39532154 Production Logging Techniques

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Table of Contents

Introduction ............................................................................................................................................ 7

Casing Collar Locator ............................................................................................................................. 10

Gamma Ray ........................................................................................................................................... 12

Bottom-hole pressure Gauges ............................................................................................................... 12

Theory of Operation .......................................................................................................................... 12

Spinner Flowmeter Logging ................................................................................................................... 13

Theory of Operation .......................................................................................................................... 13

Calibration ......................................................................................................................................... 15

Temperature Log ................................................................................................................................... 16

Noise/Acoustic Log ................................................................................................................................ 18Summary of typical noise logging applications: .................................................................................. 18

Tool Description................................................................................................................................. 19

Analysis/Interpretation ...................................................................................................................... 20

Logging Procedure ............................................................................................................................. 21

Gradiomanometer ................................................................................................................................. 21

Tool Description................................................................................................................................. 21

Gamma ray density device ..................................................................................................................... 23

Radioactive Tracers and Gamma ray detectors ...................................................................................... 24

Pulse Neutron Capture Logging and Oxygen Activation ............................. ...................... ....................... 26

Operating Principle ............................................................................................................................ 26

Neutron Capture Theory .................................................................................................................... 27

Evaluation of Water Saturation (S w) behind casing ................................... ............................ .............. 28

Factors affecting log interpretation ................................................................................................ 29

Applications of Pulsed Neutron Capture Logs ......................... ................................ ...................... ...... 30

Through-Tubing Neutron Log ................................................................................................................. 30Down-hole Video Camera and Borehole Logging ............................. ............................. .......................... 31

Combination Tools ................................ ........................ ............................ ................................ ............. 31

Schlumberger Production Combination Tool ......................... ................................ ....................... ...... 32

Gas Well Deliverability Testing ........................... ................................ ...................... .............................. 34

Flow-after-flow test ........................................................................................................................... 35


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Isochronal test ................................................................................................................................... 36

Modified Isochronal test .................................................................................................................... 37

Analysis of Conventional backpressure tests ...................................................................................... 37

Rawlins and Schellhardt Equation .................................................................................................. 37

Oil Well Deliverability Testing ............................................................................................................ 38

Productivity Index, PI ......................................................................................................................... 39

Rate Pressure Relations ..................................................................................................................... 39

For Under-saturated Oil Wells ........................................................................................................ 39

Saturated Oil Wells ........................................................................................................................ 40

Sampling Techniques ............................................................................................................................. 41

Drill Stem Testing ............................................................................................................................... 41

Repeat Formation Tester (RFT) .......................................................................................................... 42References............................................................................................................................................. 44

Table of Figures

Figure 1: Percentage breakdown of 100 random Production Logging operations and the main reasons forthe job. (Courtesy Sondex Production Logging Tool string) ............................ ........................ ................... 8

Figure 2: Schematic of the CCL Tool (Allen & Roberts, OGCI Tulsa, 1982)............................... ................. 10Figure 3: Typical collar record showing the corresponding "blips" (M.L. Connell & R.G. Howard,Halliburton Energy Services) .................................................................................................................. 11Figure 4: Schematic of the Gamma Ray Tool (Courtesy Sondex PLT) ............................ ........................ ... 12Figure 5: Cross-section of the Quartz Pressure Single Gauge (Courtesy Sondex PLT) ........................... .... 13Figure 6: Diagram showing the basic configurations of the main types of spinner flowmeters................ 15Figure 7: Schematic of the high resolution thermometer (Allen & Roberts, OGCI Tulsa, 1982)................ 16Figure 8: Lithological influence on static temperature gradient (Allen & Roberts, OGCI Tulsa, 1982) ...... 17Figure 9: Schematic of Noise Logging Tool (Allen & Roberts, OGCI Tulsa, 1982) ........................ .............. 19Figure 10: Noise Spectrum (Allen & Roberts, OGCI Tulsa, 1982) ............................................................. 19

Figure 11: Change in transmission medium within the wellbore (Allen & Roberts, OGCI Tulsa, 1982) ..... 20Figure 12: Vertical section of a typical Gradiomanometer (Allen & Roberts, OGCI Tulsa, 1982) ..... ......... 22Figure 13: Empirical chart for determining slippage velocity (Courtesy Schlumberger) ........................... 23Figure 14: Schematic showing how the gamma ray density device is used to determine fluid density(Courtest Sondex PLT) ............................................................................................................................ 24Figure 15: Typical radioactive tracer-detector tool configuration for velocity-shot measurements(Allen &Roberts, OGCI Tulsa, 1982) .................................................................................................................... 25


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Figure 16: Configuration of the Pulsed Neutron Tool (http://oilandgastraining.net) ...................... ......... 26Figure 17: Plot of gamma ray count rate versus time after neutron burst (http://oilandgastraining.net) 27Figure 18: Simple formation model (http://oilandgastraining.net) ............................................ ............. 28Figure 19: Diagram showing oxygen activation as water flows past the detectors ......................... ......... 30Figure 20: Composite Production Log Example 1 (Courtesy Sondex)....................................................... 32

Figure 21: Composite Production Log Example 2 (Courtesy Sondex)....................................................... 33Figure 22: Composite Production Log Example 3 (Courtesy Sondex)....................................................... 34Figure 23: Rates and pressures in flow-after-flow test (Lee, 1996) ........ ........................... ...................... 36Figure 24: Flow-rate and pressure diagrams for an isochronal test of a gas well (Lee, 1996)................... 36Figure 25: Flow rate and pressure diagrams for modified isochronal tests on gas wells (Lee, 1996) ........ 37Figure 26: Empirical flow-after-flow analysis (Lee, 1996) ................................ ....................... ................. 38Figure 27: Inflow Performance Relationship for an Undersaturated reservoir ........................................ 39Figure 28: Inflow Performance Relationship for a Saturated reservoir ............................. ....................... 40Figure 29: IPR and TPC showing how changes in tubing size or stimulation affects production rate ........ 40Figure 30: Schematic of the Drill Stem test tool ........................... .......................... ............................ ..... 42Figure 31: Schematic of the Schlumberger RFT (Allen & Robert, 1982) ........................................... ........ 43


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Ex ecutive Summary

P roduction Surveillance is the procedure of measuring and monitoring certain fluid properties

over the life of the well, which can be useful in identifying production and mechanical problems,

generating flow profiles, monitoring changes in fluid saturation, and for comparison with

expected well performance. The ultimate purpose of which is to provide information which can

aid in maximizing oil recovery, extending the life of the well, and reducing operating costs.

This paper will discuss the science, logging procedure, interpretation, applications, and the tools

used to measure the following downhole fluid properties:

y Temperature

y P ressure

y Fluid Density

y Fluid Velocity

y Neutron Capture Capability ( P hotoelectric Absorption Capacity)

y Radioactivity

y Sound Transmission Characteristics

y Electrical P roperties such as conductivity or dielectric constant

The radioactive tools are used mainly to evaluate fluid type and saturations behind casing, while

the flow and fluid differentiation devices are used mainly to evaluate fluids and fluid movement

inside casing. The combination of noise and temperature measurements can also provide good

definition of flow behind casing.

The paper also goes on to discuss gas well and oil well deliverability testing, and how it is used

to determine an important productivity indicator known as the Absolute Openflow P otential

(AOF P ). It is also shown how the values of surface production rate and bottom-hole flowing

pressure can be used to generate an Inflow P erformance Relationship (I P R) for both oil and gas

wells. The I P R curve can be used to predict future production at any stage in the reservoirs life,

as well as how production is influenced by changes in drawdown, tubing size, or by stimulation.

The P roductivity Index test for oil wells, which is the simplest form of Deliverability test is

mentioned. Transient pressure analysis is not considered a P roduction Surveillance Technique,

but can help in well problem diagnosis, when production and mechanical problems are not

found. For instance the well may not be producing at the expected rate because of a low

permeability formation, or the presence of skin damage. As such the decision can then be made


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whether to acidize, hydraulically fracture, or plug and abandonment the well. Economics is

usually a major driving force in such decision making. P roduction from the well after stimulation

must be able to offset the cost of the stimulation job, plus realize profits in reasonable time.

Fluid sampling techniques such as Drill Stem testing and Repeat (Wireline) Formation Testing is

then discussed. They are generally done on newly drilled exploratory wells. The DST

determines the potential of the formation, and involves simultaneously recording formation

pressure while taking fluid samples. The RFT is used to confirm the presence of formation fluid,

while giving an indication of productivity and formation pressure.


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I ntroductionP roduction Logging Tools ( P LT) are used to gather fluid data from a producing well, which is

then ultimately used to maximize hydrocarbon recovery from reservoirs or manage fluid profiles

for injection wells. P roduction logs are application in three (3) major areas:

y Diagnosis of mechanical problems

y Analysis of individual well performance in relation to the reservoir

y Management of reservoir fluids.

P roduction Log data can be interpreted to help indentify some of the following production

problems:

Mechanical Condition of the Well

y

Casing, tubing, or packer leaksy Corrosion damage

y Collapsed casing

y Wellbore restrictions

Anomalous Fluid Movements Between Zones

y Fluid flow behind casing (channelling) due to poor primary cement job.

y Fluid flow into thief zones.

Evaluation of Completion Efficiency ( P roducing Well)

y Negligible or no contribution from some zonesy Zones contributing only water or gas, when oil is expected

y Zones producing below their potential as forecasted by other data sources

y Location of perforations or points of fluid entry

Evaluation of Completion Efficiency (Injection Well)

y Indentify zones to which the injected fluid is entering

y Quantify of injected fluid entering zone(s)

Design and Evaluation of Stimulation Treatment

y Indentify zones requiring stimulationy Zones to which stimulation fluid is entering

y Monitor reservoir performance after stimulation

Reservoir Management

y Initial fluid saturations in each zone

y Saturation changes due to production or extraneous fluid movement


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y Rate at which the reservoir is being depleted

The pie chart below shows the typical breakdown of 100 random production logging operations

analysed by the prime reasons for the job.

Reason for Production Log Information obtained

P roduction P rofiling To profile the well to check how it isperforming against expectations.

Injection P rofiling To determine the injection profile of a water or gas injection well.

Excessive gas P roblems Gas coning which limits the flow of oil.Locating the source of gas production isimportant when planning remedial work inthese wells.

Water P roblems The majority of production logging jobs isperformed because large volumes of unwanted water are produced. Water production is very expensive since it limits theproduction of hydrocarbons, and has to betreated and disposed of safely. Locating thesource of water entry is essential whenplanning remedial work such as a squeezecement job.

Mechanical P roblems Holes in tubing, packers, or casing can belocated. Blocked perforations can also beidentified.

Figure 1: Percentage breakdown of 100 random Production Logging operations and the mainreasons for the job. (Courtesy Sondex Production Logging Tool string)


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P roduction logs are run into cased-hole production or injection wells with or without tubing. In

completed wells with tubing, the tubing may be pulled and then the tools run into the hole, or if

your internal diameter is large enough, the tool may be run through the tubing in which case the

procedure is called Through-Tubing P roduction Logging. Some production logging tools can

also be run in open-hole, however due to rate control, sand, and water problems typicallyassociated with barefoot completions, they are rarely applied, and as such open-hole production

logging is scarcely done. Hence, only cased holed and through-tubing production logging will be

discussed.

The tools can either be run on an electric wireline and records taken at surface, or on a slick

wireline and records taken on bottom-hole charts or magnetic tape. A lubricator is installed on

the wellhead to facilitate the lowering of the tools. Tools will function properly at a maximum

hydrostatic pressure of 15,000 psi and maximum wellbore temperature of 350F.

The most significant production logging tools in use today are:

Bottom-hole pressure device

y Quartz P ressure Single (Q P S)

Temperature devices

y High resolution thermometer

y Radial differential temperature device

Noise device

y Noise Log - usually run in conjunction with a temperature log

Spinner flowmeters

y Inflatable packer f lowmeter

y Continuous flowmeter

y Fullbore flowmeter

y Basket flowmeter

y Diverter flowmeter

Fluid Density Devicesy Gradiomanometer

y Gamma ray density device

Radioactive tracers and Gamma ray detectors

P ulse Neutron devices

y P ulse Neutron Capture Logging & Oxygen Activation


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Gamma ray neutron devices

y Through-Tubing Neutron Log

Slim hole cameras

P eripherals run in conjunction with the main P roduction Logging Tools:

Casing Collar Locator (CCL)

Gamma Ray Tool

Caliper

Centralizer

Casing Collar LocatorThe casing collar locator is an electric logging tool that detects the magnetic anomaly caused by

the relatively high mass of the casing collar, it also responds to changes in metal volume at the

completion items, and perforations. It is mainly used for depth correlation, but can also be used

to detect holes and perforations. A signal is transmitted to the surface equipment that provides a

screen display and printed log which enables the output to be correlated with previous logs and

pup joints installed for correlation purposes.

The figure below shows a magnetic collar locator which is designed such that as the unit moves

through a collar, the increased thickness of the metal disturbs the magnetic field and causes a

blip to be recorded at that depth on the log.

Figure 2: Schematic of the CCL Tool (Allen & Roberts, OGCITulsa, 1982)


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Figure 3: Typical collar record showing the corresponding "blips" (M.L. Connell &R.G. Howard, Halliburton Energy Services)


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G amma RayMeasures natural gamma ray radiation levels in the wellbore. Used for depth correlation,

lithology, and radioactive scale identification that is associated with water production. The

gamma ray detector used is a huge high temperature Sodium-Iodide crystal. When gamma rays

from the formation strike the crystal, photons of light are emitted. The levels of light are verysmall so a photomultiplier tube ( P MT) is used to amplify the signals to a level that can be

detected. The detector circuit detects and filters the amplified signals which are then output from

the tool as a gamma ray trace on the log. The P MT requires a high voltage power supply to

amplify the photons of light.

Bottom-hole pressure

Gauges A Quartz Gauge is the typical tool used by most service companies to measure changes in

down-hole flowing and shut-in pressures. This information indicates the efficiency of the well

and performance of the reservoir.

Theory of Operation A bottom-hole pressure bomb which is basically a pressure-fight container is lowered into the

well and measures and records the pressure at a specific depth or at the midpoint of the

perforations. The shut-in bottom-hole pressure test measures the pressure after the well has

been shut-in for a specified period of time. The flowing bottom-hole pressure is the pressureafter the well has been flowing for a period of time to achieve stabilized flow.

Wellbore pressure is transmitted through an isolating metal bellows to a volume of silicone oil

which surrounds the quartz pressure crystal. The quartz crystal oscillates at its natural

frequency, while changes in hydrostatic pressure alter its natural frequency. The frequency of

Figure 4: Schematic of the Gamma Ray Tool (Courtesy Sondex PLT)


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the crystal oscillations is affected by wellbore temperature, and hence a second temperature

crystal which is not exposed to the well pressure is included within the gauge to measure the

temperature of the pressure crystal. This reference crystal is used to reduce the output

frequencies.

Spinner Flowmeter LoggingThe flowmeter measures well fluid velocity using a turbine impeller. There are different

variations of the tool for different logging and wellbore conditions, however, basically they allconsist of a propeller mounted on a jewel-bearing supported shaft. Rotation rate and direction

are determined either magnetically or optically. The rate at which the spinner rotates is directly

proportional to the fluid velocity. A flow log which records fluid velocity with depth is produced.

The main reasons for measuring flowrate downhole are:

y To determine which intervals are producing

y How much they are producing

y To locate any possible thief zones

Theory of Operation1. Spinner flowmeters measure fluid velocity by the rotation of a mechanical impeller within

the moving fluid.

2. The rotating impeller generates electrical pulses which are transmitted up the wireline to

the surface instrumentation.

Figure 5: Cross-section of the Quartz Pressure Single Gauge (Courtesy Sondex PLT)


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3. The measured pulses are related to revolutions per min and fluid velocity in ft/min.

4. Fluid velocity is converted to flowrate for a given diameter.

Spinners may be run in a static mode for stationary readings, or they may be run in a dynamic

mode for a profile of flow in the well. Dynamic operation offers the following advantages over

static operation:

y Covers more of the well and shows the precise location where flow enters or exits.

y Data is collected faster; therefore head conditions are more nearly constant during the

test.

y Flow test resolution is increased

y Dynamic measurements are less prone to depth errors.

Static spinner tests are however easier to quantify because correction for logging speed is notrequired. The ideal logging practice is to profile the well in dynamic mode, and then collect

stationary readings at selected zones of interest e.g. perforation depths.

There are four (4) basic spinner flowmeter configurations:

a) Inflatable packer flowmeter diverts all flow directly through the spinner.

Measurement precision is excellent even at low flow velocities. However, the restriction

created by the packer tool causes a pressure drop that may alter the flow profile and at

higher rates may push the tool up the wellbore. As such an upper limit of about 1500 bpdin 7 casing is placed on the use of this tool.

b) Continuous flowmeter logs either with or against the flow direction and can take

stationary readings. The spinner rotates continuously hence the name continuous

flowmeter. It is typically used through tubing and in casing for high rate gas wells. There

are no upper limits on flow velocity as with the inflatable packer flowmeter; however

because of its small diameter only a fraction of the flow stream is sampled, thus

increasing calibration problems.

c) Fullbore flowmeter was developed to improve cross-sectional sampling. The toolsutilizes collapsible blades that unfold below the tubing, hence the tool cannot measure

flow within the tubing. Has much better resolution than the continuous flowmeter for

medium to lower flowrates. Minimum rates are about 65 bpd in 5 casing.

d) Diverter Basket flowmeter the flowmeter is closed down to tool diameter while

running in or pulling out of hole, and opens automatically when it leaves the tubing and


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enters the casing. The spinner runs on precision bearings and rotation is sensed by zero

drag Hall Effect detectors allowing the measurement of very low flow rates.

e) Diverter flowmeter was developed to accurately measure multiphase flow in

horizontal wells, even at relatively low flowrates. With the tool stationary, motorized

vanes can be extended to contact the casing wall and divert most of the flow through thespinner. It is the most precise flow measuring device, with an upper limit of 400 bpd in

5 casing.

CalibrationThe tools are calibrated by using a multi-pass technique, where the tool response in revolutions

per second is recorded during several runs at known logging speeds, and a plot of rps versus

tool velocity at various depths is made.

The following factors impact spinner impeller response:

y Viscosity of the wellbore fluid, with gas bubbles being especially bad.

y Density and density changes in the wellbore fluid.

y Debris (grease, scale, sand, etc) in the well.

Figure 6: Diagram showing the basic configurations of the main types of spinner flowmeters


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y Spinner position in the well.

y Variable logging speed.

y Flow direction past the impeller.

y Diameter changes (rugosity) in the well.

y Unstable pumping or flowing conditions.

As such it is important to be fully aware of the flowing and wellbore conditions in order than

corrections can be made to ensure good tool resolution and accuracy.

Temperature Log A tiny platinum resistor sensor (temperature sensitive) is enclosed in an Inconel probe tube

exposed to the wellbore fluid. The resistance of the sensor is affected by temperature changes

which causes a differential voltage ( P otential difference) across the probe. This differentialvoltage is converted to a frequency and output as a temperature measurement. The

measurement is then amplified electronically to give very high resolution. The rapid response

time of the sensor makes it able to detect tiny temperature changes. Hence the tool is very

accurate, and the effects of changing line speed are minimized. Static or flowing wellbore

temperature can be recorded.

Figure 7: Schematic of the high resolution thermometer (Allen & Roberts, OGCITulsa, 1982)


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Heat transfer by fluid movement (convection) depends on the rate of fluid movement as well as

the specific heat capacity of the fluid. Gas expansion results in significant cooling, while liquid

expansion results in a slight heating effect. With a static fluid situation, temperature in the well

is primarily affected by conductive heat transfer. Hence if the geothermal gradient for a

particular sand-shale sequence is known, the measured temperatures as displayed on thetemperature log can be compared to the calculated temperatures to determine whether a

heating or cooling effect is prevailing, and hence distinguish whether the fluid flow is

predominantly gas or liquids. Geothermal gradient in a particular area is dependent on the

conductivity of the formations, which varies with lithology as well as geological features e.g.

washouts. The greater mass of cement required to fill a washout provides insulation such that

the temperature in the rock beyond is not affected as much by the conductive heat transfer due

to the fluid movement. These features can mask temperature readings and contribute to wrong

interpretations if the geology and wellbore rugosity is not well known.

The radial differential temperature device has the potential of sensing flow through a channel

along one side of the casing. It comprises of a section that can be anchored by bow springs at a

particular depth, while two arms containing temperature sensors are extended to contact the

casing. The difference in the output of these sensors as they are rotated around the

circumference of the casing indicates fluid movement in a channel.

Figure 8: Lithological influence on static temperature gradient (Allen & Roberts, OGCI Tulsa, 1982)


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N oise/Acoustic Log A noise log is a recording of the amplitude of audible sound frequencies generated by moving

liquid or gas at various points in the well. The sounds/noises can be attributed to pressure drops

as fluids enter the wellbore or move through spaces behind the casing. The sounds of the

moving fluids or the hiss of escaping gas are caused by disturbances in a liquid/gas interface or by turbulence in the fluid stream. This audible noise level and frequency patterns in the wellbore

which are caused by movement of fluids inside or outside the casing can be used to establish:

y The presence of flow.

y The path of the flow.

y Fluid phases involved.

y Flowrate to a certain extent.

The noise log is very effective for gas detection as the gas makes its way up through the fluid on

account of its lower density. It is also effective for detection of various kinds of gas, water, or oil

single phase flow. High-noise amplitudes indicate locations of greater turbulence, such as leaks,

channels, and perforations.

Summary of typical noise logging applications:y Detection of channels in the cement sheath for gas influx

y Measure flowrates

y

Identify open perforationsy Detect sand production

y Locate gas-liquid interfaces.

The noise tool is usually run in conjunction with the temperature tool to provide to provide

auxiliary and complimentary data as well to assist in the interpretation. Together, they are the

best tools for locating and defining flow behind casing. Cooling areas are indentified on the

temperature log, and the noise log is then used to analyze these cooling zones for indications of

gas entry, or gas channelling.


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Tool Description A noise logging tool is about 1.5 inches in diameter and 6 feet in length, and comprises of a

sensitive piezoelectric crystal microphone and wave-band audio amplifier. This tool is

electronically connected to a speaker and several high-pass filters at surface. The piezoelectric

crystal microphone detects the sound which is then amplified before it is sent to the surface for filtering. Once detected at surface, the noise amplitude spectrum is filtered through many high-

pass filters that present the noise amplitudes above 200, 600, 1,000, and 2,000 Hz. A plot of

amplitude versus frequency is then recorded on an oscilloscope. Four tracks are usually

recorded displaying the average amplitude of all sound frequencies above the cut-off frequency

as shown in the in the figure below.

Figure 9: Schematic of Noise Logging Tool (Allen & Roberts, OGCI Tulsa, 1982)

Figure 10: Noise Spectrum (Allen & Roberts, OGCI Tulsa, 1982)


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Analysis/ I nterpretationThese different frequency ranges can be tied to different noise sources or could be an indicator

of the fluid-flow regimes prevalent. Comparisons are made with known sound patterns

developed in laboratory simulations. Fluid identification is made based on the following facts:

y At a differential pressure above 100 psi, most of sonic energy above 1000 Hz is created

by gas movement.

y Single phase liquid movement creates more energy below 1000 Hz.

y Two phase flow usually creates a peak in the 200-600 Hz band, particularly with gas

moving through a liquid filled channel.

y Flow in a channel behind the casing creates energy peaks characteristic of restrictions in

the channel. Undisturbed flow inside casing or tubing should not create peaks.

y

Attenuation is a function of frequency and nature of the medium.o Sound transmission is highly attenuated in gas; twice as much as in water (as

shown in figure 11).

Figure 11: Change in transmission medium within the wellbore (Allen& Roberts, OGCI Tulsa, 1982)


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Logging Procedurey The well is open to stabilized flow.

y The tool string is lowered to the bottom of the wellbore, while at the same time recording

a flowing temperature survey.

y The noise tool is then pulled upwards and stationary readings taken every 2 to 2.5 m

across the perforations, and at 5 m stops between perforated zones.

y The well is then shut-in, and additional noise/temperature surveys are run at

approximately 1.5 to 2.5 hrs after shut-in if required.

Measurements are taken with the tool stationary to avoid noise generated because of tool

movement against casing, and wireline motion through the lubricator.

G radiomanometerThe purpose of this tool is to measure the density of the borehole fluid continuously with depth.

Tool DescriptionThe gradiomanometer measures the difference in pressure between two sensors which are

spaced approximately 2 feet apart vertically. The pressure difference is the sum of the

hydrostatic head, friction head, and kinetic head prevailing in the wellbore at the time of logging.

For normal flow velocities (laminar flow) friction is negligible, and if there is no change in flow

velocity between the two bellows (steady state), kinetic effect is also negligible. Hence under

these conditions the pressure difference seen by the gradiomanometer is a function of the

hydrostatic head only i.e. P = g (h 2 h 1). Since the acceleration due to gravity (g) is a known

constant, and the distance between the two pressure sensing bellows can be determined, then

the differential pressure observed is directly proportional to the average fluid density in that

zone. The tool has a resolution of about 0.01 gm/cc.


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The gradiomanometer is most effective for identifying gas entry and locating standing water

levels.

The downhole density of oil and water can be determined based on static gradiomanometer measurements, while the apparent fluid density is determined from dynamic gradiomanometer

measurements at various levels. The water holdup can then be calculated at various levels in

wellbore using the equation:

,

Once the difference in density between the oil and water, and the water holdup are known, an

empirical chart can be used to determined the slippage velocity, , which is the differencebetween the oil stream and water stream velocities ( - ). If the velocity of the total flow

stream, , is obtained via a flowmeter measurement, then the oil and water flowrates moving at

any level can be determined from:

Figure 12: Vertical section of a typical Gradiomanometer(Allen & Roberts, OGCI Tulsa, 1982)


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Where,

are in bpd

Since the oil rate and water rate at different levels can be calculated, the zone contributing

water can easily be identified.

G amma ray density deviceThis tool consists of a cage open to wellbore fluid. At the base of the tool is the gamma ray

source, and at the top a focused detector which measures radioactivity. Since radioactivity is a

statistical measurement, stationary readings will improve accuracy. Low energy gamma rays

are emitted from the radioactive source in the bottom of the tool, and are focused to cross awindow through which the well fluids pass. Located adjacent to the radioactive source is a

scintillation gamma ray detector designed to detect gamma rays from the source only (hence K,

Th, and U often found in shales will not be detected).

Figure 13: Empirical chart for determining slippage velocity (CourtesySchlumberger)


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The logarithm of the number of gamma ray counts made by the detector is inversely

proportional to the average density (photoelectric absorption) of the fluid. Hence low fluid

densities will have a high number of gamma ray counts, while high density fluids will have a low

number of gamma ray counts.

Radioactive Tracers and G amma ray detectorsThe tracer survey is one of the best available methods for recording fluid movement

quantitatively in water injection wells, and particularly for locating flow behind pipe. The tracers

are however less effective in monitoring multiphase flow from production wells or where surface

contamination by tracers being produced back to surface may be an issue. For water injection

well surveys, radioiodine in water (iodine I-131) is most commonly used since it has a short half-

life (8.1 days) and is miscible in water. The Geiger Mueller tube is the preferred detector for

through-tubing applications since it is more rugged than the scintillation detector, although less

sensitive.

Figure 14: Schematic showing how the gamma ray density deviceis used to determine fluid density (Courtest Sondex PLT)


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Ejector-type through-tubing tools such as the one shown above are used. A small slug of

radioactive liquid isotope is ejected through the port, and the time taken to travel from the

ejector to detector, or between two detectors is measured. By positioning the tool at several

depths and ejecting small slugs, a fluid velocity log can be made.

Accuracy is good in the high and medium flow velocity ranges, but at lower rates the slow

movement of the slug makes it difficult to determine arrival time. However, even at low rate,

resolution and accuracy is much better than with mechanical spinners.

The rate of disappearance of the tracer into a zone is also an indication of the volume of water

going into that zone.

Figure 15: Typical radioactive tracer-detector toolconfiguration for velocity-shot measurements(Allen &

Roberts, OGCI Tulsa, 1982)


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Pulse N eutron Capture Logging and O xygen ActivationThe pulsed neutron capture log is a cased-hole log primarily used to evaluate porosity, water

saturation during different stages of production, and to detect gas bearing zones. This technique

requires a formation water salinity of at least 50,000 ppm and porosities greater than 15%. As

such the pulsed neutron device has several production logging applications which will bediscussed later.

Operating PrincipleP ulsed neutron capture logging tools are typically small-diameter through-tubing tools which are

1 11/16 or less in diameter. The tool consists of an electronically activated neutron generator,

and two detectors, one near, and the other a far detector. The generator periodically emits

bursts of high energy (14 MEV) neutrons every 1000 s or less depending on the Service

Company, and tool model. The detectors used are the typical sodium iodide crystal scintillation

detectors which do not discriminate between the sources of gamma ray energies. As a result

the tool also measures background count rate to distinguish natural from induced gamma rays.

Figure 16: Configuration of the Pulsed NeutronTool (http://oilandgastraining.net)


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N eutron Capture Theory After the pulsed neutron tool emits a burst of high-energy neutrons, these neutrons immediately

move into the wellbore and formation, and quickly lose most of their energy eventually slowing

down to the thermal state. These lower energy thermal neutrons are then captured by the

formation and the fluids contained within its pore spaces. Each time a neutron is captured; agamma ray is released and is detected by the tool. The measure of their ability to capture these

neutrons is called the capture cross section denoted by sigma ( The higher the capture cross

section, the greater the tendency for the atom or molecule to capture the neutrons. The count

rate of these gamma rays indicates the rate of neutron population decay. Gamma ray count rate

and the rate of neutron decay yield a measurement of neutron capture cross-section of the

formation.

The neutron population decays exponentially according to the equation,

Where: N = thermal neutron density at a point in the formation

= initial thermal neutron density at time

t = time since

= thermal decay time (TDT) of the formation.

Figure 17: Plot of gamma ray count rate versus time after neutron burst(http://oilandgastraining.net)


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The P ulsed neutron capture tool is essentially a thermal decay time (TDT) device, since it

measures the time taken for the neutron population to decrease to 65% of its original

population.

For purposes of interpretation, the thermal neutron capture cross section expressed in capture

units (cu) is used: =

Chlorine has a very high capacity to capture thermal neutrons; hence thermal neutron decay

rate will be high if chlorine is present. Since chlorine is primarily associated with formation

water, porous zones with low decay rates or low capture cross-section should be hydrocarbon

zones. Identification of hydrocarbon zones becomes increasingly difficult with lower salinities,

lower porosity, and higher clay content.

Evaluation of Water Saturation (S w) behind casingThe simplest model of the formation for purposes of pulsed neutron capture logging is shown

below:

The capture cross-section of a formation, as recorded on the log, is the sum of the capture

cross-sections of each component weighted by their fractional volumes as follows:

Figure 18: Simple formation model(http://oilandgastraining.net)


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log = (1 V sh - ) +

This basic equation can be rearranged, to calculate water saturation directly from the recorded

value of log .

For clean shale free formations, the equation is simplified to:

To solve this equation, six parameters are needed:

y and at every depth. P orosity can be obtained from the neutron porosity and density

porosity logs, or sonic log. Shale content can be obtained from the Gamma ray log and a

simple calculation.

V sh = 0.33(2 (2xIGR) 1) for pre-tertiary (consolidated) rock

V sh = 0.083(2 (3.7xIGR) 1) for Tertiary (unconsolidated) rocks:

.

y Capture cross-sections for matrix, shale, hydrocarbon, and water. These are usually

constant over some depth interval. These values are obtained by direct measurement,

crossplots, or estimated from log values in nearby zones.

Factors affecting log interpretationy Invasion The TDT device has a relatively shallow depth of investigation (10 to 15 in).

Therefore fluids in the invaded zone would influence the capture cross-section

measurement, which would increase or decrease S w depending on the type of the mud

filtrate.y Lithology - Matrix rock salt or other minerals with a high capture cross-section will cause

high values, and therefore high Sw.


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Applications of Pulsed N eutron Capture Logs1. Evaluation of Water Saturation Through Casing can be used to check for bypassed

production in the producing level, or to locate other zones for possible completion.

2. Time-Lapse Logging This technique is used to monitor changes in saturation, and

movements of gas-oil or water-oil contacts, which can be predictive of breakthrough or depletion.

3. Oxygen-Activation Detects water movement past the logging tool. When the neutron

burst occurs, oxygen present in the water molecules becomes activated to unstable

isotope with a half-life of approximately seven (7) seconds. As this isotope returns to its

normal state, gamma rays are emitted which may be detected by the near and far

background count rate measurement.

The figure above shows the activated oxygen population as a bell shaped curve whose area is

decaying as the water flows up past the detectors. This techniques only works for the tool

logged in an upward direction.

Through-Tubing N eutron LogUsed for monitoring gas movement into oil zones. Gas has a lower hydrogen index on the

neutron log; therefore by comparing neutron logs run through tubing during the producing life of

the well, gas invaded zones can be identified since they would show a high count rate. Logs

Figure 19: Diagram showing oxygen activationas water flows past the detectors


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must be run with the well shut in because the neutron device is not compensated for borehole

fluid movement effects.

Down-hole Video Camera and B orehole LoggingThis is one of the easiest and most basic methods of detecting fluid movement in a well, yet one

of the most expensive methods.

Logging P rocedure:

y A metal centralizer is placed on the camera, and diameter adjusted to suit the wellbore

diameter

y Silicon grease is placed on the O-ring at the end of the cable head, and the camera

rotated onto it

y The camera is then suspended over the well using an extended arm mast

y The winch control system is turned on

y The camera control system is powered on

y The camera lens is then lowered to the desired depth

y The camera survey is run over the desired depth interval in VCR mode

y Camera is then removed from borehole.

Combination ToolsService companies usually run combinations of these tools/devices in one combination tool

string. This reduces:

y Operating/Logging Time

y Reduced time to restabilize the well if several flow rates are used

y Down time

y Cost

It also provides a means of correlation, as well as confirmation of different measurements. Italso increases the chance of making several runs before well flowing conditions change in

unstable wells.


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Schlumberger Production Combination ToolThis tool combines the high resolution thermometer, gradiomanometer, continuous or fullbore

flowmeter, caliper, manometer, and a collar locator into one device to permit making the five

surveys on one run in the hole. The tool also permits all recording to be made digitally at the

same time.

Figure 20: Composite Production Log Example 1 (Courtesy Sondex)


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In figure 20, the spinner flowmeter logs give the inflow profile, while the density and fluid

capacitance logs indicate a mixture of oil and water at different depths. The curves show high

turbulence as is expected from a flowing mixture of oil and water. The temperature curve

indicates the points of inflow. The spinner curves show fast fluid entry, jetting effect, at 11,680

which corresponds to a high permeability layer.



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This is an interpretation of a well flowing gas, oil and water. Although the well has several

zones, the interpretation shows that a single reservoir exists with gas at the top, oil in the

middle, and water at the bottom. First the flowmeter is used to determine the bulk flowrate, then

the capacitance tool is used to determine the water holdup (fraction) in the well, and finally

knowing the water holdup, we can use density data to determine the oil and gas holdups. At the

top of the well there is a drastic reduction in fluid density, which is confirmed as the point of gas

entry into the wellbore. There is also a reduction in temperature at the top, caused by the

cooling effect of gas expansion. The capacitance also increases significantly at the bottominterval; therefore this must be a water zone since water has a high dielectric constant.

G as Well Deliverability Testing A complete analysis of a flowing gas well test should allow determination of the following:

1) A productivity indicator known as the Absolute Open-flow P otential (AOF P ). This is the

maximum rate at which a well can flow against a theoretical atmospheric backpressure

at the sandface. In practice the well cannot produce at this rate, and the AOF P is usedby regulatory bodies to limit the production rate of oil and gas companies.

2) Reservoir inflow performance relationship (I P R) or gas backpressure curve. The I P R

curve describes the relationship between surface production rate and bottom-hole

flowing pressures ( P wf) for a specific value of reservoir pressure i.e. either the original

reservoir pressure or the current average value. The I P R can be used to forecast future



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production at any stage in the reservoirs life. These rate forecasts are needed in the

preparation of field development programs, in the design of processing plants, and in the

negotiation of gas sales contracts.

3) Stabilized shut-in reservoir pressure.

In early gas well testing, the wells were opened to the atmospheric pressure and allowed to

flow, the AOF P was then determined using impact pressure gauges. P redicting rate based on

such tests is useful for shallow wells, but is highly inaccurate for deeper wells producing through

small tubing strings. Because of the inaccuracy, the danger associated with limited well control,

and the large amount of gas flaring which was both a wastage and environmental problem, this

testing practice has been largely discontinued. Modern gas well testing utilizes controlled and

reasonable flowrates, which can yield the equivalent of an AOF P .

The three most common types of gas well deliverability tests are:

y Flow-after-flow or Conventional backpressure test

y Isochronal test

y Modified isochronal test

Flow-after-flow test 1. The well is shut-in until a stabilized bottom-hole shut in pressure is obtained.

2. The well is opened to flow at a selected constant rate until bottom-hole flowing pressure

(P wf) stabilizes.

3. The stabilized flow rate and P wf are recorded

4. The flowrate is then increased by using a larger choke size, and the well allowed to flow

until pressure stabilizes at this new rate.

5. The stabilized flow rate and P wf are again recorded.

6. The process is the repeated for a total of 4 to 5 rates.

The pressure is measured by using a bottomhole pressure gauge, and each flowrate is

established in succession without an immediate shut-in period.


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I sochronal test The objective is to obtain data to establish a stabilized deliverability curve for a gas well, but

without flowing the well for long periods to achieve stabilized flow conditions. This is often

necessary for low permeability reservoirs, because it saves time and money.

1. The well is allowed to produce at a known constant rate for a set time period and the

flowing bottom-hole pressure recorded.

2. The well is then shut in and P wf allowed to build up to the average reservoir pressure.

3. The well is then allowed to produce at a higher flow rate for the same time period as the

first flow rate, and the bottom-hole pressure is again recorded.

4. The well is shut in again and P wf allowed to build up to the average reservoir pressure.

5. The procedure is repeated for 3 to 4 stabilized rates.6. The well is allowed to flow for an extended period.

The exact length of time of the flow periods is not important as long as they are all the same.

Figure 23: Rates and pressures in flow-after-flow test (Lee, 1996)

Figure 24: Flow-rate and pressure diagrams for an isochronal test of a gas well (Lee, 1996)


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M odified I sochronal test The objective of this test is to obtain the same information as in an isochronal test but without

the same lengthy shut in periods required. The flow periods are of equal duration, and the shut

in periods are of equal duration; but not necessarily the same as the flow periods. Shut-in

bottom-hole pressure is not allowed to build up to the stabilized shut in pressure after each flowperiod.

Analysis of Conventional backpressure tests

Rawlins and Schellhardt Eq uationThe relationship is expressed as:

Therefore a log-log plot of gives a straight line with slope = and intercept = -

1/n logC

The AOF P may be determined directly from the graph or this equation:

Figure 25: Flow rate and pressure diagrams for modified isochronal tests ongas wells (Lee, 1996)


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Where n is called the deliverability exponent, and is 1/m, where m = ( P 2 - P 1)/(q 2 q 1) and C =10 -(n x intercept)

O il Well Deliverability Testing

Oil well deliverability testing allows us to determine Inflow P erformance Relationship which isused to:

y Forecast production at any stage in the life of the well.

y Determine how production will change for a particular drawdown.

y Determine q omax or absolute open-flow potential.

y Monitor how production changes with tubing sizes.

y Monitor production changes after stimulation.

IP R is needed before a well is completed to:

y Determine tubing size

y Design completions e.g. S P F

y Decide if stimulation is needed

y Estimate inflow to size equipment

Figure 26: Empirical flow-after-flow analysis (Lee, 1996)


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Productivity I nde x, P I This is a measure of the ability of a well to produce. It is defines by the symbol, J, and is the

ratio of the total oil flowrate to the pressure drawdown required to achieve that flowrate.

Rate Pressure Relations

For Under-saturated Oil WellsReservoir pressure (P r) is greater than the bubble-point pressure (P b), no free gas phase, only solutiongas.

Single test point,

Single test point at

Figure 27: Inflow Performance Relationship for an Undersaturated reservoir


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Saturated Oil WellsPr < Pb, free gas phase, plus gas in solution

=

Figure 28: Inflow Performance Relationship for a Saturated reservoir

Figure 29: IPR and TPC showing how changes in tubing size or stimulation affectsproduction rate


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Sampling Techni q ues

Drill Stem TestingDrill stem testing is done on newly drilled exploratory wells to determine whether the well should

be completed for production, or plugged and abandoned. It is done to basically determine the

potential of a producing formation, and involves simultaneously recording the formation

pressure while taking samples of pristine formation fluid.

A typical drill stem test is usually split into four periods:

1. P re-Flow P eriod this is a period of production to allow wellbore cleanup. It is used to

remove any super charged given to the formation due to mud infiltrating into the

prospective formation during the drilling operation.

2. Initial Shut In P eriod allows the formation to recover from pressure surges caused

during the pre-flow period. P ressure is allowed to build up.

3. Main Flow P eriod this is a more lengthy production period than the pre-flow period. It is

designed to test the formation flow characteristics more rigorously. Flowing pressures

and temperatures are recorded, and fluid samples are taken to the laboratory for P VT

analysis.

4. Final Shut-In P eriod formation pressure is recorded over this period. By analysis of the

pressure build-up curve, formation permeability, and degree of formation damage can be

determined. It can also tell us if we have found a small reservoir.

Drill Stem testing procedure:

1. The test tool is made up on the bottom of the drill pipe. The bottom assembly consists of

one or more isolating packers, and a surface operated valve.

2. The DST valve is then closed and the drill string is run into the well to the desired testing

depth.

3. Weight is applied to the tool to expand the packer so as to isolate the desired formation

zone from the column of mud.

4. The control valve is opened and formation fluids are allowed to enter the drill pipe.


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5. Records of flowing bottom-hole pressure and temperature are made and fluid samples

taken.

Repeat Formation Tester (RFT)The repeat formation tester is a logging type device which allows confirmation of formation fluid,

indications of productivity, and formation pressure. The tool design essentially consists of:

y A packer which can be forced against the wall of the borehole to isolate the mud column.

y A hydraulic piston used to create pressure drawdown.

y Two sample chambers (usually of 2 gal capacity) to collect formation fluid samples.

During one trip in the hole, any amount of formation pressure measurements can be made in

different zones. Using the piston to create the drawdown, two fluid samples can be obtained

simultaneously in promising zones.

Figure 30: Schematic of the Drill Stem test tool


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The pretest chambers provide an indication of whether or not a packer seal has been obtained,

and if it has, then an estimate of flow rate from the zone. P ressures are recorded during flow

and build-up. Build-up occurs very rapidly in high permeability zones.

Figure 31: Schematic of the Schlumberger RFT (Allen & Robert,1982)


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References[1] Allen, T. and Roberts, A., P roduction Operations Volume 1, 2 nd Ed. Oil & Gas Consultants

International, Inc., Tulsa, 1982.

[2] Sondex P roduction Logging Tools User Guide, Sondex Wireline Ltd., 2006.

[3] Faber, B. Msc, P roduction Logging Measurements and Interpretation, Well Log Analysis

Centre, Geofizyka Toru Sp. z o.o.

[4] John, L. and Wattenbarger, R.A., Gas Reservoir Engineering, Society of P etroleum

Engineers Inc., 1996.

[5] Crowder, R.E. and Mitchell, K., Spinner Flowmeter Logging A Combination of Borehole

Geophysics and Hydraulics

Documents

39532154 Production Logging Techniques