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UNIVERSITY OF TRINIDAD & TOBAGOUNIVERSITY OF TRINIDAD & TOBAGO
MENG PETROLEUM ENGINEERINGMENG PETROLEUM ENGINEERING
NAME: NAME: CEDRIC KIMLOAZCEDRIC KIMLOAZ
ID#: ID#: 107000908107000908
COURSE CODE: COURSE CODE: PROD 410BPROD 410B
COURSE NAME:COURSE NAME:
PRODUCTION ENGINEERING IIPRODUCTION ENGINEERING II
TOPIC:TOPIC:
Production Surveillance TechniquesProduction Surveillance Techniques
DATE SUMBITTED: DATE SUMBITTED: 11/10/1011/10/10
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....................................................................................................................................18
Summary 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 (Sw) behind casing................................................................................28
Factors affecting log interpretation...................................................................................................29
Applications of Pulsed Neutron Capture Logs.......................................................................................30
Through-Tubing Neutron Log....................................................................................................................30
Down-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)..............................................................................................................42
References.................................................................................................................................................44
Table of Figures
Figure 1: Percentage breakdown of 100 random Production Logging operations and the main reasons for the job. (Courtesy Sondex Production Logging Tool string).........................................................................8Figure 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)...............................................................19Figure 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)........................................................32Figure 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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Executive Summary
Production 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:
Temperature
Pressure
Fluid Density
Fluid Velocity
Neutron Capture Capability (Photoelectric Absorption Capacity)
Radioactivity
Sound Transmission Characteristics
Electrical Properties 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 Potential
(AOFP). It is also shown how the values of surface production rate and bottom-hole flowing
pressure can be used to generate an Inflow Performance Relationship (IPR) for both oil and gas
wells. The IPR curve can be used to predict future production at any stage in the reservoir’s life,
as well as how production is influenced by changes in drawdown, tubing size, or by stimulation.
The Productivity Index test for oil wells, which is the simplest form of Deliverability test is
mentioned. Transient pressure analysis is not considered a Production 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
5
permeability formation, or the presence of skin damage. As such the decision can then be made
whether to acidize, hydraulically fracture, or plug and abandonment the well. Economics is
usually a major driving force in such decision making. Production 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.
6
IntroductionProduction Logging Tools (PLT) 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. Production logs are application in three (3) major areas:
Diagnosis of mechanical problems
Analysis of individual well performance in relation to the reservoir
Management of reservoir fluids.
Production Log data can be interpreted to help indentify some of the following production
problems:
Mechanical Condition of the Well
Casing, tubing, or packer leaks
Corrosion damage
Collapsed casing
Wellbore restrictions
Anomalous Fluid Movements Between Zones
Fluid flow behind casing (channelling) due to poor primary cement job.
Fluid flow into thief zones.
Evaluation of Completion Efficiency (Producing Well)
Negligible or no contribution from some zones
Zones contributing only water or gas, when oil is expected
Zones producing below their potential as forecasted by other data sources
Location of perforations or points of fluid entry
Evaluation of Completion Efficiency (Injection Well)
Indentify zones to which the injected fluid is entering
Quantify of injected fluid entering zone(s)
Design and Evaluation of Stimulation Treatment
Indentify zones requiring stimulation
Zones to which stimulation fluid is entering
Monitor reservoir performance after stimulation
Reservoir Management
Initial fluid saturations in each zone
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Saturation changes due to production or extraneous fluid movement
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
Production Profiling To profile the well to check how it is performing against expectations.
Injection Profiling To determine the injection profile of a water or gas injection well.
Excessive gas Problems Gas coning which limits the flow of oil. Locating the source of gas production is important when planning remedial work in these wells.
Water Problems The majority of production logging jobs is performed because large volumes of unwanted water are produced. Water production is very expensive since it limits the production of hydrocarbons, and has to be treated and disposed of safely. Locating the source of water entry is essential when planning remedial work such as a squeeze cement job.
Mechanical Problems Holes in tubing, packers, or casing can be located. Blocked perforations can also be identified.
8
Figure 1: Percentage breakdown of 100 random Production Logging operations and the main reasons for the job. (Courtesy Sondex Production Logging Tool string)
Production 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 Production Logging. Some production logging tools can
also be run in open-hole, however due to rate control, sand, and water problems typically
associated 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 350°F.
The most significant production logging tools in use today are:
Bottom-hole pressure device
Quartz Pressure Single (QPS)
Temperature devices
High resolution thermometer
Radial differential temperature device
Noise device
Noise Log - usually run in conjunction with a temperature log
Spinner flowmeters
Inflatable packer flowmeter
Continuous flowmeter
Fullbore flowmeter
Basket flowmeter
Diverter flowmeter
Fluid Density Devices
Gradiomanometer
Gamma ray density device
Radioactive tracers and Gamma ray detectors
Pulse Neutron devices
Pulse Neutron Capture Logging & Oxygen Activation
9
Gamma ray neutron devices
Through-Tubing Neutron Log
Slim hole cameras
Peripherals run in conjunction with the main Production Logging Tools:
Casing Collar Locator (CCL)
Gamma Ray Tool
Caliper
Centralizer
Casing Collar Locator The 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.
10
Figure 2: Schematic of the CCL Tool (Allen & Roberts, OGCI Tulsa, 1982)
11
Figure 3: Typical collar record showing the corresponding "blips" (M.L. Connell & R.G. Howard, Halliburton Energy Services)
Gamma Ray Measures 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 very
small so a photomultiplier tube (PMT) 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 PMT requires a high voltage power supply to
amplify the photons of light.
Bottom-hole pressure GaugesA 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 OperationA 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 pressure
after 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
12
Figure 4: Schematic of the Gamma Ray Tool (Courtesy Sondex PLT)
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 Logging The 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 all
consist 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:
To determine which intervals are producing
How much they are producing
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.
13
Figure 5: Cross-section of the Quartz Pressure Single Gauge (Courtesy Sondex PLT)
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:
Covers more of the well and shows the precise location where flow enters or exits.
Data is collected faster; therefore head conditions are more nearly constant during the
test.
Flow test resolution is increased
Dynamic measurements are less prone to depth errors.
Static spinner tests are however easier to quantify because correction for logging speed is not
required. 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 bpd
in 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 tools
utilizes 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 ½” 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
14
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 the
spinner. It is the most precise flow measuring device, with an upper limit of 400 bpd in
5½” 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:
Viscosity of the wellbore fluid, with gas bubbles being especially bad.
Density and density changes in the wellbore fluid.
Debris (grease, scale, sand, etc) in the well.
15
Figure 6: Diagram showing the basic configurations of the main types of spinner flowmeters
Spinner position in the well.
Variable logging speed.
Flow direction past the impeller.
Diameter changes (rugosity) in the well.
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 LogA 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 (Potential difference) across the probe. This differential
voltage 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.
16
Figure 7: Schematic of the high resolution thermometer (Allen & Roberts, OGCI Tulsa, 1982)
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 the
temperature 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.
17
Figure 8: Lithological influence on static temperature gradient (Allen & Roberts, OGCI Tulsa, 1982)
Noise/Acoustic LogA 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:
The presence of flow.
The path of the flow.
Fluid phases involved.
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: Detection of channels in the cement sheath for gas influx
Measure flowrates
Identify open perforations
Detect sand production
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.
18
Tool DescriptionA 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.
19
Figure 9: Schematic of Noise Logging Tool (Allen & Roberts, OGCI Tulsa, 1982)
Figure 10: Noise Spectrum (Allen & Roberts, OGCI Tulsa, 1982)
Analysis/Interpretation These 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:
At a differential pressure above 100 psi, most of sonic energy above 1000 Hz is created
by gas movement.
Single phase liquid movement creates more energy below 1000 Hz.
Two phase flow usually creates a peak in the 200-600 Hz band, particularly with gas
moving through a liquid filled channel.
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.
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).
20
Figure 11: Change in transmission medium within the wellbore (Allen & Roberts, OGCI Tulsa, 1982)
Logging Procedure The well is open to stabilized flow.
The tool string is lowered to the bottom of the wellbore, while at the same time recording
a flowing temperature survey.
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.
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.
Gradiomanometer The 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 = ρg (h2 – h1). 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.
21
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: ¿ y
w=ρt−ρ
o
ρw−ρo
ρt=apparent fluid density, ρo=oil density ,∧ρw=water density
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, vs, which is the difference
between the oil stream and water stream velocities (vo - vw). If the velocity of the total flow
stream, q t, is obtained via a flowmeter measurement, then the oil and water flowrates moving at
any level can be determined from:qo=¿¿ (1− yw )(q t+vs A y w)
qw= yw [q t−A vs (1− y w) ]
22
Figure 12: Vertical section of a typical Gradiomanometer (Allen & Roberts, OGCI Tulsa, 1982)
Where,
qo∧qw are in bpd
A=1.4 (ID csg2 −OD tool
2 )
vs=slippage velocity∈ft /min
Since the oil rate and water rate at different levels can be calculated, the zone contributing
water can easily be identified.
Gamma 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 a
window 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).
23
Figure 13: Empirical chart for determining slippage velocity (Courtesy Schlumberger)
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 Gamma 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.
24
Figure 14: Schematic showing how the gamma ray density device is used to determine fluid density (Courtest Sondex PLT)
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.
25
Figure 15: Typical radioactive tracer-detector tool configuration for velocity-shot measurements(Allen &
Roberts, OGCI Tulsa, 1982)
Pulse Neutron Capture Logging and Oxygen 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 be
discussed later.
Operating PrinciplePulsed 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 µs 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.
26
Figure 16: Configuration of the Pulsed Neutron Tool (http://oilandgastraining.net)
Neutron Capture TheoryAfter 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; a
gamma 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 (Σ ¿ . 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, N=N o e−t /τ
Where: N = thermal neutron density at a point in the formation
No= initial thermal neutron density at time t o
t = time since t o
τ = thermal decay time (TDT) of the formation.
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Figure 17: Plot of gamma ray count rate versus time after neutron burst (http://oilandgastraining.net)
The Pulsed 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: 𝜮 = 4550
τ
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 (Sw) 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:
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Figure 18: Simple formation model (http://oilandgastraining.net)
𝜮log = (1 – Vsh -∅ )Σma + ∅ ( 1−Sw ) Σh+∅ Sw Σw+V s h Σs h
This basic equation can be rearranged, to calculate water saturation directly from the recorded
value of 𝜮log.
Sw=¿¿
For clean shale free formations, the equation is simplified to:
Sw=¿¿
To solve this equation, six parameters are needed:
∅ and V s h at every depth. Porosity 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.
Vsh = 0.33(2(2xIGR) – 1) for pre-tertiary (consolidated) rock
Vsh = 0.083(2(3.7xIGR) –1) for Tertiary (unconsolidated) rocks:
I GR=GRlog−GRcs
GRs h−GRcs
.
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 interpretation 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 Sw depending on the type of the mud
filtrate.
Lithology - Matrix rock salt or other minerals with a high capture cross-section will cause
high 𝜮 values, and therefore high Sw.
Applications of Pulsed Neutron 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.
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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 Neutron 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
must be run with the well shut in because the neutron device is not compensated for borehole
fluid movement effects.
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Figure 19: Diagram showing oxygen activation as water flows past the detectors
Down-hole Video Camera and Borehole 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 Procedure:
A metal centralizer is placed on the camera, and diameter adjusted to suit the wellbore
diameter
Silicon grease is placed on the O-ring at the end of the cable head, and the camera
rotated onto it
The camera is then suspended over the well using an extended arm mast
The winch control system is turned on
The camera control system is powered on
The camera lens is then lowered to the desired depth
The camera survey is run over the desired depth interval in VCR mode
Camera is then removed from borehole.
Combination ToolsService companies usually run combinations of these tools/devices in one combination tool
string. This reduces:
Operating/Logging Time
Reduced time to restabilize the well if several flow rates are used
Down time
Cost
It also provides a means of correlation, as well as confirmation of different measurements. It
also increases the chance of making several runs before well flowing conditions change in
unstable wells.
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
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surveys on one run in the hole. The tool also permits all recording to be made digitally at the
same time.
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Figure 20: Composite Production Log Example 1 (Courtesy Sondex)
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.
33
Figure 21: Composite Production Log Example 2 (Courtesy Sondex)
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 bottom interval; therefore this
must be a water zone since water has a high dielectric constant.
Gas Well Deliverability TestingA complete analysis of a flowing gas well test should allow determination of the following:
1) A productivity indicator known as the Absolute Open-flow Potential (AOFP). 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 AOFP is used
by regulatory bodies to limit the production rate of oil and gas companies.
2) Reservoir inflow performance relationship (IPR) or gas backpressure curve. The IPR
curve describes the relationship between surface production rate and bottom-hole
flowing pressures (Pwf) for a specific value of reservoir pressure i.e. either the original
reservoir pressure or the current average value. The IPR can be used to forecast future
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Figure 22: Composite Production Log Example 3 (Courtesy Sondex)
production at any stage in the reservoir’s 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 AOFP was then determined using impact pressure gauges. Predicting 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 AOFP.
The three most common types of gas well deliverability tests are:
Flow-after-flow or Conventional backpressure test
Isochronal test
Modified isochronal test
Flow-after-flow test1. 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
(Pwf) stabilizes.
3. The stabilized flow rate and Pwf 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 Pwf 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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Isochronal testThe 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 Pwf 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 Pwf 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.
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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)
Modified Isochronal testThe 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 flow
period.
Analysis of Conventional backpressure tests
Rawlins and Schellhardt EquationThe relationship is expressed as:
qsc=C(P r2−Pwf
2 )n=C(∆ P2)n
log qsc=log C+nlog (Pr2−Pwf
2 )
nlog (Pr2−Pwf
2 )=log qsc−logC
log (P r2−Pwf
2 )=1n
log qsc−1n
logC
Therefore a log-log plot of (∆ P)2 against qsc gives a straight line with slope = 1n
and intercept = -
1/n logC
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Figure 25: Flow rate and pressure diagrams for modified isochronal tests on gas wells (Lee, 1996)
The AOFP may be determined directly from the graph or this equation: q AOF=C [P r2−Pb
2]n
Where n is called the deliverability exponent, and is 1/m, where m = ( ∆P2 -∆P1)/(q2 –q1) and C = 10-(n x intercept)
Pb=sand face pressure=14.7 psia
Oil Well Deliverability TestingOil well deliverability testing allows us to determine Inflow Performance Relationship which is
used to:
Forecast production at any stage in the life of the well.
Determine how production will change for a particular drawdown.
Determine qomax or absolute open-flow potential.
Monitor how production changes with tubing sizes.
Monitor production changes after stimulation.
IPR is needed before a well is completed to:
Determine tubing size
Design completions e.g. SPF
Decide if stimulation is needed
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Figure 26: Empirical flow-after-flow analysis (Lee, 1996)
Estimate inflow to size equipment
Productivity Index, PIThis 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 (Pr) is greater than the bubble-point pressure (Pb), no free gas phase, only solution gas.
Single test point, Ptest>Pb
Jo=q test
PR−Ptest
Single test point at Ptest<Pb
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Figure 27: Inflow Performance Relationship for an Undersaturated reservoir
Jo=qtest
( PR−Pb )+PR
1.8[1−0.2 R−0.8 R2]
Saturated Oil WellsPr < Pb, free gas phase, plus gas in solution
qo=Jo
PR
1.8[1−0.2 R−0.8 R2]
R=Pwf
PR
Jo=productivity index at zero drawdown
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Figure 28: Inflow Performance Relationship for a Saturated reservoir
Figure 29: IPR and TPC showing how changes in tubing size or stimulation affects production rate
Sampling Techniques
Drill Stem Testing Drill 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. Pre-Flow Period – 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 Period – allows the formation to recover from pressure surges caused
during the pre-flow period. Pressure is allowed to build up.
3. Main Flow Period – 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 PVT
analysis.
4. Final Shut-In Period – 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:
A packer which can be forced against the wall of the borehole to isolate the mud column.
A hydraulic piston used to create pressure drawdown.
Two sample chambers (usually of 2 ¾ 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.
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Figure 30: Schematic of the Drill Stem test tool
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. Pressures are recorded during flow and build-up. Build-up occurs very
rapidly in high permeability zones.
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Figure 31: Schematic of the Schlumberger RFT (Allen & Robert, 1982)
References[1] Allen, T. and Roberts, A., Production Operations Volume 1, 2nd Ed. Oil & Gas Consultants
International, Inc., Tulsa, 1982.
[2] Sondex Production Logging Tools User Guide, Sondex Wireline Ltd., 2006.
[3] Faber, B. Msc, “Production Logging – Measurements and Interpretation”, Well Log Analysis
Centre, Geofizyka Toruń Sp. z o.o.
[4] John, L. and Wattenbarger, R.A., Gas Reservoir Engineering, Society of Petroleum
Engineers Inc., 1996.
[5] Crowder, R.E. and Mitchell, K., ‘Spinner Flowmeter Logging – A Combination of Borehole
Geophysics and Hydraulics’
44
