (single and multi-shot surveys), there is always the chance that the surveyor may make a mistake. It is good practice for two people to independently read the film and compare their readings.

4. Instrument calibration errors. All measuring instruments should be calibrated regularly and a record made of the calibration date and results. The drilling program could include a cautionary note to check the calibration certificate, which should be kept with the tool. If the tool has not been recently calibrated or if the data is not available, the tool should be replaced.


5. Forgetting to account for magnetic variation. At most places on the Earth's surface there will be a difference between true and magnetic north. Most survey calculations are done relative to true north, which does not change. Magnetic north changes with time. To compensate for this, look at a recent aeronautical or marine chart or other suitable chart containing lines that join points of equal magnetic variation, called isogonals. The chart will also give a date of publication and state how quickly the variation changes in the area. It is therefore possible to assess what the current variation for your location will be. Variation can be east or west and this will be stated on the chart. If variation is west then the variation should be subtracted from the compass survey reading; if east it should be added. There is a rhyme which can help you remember this: "Variation west, compass best. Variation east, compass least."

6. Magnetic interference. Even if the correct configuration of Monels is run, magnetic interference may come from various places. Monels occasionally develop magnetic "hot spots"; these can be checked by running a compass along the Monel collar. These hot spots tend to be near the connections. Also, if you run a magnetic single shot on sandline or wireline, the line itself can develop a strong enough magnetic field to affect the survey tool. To avoid significant error due to the line, position the survey tool over 4 m away for a line diameter up to 5 mm and 8 m away for greater sizes. The survey tool could also be dropped using a timer and then fished on wireline so that the line is not attached to the tool when the survey is taken. Close proximity to other wells, fish that have been sidetracked past, or casings are also likely to cause interference.

7. Gyro tools do not suffer from magnetic interference. However, gyro tools have several potential sources of error. First, the tool has to be aligned on surface with a fixed reference that is at a known direction from the center of the rotary table. Incorrect initial alignment will throw out the entire survey. It may be possible to detect this by checking the recorded azimuths against a previous survey at the same depths. Gyroscopes also "precess"; that is, the gyro will slowly wander away from its initial alignment. The rate of precession depends on several factors, such as friction from the bearings and gimbals, the rotation of the Earth, and small imperfections in the gyro. The rate of precession is measured by doing regular drift checks on surface and while surveying. A drift check simply holds the tool on depth for 10 to 15 minutes so that several shots are taken. Examination of these shots will show the rate of precession so that the survey readings can be corrected for the total drift at the time of the survey. Laser ring gyros are more accurate than mechanical gyros.

Magnetic Interference

There are two types of magnetic interference; drill string and external magnetic interference which can include; 1) interference from a fish left in the hole; 2) nearby casing; 3) a magnetic “hot spot” in the drill collar; 4) fluctuation in the Earth’s magnetic field; and 5) certain formations (iron pyrite, hematite and possibly hematite mud).

Any deviation from the expected magnetic field value can indicate magnetic interference. External magnetic interference can occur as the drill string moves away from the casing shoe or from the casing window. It can also occur as another cased hole is approached. All surveying instruments using magnetometers will be affected in accuracy by any magnetic interference. In such a case, gyroscopic (gyro) measurements will have to be used. There are certain instances where a gyro survey may need to be used if the well requires steering out of casing or if a possible collision exists with another well. There are also cases where magnetic interference may be corrected or at least taken into account until a different BHA is used.


Drill String Magnetic Interference The drill string can be compared to a long slender magnet with its lower end comprising one of the magnetic poles. Even if the components of a drilling assembly have been demagnetized after inspection, the steel section of the drill string will become magnetized by the presence of the Earth’s field.

Drill string magnetism can be a source of error in calculations made from the supplied magnetometer data. This may happen as the angle builds from vertical (Figure 5-4) or as the azimuth moves away from a north/south axis. Also, changing the composition of the BHA between runs may change the effects of the drill string. Correction programs for magnetism of the drill string exist.

Changes in horizontal component of magnetic field with inclination

It is because of drill string magnetism that non-magnetic drill collars are needed. Non-magnetic drill collars are used to position the compass or direction sensors out of the magnetic influence of the drill string. The magnetometers are measuring the resultant vector of the Earth’s magnetic field and the drill string. Since this is in effect one long dipole magnet with its flux lines parallel to the drill string, only the Z-axis of the magnetometer package (Z-axis is usually the axis of the surveying tool) is affected, normally creating a greater magnetic field effect along this axis. The magnitude of this error is dependant on the pole strength of the magnetized drill string components and their distance from the MWD tool. The error will normally appear in the calculated survey as an increased total HFH value (higher total field strength than the Earth alone). This increase is due to the larger value of the Z-axis magnetometer. The total H value should remain constant regardless of the tool face orientation or depth as long as the hole inclination, azimuth and BHA remain relatively constant.

When drill string magnetism is causing an error on the Z-axis magnetometer, only the horizontal component of that error can interfere with the measurement of the Earth’s magnetic field (see Magnetic Field Strength section). The horizontal component of the Z-axis error is equal to the Z-axis error multiplied by the sine of the hole deviation. This is why experience has shown that the magnetic survey accuracy worsens as the hole angle increases (especially with drill string magnetic interference). Since the horizontal component of the Earth’s magnetic field is smaller on the Alaskan Slope, the error from a magnetized drill string is relatively greater than that experienced in lower latitudes. Thus, a 50 gammas error has a larger affect on a smaller horizontal component, 0.53% error in Alaska compared to only 0.20% in the Gulf of Mexico.


The increased value of the Z-axis due to drill string magnetism will normally cause all calculated azimuths to lie closer to north. This error will show up when a gyro is run in the well. Usually all MWD surveys will be positioned (magnetically) north of the gyro survey stations. (Some gyros derive True North from the Earth’s rotation.)

Minimizing Errors One way to minimize the error caused by the drill string is to eliminate as much of the magnetism as possible. This is done by isolating the magnetometer package with as many non-magnetic drill collars as possible. The length of the non-magnetic collars implies a uniform and non-interrupted non-magnetic environment. This, however, is not true in practice. Each connection in a drill string, whether magnetic or not, is magnetic due to the effects of the mechanical torque of the pin in the box. This mechanical stress causes the local metal around the connection to change its magnetic properties and can actually cause a survey azimuth reading error in the tens of degrees in some cases. Therefore, never space within 2 feet of a connection. Additionally, do not space exactly in the centre of a non- magnetic collar. When a collar has been bored from both ends, there is a very slight ridge at the point where the two bores come together. This becomes magnetically hot due to the cyclic rotation stresses to which the collar is subjected during rotary drilling. Usually, this effect can be removed by trepanning the collar bore. As much as 40o of azimuth error has been seen due to this effect.

Obviously the presence of a steel stabilizer or steel component between two non-magnetic collars results on a pinching of the lines of force (Figure 5-5). This is detrimental to the accuracy of the survey. A steel stabilizer may be satisfactory on the Equator, but not as far north as Alaska. In Alaska all stabilizers used in the BHA are non-magnetic, since a conventional steel stabilizer located between two non-magnetic collars results in an interfering field which may reach 250 gammas.

Even non-magnetic stabilizers are actually magnetic near the blades. At a minimum, hard metal facing and matrix used on stabilizers can be very magnetic. Never space inside a non-magnetic stabilizer.

The following are circumstances where more non-magnetic drill collars are necessary to counter drill string magnetism effects. These are also examples in which the azimuth accuracy will likely decrease.

• The further away from the Equator (in latitude).

• The larger the hole inclination.

• The further away from a north/south hole azimuth.

Note that even with 40m (120 feet) of non-magnetic material above the magnetometer package the effects of drill string magnetism in places like Alaska may still be seen.


Effect of steel stabilizer

Special Notes

• lf magnetic interference is encountered from the drill string, the total H value should remain constant regardless of tool face orientation or depth as long as the hole inclination, azimuth and BHA remain fairly constant.

• The horizontal component of the Z-axis error is equal to (Z-axis error) x Sin(I). This is why a magnetic survey declines as the hole angle increases (especially with drill string magnetic interference).

• Drill string interference is more pronounced in areas of high dip angle.

External Magnetic Interference

When magnetic interference from external sources is encountered (such as from a fish in the hole or from nearby casing), all three axis of the directional sensor package will be affected. Therefore, the total magnetic field will vary. The total H value will also vary when the sensor package is close to casing joints. If a hot spot occurs on a non-magnetic collar, the total H value will change with varying tool face settings, but will be repeatable when the BHA is placed in the same orientation. In places such as Alaska, total field strength can routinely vary by 100 gammas.

• Do not mistakenly interpret change in total H value as a failed magnetometer sensor. It may be caused by magnetic interference.

• Do not mistakenly interpret a change in a survey with a failed magnetometer or inclinometer; it may be due to a tool face dependency.


Directional Sensor Package Spacing

In order to avoid magnetic interference, non-magnetic drill collars must be used and empirical charts are used to estimate the length of non-magnetic material needed. Experiments have shown that mud motors can produce a magnetic field from 3 to 10 times greater than components such as steel stabilizers and short drill collars. As a rule of thumb, anytime a mud motor is run, a non-magnetic short drill collar (of 3m to 5m) should be placed between the motor and sensor package. It may even be necessary to use a non-magnetic orienting sub in some areas of the world.

The following formula can be used to accurately predict errors in azimuth due to magnetic interference from the drilling assembly.

IF = 770 + LP - LP (14 + X)2 (y + b)2 (y + b + c)2 AE = 57,300 x IF x SinI x Sin(Az – MD) H x Cos(dip) IF = calculated interfering field AE = Azimuth Error X = Length of non-magnetic collar above MWD, note the dimension 14 feet is an assumed value for the distance from the sensor package to the bottom of the NMDC and the actual value should be used for the respective tool configuration. b = Length of non-magnetic collar below MWD c = Length of magnetic material below MWD H = Total magnetic field strength in gammas Az = Azimuth of the well I = Inclination of the well MD = Magnetic declination Dip = Dip angle This formula is relatively easy to use and interpret. The absolute value of the predicted azimuth error (AE) should be less than 0.5 degrees. If it is not, continue adding lengths of non-magnetic drill collars both above and below the MWD collar until the AE value is below 0.5 degrees. Other equations have been prepared by other directional companies.

For horizontal drilling, and especially for well paths with a medium radius of curvature, it may be impractical to achieve a predicted azimuth error of less than 0.5 degree. Some operators may prefer to drill with a predicted error of one degree during the build up phase of the well and then correct for it later. If a mud motor is used to correct the well azimuth (on a slant hole) and a change in the magnetic field is observed, due to magnetic interference from the motor, the change may not be problem as long as the operator and directional driller are aware of the change and take it into account. A simple way would be to re-survey the corrected path with a different spacing or a different BHA.

Non-magnetic directional DC

1

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Directional Drilling FundamentalsDirectional Drilling Fundamentals


4/2002

Introduction to Directional DrillingIntroduction to Directional Drilling

•• Directional drilling is defined as the practice of Directional drilling is defined as the practice of controlling the direction and deviation of a well bore controlling the direction and deviation of a well bore to a predetermined underground target or location.to a predetermined underground target or location.

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Directional WellsDirectional Wells

•• SlantSlant•• Build and Build and

Hold Hold •• SS--CurveCurve•• Extended Extended

ReachReach•• HorizontalHorizontal

2

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Applications of Directional DrillingApplications of Directional Drilling

•• Multiple wells from offshore structureMultiple wells from offshore structure•• Relief wellsRelief wells•• Controlling vertical wellsControlling vertical wells

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•• SS--CurveCurve

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•• ExtendedExtended--Reach DrillingReach Drilling

•• Replace Replace subseasubsea wells and tap offshore reservoirs from wells and tap offshore reservoirs from fewer platformsfewer platforms

•• Develop near shore fields from onshore, andDevelop near shore fields from onshore, and•• Reduce environmental impact by developing fields from Reduce environmental impact by developing fields from

padspads

3

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Directional Drilling ToolsDirectional Drilling Tools

•• Steerable motorsSteerable motors•• Instrumented motors for Instrumented motors for geosteeringgeosteering applicationsapplications•• Drilling toolsDrilling tools•• Surveying/orientation servicesSurveying/orientation services•• Surface logging systemsSurface logging systems•• AtAt--bit inclinationbit inclination

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•• SidetrackingSidetracking

•• Inaccessible locationsInaccessible locations

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•• Drilling underbalancedDrilling underbalanced

•• Minimizes skin damage,Minimizes skin damage,•• Reduces lost circulation and stuck pipe incidents,Reduces lost circulation and stuck pipe incidents,•• Increases ROP while extending bit life, andIncreases ROP while extending bit life, and•• Reduces or eliminates the need for costly stimulation Reduces or eliminates the need for costly stimulation

programs.programs.

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Directional Drilling LimitationsDirectional Drilling Limitations

•• DoglegsDoglegs•• Reactive TorqueReactive Torque•• DragDrag•• HydraulicsHydraulics•• Hole CleaningHole Cleaning•• Weight on BitWeight on Bit•• Wellbore StabilityWellbore Stability

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Methods of Deflecting a WellboreMethods of Deflecting a Wellbore

•• Whipstock operationsWhipstock operations•• Still usedStill used

•• JettingJetting•• Rarely used today, still valid and inexpensiveRarely used today, still valid and inexpensive

•• Downhole motorsDownhole motors•• Most commonly used, fast and accurateMost commonly used, fast and accurate

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Whipstock OperationsWhipstock Operations

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JettingJetting

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Effect of Increased Bit WeightEffect of Increased Bit Weight

•• Increase Weight on Bit Increase Weight on Bit ––Increase Build Rate Increase Build Rate

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Effect of Increased Bit WeightEffect of Increased Bit Weight

•• Decrease Inclination Decrease Inclination --Decrease Weight on BitDecrease Weight on Bit

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Reasons for Using StabilizersReasons for Using Stabilizers

•• Placement / Gauge of stabilizers control directionalPlacement / Gauge of stabilizers control directional•• Stabilizers help concentrate weight on bitStabilizers help concentrate weight on bit•• Stabilizers minimize bending and vibrationsStabilizers minimize bending and vibrations•• Stabilizers reduce drilling torque less collar contactStabilizers reduce drilling torque less collar contact•• Stabilizers help prevent differential sticking and Stabilizers help prevent differential sticking and

key seatingkey seating

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Stabilizer ForcesStabilizer Forces

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Directional ControlDirectional Control

•• BHA typesBHA types

•• Building assembly Building assembly •• Dropping assemblyDropping assembly•• Holding assemblyHolding assembly

•• Design principlesDesign principles

•• Side forceSide force•• Bit tiltBit tilt•• HydraulicsHydraulics•• CombinationCombination

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Building AssembliesBuilding Assemblies

•• Two stabilizer assemblies Two stabilizer assemblies increase control of side force increase control of side force and alleviate other problemsand alleviate other problems

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Building AssembliesBuilding Assemblies

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Dropping AssembliesDropping Assemblies

•• To increase drop rate:To increase drop rate:•• increase tangency lengthincrease tangency length•• increase stiffnessincrease stiffness•• increase drill collar weightincrease drill collar weight•• decrease weight on bitdecrease weight on bit•• increase rotary speedincrease rotary speed

•• Common TL: Common TL: •• 30 ft30 ft•• 45 ft45 ft•• 60 ft60 ft•• 90 ft90 ft

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Dropping AssembliesDropping Assemblies

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Holding AssembliesHolding Assemblies•• Designed to minimize side force and decrease Designed to minimize side force and decrease

sensitivity to axial loadsensitivity to axial load

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Stabilization PrincipleStabilization Principle

•• Stabilizers are placed at specified points to control Stabilizers are placed at specified points to control the drill string and to minimize downhole the drill string and to minimize downhole deviationdeviation

•• The increased stiffness on the BHA from the added The increased stiffness on the BHA from the added stabilizers keep the drill string from bending or stabilizers keep the drill string from bending or bowing and force the bit to drill straight aheadbowing and force the bit to drill straight ahead

•• The packed hole assembly is used to maintain The packed hole assembly is used to maintain angleangle

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Special Special BHA’sBHA’s

•• Tandem StabilizersTandem Stabilizers•• Provides greater directional controlProvides greater directional control•• Could be trouble in High Doglegs Could be trouble in High Doglegs

•• Roller ReamersRoller Reamers•• Help keep gauged holes in hard formationsHelp keep gauged holes in hard formations•• Tendency to drop angleTendency to drop angle

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Application of Steerable AssembliesApplication of Steerable Assemblies

•• Straight Straight -- HoleHole•• Directional Drilling / SidetrackingDirectional Drilling / Sidetracking•• Horizontal DrillingHorizontal Drilling•• Re Re -- entry Wellsentry Wells•• Underbalanced Wells / Air DrillingUnderbalanced Wells / Air Drilling•• River CrossingsRiver Crossings

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Steerable AssembliesSteerable Assemblies

•• Build Build

•• DropDrop

•• HoldHold

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Mud MotorsMud Motors

TurbineTurbine PDMPDM

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Commander Commander TMTM PDM MotorsPDM Motors

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Motor SelectionMotor Selection

•• These are the three common motor configurations These are the three common motor configurations which provide a broad range of bit speeds and which provide a broad range of bit speeds and torque outputs required satisfying a multitude of torque outputs required satisfying a multitude of drilling applicationsdrilling applications•• High Speed / Low Torque High Speed / Low Torque -- 1/2 Lobe1/2 Lobe•• Medium Speed / Medium Torque Medium Speed / Medium Torque -- 4/5 Lobe4/5 Lobe•• Low Speed / High Torque Low Speed / High Torque -- 7/8 Lobe7/8 Lobe

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Components of PDM MotorsComponents of PDM Motors•• Dump SubsDump Subs•• Motor SectionMotor Section•• Universal Joint AssemblyUniversal Joint Assembly•• Adjustable AssemblyAdjustable Assembly•• Bearing AssemblyBearing Assembly

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Dump Sub AssemblyDump Sub Assembly

•• Hydraulically actuated valve located at the top of Hydraulically actuated valve located at the top of the drilling motorthe drilling motor

•• Allows the drill string to fill when running in holeAllows the drill string to fill when running in hole•• Drain when tripping out of holeDrain when tripping out of hole•• When the pumps are engaged, the valve When the pumps are engaged, the valve

automatically closes and directs all drilling fluid automatically closes and directs all drilling fluid flow through the motorflow through the motor

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Dump SubDump Sub

•• Allows Drill String Allows Drill String Filling and DrainingFilling and Draining

•• OperationOperation-- Pump Off Pump Off -- OpenOpen-- Pump On Pump On -- ClosedClosed

•• Discharged PortsDischarged Ports•• ConnectionsConnections

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Motor SectionMotor Section•• Positive Positive

Displacement Motor Displacement Motor ( PDM )( PDM )

•• Lobe ConfigurationsLobe Configurations•• StagesStages

Performance Performance CharacteristicsCharacteristics

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Motor SectionMotor Section

•• Positive Displacement MotorPositive Displacement MotorPDMPDM

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Universal Joint AssemblyUniversal Joint Assembly•• Converts Eccentric Rotor RotationConverts Eccentric Rotor Rotation

in to Concentric Rotationin to Concentric Rotation

•• Universal JointUniversal Joint

•• Flex RodFlex Rod

Constant Velocity Joint Constant Velocity Joint ----

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Adjustable AssemblyAdjustable Assembly•• Two Degree and Three Two Degree and Three

DegreeDegree•• Field Adjustable in Field Adjustable in

Varying Increments to Varying Increments to the Maximum Bend the Maximum Bend AngleAngle

•• Used in Conjunction Used in Conjunction with Universal Joint with Universal Joint AssemblyAssembly

H = 1.962 o

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Bearing AssemblyBearing Assembly

•• Transmits Bit Axial and Radial Loads to the Drill Transmits Bit Axial and Radial Loads to the Drill StringString

•• Thrust BearingThrust Bearing•• Radial BearingRadial Bearing•• Oil ReservoirOil Reservoir•• Balanced PistonBalanced Piston•• High Pressure SealHigh Pressure Seal•• Bit Box ConnectionBit Box Connection

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Motor SpecificationsMotor Specifications•• Motor SpecificationsMotor Specifications•• Dimensional DataDimensional Data•• Ultimate Load FactorsUltimate Load Factors•• Performance ChartsPerformance Charts

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Motor SpecificationsMotor Specifications

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Motor SpecificationsMotor Specifications

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Performance ChartsPerformance Charts

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Operational ConstraintsOperational Constraints•• ServicingServicing

-- HoursHours•• Drilling FluidDrilling Fluid

--Percentage Sands Percentage Sands -- 0.5 %0.5 %-- Percentage Solids Percentage Solids -- 5 %5 %

•• Circulation RateCirculation Rate•• Full Load ( Differential Pressure)Full Load ( Differential Pressure)

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Operational Constraints Cont’d Operational Constraints Cont’d

•• Temperature Temperature -- 200 Degrees F200 Degrees F•• Motor StallingMotor Stalling•• No No SpuddingSpudding

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Disadvantages of PDMDisadvantages of PDM

•• Low Maximum Temperature CapabilityLow Maximum Temperature Capability

•• Susceptible to Oil Based Mud DamagedSusceptible to Oil Based Mud Damaged

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Operational FeaturesOperational Features

•• StabilizationStabilization•• Off Off -- set Padset Pad•• Rotor BypassRotor Bypass

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Stabilization Stabilization •• Improves Well Improves Well -- bore Straightness and bore Straightness and

ControlControl•• Screw Screw -- on Stabilizeron Stabilizer•• Integral Blade StabilizersIntegral Blade Stabilizers

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Offset Offset -- Set PadSet Pad•• Adjustable PAD Located Below Adjustable Adjustable PAD Located Below Adjustable

BendBend•• Oriented with Center of Pad on Low Side of Oriented with Center of Pad on Low Side of

BendBend•• Provides Lower Point on Drilling Motor to Provides Lower Point on Drilling Motor to

Increase BuildIncrease Build Rate CapacityRate Capacity

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Rotor BypassRotor Bypass•• Used to Increase the Flow Rate Through the Used to Increase the Flow Rate Through the

Drilling Motor Beyond the Capacity of the Power Drilling Motor Beyond the Capacity of the Power SectionSection

•• All Multi All Multi -- lobe Motors from 3 3/8’’ and lobe Motors from 3 3/8’’ and Larger Use Ported RotorsLarger Use Ported Rotors

•• May be Field Installed if RequiredMay be Field Installed if Required

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Trouble ShootingTrouble Shooting•• Pressure IncreasesPressure Increases•• Pressure LossesPressure Losses•• Lack of PenetrationLack of Penetration

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Pressure IncreasesPressure Increases•• Bearing Pack SeizedBearing Pack Seized•• Motor or Bit PluggedMotor or Bit Plugged•• Tight HoleTight Hole

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Pressure LossesPressure Losses

•• Twist Twist -- offoff•• Dump Sub InoperableDump Sub Inoperable•• Stater Stater Worn OutWorn Out•• WashhingWashhing

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Lack of PenetrationLack of Penetration•• Bit WearBit Wear•• Stator Wear (Weak Motor)Stator Wear (Weak Motor)•• Internal Motor DamageInternal Motor Damage•• Incorrect WOBIncorrect WOB•• Formation ChangeFormation Change•• Stabilizer Hanging UpStabilizer Hanging Up

19

4/2002

Motor Performance TestMotor Performance Test

4/2002

Motor History Motor History

4/2002

Motor Service ReportMotor Service Report

20

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Planning a Directional WellPlanning a Directional Well

•• GeologyGeology•• Completion and ProductionCompletion and Production•• Drilling ConstraintsDrilling Constraints

4/2002

GeologyGeology

•• LithologyLithology being drilled through being drilled through •• Geological structures that will be drilled Geological structures that will be drilled •• Type of target the geologist is expecting Type of target the geologist is expecting •• Location of water or gas topLocation of water or gas top•• Type of WellType of Well

4/2002

Completion and ProductionCompletion and Production

•• Type of completion required (Type of completion required (““fracfrac jobjob””, pumps , pumps and rods, etc.)and rods, etc.)

•• Enhanced recovery completion requirementsEnhanced recovery completion requirements•• Wellbore positioning requirements for future Wellbore positioning requirements for future

drainage/production plansdrainage/production plans•• Downhole temperature and pressureDownhole temperature and pressure

21

4/2002

DrillingDrilling

•• Selection of surface location and well layoutSelection of surface location and well layout•• Previous area drilling knowledge and identifies Previous area drilling knowledge and identifies

particular problematic areasparticular problematic areas

4/2002

DrillingDrilling

•• Casing size and depthsCasing size and depths•• Hole sizeHole size•• Required drilling fluidRequired drilling fluid•• Drilling rig equipment and Drilling rig equipment and

capabilitycapability•• Length of time directional services Length of time directional services

are utilizedare utilized•• Influences the type of survey Influences the type of survey

equipment and equipment and wellpathwellpath

4/2002

PlanningPlanning

•• Build ratesBuild rates•• Build and hold profiles should be Build and hold profiles should be

at least 50mat least 50m•• Drop rate for SDrop rate for S--curve wells is curve wells is

preferably planned at 1.5 preferably planned at 1.5 oo/30m /30m •• KOP as deep as possible to KOP as deep as possible to

reduce costs and rod/casing wearreduce costs and rod/casing wear•• In build sections of horizontal In build sections of horizontal

wells, plan a soft landing sectionwells, plan a soft landing section

22

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PlanningPlanning

•• Avoid high inclinations Avoid high inclinations through severely faulted, through severely faulted, dipping or sloughing dipping or sloughing formationsformations

•• On horizontal wells clearly On horizontal wells clearly identify gas / water contact identify gas / water contact points points

•• Turn rates in lateral Turn rates in lateral sections of horizontal sections of horizontal

•• Verify motor build ratesVerify motor build rates

4/2002

PlanningPlanning

•• Where possible start a Where possible start a sidetrack at least 20m sidetrack at least 20m out of casing out of casing

•• Dogleg severity could Dogleg severity could approach 14approach 14oo/30m /30m coming off a coming off a whipstockwhipstock

•• Identify all wells within Identify all wells within 30m of proposed well 30m of proposed well path and conduct antipath and conduct anti--collision checkcollision check


DIRECTIONAL DRILLING FUNDAMENTALS

Introduction to Directional Drilling When preparing to drill a vertical or directional well, all operational components of the process are reviewed, optimized and included in a drilling program. The surface location is scouted to determine the best site that will allow for any natural drift, provide suitable access for drilling rig, service rig, production facilities and can be constructed for a reasonable cost. A casing program is prepared to provide 1) adequate well control, 2) prevent water table contamination, 3) maintain wellbore integrity, 4) plan for varying formation fracture gradients, and 5) provide hydraulic isolation of various producing zones.

Mud programs are developed to provide good wellbore cleaning, reasonable filter cake development and minimal formation damage. Cement programs are required to provide good hydraulic isolation and casing support given the bottom hole temperature and pressure.

Since the highest possible rate of penetration possible is desired, considerable time is spent preparing an effective bit program to optimally drill the well. Previous wells drilled in the area are reviewed, to determine any potential drilling problems. Finally a proper BHA and drill string design is prepared to provide sufficient design safety parameters.

A directional drilling company will review most of these same components or ask the operator what he is selecting and apply it to the well profile and equipment limitations. For example the drilling fluid needs to be compatible with the Measurement While Drilling (MWD) equipment and motors. With their area knowledge it will also be reviewed for hole cleaning capability for high inclination wells. A drilling motor is selected that will provide optimum performance for the planned hydraulics or modifications are recommended.

A bottom hole assembly (BHA) and drill string design is suggested that will allow the best ROP for the different drilling conditions (rotating versus orient or slide drilling). In some cases the desired well path cannot be optimally drilled with the drill string currently available on the rig and changes are recommended.

Bit selection for a standard vertical well may not be suitable for the planned directional well path. Although a particular PDC bit provides the best ROP for the area, it may not provide the directional control needed. Also special drilling motors may be required to provide sufficient horsepower. If the project involves sidetracking of the horizontal legs special diamond sidetrack bits may be required.

Area formation integrity knowledge while it is being directional drilled through (sloughing, loss of inclination, inability to control direction, potential for differential sticking to name a few) is extremely important to minimize drilling time or potential problems. Let’s assume a directional plan with a very tight target size is prepared that kicks off very low in a formation that has a history of erratic build rates. Several things could happen in this scenario:

• Planned build rates are attained and target reached

• Very aggressive oriented drilling operations are required (full single slides) and the ROP is half of normal

• Trips required to change the motor setting (increase or decrease the adjustable housing setting)


• Erratic doglegs are created that may cause problems later when running casing

• Target is missed and well must be plugged back and sidetracked

When permitted, a directional company also reviews the well pad layout and provides their recommendations to reduce directional costs for multiple well pads. When they are involved with a project from the start and are aware of future re-entries, multi-laterals, sidetracks and production requirements a more optimally tuned well path can be designed.

APPLICATIONS OF DIRECTIONAL DRILLING

Multiple Wells From Offshore Structure One of today's more common applications of directional drilling techniques is in offshore drilling. Many oil and gas deposits are situated beyond the reach of land based rigs. To drill a large number of vertical wells from individual platforms is impractical and would be uneconomical. The conventional approach for a large oilfield has been to install a fixed platform on the seabed, from which as many as sixty directional wells may be drilled. The bottomhole locations of these wells can be carefully spaced for optimum recovery. This type of development greatly improves the economic feasibility of the expensive offshore industry by reducing the number of platforms required and simplifying the gathering system.

In a conventional development, the wells cannot be drilled until the platform has been constructed and installed in position. This may mean a delay of 2 - 5 years before production can begin. Pre-drilling some of the wells through a subsea template while the platform is being constructed can considerably reduce this delay. These wells are directionally drilled from an offshore rig, usually a semi-submersible, and tied back to the platform once it has been installed.

Relief Wells

Directional techniques are used to drill relief wells in order to "kill" blowout wells. The relief well is deviated to pass as close as possible in the reservoir to the uncontrolled well: it is not generally targeted to hit the out of control well as costs to do this would be prohibitive. Heavy mud is pumped into the reservoir to overcome the pressure and bring the wild well under control.

Controlling Vertical Wells Directional techniques are used to "straighten crooked holes". In other words, when deviation occurs in a well which is supposed to be vertical, various techniques are used to bring the well back to vertical. This was one of the earliest applications of directional drilling.


Sidetracking

Sidetracking out of an existing wellbore is another application of directional drilling. This sidetracking may be done to bypass an obstruction (a "fish") in the original wellbore or to explore the extent of the producing zone in a certain sector of a field.

Inaccessible Locations

Directional wells are often drilled because the surface location directly above the reservoir is inaccessible, either because of natural or man-made obstacles. Examples include reservoirs under cities, mountains, lakes, etc.

Other Applications

Directional wells are also drilled to avoid drilling a vertical well through a steeply inclined fault plane, which could slip and shear the casing.

Potential Shear Point


Directional Wells may also be used to overcome the problems of salt dome drilling. Instead of drilling through the salt, the well is drilled at one side of the dome and is then deviated around and underneath the overhanging cap.

Directional wells may also be used where a reservoir lies offshore but quite close to land, the most economical way to exploit the reservoir may be to drill directional wells from a land rig on the coast.

Reservoir Optimization

Horizontal drilling is the fastest growing branch of directional drilling. Horizontal wells allow increased reservoir penetration, especially in thinner reservoirs, allow increased exposure of the pay zone and allow higher production rates at equivalent drawdowns. Numerous specific applications for horizontal drilling are being developed with major advances occurring in the tools and techniques used.


Multilateral Wells

Within the science of horizontal drilling, multilateral hole drilling is rapidly becoming a common occurrence. Wells are drilled horizontally to total depth and laterals drilled from them in various directions. These laterals remain essentially horizontal and are directionally controlled to ensure maximum pay zone exposure.

DIRECTIONAL DRILLING LIMITATIONS Any drilling limit described in a textbook written today would be simply broken tomorrow by some operator. We have drilled horizontal wells with laterals over 6,100m long; extended reach wells with over 10,000m of horizontal reach (horizontal to vertical ratio of 6 or 7 to 1); multi-lateral horizontal wells with 10 legs; purposefully turned horizontal wells 180o in bearing; drilled 27 wells off a single land based pad location; re-entered just about every wellbore configuration to drill to a new target and are now drilling stacked well pairs within 3m (10’) of each other. Coiled tubing drilled wells are also setting new records with lateral sections in excess of 1,200m. Just about anything can be drilled provided you have the financial support. It is better to know the potential equipment or wellbore limitations. The following is a list of some of the factors considered when planning a directional well:

1.) Through experience many operators have established their own maximum inclination and/or dogleg severity limits to minimize rod and casing wear.

2.) Open-hole and cased hole logging equipment have limits on dogleg severity the tools can safely pass through that depends upon the tool OD, hole OD and tool length.

3.) It may be impossible to get sufficient weight on bit (WOB) to drill the well depending upon factors such as drag, drill string assembly design, mud type and hole geometry to name a few.

4.) Key seat and differential sticking potentials.

5.) Maximum dogleg directional equipment can be rotated or slid through (bending stresses).

6.) Wellbore stability (tectonic conditions, sloughing, boulders)

7.) Ability to steer the BHA along the required course (reactive torque).

8.) Ability for equipment to build inclination at the required rates

As directional drilling technologies continue to develop, new applications will emerge. Although oil and gas drilling applications will continue to dominate the future of the directional industry, environmental and economic considerations will force other industries to consider directional drilling alternatives to conventional technologies.

Methods of Deflecting a Wellbore There are several methods of deflecting a wellbore. Deflecting means changing the inclination and/or direction of a wellbore. Three common methods of accurately kicking off a well are whipstock operations, jetting, and downhole motors. The mud motor techniques are most commonly used because they are fast and accurate, however the whipstock is still used. Jetting is rarely used today, but it is still a valid and inexpensive technique.

Rotary bottomhole assemblies are the least expensive method of deflecting a well and should be used whenever possible. Unfortunately, the exact response of a rotary bottomhole assembly is very difficult to predict and left or right hand “walk” is almost impossible to control. When refinements of the wellbore course are critical, a mud motor is typically used.


Openhole Whipstock The whipstock was the first widely used deflection tool for changing the wellbore trajectory, and is seldom used in open-hole deflections today. A whipstock is selected according to the wedge needed to effect the desired deflection. A bit that is small enough to fit in the hole with the whipstock is then chosen; at the start of the running mode, the bit is locked to the top of the whipstock. When the whipstock is positioned at the kickoff depth, whether it is the total depth of the wellbore or the top of a cement plug, it is carefully lowered to bottom, and the centerline of the toe is oriented in the desired direction by a conventional nonmagnetic collar with a mule-shoe sub and by a single-shot survey. With the whipstock assembly oriented, enough weight is applied to the toe of the wedge so that it will not move when rotation begins.

Additional weight is applied to shear the pin that holds the drill collars to the wedge; then rotation can begin. Forcing the bit to cut sideways as well as forward, the wedge deflects the bit in an arc set by the curvature of the whipstock. When the bit reaches the end of the wedge, it ordinarily continues in the arc set by the wedge. Drilling continues until the top of the whipstock assembly reaches the stop.

The whipstock is then retrieved and the hole is opened with a pilot bit and a hole-opener. The wellbore is enlarged to the original hole size, and the assembly is pulled again. A full gauge directional BHA is then run and standard drilling is resumed.

Retrievable Whipstock Operations

Jetting

The jet bit method of deflecting a well was, at one time, the most common method used in soft formations. Jetting has been successfully used to depths of 8,000 feet (2,400m); however the economics of this method and the availability of other directional drilling tools limit its use.


Geology is the most important influence on where jetting can be used; next in importance is the amount of hydraulic energy available for jetting. Sandstones and oolitic limestones that are weakly cemented are the best candidates for jetting. Unconsolidated sandstones and some other types of very soft rocks can be jetted with some degree of success. Very soft rocks erode too much, making it difficult to jet in the desired direction; when rotation begins, the stabilizers cut away the curved, jetted section and return to a nearly vertical well path.

Even though shales may be soft, they are not good candidates for jetting. Most medium-strength rock is too well cemented to jet with conventional drilling rig pumps, so it limits the depth to which jetting can be applied. Higher pressures and more hydraulic energy can extend the depth to which jetting is practical.

A major drawback to jetting is that the formation must be favorable at a shallow depth or in the desired kickoff interval; otherwise, the technique is no better than the use of a mud motor with a deflecting device. Another problem is that if jetting is continued too long without conventional drilling being resumed, large doglegs can be created.

There are special bits made for jetting including those with two cones and an elongated jet nozzle replacing the third cone. The elongated nozzle provides the means to jet the formation while the two cones provide the mechanism for drilling. Other tri-cone deflection bits are available with an enlarged fluid entrance to one of the jets. This allows a greater amount of fluid to be pumped through one of the jets during jetting operations.

To deflect a well using the jet method, the assembly is run to the bottom of the hole, and the large jet is oriented in the desired direction. The kelly should be high to allow rotary drilling after the deflection is started. The center of the large nozzle represents the toolface and is oriented in the desired direction. Maximum circulation rate is used while jetting. Jet velocity for jetting should be 150 m/sec (500 ft/sec).

Jetting Bit

The drill string is set on bottom and if the formation is sufficiently soft, the WOB drills off. A pocket is washed into the formation opposite the large nozzle. The bit and near-bit stabilizer work their way into the pocket (path of least resistance). Enough hole should be jetted to “bury” the near-bit stabilizer. If required, the bit can be pulled off bottom and the pocket spudded. The technique is to lift the string about 1.5m (5’) off bottom and then let it fall, catching it with the brake so that the stretch of the string (rather than the full weight of the string) causes it to spud on bottom. Spudding can be severe on a drillstring, drilling line and derrick and should be kept to a minimum. Another technique that may help is to ‘rock’ the rotary table a little (15o) right and left of the orientation mark while jetting.

Large TFA

Nozzle


Jetting Operations

After a few feet have been jetted, the pumps are cut back to about 50% of that used for jetting and the drill string is rotated. It may be necessary to pull off bottom momentarily due to high torque (near-bit stabilizer wedged in the pocket). High WOB and low RPM are used to try to bend the collars above the near-bit stabilizer and force the BHA to follow through the trend established while jetting. The remaining length on the kelly is drilled down. Deflection is produced in the direction of the pocket i.e. the direction in which the large jet nozzle was originally oriented.

To clean the hole prior to connection/survey, the jet should be oriented in the direction of deviation. After surveying, this orientation setting (toolface setting) is adjusted as required, depending on the results achieved with the previous setting. Dogleg severity has to be watched carefully and reaming performed as required.

The operation is repeated as often as is necessary until sufficient inclination has been achieved and the well is heading in the desired direction. The hole inclination can then be built up to maximum angle using 100% rotary drilling and an appropriate angle build assemble.

Rotary Bottomhole Assemblies

There are three basic types of rotary bottomhole assemblies used in directional drilling: Building Assemblies, Dropping Assemblies, and Holding Assemblies

A building assembly is intended to increase hole inclination, a dropping assembly is intended to decrease hole inclination, and a holding assembly is intended to maintain hole inclination. It should be noted that a building assembly might not always build angle. Formation tendencies may cause the assembly to drop or hold angle. The building assembly is intended to build angle. The same is true for the dropping and holding assemblies.

Before the invention of measurement while drilling (MWD) tools and steerable motors, rotary bottomhole assemblies (BHA) were used to deflect wellbore. A bottomhole assembly is the arrangement of the bit, stabilizer, reamers, drill collars, subs and special tools used at the bottom of the drill string. Anything that is run in the hole to drill, ream or circulate is a bottomhole assembly. The simplest assembly is a bit, collars and drill pipe and is often termed a slick assembly. The use of this


assembly in directional drilling is very limited and usually confined to the vertical section of the hole where deviation is not a problem.

In order to understand why an assembly will deviate a hole, let’s consider the slick assembly, which is the simplest and easiest to understand. The deviation tendency in this assembly is a result of the flexibility of the drill collars and the forces acting on the assembly causing the collars to bend. Even though drill collars seem to be very rigid, they will bend enough to cause deviation.

The point at which the collars contact the low side of the hole is called the tangency point. The distance L from the bit to the tangency point is dependent upon collar size, hole size, applied bit weight, hole inclination, and hole curvature. Generally, the distance L is less than 50m (150 feet).

Above the tangency point of the slick assembly, the remainder of the drill string generally has no effect on deviation. As weight is applied to the bit, the tangency point will move closer to the bit.

Because of the bending of the drill collars, the resultant force applied to the formation is not in the direction of the hole axis but is in the direction of the drill collar axis. As bit weight is applied, the tangency point moves toward the bit increasing the angle. It can readily be seen that an increase in bit weight leads to an increase in deviation tendency.

Effect of Increased Bit Weight

Unfortunately, the direction of the resultant force is not the only force involved. The resultant force can be broken up into its components. The primary force would be the drilling force in line with the axis of the borehole. The bit side force is caused by the bending of the collars and is perpendicular to the axis of the borehole. The force due to gravity (acting on the unsupported section of drill collars) is in the opposite direction and counteracts the side force. The net deviation force is then equal to the summation of the bit side force and the force due to gravity. If the force due to gravity is greater than the bit side force the angle will drop.

Changing the weight on bit can control the deviation tendency. Increasing the bit weight will lower the tangency point increasing the angle. Since resultant force is proportional to the sine of angle, an increase in bit weight increases the bit side force and ultimately the deviation tendency. Of course, a decrease in bit weight will decrease the deviation tendency.


Another factor affecting deviation tendency is the stiffness of the drill collars. Stiffer collars will bend less, which increases the height to the tangency point. If the tangency point moves up the hole, then the deviation tendency will be reduced. Therefore, small diameter drill collars will enhance the deviation tendency.

The addition of a stabilizer above the bit significantly affects the deviation tendency of a bottomhole assembly. The stabilizer acts as a fulcrum around which the unsupported section of the bottomhole assembly reacts. The addition of the moment arm between the bit and stabilizer increases the bit side force. In fact, the single stabilizer assembly is a very strong building assembly.

Reasons for Using Stabilizers

1.) The placement and gauge of stabilizers are used as the fundamental method of controlling the directional behavior of most bottom hole assemblies.

2.) Stabilizers help concentrate the weight of the BHA on the drill bit.

3.) Stabilizers resist loading the bit in any direction other than the hole axis.

4.) Stabilizers minimize bending and vibrations, which cause tool joint wear and damage to BHA components such as, MWD tools.

5.) Stabilizers reduce drilling torque by preventing collar contact with the side of the hole and by keeping the collars concentric in the hole but also add torque due to their side-loading.

6.) Stabilizers help prevent differential sticking and key seating.

The side cutting ability of a bit is proportional to the side force exerted at the bit. Under static conditions, the side force on the bit can be calculated using a computer program. When the entire bottomhole assembly is considered, it can also be shown the stabilizers in the assembly exert a side force. The stabilizers have a side-cutting ability too. One would think the deviation tendency could then be calculated. Unfortunately, the side forces will change under dynamic conditions. Both the bit and the stabilizers cut sideways reducing the side force on each until equilibrium is reached.

Under dynamic conditions, the relative side-cutting of the bit and stabilizers becomes complicated which, in turn, makes the deviation tendency very difficult to calculate. The relationship between the bit and stabilizer side-cutting is dependent upon the type of bit, type of stabilizer, penetration rate, rotary speed, lithology, hole size, and bottomhole assembly type.

Stabilizer Forces


The side-cutting ability of soft formation bits is generally considered better than for hard formation bits. Diamond bits have a greater side-cutting ability because they are designed with more of a cutting structure along the lateral face of the bit.

The magnitude and direction of the formation deviation tendency will depend upon bed dip. Generally, the bit will walk up dip when beds are dipping 0o to 45o and down dip when beds are dipping 65o to 90o. Bed dips between 45o and 65o can cause either an up dip or down dip walk. Bed strike can cause the bit to walk left or right.

Building Assemblies As previously stated, the building assembly uses a stabilizer acting as a fulcrum to apply side forces to the bit. The magnitude of that force is a function of the distance from the bit to the tangency point. An increase in bit weight and/or decrease in drill collar stiffness will increase the side force at the bit increasing the rate of build.

The strongest building assembly consists of one stabilizer placed 3 to 6 feet above the bit face with drill collars and drill pipe above the stabilizer. This assembly will build under the majority of conditions. Of course, the rate of build will be controlled by formation tendencies, bit and stabilizer types, lithology, bit weights, drill collar stiffness, Drillstring RPM’s, penetration rate, and hole geometry.

Building Assemblies

Another strong to moderate building assembly consists of a bottomhole stabilizer placed 3 to 6 feet from the bit face, 60 feet of drill collars, stabilizer, collars, and drill pipe. This is the most common assembly used to build angle. The second stabilizer tends to dampen the building tendency. This assembly can be used when the previous assembly builds at an excessive rate. Other building assemblies can be seen above.


Dropping Assemblies A dropping assembly is sometimes referred to as a pendulum assembly. In this assembly, a stabilizer is placed at 30, 45, or 60 feet from the bit. The stabilizer produces a plumb bob or pendulum effect; hence the name pendulum assembly. The purpose of the stabilizer is to prevent the collar from touching the wall of the hole causing a tangency point between the bit and stabilizer.

An increase in the length of the bottomhole assembly (the length below the tangency point) results in an increase in the weight. Since the force is determined by that weight, the force is also increased exceeding the force due to bending. The net result is a side force on the bit causing the hole to drop angle.

Additional bit weight will decrease the dropping tendency of this assembly because it increases the force due to bending. Should enough bit weight be applied to the assembly to cause the collars to contact the borehole wall (between the stabilizer and the bit), the assembly will act as a slick assembly. Only the section of the assembly below the tangency point affects the bit side force.

If an increase in dropping tendency is required, larger diameter or denser collars should be used below the stabilizer. This increases the weight of the assembly, which results in an increase in dropping tendency. As an example, suppose a dropping assembly with 7” (178mm) drill collars was being used in a 12 ¼” (311mm) hole. By substituting 9” (229mm) collars for the 7” collars, an increase in dropping tendency can be achieved.

Dropping assemblies will have a higher rate of drop as hole inclination increases.

Dropping Assemblies


Holding Assemblies Holding the inclination in a hole is much more difficult than building or dropping angle. Under ideal conditions, most assemblies either have a building or dropping tendency. Most straight hole sections of a directional well will have alternating build and drop tendencies. When holding inclination, these build and drop sections should be minimized and spread out over a large interval. The most common assemblies are indicated below indicating their strength at holding inclination.

Holding Assemblies

When selecting a hold assembly, research the well records in the area to find out which assembly works best for the types of formations being drilled. If no formation is available, use a medium strength assembly and adjust it as necessary.

These build and drop assemblies are still used on directional wells but generally limited to slant hole drilling. The hold assemblies are very commonly used on deep vertical wells to minimize the amount of directional drilling required.

SPECIAL BHA’S

Tandem Stabilizers It’s fairly common to run a string stabilizer directly above the near-bit stabilizer. This is normally for directional control purposes. An alternative is to run a near-bit with a longer gauge area for greater wall contact. High rotary torque may result in either case. It is dangerous to run tandem stabilizers directly after a more limber BHA due to the reaming required and potential sticking.


Roller Reamers In medium/hard formations where rotary torque is excessive, it may be necessary to dispense with some to all of the stabilization. Roller reamers are a good alternative however they behave different then stabilizers. As a rule they tend to drop angle.

APPLICATIONS OF STEERABLE ASSEMBLIES

A steerable assembly is defined as a bottomhole assembly whose directional behavior can be modified by adjustment of surface controllable drilling parameters including rotary speed and weight on bit. The ability to modify behavior in this way enables the assembly to be steered toward a desired objective without its removal from the wellbore. To some extent, rotary assemblies are steerable if the build or drop tendency is weight sensitive. However, the ability to control a rotary assembly is limited especially controlling walk.

The most common steerable assembly consists of a Positive Displacement Motor (PDM) that incorporates a fixed or adjustable bent housing on top of the bearing housing below the stator. With the smaller displacement of the bit as compared to using a bent sub, the motor can be safely rotated at RPM’s up to 50 depending upon the bend setting and formation. The motor housing may also incorporate an 3mm (1/8”) undergauge stabilizer. With the bent housing, the stabilizer is not required but the hold tendency of the assembly in the rotary mode is improved.

The steerable system operates in two modes; sliding and rotary drilling. In the slide mode, the motor acts like a typical motor run. The motor is oriented in the desired direction (tool face), and drilling progresses without drill pipe rotation. The change in inclination and or direction is derived from the bit tilt from the bent housing and the side force created from the stabilizer or the wall contact with the motor.

In the rotary drilling mode, the assembly is rotated per normal but at lower values (30 to 50 RPM) and the side force is cancelled by this rotary action. In some formations the assembly will change inclination/direction even in the rotary mode. Because of the bit offset or the side force associated with a steerable system, the assembly will drill an overgauge hole in the rotary mode.

Advances in downhole motor reliability have made the steerable system economical in many applications. Typically, the mean time between failures is in excess of 2000 hours for the motor and excess of 800 hours for the measurement while drilling equipment thereby exceeding the life of a tri-cone bit. Where feasible, the tri-cone bit has been replaced with a PDC or diamond bit. When properly matched to the formation and motor torque output, a PDC bit can last much longer than a tri-cone bit; however, a PDC bit cannot always be used. They are applicable to soft and medium hardness formations with consistent lithology. In areas where formation hardness changes a lot, PDC bits do not perform as well as tri-cone bits. Also the ability or ease of controlling build and turn rates of a PDC vary considerably.

In some cases, the penetration rate of a steerable system will out perform that of a rotary assembly. The majority of the time, it is used in soft formations. As formation hardness increases, rotary assemblies will drill faster than a steerable system unless special high torque performance motors are used. Harder formations are less sensitive to rotary speed, and bit weight is the predominant drilling parameter. In hard formations, the penetration rate for a motor can be half that of a rotary assembly. In soft to medium hard formations, the penetration rate for a downhole motor has been twice that of a rotary assembly.


As the torque and drag in a directional well increases, the rate of penetration for a steerable system while sliding can be considerably less than while rotating. In some cases it will be half the rate seen while rotating. Therefore, it is advantageous to rotate a steerable system as much as possible especially when approaching TD.

The directional plan can be followed much more closely with a steerable system. Since trips are not required, corrections in the slide mode are made much more frequently. The frequent corrections will keep the wellbore closer to the planned path. In the hold section, the directional driller will often rotate for a portion of a connection and slide for the remainder of the connection. He must first get a feel for how much the assembly is walking and building or dropping while in the rotary mode. Once he gets a feel for that then he can determine how much he needs to slide per connection and what the tool face orientation must be.

This does not mean that the dogleg severity is very low. It only means that the changes are small and frequent. Surveys at 20m to 30m intervals will not pick up the actual dogleg severity in the well, whereas with rotary assemblies and motor corrections, the dogleg severity is picked up by the surveys. Frequent motor corrections (short dogleg intervals) will minimize problems associated with keyseats. The doglegs are not long enough for keyseats to form easily.

The steerable system should be designed to generate a dogleg severity 25 percent greater than that required to accomplish the objectives of the directional plan (a more aggressive bent housing setting). Formation tendencies can cause the dogleg severity of a steerable system to change. If it decreases the dogleg severity generated by the system, then a trip may be require to pick up a more aggressive assembly. However if the assembly is designed to be more aggressive, then the assembly will still be able to produce a dogleg severity sufficient to keep the wellbore on course and less slide drilling is required resulting in a higher average ROP. Reducing the dogleg severity of a steerable system is not a problem. Alternately sliding and rotating the assembly will reduce the overall dogleg severity.

The most significant advantage of the steerable system is that a trip does not have to be made in order to make a course correction. When a correction is required, the motor is oriented and drilling continues in the slide mode until the correction is complete. Then drilling in the rotary mode continues until the next correction is required. If a steerable system is not used, a trip would be required to pick up a motor assembly before making the correction. After the correction is made, another trip would be required to pick up the rotary assembly.

Another advantage of the steerable system is that it provides the ability to hit smaller targets at a reasonable cost. Because a trip is not required to make a course correction, the steerable system can hit a smaller target with less cost. It’s not that a small target can not be hit using rotary assemblies and motor corrections; it’s that the costs increase significantly as the target gets smaller.

Steerable systems are typically used in drilling multi-target directional and horizontal wells. Drilling through a cluster of wells is another good application for a steerable system. Drilling out from under a crowded platform may require building, dropping and turning at various rates over a relatively short distance in order to avoid other wellbores. A steerable system is capable of making all the corrections without tripping. In an environment where the daily operating costs are high, the steerable system can result in significant savings.

Just because the industry has the capability to hit smaller targets does not mean that the targets should be unduly restricted. The smaller the target, the more expensive it can be to hit. With a steerable system, the cost differential isn’t as high as it would be using rotary assemblies and making motor corrections.


MUD MOTORS

There are two major types of downhole motors powered by mud flow; 1) the turbine, which is basically a centrifugal or axial pump and 2) the positive displacement mud motor (PDM). The principles of operation are shown in Figure 7.1 and the design of the tool are totally different. Turbines were in wide use a number of years ago and are seeing some increased use lately but the PDM is the main workhorse for directional drilling.

Turbine Motor Positive Displacement Motor

Motor Selection

Four configurations of drilling motors provide the broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications. These configurations include:

1.) High Speed / Low Torque

2.) Medium Speed / Medium Torque

3.) Low Speed / High Torque

4.) Low Speed / High Torque -Gear Reduced

The high speed drilling motor utilizes a 1:2 lobe power section to produce high speeds and low torque outputs. They are popular choices when drilling with a diamond bit, tri-cone bit drilling in soft formations and directional applications where single shot orientations are being used.

The medium speed drilling motor typically utilizes a 4:5 lobe power section to produce medium speeds and medium torque outputs. They are commonly used in most conventional directional and horizontal wells, in diamond bit and coring applications, as well as sidetracking.

The low speed drilling motor typically utilizes a 7:8 lobe power section to produce low speeds and high torque outputs. They are used in directional and horizontal wells, medium to hard formation drilling, and PDC bit drilling applications.

The gear reduced drilling motor combines a patented gear reduction system with a 1:2 lobe high speed power section. This system reduces the output speed of the 1:2 lobe power section by a factor of three, and increases the output torque by a factor of three. The result is a drilling motor with similar


performance outputs as a low speed drilling motor, but with some significant benefits. The 1:2 lobe power section is more efficient at converting hydraulic power to mechanical power than a multi-lobe power section and also maintains more consistent bit speed as weight on bit is applied. This motor can be used in directional and horizontal wells, hard formation drilling, and PDC bit drilling applications.

Some other motor selections are also available including a tandem and modified motor. These variations are described below.

Tandem Drilling Motor - The drilling motor utilizes two linked power sections for increased torque capacity.

Modified Drilling Motor - The bearing section of the drilling motor has been modified to provide different drilling characteristics (ie. change bit to bend distance, etc.).

Motor Components

All drilling motors consist of five major assemblies:

1.) Dump Sub Assembly

2.) Power Section

3.) Drive Assembly

4.) Adjustable Assembly

5.) Sealed or Mud Lubricated Bearing Section.

The gear reduced drilling motor contains an additional section, the gear reducer assembly located within the sealed bearing section. Some other motor manufacturers have bearing sections that are lubricated by the drilling fluid.

Dump Sub Assembly As a result of the power section (described below), the drilling motor will seal off the drill string ID from the annulus. In order to prevent wet trips and pressure problems, a dump sub assembly is utilized. The dump sub assembly is a hydraulically actuated valve located at the top of the drilling motor that allows the drill string to fill when running in hole, and drain when tripping out of hole. When the pumps are engaged, the valve automatically closes and directs all drilling fluid flow through the motor.

In the event that the dump sub assembly is not required, such as in underbalanced drilling using nitrogen gas or air, its effect can be negated by simply replacing the discharge plugs with blank plugs. This allows the motor to be adjusted as necessary, even in the field. Drilling motors 95 mm (3 3/4”) and smaller require the dump sub assembly to be replaced with a special blank sub.

Power Section

The drilling motor power section is an adaptation of the Moineau type positive displacement hydraulic pump in a reversed application. It essentially converts hydraulic power from the drilling fluid into mechanical power to drive the bit.

The power section is comprised of two components; the stator and the rotor. The stator consists of a steel tube that contains a bonded elastomer insert with a lobed, helical pattern bore through the center.


The rotor is a lobed, helical steel rod. When the rotor is installed into the stator, the combination of the helical shapes and lobes form sealed cavities between the two components. When drilling fluid is forced through the power section, the pressure drop across the cavities will cause the rotor to turn inside the stator. This is how the drilling motor is powered.

It is the pattern of the lobes and the length of the helix that dictate what output characteristics will be developed by the power section. By the nature of the design, the stator always has one more lobe than the rotor. The illustrations in Figure 7-2 show a 1:2 lobe cross-section, a 4:5 lobe cross-section and a 7:8 lobe cross-section. Generally, as the lobe ratio is increased, the speed of rotation is decreased.

Cross-sections of the most common power section lobe configurations

The second control on power section output characteristics is length. A stage is defined as a full helical rotation of the lobed stator. Therefore, power sections may be classified in stages. A four-stage power section contains one more full rotation to the stator elastomer, when compared to a three stage. With more stages, the power section is capable of greater overall pressure differential, which in turn provides more torque to the rotor.

As mentioned above, these two design characteristics can be used to control the output characteristics of any size power section. This allows for the modular design of drilling motors making it possible to simply replace power sections when different output characteristics are required.

In addition, the variation of dimensions and materials will allow for specialized drilling conditions. With increased temperatures, or certain drilling fluids, the stator elastomer will expand and form a tighter seal onto the rotor and create more of an interference fit, which may result in stator elastomer damage. Special stator materials or interference fit can be requested for these conditions.

Drive Assembly Due to the design nature of the power section, there is an eccentric rotation of the rotor inside of the stator. To compensate for this eccentric motion and convert it to a purely concentric rotation drilling motors utilize a high strength jointed drive assembly. The drive assembly consists of a drive shaft with a sealed and lubricated drive joint located at each end. The drive joints are designed to withstand the high torque values delivered by the power section while creating minimal stress through the drive


assembly components for extended life and increased reliability. The drive assembly also provides a point in the drive line that will compensate for the bend in the drilling motor required for directional control.

Adjustable Assembly

Most drilling motors today are supplied with a surface adjustable assembly. The adjustable assembly can be set from zero to three degrees in varying increments in the field. This durable design results in wide range of potential build rates used in directional, horizontal and re-entry wells. Also, to minimize the wear to the adjustable components, wear pads are normally located directly above and below the adjustable bend.

Sealed or Mud Lubricated Bearing Section

The bearing section contains the radial and thrust bearings and bushings. They transmit the axial and radial loads from the bit to the drill string while providing a driveline that allows the power section to rotate the bit. The bearing section may utilize sealed, oil filled, and pressure compensated or mud lubricated assemblies. With a sealed assembly the bearings are not subjected to drilling fluid and should provide extended, reliable operation with minimal wear. As no drilling fluid is used to lubricate the drilling motor bearings, all fluid can be directed to the bit for maximized hydraulic efficiency. This provides for improved bottom-hole cleaning, resulting in increased penetration rates and longer bit life. The mud-lubricated designs typically use tungsten carbide-coated sleeves to provide the radial support. Usually 4% to 10% of the drilling fluid is diverted pass this assembly to cool and lubricate the shaft, radial and thrust bearings. The fluid then exits to the annulus directly above the bit/drive sub.

Gear Reducer Assembly

An alternative to the type low speed drilling motor is the gear-reduced design. It utilizes a gear reduction assembly within the sealed bearing section in combination with a 1:2 lobe power section. This patented design reduces the speed of rotation by a factor of three while increasing the torque by the same multiple. The benefit with this design is increased stability in the bit speed for different differential pressures, and improved hydraulic efficiency out of the power section.

Kick Pads Most drilling motors can incorporate wear pads directly above and below the adjustable bend for improved wear resistance. Eccentric kick pads can also be used on most motors ranging from 121 mm (4 3/4’) to 245 mm (9 5/8”) in size. This kick pad is adjustable to match the low side of the motor to increase build rate capabilities. It will also allow lower adjustable settings for similar build rates, thereby reducing radial stresses applied to the bearing assembly, and permit safer rotation of the motor. They can be installed in the field by screwing them onto specially adapted bearing housings.


General motor component layout

Stabilization Bearing housings are also available with two stabilization styles, integral blade and screw-on. The integral blade style is built directly onto the bearing housing and thus cannot be removed in the field. The screw-on style provides the option of installing a threaded stabilizer sleeve onto the drilling motor on the rig floor in a matter of minutes. The drilling motor has a thread on the bottom end that is covered with a thread protector sleeve when not required. Both of these styles are optional to a standard bladed bearing housing.


MOTOR OPERATIONS In order to get the best performance and optimum life of drilling motors, the following standard procedures should be followed during operation. Slight variations may be required with changes in drilling conditions and drilling equipment, but attempts should be made to follow these procedures as closely as possible.

Assembly Procedure & Surface Check Prior to Running in Hole

Most motors are shipped from the shop thoroughly inspected and tested, but some initial checks should be completed prior to running in hole. These surface check procedures should only be used with mud drilling systems. To avoid potential bit, motor, and BOP damage, these preliminary checks should be completed without a bit attached. A thread protector should be installed in the bit box whenever moving the motor, but must be removed before flow testing.

• Only apply rig tongs on the identified areas of the drilling motor. All connections marked “NO TONGS” of the drilling motor are torqued in the service shop. Further make-up on the rig floor is not necessary, and if attempted may cause damage.

• Remove the thread protector from the bit box and inspect the threads for damage.

• Lower the drilling motor until the dump sub ports are below the rotary table, yet still visible. CAUTION: The dump sub valve will remain open until there is enough fluid pressure to close it. Therefore, the drilling motor should be lowered until the ports are below the rotary table. This will prevent the initial flow of drilling fluid from spraying on the rig floor.

• Slowly start the pumps and ensure drilling fluid is flowing out of the dump sub ports. Increase the flow rate until the dump sub ports close, and drilling fluid stops flowing out. Make note of the circulation rate and standpipe pressure. CAUTION: Do not exceed the maximum recommended flow rate for this test.

• Lift the drilling motor until the bit box becomes visible. It should be rotating at a slow, constant speed. Listen to the bearing section of the drilling motor for excessive bearing noise, especially if the tool has been used previously without being serviced.

• Before stopping the pumps, the drilling motor should be lowered below the rotary table. Ensure that drilling fluid flows out of the dump sub ports after shutting down the pumps. It is possible that the dump sub valve remains closed after this test due to a pressure lock. If this occurs, no drilling fluid will flow out of the ports. To remove the pressure lock, bleed off some stand pipe pressure and the valve will open. The surface check should be as short as possible; since it is merely to ensure that the drilling motor is rotating.

• After this surface check, the bit should be attached to the motor using a bit-breaker, while holding the bit box stationary with a rotary tong. Be sure to avoid contacting the end cap directly above the bit box with the tong dies. It is recommended that you never hold the bit box stationary and rotate the drilling motor counter-clockwise, or hold the drilling motor stationary and rotate the bit box clockwise. This could possibly cause the internal drilling motor connections to back off and damage it. Although rotating in the opposite direction will result in drilling fluid to be pushed out the top end, the internal connections will not be at risk of disconnecting.

• If the drilling motor has been used previously, an overall inspection should be completed. Inspect for seal integrity by cleaning the area above the bit box and visually checking for


lubricating oil leakage or seal extrusion. General visual inspection of the entire drilling motor should be carried out to check for missing oil plugs, housing damage, or loose connections.

• Set the adjustable assembly to the desired bend. The instructions for this procedure depend upon the motor manufacturer and should be adhered to. Ensure the rig tongs can generate the required make-up torque the motor.

• If a float sub is used, it should be placed immediately above the drilling motor.

Tripping In Hole Generally, a drill string with a drilling motor can be run into the hole like a standard bottom hole assembly. The drilling motor is rugged, but care should be taken to control travel speed while tripping into the hole. The drill string should be tripped with the blocks unlocked and special care must be taken when passing the B.O.P., casing shoe, liner hanger, bridges and nearing bottom. Tight spots should be traversed by starting the pumps and slowly reaming the drilling motor through them. When reaming, the drill string should be periodically rotated to prevent sidetracking. Great care should be taken during these operations.

When tripping to extreme depths, or when hole temperatures are high, periodic stops are recommended to break circulation. This prevents bit plugging and aids in cooling the drilling motor, preventing high temperature damage.

Fluid should not be circulated through a drilling motor inside casing if a PDC or diamond bit is being used, as this may damage the bit cutters.

If a dump sub assembly is not used and the pipe is not being filled while tripping in, the back pressure on the power section will cause the rotor to turn in reverse. This could cause internal connections of the drilling motor to unscrew. Stop and break circulation before putting drilling motor on-bottom. Failure to do so could plug jets and/or damage the drilling motor.

Drilling

After the assembly has been tripped to the bottom of the hole, drilling motors should be operated in the following manner:

• With the bit 1-2 meters (3-6 feet) off bottom, start the pumps and slowly increase the flow rate to that desired for drilling. Do not exceed the maximum rated flow rate for the drilling motor.

• Make a note of the flow rate and the total pump pressure. Note that the pressure may exceed the calculated off bottom pressure due to some side load effects between the bit and the hole diameter.

• After a short cleaning interval, lower the bit carefully to bottom and slowly increase the weight. Torque can be affected by a dirty, uncirculated hole and the hole should be adequately cleaned prior to orienting the tool. Fill maybe cleaned out of the wellbore by slowly rotating the drilling motor or by staging the drilling motor full circle 30o to 45o at a time. This prevents ledge buildup and side tracking.

• Orient the drill string as desired and slowly apply further weight onto the bit. Pump pressure will rise as the weight on bit is increased. Record the change in system pressure between the off bottom and on bottom values. This will be the differential pressure. Try to drill with steady pump pressure by keeping a steady flow rate and constant weight on bit.


• Adding weight on bit will cause both the differential pressure and torque to increase. Similarly, reducing weight on bit will reduce both the differential pressure and the torque. Therefore, the rig pressure gauge enables the operator to monitor how the drilling motor is performing, as well as a weight on bit indicator.

• Applying excessive weight on bit may cause damage to the on-bottom thrust bearings. Similarly, applying excessive tension while stuck may cause damage to the off-bottom thrust bearings. Refer to the manufacturer specifications for the recommended maximum loads for these conditions.

• Optimum differential pressure can be determined by monitoring motor performance, penetration rate, and drilling requirements. Also, maintaining a constant weight on bit and differential pressure assists in controlling orientation of the drill string.

Reactive Torque

Drilling motors drive the bit with a right-hand (clockwise) rotation. As weight is added to the bit, reactive torque acting on the drilling motor housing is developed. This left-hand (counter-clockwise) torque is transferred to the drill string and may cause the joints above the motor to tighten. Reactions of this type increase with larger weight on bit values and reach a maximum when the motor stalls. This reactive torque also affects the orientation of the motor when it is used in directional drilling applications. Therefore, this reactive torque must be taken into account when orienting the drilling motor from the surface in the desired direction. As a rule-of-thumb 4 ½” drill pipe will turn 10o for every 300m (1,000’).

Critical Rotary Speed

Motor sections are available in a number of configurations. These different designs are identified by the number of lobes on the rotor and cavities in the stator. For example a 4/5 power section has 4 lobes and 5 cavities. With every rotation made by the rotor, there are eccentric motions about the radius of the rotor equal to the number of lobes. So a 4/5 power section would go through 4 eccentric movements for every rotation. In all multi-lobed tools, regardless of size or configuration, the critical tolerance for this eccentric movement is 1000 cycles per minute. Exceeding this critical tolerance sets up three degenerative cycles in the tool:

• The high oscillation factor combined with the inherent friction of the rotor contacting the stator results in excessive heat generation in the stator molding. Oscillations above 1000 cycles per minute may result in temperatures sufficient to cause hysteretic failure of the stator molding (elastomer doesn’t return to original shape).

• Vibration frequencies are introduced by the high oscillation rates that can contribute to mechanical failures in motor components other than the rotor and stator. It is not known if these vibrations are harmonic or random however, it is logical to assume that some degree of resonance would be present in the frequency.

• The centrifugal force of the rotor in an “over-speed” condition combined with the diminished compressive strength of a stator in hysteretic failure, accentuate the eccentric motion (run out) of the rotor. The result is an expontenial increase in the degenerative effects of the condition.


Drilling Motor Stall Stalling usually occurs when the application of excessive weight on bit or hole sloughing stops the bit from rotating and the power section of the drilling motor is not capable of providing enough torque to power through. This is indicated by a sudden sharp increase in pump pressure. This pressure increase is developed because the rotor is no longer able to rotate inside the stator, forming a long seal between the two. If circulation is continued, the drilling fluid forces it’s way through the power section by deflecting the stator rubber. Drilling fluid will still circulate through the motor, but the bit will not turn. Operating in this state will erode and possibly chunk the stator in a very short period of time, resulting in extensive damage. It is very important to avoid this operating condition.

When stalling occurs, corrective action must be taken immediately. Any rotary application should be stopped and built up drill string torque released. Then the weight on bit can be reduced allowing the drill bit to come loose and the drilling motor to turn freely. If the pump pressure is still high, the pumps should then be turned off. Once again, failure to do this will result in the stator eroding until the drilling motor is inoperable.

Other conditions can be occurring downhole that indicate the motor is stalling. On underbalanced wells when the motor is being supplied with too low a combined equivalent flow rate will not drill (see later discussion on two-phase flow tests). Under gauge bits or a badly worn heel row of cutters on the bit can also make the motor stall.

Bit Conditions

The bit speeds developed when drilling with a drilling motor are normally higher than in conventional rotary drilling. This application tends to accelerate bit wear. When drilling with a drilling motor and simultaneously rotating the drill string, it is important to avoid locking up the bit and over running the drilling motor with the rotary table. A locked bit will impart a sudden torque increase in the drilling motor which can be detected by a sudden, sharp increase in standpipe pressure. Small pressure fluctuations can also indicate the onset of bit failure.

Rotating the Drilling Motor

For directional control, we often rotate a drilling motor which has the adjustable assembly set for a deviation angle. It has been found that rotating the drilling motor set at bends greater than 1.8 degrees may fatigue the housings of the drilling motor to a point where a fatigue crack is initiated, and fracture occurs. Additionally, rotation of motors with settings greater than 1.83 degrees place high radial stresses on the bearing section which may initiate premature failure. Most motor manufacturers have a policy that drilling motors set at greater than 1.83 degrees not be rotated. The extent of the damage is very dependent upon the drilling conditions and formations being drilled. Although fractures from fatigue due to rotating over 1.83 degrees are a relatively rare occurrence, a risk is still being taken when it is done. The operator of the drilling motor must be aware of this risk.

It is also recommended that the speed of rotation not exceed 50 RPM. If this value is exceeded, excessive cyclic loads would occur to the drilling motor housings and possibly causing pre-mature fatigue problems.


Tripping Out Prior to tripping out when drilling with conventional mud, it is recommended that the fluid be circulated for at least one “bottoms-up’ time to ensure that the wellbore has been cleaned thoroughly.

The tripping out procedures for a drilling motor is basically the same as those for tripping in. Taking care when pulling the drilling motor through tight spots, liner hangers, casing, casing shoes, and the B.O.P. is necessary to minimize possible damage to both the drilling motor and the wellhead components. Rotating may also be done to assist with the removal of the drill string. The dump sub valve will allow the drill string to be emptied automatically when tripping.

Although the drill string will drain when tripping out, the drilling motor itself may not. Once the drilling motor is at surface, rotating the bit box in a counter-clockwise direction will naturally drain the drilling motor through the top. This is recommended before laying down the motor since aggressive drilling fluids can deteriorate the elastomer stator and seals. When possibly, fresh water should also be flushed through to ensure thorough cleaning of the drilling motor. Also, clean the bit box area with clean water and install a thread protector into the box connection.

Rotating the bit box in a clockwise direction will naturally drain the drilling motor through the bottom, but one of the internal connections could break and unscrew. For this reason, it is not recommended to rotate it in this manner.

Surface Checks After Running in Hole

Before laying down a drilling motor, it should be inspected in the event that it is required again before servicing. Listen for indications of internal damage when draining the drilling motor. Inspect the seal area between the bit box and the bearing section for lubricating oil leakage, and check the entire drilling motor for loose or missing pressure plugs. If there are any concerns with the drilling motor, it should be laid down for servicing.

Drilling Fluids

Most drilling motors are designed to operate effectively with practically all types of drilling fluids. In fact, the stator or power-section of most PDM’s are supplied by the same one or two manufacturers with the same general elastomer type. Successful runs have been achieved with fresh or salt water, oil based fluids, fluids with additives for viscosity control or lost circulation, and with nitrogen gas. However, some consideration should be taken when selecting a drilling fluid, as elastomer components of the drilling motor are susceptible to pre-mature wear when exposed to certain fluids especially under higher temperatures.

Hydrocarbon based drilling fluids can be very harmful to elastomers. A measure of this aggressiveness is called the Aniline Point. The Aniline Point is the temperature at which equal amounts of the hydrocarbon and aniline become miscible. This temperature is an indication of the percent of light ends (aromatics) present in the hydrocarbon. It is recommended that the aniline point of any drilling fluid not be lower than 70 to 94.5o C (158 to 200o F), depending upon stator manufacturer. The lower the aniline point the higher the percentage of elastomer damaging “high-ends” in the hydrocarbon fluid. Also, the operating temperature of the drilling fluid should be lower than the aniline point. Operating outside these parameters tends to excessively swell elastomers and cause premature wear, thus reducing the performance of the motor. In cases where hydrocarbon based fluids are used it is recommended that stators material or designs that account for the elastomer swelling be used (HSN or changed interference of stator/rotor.


Drilling fluids with high chloride content can cause significant damage to internal components (chrome plated rotors). When these components become damaged, the drilling motor’s performance is dramatically reduced.

Lost circulation materials can be used safely with drilling motors but care must be taken to add the material slowly to avoid plugging the system. (Good rule of thumb is no more than 2.5 lbs/barrel). If coarse lost circulation material is required a circulating sub should be installed above the motor assembly to by-pass the motor.

The percentage of solids should be kept to a minimum. Large amounts of abrasive solids in the drilling fluid will dramatically increase the wear on a stator. It is recommended that the sand content be kept below 2% for an acceptable operational life. A solids content greater than 5% will shorten rotor and stator life considerably.

For the above reasons, it is extremely important to flush the drilling motor with fresh water before laying it down, especially when working with the types of drilling fluids described above. Failure to do so will allow the drilling fluid to further seriously deteriorate components to the drilling motor long after it has been operated. The solids can also settle out in the motor and in the worse case lock the motor up.

Temperature Limits

The temperature limits of drilling motors again depend on the effect of different fluids and temperatures on the components made of elastomers. Generally, standard drilling motors are rated for temperatures up to 105o C (219o F). At temperatures above this, the performance characteristics of elastomers are changed, resulting in reduced life expectancy. When exposed to higher temperatures, the elastomers swell, creating more interference than desired, wearing the parts out prematurely. The strength of the elastomers is also affected. When drilling in wells with temperatures greater than 121o C (250o F) it is important to maintain circulation to minimize the temperature the stator liner is subjected to.

To compensate for these elastomer changes, special materials and special sizes of components are used. This results in drilling motors that are specifically assembled for high temperatures. These special order drilling motors may be operated in temperatures up to 150o C (300o F) and higher. The rubber in the stator is specially selected for more clearance at higher temperatures to minimize interference. Therefore, at lower temperatures, the stator elastomer will not seal adequately on the rotor and fluid bypass will occur. Therefore, it is important that the drilling motor be used in the conditions it is designed for in order to operate as required.

Hydraulics

The use of a PDM in the drill string changes the hydraulic calculations and should be considered. Various factors have to be taken into account. These are:

1.) Range of flow rates allowable: Each size and type of PDM is designed to take a certain range of volumes of fluid.

2.) No-load Pressure Loss: When mud is pumped through a mud motor which is turning freely off-bottom (i.e. doing no work) a certain pressure loss is needed to overcome the rotor/stator friction forces and cause the motor to turn. This pressure loss and motor RPM


are proportional to flow rate. Their values are known for each size and type of PDM. The no-load pressure loss is usually no greater than 100 psi.

3.) Pressure Drop across the Motor: As the bit touches bottom and effective WOB is applied, pump pressure increases. This increase in pressure is normally called the motor differential pressure. Motor torque increases in direct proportion to the increase in differential pressure. This differential pressure is required to pump a given volume of mud through the motor to perform useful work. For a multi-lobe motor, it can be 500 psi or even more.

4.) Stall-out Pressure: There is a maximum recommended value of motor differential pressure. At this point, the optimum torque is produced by the motor. If the effective WOB is increased beyond this point, pump pressure increases further. The pressure across the motor increases to a point where the lining of the stator is deformed. The rotor/stator seal is broken and the mud flows straight through without turning the bit (blow-by or slippage). The pump pressure reading jumps sharply and does not vary as additional WOB is applied. This is known as stall-out condition.

Studies have shown that the power output curve is a parabola and not a smooth upward curve, as originally thought. If the PDM is operated at 50%-60% of the maximum allowable motor differential pressure, the same performance should be achieved as when operating at 90% of differential. The former situation is much better however, there is a much larger ‘cushion’ available before stall-out. This should result in significantly longer motor life.

The greater the wear on the motor bearings, the easier it is to stall-out the motor. It is useful to deliberately stall out the PDM briefly on reaching bottom. It tells the directional driller what the stall-out pressure is. He may want to operate the motor at about 50% of stall-out differential pressure. In any case, he must stay within the PDM design specifications.

It is obvious that, if the pump pressure while drilling normally with a mud motor is close to the rig’s maximum, stalling of the PDM may lead to tripping of the ‘pop-off valve’. This should be taken into account in designing the hydraulics program.

Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be blanked off or jetted with a jet nozzle. When the standard performance range for the motor matches the drilling requirements, a blanking plug is normally fitted.

The selection of the rotor nozzle is critical. Excessive bypass will lead to a substantial drop in motor performance and, consequently, drilling efficiency. If a rotor nozzle is used at lower flow rates, the power of the motor will be greatly reduced.

From the above, it is clear that careful planning of the PDM hydraulics program is required.


Example of a typical motor performance chart for a 1:2 lobe motor.


Example of a typical motor performance chart for a 4:5 lobe motor.

PLANNING TO DRILL A DIRECTIONAL WELL In order to plan a directional well that can be drilled safely and be cost effective, a great deal of information is needed by the directional company. By reviewing the information and requirements the best plan can be selected that will meet everyone’s needs and produce a usable wellbore. The planning of a directional well can involve multiple disciplines and their needs must be successfully combined into the wellpath proposal. Obviously not all wells require input from each division but the more complex the well is the more important a synergy is developed within the departments and with the directional drilling company.

Geology Interaction with the geologists is of prime importance to understand any limitations in the particular zone of interest. Although all information collected is important to the drilling operation communication at this stage can be the make or break point of the well.


• Lithology being drilled through (sand, shales, sloughing tendencies, coals, salt, medium hard formations with hard or soft stringers, marker zones)

• Location of water or gas top

• Level of geological control

• Type of target the geologist is expecting (channel sand, pinnacle reef, a seismic irregularity, exploration or infill drill)

• Geological structures that will be drilled through or into (dip, faults, unconsolidated shales)

• Regulatory issues (oil or gas target boundaries, wellbore clearance from existing wells, location of final total depth)

• Type of Well (Oil or Gas)

• Future sidetrack or re-entry potentials

Completion and Production

This group is often missed and may result in a costly error if their needs are not considered in the planning phase. They usually share some of the planning responsibility with the geology department.

• Location of surface facilities or ability to move existing when infill drilling on an existing pad

• Type of completion required (frac, pump rods)

• May specify maximum inclination and dogleg limits based upon log and production requirements

• Enhanced recovery completion requirements

• Wellbore positioning requirements for future drainage/production plans

• Downhole temperature and pressure

Drilling

This group usually has control over the main operation and tries to pull all parties together. The overall cost estimation and economic feasibility may also rest in their hands. Consequently, the directional representative usually spends most of their time consulting with the members in this group. Even though the other groups have just as important information, the drilling group typically controls how the well is drilled and will make the final decision on any operational issues that occur.

• Selection of surface location and well center(s) layout

• Casing size and depths

• Hole size

• Required drilling fluid

• Drilling rig equipment and capability

• Length of time directional services are utilized

• Influences the type of survey equipment and wellpath

• Previous area drilling knowledge and identifies particular problematic areas


Planning

Once the information has been collected from the various departments, a directional plan is prepared that meets all the requirements (if possible). A good well planner also tries to incorporate operational issues that contribute to the success of the well and can have a dramatic impact on the length of time required for directional equipment. This can be very important on pad layouts for multiple directional wells and can save the operator considerable expenses if properly utilized.

Anyone can plan a well to be drilled from point ‘A’ to ‘B’ but it requires operational knowledge to plan a profile that can physically be drilled without unnecessary trips to change assemblies given the hole size and area. The following are few of the general rules-of-thumb when well paths are being prepared:

• Build rates kept at 2 to 3 o/30m for pumping oil wells. In fact most oil wells are planned at this rate unless the horizontal displacement requires higher build rates to reach the target. Typically most operators prefer to keep the actual doglegs less than 8 or 9 o/30m, therefore the plan should be less than 7 o/30m to allow for operational variances.

• The hold portion for build and hold profiles should be at least 50m (150’) to allow for operational adjustments should they have trouble achieving build rates.

• The drop rate for S-curve wells is preferably planned at 1.5 o/30m but can go as high as 2.5. A key-seat or differential sticking risk could occur with aggressive drop rates in softer formations. Also a minimum 30m (100’) tangent section should be planned in the middle of an S-curve profile to allow for drilling problems or changes in target depths.

• Keep the KOP as low as possible to reduce directional costs and on pumping oil wells to reduce potential rod/casing wear. KOP must be selected in a competent formation.

• Pick a KOP that has a competent enough formation that will allow the planned build rate to be achieved.

• On long or extended reach well profiles keep the KOP low to provide a larger vertical portion for applying weight on bit but also keep the build rate low (less than 4 o/30m).

• When planning a well that will use single shot survey equipment make sure at least two thirds of the build section is completed before drilling into any problem zone. If it cannot be accomplished use higher build rates or place KOP as low as possible in the problem zone an insure a sufficient hold section after terminal angle is reached (100m).

• In build sections of horizontal wells, plan a soft landing section (lower build rate) for casing point if the required motor setting is greater than 1.8o or severe geological uncertainty exists (target TVD changes greater than 2m).

• Plan for a terminal angle of a minimum 15o since it is easier to hold inclination and direction.

• Avoid high inclinations through severely faulted, dipping or sloughing formations.

• On horizontal wells be sure to clearly identify any gas or water contact points and keep sufficient clearance below or above to prevent breakthrough.

• Turn rates in the lateral sections of horizontal wells should be kept at less than 8 o/30m, especially if the proposed lateral length is long.


• Know what build rates are achievable for the motors being used in a specific hole size. The following rates are for most standard motors.

311mm hole - up to 10+ o/30m (motor with kick pad) 222mm hole – up to 14 o/30m 159mm hole – up to 25 o/30m 121mm hole – up to 35 o/30m

• Keep subsequent sidetracks on horizontal legs at least 20m (60’) apart.

• Where possible don’t start a sidetrack until at least 20m out from casing point.

• Be sure to identify what profiles will require trips to set motor down before any rotation should occur.

• Assume a dogleg of approximately 14 o/30m will occur coming off a whipstock.

• Identify all wells within 30m of proposed well path and conduct anti-collision check. On long horizontal sections this should be extended to 100m away.

• Where possible design a wellpath that will minimize the percentage of hole drilled in the oriented mode. Typically the ROP of these sections are one half or less of the rotary ROP.

Torque And Drag One of the most significant problems associated with extended reach or horizontal drilling is torque and drag which is caused by the friction between the drill string and the hole. The magnitude of the torque and drag is determined by the magnitude with which the pipe contacts the hole wall and the friction coefficient between the wall and pipe. Figure 8-1 shows the forces associated with an object on an incline. The weight component along the axis of the incline (w SinΦ) would be the force required to move the object in a frictionless environment.

Forces on an inclined plane


Unfortunately, friction is always present and will contribute to the force required to move the object. The friction force is equal to the normal force times the friction coefficient. Therefore, the force required to pull the pipe from the hole is:

T= -W SinΦ + µ WCosΦ Where: T = Axial Tension

W = Buoyed Weight of Pipe µ = Friction coefficient Φ = Angle of incline

The force required to push the pipe from the hole is:

T= -W SinΦ - µ WCosΦ

The friction coefficient depends upon the type of drilling fluid in the wellbore and the roughness of the wellbore walls. Cased hole should have a lower friction coefficient than open hole. Untreated water based muds will have a higher friction coefficient than oil based muds. Friction coefficients have been reported to range from 0.1 to 0.3 for oil based muds and 0.2 to 0.4 for water based muds. When hole curvature is considered, an additional force is added to the normal force. Pipe placed in a curved wellbore under tension will exert a force proportional to the tension and rate of curvature change.

Buckling of the drill string while tripping into the wellbore causes an additional drag force. The critical buckling load is a function of the inclination, pipe size and radial clearance. Once the compressive forces in the drill string exceed the critical buckling load, an additional normal force is imposed on the drill string increasing the drag force in sections of the wellbore.

The torque in the drill string is determined by the normal force times the friction coefficient and is the force resisting rotation of the drill string. The torque and drag will increase as the tension and dogleg severity increases. In normal directional wells, the drag is the main concern but as depth, inclination, build rate and length of hold section increase the torque can become a major concern. Torque will also limit the tension capability of drill pipe when combined with tensile loads.

There are three main ways to reduce the drag in the well; 1) change friction coefficient by changing mud system, 2) change the directional profile or 3) change the string weight or tension. Since the drag is proportional to the coefficient of friction, finding a way to reduce this value by half will halve the drag.

Changing the directional profile can have significant benefits but if you’ve already drilled a good portion of the profile, wiper/reamer trips to smooth out any ledges or doglegs in the build section can have significant benefit.

Replacing drill collars with hevi-weight or regular drill pipe can have a significant effect on reducing the tension and normal forces thus drag.

There are excellent torque and drag models in the market that very accurately predict values for a chosen wellpath. It must be remembered this is just a model and one of its better design uses is for comparison of different profiles with all other factors the same. Another very helpful place to utilize this tool, is while drilling horizontal wells. Large changes between predicted and actual drag values can indicate the hole is not cleaning. These models are also used to effectively design the drill string from the bottom of the well to surface.


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Optional Topics Optional Topics


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Measurement While Drilling (MWD)Measurement While Drilling (MWD)

•• Telemetry systems:Telemetry systems:•• Mud pulseMud pulse

•• Positive pulsePositive pulse•• Negative pulseNegative pulse•• Standing wave Standing wave pulserspulsers

•• ElectromagneticElectromagnetic

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Positive and Negative Pulse ValvesPositive and Negative Pulse Valves

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Hydraulic ConsiderationsHydraulic Considerations

•• Keep the pump rate as high as possible for the Keep the pump rate as high as possible for the required flow rates required flow rates

•• Mud pump pressure pulses at increased frequency Mud pump pressure pulses at increased frequency are filtered out by MWD surface gearare filtered out by MWD surface gear

•• Make sure the pump liners are in good conditionMake sure the pump liners are in good condition•• Keep the pulsation dampeners fully chargedKeep the pulsation dampeners fully charged•• Maintain as constant weight on bit as possible, Maintain as constant weight on bit as possible,

particularly when drilling with mud motorsparticularly when drilling with mud motors•• Mud additives should be mixed as uniformly as Mud additives should be mixed as uniformly as

possiblepossible•• Avoid duplex mud pumps if possibleAvoid duplex mud pumps if possible

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Electromagnetic MWDElectromagnetic MWD

•• The electromagnetic wave travels (The electromagnetic wave travels (radiallyradially) through the ) through the formation to surface, guided along the electrically formation to surface, guided along the electrically conductive drill string conductive drill string

•• The electromagnetic lowThe electromagnetic low--voltage signal is then detected, voltage signal is then detected, amplified and decoded at surfaceamplified and decoded at surface

•• The low frequency of the electromagnetic wave is chosen to The low frequency of the electromagnetic wave is chosen to optimize the data transmission rate while minimizing signal optimize the data transmission rate while minimizing signal attenuation and to give the longest possible transmission attenuation and to give the longest possible transmission rangerange

•• Dry air or gas drilling provides results that are similar to a Dry air or gas drilling provides results that are similar to a non conductive mudnon conductive mud

•• Nitrogen, air, or methane are excellent insulators therefore Nitrogen, air, or methane are excellent insulators therefore adding a mist or foam to these gases will improve adding a mist or foam to these gases will improve transmission efficiencytransmission efficiency

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Directional Sensor PackageDirectional Sensor Package

•• MWD tool directional sensor packageMWD tool directional sensor package•• triaxialtriaxial inclinometers inclinometers •• triaxialtriaxial magnetometersmagnetometers

•• Measure hole inclination and hole directionMeasure hole inclination and hole direction•• DriftDrift•• AzimuthAzimuth

•• The The triaxialtriaxial inclinometer measures the 3 inclinometer measures the 3 orthogonal axes components of the earth gravity orthogonal axes components of the earth gravity vector vector ‘‘GG’’

•• The The triaxialtriaxial magnetometer measures the three magnetometer measures the three orthogonal axes components of the earth magnetic orthogonal axes components of the earth magnetic field vector field vector ‘‘HH’’

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Tool FaceTool Face

•• Tool face is an angular measurement of the orientation of Tool face is an angular measurement of the orientation of the BHA versus the top of the hole or magnetic north the BHA versus the top of the hole or magnetic north

•• Reference for tool face is usually the Reference for tool face is usually the ““Scribe markScribe mark”” on the on the nonnon--magnetic drill collarmagnetic drill collar

•• Computation for tool face angles are made from Computation for tool face angles are made from magnetometersmagnetometers

•• Accuracy requirementAccuracy requirement•• Tool face (typically +/Tool face (typically +/-- 1 to 2 degrees)1 to 2 degrees)•• Azimuth (typically +1Azimuth (typically +1-- 0.5 degrees)0.5 degrees)



OPTIONAL TOPICS Measurement While Drilling (MWD)

Most commercial MWD Systems use mud pulse or electromagnetic telemetry to transmit survey data during tool operation. In Mud Pulse the mud pressure in the drill string is modulated to carry information in digital form. Pressure pulses are converted to electric voltages by a transducer installed in the pump discharge circuit (standpipe). Then this information is decoded by the surface equipment. Tool measurements (toolface, inclination, azimuth etc.) are digitized downhole and then the measured values are transmitted to the surface as a series of zeroes and ones. The surface pulse decoders recognize these as representations of tool measurements. Many variations on the signal decoding exist and manufacturer should be contacted to determine their method, although this can be proprietary information. The electromagnetic system is more complicated and will be discussed later but it essentially it measures the voltage potential difference at surface, that is generated by the electromagnetic waves sent from the tool through the formation to surface, into zeros and ones as well.

With mud pulse telemetry there are generally three main systems in common use today. The positive pulse telemetry uses a flow restrictor which when activated increases the stand pipe pressure. Negative pulse tools have a diverter valve that vents a small amount of mudflow to the annulus when energized. This decreases standpipe pressure momentarily. The third method is by standing (or continuous) wave pulsers that use baffled plates, which temporarily interrupt mud flow creating a pressure wave in the standpipe. Changes in relative rotation speed of the plates changes the wave phasing. These phase changes are identified aat surface and decoded.

Positive pulse telemetry creates pressure pulses with a poppet type flow restrictor or a rotatlng valve. Unlike the negative system, flow is never interrupted. The system is much more tolerant of LCM and mud solids than either of the others, making its downhole reliability very good. It is also the least affected by pump and mud motor noise. The tool can have its valve gap modified if pulse heights are insufficient, or if too much pressure drop occurs in the tool during valve closure. Because of the large pulse amplitudes, positive pulse is generally thought to be the most reliable for decoding.

Figure 6-2 Schematic of positive and negative pulse valves


When the negative pulse system is activated, a diverter valve channels mud flow to the annulus, decreasing standpipe pressure. The timing of these pulses is decoded into a series of l’s and 0’s, effectively transmitting tool data. Advantages of the system include low power consumption, and ease of decoding. The completeness of the valve opening/closing create very clean waveform - pulses downhole. This tends to reduce effects of pump noise by making the pulser signal easier to decipher. Negative pulse systems must maintain a pressure differential between the drill pipe and the annulus in order to create a pressure drop when the diverter valve is opened. This may limit allowable jet or nozzle selection at the bit. This is the main disadvantage of the negative pulse system.

All of these systems use surface transducers to record standpipe pressure. It is recommended to provide a mounting device to allow the transducer to be vertically mounted above the mud flow (threads down) to avoid mud solids settling out on the transducer element. This condition would create decoding problems by reducing transducer efficiency.

HYDRAULIC CONSIDERATIONS

The drilling fluid system introduces noise during pump operation which can make MWD surface equipment struggle to decode the tool signal from down-hole. MWD performance can be improved by careful attention to the mud system.

• Keep the pump rate as high as possible for the required flow rates. Mud pump pressure pulses at increased pump frequency are filtered out by MWD surface gear. This reduces the effect of pump noise on the MWD signal.

• Make sure the pump liners are in good condition. Damaged liners cause so much noise they may

even have an identifiable signature on the surface pressure record. If the MWD engineer mentions a bad liner signature - at least check it out.

• Keep the pulsation dampeners fully charged. The ideal mud flow would be at constant pressure,

the only changes in system pressure being those of the MWD pulser. Properly charged dampeners go a long way towards this ideal condition.

• Maintain as constant weight on bit as possible, particularly when drilling with mud motors.

Changes in motor torque will themselves cause changes in standpipe pressure. By keeping these to a minimum, reliability of signal decoding will be improved.

• Mud additives should be mixed as uniformly as possible. Changes in viscosity and suspended

solids concentration can attenuate the MWD signal more than usual. Slugged additives can also clog the tools.

• Avoid duplex mud pumps if possible. Their noise is particularly difficult to filter.

The mud column is the mud pulse MWD tool communication line to the surface. Keeping this system clean, uniform and as free as possible of induced noise can materially improve the quality of the MWD job.


ELECTROMAGNETIC MWD

Directional surveying with the EM MWD tool has become a reliable and cost effective means for surveying both directional and horizontal wells. Advances made over the past years have significantly improved tool reliability when drilling in harsh underbalanced air/mist environments, and have also overcome some of the earlier obstacles associated with operational depth. Additionally since the rig pumps do not have to be cycled to receive a survey, the overall survey cycle time can be reduced and can add up to a significant length of time on high ROP wells. The EM MWD is a viable and reliable method to survey underbalanced wells where conventional mud pulse survey tools cannot work.

Geoservices began research into electromagnetic type transmission in 1982 with the first successful field test achieved in 1983. Commercial operations commenced in 1984 when the technology was applied to a pressure and temperature gauge and this was followed in 1987 by an MWD tool.

Electromagnetic telemetry consists of the injection and transmission of a low frequency electromagnetic carrier wave into the ground. The phase of this carrier wave is specially modulated to carry the raw directional and formation evaluation parameters. Electromagnetic transmission in an oil well can be approximated to the way ordinary coaxial cable can act as a wave guide for signal propagation. The casing string and drill string can be considered as the main coaxial cable conductor, while the formations situated at infinity can be considered the shielding or external conductor. Formations close to the wellbore, between the two conductors, can be considered as the insulation.

The electromagnetic wave travels (radially) through the formation to surface, guided along the electrically conductive drill string. The electromagnetic low-voltage signal is then detected, amplified and decoded at surface. The low frequency of the electromagnetic wave is chosen to optimize the data transmission rate while minimizing signal attenuation and to give the longest possible transmission range. Dry air or gas drilling provides results that are similar to a non conductive mud. Nitrogen, air, or methane are excellent insulators therefore adding a mist or foam to these gases will improve transmission efficiency.

One important consideration, when using the EM MWD, is the operational depth. The average depth of operations today is 2315 m (7600 feet) TVD. The standard tool has been successfully run to 3750 m (12,300 feet) TVD, utilizing a single point of transmission. An extended cable and the latest extended range EM MWD tools have extended this operational depth limit.

Since the dependence on drilling fluid properties is minimal all hydraulic concerns or pump issues can be ignored with EM systems. They also have no moving parts which increases their reliability over mud pulse systems.


DIRECTIONAL SENSOR PACKAGE

The directional sensor package of any MWD tool consists of a set of triaxial inclinometers and triaxial magnetometers to measure respectively hole inclination (drift) and hole direction (azimuth). The triaxial inclinometer measures the 3 orthogonal axes components of the earth gravity vector ‘G’. The triaxial magnetometer measures the three orthogonal axes components of the earth magnetic field vector ‘H’. The reference axes for measurements are usually as follows but each vendor’s tools can have different reference convention.

“Z axis’ along the tool axis and positive toward surface.

“Y axis’ in a plane perpendicular to the tool axis and used as reference for angular tool face measurements. Usually passing through the scribe mark of the collar (reference for angular tool face).

“X axis” orthogonal to both Y and X axis.

Both set of orthogonal axes for inclinometers and magnetometers are aligned between each others at manufacturing and assembling. Nevertheless, these mechanical alignments are not 100% accurate and a calibration (in town) of the sensor package must be performed by the MWD vendor. All sensors are subject to drift, both in temperature and due to possible internal magnetic interference. All drill collar materials must be non-magnetic to avoid drill string magnetism interference with magnetometer measurements. The calibration process is best achieved in a controlled magnetic environment and using “roll test procedures” which output correction coefficients which are entered into the software for computation of inclination, azimuth and tool face. Incorrect entry of these coefficients have caused large errors in surveying and could have catastrophic consequences. The same applies for local magnetic declination entering to the surface system.

TOOL FACE

Tool face (TF) is an angular measurement of the orientation of the BHA versus the top of the hole (gravity tool face) or magnetic north (magnetic tool face). Reference for tool face is usually the “Scribe mark” on the non-magnetic drill collar. Computation for tool face angles are made from magnetometers. Accuracy requirement for tool face (typically +/- 1 to 2 degrees is not at all the same as the one for Azimuth (typically +1- 0.5 degrees).

None of the directional sensors in common use have any moving parts other than the pulser system and they are all very reliable. Several vendors have retrievable systems which can be replaced without pulling the drill pipe by using slickline.

All MWD sensors must be calibrated in special facilities free of magnetic interference. Correction coefficients are entered by software in surface processing.


COMPASS & GRID CORRECTIONS

Magnetic survey tools do not reference to geographic north but to the earth’s north magnetic pole. Since geographic and magnetic north differ an error is introduced in the survey called magnetic declination. However these values are well known at most places on earth and are easily added to survey calculations.

The grid correction is a survey error caused by differences in map orientation. Most maps are drafted to have true north be vertical. Because the maps are on rectangular coordinates and the earth is spherical, errors occur at various surface locations. These errors are not added to the raw data display on MWD or any other type of survey, but are used in map plotting of the survey.

Finally, MWD tools have an internal correction caused by misalignment of the sensor with the drill collar during assembly. It only affects toolface readings and is added in by the MWD engineer during display set up. While the correction does not affect the drillers operation, be aware that it exists and is a possible source of survey error if entered incorrectly.

POWER SUPPLIES

Tool power is supplied by battery, a downhole alternator or both. Batteries allow tool operation without mud flow. However their energy is limited. This means that the operating time is limited, and the sensor power output is limited. While not normally a problem on directional - only services, with the addition of formation evaluation sensors, the problem becomes more obvious. In addition, batteries have limitations in temperature. Alternators solve the energy limit problem but introduce some of their own. Mud pumps must be above a ‘drop-out” minimum rate for them to work, the turbines necessary to drive them can clog, and they limit the flow rate range in which an individual tool can operate.

Alternator tools must be tailored for the pumping system in use on the rig. Turbine stages are configured for the expected mud flow rates. Expected flow rates are important information to set up the job with alternator tools. The drilling engineer should be sure the MWD vendor has this information well before the job is to begin. The alternator tools have an internal over-voltage protection device which stops the tools should the alternator output exceed its limit.

TRANSMISSION TRIGGER

All MWD tools have a signal mechanism to tell the tool to begin data transmission. In this way the surface equipment will be synchronized with the downhole tool’s data pulses allowing decoding.


SURFACE EQUIPMENT

The surface equipment performs the pressure pulse decoding and survey computations. All vendors use an operator console which is electrically connected to the transducer and rig power, and a remote driller’s or rig floor display. The operator’s console has digital readouts for azimuth, inclination and toolface.

The driller’s dial, or rig floor display, has indicators for azimuth and inclination. They also have a display for toolface orientation.

DATA TRANSMISSION FORMATS

MWD tool data are sent to the surface as a series of 0’s and 1’s. The pulse tools are programmed to begin a data sequence with a distinct marker recognizable by the surface decoder. EM MWD tools have a data on demand format. Data are then transmitted in order, with a certain number of 0’s and 1’s representing a ‘word” or frame of information. Transmission formats are programmable at the surface to send data in different styles. For example, toolface becomes very important while slide drilling with a mud motor. Since an entire sequence may take 3 to 5 minutes to transmit, it would be wise to use a format that sends several toolfaces per sequence, particularly during rapid drilling. Conversely, for pore pressure detection, high rates of gamma ray and resistivity are needed. The tool programming needs to be planned according to the objective of the bit run.

Tools often detect rotation by measuring the x and y (normal to tool axis) magnetic fields. If change exceeds 240 degrees over a 10 second period, the tool switches to rotating mode. Rotating mode data will be sent uphole if the tool is programmed to do so.

Synchronization of data bits is important! If the surface equipment loses communication with the downhole tool for even a short time, whole timing sequences of data will be lost, as the surface equipment cannot re-establish which bits represent which downhole data. A program has been written into the tool logic to recognize these events and produce warning error codes.

Sometimes the existing rig hydraulics and necessary drilling program makes detection at higher data rates difficult. Several of the MWD tools can be reprogrammed to transmit at lower speeds. While this will increase the time between surface readings, it certainly is better than no surface readout at all!

MWD INFORMATION

In addition to the directional information today’s MWD equipment also provides other information depending upon the tool type and sophistication. New generation logging equipment is being developed as we speak to reduce or eliminate the need for open hole logging. Although the cost of this service can may be double the directional package the ability to get information quicker reducing the time the hole is unsupported with casing can be invaluable. Unfortunately with this extra cost also comes the increased “lost-in-hole” charges should the tools become stuck down hole.


GAMMA RAY

All MWD tools are capable of providing this service and this tool is frequently used while drilling horizontal wells. The term commonly referred to is “geosteering”. The probe measures natural gamma radiation and has a depth of investigation between 8 to 15 inches depending upon your trust in the technology.

Recently two variations in this tool have been made available to the industry. One type is called “focussed” gamma ray and the other is called “dynamic oriented” gamma ray and both are used to help reduce geological uncertainty. The focussed tool uses a shielded gamma probe with a known orientation to the high side of the motor. If the vendor is smart, the shield is oriented directly to high side of the motor. The data can only be interpreted into high side or low side readings if the tool is not rotating. By positioning the motor high side, a gamma reading of the high side of the hole can be obtained. The tool is generally oriented and then dragged backwards to provide a section view of the high side gamma readings. Unfortunately the drill string typically turns while being dragged backwards so true high side readings may not be obtained. Using this information the geologist can compare the gamma readings to other vertical logs and determine if he is still in the sand.

The “dynamic oriented” gamma ray tool has an accelerometer tied into the shield orientation so every time a gamma count is taken the tool face is also recorded to determine what portion of the hole the reading came from. This data is then stored into separate banks of high side and low side data that is sent to surface so the changes in gamma counts on the high side and low side of the hole are known while rotating. Static checks can be made similar to the focussed gamma ray tool. It is important to remember that if you are slide drilling this data is only being collected from the high side of the motor and not necessarily from the high side of the wellbore. The oriented gamma ray tool had excellent success in horizontal wells and reduced the number of sidetracks required since they were able to stay in “the zone” better. One project recorded an average of 2 sidetracks per lateral without the tool and one sidetrack per 50 wells with the tool.


DOWNHOLE PRESSURE

Several companies have developed pressure gauges that read annular and drill pipe pressure. This is a very important tool for underbalanced drilling and enables appropriate decisions to made while drilling (see Planning and Underbalanced Horizontal Well).

TEMPERATURE SURVEYS

Temperature surveys are also taken from the inside of the drill string to monitor downhole circulating temperatures. This is important to protect the MWD tools that have lower temperature limitations. The main risk with high temperatures besides damaging the probes is a dangerous battery explosion potential when the tools are brought back to surface.

OTHER SENSORS

Currently a limited number of logging while drilling tools (resistivity, density, neutron porosity and acoustic porosity) are readily available. Also vibration, bending moment, torque, bit RPM and weight on bit sensors are available on some products. Limited quantity and sizes are currently available for these sensors and many are sensitive to the dogleg severity they are either slide or rotated through. In this decade look for some remarkable changes in the available sensors of MWD and LWD equipment.

SPECFIC FEATURES OF THE COMPUTALOG MWD SYSTEM

The Computalog MWD system consists of s Secondary Acquisition Module (SAM) which controls downhole data transmission, a Computalog Interface Display (CID), a Rig Floor Display (RFD) for remote display of data, and a pulser which generates the signal. A personal computer is used by the operator for configuration, displaying and logging of data.

The standard system provides drill string orientation and temperature information as measured downhole by the SAM. The SAM is initially programmed through the CID at surface to operate in a user specified mode downhole. This mode determines how and in what order the data will be acquired from its own sensors and from other sub-assemblies (gamma ray).

The SAM is cued by a mud flow sensor to begin a transmission sequence; this consists of a synchronization pulse followed by frames of data. The typical frame pattern consists of a long frame containing survey data (typically 120 sec) followed by repeated short update frames (12 sec) of one or more critical data items. All data is transmitted using a patented encryption algorithm which ensures data integrity. The data transmission will shut down when the mud flow stops, or earlier, depending on the mode of operation. Typical modes include survey, steering, raw, calculated etc.


On surface, pressure samples are digitally filtered and correlated to extract the average pressure, the position of the synchronizing pulses and the position of the data pulses. Using a combinatory algorithm, the pulse positions are decoded to yield the values in the exact format and resolution in which they were transmitted.

MWD SURFACE SYSTEM The MWD surface system consists of an interface display for data reception, a rig floor display for remote display of data, a PC which logs the data and a printer. The mud signal is digitally filtered within the interface display and five integrity checks are completed on all data. These checks enable the system to recognize pulses of 9 psi amplitude in a system operating at 4300 psi. these filters are programmable for various applications.

The data can be plotted on screen or on the plotter on an ongoing basis during MWD transmission. The software also evaluates the data transmission to aid the operator for troubleshooting.

Rig sensors are easily installed and connect to one cable on the rig floor. This cable transmits sensor information from the hazardous location to the interface display in the operations wellsite shack. Additional readouts can be connected to provide data to other locations around the rig.

MWD DOWNHOLE COMPONENTS The downhole components are housed in a non-magnetic drill collar. The MWD probe is bolted to the pulser sub (in the case of the negative pulse system) and screwed into the top of the MWD NMDC or bottom landed into a sleeve (positive pulse system). The gamma sensor for the positive pulse system is at the top of the MWD NMDC whereas the on the negative pulse it is at the bottom.


SENSORS The secondary acquisition module is a programmable microprocessor-based subsystem. It acts as a master module downhole, sampling seven sensors, collecting and transmitting data from other modules within the downhole assembly. Pulse format is generated and transmitted to the pulser for the data transfer to surface. Data is collected from:

• Three axis magnetometers and accelerometers

• Calibrated temperature correction for sensors

• Mud flow determination by sensor or switch

• Generation of error bits for high temperature, magnetic anomaly and accelerometer failure.

The gamma ray sensor is a digital acquisition system utilizing a scintillation detector. It is field programmable for sample time and rates (typically every 24 seconds) and stored in non-volatile memory. As previously discussed a focused or dynamic oriented gamma ray options area available.

PROGRAMMABILITY The operator can program the tool (on surface) for the parameters needed for a specific well. Some programmable features include:

1. Data rate

2. Order in which data is sent to surface

3. Length of time in which sensors are sampled for acquiring data.

4. Angle at which tool changes from magnetic updates to gravitational updates

5. Type of data sent to surface (raw or calculated)

6. Threshold at which the magnetic anomaly or vibration flag is set

7. Which integrity checks are sent to surface after transmission of data

8. Resolution of rapid tool-face updates (normally 2.0 degree every 12 seconds)

9. Threshold for rotary mode. Tool-faces are not sent during rotary mode to conserve power consumption


TRANSMIT TIMES FOR VARIOUS MWD CONFIGURATIONS

Directional – raw data 232 sec

Pressure up delay 45 sec

Static survey Temp, angle, azimuth, TF 139 sec

TF

upda

te

TF

upda

te

TF

upda

te

TF

upda

te

Directional – calc data 153 sec


Calculated survey Angle, azimuth 48 sec TF

upd

ate

12 s

ec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

Directional and gamma – raw data 232 sec


Static survey Temp, angle, azimuth, TF 139 sec

TF update gamma ray reading 24 sec


Directional and gamma – calc data 141 sec


Calculated survey Angle, azimuth 48 sec



During the static survey continuous temperature, drift angle, azimuth and tool face updates are provided by the tool.



Documents

Computalog - Drilling Service Fundamentals