Table Of Contents VERSION 1.00.............................................................................................................................................. 1

TABLE OF CONTENTS.............................................................................................................................. I

PORE PRESSURE ENGINEERING ........................................ ERROR! BOOKMARK NOT DEFINED. INTRODUCTION............................................................................................................................................ 1

What Is Overpressure And Why Study It? .............................................................................................. 1 Responsibilities....................................................................................................................................... 1

WELLBORE PRESSURE CONCEPTS ............................................................................................................... 3 Hydrostatic Pressure .............................................................................................................................. 3 Overburden Pressure.............................................................................................................................. 3

Obtaining Bulk Densities from E-Logs ........................................................................................................... 4 Obtaining Bulk Densities From Cuttings Bulk Density................................................................................... 6

Limitations.................................................................................................................................................. 6 Obtaining Bulk Densities from Cuttings Density Column .............................................................................. 6

Limitations.................................................................................................................................................. 6 Obtaining Bulk Densities from Drilling Models ............................................................................................. 6 Calculating OBP.............................................................................................................................................. 6

Formation Pressures .............................................................................................................................. 6 Normal Hydrostatic Pressure ............................................................................................................................... 7 Subnormal Pressures............................................................................................................................................ 8 Overpressure........................................................................................................................................................ 8

Artesian Well .................................................................................................................................................. 8 Hydrocarbon Column...................................................................................................................................... 8

Pressure Representation......................................................................................................................... 8 Pressure/Depth Representations........................................................................................................................... 8

Equilibrium Density, Equivalent Density........................................................................................................ 8 Pressure Gradients........................................................................................................................................... 9 Hydrodynamic Levels ..................................................................................................................................... 9

Definitions .................................................................................................................................................. 9 Flow .......................................................................................................................................................... 10

Stress concepts...................................................................................................................................... 10 CAUSES OF ABNORMAL SUBSURFACE PRESSURE ...................................................................................... 12

Introduction .......................................................................................................................................... 12 Undercompaction ................................................................................................................................. 13

Conclusion......................................................................................................................................................... 14 Diagenesis ............................................................................................................................................ 14

Clay Diagenesis ................................................................................................................................................. 14 Clay Minerals ................................................................................................................................................ 15 Clay Chemistry and Structure ....................................................................................................................... 15 Diagenetic Reactions (Dewatering)............................................................................................................... 15

Theory and Experimental Observations .................................................................................................... 15 Models of Montmorillonite Dehydration .................................................................................................. 16

Consequences of Clay Diagenesis................................................................................................................. 17 Shale Water Salinity ................................................................................................................................. 17

Summary ....................................................................................................................................................... 17 Carbonate Compaction ...................................................................................................................................... 17 Dolomitisation ................................................................................................................................................... 17

Effects and Relevance ................................................................................................................................... 18 Gypsum/Anhydrite Relationships...................................................................................................................... 18 Evaporite Deposit Seals ..................................................................................................................................... 19 Solution Processes ............................................................................................................................................. 19 Organic Matter Transformation ......................................................................................................................... 19

Thermal Processes................................................................................................................................ 20 Aquathermal Pressuring..................................................................................................................................... 20

Objections ..................................................................................................................................................... 20

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Viscosity ................................................................................................................................................... 39 Water-loss (Filtration Rate) ...................................................................................................................... 39 Suspended Solids ...................................................................................................................................... 40

Bit Type And Wear ....................................................................................................................................... 40 Personnel And Equipment............................................................................................................................. 40 Conclusion..................................................................................................................................................... 40

D Exponent ........................................................................................................................................................ 40 Corrected d exponent..................................................................................................................................... 41 Factors That Influence The Dc Exponent ...................................................................................................... 41

Discussion................................................................................................................................................. 42 Mechanical Parameters included in the d exponent formula ................................................................ 42

Turbine Motors ................................................................................................................................ 42 Hole Section Change........................................................................................................................ 42

Other Mechanical Parameters............................................................................................................... 42 Bit Type / Drilling Action ................................................................................................................ 42 Bit Wear ........................................................................................................................................... 43 Bottom Hole Assembly Configuration............................................................................................. 44 Hole Angle ....................................................................................................................................... 44 Junk In The Hole.............................................................................................................................. 45

Formation Parameters........................................................................................................................... 45 Unconformities................................................................................................................................. 45 Lithological Variations..................................................................................................................... 45

Drilling Fluid Parameters ..................................................................................................................... 46 Bit Hydraulics .................................................................................................................................. 46 Differential Pressure......................................................................................................................... 46

Calculating Pore Pressure Values from Dc Exponent ................................................................................... 46 Eaton’s Method......................................................................................................................................... 46 ∆P Ratio .................................................................................................................................................... 47 Trend Lines............................................................................................................................................... 47

Trend Line Fitting................................................................................................................................. 47 Trend Line Shifting .............................................................................................................................. 48

Application and Conclusion .......................................................................................................................... 48 Agip Sigmalog................................................................................................................................................... 49

Theory ........................................................................................................................................................... 49 Methodology ................................................................................................................................................. 49 Conclusion..................................................................................................................................................... 50

Drag, Torque And Fill ....................................................................................................................................... 50 Miscellaneous .................................................................................................................................................... 51

Standpipe, Mud Flow Out, Differential Flow, Pit Volume............................................................................ 51 Mud Weight Out............................................................................................................................................ 51 Mud Resistivity In And Out .......................................................................................................................... 51 M.W.D. ......................................................................................................................................................... 51

Methods Depending On Lagtime.......................................................................................................... 52 Gas..................................................................................................................................................................... 52

Introduction ................................................................................................................................................... 52 Background Gas ............................................................................................................................................ 52 Gas Shows..................................................................................................................................................... 53 Connection And Trip Gas.............................................................................................................................. 53 Normalized Connection Gas.......................................................................................................................... 54 Gas Composition ........................................................................................................................................... 54

Shale Density..................................................................................................................................................... 55 Theory and Limitations ................................................................................................................................. 55 Methods Of Measurement ............................................................................................................................. 56

Heavy Liquids........................................................................................................................................... 56 Variable Density Column.......................................................................................................................... 56 Mercury Pump .......................................................................................................................................... 56 Pycnometer ............................................................................................................................................... 56

Methodology ................................................................................................................................................. 57 Shale Factor ....................................................................................................................................................... 58 Flowline Temperature........................................................................................................................................ 58

Introduction ................................................................................................................................................... 58 Geothermal Concepts .................................................................................................................................... 58

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Pilkington .......................................................................................................................................................... 82 Breckels And Van Eekelen ................................................................................................................................ 82 Bryant ................................................................................................................................................................ 82 Conclusions On The Different Fracture Pressure Detection Techniques ........................................................... 83

BASIC WELL CONTROL ............................................................................................................................. 84 Shut-in Procedures ............................................................................................................................... 84

Introduction ....................................................................................................................................................... 84 Shut-in Procedures............................................................................................................................................. 84

Drilling Ahead – Surface BOP Stack In Use................................................................................................. 84 Tripping Pipe – Surface BOP Stack In Use................................................................................................... 85 Drilling Ahead – Subsurface BOP Stack In Use ........................................................................................... 85 Tripping Pipe – Subsurface BOP Stack In Use ............................................................................................. 85 Exercises ....................................................................................................................................................... 86

Basic Well Control Theory ................................................................................................................... 86 Examples ........................................................................................................................................................... 86 Summary............................................................................................................................................................ 88

Exercises ....................................................................................................................................................... 89 Kill Procedures..................................................................................................................................... 89

Slow Pump Rate ................................................................................................................................................ 89 Obtaining Shut-in Pressures and Effects of Gas Migration................................................................................ 89 Identification of Influx....................................................................................................................................... 90

Exercises ....................................................................................................................................................... 91 Kill Mud Weight................................................................................................................................................ 91

Exercises ....................................................................................................................................................... 91 Introduction To Kick Killing Procedures........................................................................................................... 91

Introduction ................................................................................................................................................... 91 Wait And Weight Method ............................................................................................................................. 92

Introduction............................................................................................................................................... 92 Procedure For Wait and Weight Method .................................................................................................. 92 Pressure Schedule For Drill Pipe .............................................................................................................. 93

Exercises ....................................................................................................................................................... 94 Driller’s Method............................................................................................................................................ 94 Concurrent Method ....................................................................................................................................... 94

Introduction............................................................................................................................................... 94 Procedure For The Concurrent Method..................................................................................................... 95

Exercises............................................................................................................................................................ 95 Kill Procedures With Subsurface BOP Stacks................................................................................................... 95

Introduction ................................................................................................................................................... 95 Problems Associated With Kick Detection ................................................................................................... 95 Hanging-off ................................................................................................................................................... 96 Subsea BOPs ................................................................................................................................................. 96 Choke Line Pressure Loss ............................................................................................................................. 96 Exercises ....................................................................................................................................................... 97 Kill Procedures.............................................................................................................................................. 97

Introduction............................................................................................................................................... 97 Procedure For Calculating An Unknown Value Of Reduced Circulating Pressure................................... 97 Suggested Procedure For Killing A Well Using A Subsea Stack.............................................................. 97

Other Considerations In Deepwater Drilling ..................................................................................................... 98 Comparison Of The Three Methods Of Well Control ....................................................................................... 98

Conclusions ................................................................................................................................................. 100 Exercises ..................................................................................................................................................... 100

Kick Tolerance ................................................................................................................................................ 100 Exercises ..................................................................................................................................................... 101

Saltwater Or Oil Kicks..................................................................................................................................... 101 Example ...................................................................................................................................................... 102

Weight Material Required And Mud Volume Increase ................................................................................... 103 Examples..................................................................................................................................................... 103 Exercises ..................................................................................................................................................... 104

DRILLING FLUID BASICS ................................................................................................................... 105 FUNCTIONS OF DRILLING FLUIDS ........................................................................................................... 105

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OPTIMUM BIT HYDRAULICS ............................................................................................................ 122 INTRODUCTION........................................................................................................................................ 122 CONSTRAINTS ......................................................................................................................................... 122

Minimum Flow Rate ........................................................................................................................... 122 Maximum Flow Rate........................................................................................................................... 123 Maximum Pump Pressure................................................................................................................... 123

BIT HYDRAULICS (KENNETH SCOTT METHOD) ....................................................................................... 123 Procedure ........................................................................................................................................... 123

B.V. RANDALL METHOD......................................................................................................................... 124 Guidelines........................................................................................................................................... 124 Procedure ........................................................................................................................................... 125

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responsibility upon the pressure engineer such that his knowledge and his capabilities will be tested to the utmost. Every well is different, and knowledge may be gained from every wellsite situation. The completion of a demanding assignment that results in the attainment of total depth with the minimum amount of hole problems and the maximum amount of information is one of the most rewarding aspects of the job.

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ρma = density of rock matrix in g/cc

ρf = density of fluid in g/cc

H = section or interval thickness in ft

Substance Density (g/cc)

Sandstone 2.65

Limestone 2.71

Dolomite 2.87

Anhydrite 2.98

Halite 2.03

Gypsum 2.35

Clay 2.7-2.8

Freshwater 1.00

Seawater 1.03-1.06

Oil 0.6-0.7

Gas 0.015

Drilling fluids 1.03-2.04

Table 1 Table of lithologies and average densities.

Bulk density can be obtained from:

• E-logs

• Cuttings density measurement

• Some mathematical drilling models

Obtaining Bulk Densities from E-Logs Get bulk density readings from density E-logs of offset wells and a suitable lithological interval.

To derive bulk density from sonic logs do the following:

Step 1: derive porosity, φ

φ = (∆t - ∆tma) / (∆tf - ∆tma)

Where:

∆t = transit time read from the sonic log in µsec/ft

∆tma = transit time of the matrix in µsec/ft

∆tf = transit time of the fluids in the pore in µsec/ft

Note:

Use values of 180-200 µsec/ft for ∆tf.

For ∆tma use the following values:

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Obtaining Bulk Densities From Cuttings Bulk Density Below is the recommended method to be used while drilling and waiting for E-log results.

Procedure:

1. Fill a mud balance cup with a volume of clean cuttings equivalent to the density of drill water, Dw (1.03 g/cc or 8.33 ppg)

2. Top up the cup with drill water and obtain the combined density of cuttings and drill water, R.

3. Calculate the density: ρb (g/cc) = Dw / ((2 x Dw) – R)

Limitations • Possible hydration of clay cuttings in the annulus and consequent swelling will cause

lower bulk density readings.

• Oil mud contamination of cuttings reduces bulk density readings.

Obtaining Bulk Densities from Cuttings Density Column The density gradient column is a partial mixture of two fluids in a graduated cylinder such that the densities of the two fluids vary evenly from top to bottom. Calibration beads of varying densities suspended in the mixture permit the user to prepare a calibration graph of the density of the fluid with respect to column height.

Xxxxxxxxx: expound more on this xxxxxxxx

Purpose: to obtain shale density and assess the degree of compaction

Limitations • Special facilities have to be provided because of the toxicity of the substances used

• Operator error – degree of consistency and careful of methodology

• Problems of hydrated or oil wet cuttings give low density readings

• Some substances might be heavier than 2.85 g/cc

Obtaining Bulk Densities from Drilling Models Ex: Agip Sigmalog

Calculating OBP To calculate the overburden pressure (OBP):

1. Calculate the OBP for the first interval. In onshore areas it is from the depth of the water table and in offshore areas it is the water depth.

2. Calculate the OBP for each lithological interval

3. Add all the intervals to get the OBP at a certain depth

Formation Pressures Formation pressure is the pressure of the fluid contained in the pore spaces of the sediments. It is also called pore pressure.

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Subnormal Pressures One of the most common causes is the reservoir outcropping at a lower altitude than the elevation at which it was penetrated during drilling. This explains why such pressure anomalies are so frequently encountered in mountainous areas.

The position of the water table in relation to the land surface is also a cause of subnormal pressure, esp. in arid areas.

A rarer situation is the marked reduction of average fluid density due to the presence of a significantly thick gas column. The shallower the depth of the reservoir in question the more marked will be the effect.

Overpressure

Artesian Well If the intake point (outcrop) of an aquifer is situated at a higher altitude than the wellsite then the formation pressure will be abnormally high.

Hydrocarbon Column Within a hydrocarbon bearing reservoir the fluid column creates a pressure anomaly. This is at its maximum at the top of the reservoir. The force that the water exerts on the hydrocarbon interface due to buoyancy is a function of the differences in density between the water and hydrocarbons. The resulting pressure anomaly at the top of the hydrocarbon column is derived by the following formula:

Phc = 0.0519 x H x (dw – dhc)

Where,

Phc = pressure anomaly at the top of the hydrocarbon column

H = height of the hydrocarbon column

dw = density of the water

dhc = density of the hydrocarbons

Overpressure due to this difference in density progressively decreases from a maximum at the top of the reservoir to zero at the water-hydrocarbon contact. Any overpressure already existing in a series is increased by such an additional anomaly.

Pressure Representation

Pressure/Depth Representations

Equilibrium Density, Equivalent Density The primary aim of drilling mud is to counterbalance formation pressure, which is generally expressed in terms of equilibrium density.

Need to check this out:

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In the case of an outcropping aquifer it is possible to assume that the pseudo-potentiometric level is given by the altitude of the outcrop, so that H = Z.

Piezometric level: d = well measurement Represents formation pressure as a head of salt water. The salinity is that measured in a test sample.

The piezometric level is the height at which the water level stabilizes in a non-artesian well.

Potentiometric level: d = average density The density used corresponds to the average density of the water column saturating the reservoir between the intakes and the datum point.

In the case of a fresh water aquifer, the potentiometric level (or true level) corresponds to the pseudo-potentiometric and piezometric levels.

Flow Maps of potentiometric levels show that even in deep-lying aquifers hydrodynamic flow occurs. True hydrostatic conditions do not in practice exist at the basin level.

If the potential of a given fluid is not uniform, a force acts upon the fluid to push it in the direction of minimum potential.

Stress concepts Unlike liquids, which can withstand only internal loads that are equal in all directions (isotropic distribution), solids can support differing loads in a variety of directions. When a solid is subjected to external forces it reacts by redistributing elementary internal loads, called stresses. These differ in two important ways from the pressures undergone by liquids:

• They differ in spatial direction: a given stress ellipsoid can have any orientation;

• There are two types. These differ according to how the load is applied. If loading is perpendicular to the elementary surface in question the stress is said to be normal, and can be compressive or tensile. Tangential loading of the given elementary surface produces what is called shear stress.

A number of items of information are needed in order to define stress conditions at a given point.

The mechanics of continuous environments state that at any given point in a solid there exist three planes intersecting at right angles. Their orientation is unknown, but they are subject to normal stresses only. They are known as the principal planes, and the associated stresses are known as the principal stresses. These planes are therefore not subjected to shear stress. This means that six parameters are required to describe stress conditions at a point in a solid: the values of the three principal stresses and the three orientation parameters of the principal planes.

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Causes of Abnormal Subsurface Pressure

Introduction Pore pressures can be either normal or abnormal or subnormal. Normal pore pressure will be the hydrostatic pressure due to the average density and vertical depth of the column of fluids above a particular point in the geological section – that is, to the water table or sea level. The convention is that abnormal pressures are higher than normal and subnormal pore pressures are lower.

Abnormal pressure has many origins. The object of this chapter is to list them and attempt to explain each one of them in detail. This would give the user enough information to understand the phenomena properly and decide what line of action should be taken when faced with the resulting problems during drilling operations.

Abnormal pressures are hydrodynamic phenomena in which time plays a major role. Every occurrence of abnormal pressure has a limited lifespan, governed on one hand by the continued existence of the reason of the overpressure and on the other by the effectiveness of the seal.

A closed or semi-closed environment is in fact essential for abnormal pressure to exist and above all to be maintained.

The formation of abnormal subsurface pressures can be the result of one or more processes.

The relevant processes are:

A. Undercompaction

B. Diagenesis

Clay diagenesis

Clay minerals

Clay chemistry and structure

Diagenetic reactions

Consequences of clay diagenesis

Carbonate Compaction

Dolomitisation

Gypsum/anhydrite relationships

Evaporite Deposit Seals

Solution Processes

Organic Matter Transformation

C. Thermal Influences

Aquathermal Pressuring

D. Osmosis

E. Tectonic Movements And Deformation

Uplift

Faulting

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• the phase of active subsidence is more recent

• the absence of draining layers of sand or silt are absent in clay intervals (the thicker the clay section, the higher the probability)

The presence of drains within the argillaceous series is an essential factor governing abnormal pressure. The presence and magnitude of the abnormal pressure appear to be related to the ratio of sand to clay in the sedimentary series.

Harkins and Baugher (1969) show that when continental sands and clays cover marine clays, abnormal pressure develops preferentially in environments with a sand content of less than 15%. It will be readily understood that this percentage limit is itself a function of several factors, in particular the degree of confinement of the sand bodies.

The mechanism for expelling water from clays towards porous reservoirs is the same as that for a fluid to migrate towards zones of lower resistance to flow. As expulsion rate is at maximum close to drains, the early stages of this process lead to compaction in the immediately adjacent clay beds. The resulting reductions in porosity and permeability retards further fluid expulsion. In certain cases this same mechanism can contribute to the formation of diagenetic cements that affect the sands at the clay boundary.

The fluid pressure within clay is often assumed to be similar to that in the adjacent sand body with which it is in contact. However, during the compaction process the pressure in the clay further away from the drain is probably higher. This hypothesis, proposed by Magara (1974) seems logical but has never been tested experimentally.

The increases in formation pressure, which can be attributed to the effects of sedimentation rate, are sometimes insufficient to explain certain pressure anomalies.

Conclusion The overburden effect is defined as the result of the action of subsidence on the interstitial fluid pressure of the formation. If fluids can only be expelled with difficulty relative to burial conditions, they must support all or part of the weight of the overlying sediments.

Porosity decreases less rapidly than it should with depth and clays are then said to be undercompacted.

Formation pressure intensity is controlled as much by the rate of subsidence as by the dewatering efficiency. Imbalance between these two factors is the most frequent cause of abnormal pressure.

Diagenesis Diagenesis is the physical and chemical changes that take place within a rock after deposition.

Clay Diagenesis The closest interrelationship between diagenetic and compaction processes occurs with clay minerals, specifically the alteration of montmorillonite to illite. Other diagenetic processes that can influence the pore pressure gradient are:

• Alteration from calcite to dolomite

• Gypsum / anhydrite stability

• Certain results of solution deposits

For the purposes of biogenic hydrocarbon provenance, the diagenetic activity of clay minerals is the most important process at work in sedimentary basins.

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The diagenesis of montmorillonite is endothermic, because the main agent of change is heat coming from the increase of temperature with burial. It is essentially an endothermic de-watering of montmorillonite.

Models of Montmorillonite Dehydration The water content of the mineral is of three types:

• Interstitial pore water

• Inter-lattice oriented water

• Lattice surface oriented water: this has the strongest bond to the mineral

Powers (1959) suggested a two-stage model for the expulsion of water from the smectites:

Stage 1: Free pore water is expelled near the surface under the influence of pressure.

Stage 2: Interlayer water is released gradually, first under the effects of pressure, then increasingly under the influence of temperature.

Burst (1969) improved on this model and proposed three stages of dehydration: (see diagram……..)

Stage 1: Expulsion of free pore water and part of the interlayer water, as far as the last two molecular layers, under the influence of pressure. This process takes place increasingly slowly as permeability declines relative to depth.

Stage 2: Expulsion of the last-but-one molecular layer of interlayer water under the influence of temperature increase. The temperature at which water is released at this stage occurs between 90 and 100°C.

Stage 3: Gradual expulsion of the last molecular layer of interlayer water.

Check with the Sperry Sun books on this three-stage dewatering process:

Stage 1: initial burial of the sediment expels the majority (80%) of the free (locally marine) interstitial pore water in the clay lithology.

Stage 2: Increasing temperature from 180 to 220°F releases two or more layers of inter-lattice oriented water with associated cations. The water expelled will be rich in ions and silica.

Stage 3: Increasing temps to 280 degF, and the availability of K ions, enable the exchange of the last 2 layers (relatively fresh but may contain excess K ions) oriented water from the mineral into the lithology.

There are, however, three areas of uncertainty, namely the quantity of water adsorbed onto the clay sheets, its density and the temperature range needed for dehydration.

Jonas et al (1982) and Fripiat and Letellier (1984), who studied the thermodynamic and microdynamic properties of water at or near mineral surfaces, arrived at two conditions important for current thinking:

• that surface influences affect no more than two or three molecular layers;

• that the structure of this bound water is not noticeably different from that of free pore water, and it therefore seems improbable that its density could reach the values previously quoted, regardless of its position in the pore spaces (i.e. between fine particles or in the interlamellar spaces).

Regardless of this controversy, it will be noted that the release of water can probably contribute significantly to the creation of abnormal pressure, since it occurs at high temperatures, and therefore at considerable depths where the capacity for water expulsion under the influence of the overburden is reduced.

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The conditions whereby this process may take place are many and varied, and are influenced by the presence of other molecules and ions in such substances as dissolved CO2 and magnesian brines, MgCl2. The presence of 6-7% NaCl in solution lowers the temperature range at which dolomite will precipitate. If sulfate ions, SO4, are present the temp of precipitation can be lowered.

Dolomites occur as:

• Primary deposits like the Permian evaporites in northern England.

• Derived by metasomatic alteration thru penecontemporaneous dolomitisation over a large area of unconsolidated limestone deposited on the sea floor.

Secondary dolomitisation is caused at depth by circulating solutions rich in Mg and CO2, possibly derived from the breakdown of earlier dolomites. Dolomitisation followed by breakdown and re-calcitisation is also widely known.

Effects and Relevance During dolomitisation there is an increase in the bulk density of the mineral from 2.71 to 2.86 g/cc. Thus the volume of the mineral is decreased and there is an increase in porosity and permeability of a rock composed of this material.

The increase in porosity without an appropriate change in the volume of pore fluid is a common source of abnormally low pressures. Dolomitisation increases the permeability of a rock, which can result in under-pressured formations where lost circulation of drilling fluids can occur. If the pore pressure is abnormally high in the dolomites it is this type of lithology that can be a source of pore fluid influx.

Sulfate Diagenesis: Gypsum/Anhydrite Relationships Gypsum is the initial deposit of calcium sulfate, CaSO4, associated with marine sediments, esp. evaporites. It is a hydrated form (CaSO4.H2O), and anhydrite or hemihydrate is the dehydrated form.

CaSO4.2H2O <> CaSO4 (anhydrite) + 2H2O

CaSO4.2H2O <> CaSO4.1/2H2O (hemihydrate) + 3/2H2O

Effects and Relevance In general anhydrite is the secondary mineral produced by dehydration of gypsum. It may rarely occur as a primary deposit depending on the stability between the two minerals as controlled by salinity, temperature and pressure.

The temperature of transition from gypsum to anhydrite in pure water is about 40°C, but that this may be lowered considerably by the presence of NaCl in solution to 25°C, increasing pressure and the presence of sulfates and other ions.

The physical changes that take place are:

• an increase in density from 2.35 to 2.98 g/cc

• a 40% loss in volume

• an overall increase in substance volume (anhydrite plus water of dehydration, of about 1%)

Anhydrite is very rarely porous. The excess fluid is deposited in normal detrital pore spaces and/or it would assist in the replacement by dissolving and re-distributing surrounding evaporites. Void spaces within the gypsum/anhydrite assemblage will be occupied by halite.

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Many authors agree that the rise in pressure may lead to microfissuring and allow pressure to be partially dissipated, thus contributing to primary migration.

Undercompacted clay zones often have high gas content. This suggests that cracking of the organic matter makes a contribution to abnormal pressure. On the other hand, since some undercompacted clays have no sign of gas it can be assumed that hydrocarbon transformation is not the dominant cause of abnormal pressure.

Thermal Processes The effects are twofold, those on an open hydrodynamic system, which affect the compaction profile and those on enclosed systems i.e. entrapped fluids.

Aquathermal Pressuring The thermal expansion effect is a concept put forward by Barker (1972). It is a consequence of the expansion

Essentially any volume of the pore water that becomes isolated due to formation of permeability barriers is then a fixed volume subject to the effects of temperature and imposed pressure. The effects of pressure are those of increasing and decreasing depth. Temperature affects the actual volume and density of the fluid. As the volume is fixed and expansion restricted, the density must be fixed and accordingly the fluid pressure gradient increase.

Any fixed volume of fluid will be subject to temperature-controlled expansion and contraction. Thus if a non-compressible liquid volume is raised through the geothermal gradient it will become under pressured; and if lowered it will become over pressured.

Aquathermal expansion (pressuring) only has an effect if the following conditions are satisfied:

• The environment is completely isolated.

• Pore volume is constant.

• The rise in temperature takes place after the environment is isolated.

In fact, for the thermal effect to be significant the system must be perfectly closed, since creation of overpressure is associated with a very small increase in the volume of water. The volume of increase is in the order of 0.05% for a burial of 1 km with a temperature gradient of 25 deg C/km (Magara, 1975). This means that even the smallest leak will reduce or even cancel out the thermal effect. Whether the expansion effect gives rise to any overpressure will depend on the extent to which the rate of expansion due to the rise in temperature matches the dewatering rate.

Even so, since the fluid expands so little, clays are usually sufficiently permeable to allow the additional volume to be dissipated in a short geological time given a “normal” geothermal flux. However, if the geothermal gradient steepens significantly and is accompanied by a rapid burial rate, the resulting increase in fluid volume may exceed dewatering efficiency.

Strong thermal anomalies associated with volcanic intrusions or nearby magma chambers may create local overpressures of limited duration (generally less than one million years).

Objections Many objections can be raised against thermal origins of overpressure due to the expansion of water. These are:

• Completely impervious formations are rare.

• Transition zones, which correspond to a gradual shift from hydrostatic to abnormal pressure, reflect the hydraulic transmissivity through clays.

• A rise in temperature reduces viscosity and makes fluids easier to expel.

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Conclusion Although lab tests have proven that osmotic effects are real, the evidence for their existence in nature is far less certain.

It will be noted that lab trials used only thin membranes of pure clay and strongly contrasting saline solutions. These cannot easily be extrapolated to the geological environment.

It seems that the capacity for osmosis to generate abnormal pressure is limited to special cases such as sharply contrasting salinity, proximity to salt domes and lenticular series. In most instances of abnormal pressure, the role of osmosis is difficult to prove and must be thought of as minor.

Tectonic Movements and Deformation Any process that shifts sediment from its normal position of compaction deformation will affect the fluid pressures contained in that sediment. This means that tectonics may cause abnormal pressure or restore pressure to normal.

The link between tectonics and fluids can be viewed from two related standpoints:

• Tectonic activity causes rock deformations which have a direct or indirect effect on fluid pressure distribution;

• To a greater or lesser extent fluid pressure alters the way in which deformations develop as a result of stress.

The categories of tectonic movement and deformation involved are:

• Uplift

• Faulting

• Folding

• Diapirism

• Tectonic deformation: Sediment deformation

Uplift The crustal thinning that has aided downwarping has enabled higher heat flow into the basin that eventually results in upwarping.

Changes in formation relief and geometry are a direct cause of pressure redistribution. Relief induces hydrodynamic activity, which in turn is an underlying cause of some of the pressure anomalies observed.

Deep-lying sediments may be uplifted and part of the overlying strata then eroded. In this way zones of high pressure could be brought closer to the surface, which would make them appear anomalous. Such situations are referred to as paleopressures.

This hypothesis assumes a closed system and rapid uplift. But, this raises numerous objections:

1. Since tectonic movement is usually accompanied by fracturing, pressure would tend to dissipate.

2. The lower temperature at the reduced depth would decrease the fluid volume and therefore the pressure.

In fact temperature equalization probably ensures that fluid pressure declines more quickly than overburden pressure during erosion, thus leading to a negative pressure anomaly (Magara, 1975).

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Joints are fractures with little or no displacement. They are capable of depriving impervious rocks of their ability to act as a seal. On the other hand, plastic clays, anhydrites and above all salt deposits are self-repairing, and are the only seals capable of retaining their impermeability even in conditions of severe deformations (Iran, Iraq). Fracture intensity depends on both the stress field (type of tectonic activity) and the mechanical behavior of the layers.

Overthrust Zones

Fluids and at high pressure and temperature act as a lubricant for the movement of the overthrust block. Very pronounced overpressure can be induced by contact between the overthrust surface and the substratum. Rapid loading occurs, causing abnormal pressure in underlying confined sequences. The significance of these effects will depend on the thickness of the nappe and the degree of hydrodynamic confinement within the sequences beneath the overthrust.

Folding The same tectonic forces that cause thrust faulting will cause beds of sediment to buckle. This will have similar effects of raising and lowering beds through the compaction and geothermal gradients.

Tectonics and Sedimentation

Deltaic Areas The development of a delta depends on the balance between sedimentation rate, subsidence rate and eustatic variations in the sea level. Undercompacted zones are formed in underdrained or undrained parts of the delta.

The two zones of a delta are:

• Proximal zone, where growth faults will develop preferentially

• Distal zone with shale domes and ridges

Growth Faults Growth faults are also known as synsedimentary or listric faults. They possess a curved fault plane which is invariably concave towards the basin. This plane is nearly vertical in its upper part, then tends gradually to conform to the dip of the strata as its slope decreases towards its base. The downstream compartment displays thickening of the sediments in the form of a “roll-over” (compensation anticline) near the fault.

Although the importance of gravity in the development of growth faults is undisputed, trigger mechanisms are still open to debate. Basement tectonics, gravitational slumping of the sediments, salt or clay diapirism, differential compaction or a combination of these factors have all been suggested. Crans et al (1980) showed that during compaction, clays could slide down under own weight on a slope of less than 3deg. Lowering of the downdip compartment creates a surface depression that traps sediments. Their additional weight encourages further slipping. The slip plane is itself seated in an incompetent layer.

The base of the updip compartment of growth faults often includes a ridge of undercompacted shale (residual shale mass) resulting from differential compaction.

The preferential site for hydrocarbon accumulation is the rollover structure of the downdip compartment against the fault. If such structures are drilled, there is always the risk of crossing the fault and penetrating the ridge of undercompacted shale, thus risking a sudden rise in formation pressure.

Shale Diapirism

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• Contamination of pore fluids: Pore fluids of formations near the intrusion will have an increase in the concentration of dissolved salts. There will be an increase in pore water density and possible acceleration or escalation of osmotic activity.

• Rafters: Large rafters of formations can become engulfed within the intrusive salt body and entirely sealed off from the normal hydrostatic gradient. The mobility pressure is transmitted to all the fluids within the enclosed rafter and the result is near lithostatic pore pressures.

• Associated tectonics: includes uplift of formations, lateral discontinuity of formations and induced faulting.

• Deformation of sediments

Porosity can be increased or decreased by deformation of the sediment along axes other than the vertical axis of overburden.

Summary Of Tectonic Effects The uplift of a sealed volume by any process will transport the pressure at which the volume was sealed, up through the geological column. The burial of sealed volumes of pore fluid has also been cited as a geopressuring mechanism.

The following factors that affect the formation of geopressures:

• Paleo-factors: depth at the time of sealing, paleo geothermal gradient, pore fluid composition

• Current factors: current depth, pressure of confinement, geothermal gradient, pore fluid composition

Tectonic mechanisms may be summarized as follows:

Extension > open fractures > pressure dissipation

Easy expulsion of fluids > compaction > normal pressure

Compression difficult expulsion > undercompaction > abnormal pressure > possible hydraulic fracturing > expulsion > compaction

Pore Fluids And Confinement ???? In most circumstances the pore fluids will consist of a mixture of connate waters of variable salinity, with possible volumes of hydrocarbons, oil and/or gas. Also the waters may consist of differing ionic brines, and a gas portion may have appreciable volumes of H2S, CO2 or other non-hydrocarbon gases.

Gases are subject to the standard chemical laws relating to gases:

Boyle’s Law: states that the volume of a gas varies inversely as the pressure to which it is subjected (temperature constant)

Charles’ Law: states that the volume of a given mass of gas is directly proportional to the absolute temperature

Miscellaneous Processes

Mud Diapirs and Sandstone Dikes (Move to Subduction Zones ??) These features are overpressure phenomena that result from rapid deposition of sediments that are relatively mobile. The phenomenon is often associated with biogenic gas activity, which

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Underground blowouts also introduce higher pressures into shallow formations.

Excessive equivalent mud densities can induce supercharging of permeable formations.

Piezometric Fluid Levels The down dip segment of a monoclinal aquifer will be subject to an artesian pressure, due to an extended hydrostatic head.

Conclusion Identifying the cause of the over pressure is generally a delicate matter, and calls for a sound knowledge of the geology of the region. Below are the points that need to be considered:

• The crucial importance of seals and drains in maintaining abnormal pressure

• Time is the determining factor in fluid dispersal (that’s why overpressure zones are commonly found in young sedimentary sequences)

• High pressure may result from a combination of various causes

• Most high-pressure zones are more likely to be found in clay-sandstone sequences

• The lithological changes which some of the causes bring about can be used for detection purposes during drilling

The characteristics and typical environments of the various origins are summarized in the following table:

Origin Characteristics Environment

Overburden effect Major contribution to the existence of abnormal pressure

Leads to undercompaction

Geographically widespread

Long-lasting effect linked to sedimentation rate

Young clay-sand sequences:

• Deltas

• Passive continental margins

• Accretionary prisms of subduction trenches

• Evaporite deposits

Aquathermal Expansion of water

Requires a very well sealed environment

Temperature plays a major role

May be superimposed on the overburden effect

Closed system w/ steep geothermal gradient

Volcanic zones

Tectonics Very varied characteristics due to redistribution of masses and fluid pressures

Faults, folds, overthrust faulting, clay diapirism, salt diapirism

Lateral pressuring

Cracking of organic matter and hydrocarbons

Cracking = increased volume

Develops either in undercompacted environments or independently

Important role of temperature

Sediments rich in organic matter

Clay diagenesis Second order cause. May be superimposed on the overburden

Thick argillaceous sequences

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Overpressure Detection Techniques

Introduction There are numerous techniques available to the pressure engineer, which assist in the prediction, detection and evaluation of overpressured formations.

Normal Compaction Trend In order to evaluate abnormal pressure linked to compaction anomalies it is necessary to define a normal compaction trend for reference purposes.

Compaction data will give a linear trend on a logarithmic plot of porosity vs. depth. Argillaceous sediments must be used for determining this relationship.

The following influences the slope of a normal compaction curve:

• The mineralogy and relative proportions of the phyllosilicates in the clay

• The non-argillaceous mineral content (quartz, carbonates, organic matter, etc)

• The sedimentation rate, which conditions the texture by means of the spatial arrangement of particles. Porosity is lower if sedimentation occurred at a lower rate.

• The geothermal gradient

Characteristics of Undercompacted Zones

Transition Zone Transition zone is an interval that exhibits a gradual change in pore pressure from abnormal to hydrostatic. Its thickness depends on clay permeability, drainage conditions and the time factor. It is easier to detect abnormal pressure if the transition zone is gradual. The thicker the transition zone, the easier the undercompacted zones will be detected.

Diagenetic Cap Rock Diagenetic cap-rocks are the indurated and carbonated shale levels at the top of certain undercompacted zones.

The consensus is that they are of a secondary or diagenetic nature. Some consider them that diagenetic cap-rocks can be the cause of underlying overpressures, while others believe that they are a consequence of it.

Diagenetic cap-rocks do not necessarily accompany undercompacted sequences.

List of Overpressure Detection Methods Below is a tabulation of methods used to aid the engineer in predicting and evaluating overpressured zones.

Method Phase of Operation

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Method Phase of Operation

VSP

Table 5 Table of overpressure detection methods.

Pre-spud Data Geophysical data

Geological prognosis

Nearest offset well data

Piezometric Maps

Geophysical data The geophysical methods used are:

Seismic velocity (most frequently used)

Gravity (rarely used)

Magnetic survey (rarely used)

Seismic Methods

Very High Resolution Seismic A technique generally used for studying the seabed. Its depth of investigation is limited to 50-100 meters. Its resolution range is down to less than a meter. It is important for platform anchorage and can also reveal gas pockets and dismigrations (gas chimneys) close to the surface.

High Resolution Seismic This has a resolution in the 1-5 meter range and a depth of investigation between 1000-1500 meters. It is an adjunct to conventional seismic methods in the superficial blind spots of the “twilight zone”.

Conventional Seismic Methods It has a lower resolution of 5 to 50 meters and a depth of investigation extending to down several thousand meters. It is the most important source of information about abnormally pressured zones in the vicinity of wells to be drilled.

The seismic section can reveal gas zones (bright spots), faulting and diapirs. It provides an indication of lithologies and facies and zones of undercompaction.

Analysis of internal velocities by deduction from seismic velocities is particularly useful when assessing the development of compaction and the sand-clay ratio.

3-D Seismic The 3D method gives a subsurface scan on a regularly spaced grid of points instead of a pattern of lines. Acquisition is done through a line spacing of 50-100 meters instead of wide seismic loops. This results in establishing the geometry of structures with greater accuracy and the lateral acoustic variations of a given seismic horizon can be defined in 3D.

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Where,

V = interval velocity

A and B = constants

Z = depth

Faust’s Law introduces the factor of geological age into the formula by postulating that velocity increases uniformly with age. The linearity of this relationship is only valid for a given geological period.

LogV = A + B LogZ + C logT

Where,

C = constant

T = geological time

Quantitative pressure evaluation may be carried out using either the equivalent depth method or the Eaton method.

Estimating The Sand/Shale Ratio This method is used successfully in deltaic zones. It is based on the fact that, on a semi-logarithmic plot of ∆t vs depth, the points for normally compacted clay are the slowest. A trend line passing through these points represents the clay trend. Another line drawn parallel to it based on a velocity 25% higher defines the sand trend. The position of the measured velocities in between these trend lines gives an estimate of the sand/shale ratio.

Reliable interpretation of velocity analyses relies on information about a number of criteria depending on terrain, signal quality and subsequent processing:

• Unforeseen changes in lithology

• High angle dip

• Faulting

• Complex tectonics

• Static corrections

• Normal move-out corrections

• Multiple reflections

• Abnormal seismic paths

Amplitudes The amplitude of the signal reflected from the contact between two layers depends on the interface reflection coefficient. This coefficient is a function of the contrast between the acoustic impedances of each layer. Acoustic impedance is the product of the density and the acoustic velocity.

The presence of gas sometimes creates significant amplitude anomalies. Studying such anomalies is the very basis of detecting hydrocarbons directly from seismic data.

On the other hand, lateral amplitude variations can also be due to lateral facies changes that must be taken into account when extrapolating on the basis of reference wells.

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Piezometric Maps Piezometric maps give an appreciation of abnormal pressure distribution factors.

While Drilling Data

Introduction By far the most relevant and significant data for overpressure prediction, detection and calculation becomes available during the drilling of the well.

Below is a summary of the changes to the numerous indicators as an overpressured zone is approached or drilled:

Pressure Indicator Change in Value Reason for change

Drill rate (ft/hr) Increases Formation is undercompacted, differential pressure at the bit is approaching zero

D exponent Decreases As ROP increases, d-exponent decreases, reflecting overall increased formation drillability

Total gas Increases Reflects greater volume of in situ gas

Background gas Increases Greater volume of in situ gas, loss of overbalance

Connection Gas increases Reflects loss of overbalance as formation pressure approaches mud hydrostatic

Torque increases Often due to loss of overbalance, causing hole to come in around collars and stabilizers.

Drag increases Reflects hole instability due to loss of overbalance

Fill increases Hole instability

Flowline density decreases As overbalance is lost, formation fluid contaminates drilling fluid

Flowline viscosity increases Formation fluid is often hotter, containing mineral hardness, causing mud fluctuation

Flowline salinity increases The more highly saline formation fluid enters the well bore as overbalance is diminished.

Shale density decreases Reflects undercompaction in an overpressured environment.

Cuttings shape, size increases Reflects hole instability, less gouging of formatic presence of cavings.

Presence of gypsum increases In an evaporite environment, anhydrite rehydrates to gypsum in the presence of water, being both a cause and a result of overpressure.

Flowline temperature increases Overpressured zones, possessing greater than normal pore fluid, act as thermal

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Lithology This is a major factor controlling ROP changes. The drillability of a rock depends on its porosity, permeability, hardness, plasticity and abrasiveness, as well as the cohesion of its constituent particles.

All else being equal, a change in ROP reflects a change of lithology. Cuttings analysis must be crosschecked against changes in ROP. When examining compaction, ROP analysis is in two stages. The first stage identifies argillaceous beds and the second examines how penetration rate changes within them.

It is common that an increase in silt content can reduce shale drillability up to a certain point, after which drillability improves again.

Unlike most parameters, it seems unlikely that such changes in lithological detail will ever be quantified. They depend on the experience of the geologist.

Compaction The compaction of a sediment is reflected by its porosity, that is to say the extent of matrix grain-to-grain contact.

With unchanging lithology and no changes in any of the other variables, ROP will gradually decline as compaction increases. The reverse happens if there is undercompaction. The relative change in ROP is a function of the degree of undercompaction.

Differential Pressure Differential pressure (∆P) is the difference between the pressure exerted by the mud column and the pore pressure.

For any given lithology ROP slows as ∆P increases and vice versa. For example, according to Goldsmith (1975) a ∆P of 500 psi (35 kg/cm2) can cause the ROP to slow down by around 50%.

In undercompacted shales, lower ∆P and increased undercompaction cause higher ROP. Some authors believe that compaction has a negligible effect, implying that there must be a direct relationship between ROP and ∆P. This hypothesis is probably only valid over short intervals.

WOB Changes in WOB have more effect on ROP than any other drilling parameter.

Generally speaking, ROP increases with WOB.

A minimum WOB, called the threshold weight, is needed to get drilling started. This could be negative in the case of a slightly consolidated formation, since jetting alone is sufficient to ensure penetration.

Above the threshold weight ROP rises almost proportionally with WOB. Above a certain point called the flounder point the ROP stops rising since the bit teeth become jammed in the rock. The idea of a flounder point is valid only for soft formations.

RPM It was initially thought that the relationship between ROP and RPM was linear. But Vidrine & Benit (1968) and also Prentice (1980) considered the relationship exponential:

R = Na

Where,

R = ROP

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Suspended Solids Solids can have the effect of reducing immediate water-loss, and in certain cases this can limit ROP.

If there are many solids in the mud, penetration can be impeded because the teeth are prevented from making clean contact with the formation.

This effect is thought to be relatively insignificant.

Bit Type And Wear Optimizing the ROP chiefly depends on matching the bit type to the formation.

The usual critical parameters for tri-cone bits are:

• Tooth height and spacing

• Amount of axial offset per cone

• Resistance to wear

Bits are classified by the hardness of the formations they are designed to drill.

A major change in bit type distorts the value of the drilling rate and alters drilling performance in the event of changes in lithology. This is a hindrance when interpreting progressive changes in the ROP.

For these reasons, when approaching undercompacted zones the bit should not be changed to a type other than the one already in use.

At the end of its useful life, a bit can mask changes in lithology, compaction or differential pressure due to a decrease in ROP under the effects of wear.

Tri-cone bit-wear affects both teeth and bearings. Tooth bits undergo gradual tooth wear, but bearings can wear out quite abruptly once they are no longer watertight. Insert bits tend not to wear out gradually, but instead their inserts break off in hard, abrasive formations. Insert breakage depends on how well the bit is matched to the formation, on the RPM and on vibration.

A diamond bit proceeds by making scratches or grooves, not by cratering. Relationships between ROP and drilling parameters follow different rules. RPM and possibly hydraulic flow are the main factors and their relationship with the ROP is linear.

Personnel And Equipment Rig equipment can impose an upper limit on parameters. Personnel, esp. drillers, must ensure that the chosen drilling parameters are done.

Conclusion Under ideal conditions in shales, ROP can be thought of as dependent on porosity, and therefore a way of detecting undercompaction. In normal use, however, many parameters affect the reliability of the measurement. To use it properly we have to employ drilling models, such as the Dxc, the Sigmalog or normalized drilling rate.

D Exponent The d and dc exponents (Dx and Dxc) were developed to help in correcting or “normalizing” the drill rate for the effects of changes in WOB, RPM, hole size and mud weight with respect to the recognized effects of differential pressure and compaction on ROP.

Jordan and Shirley (1966) developed the d exponent method in the mid-60’s for overpressure detection in the US Gulf Coast. The commonly accepted equation is for Standard US units:

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• Junk in the hole

3. Formation parameters

• Unconformities

• Lithological variations

4. Drilling fluid parameters not in the dc exponent modification

• Bit hydraulics

• Differential pressure

Discussion

Mechanical Parameters included in the d exponent formula

Turbine Motors When a turbine motor is run, where minimal bit weights and high RPM are used, the Dxc values are deviated and these values should be ignored. In this case it is futile to shift the trend line because:

1. The drilling action associated with the turbine run is controlled and not influenced by the formation’s drillability.

2. The hole angle is being changed and it is very difficult to fit or shift a trend line to deviating well data.

3. The turbine run might be short.

This is not to say that trend line shifts are never appropriate for turbine runs. A long, straight run of a similar drilling action on a competent formation may well require a shift.

It is possible in situations of extensive controlled drilling, such as ROP restraint to facilitate good hole cleaning, that trend shifts may help in the interpretation. Any such shifts must be considered as temporary and a return to a normal drilling action will require a return to the original trend.

Hole Section Change It is often observed that the calculated dc exponents are quite different above and below a change in hole size. All of the basic formula inputs are usually changed at such a stage.

There is no easy way of assessing the pore pressure in such a situation. The bit weight per bit area expression in the formula should accommodate the change in hole size or the model is invalid. Sometimes the established trend line should be continued in anticipation of the pore pressure increasing.

Other Mechanical Parameters

Bit Type / Drilling Action The d exponent was formulated for the drilling action of mill tooth bits. However, in recent years the method was applied to insert, PDC, Stratapax and diamond bits. When there is a change from one type of drilling action to another there is usually a noticeable change in the dco. Therefore, it is usually necessary to shift the trend line.

Another aspect of bit type is whether the bit in the hole is suitable for the formation being drilled. Such a situation may require a temporary shift in the trend line. However the data obtained during such a situation will be poor and should be subsequently neglected.

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Prev bitTotal rotating time or footage axis

Tooth wear

Previous bit T6 = H0 = 0.75

Total rotating time: t0 = 20 hrs

Current bit: rotating time: t = 12 hrs

You can graphically calculate the bit wear from the current graph or use the following formula:

H = H0 x (t/t0)

H = 0.75 x (12/20) = 0.45

The bit wear function F(H) was established for tooth bits. For other types of bit some authors suggested applying a correction coefficient K to F(H):

Tooth bits: K=1

Insert bits: 0.4 < K < 0.6

Diamond bit: 0 < K < 0.2

No bit wear correction: K = 0

It should be noted that it is unsatisfactory to introduce correction coefficients for other bit types using a relationship based on the wear characteristics of tooth bits, because the wear processes involved are quite different.

Discussion Bit wear corrections are frequently used by mudlogging companies, but are not entirely satisfactory for the following reasons:

1. Any relationship between ROP and wear is not realistic.

2. Bit wear formulae do not take lithology into account. In particular they ignore the hardness and abrasiveness of the formation being drilled.

3. Bit wear evaluation while drilling takes no account of WOB.

Bottom Hole Assembly Configuration The stabilizer of the BHA may support some of the drilling weight and result in erroneous data. This will be particularly evident in deviated wells. The phenomena may also occur in plastic formations such as salt or highly pressured shales/clays. In this case the shales/salts etc will support the drill string and in the process makes dc exponent evaluation very difficult.

Hole Angle

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data can’t be interpreted for the positioning of the trend lines or pore pressure. It is important to base the trend line upon properly indurated sediments.

Drilling Fluid Parameters

Bit Hydraulics Circulation rates may influence the ROP if there is considerable change. For example from good hole cleaning to annulus overloading. However the major hydraulic influence on ROP is at the bit. Bit hydraulic parameters are optimized to ensure all cuttings are removed from the bit teeth. This enables the bit to perform to its optimum efficiency, depending upon:

• The WOB/RPM relationship

• It’s suitability for the formation

• The degree of wear on the various bit parts

• The differential pressure between the formation at the bit and the ECD

Poor bit hydraulics will result in reduced ROP and appropriate trend line shifts may be a temporary necessity.

Differential Pressure As the overbalance between the ECD and pore pressure increases, the ROP decreases. There is no easy way of assessing the pore pressure in such a situation. A temporary shift in the trend line will be necessary to adjust for a mud weight increase. When the pore pressure increases, the original trend line should be used for pressure calculations.

When drilling with an overbalance in excess of 500 psi it is observed that the dc exponent is insensitive to changes in overbalance. It becomes very difficult to detect changes in the overbalance between say 800 psi and 1500 psi. the impact of this is that pressure reversals to decreasing pore pressures will go unnoticed and result in hole problems such as differentially stuck pipe or mud losses.

Calculating Pore Pressure Values from Dc Exponent Values for pore pressure may be calculated utilizing several methods:

1. Eaton’s: p = S – (σ x ((dc)o/(dc)n))1.2 (check formula if: (σ x ((dc)o/(dc)n) 1.2))

2. ∆P ratio: p = N x (dc)n/(dc)o

Where: p = pore pressure ppg

σ = S-N

N = normal pore pressure ppg

(dc)n = normal dc

(dc)o = observed dc

Eaton’s Method Eaton’s equation was derived with empirical data which applied known pressures to resistivity, conductivity and sonic logs from a broad range of US gulf Coast wells. The equation was then applied to the dc exponent data and found to be equally suitable. In using Eaton’s formula it should be noted that dc exponent profiles are of different character to plots of wireline data. Resistivity etc are direct measurements of lithological properties which are the result of the

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The two questions the operator should ask are:

1. How will bad data appear?

2. What sort of slope will the trend line have? The slope is a function of geology and in particular the relationship of age to depth.

Example: (see pp 11-13 / 4-Drilling Models book) a well has Oligocene and Pliocene sands overlying mixed lithologies of the upper Miocene. These mixed lithologies include anhydrite, salt, sand and shales.

Applying these two questions it is evident that:

• The bad data is that which represents anhydritic shale. In the first case the ROP will be lower, and thus the dco values will be higher, than those of cleaner shale. For a sandy shale the reverse will be the case.

• In this case there is a very thick vertical sequence of tertiary sediments, particularly from the Miocene. The trend line will be near vertical. It is more steeply inclined than in an area of a large age range over a shorter depth interval.

Example (p14 Baroid books): the bad data is sandy shale that is evidenced by faster ROP’s and lower dco values than for cleaner shales. The trend line is positioned so that all the bad data will be to the left of the trend line. The geological sequence is a more complete tertiary sequence over a shorter vertical interval. Therefore the trend line will be less near the vertical than the one above.

Trend Line Shifting Essentially there are only 4 situations that justify the shifting of established dc exponent trend lines. These are:

1. A permanent shift for a major unconformity. Note: this may be a rare occurrence.

2. A shift for a change in drilling section. This may be permanent depending on the drilling program.

3. A shift for a considerable change in hole inclination. This is valid for as long as the hole has that inclination +/- 5 deg.

4. Temporary shifts to the trend line for extreme changes in mechanical, hydraulic or other influences described in the section Factors affecting the dc exponent curve.

Shifting must be exercised with great caution and a studied consideration of all conditions influencing the dc exponent. It is strongly recommended that an original, established trend line is never completely abandoned, but retained for reference, even after the shift has been made.

Application and Conclusion The model is applicable for clay/shale sequences but has been shown to be relevant in other lithologies. The pressures of the reservoir rocks can be estimated from those pressures evaluated in immediately overlying clays or shales.

Calculations of pore pressure are made by comparing the observed values with those anticipated and by using Eaton’s formula. In evaporite areas a proportional ratio may be useful.

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fact that the bit face is more difficult to clean in shales. Changes in n has a minor effect on σt’0.5. It is therefore not a problem to apply it to other sectors than the Po valley.

4. A reference trend rock strength (square root of σr) is then calculated using particular trend coefficients.

σr0.5 = α x (Z/1000) + β

where,

σr0.5 = parameter defining the reference conference trend.

α = trend slope

β = intersection of the trend with the horizontal axis for Z=0

Z = depth in meters

The slope of the trend usually remains constant at 0.0881 / 1000 m.

5. Determine porosity:

φ = 1 / (1.4 + (9 x σo0.5 x σr0.5 / σφ0.5)

σφ0.5 = trend of the σφ0.5 points most to the right

6. Finally, calculation of formation pore pressure is achieved by finding the ratio between the depth-corrected raw rock strength (σr0.5) and σφ0.5. The σr0.5 trend must be shifted to allow for changes of formation, bit or diameter, such that:

σr10.5/σr20.5 = σφ10.5/ σφ20.5

((the reference trend rock strength, (square root of σr/square root of σt’) and the current bit equivalent circulating density.)) check this one.

Rock strength parameter, σo0.5, is plotted against linear horizontal and vertical scales. For identical lithologies Sigmalog behaves like compaction, i.e. increases with depth. The highest values represent the lowest porosities.

A shift is required each time there is a change of lithology, diameter or bit type, but the slope remains the same. If values of σo0.5 start to fall without any change of lithology or drilling conditions, this suggests an increase in porosity and/or formation pressure.

Conclusion The efficiency of Sigmalog are very similar to those of d exponent. It is a method that is not easy to use and therefore ill suited to unexplored basins. Its use should be limited to clays and shales. On the other hand it relies too heavily on the operator’s judgment when determining the various trend shifts required. At the same time the interpreter has little control over the calculation stage.

Drag, Torque And Fill Drag, torque and fill are all indirect, qualitative indicators of overpressure; they are also indicators of hole instability and other mechanical problems that have nothing to do with overpressure.

Drag is the excess force that is necessary to pull the drill string up, whether it is for a connection or a trip. As overpressured shale is drilled into, drag is often noted. This is due to the inability of the underbalanced mud density to hold back the physical encroachment of the formation into the wellbore. Drag is also due to inefficient hole cleaning, formation damage caused by the drilling fluid, hanging up of the stabilizers in deviated holes, etc.

Rotating torque often increases in an overpressured zone due to the physical encroachment of the formation (esp. shale) into the wellbore. Increases in rotating torque are also caused by

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• Mud temperature

• Mud resistivity

• Formation resistivity

• Formation radioactivity

If the true WOB is known, drilling rate can be normalized with better accuracy.

Information on true bottomhole mud pressure gives a more accurate view of the effects of swab, surge and annular pressure loss.

Differential resistivity between mud in the drill pipe and the annular space may well be considered a kick indicator.

Methods Depending On Lag Time

Gas

Introduction Gas may be used as a qualitative and semi-quantitative indicator of overpressure. Gas is derived both from drill cuttings and from the in-situ formation, enters the drilling mud, and is circulated to the surface where it is broken out from the mud by a gas trap. ILO’s THA measures 1% gas in air as being equivalent to 50 units. Gas shows can be categorized according to its source as follows:

• Cuttings gas: gas released from the drilled formation and by the cuttings moving up the annulus

• Produced gas: gas issuing from the borehole walls. This may be due caving or swelling and can also arise from diffusion or effusion if differential pressure is negative.

• Recycled gas: if the mud is not completely degassed at the surface, it may be returned downhole still gas cut.

• Contamination gas: from petroleum products in the mud or from thermal breakdown of additives. Breakdown of organic matter in shales or thermal effects produced by the bit can also give rise to gaseous hydrocarbons.

The amount of gas detected at any point in the well is related to the:

• Hydrocarbon distribution

• Porosity and permeability of the formation

• Differential pressure

• Volume of rock drilled (the hole size, ROP)

• Circulation rate

• Mud characteristics (type, viscosity, temperature, hydrocarbon solubility, etc.)

• The measuring equipment

Background Gas Background gas is the gas released by the formation while drilling. It usually consists of a low but steady level of gas in the mud that may or may not be interrupted by higher levels resulting from the drilling of a hydrocarbon zone or from trips and connections.

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Observing the frequency and progression of connection gases can be a valuable aid in evaluating differential pressure.

To monitor connection gas correctly the following criteria should be observed:

• Lithology: preferential attention must be paid to connection gases from argillaceous sections. Permeability is then less critical and the gas arises from diffusion or cavings.

• Connection gases may be compared with one another, provided connection times are fairly uniform. On the other hand, in the case of trip gas stopping times vary and comparisons are more difficult.

• Coming out of the hole can produce a temporary condition of negative ∆P or exaggerate one that already exists. In order to keep the effects of swabbing on connection gas to a minimum it is recommended that pulling speed should be kept steady.

Below are some situations that can be encountered while drilling with a steady mud weight:

• Background gas stable – connection gas sporadic: This situation is not characteristic of formation pressure variation. Connection gas may be present due to swabbing, lithological changes or caving. However, variable connection conditions can give rise to this situation in a transition zone. Interpreting this situation is ambiguous.

• Background gas stable – connection gas increasing: This is typical of entering a transition zone. The stable background gas suggests positive ∆P. But the increasing incidence of connection gas reflects a decline in ∆P.

• Background gas and connection gas on the increase: This means that a zone of negative ∆P is being drilled.

The best information concerning well equilibrium is to be obtained from observing overall trends in connection gas irrespective of short-term fluctuations. In fact connection gas is more of a method for monitoring developments in pressure than a means of precisely defining the top of the overpressured zone.

Abnormal pressure is confirmed if, by adjusting the mud weight, the value of the connection gas is reduced.

Normalized Connection Gas ???? In order to obtain standardized gas data, some companies recommend deliberately creating standard gas shows using a rule known as "10-10-10”. The method involves inducing gas slugs under three different sets of equivalent density conditions. Gas shows can then be interpreted more accurately.

Expound on method ………..

The method is good in principle, but is time consuming when applied regularly and may also lead to stuck pipe.

Gas Composition The occurrence or increased incidence of heavier gas components is commonly observed when drilling into transition zones. This can be used as a means of detecting undercompacted zones.

Undercompacted clays are often source rocks. If volatile hydrocarbons given off by maturation of organic matter due to heat stored in the undercompacted zone are trapped, drilling through this zone is accompanied by an increase in background gas. On the other hand, selective retention of heavy hydrocarbons as a result of the migration of light components through the transition zone leads to an anomaly in gas composition.

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• Shale exhibits varying mineralogy; hence care must be taken in the selection of the sample. The shale should be uniform in mineralogy, something that can not be discerned using the naked eye, or, for that matter, a reflecting microscope. Also, it must be assumed that the shale sample comes from the bottom and has not been mixed or settled during circulation or connections; also, it must not be a caving.

• The procedure for collecting shale densities may incorporate user inaccuracies. This results from improper processing of samples, different operators, the type of density column, the established trend line, etc.

• The density measurement technique is dependent upon proper calibration

• The inability to measure any valid density for shales at shallow depths in many marine basins; this precludes the establishment of a normal compaction trend.

• Lastly, there is some question to the validity of the equivalent depth hypothesis.

Methods Of Measurement

Heavy Liquids Kits of liquids of different densities are available. A set of densities from 2.20 to 2.70 g/cm3 in stages of 0.05 g/cm3 will cover the entire range of shale densities. The method is based on the Archimedes principle. Each cutting is immersed successively in liquids of increasing density until it no longer sinks.

In addition to the disadvantage of insufficient accuracy, cuttings must be transferred from one liquid to another with care in order to avoid any change in the density of the liquids through mixing.

Variable Density Column A variable density column can be prepared by partially mixing miscible liquids of known densities. The density distribution is checked using beads of calibrated density that can be used to prepare a graph of density against column height.

The most commonly used liquids are bromoform (d=2.89) and carbon tetrachloride (d=1.59), or the somewhat less toxic trichloroethylene (d=1.47).

Each cutting is immersed in the column after having been dried on absorbent paper, then all that is necessary is to read off the height at which the sample has come to a halt and check this value on the calibration curve in order to obtain the shale density.

As long as the column is properly calibrated this method is more accurate and faster than the previous method. It is the most widely used method.

Mercury Pump

Pycnometer

Microsol (Geoservices)

The principle behind this method involves comparing the weight of the cuttings in air and in water. Shale density is obtained by the formula:

ρb = L1 / (L1-L2)

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Shale Factor The shale factor technique is a method of measuring the cation exchange capability (C.E.C.) of the shale cuttings. Montmorillonite clay possesses a greater degree of cation exchange capability than illite clay; the measurement is based on the milliliters of methylene blue that is absorbed per gram of crushed shale sample. The theory behind this technique recognizes that montmorillonite clay disappears with depth as it diagenetically alters to illite and mixed layer clays; hence shale factor (expressed in ml/gm) should decrease with depth. Ideally, zones of shale overpressure contain greater-than-normal amounts of montmorillonite, the montmorillonite either having been delayed or only now in the process of being altered to illite; during this diagenesis, huge volumes of oriented, inter-particle water are released, thereby being a source of pressure generation. Hence a trend of increasing shale factor versus depth indicates overpressure development; this conclusion is usually corroborated by a trend of decreasing shale density.

In some marine basins like Australia’s Bass Strait, shale factor and shale densities are major overpressure detection techniques.

Shale factor is not a reliable technique for detecting abnormal pressures, and cannot on its own lead to the conclusion that they are present. It may however provide confirmation and assist interpretation. The results may also contribute to the recognition of lithological markers.

Flowline Temperature

Introduction Flowline temperature is a qualitative, lagged overpressure detection technique, utilizing trends and changes in the flowline temperature of drilling fluids. The theory behind its use lies in the fact that overpressured formations, possessing greater-than-normal quantities of pore fluid, act as thermal insulators to the natural flow of heat from the earth’s core. Ideally, then, an overpressured zone should be detected in a rise in flowline temperature above what is normal. In actual use, the flowline temperature is subject to numerous variables which include such things as:

• Lithology

• Formation thickness

• Circulation rate

• Circulating while drilling as opposed to conditioning mud

• Ambient and diurnal temperature

• Addition of new mud/dilutions

• Length of marine riser, etc.

Due to the influence of these many variables, good use of the flowline temperature as an overpressure detection tool demands attention and interpretation; the technique has usually had very limited success, esp. for offshore locations.

Geothermal Concepts The geothermal gradient is the rate at which formation temperature increases with depth. It is calculated as follows:

Gt = 100 x ((T2 – T1)/(Z2 – Z1)

Where,

Gt = geothermal gradient. DegC/100m

T1 = temperature (degC) at depth Z1 (m)

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• The bottomhole temperature

The thermal profile is not very sensitive to local variations in geothermal gradient or ROP.

Below is a table that compares the temperatures measured at the surface with those measured with the wireline logs.

Depths (m) Hole Diam (in)

Flow Rate (l/min)

Pump Press. (bar)

Wireline Log Temp, deg C

Mud Temp Out, deg C

900 17 3/8 3700 95 35 37

2582 12.25 2200 165 71 56

4625 8.5 1700 130 126 60

4850 5.75 650 135 150 46

5048 5.75 650 135 165 40

At the top part of the well the mud temperature out sensor recorded a higher temperature than that of the wireline log. A reduction in flow from 1700 l/min to 650 l/min produces a fall of 14 deg C in the temperature out reading. M.W.D. tests have shown that a reduction in flow may in fact be accompanied by an appreciable fall in bottomhole temperature while drilling.

There are rare cases where mud temperature out has actually been used to detect undercompacted zones. This is because many factors mask the temperature changes. These factors are:

1. Offshore drilling: the marine riser assists heat exchange between the mud and the surrounding sea. The amount of cooling depends on the length and size of the riser.

2. Drilling and circulating halts: these cause cooling of the mud in the circulating pits and in the upper part of the hole. The length of the halt determines the amount of cooling. Trend to trend plotting of mud temperature out will remove irrelevant scatter and takes account of stabilized temperatures only.

3. Surface operations: transfers of mud between active pits and reserve pits disturb the mud temperature in.

4. Climatic changes: in the case of an onshore well, exposure of the pits to the open air can result in significant mud temperature in variations due to the ambient conditions (sun, snow etc.)

5. String rotating speed: rotation of the string is transmitted to the mud and has an appreciable effect on thermal transfers at the borehole walls.

6. Lithology: in order to keep lithological effects to a minimum, preference must be given to temperatures relating to shales.

7. Fluid kick: an influx of formation fluid will bring about an increase in mud temperature out commensurate with its volume.

8. Influx or diffusion of gas: increase of gas near the surface will bring a reduction in temperature due to endothermic expansion.

9. Mud type: heat exchange between the formation and the mud will depend on the conductivity of the mud. Internal heating of the mud will depend on its specific heat.

10. Measurement quality: it may be affected by the position of the sensor, the mud level, and turbulence and settling of cuttings around the sensor.

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Bottomhole Measurements during Formation Testing Temperature measurements of fluid produced in the course of formation testing are more representative of formation temperature. Two types of measurement may be performed:

• A maximum thermometer of the type used in wireline logging is placed in the mechanical pressure recorders

• Continuous thermometry in association with electronic pressure recorders

Such measurement s are not performed regularly and it is not common for them to be made at several depths within a given well.

Bottomhole “Temp Plates” Measurements

Thermometry A continuous profile of the change in temperature of the mud column in a well can be obtained with thermometric logging tools (HRT, etc). these are generally used in either geothermal wells or in oil drilling to detect mud-loss zones or the top of the cement behind the casing.

The measured values are not representative of either formation temperatures or changes in the gradient, because mud temperatures are not stabilized in relation to the true formation temperature.

Conclusion Although undercompacted zones are accompanied by temperature anomalies, it is not easy to detect these using available methods for measuring mud temperature, These methods depend on a number of variables which frequently mask changes in geothermal gradient.

Bottomhole temperature measurements during logging , which have the disadvantage of being performed subsequently and in isolation, nevertheless provide a better estimate of true formation temperature. However, the quality of the measurement depends on the time elapsed since drilling ceased.

Mud Density With modern methods for measuring mud weight, particularly gamma ray density, mud weights in and out can be monitored continuously and accurately.

A decrease in mud weight out (for a constant mud weight in) may be due to the following:

• Expansion of gas released by drilling of the formation as it reaches the surface

• A kick of hydrocarbons or water (spontaneously or as a result of swabbing)

• Gas diffusion (if ∆P is negative)

• A bubble of air (after tripping or connection)

Most reductions in mud weight are due to gas released while drilling.

The volume of gas released at the bottom of the hole while drilling can be calculated using the following formula:

Vg = (1.27 x D)2 x π x (R/600) x φ x Sg

Where,

Vg = volume of gas released into the mud per minute (l/min)

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Dr = 1.3 x (2400/(2400 + 3560)

Dr = 0.52

Find: the bottomhole equivalent density

∆P = ((1.3 – 0.52)/0.52) x ln(455 + 1.02) = 9.19 kg/cm2

Deqv = ((455-9.19)/3500) x 10 = 1.27

Cuttings / Cavings Wellsite geologists generally regard large cuttings as being cavings. But in sections of negative ∆P large cuttings may also be produced and be confused as cavings. A concomitant disappearance or sharp reduction in very fine cuttings can generally be used to decide the matter.

An increase in the volume and size of cavings implies instability of the borehole walls (thermal or mechanical imbalance when drilling).

The problem is mainly associated with argillaceous rocks, although all other formations may also be affected provided that they are located at sufficient depth.

High formation pressures contribute to destabilization of the borehole walls in two essential ways. On one hand, they reduce the strength of the rock, while on the other hand they can cause circular concentric tension fractures in low permeability formations such as shales.

The cavings observed at the shakers have two essential shapes (see Elf p. 157). The first is a flattened, elongated flake, frequently confused at first sight with the cleavage of laminated shale. It has a concave cross-section. The second shape is blockier, often with microfissures.

Laboratory tests have demonstrated that the fracture mechanism due to excessive compression can produce both types of cavings at the same time or in succession.

Plate-shaped cavings are therefore not a definite indication of overpressure, since stress effects in normally compacted rocks can also produce them.

Cuttings Gas Cuttings gas is gas produced by breaking a certain volume of cuttings in a blender.

Cuttings incorporate a microporous system containing formation fluid that is not polluted by the mud because of capillarity and adsorption forces. The non-polluted volume depends on the permeability of the rock. Shales retain a large proportion of their fluid content right up to the surface.

It is hoped that the frequently noted increase in gas content in undercompacted shales will be better detected by using cuttings gas. Similarly changes in the composition of gas indicators that frequently occur in transition zones may provide a means for the detection of abnormal pressure.

Conclusion There are many methods for the detection of abnormally pressured zones while drilling, and they vary considerably in effectiveness. Below is a table of methods used classified on their corresponding degree of reliability.

Detection Reliability Real-time Methods Lag-time Methods

RELIABLE Drilling Rate

Dxc (without wear factor)

Normalized ROP

Gas – Connection Gas

Gas – Background Gas

Gas – Reservoir Gas

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p = S - (σ x (Ro/Rn)1.2)

p = S - (σ x (Cn/Co)1.2)

p = S - (σ x (∆tn/∆to)3.0)

Where, p = pore pressure psi/ft

S = overburden pressure, psi/ft

σ = normal matrix stress pressure, psi/ft (S-pn)

R = resistivity

C = conductivity

∆t = interval transit time

o = observed

n = normal

Once the E-log data is plotted, a comparison can be made between the seismic, drilling and well logging data in order to interpret, predict, identify and evaluate any abnormal formation pore pressures.

Direct Pressure Measuring Tests Actual bottom hole pressure measurements are really the only true quantitative tools for overpressure detection and evaluation. Measurements of actual bottom hole pressure are essential for scaling the pre-spud and during drilling indicators. These tests are essential to verify the data from other indicators.

Direct pressure measuring tests include:

• Kicks

• Formation Interval Tests

• Repeat Formation Tests

• DST

• Production Tests

Kicks are the least desirable of the pressure measurements. They are the most potentially dangerous and expensive of the various pressure measuring tests. However, if quickly and properly controlled, the data provided by a kick can be free and very informative.

FITs and RFTs are wireline formation tests. The FIT can collect only one sample whereas the RFT can make numerous measurements of formation pressure at various intervals. These are probably the cheapest and least hazardous means of obtaining formation pressures.

DSTs are probably the most difficult bottom hole pressure measuring tests to, not only run, but also to interpret. In a DST, drill pipe is run to the zone of interest and a packer is set above the zone in order to seal off the zone of interest. A pressure differential is placed on the formation by lowering the mud hydrostatic using air, oil or a water “cushion”. Influx of formation fluid at bottom hole pressure occurs, and this is collected and measured at the surface.

Production tests are a final method for actual measurement of bottom hole pressure. These tests are expensive and seldom utilized except to accurately evaluate reservoir characteristics for possible production.

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Quantitative Pressure Evaluation

Introduction The only detection methods that can be used to evaluate pressure quantitatively are:

1. Formation Tests, which give a direct measurement of the pressure

2. Seismic interval velocities

3. Dxc, Sigmalog, Normalized ROP

4. Shale Density

5. Gas Shows

6. Kicks/Mud Losses: Mud Flow Measurements, Pit Levels

7. Wireline Logs: Resistivity/conductivity, Sonic, Density

Most methods of evaluation are based on the principle of comparing the undercompacted clays with a normal compaction state, which means that a normal compaction trend must be established.

Equivalent Depth Method

Applications This method is applied to the following:

• Interval velocities

• Dxc

• Shale Density

• Resistivity/Conductivity

• Sonic

• Density Log

• Any direct or indirect measurements of clay porosity

Principle The principle is that every point A in an undercompacted clay is associated with a normally compacted point B. The compaction at point A is identical at point B.

Log φ

ZA

Depth

A

B ZB

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Using this formula in the previous example we get an answer of 1.41

Establishing Isodensity Lines

Z Y

X

A

B ZB

ZA

Depth

1. Extend the normal compaction trend XY to the depth origin X

2. Choose a point B located on the normal compaction trend line

3. For a selected value of Deqla calculate depth A using the following formula derived from:

ZA = 1,26ZB / (2.31 – DeqlaA)

4. Position point A on the vertical from B, then draw a straight line XZ passing through A

The equivalent depth method may be used regardless of whether the porosity parameter concerned is represented arithmetically or logarithmically.

Ratio Method

Applications This method could be applied to the following methods:

• Dxc

• Shale Density

• Sonic Log

• Resistivity/Conductivity Log

• Density Log

Principle The difference between observed values for the compaction parameter and the normal parameter extrapolated to the same depth is proportional to the increase in pressure.

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measurement data (obtained from RFT and Tests) can appreciably improve the results of the method. A correction coefficient (c) could be added:

Deql = c x Deqln x (Dxcn / Dxco)

Example:

Calculated Deql = 1.25

RFT Deql = 1.35

C = 1.35/1,25 = 1.08

This correction coefficient remains applicable as long as the origin and the causes maintaining the abnormal pressure remain constant for the unit in question.

Eaton Method

Application The Eaton Method could be applied to the following methods:

• Interval Velocities

• Dxc

• Resisitivity/Conductivity Log

• Sonic log

It may also be extended to:

• Shale Density

• Density Log

Principle The relationship between the observed parameter/normal parameter ratio and the formation pressure depends on changes in the overburden gradient.

These are the following formula:

Resistivity:

P = OBG – (OBG – Pn)(Rsh obs – Rsh normal)1.2

Conductivity:

P = OBG – (OBG – Pn)(C normal – C obs)1.2

Dxc:

P = OBG – (OBG – Pn)(Dxc obs – Dxc normal)1.2

∆t sonic:

P = OBG – (OBG – Pn)(∆t normal - ∆t obs)3

Where,

OBG = overburden gradient (psi/ft)

Pn = normal pore pressure gradient (psi/ft)

Rsh = Shale resistivity

Example: (resistivity)

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Sigmalog Evaluation

Normalized ROP Evaluation (Prentice)

Evaluation By Direct Observation Of The Differential Pressure Direct observation of factors associated with well equilibrium may provide more accurate and reliable information, and is generally the only means of detecting overpressure not directly associated with undercompaction.

Gas The usefulness of gas shows in qualitative evaluation is described in the section on Gas above. As long as mud weight is close to the equilibrium density, it is possible to monitor background gas, connection gas and the effect of mud weight adjustments on gas shows, so as to achieve satisfactory and continuous evaluation of formation pressure.

Mud Losses Lost circulation may arise for the following two reasons:

• Excessive filtration of mud into a very permeable formation subjected to high differential pressure

• Fracturing of weak horizons (or opening of pre-existing fractures) caused by excessive ∆P

Losses may occur while drilling or be caused by excessive pressure loss due to surging while tripping.

Observing the losses that occur while circulation is in progress, with the well stable under static conditions, provides an accurate picture of well equilibrium. Well balance depends as much on the ∆P as on the fracture pressure.

It is only safe to use to use formation pressure data inferred from a mud loss if the location of the zone concerned is accurately known. The loss rate depends not only on the ∆P but above all on the porosity and permeability of the loss zone, or the nature of the fracture system.

Kick A kick indicates that formation pressure is greater than the mud weight. Only bottomhole kicks should be taken into account for formation pressure evaluation. Kicks due to gas expansion at the surface are not a direct indication of bottomhole formation pressure.

The kick flow depends on ∆P, the porosity and permeability of the formation.

If a kick occurs it is necessary to shut-in the well, formation pressure can be deduced from the shut-in drill pipe pressure:

P = (MW x Depth x 0.0519) + SIDPP

Formation Tests

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Fracture Gradient

The Overburden Relationship Each of the fracture gradient prediction formulae is based on three variables in order to quantify the fracture pressure. These variables are:

• Overburden pressure

• Pore pressure

• Horizontal matrix stress

The overburden is supported by the rock grains, crystals and matrix and particularly by the fluid contained in the pore spaces between the matrix. The downward stress or overburden stress, S, is exactly balanced by the sum total of an upward matrix stress, σ, and an upward pore pressure, p, as so expressed:

S = σ + p

States of Stress Underground The stress field may be described as three mutually perpendicular stresses, each normally of a different value. If we consider these stresses to be all compressive (likewise we could consider all to be tensional) the stress field might look something like this:

σ2

σ1

σ3

Conventional with rock mechanics, the greatest stress is designated σ1, the intermediate stress, σ2, and the least stress σ3. These stress fields are always assumed to have one principle stress axis vertical and perpendicular to the earth’s surface.

As some critical relationship in the values of σ1 and σ3 is approached and then satisfied, rupture occurs resulting in a fault plane perpendicular to the σ1σ3 plane and at some angle to the least stress axis σ3. For most sandstones, shales and limestones the angle averages 60 deg.

In regions characterized by normal faulting the greatest stress axis σ1 is essentially vertical and equal to the overburden stress, and the least stress axis σ3 is horizontal.

Areas characterized by mountain building, folds and thrust faults (faults dipping at 30 deg from the horizontal); areas in which active horizontal compression of rock has and more than likely is still taking place) possess a stress field in which case σ1 is horizontal and σ3 is vertical. For this situation the overburden stress is essentially vertical and equal to the least stress σ3.

Deformation is dependent on some critical relationship between the greatest stress, σ1, and the least stress, σ3.

In the case of the borehole it has been recognised by most authorities that the formation cannot withstand a tensile stress which causes the formation to fail when the least effective stress is reduced to zero. Such a tensile stress may be exerted by the mud hydrostatic which, when equal

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Terzaghi also recognized that the additional tectonic stresses are often superimposed upon the effective horizontal stresses, such that σx may be greater than σy (or vice versa)

σx = (v/(1-v)) x σz + Tx where

Tx = tectonic stress in the x horizontal direction

Terzaghi’s findings were that the usual range in values for v was 0.25 to 0.30. However, subsequent studies, notably by Heim at the beginning of the century, showed that at depth σz=σx=σy such that Poisson’s ratio, v, may have an upper limit of 0.50.

Biot’s studies on rock deformation led him to propose the following expression for fracture pressure:

Pf = (2v/(1-v)) x S + (α x ((1-3v)/(1-v)) x P), where

α = a porosity factor where α = 1 – (Cr/Cb) where Cr = compressibility of the solid rock and Cb = compressibility of the porous rock skeleton.

Biot’s relationship is such that when there exists no porosity, Cr = Cb and the pore pressure term disappears.

The Relationship Between σ1 and σ3 F = kσ + p where,

K = some fraction of the matrix stress

In essence this formula states that to induce a fracture a pressure equal to the pore pressure and some portion of the matrix stress must be applied.

Formation Fracture Gradient Prediction Formulas

Hubbert And Willis They stated that for areas characterized by normal faulting the least stress, σ3, is horizontal and fractures will be induced when the value of this is approximately 1/3 the overburden pressure, i.e., if the vertical stress σv = S – p then the horizontal stress σh = (S - p) / 3. σ3 is based on empirical results of laboratory triaxial compression tests on rock cores. Furthermore, they premise that the pore pressure has no significant effect on the mechanical properties of the rock. To fracture the formation a pressure Pfrac equal to the pore pressure plus a pressure equal to the horizontal stress must be applied:

Pfrac = p + (S – p)/3

Therefore, Pfrac = (S + 2p)/3 ,where

Pfrac = fracture pressure gradient, psi/ft

P = pore pressure gradient, psi/ft

S = overburden gradient, 1.0 psi/ft

This fracture formula assumes:

1. A constant Poisson’s ratio of 0.25

2. A constant overburden gradient of 1.0 psi/ft

Subsequently, Hubert and Willis postulated a larger range for values of Poisson’s ratio, from 0.25 to 0.50 (similar to Heim and Biot) such that their expression for fracture pressure gradient may be given as:

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Christman Christman recognized a modification of Eaton’s formula for application on offshore drilling. Basically, the effect of increasing water depth is to lower the total overburden gradient. His expression for fracture gradient is:

Pf = Kσ + p

His expression and findings recognized a variable stress ratio and a variable overburden gradient that considered not only the water depth but also the air gap. Furthermore, he showed there to be a direct relationship between rock bulk density and stress ratio.

Anderson, Ingram And Zanier They recognized that large variations in fracture pressure gradients existed at the same depths within the same geological area. They attempted to explain these variations by attempting to establish that Poisson’s ratio has a strong influence on fracture pressures. Using both Terzaghi’s model of effective stress and Biot’s stress-strain relationship, they showed that Poisson’s ratio was very sensitive to changes in shale content.

Shale content can be measured from conventional sonic and density logs. They termed this shale content the shale index:

Ish = (σs - σd) / σs where,

Ish = shale index

σs = porosity from sonic logs

σd = porosity from density logs

This shale index could then be used to calculate Poisson’s ratio:

V = Aish + B where,

A and B are constants of a linear slope.

Alternatively, they advocate calculation of Poisson’s ratio using Biot’s relationship:

v = (Pf - αp) / (Pf + 2S -3αp) where,

Pf = fracture pressure

p = pore pressure

S = overburden pressure

α = porosity factor, estimated by α = 1-(1-φp)

Daines Daines reiterated much of the work Terzaghi, Hubert and Willis, Matthews and Kelly, etc., but re-emphasized Terzaghi’s notion of additional tectonic stresses superimposed upon the local effective stresses. He utilizes the following fracture pressure expression:

F = σt + σ1’ x (v/(1-v)) + p where,

F = fracture pressure

σt = superimposed tectonic stress

σ1’ = effective vertical stress = σ - p

Below is a tabulation of Poisson ratios to be used for a lithology:

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AGIP Giacca et al recognized that fracture pressure gradients are influenced by rock deformational characteristics. They recognized the following relationship for elastic formations:

F = (2µ/(1-µ)) x σ + p where,

F = fracture pressure

µ = Poisson’s ratio

For elastic formations susceptible to fluid invasion they recognized:

F = (2µ) x σ + p

Finally for plastic formations such as shales, marls and salts

F = S

For most circumstances, Agip utilizes the first equation only and usually with µ = 0.25 because this work is based on Terzaghi, the conceivable range of Poisson’s ratio is 0.20 to 0.30.

It should be noted that the Agip fracture pressure expression for plastic formations (F = S) has not been corroborated by most field data.

Pilkington Pilkington utilizes a method essentially similar to Eaton’s but differing from Eaton’s in that it does not require actual leak-off data to predict fracture gradients. It utilizes an effective stress ratio K that is calculated using the Brister equations. The Brister equations yield a value of K that is derived from a best fit to the average effective stress ratio curves for US Gulf Coast data. These are follows:

K = 3.9 (S/D) – 2.88 for S/D < 0.94

K = 3.2 (S/D) – 2.224 for S/D > 0.94

Pilkington claims that the calculated K is valid for both normally and abnormally pressured formations in tectonically relaxed basins, and is not valid for carbonates and brittle or naturally fractured formations.

Breckels And Van Eckelen They derived a relationship between horizontal in situ stress and depth and pore pressure. The results of their studies indicate that for most basins that are similar to the US Gulf Coast, the Gulf Coast curve of horizontal stress vs depth will yield very acceptable data.

Their equation for calculation of fracture pressure as a function of depth and pore pressure is:

Shmin = 0.197D1.145 + 0.46(Pc-Pcn) for D < 11500 ft

Shmin = 1.167D – 4596 + 0.46(Pc-Pcn) for D > 11500 ft

Perhaps one of the most significant conclusions of these authors is that there exists a relationship between horizontal stress and pore pressure, ie as pore pressure increases then so does the horizontal stress.

Bryant Bryant’s method employs a variation of the Matthews and Kelly method using variable overburden.

F = kσ + p

The effective stress ratio K is determined by two differing means:

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Basic Well Control

Shut-in Procedures

Introduction There are two primary objectives in any well control operation. These objectives are:

1. To kill the well safely.

2. To minimize borehole stresses.

Shut-in Procedures Once a kick has been detected, minimizing the amount of influx of formation fluids is the next important consideration because a smaller influx simplifies any problems that may occur during well control operation.

The most common instances, which may require a well to be shut-in, are while drilling ahead or while drill pipe is being tripped.

When the well is shut-in, the formation pressure is balanced and the possibility of heaving shale is reduced. Shutting in a well rather than leaving it open can cause additional stuck pipe problems only when lost returns occur. Of course, when lost returns occur during well control operations, the stuck pipe becomes the least of the concerns.

Drilling Ahead – Surface BOP Stack In Use The shut-in procedure is:

1. When a kick is detected or suspected, raise the kelly immediately until the uppermost tool joint in the drillstring is above the rotary table.

2. Shut down the rig pumps.

3. Check for flow.

4. Close the annular preventer.

5. Notify the operator personnel.

6. Read and record the shut-in pressures and the amount of pit gain.

There is considerable controversy in the industry about whether the choke lines should or should not be opened prior to closing the annular preventer.

Some operators use the soft shut-in procedure. They prefer to check for flow, open the HCR (high closing ratio), open choke and choke lines, close the preventers and then pinch the flow-off by closing the choke. This they believe has two advantages:

1. It cleans out the lines that will be used later in the well control operation.

2. It also tends to prevent a “water hammer” effect from occurring that can cause formation breakdown.

The disadvantage of the soft shut-in is that additional formation fluids enter the wellbore while the valves are being opened and the annular preventer is being closed.

The other shut-in procedure is called the hard shut-in. This procedure assumes that the HCR valve is closed and that the choke is in the closed position. The HCR valve and choke lines are left closed and the annular preventer is closed without opening the lines first.

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2. Install a full opening, fully opened drill pipe safety valve on the drill pipe and make it up properly.

3. Close the drill pipe safety valve.

4. Close the annular preventor.

5. Notify appropriate supervisory personnel.

6. Make hang-off decision.

7. Pick up the kelly and make it up on the drill string.

8. Open the safety valve.

9. Read and record the pressures. Note the amount of pit gain.

Exercises

Basic Well Control Theory In order to kill a well, the bottom hole pressure must be maintained constant at a level greater than or equal to the formation pressure.

Well control is based on both sides of the U-tube being balanced:

BHP = 5200 PSI

BOTH 0 PSI

ANNULUS SIDE

DRILL PIPE SIDE

From the diagram above assume that both sides are filled with 10 ppg mud and that the system is closed. The BHP is equal to the sum of the hydrostatic pressure exerted by the mud (5200 psi at 10000 ft) plus any pressures imposed at the surface (0 psi). Both sides of this system exert the same hydrostatic pressure; both sides have 0 psi imposed surface pressure, so the system is balanced and is in equilibrium.

Examples Example 1:

Assume the following conditions:

1. The U-tube is closed on both sides

2. The drill pipe is filled with 10 ppg mud.

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We want BHP dp side = BHP annulus side = FP

The total system pressure loss was measured as being 2500 psi prior to the kick. Of this 2400 psi was lost as a result of mud friction in the surface equipment, drill pipe and bit. 100 psi was lost in the annulus. The annulus pressure loss exerts an additional 100 psi on bottom as a result of circulating friction in the annulus. The annulus pressure loss plus the choke pressure loss plus the hydrostatic pressure of the mud and gas on the annulus side are equal to the BHP exerted on the annulus side

BHP annulus side = Hpmud + Hpgas + Choke Pressure + Annulus Pressure Loss

Hpmud = 10 x .052 x 7000’ = 3640 psi

Hpgas = 0 psi

Annulus Pressure Loss = 100 psi

BHP = FP = 5700 psi

5700 = 3640 + 0 + Choke Pressure + 100

Choke Pressure = 5700 – 3640 – 100 = 1960 psi

A choke pressure of 1960 psi will balance the annulus side with the formation presure.

BHP = FP = SIDPP + HP10ppg at 10000 ft

HP10ppg at 10000 ft = 5200 psi

SIDPP = 5700 – 5200 = 500 psi

500 psi must be exerted at the surface from the drill pipe side before any movement can take place. We already know that an additional 2500 psi of pressure will be required because of friction to pump the mud at our desired pump rate. Therefore, a pump pressure reading of 3000 psi will be indicated when the pump is brought up to the necessary circulating rate.

Summary In a closed U-tube system, a balance between the two sides of the U-tube is automatically established. The surface indicated pressures would automatically be those necessary to maintain balance in the closed system. The imposition of additional pressure anywhere in a closed, balanced U-tube system will result in that additional imposed pressure being felt equally at all points in the U-tube system.

The drillpipe side of the U-tube is normally uncontaminated with formation fluid, so the hydrostatic pressure exerted by the mud in the drill pipe is effective over the total vertical depth and this pressure is known. The system pressure loss is known by prior measurement. The SIDPP is known also. This means that the BHP on the drill pipe side is also known. If we pump at a constant rate and restrict the choke openings correctly, we can calculate the BHP on the drill pipe side. Since the system is balanced, we can hold the BHP on the drill pipe side equal to the FP. The annulus side will also be balanced relative to the FP since the drill pipe side and the annulus sides are balanced relative to each other. Thus we can hold the BHP constant by manipulating the drill pipe pressure. Given the system pressure loss, hydrostatic pressure of the mud in the drill pipe, and the SIDPP, we can compute the formation pressure and the necessary drill pipe pressure at all times.

The annulus side of the U is frequently contaminated with an unknown weight and the volume of formation influx. Due to this, the casing pressure cannot generally be used to compute BHP, but any change in the casing pressure will result in a like change in drill pipe pressure. The system is balanced and closed, so any change in the imposed pressure at the choke will be felt equally at all points in the system. Thus it is possible to hold BHP constant at the desired level. This the underlying principle of well control.

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Pressure recorded on the casing or drill pipe side that is in excess of the pressure initially required to balance the FP is called trapped pressure. Trapped pressure can result from either closing the well in without completely shutting down the pumps or gas migration. Trapped pressures will cause all kick calculations to be incorrect.

A recommended procedure for checking rapped pressure is as follows:

Bleed small amounts (less than 1 bbl) on the casing side and then shut-in the well. If the drill pipe pressure continues to decrease each time mud is bled from through the choke, keep repeating the bleeding and shut-in sequence.

If the SIDPP remains the same following two successive bleed-offs, use this figure as the true SIDPP. Continued bleeding will only allow more influx to occur.

Bleed from the casing side only in small amounts (1/4 to ½ bbl, if possible). Bleeding large amounts of mud may allow additional influx of formation fluids to occur.

There are instances when a float valve is installed in the drill string. When a float valve is present it naturally prevents the kick pressure from being recorded on the drill pipe. The SIDPP can be found out by either of the two methods.

Method 1: The kill rate pressure is known:

1. Shut-in the well, record the SICP and obtain the pre-recorded kill rate from the IADC.

2. Hold the casing pressure constant with the choke and bring the pump to the kill rate.

3. Note the circulating pressure obtained with the pump at the kill rate.

4. Shut down the pump and close the choke. The circulating pressure obtained with the pump at the kill rate minus the prerecorded circulating pressure at the same pump rate is the SIDPP.

Method 2: The kill rate is unknown:

1. Shut-in the well and line up a low volume-high pressure pump on the standpipe (cementing pump)

2. Start the pump and fill up all the lines with mud. Any air left in the lines will cause false pressure readings.

3. Increase the pressure on the pump. Note the pressure obtained when the fluid first begins to move. Fluid is incompressible, so no movement can take place until the pressure exerted on the bottom side of the float valve is overcome.

4. The pressure obtained when the fluid first begins to move is the SIDPP.

Identification of Influx The influx may either be gas, oil, water or a combination of the three. The calculation is an approximation at best because the hole may not be gauge and the pit gain may not be necessarily accurately noted.

The formula for determining the gradient of the influx fluid is:

Influx gradient = Mud gradient in DP– ((SICP-SIDPP)/Height of influx)

Height of influx = bbls gained / annulus volume, bbls/ft

Influx density (ppg) = Influx gradient / 0.52

As a general rule, an influx with an equivalent mud weight of 1 to 3 ppg is assumed to be gas, 3 to 5 ppg is assumed to be a mixture of gas and water or gas and oil, and 5 to 7 ppg is assumed to be either oil, water or an oil-water mixture.

Example:

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Driller’s Method – After the well is shut-in and the readings are recorded, pumping is begun immediately. The influx is pumped from the wellbore without any prior weighting up of the mud. Once the influx has been pumped from the well, the well is shut-in, and the surface mud system is weighted up to the kill mud weight. The kill mud then displaces the lighter mud. This method is sometimes called the Two Circulation Method.

Concurrent Method – After the well is shut-in, pumping is begun immediately and the mud weight is raised while the kick is being circulated out. The use of this method may require several circulations before the well is fully killed. This method is also called the Circulate and Weight Method.

Wait And Weight Method

Introduction In this method, kill mud is immediately pumped down the drill pipe. This raises the hydrostatic pressure exerted by the mud in the drill pipe, so the drill pipe pressure must be allowed to decrease as the kill mud makes its way to the bit. When the kill mud reaches the bit, the hydrostatic pressure exerted by the mud in the drill pipe is equal to or greater than the formation pressure. The well is now dead on the drill pipe side, and the SIDPP will be 0 at this point. When the pump is restarted and brought up to the kill rate once again, the drill pipe pressure will now be equal to the circulating pressure required to move the mud at this rate. Since no additional changes will be made to the mud on the drill pipe side, the drill pipe pressure and the pump rate should be held constant while the annulus is displaced will the kill mud. When the kill mud reaches the surface the well should be dead (i.e., no shut-in pressures and no flow with the pumps off.).

In order to keep track of the various procedures and pressures that need to be used to kill the well, a worksheet is usually filled out after the well has been shut-in and the various readings have been recorded. The worksheet or kill sheet shows the pressures required vs. the amount of mud pumped. The heart of the kill sheet is a schedule of drill pipe pressure vs. strokes (amount of mud pumped).

Procedure For Wait and Weight Method The following steps should be followed:

1. Shut-in well using preferred shut-in procedure.

2. Record the SIDPP, SICP and the amount of pit gain. Check for trapped pressure.

3. Compute the Kill MW and weight up the surface mud system to the kill MW. Fill out the kill sheet while the mud is being weighted up.

4. Hold the casing pressure constant by manipulating the choke and bring the mud pump up to the pre-recorded kill rate. Once the pumps at the kill rate, ascertain that the drill pipe pressure is equal to the sum of the SIDPP and the pre-recorded circulating pressure at the kill rate.

5. Follow the drill pipe pressure schedule while displacing the drill pipe with kill mud.

6. Once the drill pipe is filled up with kill mud, the well may be shut-in. The SIDPP should be 0 at this point. This step is optional and is simply a check to make certain that the kill mud weight mud calculation is correct.

7. If step 6 has been followed, hold the casing pressure constant by manipulating the choke and bring the pump up to the kill rate once more. Be certain the drill pipe pressure is equal to the FCP.

8. Hold the drill pipe pressure constant (while circulating at the kill rate) at the FCP until the kill mud reaches the surface.

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Strokes Pumped Drill Pipe Pressure

0 1500 psi

100 1420 psi

200 1340 psi

300 1260 psi

400 1180 psi

500 1100 psi

This method eliminates any errors that may occur as a result of reading drill pipe pressures from a graph incorrectly.

Exercises

Driller’s Method This method requires fewer calculations than the Wait and Weight method.

The procedure is:

1. Shut-in well using the preferred shut-in method.

2. Record the SIDPP, SICP and the amount of pit gain. Be sure to check for trapped pressure.

3. Compute the mud weight to kill the well.

4. Hold the choke pressure constant by manipulating the choke and bring the pumps to the kill rate.

5. Hold the drill pipe pressure steady at the ICP (SIDPP + kill rate pressure) by manipulating the choke and pump at the kill rate until the influx is out of the hole.

6. Shut-in the well and raise the mud weight in the pits to the kill mud weight.

7. Hold the casing pressure constant and bring the pumps up to the kill rate.

8. While pumping at the kill rate, hold the casing pressure steady by manipulating the choke and displace the mud in the drill pipe with the kill mud.

9. Once the drill pipe is filled with kill mud, observe the FCP on the drill pipe gauge.

10. Keep pumping at the kill rate and hold the drill pipe pressure constant at the observed FCP by manipulating the choke until the kill mud is at the surface.

11. When the kill mud is at the surface, shut down the pump, close the choke, and verify if the SIDPP and the SICP are both 0. If so, open the choke to be sure the well does not flow. If no flow is observed, open the preventers and check again to be sure if the well is dead.

The drill pipe pressure chart could be eliminated when this method is used.

Concurrent Method

Introduction It is a method used when it is desirable to begin circulating quickly with an immediate mud weight increase. An increase in the surface mud density requires some time, and if gas migration or hole troubles are anticipated as a result of this time lag, the Concurrent Method may be used to kill the well.

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Increase in the pit level

Increase in the mud return flow rate

The roll and heave of a mobile drilling vessel causes the pit level to fluctuate, even though the amount of mud in the pits may be constant. A real increase in pit level may manifest itself only after a large gain has occurred. The heave of the vessel also results in constant changes in the flowline height relative to the ocean floor. Mud exits the well at varying rates, which makes flowline-monitoring devices of limited value.

Hanging-off Once a kick is detected the well needs to be shut-in. Hanging-off may be necessary to prevent damage to the drillstring or a stationary preventer. Hanging-off may not be necessary or desirable in every instance, but it should be used if any of the following conditions develop or are anticipated:

Bad weather

Motion compensation failure

Moving off location

Subsea BOP’s Two choke lines and additional preventers are generally included to serve as backups in case of component failure on a subsea stack. Two annular preventers, several sets of rams are included. The bottom set of pipe rams is generally placed below the choke lines. This allows the well to be shut-in if repairs need to be made to any of the BOP components or choke lines. The shear rams are also generally located below the choke lines so that the drill string can be severed, and the rig moved off quickly if an impending blowout occurs.

Choke Line Pressure Loss Choke lines generally run from the ocean floor to the surface when a subsea stack is in use. These choke lines have relatively small Ids, and in deepwater applications where long choke lines are in use, considerable pressure loss resulting from the mudflow through the choke line can develop. The pressure loss in the choke line results in additional bottom hole pressure. If the BHP is to be held constant at a known value, the amount of pressure loss in the choke lines must be known.

The slow pump rate must be taken through both the riser (preventers open, choke closed) and through the choke line with a preventer closed. If the readings are taken at the same pump rate and mud properties, the difference in the two readings will be equal to the pressure loss in the choke lines.

If the choke line pressure loss is of concern prior to the time a kick occurs, the pump rate should be slowed down enough to hold this pressure loss to a minimum. It may be necessary to obtain reduced circulating pressures with a cement pump or other high pressure-low volume pump.

The choke line pressure loss may be approximated by using the following formula:

CLPL = (0.000077 x MW0.8 x OP1.8 x PV0.2 x L)/choke line id4.8 where,

CLPL = Choke Line Pressure Loss, psi

MW = MW, ppg

OP = Pump Output, gpm

PV = Plastic Viscosity of mud, cp

L = length of choke line, ft

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5. Bring the pump up to speed. Regulate the casing pressure as the pump is brought up to speed. Once the pump is at the desired kill rate, “fine tune” the choke opening until the drill pipe gauge indicates the proper value.

6. Kill the well by following the appropriate pressure schedule and kill procedure.

7. Once the kill mud reaches the surface, shut down the pump, close the choke, and verify that the well is dead. Open the choke and check for flow through the choke line.

8. Since the preventers are located on the ocean floor, the riser is still full of the original mud. This light mud must be displaced prior to opening the preventer stack. To do this, close the bottom set of pipe rams and circulate kill mud down the choke line. Continue this reverse circulation procedure until the riser has been displaced with kill mud. The rams can then be opened without the danger of allowing additional influx to enter the wellbore.

Other Considerations In Deepwater Drilling The reasons that early kick detection are especially important on a floating vessel are as follows:

1. The fracture gradients in deep water are relatively low. The fracture gradients are low because the fracture gradient of a formation is directly related to the overburden stresses applied to it. A larger overburden generally implies a higher fracture gradient.

2. Choke line friction during bubble expansion may cause lost returns. An underground blowout might occur.

3. The collapse resistance of large diameter pipe is lower than the collapse resistance of smaller diameter pipe of the same wall thickness. A gas bubble that is allowed to enter the riser can unload the riser of mud, leaving the riser subject to the full hydrostatic force exerted by the water surrounding it. The riser may collapse as a result of it.

Comparison Of The Three Methods Of Well Control We will now attempt to compare the borehole stresses that occur when using any one of the three previously mentioned well control procedures when a gas kick occurs.

In order to control a well, the BHP needs to be maintained constant at a level equal to the formation pressure. The BHP on the annulus side is the sum of the hydrostatic pressure exerted by any mud above the gas, the hydrostatic pressure exerted by the gas itself, the hydrostatic pressure exerted by the mud below the gas, the annular pressure loss while circulating and the surface imposed pressure (choke pressure).

Gas expands as it rises to the surface and this increase in gas bubble length results in a decrease in the hydrostatic pressure exerted by the fluids in the annulus. An increase in surface imposed pressure (choke pressure) is necessary to maintain the BHP constant at the desired level. If an oil or water kick occurs, expansion does not take place, and the borehole stresses encountered are lower than those that would be expected in a gas kick.

Example:

Assume the following:

Hole diameter = 8.5 in.

Drill pipe OD = 4.5 in.

Drill pipe ID = 3.826 in.

Total Depth = 15000 ft

Mud Weight in use = 15 ppg

Pump output = 0.15 bbls/stk

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Bbls of mud pumped

Wait and Weight

16 ppg kill mud

Driller’s Method

16 ppg kill mud

Concurrent

16 ppg kill mud

Wit and Weight

17 ppg kill mud

1071 - 678 624 -

1184 - 561 624 -

1284 - 458 603 -

1384 - 355 582 -

1584 - 150 562 -

1684 - 46 535 -

1729 - 0 532 -

1942 - - 468 -

2913 - - 312 -

3884 - - 156 -

4855 - - 0 -

Conclusions Of the three methods used, the Wait and Weight Method using the proper kill weight results in the least amount of casing pressure and the least borehole stresses. The reason is that the kill mud reaches the annulus while the influx is still in the hole, and this heavier kill mud helps to exert additional hydrostatic pressure on the bottom. The additional hydrostatic pressure exerted by the kill mud means that the choke pressure (surface-imposed pressure) can be held at a lower value and still maintain the BHP at the desired value.

Using the Concurrent Method allows lower casing pressure values than the Driller’s Method. This is because some of the heavier mud reaches the annulus before the gas bubble is out of the hole. Since this heavier mud is less than the kill mud, the casing pressures are higher than those encountered with the Wait and Weight Method.

Most engineers agree that overkilling the well has no tangible benefit, and may in fact, be detrimental to the kill operation. The reason is that overkilling a well causes higher BHP to be exerted on the drill pipe side due to the extra hydrostatic pressure exerted by the mud in the drill pipe. Thereby higher choke pressures are also necessary in the casing side in order to keep the system in balance.

If a trip margin is to be added, it should be added only after the well is dead.

Exercises

Kick Tolerance In order to kill any kicks safely the equivalent mud weights at any depth in an open hole must not be allowed to exceed the fracture gradients at that particular depth.

Kick Tolerance is the maximum allowable pressure or its equivalent ppg that the weakest point in a wellbore can withstand, which is based upon having no influx of formation fluid in the wellbore. If an influx of formation fluids has occurred, then the kick tolerance factor will become less. In drilling the last casing seat is often assumed to be the weakest point of a wellbore.

Kick Tolerance is computed by the following method:

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Example Assume the following:

Hole diameter = 8.5 in.

Drill pipe OD = 4.5 in.

Drill pipe ID = 3.826 in.

Total Depth = 15000 ft

Mud Weight in use = 15 ppg

Pump output = 0.15 bbls/stk

Kill rate pressure = 1000 psi at 20 stk/min

Pit Gain = 25 bbls

SIDPP = 780 psi

SICP = 960 psi

Surface stack in use.

For simplicity a constant hole and pipe diameter are assumed.

Calculations:

Drill pipe capacity = 213 bbls

Kelly to bit = 1420 strokes

Capacity of annulus = 758 bbls (0.0505 bbls/ft)

Strokes, bit to surface = 5053 strokes

Total strokes required to displace the mud in the well = 6473 strokes

Barrels required to displace mud in the well = 971 bbls

Kill weight mud = 16 ppg

ICP = 1780 psi

Length of influx = 25 bbls / 0.0505 bbls/ft = 495 ft

Influx gradient = mud gradient – ((SICP-SIDPP)/Length of influx)

= 0.78 psi/ft – (180 psi / 495 ft) = 0.42 psi/ft

A 0.42 psi/ft gradient means that wellbore fluid influx is a mixture of saltwater and oil.

The following table of expected casing pressure vs. amount of kill mud pumped was constructed using the data above. The calculations are based on the Wait and Weight Method.

Barrels of mud pumped Casing Pressure expected psi

0 960

100 960

213 960

413 752

513 649

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The pits will overflow because they hold only 275 bbls. Therefore around 30 bbls of mud need to be dumped before, barite can be mixed. This will reduce the string volume to 970 bbls that in turn will require less barite.

Example 2:

Problem: Assume that the present MW is 10 ppg. An inventory of the barite in the bulk tanks reveals that there is 500 sacks of barite. Does the rig have enough barite on hand to increase the weight of a 1200 bbl mud system to 11 ppg?

Solution:

The lbs/bbl of barite required = (1490 x (11-10)) / (35.4 – 11) = 61.06 lbs/bbl

Total lbs of barite required = 61.06 lbs/bbl x 1200 bbls = 73278 lbs

Number of sacks required = 73278 lbs / 100 lbs/sack = 733 sacks

Therefore, the rig does not have sufficient barite on location to raise the mud weight by 1 ppg.

Exercises

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• Aggregation – This is the opposite of dispersion, when the clay platelets remain or become stacked together.

• Flocculation – An edge-to-edge or edge-to-face clumping of platelets which result when attractive forces predominate.

• Deflocculation – It results when attractive forces between edge-edge and edge-face are neutralized.

Clay may then exist in combinations of the above.

Causes, Description And Remedies For Clay Behavior

Dispersion Dispersion results when dry clay aggregates are added to fresh water. Usually caustic soda (NaOH) is added to the water to assist in the disaggregation.

The properties of dispersion are:

• The attractive forces are minimal.

• PV is high to very high

• YP is relatively low.

• Gels are low and flat to progressive.

• Filtration rate is low.

Flocculation In the presence of salt or divalent ions, such as drilling rock salt or anhydrite with a fresh water mud, flocculation and aggregation of clay platelets results.

Properties of flocculation are:

• The attractive forces are at a maximum.

• PV is high.

• YP is very high.

• Gels are high and progressive.

• Filtration rate is very high.

Common Contaminants And Treatment

Salt Salt causes flocculation. Addition of chemical thinners will reduce the very high YP; addition of filtration control agents will reduce high water loss; water dilution or even salt saturation may be necessary.

Anhydrite Anhydrite causes flocculation and flocculation-aggregation. It is usually best to treat out the contaminating Ca2+ ion by addition of soda ash:

Na2CO3 + CaSO4 -> CaCO3 + Na2SO4

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• It gives greater yield to bentonite

Other Additives The other additives to the mud are:

1. Oil

2. Oil mud products

3. Soda ash

4. Bicarbonate of soda

5. Defoaming agents

6. Corrosion inhibitors

7. Surfactants

Basic Types Of Drilling Fluids

Spud Muds / Native Muds • These utilize bentonite or native clays from formations drilled

• They require little or no chemical treatment

• They have no resistance to contamination

Organic-thinned Freshwater Muds • These muds contain bentonite for viscosity; lignin, tannin or lignosulfonate for control of gels;

CMC or similar for water loss control and caustic soda for pH.

• They have fair resistance to contamination

Lime Muds • Lime muds are an inhibitive freshwater mud utilizing Ca(OH)2 to inhibit shale hydration.

• They use organic thinners, caustic for pH.

• They have good resistance to contamination.

Gyp Muds • They are inhibitive freshwater muds that contain gypsum to inhibit shale hydration.

• They contain caustic for pH; lignosulfonate thinner; filtration agents.

• They have good resistance to anhydrite and salt contamination.

Salt / Polymer Muds • An inhibition of shale hydration, utilizing esp. KCl.

• Cellulosic polymer provides most of the viscosity.

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Basic Hydraulics

Rheology And Hydraulics

Introduction and Definition Rheology denotes the deformation of materials, in particular for the oilfield, how a fluid behaves in flow.

Rheological behavior is determined by various physical properties of the fluid:

1. Density: influences inertia, the resistance to flow

2. Viscosity: is essentially the internal friction, also a resistance to flow

3. Various unique physical properties influencing and characterising the fluid’s response to applied stress.

The rheological behavior of a fluid is the relationship of these physical properties and several non-physical properties (such as plastic viscosity, yield point, n and K) to a shear stress (such as pump pressure) and a shear rate (fluid viscosity).

Hydraulics incorporates fluid flow properties such as viscosity, flow type, pressure loss, etc, all of which are influenced by rheological properties.

Viscosity The relationship between shear stress and shear rate is called viscosity.

Viscosity = shear stress / shear rate

Shear stress is an applied force which causes two contiguous layers of fluid to slide relatively to each other. The frictional drag so resulting is a measure of the shear stress.

Shear Stress = force / area = lbs/100 ft2 or dynes/cm2

Shear rate is the rate at which two contiguous layers slide relatively to each other.

Shear rate = relative velocity / separation distance = sec-1

Therefore, viscosity (centipoise) = shear stress / shear rate = lbs/100 ft2 / sec-1

Viscosity is usually plotted as a function of shear stress (y axis) and shear rate (x axis). This distinguishes each fluid and is the one most significant physical, empirical property describing a fluid’s rheological behavior.

Historically, viscosity has been considered a function of shear rate, i.e., viscosity most often changes with the shear rate. Consequently, the shear rate must be specified for a viscosity measurement. For some fluids, viscosity is independent of shear rates.

Newtonian and Non-Newtonian Fluids

Introduction The two broad categories of rheological behavior are defined by the various unique physical properties of fluids. These are:

110

Non-Newtonian fluids exhibit both Newtonian and Non-Newtonian properties at different shear rates.

LAMINAR TURBULENT

Critical velocity

PV Region in w/c a Non-Newtonian fluid behaves as a Newtonian fluid.

YP

Mixed Newtonian and Non-Newtonian behavior.

Shear Stress, Lbs/100 ft2

300 600

Shear Rate (sec-1)

Most drilling fluids are Non-Newtonian.

Flow Patterns And Velocity Profiles Of Non-Newtonian Fluids Laminar Flow is characterized by the fluid’s elements all moving in the same direction and roughly parallel to each other. The velocity of the elements may vary.

Turbulent flow is characterized by the fluid elements moving in various directions, with varying velocities.

Viscosity Vs. Shear Rate For Newtonian fluids, viscosity remains constant over most ranges of shear rates until the critical velocity is exceeded. This usually occurs at shear rates common to flow inside the pipe and at the bit.

For Non-Newtonian fluids, viscosity varies considerably, with the greatest viscosities occurring at the low shear rates characteristic of the pits, and at the lowest viscosities occurring at the very high shear rates encountered at the bit.

Thixotropy is the variance of viscosity with shear rate. Most drilling fluids, esp. polymers, possess a “shear thinning” thixotropy at the bit. This property has considerable influence on hydraulic performance.

Hydraulics Hydraulics is concerned with the behavior of fluids in motion as far as this motion influences and determines velocity, flow patterns, pressure losses, etc.

Hydraulics is dependent on:

• Fluid rheological properties (density, viscosity, thixotropy, etc.)

• Dimensions of the circulating system (i.d., o.d., length, volume)

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b) Slip Velocity

c) Surge and Swab pressures

d) Jet Velocity

e) Hydraulic impact force

f) Hydraulic horsepower

The Power Law Model The Power Law is a rheological behavior- hydraulics model which follows more closely or approximates actual fluid behavior at annular shear rates than does the Bingham plastic model.

Shear rates in the annulus are often less than 150 RPM on the rheometer. The Bingham model examines fluid behavior at shear rates between 300 and 600 RPM on the rheometer. Hence PV and YP do not afford the accuracy needed to predict pressure losses in the annulus.

The Power Law equation is:

τ = Kγn where,

τ = shear stress, lbs/100ft2 or dynes/cm

K = consistency index, lbs/100ft2

γ = shear rate, sec-1

n = Power Law index

While producing more accurate pressure loss calculations, the Power Law model may predict a lower-than-actual ECD.

The Power Law model can be modified to give greater accuracy by using the initial gel strength reading (or the shear value at a shear rate of 3 RPM). This provides a better, more accurate value of n and k.

See graph ……………...

Procedure 1. Calculate n and k

2. Calculate the velocity of each annular section.

3. Calculate xxxx for each section.

4. Find τ where τ = Kγn

5. Calculate Reynold’s number (not necessary)???

6. Determine if an intersection exists between Reynold’s number and n; if not, flow is laminar and the Power Law is used to calculate pressure loss; if yes, use Bingham Model.

The Aims Of Hydraulics The aims of hydraulics are to utilize rheological behavior in order to describe flow properties such that the following may be achieved and determined:

1. Hole cleaning

2. Hydraulic efficiency

3. Calculation of circulating pressure losses

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1. Mud weight

2. Cuttings density and diameter

3. Annular velocity

4. Mud properties

5. Type of flow

6. Hole size

Bingham Plastic Model Slip Velocity Formula For the Bingham Plastic Model:

Vs = ((53.5 – (Wc – W)D2 x V) / (6.65 x YP x (dh – dp))) + (PV x V) (for laminar flow)

Vs = square root of (D x (Wc – W)) / W (for turbulent flow)

Where,

Vs = slip velocity, ft/sec

V = annular velocity, ft/sec

D = cuttings diameter, in.

Wc = cuttings density, ppg

W = MW, ppg

Power Law Model Slip Velocity Formula For the Power Law Model:

1. First calculate effective mud viscosity at the annular velocity:

Effective mud viscosity, µ = (((144 x V)/(dh-dp))x((2n+1)/3n))n x (3.33 x k x (dh-dp)) / V which simplifies to: = ((164 x V) / (dh-dp)) n x (3.33 x k x (dh-dp)) / V

2. Then find the slip velocity:

Vs = (175 x D x (Wc – W)0.667) / (W0.333 x µ0.333)

Where,

V = annular velocity, ft/sec

K = (1.07 x θ300) / 511n

µ = effective viscosity, cp

Vs = slip velocity, ft/sec

Conclusion For each annular section, slip velocity is subtracted from annular velocity to arrive at a net cuttings rise velocity. If for any section the difference between annular velocity and net cuttings velocity is great, an adjustment in mud properties should be considered.

The largest annular section is of special importance, because it has the lowest annular velocity. Cuttings are more prone to fall in this section. Of particular significance is the offshore riser. The annular velocity in the riser is often so much less than other sections that, for special circumstances (e.g. shale cavings), flushing of the riser utilizing the kill/choke lines may be necessary.

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As some hydraulics programs are developed around maintainance of maximum jet velocity, each succesive hole section and greater depths require a reduction in nozzle size in order to maintain efficient hole cleaning and high ROP.

Particular requirements may outweigh considerations of optimum jet velocity, e.g. use of LCM, the possibility of having to cement through the bit.

Guidelines: A good average value is 250 ft/sec for firm to hard formations; soft shales may require considerably less due to the possibility of eroding the hole.

Bit Hydraulic Horsepower Bit hydraulic horsepower comprises the ability of the drilling fluid to:

Remove the cuttings

Clean the bit cutting surfaces

Bhhp = (Pb x GPM) / 1714

Bhhp = 5 x 10-7W x GPM x Vn2

Where,

Pb = bit pressure loss, psi

GPM = pump output

W = MW, ppg

Vn = nozzle velocity, ft/sec

A common approach to designing a hydraulics program is to maximize or optimize bit hydraulic horsepower. It can be seen that bit hydraulic horsepower is maximized when the bit pressure loss and the pump output are maximized. Alternatively, it can be seen that bit hydraulic horsepower is directly proportional to the square of the jet velocity.

It has been found that ROP is greatest when Pb = 0.66 x standpipe pressure. This formula is commonly used to maximize bit hydraulic horsepower.

Not only is ROP directly proportional (to a degree) to bit hydraulic horsepower; whenever WOB is increased to effect an increase in ROP bit hydraulic horsepower must be increased.

Although largely dependent on formation strength, size of hole, bit type, etc., a guideline for soft to firm formations (like the Gulf Coast) is:

2.5 to 5 hp/in2 of bit area

up to 30 hp/in2 for large holes

1.5 to 2.5 hp/in2 for diamond bits

Jet Impact Force IF = (W x GPM x Vn) / 1932

IF = 5.2 x 10-4 x W x GPM x Vn

IF = 0.0173 x GPM x square root of (W x Pb)

Where,

IF = jet impact force, lbs

W = MW, ppg

GPM = pump output

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Some Observations On Hydraulics The circulating pressure losses at the bit are directly proportional to the mud weight.

P α MW

Ex: if Pb = 500 psi with a 10 ppg mud; then Pb = 600 psi with a 12 ppg mud

Circulating pressure losses are directly proportional to the 1.86 power of the flow rate (for general purposes, the 2.0 power may be used).

Psys α GPM1.86 or Psys α SPM1.86

Ex.: Psys = 3000 psi at 10.8 bbl/min

then at 5.4 bbl/min Psys = (5.4/10.8)1.86 x 3000 psi = 826 psi

Hydraulic horsepower required to circulate varies with the cube of the flow rate.

HHP = GPM3

The smaller the hole size, the higher the annular velocity required to remove the cuttings.

n values of 0.6 to 0.7 are satisfactory for good hole cleaning. This corresponds to a PV:YP ratio of 1 to 2:1.

A large increase in PV has little effect on circulating pressure losses in laminar flow. A small increase in YP has a large effect on circulating pressure losses in laminar flow. PV and YP have no effect on circulating pressure losses in turbulent flow.

AMOCO’s Hydraulic Guidelines for flow rate: 30 to 50 GPM per inch of bit diameter. Below is the table:

Bit Diameter, in. Minimum Flow Maximum Flow

26 780 1300

20 600 1000

17.5 525 875

12.25 368 613

8.5 255 300

6 180 300

AMOCO’s Hydraulic Guidelines for bit horsepower: <10 fph, 2.5 to 3 hp/in2. Below is the table:

Bit Size, in 2.5 hp/in2 3 hp/in2

8.5 142 170

6 71 85

AMOCO’s Hydraulic Guidelines for bit horsepower: >10 fph, Bit hp α square root of ROP, with 5 hp/in2 maximum. Below is the table:

Bit Size, in Bit hp

17.5 1202

12.25 589

8.5 284

Pressure loss at the bit is inversely proportional to the square of the jet area.

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Optimum Bit Hydraulics

Introduction Optimum bit hydraulics are essential for maximum ROPs under all circumstances.

Constraints There are three constraints that must be imposed before any attempt is done to optimize the hydraulics of the circulating system.

Max Pump Pressure

Minimum Flow Pressure

Maximum Flow

Flow Rate

Minimum Flow Rate This is the minimum flow rate that will ensure that the hole is kept clean. Various methods can be used to determine this value.

Randall suggests using not less than 30 GPM/inch of bit diameter.

Another method is to determine the slip velocity in the largest annular section and using this value to back calculate the flow rate that will generate an annular velocity equivalent to this plus the safety margin. Since there are many formulae for calculating slip velocity, this method recommends that the slip velocity be calculated using this formula:

Qmin = (Vs x (dh2 – dp2))/24.51

Where,

Qmin = minimum flow rate in GPM

Vs = slip velocity in ft/min

Dh =diameter of hole, in

Dp = diameter of pipe, in

Note: the slip velocity and annular dimensions used in the formula should pertain to the annular section with the largest hydraulic radius, e.g. the riser.

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5. Using u determine the optimum system pressure loss (Popt).

For maximum hp: Popt = Pmax / (u + 1)

For maximum impact force: Popt = (2 x Pmax) / (u + 2)

6. Determine the flow rate which will result in this pressure loss using one of the pairs of data (flow rate and pressure) used in step 4. Use the following formula:

Required flow rate = (Popt/P1)1/u x Q1

7. Check that the flow rate determined in step 6 falls within your limits. If it doesn’t go to the next step. Otherwise, use the flow rate corresponding to the closest limit and recalculate the optimum pressure loss (Popt).

8. Calculate the pressure loss required across the bit.

Pbit = Pmax – Popt

9. Calculate the required jet area as per Randall Method.

B.V. Randall Method Randall’s method is very much a rule of thumb and is based on the assumption that optimum hydraulics will be achieved with flow rates and pressure losses which fall somewhere between those that optimize hydraulic impact force and those that optimize hydraulic horsepower.

Guidelines Flowrate: 30-50 gpm/in. of bit diam. The flow must be high enough to clean the bit, but too high a flowrate will damage the bit as well as erode the hole. For ROPs <15 fph use 35 gpm/in of bit diam. For faster ROPs use 40-45 gpm/in of bit diam.

Jrt hp: 2.5-5 hp/sq in of bottom area. For ROP <10 fph, 2.5-3 hyd hp/sq in is the maximum needed. At higher ROPs hp is very close to the square rrot of the ROP ( 4hp for 16 fph) Jet hp > 5 hp/sq in of botto, area may cause premature bit failure, so should be used only when the higher ROPs justify extra bit and trip costs.

Max. bit hydraulics: 50-65% of available pump pressure across the bit jet nozzles. Maximum impact occurs when about 50% of the pump pressure is across the bit. The most effective drilling occurs between max hp and max impact.

Two jets for smaller bits at lower ROP; otherwise use three jets. Recommended to blank off one jet on bits <9.5 ins and ROPs of <50 fph.

Maintain laminar flow in the annulus bec. it causes less scouring and erosion of the well bore, less fluid loss and better cuttings transport than turbulent flow.

Plastic Viscosity: reflects the solids concentration in a mud. Water and solids removal equipment decrease PV. Chemical dispersants (thinners) increase PV. PV has only minor effects on pressure losses, but may have a very significant detrimental effect on ROP.

Yield Point: reflects forces between colloidal particles and molecules in the mud. Increased YP, esp. in low solids nondispersed muds, tends to decrease pressure losses in the drillstring (tending to increase hydraulics at the bit), and tends to cause laminar flow and increase cuttings transport in tbe annulus. High YP will cause high pressures in the annulus and potential lost circulation. YP is strongly affected by chemical treatment and may be affected in an unpredictable way by bottom hole temperature. YP >3 lb/100 ft2 usu. will cause laminar flow in 12.25” hole, and 5-7 is often sufficient in 8.5” in. hole for dispersed and nondispersed muds respectively.

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