Water Management Manual

identification and treatmentof water-control problemsfor improved reservoir recovery efficiency

WATERMANAGEMENT

WATER MANAGEMENT MANUAL

CONTENTS

• Introduction

• Table of Contents

• Conformance Problems

• Data Collection

• Testing Methods and Equipment

• Computer Programs

• Treatment Options

• Placement Techniques and Equipment

• Conformance Treatment Evaluations

Introduction 0-1

IntroductionWhat Is ConformanceTechnology?Conformance Technology is theapplication of processes to reservoirsand boreholes to reduce waterproduction, enhance recovery effi-ciency, or satisfy a broad range ofreservoir management and environ-mental objectives. Although the use ofconformance processes may not resultin increased production, such pro-cesses can often improve anoperator’s profitability as a result ofthe following benefits:

• longer productive well life

• reduced lifting costs

• reduced environmentalconcerns and costs

• minimized treatment anddisposal of water

• reduced well maintenance costs

Ideally, conformance control shouldbe performed before a condition canresult in serious damage. As withpersonal health, treating potentialproblems before they become seriousis considerably less costly thanallowing a condition to deteriorateuntil drastic actions must be taken.For example, just as changing lifestylehabits can reduce a person’s risk ofheart disease, treating a well’spotential coning problem may preventit from “bottoming out” in the future.

The ConformanceControl ProcessThe first step in effective conform-ance control is understandingpotential conformance problems.Chapter 1 of this book reviews thecharacteristics of correct reservoirbehavior and identifies both near-wellbore and reservoir-relatedconformance problems.

Historically, operators assessed theproduction of unwanted fluids basedon individual wells. Recent experi-ence, however, suggests that reservoirdescriptions and reservoir evaluationscan often provide valuable informa-tion that may result in more effectiveconformance control. Chapter 2explains the principles of reservoirdescription and reservoir evaluationand provides information regardingstatic and dynamic reservoir proper-ties and how these properties canaffect the design of typical conform-ance treatments.

Before an effective conformancetreatment can be designed, theconformance problem must bethoroughly examined. Chapter 3provides information regarding theproduction logs, cement logs,reservoir monitoring tools,downhole video equipment, andtracer surveys used for problemprediction, problem identification,and treatment evaluation.

ConformanceTechnology

CONFORMANCE TECHNOLOGY

0-2 Introduction

A simulator, such as the QuikLook simulator, can be usedto help optimize the design of a conformance treatmentand evaluate the chosen solution. A tool that can provideassistance during the diagnosis and treatment selectionphases is Halliburton’s XERO water-control expertsystem. This PC-based program uses artificial intelli-gence techniques to identify the problem, select theproper fluid system for treating the problem, and recom-mend treatment designs based on the identified problemand built-in engineering calculations. Chapter 4 providesa detailed description of the QuikLook simulator and theXERO system.

When a conformance problem is identified, engineersshould choose an appropriate chemical system to treat theproblem. Chapter 5 provides more specific informationabout water-based polymer systems and diesel systems.

When a chemical system has been selected, designersmust focus their attention on selecting the appropriateplacement techniques and equipment. Chapter 6 de-scribes various placement techniques as well as thepumping, mixing, monitoring, and filtering systemstypically used for conformance control. This chapter alsoprovides information regarding the use of coiled tubing,which is becoming a popular alternative to the traditionalworkover rig.

After a treatment has been performed, engineers canperform several tests to monitor the treatment’s success.Chapter 7 briefly summarizes treatment evaluationmethods.

Contents i

HALLIBURTON

Contents

Introduction–Conformance Technology ............................................................. 0-1

What Is Conformance Technology?........................................................................ 0-1The Conformance Control Process ........................................................................ 0-1

Chapter 1–Conformance Problems .................................................................... 1-1

Recovery Mechanisms ........................................................................................... 1-1Primary Recovery ........................................................................................... 1-1Depletion (Solution Gas) Drive .................................................................................................. 1-1Segregation Drive without Counterflow ..................................................................................... 1-1Gravity Drainage (Segregation Drive with Counterflow) ............................................................ 1-2Waterdrive ................................................................................................................................. 1-2Secondary Recovery ...................................................................................... 1-3Water-Injection Pressure Maintenance...................................................................................... 1-3Gas-Injection Pressure Maintenance ........................................................................................ 1-3

Problem Sources .................................................................................................... 1-3Near-Wellbore Problems ................................................................................ 1-3Casing Leaks ............................................................................................................................ 1-3Channels Behind Casing ........................................................................................................... 1-4Barrier Breakdown .................................................................................................................... 1-4Debris, Scale, and Bacteria ....................................................................................................... 1-5Completion Into or Near Water or Gas ...................................................................................... 1-5Reservoir-Related Problems .......................................................................... 1-5Coning and Cresting ................................................................................................................. 1-5Channeling Through Higher Permeability .................................................................................. 1-6Fingering ................................................................................................................................... 1-6Fracturing Out of Zone .............................................................................................................. 1-6Fracture Communication Between Injector and Producer.......................................................... 1-6Lack of Communication Between Injector and Producer ........................................................... 1-6

Conclusions ............................................................................................................ 1-7Bibliography ............................................................................................................ 1-7


ii Contents

Chapter 2–Data Collection................................................................................... 2-1

Well Testing ............................................................................................................ 2-1Effect of Reservoir Nonidealities ................................................................... 2-1Faults and Barriers .................................................................................................................... 2-1Permeability Anisotropy ............................................................................................................. 2-2Well Tests for Vertical Permeability ............................................................... 2-2Vertical Interference and Pulse Tests ........................................................................................ 2-2Formation Testers...................................................................................................................... 2-2Layered Reservoirs ......................................................................................... 2-2Natural Fractures ............................................................................................ 2-2Multiple-Well Testing ....................................................................................... 2-3Interference Tests ...................................................................................................................... 2-3Pulse Tests ................................................................................................................................ 2-3

Reservoir Descriptions ........................................................................................... 2-3Reservoir Heterogeneity and Conformance ................................................. 2-4Solutions for Reservoir-Related Conformance Problems ........................... 2-7Coning and Cresting ................................................................................................................. 2-7High-Permeability Channeling ................................................................................................... 2-9Fingering ................................................................................................................................... 2-9Induced Fractures ..................................................................................................................... 2-9Natural Fractures ...................................................................................................................... 2-10Permeability Barriers ................................................................................................................. 2-10Development Planning ................................................................................... 2-10Field Development .................................................................................................................... 2-10Production Planning .................................................................................................................. 2-11

Reservoir Monitoring .............................................................................................. 2-11The Reservoir-Monitoring Process................................................................ 2-11Seismic Data Acquisition ........................................................................................................... 2-11Seismic Processing ................................................................................................................... 2-12Seismic Data Interpretation ....................................................................................................... 2-12Well Log Analysis ...................................................................................................................... 2-12Well Test Analysis ..................................................................................................................... 2-12Geologic Model ......................................................................................................................... 2-12Seismic Verification ................................................................................................................... 2-12Simulation Model-Building ......................................................................................................... 2-13Reservoir Fluid Saturation Distribution ...................................................................................... 2-13Example ........................................................................................................... 2-13


Contents iii

HALLIBURTON

Chapter 3–Testing Methods and Equipment ...................................................... 3-1

Fluorescent Dyes as Waterflood Tracers ................................................................ 3-1Acknowledgment ............................................................................................ 3-1Summary ......................................................................................................... 3-1Manual for Tracer Test Design and Evaluation ............................................. 3-2Abstract ..................................................................................................................................... 3-2Background Information ............................................................................................................ 3-2Information Necessary to Plan a Tracer Test ............................................................................. 3-3Calculation of Tracer Amounts ................................................................................................... 3-4Injection and Sampling .............................................................................................................. 3-5Chemical Analysis of Data ........................................................................................................ 3-6

Logging Methods .................................................................................................... 3-9FracPressure Analysis ................................................................................... 3-9TracerScan Analysis ....................................................................................... 3-9

Logging Services.................................................................................................... 3-9Openhole Logs ................................................................................................ 3-9Nuclear Magnetic Resonance ........................................................................ 3-15Cement Evaluation Logs ................................................................................ 3-17Conventional Bond-Logging Tools ............................................................................................. 3-17Ultrasonic Bond-Logging Tools .................................................................................................. 3-17Casing Evaluation Logs ................................................................................. 3-22Mechanical Logging Devices ..................................................................................................... 3-23Electromagnetic Phase-Shift Devices ....................................................................................... 3-24Ultrasonic Casing Tools ............................................................................................................. 3-26Pulsed Neutron Logs ................................................................................................................. 3-31Production Logging Tools .......................................................................................................... 3-41Downhole Video Services .............................................................................. 3-53Application in Oilwell Environments ........................................................................................... 3-53Detection of Fluid and Particulate Entry .................................................................................... 3-57Logging ..................................................................................................................................... 3-57Problem Identification and Remedial Treatment Planning .......................................................... 3-57In-Progress Monitoring .............................................................................................................. 3-57Post-Treatment Confirmation ..................................................................................................... 3-57Operating Limits ........................................................................................................................ 3-57Other Applications ..................................................................................................................... 3-58

Conclusions ............................................................................................................ 3-59


iv Contents

Chapter 4–Computer Programs .......................................................................... 61

Introduction ............................................................................................................ 4-1

QuikLook Simulator ................................................................................................ 4-1Purpose and Philosophy of QuikLook .......................................................... 4-2QuikLook Theory ............................................................................................. 4-3Conformance Fluids Modeled by QuikLook ................................................. 4-3WELLCAT Software......................................................................................... 4-3General Data Requirements ........................................................................... 4-4Validation of the QuikLook Simulator ........................................................... 4-4Example 1—First SPE Comparative Study ............................................................................... 4-4Example 2—Second SPE Comparative Study .......................................................................... 4-9QuikLook as a Conformance Simulator ........................................................ 4-13Case 1—Water Channeling in an Injector-Producer System (PermSeal Solution) ..................... 4-13Case 2—Water Coning of a Single Gas Producer (H2Zero and PermSeal Solutions) ................ 4-20Case 3—Water Coning of a Black-Oil Producer (PermSeal Solution) ....................................... 4-25

The XERO Program ............................................................................................... 4-31Phase 1–Problem Identification ..................................................................... 4-31Phase 2–Treatment Design ............................................................................ 4-39

Summary and Conclusions .................................................................................... 4-42References ............................................................................................................. 4-43

Chapter 5–Treatment Options ............................................................................. 5-1

Water-Based Polymer Systems .............................................................................. 5-2PermSeal Service ............................................................................................ 5-2PermTrol Service ............................................................................................. 5-3H2ZeroSM Service ............................................................................................. 5-3Injectrol® Service ............................................................................................. 5-4Example .................................................................................................................................... 5-4Treatment Procedure ................................................................................................................. 5-5Injectrol Sealants and Services ................................................................................................. 5-5Relative Permeability Modifiers ..................................................................... 5-5Kw-FracSM Stimulation Service .................................................................................................. 5-5Oxol II RPM Removal Service ................................................................................................... 5-6

Squeeze Cementing ............................................................................................... 5-7General Design Principles ............................................................................. 5-7Lack of Proper Fluid Control ...................................................................................................... 5-9Improper Perforation Cleanup ................................................................................................... 5-9Low Placement Rates ............................................................................................................... 5-9No Knowledge of Where Cement Is Needed ............................................................................. 5-9

Contents v

HALLIBURTON

Poor Injection Point Control ....................................................................................................... 5-9Effect of Bottomwater ................................................................................................................ 5-9Crossflow .................................................................................................................................. 5-9Poor Bonding ............................................................................................................................ 5-9Cement Flowback ..................................................................................................................... 5-9Multiple Injection Zones............................................................................................................. 5-10MOC/One Cement ........................................................................................... 5-10


Chapter 6–Placement Techniques and Equipment............................................ 6-1

Placement Techniques ........................................................................................... 6-1Placement in Injection vs. Production Wells ................................................ 6-1Injection Wells ........................................................................................................................... 6-1Production Wells ....................................................................................................................... 6-1Controlling Fluid Movement ........................................................................... 6-2K-MaxSM Service ....................................................................................................................... 6-2Bullheading ..................................................................................................... 6-2Mechanical Packer Placement ....................................................................... 6-4Dual-Injection Placement ............................................................................... 6-4Chemical Packers ........................................................................................... 6-5Isoflow Placement........................................................................................... 6-5Transient Placement ....................................................................................... 6-5

Service Equipment ................................................................................................. 6-6Monitoring Systems........................................................................................ 6-6Filtering Systems ............................................................................................ 6-6Mixing and High-Pressure Pumping Systems.............................................. 6-6Pumping Equipment Example ................................................................................................... 6-6Coiled Tubing ................................................................................................... 6-9

Conclusions ............................................................................................................ 6-9

Chapter 7–Conformance Treatment Evaluations ............................................... 7-1

Introduction ............................................................................................................ 7-1Numerical Methods ................................................................................................ 7-1Production Data ..................................................................................................... 7-1

Injection Well Data (Hall Plot) ......................................................................... 7-1

Treatment Placement Calculations ......................................................................... 7-2Pressure-Transient Testing to Determine Treatment Volume ...................... 7-3Reservoir Simulation to Determine Treatment Volumes .............................. 7-5


vi Contents

Coning and Cresting Calculations .......................................................................... 7-5Vertical Rate Calculations .............................................................................. 7-5Critical Rate Calculations .......................................................................................................... 7-5Breakthrough Time Calculations ............................................................................................... 7-8Water Cut/Water-Oil Ratio Calculations ..................................................................................... 7-9Horizontal Well Cresting Calculations........................................................... 7-11Critical Rate Calculations .......................................................................................................... 7-11Breakthrough Time and Calculations ......................................................................................... 7-12Water Cut/Water-Oil Ratio Calculations ..................................................................................... 7-14

Chapter Abbreviations ............................................................................................ 7-15Nomenclature .................................................................................................. 7-15Subscripts ....................................................................................................... 7-15Superscripts .................................................................................................... 7-15

Bibliography ............................................................................................................ 7-16References ............................................................................................................. 7-16

Conformance Problems 1-1Chapter 1

By understanding correct reservoirbehavior, engineers can betterdetermine if current gas or waterproduction is excessive or whether itcould become excessive in the future.The production rates and ultimaterecoveries of hydrocarbons andunwanted fluids from a reservoirdepend on drive mechanisms, rockproperties, fluid properties, structuralrelief, well locations, and reservoirmanagement techniques. This chapterexplains primary and secondaryrecovery mechanisms and describescommon near-wellbore and reservoir-related problems.

Recovery MechanismsThis section covers primary andsecondary recovery mechanisms.

Primary Recovery

The principal mechanisms drivinghydrocarbon recovery are depletion,water drive, segregation, and gravityprocesses. For oil reservoirs, deple-tion (solution gas) drives result in thelowest recoveries (15 to 27%) andnatural waterdrives result in thehighest recoveries (35 to 70%), asshown in Figure 1.1 (Page 1-2). Fordry gas reservoirs, depletion drivegenerally results in the highestrecoveries (70 to 90%). Betweenthese extremes are combinationmechanisms involving limited water-or gas-cap drives, segregationconditions, and gravity drainageprocesses. The following paragraphsdiscuss each drive mechanism.

Depletion (Solution Gas)Drive

The depletion drive mechanismdepends on solution gas and oilexpansion as its source of energy tomove fluids. In an undersaturatedreservoir, the expansion of oil anddissolved gas is responsible for fluidproduction. As the pressure dropsbelow the bubble point, the reservoirbecomes saturated, and the liberatedgas initially replaces the produced oilon an equal-volume basis, providingmore reservoir energy than liquidexpansion alone. Once the saturationof the gas reaches the point where itcan flow, the gas is produced with theoil, which depletes the gas as a sourceof energy. As a result, more gasexpansion is necessary per unitvolume of oil produced. The relativepermeability to oil is reduced, and theproduced gas-oil ratio (GOR) in-creases rapidly.

Segregation Drivewithout Counterflow

In high-relief geologic structurescontaining reservoirs with both oil andgas, the oil and gas may exist asstratified or segregated phases; forexample, a gas cap may overlay an oilzone. In this type of reservoir, lowvertical permeability or the presenceof shale stringers or other imperme-able zones suppresses the counterflowof oil and gas associated with gravitydrainage processes. The primary drivemechanism is gas-cap expansion.

Chapter 1

ConformanceProblems


1-2 Conformance Problems Chapter 1

Although gas-cap depletion through coning or othermeans is harmful, this type of reservoir is often a candi-date for pressure maintenance through gas injection intothe gas cap.

Gravity Drainage(Segregation Drive with Counterflow)

The development and expansion of a gas cap over an oilzone can result from an active fluid segregation processin which oil migrates downward because of gravity, andgas migrates upward from buoyancy effects. In this typeof reservoir, the vertical permeability must favor hydro-carbon movement, and the volume of gas moving up mustbe equal to the amount of oil moving down. The rate offluid segregation increases as the mobility of oil ap-proaches that of gas. Depletion of the gas cap throughconing or other means is especially detrimental toreservoir performance because this type of reservoir isnot a candidate for gas injection into the gas cap.

Waterdrive

Natural waterdrive reservoirs occur when an oil-bearingstratum is embedded into an aquifer or when a hydraulicconnection exists between the reservoir and an outcropthat allows water infiltration. When enough water volumeexists to replace the produced oil volume, the reservoir

has an active waterdrive. If the primary movement ofwater is from the edge inward, approximately parallel tothe bedding plane, the reservoir has an edgewater drive. Ifthe primary water movement is upward from below, thereservoir has a bottomwater drive.

Water usually provides a strong energy support mecha-nism, but it does so at a cost. Often, depending on the(1) completion length of the interval, (2) oil viscosity,(3) vertical permeability, (4) density difference betweenthe oil and water, (5) distance between the perforations,and (6) water-oil contact, the water underlying the oilcan eventually move into the well.

Vertical water encroachment (bottomwater drive) occurswhen water from an underlying aquifer, possibly con-nected to an outcrop, replaces the produced hydrocarbonvolume. The upward moving water-oil contact resultingfrom reservoir depletion can eventually reach the perfora-tions, causing water production.

Horizontal water encroachment (edgewater drive) into anoil reservoir may result from a hydraulic connection withan outcrop, which can conduct large amounts of water.Generally, this effect appears as a constant-pressureboundary in the solution of the diffusivity equation for oilor gas. If permeability is heterogeneous, the drive watercan channel through the higher-permeability streaks,bypassing much of the oil contained in the lower-

Figure 1.1—For oil reservoirs, solution gas drives result in lowest recoveries. Natural waterdrives result in highest recoveries.

Solution Gas Drive

0 10 20 30 40 50 60

Percent of Original Oil Produced

Perc

ent o

f Ori

gina

l Res

ervo

ir P

ress

ure

100

90

80

70

60

50

40

30

20

10

0

Waterdrive

Gas-Cap Drive


permeability layers. If the water is more mobile than theoil (the water-oil mobility ratio is greater than 1), thewater can finger through the oil, again reducing sweepefficiency and bypassing oil.

Secondary Recovery

In primary recovery, natural reservoir energy displaces oilto the production well. Any method that improves oilproduction beyond primary recovery is referred to asimproved oil recovery (IOR). IOR processes that do notinvolve chemical reaction between the injected fluid andthe oil in place are called secondary recovery methods.Pressure maintenance techniques such as water or gasinjection are among the most widely applied secondaryprocesses.

Water-Injection Pressure Maintenance

During waterflooding, operators inject water into an oilreservoir to enhance recovery during the final stages ofthe primary recovery operation. When waterflooding isused, early breakthrough at the production well mayoccur if the water channels through high-permeabilitystreaks. If the water is more mobile than the oil, fingeringmay also occur.

Waterflood performance can be predicted based on thesame techniques used to predict natural water influx, butadditional calculations are required for the prediction offlood patterns and sweep efficiencies.

Gas-Injection Pressure Maintenance

Operators use gas injection either to maintain reservoirpressure at a selected level or to supplement naturalreservoir energy by reinjecting the produced gas. Com-plete or partial pressure-maintenance operations canresult in increased hydrocarbon recovery and improvedreservoir performance. However, gas-injection methodsand mechanisms are generally similar to those of waterinjection; therefore, early gas breakthrough caused bychanneling or fingering is still a concern. By includingthe effects of gas solution in the reservoir oil and vapor-ization of lighter hydrocarbons, engineers can model gas-injection reservoirs as water-injection reservoirs.

Although many conformance problems are exclusive to aproduction well or an injection well, such a clear delinea-tion does not always exist. Therefore, engineers mustaccurately determine the source of the problem beforethey can design the proper treatment for each well.

Engineers must also determine if fluid breakthrough ispremature. In reservoirs with various natural drives and inenhanced recovery operations, an unwanted fluid isexpected to break through eventually, even if the reser-voir is ideal.

Part of problem identification is determining if a problemactually exists or if everything has proceeded as planned.Engineers use such methods as reservoir simulation,volumetric analysis, decline curve analysis, and datacomparisons to determine if the reservoir is depleted.They may also use a pressure-volume-temperature (PVT)analysis of the reservoir oil to determine if the producedgas is from a gas cap or dissolved gas.

Conformance Problem SourcesConformance problems are classified as either near-wellbore problems or reservoir-related problems. Someproblems, however, could easily be placed in both catego-ries. For example, barrier breakdown is related to fractur-ing out of zone and could be considered reservoir-related,but it is considered a near-wellbore problem. Similarly,although coning and cresting occur in the near-wellboreregion and can result from a completion too near the wateror gas zone, they are considered reservoir-related.

Near-Wellbore Problems

Near-wellbore conformance problems include

• casing leaks

• channels behind casing

• barrier breakdown

• debris, scale, and bacteria

• completion into or near water or gas

Casing Leaks

An unexpected increase in water or gas production couldbe the result of a casing leak. Production logs, such astemperature, fluid density, Hydro, and flowmeter (spin-ner), can help, individually or in combination, locatewhere various fluids are entering the wellbore. Thermalmultigate decay (TMD) and pulsed spectral gamma test(PSGT) logs can also be used. These tools detect waterentry and waterflow into casing.

Casing evaluation logs are used to find holes, splits, anddeformities that could allow unwanted fluid entry. Thelogs also detect corrosion conditions that could eventu-



ally cause leaks. Downhole video can also show engi-neers the condition of the wellbore and where variousfluids enter the wellbore. Engineers can also comparewater analyses between the produced water and those ofnearby formations to locate the source of the leak.

Channels Behind Casing

Channels can develop behind the casing throughout thelife of the well, but such channels are most likely to occurimmediately after the well is completed or after the wellis stimulated. Unexpected water production at these timesstrongly indicates that a channel may exist. Channels inthe casing-formation annulus result from poor cement/casing bonds or cement/formation bonds. Fluid influx canonly be prevented if proper displacement techniques areused. The factors affecting displacement efficiency arelisted below.

Condition of the Drilling Fluid—Maximum circulatablehole should be achieved, and the mobility of the drillingfluid should be increased through the control of filter-cake buildup. In vertical applications, these practices willresult in low gel strength and viscosity. In deviatedwellbores, the drilling fluid should be conditioned toprevent the dynamic settling of solids to the low side ofthe wellbore.

Pipe Movement—Rotating or reciprocating the casingprovides a mechanical means of controlling gel strengthbuildup. Pipe movement can eliminate a solids-settledchannel.

Pipe Centralization—Centralizers can be used toimprove pipe standoff and to equalize the forces in theannulus. The result is uniform fluid flow around thecasing. In deviated wellbores, a standoff of at least 70%is preferred.

Displacement Fluid Velocity—Fluids should be dis-placed from the annulus at the highest rate possible whilewellbore control is still maintained.

Gas influx or fluid migration through the unset cementcolumn occurs because the slurry cannot maintainoverbalance pressure while the cement is in a gelledphase, which allows gas percolation to form a gaschannel. Once a cement slurry is in place, it begins todevelop static gel strength (SGS). Gel strength develop-ment inhibits the slurry from transmitting hydrostaticpressure, and when combined with hydration/fluid-lossvolume reductions, the result is gas migration. Gas

migration during the initial phases of cement hydrationhas been thoroughly researched and several controlmethods have been developed. These methods includesystems that exhibit controlled fluid loss, modified SGSdevelopment, and compressible systems.

Gas influx can also occur after the cement has set. Thistype of long-term gas migration is thought to occurbecause of poor displacement or the debonding of thepipe/cement/formation sheath. In the case of poordisplacement, gas flow dehydrates the drilling fluid thatthe cement bypasses and results in a highly permeableflow path for gas migration. Drilling/production/workover operations can break the cement/casing bond orcause the cement sheath to fail, resulting in a path forfluid migration. The use of good displacement practicesand expansive cements should help solve such “long-term” gas migration problems.

Once a well has been cemented, Halliburton can usediagnostic sonic tools (cement bond and pulse echo tools)to determine the effectiveness of the cement job. The logsthese tools generate must be interpreted, and this interpre-tation is historically used as the basis for remedial work,such as squeezing off water and gas. Data from thesesonic tools provide information about cement-to-pipebonding and the quality of the cement-annulus seal.

Temperature logs that exhibit deviation from the geother-mal gradient when the well is shut in indicate fluidmigration behind the pipe. A zone with an abnormally hightemperature indicates that fluid is migrating upward.Abnormally low temperatures indicate that fluid ismigrating downward. TMD and PSGT logs can detect andquantify water flow in a channel behind the casing. Whenthe well is shut in, borehole audio tracer surveys (BATS)help indicate possible fluid movement behind the pipe.

Barrier Breakdown

Even if natural barriers, such as dense shale layers,separate the different fluid zones and a good cement jobexists, the shales can heave and fracture near the wellbore.As a result of production, the pressure differential acrossthese shales allows fluid to migrate through the wellbore(Figure 1.2, Page 1-5). More often, this type of failure isassociated with stimulation attempts. Fractures can breakthrough the shale layer, or acids can dissolve channelsthrough it. Temperature, TMD, and PSGT logs can be usedto detect fluid migration caused by barrier breakdown.


Debris, Scale, and Bacteria

Debris, scale, or bacteria deposited on the perforations orin the region around the wellbore of an injector canrestrict flow through perforations, decreasing injectivityand possibly diverting fluid into unwanted regions. Thepresence of debris, scale, or bacteria may also indicatethat permeability streaks or crossflow exist.

Comparing the water analysis results of injection andreservoir fluids is an excellent means of determining thepossibility of scale problems. All fluids injected into thewell should be evaluated for the possibility of introducingbacteria to the formation face. In addition to wateranalysis results, scale problems can be detected withdownhole video.

Completion Into or Near Water or Gas

Completion into the unwanted fluid allows the fluid to beproduced immediately. Even if perforations are above theoriginal water-oil contact or below the gas-oil contact,proximity to either of these interfaces allows productionof the unwanted fluid, through coning or cresting, tooccur much more easily and quickly.

Engineers should re-examine core data, the driller’s dailyreport, and openhole logs to determine the cutoff point ofmoveable water. Data from resistivity and porosity logs,for example, can be combined to determine the locationof water and pay zones.

Reservoir-Related Problems

Reservoir-related problems include

• coning and cresting

• channeling through higher permeability

• fingering

• fracturing out of zone

• fracture communication between injector andproducer

• isolation between injector and producer

Coning and Cresting

Fluid coning in vertical wells and fluid cresting in horizon-tal wells both result from reduced pressure near the wellcompletion. This reduced pressure draws water or gas froman adjacent, connected zone toward the completion(Figure 1.3). Eventually, the water or gas can breakthrough into the perforated section, replacing all or part ofthe hydrocarbon production. When breakthrough occurs,the problem tends to get worse because higher cuts of theunwanted fluid are produced. Although reduced productionrates can curtail the problem, they cannot cure it.

Fluid density, Hydro, PSGT, and TMD logs can helpengineers determine the point of water entry into thewellbore. The PSGT and TMD logs can also indicate thepresent location of the water-oil contact before break-through. In addition to these logs, engineers can runadditional well tests to detect bottomwater encroachment.

Figure 1.2—Communication through a barrier

Oil

Water

Figure 1.3—Coning

Oil

Water

Shale Barrier



Channeling Through Higher Permeability

High-permeability streaks can allow the fluid that isdriving hydrocarbon production to break through prema-turely, bypassing potential production by leaving lower-permeability zones unswept (Figure 1.4). As the drivingfluid sweeps the higher-permeability intervals, permeabil-ity to subsequent flow of the fluid becomes even higher,which results in increasing water-oil or gas-oil ratiosthroughout the life of the project.

Tracer surveys, interference and pulse testing, reservoirsimulations of the field, reservoir descriptions, andreservoir monitoring are used for channel detection.Tracer surveys and interference and pulse tests verifycommunication between wells and help engineersdetermine the flow capacity of the channel. Reservoirdescription and monitoring verify the location of fluidsin the various formations. The data available throughreservoir description (Chapter 2) allow engineers toproduce more accurate models of the formations andthen simulate fluid movement through the reservoir.Permeability variations between zones can be revealedby core test results or pressure transient test results ofindividual zones.

Fingering

Unfavorable mobility ratios (>1) allow the more mobiledisplacing fluid (from either primary or enhancedrecovery operations) to finger through and bypass largeamounts of oil. Once breakthrough occurs, very littleadditional oil will be produced as the drive fluid contin-ues to flow directly from the source to the productionwell (Figure 1.5).

Reservoir- and drive-fluid mobilities derived from fluidand core data are probably the most important factorsfor determining whether fingering is a potential prob-lem. Engineers can use reservoir simulations or avail-able information on ideal systems to determine if sweepefficiencies are within range expected if fingering didnot exist.

Fracturing Out of Zone

An improperly designed or poorly performed stimulationtreatment can allow a hydraulic fracture to enter a wateror gas zone. If the stimulation is performed on a produc-

tion well, an out-of-zone fracture can allow early break-through of water or gas. If the fracturing treatment isperformed on an injection well, a fracture that connectsthe flooded interval to an aquifer or other permeable zonecan divert the injected fluid to the aquifer, providing verylittle benefit in sweeping the oil zone. Engineers can usetemperature logs, tracer surveys, and detailed reviews ofthe fracturing treatment to identify this problem.

Microfrac treatments and long-spaced sonic logs, usuallyperformed before the fracturing treatment, help verify theexistence of vertical stress contrasts that might indicate apotential for uncontained fracture height growth.

Figure 1.5—Fingering

Higher Permeability

Low Permeability

Producer

Oil

Injection Water

Injector

Figure 1.4—High-permeability streaks


Fracture CommunicationBetween Injector and Producer

Natural fracture systems can provide a direct connec-tion between injection and production wells, allowinginjected fluid to move through these higher-permeabil-ity channels, bypassing hydrocarbons within the rockmatrix (Figure 1.6). Even if natural fractures intersect-ing two wells are not directly connected, fluid canpreferentially flow through one fracture until it is inclose proximity to another fracture or wellbore,crossing through and sweeping only a small portion ofthe matrix.

Natural fractures serving as flow channels can be con-firmed by chloride level comparisons and tracer surveys.Reservoir description should locate the discontinuities,and reservoir monitoring should detect the movement offluids through the fracture system. A combined analysisof pressure buildup or drawdown data and interferencedata allows engineers to estimate the properties for boththe matrix and the natural fracture system.

Poorly oriented hydraulic fractures can also providechannels that allow injected fluids to bypass much of thehydrocarbon production. Although created fracturesrarely interconnect two wells, a hydraulic fracture stillprovides a channel of higher conductivity that allowsmuch reservoir fluid to be bypassed. Preferred fractureorientation and the possibility of enhanced recoveryoperations should be considered during the reservoirinitial development.

Various technologies, such as microfrac analysis andanelastic strain recovery, allow engineers to determine theexpected direction of fracture growth. If engineers knowthe lengths and directions of any hydraulic fractures, theycan use reservoir simulations to model flow through thesystem and determine the expected sweep efficiency.

Isolation Between Injector and Producer

If oil or gas production does not respond to injection, theproblem could be a lack of communication between theinjector and producer. A natural barrier, such as a sealingfault, can separate the wells, or they can be perforated indifferent zones.

Interference and pulse tests help determine if interwellcommunication exists. Reservoir description reveals thepresence of major heterogeneities, such as faults.

ConclusionsWith a basic knowledge of reservoir behavior and theprimary causes of conformance problems, a reservoirdescription team can examine various wellbore andreservoir parameters to pinpoint any conformanceproblems that might exist in a given area. Chapter 2presents detailed information regarding well testing,reservoir descriptions, and reservoir monitoring.

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Bateman, R.M.: “Building a Reservoir Description Team–A Case Study,” The Log Analyst, (1993) 67-73; 34, 4.

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3rd Meeting, Pau, France, Technip Editions, 1969.

Injection Well

Production Well

Open Fracture

Figure 1.6—Injected fluid moving through a high-perme-ability channel, bypassing hydrocarbons in the rock matrix



Byrne, W.B. and Morse, R.A.: “Waterconing May Not Be Harmful–1,” OGJ (Sept. 3, 1973) 66-70.

Chaperon, I.: “Theoretical Study of Coning TowardHorizontal and Vertical Wells in Anisotropic Forma-tions: Subcritical and Critical Rates,” paper SPE15377 presented at the 1986 SPE Annual TechnicalConference and Exhibition, New Orleans, Oct. 5-8.

Chapplelear, J.E. and Hirasaki, G.J.: “A Model of Oil-Water Coning for Two-Dimensional, Areal ReservoirSimulation,” SPEJ (April 1976) 65-72.

Coats, K.H.: “An Analysis for Simulating ReservoirPerformance Under Pressure Maintenance by Gasand/or Water Injection,” SPEJ (Dec. 1968) 331-40.

Collins, D.A., Ngheim, L.X., and Grabenstrotter, J.E.:“An Efficient Approach to Adaptive-Implicit Compo-sitional Simulation with an Equation-of-State,” paperSPE 15133 presented at the 1986 California RegionalMeeting of SPE, Oakland, CA, April 2-4.

Cottin, R.H. and Ombret, R.L.: “Application of a Multi-phase Coning Model to Optimize Completion andProduction of Thin Oil Columns Lying Between GasCap and Water Zone,” paper SPE 4632 presented atthe 1973 SPE Annual Fall Meeting, Las Vegas,Sept. 30-Oct. 3.

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Giger, F.M.: “Horizontal Wells Production Techniques inHeterogeneous Reservoirs,” paper SPE 13710 pre-sented at the 1985 SPE Middle East Oil TechnicalConference, Bahrain, March 11-14.

Høyland, L.A., Papatzacos, P., and Skjaeveland, S. M.:“Critical Rate for Water Coning: Correlation andAnalytical Solution,” SPE Reservoir Engineering(Nov. 1989) 495-502.

Joshi S.D.: “Augmentation of Well Productivity UsingSlant and Horizontal Wells,” JPT (June 1988) 729-39.

Joshi, S.D.: Horizontal Well Technology, PennWellPublishing Company, Tulsa, OK, 1991.

Kabir, C.S.: “Predicting Gas Well Performance: ConingWater in Bottom-Water-Drive Reservoirs,” paper SPE12068 presented at the 1983 SPE Annual TechnicalConference and Exhibition, San Francisco, Oct. 5-8.

Karp, J.C., Lowe, D.K., and Marusov, N.: “HorizontalBarriers for Controlling Water Coning,” JPT (July1962) 783-90.

Lake, L.W.: Enhanced Oil Recovery, Prentice Hall,Englewood Cliffs, NJ (1989) 223.

Meyer, H.I. and Garder, A.O.: “Mechanics of TwoImmiscible Fluids in Porous Media,” Journal ofApplied Physics, 25, No. 11, 1400.

Mungan, N.: “A Theoretical and Experimental ConingStudy,” SPEJ (June, 1975) 247-54.

Muskat, M.: The Flow of Homogeneous Fluids ThroughPorous Media, IHRDC, Boston (1982) 454-476.

Papatzacos, P., Gustafson, S.A., and Skaeveland, S.M.:“Critical Time for Cone Breakthrough in HorizontalWells,” presented at the 1988 Seminar on Recoveryfrom Thin Oil Zones, Norwegian Petroleum Directorate, Stavanger, Norway, April 21-22.

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Zhao, L.: Progress Report No. 16, Texas A&M UniversityReservoir Modeling Consortium (1993).

Data Collection 2-1Chapter 2

To understand the source or potentialsource of a problem, conformancecontrol design teams must thoroughlyinvestigate all aspects of well andreservoir parameters, includinggeological, petrophysical, wellcompletion, and production/injectionlog data. All of this information maynot be available, and some of theavailable information may notsufficiently identify the source of theproblem; therefore, additional testsmay have to be performed.

By fully understanding the differentmechanisms that contribute to aconformance problem, engineers canbetter evaluate the informationavailable, identify additional tests,and perhaps better determine possibleproblems. This chapter describes welltesting, reservoir description andmonitoring methods, and specifieshow a design team can use the datacollected to identify conformanceproblems and plan treatments.

Well TestingWell tests provide informationregarding pertinent reservoir proper-ties, such as horizontal and verticalpermeability. They can also reveal thepresence of heterogeneities and verifyinterwell communication.

This section discusses the generaleffects of reservoir nonidealities onpressure-transient testing and howwell testing can be used to quantifythese nonidealities. In addition, theapplication of multiple-well tests toconformance technology is discussed.

Chapter 2

DataCollection

Effect of ReservoirNonidealities

Reservoir nonidealities, such asbarriers, permeability anisotropy,layered systems, and natural frac-tures, play important roles in wellconformance. Researchers haveexamined the effects of eachnonideality on pressure-transientbehavior, and have developedmethods and tests to determine theirexistence or magnitude. Such tests,however, should be supported byadditional geologic, seismic, fluid-flow, and performance data. Engi-neers should not infer heterogeneousreservoir properties based solely ontransient testing.

Faults and Barriers

Barriers, such as sealing faults, canprevent communication betweeninjection and production wells. Iffaults are located near an injector,they could cause rapid pressurechanges early in the well life thatcould be mistaken for indications ofother injector-related problems.

On an appropriate semilog plot, alinear barrier, such as a sealing fault,appears as a second straight-lineportion of double slope in drawdown,two-rate pressure buildup, injectivity,and pressure falloff testing. Loganalysts must be careful to ensurethat wellbore storage effects are notcausing the two apparent semilogstraight lines. The use of the intersec-tion time of the two straight-linesegments allows analysts to deter-mine the distance from the well to the


2-2 Data Collection Chapter 2

fault. The method for this determination depends, ofcourse, on the type of well test performed. Multiple faultsare not as easily analyzed as a single fault because theirrelative angles and distances from the well affect transienttest-pressure behavior.

Permeability Anisotropy

The degree to which a reservoir’s permeability is aniso-tropic affects coning or cresting behavior near the welland will factor into the degree of crossflow betweenadjacent permeable layers. Typically, vertical permeabil-ity is less than horizontal permeability in petroleumreservoirs.

Because the response curve of an anisotropic reservoir isthe same as an isotropic reservoir, anisotropy cannot berecognized from a single-well test; the permeabilitydetermined from one test is considered an averagepermeability. However, multiple-well transient tests areavailable that allow engineers to recognize and quantifyanisotropic reservoir properties. Well tests are alsoavailable for determining vertical permeability.

Well Tests for Vertical Permeability

Methods for estimating vertical permeability includevertical interference testing, vertical pulse testing, and theuse of a formation tester.

Vertical Interference and Pulse Tests

To perform vertical interference and pulse tests, operatorsmust complete the well so that part of the completion canbe used for production or injection and another part forobservation. A favorable method is to separate the active(injection or production) perforations from the observa-tion perforations with a packer. Theoretically, either set ofperforations can serve as the active or observationperforations, but operators generally prefer to use theupper set for the active perforations.

In general, operational considerations for these types oftests are more demanding than other tests becauseoperators must (1) limit or eliminate wellbore storageeffects, which can mask the pressure response, and (2)eliminate any communication between the two sets ofperforations, except through the matrix permeability.

In addition to the increased operational difficulty, theanalysis of vertical pulse tests is more complex than thatof horizontal tests because of the influence of upper andlower formation boundaries on the test. Vertical interfer-ence tests are also possible, but they can only be properlyanalyzed with specialized software.

Formation Testers

Formation testers measure pressures at individual pointswithin a wellbore as fluid samples are taken. As fluids arewithdrawn from the formation, a drawdown permeabilityis calculated from the pressures measured. Sphericalbuildup permeability is calculated from pressuresmeasured while the formation relaxes to an undisturbedstate. Through mathematical relationships, horizontal andvertical permeabilities are calculated from these twovalues.

Layered Reservoirs

The pressure transient behavior of a layered system withcrossflow is the same as the behavior of a homogeneoussystem. Therefore, normal pressure-transient testing willnot reveal the layered nature of the reservoir. In thesesystems, the effective permeability-thickness product willbe the total of the permeability-thickness products of theindividual layers. Likewise, the effective porosity-compressibility-thickness product will be the total of theporosity-compressibility-thickness products of theindividual layers.

For layered reservoirs separated by barriers that preventcrossflow, early-time drawdown or buildup behaviorscannot be distinguished from those of a single-layersystem. However, at later times, once boundary effectsoccur, the presence of the boundary will be sensed atdifferent times in each layer if the layers have differentproperties. The resulting behaviors can be analyzedthrough the use of special techniques.

By isolating and testing each layer in a layered reservoirwith a straddle packer, analysts can estimate the perme-abilities, skin factors, and average pressures of all layers.

Natural Fractures

Natural fracture systems, among the most common ofheterogeneities, can create flowpaths that allow injectedwater or drivewater to bypass hydrocarbons within theformation matrix.

If the natural fractures occur predominantly in a singledirection, the reservoir behaves as a system with anisotro-pic permeability, and well-testing methods developed foranisotropic behavior can be applied.

Natural fractures can also occur in an interconnectedsystem that exhibits two distinct porosity types: (1) thefine, low-permeability pores of the matrix and (2) thehigher-permeability system of fractures, fissures, and vugs.


The existence of this dual-porosity system manifests itselfin pressure-transient testing behavior. For buildup anddrawdown tests, techniques are available for determiningthe total permeability-thickness product for the system, aswell as skin factor and average reservoir pressure. A ratioof the porosity-compressibility product of the fracturesystem to that of the total system is also available. Acombined analysis of pressure drawdown or buildup dataand interference data allows engineers to estimate theproperties of both the matrix and the fracture system.

Multiple-Well Testing

As implied by the name, multiple-well transient testsinvolve more than one well. They require at least oneactive (producing or injecting) well and at least onepressure-observation well. For practical rather thantheoretical reasons, the observation well is shut in forpressure measurement. In addition to providing informa-tion on interwell communication, multiple-well testsallow engineers to investigate a larger portion of thereservoir. The investigation area includes the regionbetween the wells and a radius of influence that dependson the reservoir properties and the testing time.

Although multiple-well tests are designed to provideinformation on the effective reservoir properties, they canalso indicate whether communication exists between twoor more wells. In a multiple-well test, the flow rate of theactive well is varied, while the bottomhole pressureresponse at the observation wells is measured. A lack ofresponse at the observation well indicates little or nocommunication. This condition suggests that either theactive and observation wells are completed in differentzones or that a boundary, such as a sealing fault, couldexist between the wells.

If a response occurs at the observation well, it can usuallyhelp engineers determine such parameters as permeabilityand the porosity-compressibility product. In addition,methods have been developed for estimating anisotropicreservoir characteristics from interference testing.Because multiple-well tests measure properties over aregion of influence, the variation in fluid properties (forexample, mobility) that exists with fluid-fluid contactscan cause the results to be unreliable or meaninglesswhen they are applied to conformance control.

The two major types of multiple-well tests are the inter-ference test and the pulse test. Of the two tests, the pulsetest requires less time, but it is more difficult to analyze.

Interference Tests

During an interference test, operators modify the long-term rate, usually by shutting in the active well. Tech-niques as simple as type-curve matching and semilogplots are applied to the pressure responses measured atthe observation wells. In addition, permeability anisot-ropy can be determined from interference tests thatinvolve multiple observation wells and more complexanalysis techniques.

If natural fractures exist, they may substantially affectobservation well behavior in interference tests. Becauseearly-time behavior is most greatly affected, type-curvemethods may not provide correct results in these in-stances, but semilog methods should still apply.

Pulse Tests

During a pulse test, a number of short-duration rate pulsesare used at the active well. These production or injectionpulses are made at the same rate and duration, and thepulses are separated by shut-in periods of the sameduration. The pressure responses measured at the observa-tion well can be small, sometimes less than 0.01 psi,requiring special pressure-measuring equipment. Whenused on naturally fractured reservoirs, pulse tests canprovide erroneous results.

Reservoir DescriptionHistorically, engineers have assessed the condition ofunwanted fluid production on a well-by-well basiswithout the benefit of reservoir understanding. Whilemany conformance problems can be traced to mechanical(near-wellbore) problems, a significant number ofconformance problems are the result of reservoir-relatedphenomena. By understanding a reservoir’s characteris-tics, engineers can more easily identify, control, andsometimes predict a conformance problem.

To understand reservoir behavior, engineers must have adescription of the static and dynamic properties of areservoir. Although reservoir information from a problemwell may provide valuable information that engineers canuse to create a treatment for that well, truly effectivereservoir understanding generally results from a multiple-well or field-scale reservoir description.

Reservoir description is the quantitative assessment ofboth static and dynamic subsurface properties, bothspatial and temporal. Reservoir descriptions can be



Static Reservoir Properties

Dynamic Reservoir Properties

φ

φ = porosity h = thickness k = permeability P = pressure Q = rateSw = water saturation

k

P

QSw

h

Figure 2.1—Static and dynamic reservoir properties(modified after Bateman, 1993)

Figure 2.2—Integrated approach to reservoir description

Geophysics Geology Petrophysics Engineering

StructuralConfiguration

StratigraphicFramework

GeologicModel

VolumetricEstimateof Fluidsin Place

ReservoirSimulator

Optimization ofField Operations

EconomicAnalysis

ProductionForecasts

performed at various scales, ranging from a broad basinanalysis to an individual reservoir unit analysis. Staticproperties do not usually change with time and includethe size, shape, position, and storage capacity of the flowunits. Dynamic properties vary with time and include theinitial, current, and future distribution of fluids in theflow units (Figure 2.1).

Ideally, a reservoir description should result in aconceptual 3D model that describes the spatial distribu-tion of fluid and rock properties within the grossthickness and areal extent of the reservoir. However, amore limited or problem-specific reservoir description,such as a study of natural fractures, may provide the

reservoir engineer with the information necessary toidentify or treat a conformance problem such as chan-neling through natural fractures.

Any reservoir description should be based on an inte-grated dataset (geology, geophysics, petrophysics,engineering) prepared by a multidisciplinary team(Figure 2.2). A field-scale reservoir description allowsteam members to quickly classify the primary productionmechanism, identify large-scale trends, and incorporatereservoir heterogeneity when planning secondary orimproved oil recovery.

Reservoir Heterogeneityand Conformance

Various heterogeneities control the distribution andmovement of fluids in a field and reservoir. These hetero-geneities include faults, stratigraphic surfaces, flow-unitboundaries, and fractures (Figure 2.3, Page 2-5).Because of macroscopic and microscopic features,porosity and permeability are also heterogeneouslydistributed throughout a reservoir and field. Table 2.1(Page 2-6) shows the impact of various types of reservoirheterogeneity on fluid distribution and movement.


Oil1. Faults:Sealing faultSemisealing faultNonsealing fault

2. Boundaries between genetic units

3. Permeability zonation within genetic units

4. Flow baffles within genetic units

5. Sedimentary structuresLaminationCross-beddingBioturbation

6. Microscopic heterogeneityTextural typesPore typesCementsClays

7. FracturesOpenPartially cementedCementedHealed

Figure 2.3—Types of reservoir heterogeneity (modified after Weber, 1992)



Figures 2.4 and 2.5 (Page 2-7) illustrate the effects thatreservoir and field-scale heterogeneity have on fluiddistribution and movement on waterfloods and oil produc-tion. Accurate descriptions and a thorough understandingof field and reservoir heterogeneity allow design teams topredict, manage, and even control the movement ofreservoir-related fluids (oil and water) and gas.

A reservoir’s static properties do not generally changeduring the life of a field. Therefore, engineers candelineate the structural features (faults and folds) anddetermine stratigraphic surfaces and geometries byinterpreting 2D or 3D seismic data.

Wireline logs provide detailed views of near-wellboreformation thickness, dip, natural and induced fractures,and petrophysical properties such as porosity, lithology,and fluid saturations. Studies of cores and cuttingsprovide details on sedimentary structures, rock texture/fabric, mineralogy, pore types and networks, and othermicroscopic heterogeneities. By integrating thesedatasets, a design team can construct a stratigraphicframework and develop structural, depositional, anddiagenetic models. The team can then use these models toconstruct a 3D geologic model that represents thedistribution of the various types of reservoir heterogene-ity throughout the field.

A well-defined geologic model provides the informationnecessary for the next phases of field/reservoir develop-ment. This model must be dynamic, must be updated asnew data is acquired, and must evolve with fielddevelopment.

Effective assessment of a reservoir’s dynamic propertiesis essential before and during the development phase. Toderive fluid types, properties, and distribution, teammembers can examine petrophysical, well-test, andproduction data and use advanced reservoir simulatorsbased on the geologic model.

Simulation is a vital part of the reservoir managementdecision-making process because it yields productionforecasts for a variety of production alternatives andeconomic scenarios. In mature fields, where productionrates have declined and formation pressures have fallen,the team may be required to evaluate existing secondaryrecovery activity and model possible secondary recoveryoptions. Strategies for pressure maintenance, infill drilling,workover, and conformance problems can be improved ifthe results of a reservoir simulation are available.

Existing geological, geophysical, petrophysical, andengineering data may often seem sparse in comparisonwith reservoir size and complexity, and acquiring new

Reservoir Heterogeneity Type

Reservoir Continuity

Horizontal Sweep Efficiency

Vertical Sweep Efficiency

ROS in Swept Zones

Rock/Fluid Interactions

Sealing fault O O — — —Semisealing fault X O O — —Nonsealing fault X O O — —Boundaries as genetic units

O O O — —

Permeability zonation within genetic units

— X O — —

Baffles within genetic units — X X X —

Lamination, crossbedding

— X — X —

Microscopic heterogeneity — — — O X

Textural types — — — O OMineralogy — — — — OTight fracturing — X — O —Open fracturing — O — O —

Table 2.1—Types of Reservoir Heterogeneity

X = Major influence O = Minor influence — = No influence


data is frequently costly. Table 2.2 (Page 2-8) shows thevalue of various data for identifying and quantifyingdifferent types of reservoir heterogeneity.

Finally, the spatial and temporal relationships that exist ina reservoir are difficult to perceive. Reservoir engineershave found 3D displays to be powerful tools for interpret-ing faulting and fluid regimes that may remain hidden orbe obscured in traditional 2D displays, such as maps andcross sections.

Solutions for Reservoir-RelatedConformance Problems

A reservoir description solution can be developed foreach of the following reservoir-related nonconformancephenomena identified in Chapter 1:

• coning and cresting

• high-permeability channeling

• fingering

• induced fractures

• natural fractures

• permeability barriers

Coning and Cresting

As mentioned in Chapter 1, whenever a well is produc-ing from an oil zone overlaying a water layer (aquifer),the near-wellbore pressure gradients may deform thehorizontal oil-water contact into a cone or crest. Theheight or vertical reach of the cone or crest above theoil-water contact depends on the pressure gradientaround the wellbore.

The tendency for water or gas to cone is inversely relatedto the density difference between existing oil and gas orwater and directly proportional to the viscosity and thepressure drawdown near the wellbore. The densitydifference between gas and oil is higher than the densitydifference between gas and water, but gas has a lowerviscosity than water. However, formation permeabilityand thickness generally dictate the extent of coning thatoccurs because higher-permeability rock has higher flowrates and requires less drawdown. In practice, most wellsare perforated closer to the oil-water contact than the gas-oil contact; therefore, water coning is a common con-formance issue.

Injector Producer

K/Φ = 7K/Φ = 3K/Φ = 5K/Φ = 2K/Φ = 5

K/Φ = 2

Figure 2.4—Effect of reservoir heterogeneity on awaterflood front [Movement of the water front is irregularfrom areal, vertical, and intrareservoir (intralayer orintrazone) perspectives.]

Cumulative Water InjectionCumulative Oil Production

Figure 2.5—Cumulative oil production and cumulativewater injection across a field [Distribution of both oil andwater volumes is generally heterogeneous; however, atleast two subtle trends in both the oil and water volumesmay be interpreted (dashed lines).]



Reservoir Heterogeneity

TypeProduction

Logs

Standard Well

Logging

Special Well

Logging

ROS Well

Logging CoresSWS

Cuttings

Outcrop or Analog

ReservoirSealing fault — O X X X — XSemisealing fault — O — — X — XNonsealing fault — O X — X — XBoundaries as genetic units

X O O X O X O


X O X O O X O

Baffles within genetic units

X O X — O — O


— O — — O — O

Microscopic heterogeneity

— — — — — — —

Textural types — — — — — — —Mineralogy — — X X O X XTight fracturing — — — — O — XOpen fracturing O X — — O X X

X = Major value O = Minor value — = No value

Table 2.2 (1 of 2)—Value of Data for the Identification and Qualification of Heterogeneity

Reservoir Heterogeneity

TypeDetailed Seismic

Horizontal Reservoir Pressure

Distribution

Vertical Reservoir Pressure

DistributionProduction

TestsPulse Tests

Tracer Tests

Production History

Sealing fault O O X X O X OSemisealing fault O O X X X X XNonsealing fault O X X — — — —Boundaries as genetic units

X O O X X X X


— — X X X — —

Baffles within genetic units

— — X — X — X


— — — — — — —

Microscopic heterogeneity

— — — — — — —

Textural types — — — — — — —Mineralogy — — — — — — —Tight fracturing — — — O — — OOpen fracturing X O X O O X O

X = Major value O = Minor value — = No value

Table 2.2 (2 of 2)—Value of Data for the Identification and Qualification of Heterogeneity


Before team members can treat a coning problem, theymust characterize fluids and reservoir-fluid interactions.To determine the coning or cresting tendencies ofdifferent parts of the reservoir, engineers must measurethe density, gravity, and viscosity of the hydrocarbonfluids and establish the relative permeability of thereservoir rocks. For example, homogeneous reservoirswith active drives are more prone to coning. To under-stand the distribution of variations in reservoir thicknessand permeability, the team must model the reservoir’sstatic properties. In this way, they can evaluate the coningtendencies of different parts of the field and/or reservoir.By understanding the reservoir and/or field static anddynamic properties, the team can anticipate potentialconing problems.

To set production limits that should preclude coningproblems in oil or gas reservoirs, team members cancalculate a critical production rate based on availablereservoir parameters. A reservoir description that includesthe distribution and magnitude of permeability heteroge-neities and variations in reservoir thickness allows suchcalculations to be refined to more accurately represent theactual fluid dynamics of the reservoir.

High-Permeability Channeling

Reservoirs containing fractures or high-permeabilitystreaks may suffer from early water breakthrough andpoor sweep efficiency. As fluids are produced from areservoir, zones of higher permeability and correspond-ingly higher flow rates create channels for the preferentialmovement of fluids. In the case of water, this conditioncan result in premature communication between areservoir and an aquifer or premature communicationbetween an injector and a producer. In either case, sweepefficiency is diminished.

To eliminate or inhibit channeling, engineers mayrecommend placing gels in the high-permeability zones atthe injection wells. These gels plug the high-permeabilityzones and force the injected water to sweep the oil-saturated, low-permeability zones. For such gel place-ments to be successful, engineers must understand thelateral and vertical distribution of the permeability zonesto identify interwell flow regimes.

To reduce or prevent the effects of high-permeabilitychanneling, engineers can map the lateral and verticaldistribution of permeability during reservoir description.By knowing the distribution of high-permeability zones(potential channels) across the field or reservoir, theoperations engineer can more easily avoid or controlchanneling-related nonconformance.

Fingering

Viscous fingering is significant in a waterflood environ-ment, especially when high oil-water viscosity ratiosexist. Under these conditions, discrete streamers or“fingers” of displacing water may move through thereservoir or field. When high oil-water viscosity ratiosexist, instabilities occur at the oil-water interface becauseof the driving fluid’s higher mobility. The mobility ratiocompares the driving fluid (water or gas) mobility to thedriven fluid (oil) mobility. Mobility is defined as the ratioof a fluid’s effective permeability to its viscosity (k

eff/µ).

Ideally, the mobility ratio should be less than 1; other-wise, fingering could result.

In a field of several types of reservoirs, the hydrocar-bons trapped in each reservoir may not be the same. Insome cases, oil gravities may vary substantially fromone reservoir to another, even in the same part of thefield. Therefore, the mobility of some hydrocarbonsrelative to water, for instance, may be different indifferent parts of a field. In addition, static reservoirproperties and heterogeneities may dictate the preferen-tial flow of oil, gas, or water, depending on the place-ment and number of these fluids.

During reservoir description, engineers can estimate thefractional flow of fluid phases based on laboratory testson core samples to determine relative permeabilities andcapillary pressures of the wetting phase. During thesetests, the variation and distribution of fluid types andfluid properties are characterized and modeled, as well asthe static reservoir properties. By integrating the staticand dynamic properties into a reservoir model, engineerscan predict and plan for zones and scenarios in whichfingering is likely to occur.

Induced Fractures

Injection above the formation parting pressure inadvert-ently creates stresses in the reservoir zone that exceed thetolerance of the reservoir rock. These stresses can inducefractures that can modify expected fluid flow patterns. Ifthe induced fractures do not extend beyond the reservoirpay zone, the effect is generally positive (similar tohydraulic fracture stimulation). However, if the inducedfractures extend into a gas or water zone, they becomehigh-permeability conduits that allow communication(channeling) between the reservoir and these zones,resulting in diminished sweep efficiency and oil recovery.

In-situ reservoir stresses and rock strength control theinitiation, opening, and propagation direction of theinduced fractures. By understanding the in-situ stress



field and the mechanical strength of the rock at reservoirconditions, engineers can accurately determine formationparting pressure and the probable intensity, spacing, length,and orientation of any induced fractures. With this informa-tion, the design team can plan or modify injection activitiesto minimize or prevent nonconformance problems.

Natural Fractures

Natural fractures are common components of manyreservoirs and can provide significant flow paths for fluidmovement. Natural fractures can connect oil and waterzones and define flow patterns or trends for subsurfacefluids. Fractures can also provide a significant portion ofreservoir quality by contributing permeability, porosity,or both.

When planning production and injection activities,engineers must consider the influence and effects that thefracture system has on hydrocarbon and water distribu-tion and movement. To understand natural fractures,engineers must determine fracture geometry, orientation,intensity, and distribution in 3D space.

The reservoir properties of the fracture system (fluid flowinteraction or crossflow related to the fracture system, andthe fracture system’s contribution to total reservoir quality)must be qualitatively or quantitatively determined. Rocksthat have a multistage history of deformation may containseveral sets of fractures, each with different characteristicsand effects on reservoir performance.

Permeability Barriers

The assumption that no horizontal or vertical permeabil-ity barriers exist in a typical reservoir is generally wrong.Intrareservoir heterogeneities, such as depositionalboundaries (nonconformities), facies changes, diageneticeffects, sedimentary structures, and irregular porenetworks can all produce permeability barriers.

These barriers disrupt predicted fluid flow, resulting indiminished sweep efficiency and nonconformanceproblems. For example, horizontal permeability barriersmay halt or redirect waterflood fronts, while verticalpermeability barriers directly affect water coning andcould, in some cases, promote a more uniform flood frontor prevent gravity segregation.

Production tests and production/injection profiles oftenshow the influence and effects of permeability barriers.Field maps of production and injection data (histories)also often reflect the influence of reservoir permeabilitybarriers (“dead zones”). However, in most cases, a

detailed geologic study is required before permeabilitybarriers can be identified, quantified, and mapped.

If the design team chooses to inject fluid to stabilize orrepressure a reservoir, they must carefully consider thedistribution and geometry of the permeability barriers inthe interwell space; otherwise, the production plan willlikely contain inefficient production and injection designs.

Development Planning

In addition to identifying and providing solutions toreservoir-related conformance problems, reservoirdescription can provide valuable information for fielddevelopment and production planning. Specifically,reservoir description can significantly enhance thequality and accuracy of performance predictions for thefollowing:

• waterflooding

• infill drilling

• horizontal/highly deviated wells

• improved/enhanced oil-recovery schemes

• stimulation applications

Field Development

During reservoir description, team members characterizeand model the fluid types, fluid properties, and field-scaleheterogeneities. This information can then be applied towell-pattern planning. For example, reservoir conditionsquantified by the reservoir description model can be usedto simulate the results of various injection schemes basedon a variety of common patterns for injection andproducing wells. In addition, special features of thereservoir and/or field, such as natural fracture distributionand orientation and permeability trends, can be includedin the evaluation of optimal well patterns.

By identifying, understanding, and mapping both thepermeability barriers and reservoir continuity, designerscan determine effective well spacing and assess sweepefficiency based on their understanding of the static anddynamic properties of the reservoir provided in thereservoir description.

If the reservoir is not well understood, fluid movementsmay occur outside modeled predictions and unexpectedheterogeneity may occur in production and injectionvolumes across the field. Poor reservoir understandingwill fail to uncover reservoir heterogeneities that cansignificantly impact the fluid distribution and movement


in the field or reservoir, limit options for field develop-ment, and negatively impact the sweep efficiency andultimate oil recovery.

Production Planning

When wells are completed too near the fluid contacts, inthe transition zones, or out of zone, expensive conform-ance problems may result early in the life of the well. Forexample, an early high gas-oil ratio (GOR) may result inthe loss of reservoir pressure, or high water cuts couldforce premature revisions of the lift equipment. Bothproblems could have been avoided with better reservoirunderstanding.

In addition to identifying and mapping fluid contacts,engineers can use reservoir description to determinereservoir thickness and distribution, which allows them todelineate zones for completion (and stimulation). Byunderstanding in-situ reservoir stresses, pressures, androck fabric and strength, engineers can help eliminatewellbore and near-wellbore damage.

When a truly effective reservoir description exists, thedesign team can better understand reservoir behavior anddevelop more effective development strategies. Ideally,reservoir descriptions should be updated throughout thelife of the field, from the exploration phase throughabandonment. The underlying objective of reservoirdescription is effective reservoir management, which canincrease production, maximize economic value, andminimize capital investments and operating expenses.

Reservoir MonitoringReservoir monitoring integrates reservoir description andreservoir simulation with multiple-reflection seismicsurveys. Reservoir monitoring allows engineers to trackthe movement of fluid saturations in a reservoir andpredict how the fluids will move in the future.

Engineers can achieve better well conformance (1) byobserving the detailed 3D horizontal and vertical move-ment of oil-water, oil-gas, gas-water, and thermal inter-faces, and (2) by being able to predict the breakthroughof injected fluids or the coning of reservoir fluids underthe current scenario or alternate scenarios. With thisinformation, they can delay or prevent breakthrough.

If breakthrough has already occurred, and a 3D seismicbaseline survey is available, engineers may be able todetermine whether lateral heterogeneity, vertical hetero-geneity, or coning was the cause. By identifying the causeof breakthrough and observing fluid movement patterns,

engineers can identify, design, and accurately place theproper conformance treatment to optimize the productionof reservoir fluids.

Reservoir monitoring does not replace reservoir descrip-tion or reservoir simulation. Instead, it integrates bothtechnologies to allow engineers to more accuratelydescribe a reservoir and predict its future performance. Inother words, the purpose of reservoir monitoring is notmerely to obtain a better reservoir description by integrat-ing more focused surface reflection seismic data withwell-log, well-test, and well-performance information.Instead, it results in an overall integrated reservoir-monitoring process that combines this description withfluid-front measurement and simulation.

If fluid movement in a producing hydrocarbon reservoiris accurately monitored, improved recovery may result.For example, reservoir monitoring may lead to betterreservoir management, better placement of infill wells,and breakthrough deferral. Reservoir monitoring mayalso result in lower costs as a result of fewer wells beingdrilled and reduced water and gas handling. As long asformation thicknesses are sufficient for seismic detection,reservoir monitoring is applicable onshore and offshoreto depths of more than 10,000 ft for both sandstones andcarbonates.

The success of reservoir monitoring is based on twofundamental principles: the seismic principle and thesimulation principle. The fundamental seismic principleis that a change in fluid saturations within a reservoir willchange the reservoir’s seismic response. The fundamentalsimulation principle is that the additional data points inspace and time provided by a direct measurement of fluidsaturation within a reservoir add substantially to the dataset used for history-matching; therefore, the data substan-tially improve the accuracy of the results.

The Reservoir-Monitoring Process

Figure 2.6 (Page 2-12) shows the steps in a reservoir-monitoring study from seismic data acquisition throughfinal integration. Each step focuses on the reservoir andintegrates with the other steps to allow reservoir monitor-ing teams to obtain the most accurate solution possible.

Seismic Data Acquisition

In this first step, members of the monitoring team design aseismic data-acquisition program to greatly enhance theirability to monitor fluid-contact movement. Their primaryfocus is on maximized resolution and repeatability.



Seismic Processing

During the seismic processing phase, team membersperform normalizations, both between successive surveysand well logs. These surveys consist of informationregarding positioning, amplitudes, two-way times, andwavelets. The normalizations are based on the knowninvariance of subsurface geology over calendar time.Least-squared-error cross-equalization filters as well astemporal and spatial shifting filters are used.

Seismic Data Interpretation

During the interpretation stage, team members useconventional seismic data to begin developing a detailedreservoir description.

Well Log Analysis

During this phase, a standard field development orreservoir exploitation log analysis should be performed.This study includes data preparation, data editing, depthshifting, environmental correction, normalization or

recalibration of log traces, log analysis, and generation ofthe final database and displays.

The log analysis should include complex lithologydetermination and a log model of rock facies in additionto the standard results such as porosity, saturation, andestimates of permeability.

During this analysis, logging analysts should edit andcorrect sonic and density logs for synthetic seismographgeneration and plot the corrected logs in two-way timefor display on seismic sections. The lithologic resultsmust be tied to the seismic signature of each well.

Well Test Analysis

During this phase, team members should analyze welltests as they would for a normal reservoir descriptionstudy. Specifically, members should determine permeabil-ity and barrier locations to situate geologic changeswithin the reservoir.

Geologic Model

A geologic model that best exemplifies the initial conclu-sions regarding deposition environment and structuralmodification can then be constructed. This model allowsengineers to integrate all seismic, well log analysis,production engineering, and geologic information.

The resulting reservoir description would normally beused in reservoir simulation projects. During the simula-tion portion of the project, engineers would modify thedescription as necessary to match actual reservoirperformance, based on measured pressure and productiondata at each well as the matching criteria.

Seismic Verification

The initial seismic model honors both the structurecontained in the seismic data and the high verticalresolution from the wells. However, it need not tie exactlyto the seismic amplitudes at each trace nor to the ob-served values of the optimal seismic indicators derivedfrom the seismic interpretation. Engineers use theseseismic amplitudes and indicators to update the model sothat its fine structure not only ties together at the wells,but also ensures that the model predicts the seismicattributes at each trace location.

Fluid movements in the reservoir are not expected tochange structural characteristics, but the different fluidsin that structure will change its seismic response. As aresult, the detailed structural model derived from the basesurvey also applies to the monitor surveys.

SeismicProcessing

Seismic DataAcquisition

Seismic DataInterpretation

GeologicalModel

Seismic ModelBuilding

Well TestAnalysis

SeismicVerification

SimulationModel Building

SimulationVerification

Final Integrationand Verification

Reservoir FluidSaturation Distribution

Well LogAnalysis

Figure 2.6—Reservoir monitoring process flowchart


Simulation Model-Building

After completing the previously described phases, teammembers develop a complete, detailed reservoir descrip-tion, which includes the integration of all seismic data,well log data, and pressure-transient test results with ageologic model. The combination of these data forms thereservoir model that the team uses to simulate fluid flowthroughout the reservoir.

During this phase, engineers verify the simulation byhistory-matching all the time-dependent data through thechanges in the reservoir description within geologicbounds. This step is similar to the normal history-matching process except, in addition to production andpressure information at well points, the information to bematched includes saturation profiles obtained from thesurface-reflection seismic portion of the reservoirmonitoring process. Therefore, a great deal more data areavailable for the reservoir simulation verification process,making the results of the process more detailed than theresults for a standard history match.

The result is a match of all of the production and monitor-ing information and a final reservoir description asexpressed by the data in the reservoir simulator.

Reservoir Fluid Saturation Distribution

The resulting reservoir simulation is as accurate anddetailed as possible from available data. Engineers canuse the simulation to generate saturation maps describingthe current distribution of fluids or to predict futurereservoir response to various production and develop-ment scenarios.

Example

Figure 2.7 is a single-layer map of a reservoir. Theincreases in gas saturation from the first time interval tothe second time interval are in the highlighted area thatwas swept by gas during the interval. The white areas onthe map indicate areas where displacement and gassaturation were unchanged. The simulation does notinclude seismic time-lapse data.

N

900 850 800 750 700 650 600 550 500 450

23

4

24

20

Wells shown at Base Brent positions

Sg Difference, OSEBERG 3

100

50

0

0.05

0.20

0.35

0.50

0.65

0.80

0.95

Meters

Met

ers

Figure 2.7—Gas-saturation difference map showing gas-displaced area estimated by simulation (Courtesy Norsk Hydro,Bergen, Norway)



Figure 2.8 is a seismic amplitude difference map for thesame reservoir, showing the difference in seismic datavalues from surveys taken 16 months apart. Becauseseismic reflections from formation interfaces should notchange, the map shows the difference in gas saturationsbetween the two points. However, since conditions cannotbe exactly duplicated from one survey to the next, noise,in the form of colored areas, also appears on the map.The area considered to show actual gas movement is themagenta and red band east of Well 20. (Note the resem-blance to the band in Figure 2.7, Page 2-13.) This bandshows how the gas front has moved in the time intervalbetween surveys.

Because they are relatively small compared to thereflections at formation interfaces, the seismic reflectionsat changes in fluid saturations cannot be readily seenfrom a single seismic survey. However, since differencemaps subtract the features of the reservoir that do notchange, engineers can use these maps to locate a fluidfront and determine how it is moving through a reservoir.Although this particular example is for a single horizontalslice, vertical fluid positions and movement can also bedetermined from these maps.

ConclusionsThrough the use of well testing, reservoir descriptions,and reservoir monitoring, engineers can more effectivelyplan and implement a successful conformance controltreatment. Chapter 3 provides specific informationregarding the methods and equipment available forreservoir evaluation and problem identification.

BibliographyArcher, S.H. and Martinez, R.D.: “A Comparison of

Petrophysical Equations for Extrapolation of Lithol-ogy Beyond Well Locations Using Seismic Data,”presented at the 53rd Meeting of the EuropeanAssociation of Exploration Geophysicists, Florence,May 1991.

Archer, S.H., King, G.A., and Uden, R.C.: “An Inte-grated Approach to Reservoir Characterization UsingSeismic and Well Data,” paper F03 presented at the1993 Meeting of the European Association of Explo-ration Geophysicists, Stavanger, Norway, June 7-11.

204

24

Wells shown at Base Brent positions

1989-1991 Difference 12-40 Hz 2356

100

50

0

0.04

0.08

0.12

0.16

0.20

0.24

0.28

23

900 850 800 750 700 650 600 550 500 450Meters

Met

ers

Figure 2.8—Gas saturation difference map showing actual gas-front position (Courtesy Norsk Hydro, Bergen, Norway)


Archer, S.H., King, G.A., Seymour, R.H., and Uden, R.C.:“Seismic Reservoir Monitoring - The Potential,”First Break (Sept. 1993) 11 No. 9, 391-97.

Breitenbach, E.A.: “President Breitenbach DefinesChallenges for SPE, Industry,” JPT (Oct. 1993) 918.

Clark, V.A.: “The Effect of Oil Under In-situ Conditionson the Seismic Properties of Rocks,” Geophysics (July1992) 57 No. 7, 894-901.

Cornish, B.E. and King, G.A.: “Combined InteractiveAnalysis and Stochastic Inversion for High-ResolutionReservoir Modelling,” presented at the 50thMeeting of the European Association of ExplorationGeophysicists, The Hague, June 1988.

Domenico, S.N.: “Effect of Water Saturation on SeismicReflectivity of Sand Reservoirs Encased in Shale,”Geophysics (Dec. 1974) 39 No. 6, 759-69.

Dunlop, K.N.B., King, G.A., and Breitenbach, E.A.:“Author’s Reply to Discussion of Monitoring Oil/Water Fronts by Direct Measurement,” JPT(Dec. 1991) 1525.

Dunlop, K.N.B., King, G.A., and Breitenbach, E.A.:“Monitoring of Oil/Water Fronts by Direct Measure-ment,” JPT (May 1991) 596.

Dussan, E.B. and Sharma, Y.: “Analysis of the PressureResponse of a Single-Probe Formation Tester,”SPEFE (June 1992) 151.

Earlougher, R.C. Jr.: Advances in Well Test Analysis,Society of Petroleum Engineers of AIME (1977)New York, 105-122.

Earlougher, R.C. Jr.: Advances in Well Test Analysis,Societyof Petroleum Engineers of AIME (1977)New York, 123-146.

Greaves, R.J., Beydoun, W.B., and Spies, B.R.: “NewDimensions in Geophysics for Reservoir Monitoring,”SPE Formation Evaluation (June 1991) 141-50.

Hao Zhi-xing and Shen Lian-di: “Mechanism of TransitTime Increase and Its Interpretation After WaterInjection Into Reservoir M in the Lao Jun Miao OilField,” SPE Formation Evaluation (June 1988)471-79.

Johnstad, S.E., Seymour, R.H., and Dunlop, K.N.B.:“The Feasibility of Monitoring Fluid MovementsDuring Production from a Norwegian Oilfield Using

Repeated Seismic Surveys,” presented at the 52ndMeeting of the European Association of ExplorationGeophysicists, Copenhagen (May 1990).

Johnstad, S.E., Uden, R.C., and Dunlop, K.N.B.:“Seismic Reservoir Monitoring Over the OsebergField,” First Break (May 1993) 11 No. 5, 177-85.

King, G.A.: “The Application of Seismic Methods forReservoir Description and Monitoring,” presented atthe 1988 SEG/CPS Production Geophysics Meeting,Daqing, Sept.

Maritvold, R.: “Frigg Field Reservoir Management,”North Sea Oil and Gas Reservoirs II, NorwegianInstitute of Technology, Graham and Trotman (1990)155-63.

Martinez, R.D. et al.: “An Integrated Approach forReservoir Description Using Seismic, Borehole, andGeologic Data,” paper SPE 19581 presented at the1989 SPE Annual Technical Conference andExhibition, San Antonio, Oct. 8-11.

Martinez, R.D. et al.: “Complex Reservoir Characterizationby Multiparameter Constrained Inversion,” presented atthe 1988 SEG/EAEG Research Workshop on ReservoirGeophysics, Dallas, Aug.

Revoy, M.: “Frigg Field Production History and SeismicResponse,” presented at the Offshore North SeaConference, Stavanger (1984).

Seymour, R.H. and Archer, J. S.: “Some Requirementsfrom Seismic Methods for Use in Reservoir Simula-tion Models,” North Sea Oil and Gas Reservoirs II,Norwegian Institute of Technology, Graham andTrotman (1990) 139-46.

Seymour, R.H. et al.: “The Potential Contribution ofSurface Seismic Surveys to Monitoring OffshoreOilfields,” presented at the 1989 51st Meeting of theEuropean Association of Exploration Geophysicists,Berlin, May.

Shell: “Science & Technology,” Brochure, SIPM GroupPublic Affairs, ref. PAC/223, Shell Centre London(Dec. 1990).

Wayland, J.R. and Lee, D.: “Seismic Mapping of EORProcesses,” Geophysics: The Leading Edge(Dec. 1986) 36-40.

Testing Methods and Equipment 3-1Chapter 3

Chapter 3

TestingMethodsandEquipment

Many technologies can help engineersdetermine the source of a conformanceproblem, foresee a potential conform-ance problem, or evaluate a conform-ance treatment. This chapter describesthree of these technologies: tracersurveys, logging services, anddownhole video services.

Fluorescent Dyes asWaterflood Tracers

Acknowledgment

Halliburton Energy Services thanksThe Tertiary Oil Recovery Project(TORP) for granting permission topublish the material presented in thissection.

Summary

In cases where very rapid communi-cation (about 5 days) is thought toexist between an injector and aproducer, fluorescent dyes areconsidered excellent tracer materials.These dyes are adsorbed to someextent on typical reservoir rocks, buteven trace amounts can be detectedvisually in the produced waterwithout elaborate chemical analysis.Detection of water flow communica-tion between wells can confirm thepresence of channels and help sizeand plan corrective treatments.

The usual placement method is toinject a concentrated “slug” of thetracer while the normal waterflood ismaintained. Producers offset to theinjection well are monitored for thepresence of tracer. Fluorescent dyesare easily detected by the naked eye

at 1 ppm concentration, equivalentto 1 lb/2,850 bbl of water. A “blacklight” is used to illuminate the watersamples for detection of 50 partsper billion of dye. The extremesensitivity of this detection methodallows the use of dyes, providedresidence time in the reservoir is nottoo long and despite high adsorptionon rock surfaces.

The two most readily availablefluorescent tracers are sodiumfluorescein, also known as uranine,which is yellow-green, and Rhoda-mine B, which is red fluorescence.Uranine is available from Halliburton(Part No. 70.15632). Pylan ProductsCo., Inc., 1001 Stewart Avenue,Garden City, NY 11530, (516) 222-1750 supplies both dyes. Severalother sources exist, and most labora-tory chemical supply houses havethese dyes.

The amount of dye to use in aparticular situation depends primarilyon how much the tracer will bediluted. A pound of dye in an injectionwell that takes 200 to 500 BWPD is asuggested starting point. This amountprovides sufficient dye for somedilution and adsorption while stillallowing the dye to be detected at theend of a channel.

These dyes are readily water-soluble,and placement is simple. The dye canbe dissolved in water, 1 lb/5 gal, andplaced into an injection well by anyconvenient method. If the well willgo on vacuum, the dye solution canbe dumped in. It can also be addedthrough a lubricator or injected withthe waterflood pump. If pumping the


3-2 Testing Methods and Equipment Chapter 3

tracer is necessary, using a tracer volume of a few barrelsof water to give the pump truck enough fluid to prime thepump would be simpler. (Everything the truck pumps fora day or two may be dyed after pumping these materials.)After placement of the dye, return the well to normalinjection to displace the tracer.

Monitor offset producers fairly often over the nextseveral days for the presence of the dye. The tracertypically “spreads out” in the formation and continues toshow up for some time after initial breakthrough. Theinitial appearance is the piece of data that allows observa-tion to estimate the shortest path between the injector andoffset producers.

If more quantitative calculations are required, such as massbalances, use other nonadsorbing tracers. Several areavailable that require only simple lab (or field) chemicaltesting. A good reference on these is listed below.

Terry, R. E., et al.: Manual for Tracer Test Design andEvaluation, published by Tertiary Oil Recovery Project,4008 Learned Hill, University of Kansas, Lawrence, KS66045. Co-Directors: Don W. Green and G. Paul Willhite.

The majority of the manual published by TORP follows.

Manual for Tracer Test Design andEvaluation

Abstract

The purpose of this information is twofold: (1) to providebackground information on a technique that utilizeschemical tracers to describe fluid flow in reservoirs and(2) to provide information that will assist an operator inthe design, implementation, and analysis of a tracer study.

Background Information

As the need for implementation of enhanced oil recoveryprocesses increases, the need for better reservoir andfluid-flow description also increases. Enhanced oilrecovery processes often use expensive chemicals, suchas polymers, surfactants, and cosurfactants. A knowledgeof the path those chemicals will traverse in the reservoiris necessary to make wise and efficient use of them. Welllogs and core permeability data provide some informationabout the region near the wellbore.

A knowledge of previous waterflooding history can adduseful information about interwell communication. Also,pressure transient tests, which can be rather expensive,can supply information about fluid flow between wells.

Another source of information of reservoir behavior is totrace injected water with a chemical and observe whenand where that chemical is produced. Several tracer testshave been reported in the literature (Page 1-5) thatprovide design and analysis techniques. A well-plannedand executed tracer test can provide information in some,if not all, of the following areas.

Directional Flow Trends

When a chemical tracer is injected into an injection welland the surrounding producing wells are monitored,different arrival times for the tracer could indicatepreferred flow paths or directional flow trends. Thesepreferred flow paths would be from the injector to thespecific producers that receive the most tracer at theearliest time. Adjustment of injection and withdrawalrates could alter these directional flow trends, giving animproved sweep efficiency.

Identification of Rapid Interwell Communication

If a channel or high-permeability streak exists between aninjector and a producing well, a tracer experiences a veryearly breakthrough. This early breakthrough identifiesproblem injection wells that could require a treatment toalter permeability.

Volumetric Sweep

Through a knowledge of injection and production rates,pattern layout, and the pore volume in the reservoir,breakthrough of tracers often yields an estimate for thevolumetric sweep efficiency. Very small injected volumesof floodwater to breakthrough indicate the existence of achannel or high-permeability streak and give an estimatefor the volume of that zone. Larger injected volumes tobreakthrough indicate a more uniform permeabilitydistribution, and again, a volume of the swept zone couldbe estimated.

Delineation of Flow Barriers

If a fault or some other barrier to fluid flow is thought toexist near a producing well, tracers can be injected intoinjection wells surrounding the suspect producing well.The failure to observe one or more tracers in the produc-ing well could be the result of a flow barrier.

Two other areas where the use of tracers provide usefulinformation are (1) evaluation of sweep improvementtechniques and (2) evaluation of relative flow of twodifferent fluids, such as brine and polymer. The formerrequires that a tracer study be conducted before and afterthe application of a sweep improvement process. The


latter requires the injection of a different tracer in eachfluid of interest.

If the measured breakthrough times are different for thetracers, then the fluids could be assumed to have con-tacted different portions of the reservoir and thus havedifferent flow characteristics.

Greenkorn described the ideal tracer as “one that wouldfollow the fluid of interest exactly as the fluid front.” Butthe ideal is impractical to attain because adsorption-desorption effects cause the tracer to lag behind the front.These effects, plus diffusion-dispersion effects, cause thetracer front to spread out more than the fluid front.Carpenter et al. have set forth the following requirementsfor a tracer to be satisfactory in measuring the movementof flood water in secondary recovery operations.

1. A tracer should be quantitatively determined in lessthan 10 ppm concentration.

2. It should be either absent or present only at lowconcentrations in the displaced and injected waters.

3. It must not react with the injected or displaced watersto form a precipitate.

4. It must not be adsorbed by the porousmedium.

5. It must be cheap and readily available.

There are four general types of tracers for use in aqueoussystems: radioisotopes, fluorescent dyes, water-solublesalts, and water-soluble alcohols. The radioisotopesprovide an advantage because they are easily detectablein small concentrations and have insignificant adsorptionlosses in the reservoir. Tritium as tritiated water is one ofthe most widely used tracers in the field. However, a firmlicensed by the Nuclear Regulatory Commission isrequired to handle and inject all radioisotope materials.Frequently, when radioactive materials are used, it isnecessary to work with state agencies as well. Thefluorescent dyes can also be detected in very smallconcentrations, but they have the disadvantage of beinghighly adsorbed on reservoir rock. The dyes should onlybe used in cases where there is thought to be a very rapid(5 days or less) communication between an injector and aproducer.

When radioactive tracers are prohibited because of a lackof a licensed firm to do the handling, water-soluble saltsand alcohols are the tracers most frequently used. A fewof the common water-soluble salts and alcohols are listedbelow.

Preferred Water Tracer Materials

Ammonium Thiocyanate (NH4SCN)

Ammonium Nitrate (NH4NO3)

Sodium or Potassium Bromide (NaBr or KBr)

Sodium or potassium Iodide (NaI or KI)

Sodium Chloride (NaCl)

2-Propanol (IPA)

Methanol (MeOH)

Ethanol (EtOH)

Analytical techniques to measure the concentrations ofeach of the tracers mentioned are described in theChemical Analysis of Data section. Unfortunately, not allof the analysis techniques can be performed with ease inthe field. This requires using a supportive laboratory forsome of the chemical analyses.

Care should be taken to determine the background levelsin field waters of any ions that might interfere with theanalysis of those ions that are considered tracers. Highlevels could inhibit the measurement of tracer concentra-tions in produced samples. Compatibility tests shouldalso be made on the proposed tracers with the injectedbrines. Adsorption of ions onto the reservoir rock surfacecould be detrimental to using a particular water-solublesalt.

The water-soluble alcohols, with the possible exceptionof 2-propanol, are susceptible to biodegradation andtherefore should be used with bactericides where thebactericides are usually in concentrations of about 50ppm. Produced samples should also be treated with thebactericide to prevent alcohol degradation before thesamples are analyzed. 2-Propanol does have a limitedsolubility in some crude oils, which could cause retentionof the alcohol in the reservoir. All of these factors shouldbe considered before selecting a tracer.

Information Necessary to Plana Tracer Test

Before a tracer test can be designed, a pilot or patternarea needs to be defined. Once a pilot area is chosen andwell pattern and isopach maps are collected, all availablereservoir data are analyzed to determine reservoirpermeability, pore volume, water saturation, and forma-tion thickness. These data, combined with productiondata, including injection and withdrawal rate information,are needed to calculate the required amounts of tracersand to model tracer breakthrough. Information pertainingto the effectiveness of a waterflood that may have beenconducted in the pilot area is also useful in the design andanalysis of a tracer test.

The importance of keeping good records of all productionand injection data and workover information for each



well in the pilot area cannot be overemphasized. Theserecords need to be kept for each well in the pilot area. Itis not enough to know the production rate for the entirefield or pattern area. A test on each production well onceor twice a month would be sufficient to identify theindividual well rates. The individual well production andinjection rates are necessary to make material balancecalculations and also, as mentioned above, to provideinput data for the mathematical treatment of the data. Thematerial balance calculation is useful in determiningexpected breakthrough times and places.

Before any tracers are injected, the reservoir must be“pressured up.” This requires that the reservoir be onwaterflood long enough to fill any void space, thereforeminimizing potential loss of tracer material.

Another major consideration in designing a tracer test isthe information obtained from the analysis of field brinesand supply waters used in injection wells. Backgroundlevels should be determined for all chemicals beingconsidered as tracers. Often, a chemical analysis has beenconducted on a water sample. This analysis usuallyprovides concentrations of Na+ and Cl- ions, bivalent ions,such as Ba2+, Ca2+, and SO

42-, and the amount of total

dissolved solids, density, viscosity, and turbidity of thewater sample. A synthetic brine can be made using thecompositions determined from the water analysis. Syn-thetic brines are usually easier to work with than actualfield brines, and as a result, tracer analysis techniques aretypically developed in the synthetic brine. However, beforea specific tracer is finally chosen, it is necessary todetermine the background level and test the analysisprocedure for the tracer in the actual field brine and/orsupply water. If a tracer is not compatible with the fieldbrine or the field brine contains ions that interfere with thetracer analysis test, that tracer should not be used.

A knowledge of which, if any, chemicals are being usedas treating agents is also useful in the design of a tracertest. Oxygen scavengers or bactericides are frequentlyused to keep corrosion to a minimum. If bactericides areused, the water-soluble alcohols become prime candidatesfor use as tracers.

Calculation of Tracer Amounts

The amount of a tracer that should be used for a givenapplication can be calculated by several different meth-ods. This section isolates one of those methods.

If the pore volume associated with a given injection wellcan be determined, the amount of tracer can be calculatedby assuming the tracer will dilute the entire pore volume.

For example, consider the injection well in Figure 3.1and the corresponding reservoir data.

Figure 3.1—Pattern Layout for Tracer AmountCalculation.

DN

0011

36

Average reservoir thickness, h = 20 ft

Average reservoir porosity, φ = 25%

Average water saturation, Sw = 55%

Density of tracer solution, 350 lb/bbl

The areal extent of the reservoir associated with thisinjection well will be given by:

Area = d2

The distance between producing wells (d) can be calcu-lated from:

2 (2002) = d2

d = 283 ft

The pore volume associated with this injection well is:

Pore Volume = (Area) (h) (φ)

PV = (80,000) (20) (0.25)

PV = 400,000 ft3 or 71,238 bbl

The water pore volume can be obtained by multiplying bythe water saturation.

(PV) Sw = 71,238 (0.55) = 39,181 bbl


If the density of the tracer solution is multiplied by thisvolume, the result is the mass (in pounds) of the tracersolution that would occupy the entire water-pore volumeassociated with the injection well.

Mass of tracer occupying entire water pore volume, mpv.

mpv: 39,181 (Density) = 39,181 (350) = 13.71 x 106 lb

If the required concentration is 10 ppm of tracer in theeffluent, the amount of tracer (m) that needs to be inject-ed will be:

m = (mass) (concentration in effluent)

m = (13.71 x 106) (10/106)

m = 137 lb

Frequently a safety factor is used in engineering calcula-tions. The magnitude of the safety factor is in the range of 2to 5 but can be higher, depending on the operator. A safetyfactor of 2 means that 274 lb of tracer would be required.Summing up the calculations and combining them into oneequation gives the following expression for m.

Eq. 3.1:

m = 0.356 (Area) (h) (φ) (Sw) (Density) (Desired Concen-

tration)

The constant contains a safety factor of 2 and a conver-sion factor, 5.615 ft3/bbl, to convert the pore volume in ft3

to barrels.

If the area is known in acres, the equation becomes:

Eq. 3.2:

m = 15,516 (Area) (h) (φ) (Sw) (Density) (Required

Concentration)

Assuming a desired breakthrough concentration of 10ppm and a density of 350 lb/bbl, Eqs. 3.1 and 3.2become:

Eq. 3.3:

m = 0.001247 (Area) (h) (φ) (Sw)

Eq. 3.4:

m = 54.3 (Area) (h) (φ) (Sw)

Injection and Sampling

Tracers are injected into the reservoir as rapidly aspossible. The alcohols and other liquid tracers should bediluted at least 50% with the injection water beforeinjection. The solid tracers, usually obtainable in 50- to100-lb bags, need to be mixed with the injection water.Care should be taken to stay well below the solubility ofthe tracers in the brine water. Table 3.1 lists solubilitydata for several common tracers in distilled water.

The solubility of the tracers in actual field brines is lessthan those listed in Table 3.1. Once a concentration isdetermined, it should always be tested in the actual fieldbrine. This test gives the operator an indication of howmuch mixing time will be required to dissolve the tracerand confirms that it will be soluble. The third column inTable 3.1 gives recommended concentrations. Theserecommended concentrations can be used as startingpoints for specific applications.

Figure 3.2 (Page 3-6) is a schematic representation of aninjection system. The system consists of a pumping unit,mixing tank, and lubricator. The mixing tank should havea capacity of about 10 bbl. The lubricator should have acapacity of about 2 bbl. The solution of water-solublesalts can be prepared easily in the mixing tank using thepump to recirculate the water. While the water is circu-lated, the tracer is added to the system. The circulationaction is usually enough agitation to solubilize the tracer.

Tracer

Solubility in Distilled Water

(lb/bbl)

Recommended Injection Concentration

(lb/bbl)Ammonium Thiocyanate 420 200

Ammonium Nitrate 1,280 200

Sodium Bromide 278 100

Potassium Bromide 187 100

Sodium Iodide 556 100

Potassium Iodide 446 200

Sodium Chloride 125 50

Table 3.1—Solubilities and Recommended Injection Concentrations



Sampling the produced water in the surrounding produc-ing wells is a very important part of the tracer program.Samples need to be taken often enough that the initialbreakthrough of tracers is not missed. On the other hand,the more often samples are taken, the more analyticalwork needs to be done, which adds expense to theprogram. A rule of thumb for sampling frequency in termsof expected breakthrough is presented in Table 3.2.

Any information the operator has on the field, i.e.,response to waterflood, etc., should be used to helpdetermine a sampling frequency.

Chemical Analysis of Data

A variety of chemicals have been used to follow the flowof water through porous media. An ideal tracer is amaterial that is easy to detect, does not interact with therock or the oil, is inexpensive, and free of environmentalhazards. All these characteristics cannot be found in asingle substance. However, several chemicals have beenidentified that meet part of the criteria and have beensuccessfully used to monitor flow of water in oil reser-voirs. Only two classes of chemicals are considered inthis (TORP) manual: alcohols and salts.

Alcohols

For tracing water flow, only water-soluble alcohols, suchas methanol (methyl alcohol), ethanol (ethyl alcohol), 1-propanol (n-propyl alcohol), and 2-propanol (isopropylalcohol) are useful. Analysis of any of these alcoholsrequires equipment not normally found in the oil field.The easiest and most rapid method of analysis for water-soluble alcohols is by gas chromatography. Operating theequipment can be performed by field personnel. How-ever, setup, maintenance, and interpretation of unusualresults requires trained personnel. Since analysis ofalcohols by gas chromatograph does not lend itself toonsite analysis, no details of analytical procedure areincluded in this version of the (TORP) manual.

For completeness, the advantages and disadvantages ofalcohol tracers are listed below.

Advantages

1. Alcohols listed above are compatible with injectionwaters.

2. Four tracers can be detected and determined in oneanalysis.

3. Analysis procedure lends itself to automation in thelaboratory.

4. Alcohols are relatively inexpensive.

Disadvantages

1. Alcohols are susceptible to biologicaldegradation.

2. Propanol has some solubility in oil.

3. Analysis does not lend itself to rapid onsite determi-nation by field personnel.

4. Alcohols are flammable and can bedangerous.

5. Alcohols are sometimes found in well-treating fluids.

Salts

Various inorganic salts have been used to trace the flowof water. A salt is comprised of two parts: the cation andan anion, which provides two distinct entities whendissolved in water. For example, sodium chloridedissolves in water to give sodium cations and chlorideanions. Each ion is a tracer. Chloride anion can bedetermined easily, but the sodium cation is determinedwith difficulty. Using chloride anion as a tracer does notdepend on the sodium cation.

Thus, potassium or ammonium chloride could be substi-tuted for sodium chloride, if chloride is the tracer.

Pump

Mixing Tank

Pump

Lubricator

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Figure 3.2—Typical injection system.

Breakthrough Sampling Interval1 day 1 to 2 hours2 days 2 to 3 hours3 days 4 to 8 hours

4 to 7 days 8 to 16 hours1 to 2 weeks once a day2 to 4 weeks every other day

1 or more months once a week

Table 3.2—Sampling Frequency in Terms of Expected Breakthrough


Three salts have been used as tracers, ammoniumnitrate, sodium bromide, and ammonium thiocyanate.Each of these tracers is discussed separately. Thediscussion includes a description of an analyticalmethod of determination.

Nitrate

Nitrate is determined colorimetrically by the reduction ofnitrate by cadmium metal in acid solution in the presenceof gentisic acid to give a colored material. The properproportion of reagents is conveniently combined in acommercial product by Hach Chemical Company ofLoveland, Colorado. The analysis procedure follows.

Procedure

1. Place 25 mL (2 tablespoons) of water sample in asmall bottle. It is convenient to use a two-ouncebottle and fill it one-half full of the sample.

2. Add contents of NitraVer V reagent pillow to bottle.

3. Shake bottle for 1 minute.

4. Let stand for 5 minutes.

5. Compare the intensity of amber color to set of standardsolutions or to a color wheel, or measure the intensity ofthe color in a spectrophotometer at 500 nm.

For field work, the color cube of a color comparatorwheel available from Hach Chemical works well.Detection and estimation of amount of nitrate can beperformed by non-experienced personnel.

Advantages

1. Ammonium nitrate is readily available from fertilizersuppliers and venders.

2. It is inexpensive.

3. Analysis can be performed in the field by non-skilledpersonnel.

4. It is a minimal biohazard.

Disadvantages

1. Ferric iron in the water can cause high results. Largeamounts of chloride cause low results.

2. Barium in the water causes turbidity that can causecolor comparison difficulty.

3. Colored substances in the water can look like theamber color developed during the reaction.

4. Ground waters can contain nitrate from runoff fromadjacent fields.

5. Using nitrate as a tracer has met with mixed successin the field.

Thiocyanate

The presence of thiocyanate in water can be detected byferric thiocyanate complex, which colors the water red.The intensity of the red color indicates the amount ofthiocyanate present. Certain materials in the water caninterfere with the formation of the ferric thiocyanatecomplex. The salt in 20,000 ppm brine decreases theintensity of the red coloration by about one-half. Copper,zinc, and lead form an insoluble precipitate with thiocy-anate. As a result, the thiocyanate is no longer availablefor forming the red ferric thiocyanate complex.

Reagent Solutions

1. Ferric chloride

a. Weigh out 10 g FeCl3 • 6H

2O and place in one-

liter flask. Measure out 15 mL concentrated HCland add to flask. (Caution: HCl fumes areirritating to eyes and nose.) Add distilled waterto make 1 L of acid ferric chloride reagent, or

b. Weigh out 1.5 oz of FeCl3 • 6H

2O and place in

1-gal glass or plastic container.

Measure 1.5 fluid oz (3 tablespoons) of concentratedhydrochloric acid and add to a 1-gal container. Adddistilled water to make 1 gal of acid ferric chloridesolution.

Note: Concentrated HCl is 12 normal. If six normal HClis available, double the amount stated. The six normalacid is less irritating to handle than the concentrated acid.

Procedure

1a. Take 100-mL of sample water and add 10 mL offerric chloride solution. A red color developsimmediately if thiocyanate is present, or

1b. Take one cup, 8 oz, of sample water and add onetablespoon of ferric chloride solution. A redcolor should develop immediately on mixing ifthiocyanate is present.

2. Compare intensity of color with that of standardsamples or measure color intensity in spectrophotom-eter at 450 nm.

Standard Solutions

Solution 1

1. Weigh out 1.3 g of ammonium thiocyanate anddissolve in 1 L of water. This gives 1,000 ppmNH

4SCN solution.

2. Take 100 mL of NH4SCN solution and dilute to 1 L.

This gives a 100-ppm NH4SCN solution.



3. Take 10 mL of 100-ppm solution and dilute to 1 L.This gives a 10-ppm NH

4SCN solution, or

Solution 2

1. Weigh out 2 oz of ammonium thiocyanate (NH4SCN)

and dissolve in 1 gal of water. This gives a 11,430-ppm NH

4SCN solution.

2. Take 8 oz of NH4SCN solution and dilute to 1 gal.

This gives a 700-ppm NH4SCN solution.

3. Take 8 oz of 700-ppm solution and dilute to 1 gal.This gives a 45-ppm NH

4SCN solution. If necessary,

prepare other concentrations of NH4SCN by dilution.

Since 20,000-ppm brine causes a decrease in colorintensity, it is convenient to use produced water tomake the NH

4SCN solution.

Advantages

1. Thiocyanate can be detected in the field by fieldpersonnel.

Disadvantages

1. Copper, lead, and zinc in the produced waterinterfere with the formation of red ferric thiocyanate.

2. High brine concentration reduces sensitivity of thetest.

3. Bromide is determined colorimetrically by theoxidation of bromide to bromine in acid solution bypotassium bromate. The intensity of the reddishbrown color of bromine in water can be used toestimate the amount of bromide. As an alternative,the bromine can be extracted into chloroform orcarbon tetrachloride. This is helpful if the watersample is yellowish in color.

Reagent Solutions

1. Potassium bromate

a. Weigh 1 g of KBrO3 and dissolve in 1 L of

distilled water, or

b. Weigh 1/2 ounce of KBrO3 and dissolve in one

quart of distilled water. Take 2 oz and dilute to 1quart with distilled water.

2. Acid buffer solution

a. In a well-ventilated area, measure out 85 mL ofconcentrated hydrochloric acid (HC1) and pourinto 1-L flask. Measure out 70 mL of concen-trated phosphoric acid (H

3PO

4) and add to liter

flask. Add distilled water to make 1 L of acidbuffer solution, or

b. In a well-ventilated area, measure out 3 oz ofconcentrated hydrochloric acid in a plastic orglass measuring cup and pour into quart glass orplastic container. Measure out 2 1/2 oz ofconcentrated phosphoric acid and add it to aquart container. Add distilled water to make onequart of acid buffer solution.

Procedure

1. Take 100 mL of water sample.

2. Add 50 mL of acid buffer solution.

3. Add 10 mL of potassium bromate solution.

4. Shake or mix solutions together A reddish-browncolor is indicative of bromine.

5. Optional - Add 25 mL of carbon tetrachloride orchloroform and shake. Reddish-brown color indi-cates bromine is present.

Alternate

1. Take 4 oz, 1/2 cup, of water sample.

2. Add 2 oz of acid buffer solution.

3. Add 1/2 ounce, 1 tablespoon, of potassium bromatesolution.

4. Mix or shake the sample. A reddish-brown color towater is indicative of bromine.

5. Optional - Add one ounce of carbon tetrachloride orchloroform and shake. Reddish-brown color indi-cates bromine is present.

6. Measure the color intensity in a spectrophotometer at390 nm.

Advantages

1. Bromide can be detected in the field by field personnel.

Disadvantages

1. Many brine waters contain approximately 100 ppmbromide.

2. Quantitative determination of bromide does not lenditself to measurement in the field.

3. Presence of iodide can interfere with bromide results.


Logging Methods

FracPressure Analysis

Engineers can combine full-wave sonic measurementswith bulk-density log data to predict fracture height as afunction of the differential pressure between downholetreatment pressure and fracture closure pressure.

The log shown in Figure 3.3 (Page 3-10) shows aFracPressure analysis. Engineers predicted fracture heightbefore the treatment to ensure that the job design limitedfracture growth and avoided the water table. Track 1contains the gamma ray and stress profiles.

Fracture pressure is the amount of pressure equal to theleast principal stress; this pressure is computed from therock properties measured by sonic and density logs. Thisstress profile identifies barriers to fracture growth andstress contrasts between producing zones.

Track 2 of Figure 3.3 shows the calculated static fractureextension. The fracture extension pressure is the pressurenecessary for the fracture to extend vertically. Thepressure blocks indicate the extent of the fracture with thelength of their right-most edge. Track 3 shows formationlithology as determined from an openhole log analysis.

TracerScan Analysis

To determine the effectiveness of hydraulic fracturetreatments, engineers may choose to inject radioactivetracers during the frac job. These tests can be run in twoways: a different isotope can be used in each of severalzones or a fluid stage or a sand stage can be simulta-neously tagged with different isotopes and evaluated witha spectral gamma ray log.

Figure 3.4 (Page 3-11) shows a TracerScan analysis of aspectral gamma ray log run after materials used in ahydraulic fracture job were tagged with two isotopes. Thefoam pad was tagged with scandium-46, and the proppantwas tagged with iridium-192. The gamma ray concentra-tions on the log indicated that each of the three intervalsremained isolated. The scandium relative-distance curvesindicate that the fracture in each zone extended beyondthe perforated intervals, particularly in the upper zone,where the fractures propagated more than 50 ft above theperforations. However, the iridium relative-distance curve

confirms that the propped intervals did not communicatewith one another. Therefore, the TracerScan log con-firmed the fracture height modeling and fracture design,and analysts deemed the operation a success.

Logging ServicesMany logging services are available for detecting andpredicting potential conformance problems. The follow-ing primary logging systems are available:

• Openhole logs

• Cement evaluation logs

• Casing evaluation logs

• Pulsed neutron logs

• Production logs

Table 3.3 (Page 3-12) provides a general overview ofhow each of the logging types can be used for conform-ance control.

Openhole Logs

Openhole logs allow analysts to determine the possiblecauses or contributors to unwanted water or gas produc-tion. Caliper logs reveal severe borehole washout areasthat can contribute to poor cement bonding. Gamma rayand SP logs can help delineate shale beds from possiblewater- or hydrocarbon-producing reservoirs. When theyare combined, resistivity and porosity logs (sonic,density, and neutron) can help analysts determine waterand pay zones. These zones can later be compared tocased-hole logs, allowing analysts to monitor changingwater levels of coning in producing reservoirs.

Figure 3.5 (Page 3-13) is an example of a typicalopenhole logging suite. Figure 3.6 (Page 3-14) is acomputer-processed interpretation that provides informa-tion on the potential of the various reservoirs.

Most openhole logging tools have an outside diameter(OD) of 3 5/8 in. and are rated to 400°F and 20,000 psi.Hostile-environment (small borehole-diameter and high-temperature or high-pressure) tools are also available formore difficult applications.



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Figure 3.3—FracPressure analysis log.


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Figure 3.4—TracerScan analysis.



Problems

Openhole Logs

Cement Evaluation Logs

Casing Evaluation Logs

Pulsed Neutron Logs

Production Logs

Acid job went to water X

Bottomwater coning X X X

Bottomwater shutoff X

Casing leaks X

Channel behind casing X X X X

Channel from injector

Early water breakthrough

Frac job went to water X

High-permeability streak X X X

No shale barrier X X X

Plugging well

Injection out of zone

Lost circulation X X X

Table 3.3—Areas of Application for Well Logs


Figure 3.5—Typical openhole logging suite.

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Figure 3.6—Computer-processed interpretation of openhole log.

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Nuclear Magnetic Resonance

Intensive research and development has led to successfuldownhole porosity measurements employing pulsedNuclear Magnetic Resonance (NMR) technology. NMRhardware, as well as interpretation methods, have beenimproved significantly. Currently, log analysts can usepowerful NMR interpretation methods for estimatingbound and free fluids, and for direct hydrocarbon-typing,including gas detection.

NMR technology can help analysts determinepetrophysical parameters that cannot be obtained fromtraditional logging methods. The MRIL tools can providethe following information:

• A lithology-independent porosity

• Formation permeability

• Free and bound water volumes and saturations(Sw-Swirr)

• Hydrocarbon detection

• Hydrocarbon typing

• Grain-size sorting and identification of reservoirheterogenities

• Linkage to clay type

Unlike the neutron/density combination, which is sensitiveto hydrogen bound in the formation and in fluids, NMRmeasurements are sensitive only to hydrogen in fluids.Thus, NMR measures the amount of bound and free fluidin a tool-dependent rock volume (the “sensitive volume”).

Combining the advantages of NMR with new interpreta-tion software allows conformance evaluation, design, andplacement improvements. This process, called StiMRIL,is a total analysis of the reservoir, consisting of produc-tion data, reservoir history, and other analytical tools toachieve a high degree of reservoir and fluid knowledge.

Figure 3.7 (Page 3-16) is a StiMRIL flow presentation.Within the depth track on the left side of the log are payflags and the numbers assigned to the selected zones, asdetermined by the zoning process. The red lines across allthe tracks delineate the zones that were chosen based onNMR permeability (MPERM). The tracks contain thefollowing information:

• Track 1 contains gamma ray, caliper, bit size,temperature, and T

2 bin information.

• Track 2 presents the clay-bound-water T2 variable-

density image.

• Track 3 presents the variable density image of theT

2 distribution generated from echo trains acquired

with long polarization time.

• Track 4 contains the NMR analysis, whichincludes effective porosity, bound water, movablewater, and hydrocarbons.

• Track 5 presents permeability calculated fromNMR measurements.

• Track 6 provides five different flow calculations tohelp operators determine the economic potential ofeach zone. The inflow analysis is based on classicreservoir engineering principles and includes avariety of inputs such as estimates of fracture half-length, skin, flowing sandface pressure drop, etc.

Track 6 also displays two normalized curves that helpoperators interpret zones of interest: permeability feet(NKH) and porosity feet (NPORH). Both are normalizedfrom 0 to 1 over the entire well. These curves provide acomparison of porosity and permeability in each zone andcan be used in pipe-setting economics.

Visual analysis of the log based on the pay flags and on theNMR analysis reveals that Zones 4, 6, and 8 could becandidates for completion and possible stimulation. Thesethree sands seem to exhibit comparable properties basedon the log display. Without StiMRIL information, all threezones would likely be completed and fractured togetherwith standard production-enhancement procedures.

An inflow profile for each zone is calculated based onreservoir pressure information and NMR permeability.The family of flow potentials presented is based on idealinfinite fracture conductivity half-lengths. For high-permeability reservoirs and matrix acidizing, the inflowanalysis is based on a family of skin values rather thanfracture half-length. This idealized inflow analysis is thefirst step in profit optimization. Combining flow informa-tion with treatment costs (consisting of both initialstimulation and possible conformance) is the first step indetermining economics.



Figure 3.7—StiMRIL presentation showing flow estimates and zoning based on permeability.

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Cement Evaluation Logs

The primary reason for cementing casing into a wellbore isto achieve hydraulic isolation between formations. Often,unwanted fluids can flow into the casing because ofimproper cementing procedures, bad borehole conditions,well age, or workover operations. Cement bond logs(CBLs) help analysts determine the current condition of thecement annulus and diagnose potential fluid-flow paths.

Cement evaluation logs are produced by conventional CBLtools or ultrasonic bonding tools. Most of these tools have a3 5/8-in. OD and are rated for at least 350°F and 20,000 psi.A few of the tools are available in 1 11/16-in. diameters forthrough-tubing applications.

Conventional Bond-Logging Tools

Conventional bond-logging tools have a single acoustictransmitter and two receivers. The receivers are typi-cally spaced approximately 3 ft and 5 ft from thetransmitter. The acoustic signals generated during eachtransmitter pulse travel to the receivers along variouspaths through the borehole fluid, casing, cement, andformation. The logging system records the waveformsand determines travel times and amplitudes of signalsreaching the receivers.

The first signal that arrives at the near receiver generallycorresponds to the first acoustic signal that traveled fromthe transmitter, through the borehole fluid, the casing,through the borehole fluid again, and back to the receiver.This signal is often called the pipe arrival. The associatedtransmitter-to-receiver travel time is recorded on the logas the travel-time curve.

In free pipe, the travel-time curve can be used to indicatetool centralization. In a particular size of unbondedcasing containing a particular fluid, the travel time shouldbe constant, except when collars are encountered. Avarying travel time may indicate that the tool is notcentered in the casing; therefore, the signal amplitudemeasurements may not be accurate.

If a sufficient bond exists between the pipe, cement, andformation, formation signals appear in the wave train.These signals traveled through a portion of the formation(and through cement, casing, and borehole fluid) beforereturning to the receiver. In slow formations, such assandstones, the acoustic wave travels more slowlythrough the formation than through the casing. As aresult, the first formation signal, or formation arrival,arrives at the receiver after the pipe arrival.

In fast formations, such as low-porosity limestones anddolomites, the acoustic wave travels more quicklythrough the formation than through casing. As a result,the formation arrival can occur before pipe arrival. Ifsuch circumstances exist, variations in the travel-timecurve can correspond to variations in the formation anddo not necessarily indicate whether the tool is centered inthe borehole.

The far receiver indicates the amplitude of the pipesignal. This signal is displayed on the log as the pipeamplitude curve. This receiver records the entire acousticwaveform. Analysts can qualitatively analyze waveformdisplays to determine if the following conditions exist:

• Free pipe

• No cement bond to formation

• Partial cement bond to formation

• Good cement bond to formation

Figure 3.8 (Page 3-18) shows conventional bond-logresponses to some of those conditions, and the generalwaveform appearance is illustrated for each of theconditions shown.

Free pipe is not firmly bonded to the cement sheath inFigure 3.8a. It vibrates freely with little signal attenuation.Both the pipe amplitude curve and the X-Z display showhigh-amplitude pipe signals in a free-pipe zone. Thealternating dark and light streaks on the X-Z display appearas straight traces. Casing collars appear as “w” patterns.

When cement is bonded to the pipe but not the formation,the pipe cannot vibrate freely, and poor acoustic couplingoccurs between the cement and the formation. The signalcannot travel effectively from the transmitter, through theformation, and back to the receiver. As a result, the logrecords low-amplitude pipe and formation signals, whichappear on the X-Z display as a lack of well-defined traces.

A partial bonding of cement and pipe can result fromchannels in the cement or from a microannulus betweenthe pipe and cement (Figure 3.8b). This condition isindicated on the X-Z display by pipe and collar signalsthat are accompanied by strong formation signals.Additionally, the pipe amplitude curve is high. If amicroannulus is suspected, the logger can increase thewellhead pressure and relog across the zone of interest. Ifthe X-Z display on the relogged interval indicates a goodbond, a microannulus exists. If a good bond does notexist, the cement may contain a channel.



Figure 3.8—Example log showing (a) free pipe, (b) partially bonded, and (c) fully bonded.

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A strong, identifiable formation signal with no pipe signalsuggests effective zone isolation and a good bondbetween both the cement and the pipe and the cement andthe formation (Figure 3.8c). Under these conditions, thepipe amplitude curve should be low.

Normal CBL interpretation assumes that changes in pipe-signal amplitude are caused by changes in bonding only,but other factors can cause variations in pipe-signalamplitude. If they are not recognized, bonding conditionscould be misinterpreted. These factors include changes inthe following:

• Pipe diameter, weight, and thickness

• Borehole fluid density

• Cement thickness and compressive strength

• Transmitter signal strength

• Receiver sensitivity

Several of these factors can be eliminated. For example,the depths where pipe-size changes exist are usuallyknown. For cement-sheath thicknesses greater than 3/4 in.,changes in cement thickness have little effect on signalattenuation.

Ultrasonic Bond-Logging Tools

Conventional bond-logging tools are generally omnidi-rectional. The acoustic signals that their transmittersgenerate travel away from the tool in all directions, andtheir receivers are sensitive to acoustic waves arrivingfrom all directions. At a particular instant, the signalamplitude at a receiver is the result of all the acousticsignals arriving at the receiver. As a result, the bondquality determined from these tools is a circumferentialaverage of the bonding around the casing. These twocases are difficult to distinguish because circumferentiallyaveraged amplitude and attenuation can be the same forhigh-strength cement containing a channel and for evenlydistributed low-strength cement.

For annular cement to attenuate the signal, a good shearmechanical bond must exist between the cement and thecasing outer wall. If a gap exists, such as a microannulusbetween cement and casing, the log can indicate poorbonding even if the gap is so thin that it prevents fluidsfrom flowing.

Ultrasonic tools provide the most beneficial data whenevaluating cement placement and bonding. Instead of aseparate source and receiver, the ultrasonic source andreceiver are packaged together as a transducer. Early

ultrasonic tools consisted of eight ultrasonic transducersin a helical array. The new generation of these toolsconsists of one rotating transducer. The ultrasonicscanning or imaging acoustic tool uses a single rotatingultrasonic transducer to produce high-resolution, circum-ferential data. The Circumferential Acoustic ScanningTool (CAST-V) acquires data for both cement evaluationand casing evaluation in the same run or pass. Therotating transducer can provide 36 to 200 measurementsper depth sample, depending upon the service company.Depth-sample rates range from 2 to 12 samples per foot,again depending upon the service company.

Not only can channels in cement be detected, but theorientations of the channels can be determined and theproper squeeze or remedial action can be performed.Because of the high horizontal sample rate, the data arenormally presented in a color-coded image instead of asingle curve. The color coding is based on the imped-ances of gas, water, and cement.

To overcome the limitations of conventional bondlogging tools, Halliburton originally developed theultrasonic Pulse Echo Tool (PET) and the newer CAST-V.PETs contain eight ultrasonic transducers equally spacedin a helical pattern around the main tool body. Forultrasonic tools, each transducer generates an acousticwave that travels toward the casing, perpendicular to thecasing wall. Most of the energy arriving at the inner wallreflects back and forth within the casing, allowing casingthickness to be more easily determined. Some energy istransferred outside the casing at each reflection, so theamplitude of the reflected wave is reduced at eachreflection. For a casing of a specified size and weightcontaining a specified fluid, the rate at which the ampli-tude decreases depends on the acoustic impedance of theannular material.

The fixed 8-transducer PET and the rotating CAST-Vmeasure borehole fluid velocity with an additionaltransducer. The distance from each transducer to thecasing wall can be determined from combining thisinformation with the two-way travel time from thetransducers to the casing inner wall. This will be dis-cussed with more detail in the casing inspection section.

The acoustic impedance of a material is the product of itsdensity and acoustic compressional velocity. The train ofreflected waves returning to the transducer providesinformation about the annular material, which allowsanalysts to distinguish cement, liquid, and gas in theannular space.



The output frequency of the ultrasonic tool ranges fromapproximately 300 to 600 kHz. However, in the region ofa gas-filled microannulus (or in cement containing gasbubbles), the ultrasonic bond log may indicate free pipe.

The preferred cement evaluation program combines theCBL and the CAST-V tools. As illustrated in Figure 3.9,the combined data from both logs provides a morecomplete and reliable evaluation.

The tracks provide the following information:

• Track 1 provides correlation data, averageimpedance, and tool centralization information.

• Track 2 provides information from both the CBL(amplitude curves) and CAST-V (FCBI) about thecement to pipe bond. High-amplitude readingsindicate free pipe while low amplitude readingsindicate good bonding. The FCBI curve is generatedfrom the impedance map and is a method to showthe percent of cement to casing bond.

• Track 3 consists of the CBL waveform, whichindicates both the cement-to-pipe bond andcement-to-formation bond. In fact the CBL tool isthe only tool available to help determine thecement-to-formation bond.

Figure 3.9—Standard CAST-V/CBL presentation showing a channel.

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• Track 4 presents the standard impedance imagefrom the CAST-V, which is corrected to the lowside of the hole. This information will help deter-mine if the cement problem is correctable or not dueto pipe position in the wellbore. The channel on theimpedance image indicates less than perfect zonalisolation. Depending upon the reservoir, the cementmay not provide the necessary zonal isolation toprevent unwanted fluid production.

Figure 3.10 examines the same zone of Figure 3.9. Thetracks provide the following information:


• Track 2 consists of the standard impedance imagefrom the CAST-V.

• Tracks 3 through 11 are the segmented curves fromthe impedance map. The impedance map is brokeninto nine segments, and five equally spaced curvesfrom each segment are plotted. Because the map isoriented to the low side of the hole, Segment E willalways be on the low side, while Segments A and Iwill be on the high side. This curve segmentationallows the actual impedance from each curve to beshown and provides a measure of the activity levelof the data. The channel is clearly identified on boththe impedance map and the segmented curves. Theimpedance of the material in the channel is about1.7, which indicates water.

Figure 3.10—Segmented presentation with the impedance map showing the activity level and impedance values.

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This activity level, called the statistical variation process(SVP), allows analysts to discern solid crystallinestructures, such as cements, from fluids. Solid-freeliquids have a consistent or steady activity level on logswhile solids, when mixed with either fluid or gas, have anirregular activity level. Cement, with a mixture of solids,liquids, or gases, should exhibit a high degree of variabil-ity in the impedance measurement. A consistent phase,such as water, gas, or drilling mud, will exhibit lessvariation in the computed impedance. After tool positionis taken into account, analysis of the vertical rate ofimpedance change can easily determine whether foamedcement or liquid is present.

SVP processing assumes that cements are not consistent,but it does not use the impedance values directly indetermining if the material is solid or liquid. Combiningthe SVP processing methods with the original impedancedata provides an easier method for determining the pipe-to-cement bond. Because liquids should have both lowimpedance and low activity level, this information can helpdetermine if the annular material is solid or liquid. Thisnew image combines the original impedance data with thevariance data to create a new image called cement.

Adapting this technique to the CBL waveform datahighlighted information not currently being used in theevaluation of cement bonding. The essential portions ofthis interpretation are collar response and the waveformamplitudes and behavior in free, bonded, partiallybonded, and microannulus situations. Subtle changes inthe CBL waveform can be seen by the naked eye. Suchchanges would be lost when presented in the conventionalMSG display. Applying the SVP processing to the entireacoustical waveform and determining the variancebetween vertical sample points makes these subtlechanges recognizable. Normally the variance processingresults are added to the standard CBL waveform, high-lighting both the high-amplitude portion of the CBLwaveform and the differences.

This entire process is known as Advanced Cement Evalua-tion (ACE). ACE can expand cement evaluation for anyservice company and tools, including segmented bond logsand other ultrasonic tools, stationary or rotational.

Figure 3.11 (Page 3-23) illustrates a complete newanalysis of both the CBL and ultrasonic data over thesame well as Figures 3.8 to 3.10. The tracks provide thefollowing information:


• Track 2 provides information from both the CBL(amplitude curves) and CAST-V (ZP BI, CEMENTBI) about the cement-to-pipe bond. ZP BI is thenormal bond index from the impedance mapwithout any further processing. CEMENT BI is thebond index from the cement image. These curvesshould track the amplitude curve from the CBLbecause both measurements are an indication ofcement-to-pipe bond.

• Track 3 consists of the CBL waveform, whichindicates both the cement-to-pipe bond andcement-to-formation bond.

• In Track 4, the CBL variance shows the differencebetween vertical samples of the acoustic waveform. The initial vertical distance between the twosides of the wedge is about five feet, the same asthe distance between the CBL source and receiver.As the pipe-to-cement bond increases, the ends ofthis wedge narrow and approach five feet. As thequality of the cement bond increases, the collarresponse disappears almost entirely. The colorschange as the bond increases from the top to thebottom of the log.

• Track 5 presents the standard impedance image.

• Track 6 consists of the cement image, which isdetermined from the impedance and variancecalculation. The channel is still present andprobably will not allow zonal isolation over theinterval.

Casing Evaluation Logs

Many water-entry problems are caused by poor mechani-cal integrity of the casing. Holes caused by corrosion orwear and splits caused by flaws, excessive pressure, orformation deformation can allow unwanted reservoirfluids to enter the casing. Halliburton uses the followingmechanical, electromagnetic, and ultrasonic logging toolsto inspect casing:

• Multi-Arm Caliper tool

• Casing Inspection tool (CIT)

• Pipe Inspection tool (PIT) using Flux Leakage/Eddy Current (FL/EC)

• Circumferential Acoustic Scanning tool (CAST)

• Pulse Echo tool (PET)


Figure 3.11—New analysis of both the CBL and ultrasonic data over the same well as Figures 3.8 to 3.10.D

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Mechanical Logging Devices

Mechanical devices use independent, spring-loaded feelerarms or fingers to measure the internal radius of thecasing. The number of arms can vary from 15 to 80,depending on casing size and tool type. Mechanicalcalipers only provide information about internal casingcondition. Their major deficiency is that they inspect onlya small circumferential fraction of the casing. The size ofthis fraction depends on the number of feeler arms, thewidth of the arms, and the casing size and weight. Forexample, a tool with 40 arms inspecting a 7-in., 35-lb/ftcasing (6.004-in. ID) would cover only 17.0% of the wall

(using a feeler width of 0.08 in.). In a 5.5-in., 17-lb/ftcasing, the fractional wall coverage is approximately21.0%. As a result, locating small holes or splits with amechanical caliper requires multiple passes with the tool.

The logs produced by most mechanical calipers presentminimum diameter (MINID), maximum diameter(MAXID), and remaining wall thickness (REMWAL)curves, as shown in Figure 3.12 (Page 3-24). To computethe remaining wall thickness, analysts subtract themeasured internal radius of the casing from the casingnominal outside radius.



REMWALInch0 .5

MAXIDInch8

8

10

10

MINIDInch

Figure 3.12—Multi-Arm Caliper log for casing inspection.

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Electromagnetic Phase-Shift Devices

Electromagnetic phase-shift devices measure the attenua-tion and phase shift of a transmitted electromagneticsignal to determine circumferential averages of casingthickness and diameter.

Casing Inspection Tool

The Casing Inspection Tool (CIT) is an electromagneticphase-shift device. The CIT casing-thickness measure-ment is made by the transmitter and the near receiver ona one-transmitter, two-receiver coil array. A 30-Hzpulsed electromagnetic field from the transmitterinduces eddy currents in the casing. The eddy currentsgenerate an electromagnetic field that is sensed by thenear receiver. Analysts can determine the casingthickness by examining the phase shift between thetransmitter and near-receiver signals.

On the standard raw-data CIT the resulting curve isdesignated as the thickness index. The measurement has avertical resolution of approximately 18 in. Because thismeasurement is omnidirectional and has a somewhatcoarse resolution, it cannot clearly detect small anomalies.

A second phase-shift is measured between the near andfar receivers. This measurement detects casing anomaliesover a short length of the casing. It has a vertical resolu-tion of about 2.5 in., and the associated curve on the CITlog is designated as the differential index. On this curve,a large deflection to the right followed by a large deflec-tion to the left indicates an increase in metal. A large

deflection to the left followed by a large deflection to theright indicates a decrease in metal.

The CIT also measures casing ID, but with a coil arraythat consists of one transmitter and one receiver. Thetransmitter coil is driven by a continuous 30-kHzsource. The resulting electromagnetic field induces eddycurrents on the inside surface of the casing. The eddycurrents, in turn, generate an electromagnetic field thatthe receiver coil detects. The phase shift between thetransmitted and received signals is a function of thecasing’s ID. This measurement is presented on the log asthe caliper index curve.

One limitation of the CIT is that it cannot clearly distin-guish perforations because perforation diameters aresignificantly smaller than the measurement’s verticalresolution. If perforation diameters are small and shotdensities are low, the volume of metal over a perforatedsection of casing is not much different from the volume ofmetal over an unperforated section. Therefore, thedifferential readings are small, and perforations aredifficult to identify. The CIT can, however, distinguishintervals perforated at high shot densities.

The Multifrequency Electromagnetic Tool

The Multifrequency Electromagnetic Tool (METG) is usedto gauge casing thickness for detection of defective ordamaged casing. This multi-frequency electromagnetic toolmeasures the casing’s magnetic properties, casing ID, andphase shift to accurately compute the casing thickness.


The METG detects oilwell casing flaws, such as corro-sion, casing wear, mill defects, burst pipe, erosion, andcrushing. A noncontact, nondestructive, electromagneticremote eddy current technique is used for determiningareas of metal loss, such as large-scale corrosion, holeslarger than 2 in., and vertical casing splits. The METG iscurrently the only method for detecting casing flaws onthe outer strings of multiple-string casings.

Electrical caliper measurements are commonly used todetermine the inner diameter of the innermost casing in thestring. These measurements help determine whetherdamage to the casing is on the inside or outside of the pipe,and its electrical properties. This caliper measurement isnot affected by nonmagnetic mineral-scale buildup.

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Figure 3.13—METG results compared to the CAST-V in the pipe-inspection mode.

Typically, the METG tools are designed to be run incombination with other casing-inspection tools. Withthrough-wiring, other tools, such as PIT or CAST-V, can berun in combination with the METG. This combination canprovide qualitative information concerning casing integrity.

Figure 3.13 compares the result from the METG with thatof the CAST-V. The following information is provided:

• Track 1 consists of the gamma, eccentricity, andovality.

• Track 2 consists of two calibrated ID (CIDL, CIDS)curves from the METG and average ID from theCAST-V.



• Track 3 consists of the ID from CASE and showssome internal wear.

• Track 4 compares two thickness curves (TH1L,TH2L) with the average thickness from the CAST-V.

• Track 5 shows the thickness image from the CAST-V.

• Track 6 provides thickness information from the tworeceivers of the METG at two frequencies.

Pipe Inspection Tool

The PIT is a FL/EC type of tool. FL/EC devices arewidely accepted for evaluating metal loss. The PITprovides 360° wall coverage with high vertical resolutionby using an array of pad-mounted coils. FL/EC toolsidentify flaws in casing or tubular goods and thendiscriminate between flaws on the external or internalsurface of the pipe.

• Flux Leakage. The flux leakage (FL) measurementis made by an induction coil near the pipe surfacethat is positioned between the north and south polesof a DC electromagnet. Current through the electro-magnet causes lines of magnetic flux in the pipe wall.Normally, this flux is contained within the walls ofthe casing, but when holes, pitting, or other defectsexist in the wall of the pipe, perturbations in the fluxlines cause some flux to spill out of the confines ofthe wall. When the inductive sensor is passed overthese perturbations, a voltage is generated in the coil.The FL coil responds to holes and inner and outerwall defects.

• Eddy Current. An eddy current (EC) excitation coilis driven by an AC source. The sensor is designed sothat in clean pipe, any signal induced into onereceiver coil is canceled by an equal signal in theother receiver coil. Several factors control the depththat the current travels into the pipe wall, althoughcurrent frequency is the primary factor. Normally, thedepth of penetration is very shallow.

When the PIT tool passes a defect on the inner wall, thereceiver coils become imbalanced, first in one direction,then the other. In this manner, a characteristic signature isproduced for the defect on the inner wall, but no responseoccurs for flaws on the outer wall or internal flaws beyondthe skin depth of penetration of the excitation current.

By comparing the response of the FL and EC signals,analysts can determine whether the defect is on the outerwall only, the inner wall only, or is a through-holedefect. FL curves can reveal holes with diameters assmall as 0.1 in. The EC measurements detect defects

with diameters as small as 0.125 in. To help analystsvisualize the pipe condition, FL/EC logs provide plotsof the raw FL/EC curves from each pad as well asdetailed 360° maps of the flux leakage and eddy current.

The PIT tool and associated software allow identificationof casing damage. Once a defect is located, the type, size,and percent of penetration are shown in Figure 3.14(Page 3-27). The PIT processing algorithm allows thestandard joint counter and grading programs to be used.The tracks provide the following information:

• Track 1 provides the gamma, tension, and hall effect,which indicates casing damage and/or quality control.

• Track 2 provides the processed eddy curves that areplotted on the same scale range with a different offset.

• Track 3 provides the processed flux curves that areplotted on the same scale range with a different offset.

• Tracks 4 and 5 indicate whether the defects are onthe inside or outside of the casing. The extent towhich the defects penetrate the casing (as a fractionof casing thickness) determines the grade as shown.Casing grade is determined by defect penetration(again, as a fraction of casing thickness).

• Track 6, the rightmost track on the log, flags casingdefects and identifies each defect as either isolated orcircumferential.

The log example shown in Figure 3.14 is from a wellwithout cement allowing pipe recovery. The pipe wasretrieved and examined showing a hole at 93 meters. Thepipe was photographed as shown in Figure 3.15a (Page3-27). The high sampling rate and full pipe coverage ofthe PIT allows accurate 3D images to be generated asshown in Figure 3.15b. The two images have an excel-lent match showing the casing damage. The hole wasdetermined to be approximately 1/8 of an inch across.

Ultrasonic Casing Tools

Two types of ultrasonic tools are commonly used forcasing inspection: (1) the Circumferential AcousticScanning Tool (CAST) and (2) the Pulse Echo Tool(PET).

Circumferential Acoustic Scanning Tool

The CAST has a rotating ultrasonic transducer that canaccurately measure casing ID, casing thickness, casingovality, and tool centralization. When the transducer ispulsed or fired in the “transmit” mode, a narrow acousticbeam propagates through borehole fluids toward the


Figure 3.14—Casing damage on the outside at 93 meters.

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Figure 3.15—Video capture of the pipe in Figure 3.11 with 3D image of the casing damage using PIT data.

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borehole wall. This beam reflects off the borehole walland travels back through the borehole fluids to thetransducer. The transducer then acts as a receiver torecord the travel time and amplitude of the reflectedsignal. The travel time (or time of flight) is the elapsedtime between the transducer’s firing and the instant whenthe highest amount of reflected energy arrives back at thetransducer. Amplitude is a measure of that peak amountof returning ultrasonic energy.

The CAST-V operates in either image mode or cased-holemode. In image mode, the tool acquires data from theinterior diameter of the pipe or formation. In cased-holemode, data is acquired from the casing ID, the casingthickness, and the annular space between the casing ODand surrounding formation. Both the amplitude andtravel-time data from both modes may be used to helpdetermine the conditions of the casing or riser. Thenavigational package is required to provide geometry ofthe casing or hole. This will allow casing wear to bemonitored accurately.

• Image Mode. In image mode, the scanner evaluatesonly the “inner” surface of the target (the formationbounding the wellbore or the inner wall of the casing).The high vertical resolution (60 samples per ft), andextensive azimuthal sampling (200 shots or radialmeasurements per sample depth) provide the neces-sary information needed for 2D and 3D images. Thetravel time and amplitude of the acoustic waveformcan provide both visual and digital data to indicatecasing integrity or problems. These images are usefulfor evaluating casing integrity by revealing distortion,wear, holes, parting, and other anomalies on the innerwall of the casing.

• Cased-Hole Mode. The ultrasonic scanner alsooperates in cased-hole mode for a thorough casingassessment including wall thickness or pipe-to-cement evaluation. The cased-hole mode determinesboth the internal radii of the casing and the casingthickness. Casing thickness combined with the IDmeasurements can be used to indicate defects on theexterior of the casing. The normal tool operation willprovide a vertical resolution of four samples per ft,and azimuthal sampling of 100 shots per sampledepth. This data can be recorded at 12 samples per ft,but the logging speed needs to be reduced. Theamplitude and travel times are also recorded toprovide image-interpretation capabilities.

The acoustic waveform is processed in cased-hole mode.Casing thickness is calculated by a Fast-Fourier transfor-mation of the frequency content of the waveform itself.

Because the resonant frequency of casing decreases ascasing thickness increases, transducer frequency must beselected according to casing thickness. Further waveformprocessing provides information about the material in theannular space between the casing and the wellbore wall.This annular space is normally filled with cement, drillingmud, water, gas, and other substances. The ultrasonictools determine the impedance value of these materialsand indicate the amount of pipe-to-cement bonding.

Waveform processing achieves cement evaluation andcasing inspection at the same time, without requiringadditional passes. Thus, high telemetry data rates, intenseprocessing capabilities, and selective transducer frequen-cies are required. Before deciding to log with a CAST,engineers must consider the wellbore fluid and the casingwall condition. If the wellbore fluid contains largequantities of solids, the solids attenuate and disperse thetransmitted and reflected signals. If the casing wallcontains scale, paraffin, or other disruptive materials, thereflected signal can be significantly attenuated andscattered, and the data will be useless.

Another major consideration in CAST logging is thedistance from the transducer head to the casing’s innerwall. If the transducer head is too close to the wall, anear-field phenomenon causes the data to be difficult tointerpret. Under these conditions, the acoustic wave isunable to travel a sufficient distance from the transducerto produce a wave front that is planar when it impacts thecasing wall. This planar condition is necessary for gooddata. If the distance is too great, the acoustic amplitude ofthe received signal is greatly reduced. Therefore, theproper transducer head size must be used to ensureoptimal standoff distance.

After the data is acquired in either mode to accuratelyevaluate the internal casing wear, tool position andeccentering need to be accounted for. Spiral or patternssimilar to a barbershop pole are indications of eccentric-ity problems, not necessarily casing wear. Specialprocessing, provided both real time and post acquisition,allows the travel time image to be corrected for the tooleccentering.

After the raw data is corrected, several different programswill allow complete interpretation of the data to com-pletely evaluate the casing damage. Figures 3.16 to 3.18(Pages 3-29 through 3-30) provide detailed informationabout packer damage on 7-in., 26-lb/ft casing. Thesefigures range from the raw data to 3D images. Figure3.16 shows where the packer was set and did not releaseproperly (B). The metal was peeled up when the packer


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Figure 3.16—Raw data from the image mode, allowing easy visualization of the casing damage.

Figure 3.17—Computed results showing casing radius for the packer damage.

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Figure 3.18—Raw data along with three-dimensional image show casing damage.

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was pulled. The amplitude and both the travel timeimages in Figure 3.16 show the channels of the packerpins. They also show that peeled metal is still in thecasing immediately above the damage (C).

• Track 1 provides tool and casing eccentricity andovality data

• Track 2 provides information about the travel time ofthe fluid in the casing along with wellbore deviation

• Track 3 is the amplitude of the first arrival in theimage mode. This will show the greatest detailconcerning any casing damage; Howeve,r the datacannot be used in any further quantitative evaluation.

• Track 4 is the uncorrected travel time for tooleccentricity. This travel time will be used along withthe fluid travel time to determine the casing radius.

• Track 5 is the corrected travel time for tool eccen-tricity. The post-processing software will correct thedata for slight eccentricity errors.


The computed results of Figure 3.17 show the amount ofmetal removed to be approximately equal to the metalremaining above the damage. The indicated damage at(D) is circumferential and seems to have been caused bythe packer compressing against the casing wall. Thesegmented presentation in Figure 3.17 provides adetailed analysis of the casing damage. The maximumdepth of the two grooved pits is about 0.125 in. deep(Segments B, G, and H). In the nondamaged area, theaverage, minimum and maximum radius curves allindicate the known casing radius.

Figure 3.18 uses a standard imaging package to displaythe calculated pipe radius in a 3D view. While theseimages correlate well with both the calculated and rawdata, it is difficult to measure actual casing damage withthese 3D images. 3D images allow excellent visualiza-tion of casing damage and corrosion; However, theseimages do not provide the necessary, minute detailrequired for monitoring.

Pulse Echo Tool

Although it is primarily a cement evaluation tool, thePulse Echo Tool (PET) can also determine casing ID andthickness. The PET has a helical array of eight transduc-ers, each acting as both a transmitter and a receiver,evaluating the adjacent segment of casing. The transduc-ers emit a short pressure pulse with a center frequencyclose to the resonant frequency of the casing (approxi-mately 400 kHz). When the pulse arrives at the casing, itgenerates both a large reflected wave and casing reso-nance waves, all of which are sensed by the transducer,which measures time of flight (t) of the reflected wavesand the frequency of the resonance waves.

A ninth transducer and a reference reflective surface aremounted in a tool cavity that is exposed to the boreholefluid. To determine the borehole’s acoustic interval transittime (Dt

f), analysts must first measure the acoustic

signal’s time of flight from the transducer to the reflectivesurface and back before determining the known distancefrom the transducer to the reflective surface. The casingID is derived from t and Dt

f, while casing thickness is

calculated from resonant-wave frequency.

To determine casing ovality and tool eccentralization,analysts compare the interval transit times of eachtransducer. If diagonally opposing pairs of transducershave the same transit time and adjacent pairs have

different times, the casing is oval. If all eight transit timesare different, the tool is eccentered.

Figure 3.19 (Page 3-32) is a PET casing profile plot withcasing ovality, eccentricity, average thickness, and otherstandard curves plotted in Track 1. In Track 4, the nominalthickness of the casing is displayed as the distance betweentwo adjacent vertical gridlines. The actual thickness thateach transducer measures is plotted as a solid black traceinset between the nominal-thickness grid lines. Eachtransducer curve is plotted next to its opposing transducer.

Pulsed Neutron Logs

Two types of pulsed neutron logs are available: (1) pulsedneutron capture (PNC) logs, which are usually run inareas with high-salinity formation waters, and (2) pulsedneutron spectrometry (PNS) logs, which are usually runin waters in which the salinity is low or unknown. Thesecased-hole logs can sometimes be used in openholeapplications. When these logs are combined with eitheropenhole or earlier pulsed neutron logs, changes in waterlevel or coning can be evaluated.

Pulsed neutron tools can detect and quantify waterflowing past the tool during logging. When water movespast the generator, oxygen is activated by the high-energyneutrons and forms a radioactive isotope of nitrogen. Thisisotope is unstable and decays with a 7.35-second half-life. As water flows past the logging tool, the tool’sdetectors register the gamma rays emitted during thedecay. This technique detects (1) channels outside thecasing, (2) leaking tubulars, and (3) water production,particularly in highly deviated wells.

Thermal Multigate Decay Logs

The Thermal Multigate Decay (TMD) log is Halliburton’sPNC log. The TMD is a dual-detector tool that can helpdetect water flow by identifying increased backgroundcount rates on the quality log. To quantify flow rates, thelogging service makes several passes with the tool over theflowing interval. Analysts can then determine flow rates bynoting the depth changes where the activation appears onthe background curves. TMD tools have a 1 11/16-in. ODand are rated for at least 300°F and 15,000 psi.



Figure 3.19—Ultrasonic pulse echo log used for casing inspection.

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Figure 3.20—TMD log showing water movement from packer leak and a channel outside pipe.

The example TMD log in Figures 3.20 and 3.21(Pages 3-33 and 3-34) is from a well involved in a log-inject-log project that determines the residual oil satura-tion in a reservoir before a waterflood. The log was runduring the early injections of brine. The LS-BKG curveincreases significantly on the quality log above the packerat X490 ft. This background increase (together with anabsence of high natural gamma activity) indicates waterflowing upward in the casing-tubing annulus because of aleak in the packer assembly. The increased LS-BKGresponse from X640 ft to X625 ft indicates a channeloutside the casing. The count rates are much lower andmore variable for channels than for flow inside the casingbecause of the smaller, more variable volume.

Pulsed Spectral Gamma Logs

The Pulsed Spectral Gamma (PSG) log is a PNS loggingdevice. The single-detector PSG tool detects water bymeasuring the activated oxygen in a spectral windowplaced around the main oxygen peak in the capturegamma ray spectrum. Because of its single-detectordesign, only qualitative interpretation is available. Ifwater is flowing past the tool, the log registers an increasein the count rate of the oxygen-activation curve. PSGtools usually have a 3 3/8-in. OD and are rated for at least300°F and 15,000 psi.

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Figure 3.21—PSG log showing oil/water contact and leaking squeezed perforations.

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The example PSG log in Figure 3.22 (Page 3-36) is froma well that analysts logged to monitor reservoir depletionby comparing open- and cased-hole saturation interpreta-tions. The oxygen-activation curves (OAI) from the fieldlog were placed on the computing center analysis inTrack 1 to aid in the interpretation. The activationincreases at each of the two bottom sets of perforations,X400 to X408 ft and X352 to X356 ft. The activationreturns to near-zero at the top perforations at X326 toX332 ft. These activation increases indicate waterflowing upward past the logging tool and entering theupper set of perforations because of reservoir pressuredifferentials.

The presence of flowing water under shut-in conditionshelps explain the overly pessimistic oil-depletion calcula-tions over this interval. The inelastic gamma ray measure-ments from the PSG log used to calculate oil saturationhave a very shallow depth of investigation and wereheavily influenced by the flowing water.

Reservoir Monitoring Tool

New developments in tool electronics detectors haveallowed a new through-tubing reservoir monitoring tool(RMT) to assist in the monitoring and management of theproduction of hydrocarbon reserves. Halliburton’s RMTElite is a unique through-tubing pulsed neutron loggingtool that consists of carbon/oxygen (C/O) system and hastwo to three times higher measurement resolution thanother systems. Its high-density Bismuth GermaniumOxide (BGO) detectors let the RMT Elite achieveresolutions previously available only with larger diameterC/O systems. The tool length is 27.2 feet long with anouter diameter of only 2 1/8 in.

The advanced modular design provides a highly versatilesystem that has multiple operating modes and capabili-ties, allowing operators to make simultaneous C/O,Sigma, and water flow measurements. Because the systemis modular, it can be combined with a complete string ofproduction logging tool sensors for detailed productionanalysis. RMT Elite allows logging speeds two to fivetimes faster than any competing system. This combinationof speed and precision allows the RMT Elite to performthe following functions:

• Accurately determine oil and gas saturations in highsalinity or fresh water formations

• Identify bypassed reserves

• Pinpoint formation fluid contacts

• Identify lithologies and mineralogies

• Provide porosity information within the completioninterval

• Evaluate gravel-packs and lithology with siliconactivation

• Detect water flow inside or outside the pipe

Because the RMT Elite can accurately evaluate the time-lapse performance of hydrocarbon producing reservoirswithout requiring tubing to be pulled from the well,operators can do the following:

• Increase production more cost effectively

• Monitor changing conditions and fluid movement

• Tap into bypassed hydrocarbon reserves

• Optimize, manage, and produce reservoirs moreefficiently

• Avoid production problems through enhanceddiagnostics

• Make faster decisions on workovers and completions

The RMT Elite can also affect the economics of the wellintervention and associated costs by reducing or eliminat-ing the following:

• The cost of killing the well

• The cost of pulling tubing out of the well

• Operational cost and lost production revenue fromadditional workovers

• Potential production losses due to formation damagefrom well-kill fluids

• The cost of recompleting the well by re-runningtubing

Figure 3.23 (Page 3-37) is an example of the RMT Elitein a steam flood environment. This example not onlyshows the remaining oil saturation, and the injected steamsaturation, but also indicates where water is movingbehind the casing. Remember that conformance is notonly the study of unwanted water production but can alsoinclude the production of gas or steam:

• The depth track recorded at the far left side of the logdisplays water flow measured by the RMT Eliteoutside the casing.

• Track 1 is the openhole density neutron porosity.Steam measured in the formation at the time of thelog is indicated by the gray shading between thecurves.



Figure 3.22—PSG log showing water crossflow between reservoirs.

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Figure 3.23—RMT Elite in a steam flood environment showing fluid saturations, bypassed reserves, and fluidmovement behind casing.

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• Track 2 displays the inelastic and capture ratiosmeasured from the RMT Elite. The red shadingindicates the current location of steam in the reser-voir. This example indicates that the steam chest haschanged when compared to the original formationcontacts.

• Track 3 displays the Carbon Oxygen and the CalciumSilicon ratio curves. The green shading between thetwo curves indicates hydrocarbons in the formation.Also displayed in the track are the natural gamma raymeasurement and the simultaneous recorded forma-tion sigma.

• Track 4 of the example displays the computed oilsaturation (shaded in green) and the gas saturation(shaded in red). These saturations were computedusing a combination of C/O and formation Sigma.

Spectral Flow (SPFL)

The Spectral Flow tool is designed to measure simulta-neous up and down water flows. This tool was intendedfor use with additional production logging tools toaccurately determine water entry and movement. TheSPFL is a high-energy PNS tool that activates the oxygenin water for a short time, allowing the oxygen to emitgamma rays of specific energy. These gamma rays aresensed and measured by detectors in the tools, and theresulting measurements are used to determine water-flowvelocities inside, as well as outside, casing.

The SPFL tool uses two spectral gamma ray detectors anda pulsed neutron generator with a special timing sequencedesigned to emphasize activation measurements. Thesespectral measurements enhance velocity estimates byallowing gamma rays from oxygen activation to bedistinguished from those arising from iron activation,silicon activation, and natural activity.

Furthermore, spectral measurements permit analysis ofCompton scattering to indicate whether water is flowinginside or outside the casing. The detectors are located farenough from the source that oxygen decay in stationarywater, mud, formation or cement is not observed. Oxygenactivation measurements clearly identify where the water ismoving and at what velocity. This allows the SpectraFlowSM Service to accurately detect and quantify downholewater flow to enhance the planning and improvement ofconformance and water management. Updating previousreliable tools and interpretation software allows the SPFLservice to achieve the following:

• Accurately identify the water entry points and chan-nels for timely planning of effective remedial action.

• Evaluate downhole flow patterns

• Create quality injection profiles that can lead toimproved conformance measures

• Reduce water disposal costs

Precise water velocity measurements using spectral dataare provided with continuous logs and stationary impulsestep-down tests:

• Use of a count-rate ratio from the two spectralgamma detectors, which provides a continuous logbut requires well calibrated detectors.

• Use of an impulse/shutdown sequence, which isperformed while the tool is stationary and is calibra-tion independent.

Logging techniques have been developed that use acombination of continuous and stationary loggingmeasurements. This procedure allows water velocitygreater than 3 ft/min to be detected and, depending on theflow volume and location, accurate quantitative velocitiesas low as 5 ft/min can be measured. For velocities over50 ft/min, improved accuracy is obtained by using themore distant natural gamma ray detector.

The example well for this SPFL was producing almost2,000 BWPD and 770 BOPD. The results of the station-ary impulse tests with the tool in inverted configurationindicated downward water flow in a channel outside thecasing. Measurements made with the natural gamma raydetector at the top of the tool showed simultaneousupward water flow inside the casing. Variations in thewater-flow velocity from test to test suggest that thecross-sectional area of the channel is not constant.

The left side of Figure 3.24 (Page 3-39) shows the plotsof the SPFL continuous logs run with the SPFL tool innormal mode; the right part of this figure shows theplots of the continuous logs run with the SPFL tool ininverted mode. The normal-mode logs measured twowater-flow entry points at 9,806 ft and 9,720 ft asindicated by the OAI measurements. The CRAT mea-surements in Track 1of the log indicate the water flowinside the wellbore.

The OAI and CRAT measurements obtained in invertedmode indicated water channeling behind pipe starting at9,642 ft, with most entering the wellbore from perfora-tions at 9,722 ft. The inverted-mode logs also weaklyindicate a second channel beginning at 9,736 ft andcontinuing to the lower set of perforations. The arrows onthe CBL-GR plot the combined water-flow measured bythe SPFL tool.


Figure 3.24—SPFL in normal and inverted mode.

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In addition to measurements made by the new water-velocity tool, a full set of production logs was recordedon this well. The PL computed analysis is shown inFigure 3.25 (Page 3-40). The analysis indicated that mostof the water was being produced by the lower perfora-tions at a rate of 1,880 BWPD and 420 BOPD. The upperperforations showed that fluid was being produced out ofthe top 8 ft. This zone was only producing 75 BWPD and350 BOPD.

Track 7 of the log in Figure 3.22, labeled Velocity, plotsthe velocity calculated from the PL spinner and thecontinuous velocity measured by SPFL tool in normalmode. The velocity from the new tool is lower than thevelocity from the spinner, which indicates that the oil wasflowing faster than the water. As the flow stabilized around9,760 ft, the two velocities were nearly equal. The veloci-ties differed again with oil entry from the upper set ofperforations and stabilized with an equal rate at 9,712 ft.



Figure 3.25—SPFL with PL analysis.

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In summary for this example, the logs indicated threesources of water. The lower perforations were producingwater from the zone and as well as a small amount from achannel in the cement. The upper perforations wereproducing water from a higher channel.

Production Logging Tools

The normal production logging string consists of thefollowing five tools:

• fluid-density tool

• hydro tool

• spinner tool

• pressure tool

• temperature tool

Two new tools have been developed by Halliburton andits suppliers to improve the calculation of holdup. Holduptools normally consist of the fluid density and hydrotools, which are center-sample devices. These center-sample devices are adequate when the fluids are wellmixed and are flowing in a steady state. Unfortunately,this environment is not usually encountered in horizontalor deviated wells. The Gas Holdup Tool (GHT) andCapacitance Array Tool (CAT) are part of the newgeneration of fullbore holdup tools. The GHT measuresgas holdup in all types of environments, includingdeviated and horizontal wells. The CAT tool can actuallymeasure all three holdups (gas, oil, and water simulta-neously). These new tools are discussed in detail.

These 1 11/16-in. tools are rated for 350°F and 15,000 psi.Either individually or in combination with each other,these tools can indicate the presence of water or gasinflux. Fluid-density and hydro devices indicate the typeand amount of fluid present in the wellbore. Flowmetersindicate both the rate and direction of flow. Temperatureand pressure tools provide valuable reservoir parametersfor additional analysis. All these measurements can becombined in Halliburton’s production logging analysis(PLA) program, which provides a complete analysis offluid flow. This analysis consists of both fluid identifica-tion and flow rate for the well.

Fluid-Density Logs

The fluid-density tool continuously measures wellborefluid densities. Changes in density can indicate eithercontact of two different fluids or fluid entry into a well. Inthe latter case, the tool can locate perforations or verifyleaks in the casing or tubing.

The fluid-density tool consists of a collimated gammasource and a collimated gamma detector mounted atopposite ends of a sample chamber. The gamma raysemitted by the source are absorbed at a rate proportional tothe density of the fluids passing through the samplechamber. The detector counts the gamma rays that are notabsorbed. The fluid density is inversely proportional to thenumber of gamma rays reaching the detector. This toolallows users to determine the density of wellbore fluid,locate zones where fluids are entering the well, locatetubing or casing leaks, determine the depth of contactbetween different fluids, and determine fluid holdups.

Hydro Logs

The hydro tool is sensitive to the dielectric constant offluid mixtures in the wellbore, which enables it to detectwater and hydrocarbons. The sensor section of the hydrotool consists of two concentric plates. The annular area isdesigned to minimize effects of fluid flow and its charac-teristics. As fluids with differing dielectric constants passthrough the annular area, the probe capacitance changes,subsequently changing the output frequency of the tool’soscillator circuit. The response is sensitive to the pres-ence and amount of water in the flowstream because ofthe considerable difference between the dielectricconstants of water (80) and hydrocarbons (2 to 4). Thetool allows users to determine hydrocarbon-water ratios,fluid holdups, and fluid entry.

Gas Holdup Tool (GHT)

The gas holdup tool is a 1 11/16-in. OD production loggingtool that measures the volumetric fraction of gas in anycased or screened wellbore. The fullbore measurement isbased on the combined effects of back scattering andphotoelectric absorption. The GHT employs a low-energycobalt-57 source and a scintillation detector to measurethe gas fraction in the annulus between the tool and thecasing. Gamma rays are radiated through the low-energy(titanium) housing, and are backscattered from the fluidin the annulus, then counted by the scintillation detector.The low energy source ensures that the gamma rays areeffectively attenuated through photoelectric absorption bythe casing, which prevents gamma rays that escape thecasing from reentering the cased wellbore and influencingthe measurement.

Because count rates are not directly related to only thedensity of the fluid, the GHT may not be used as a fluiddensity tool. In many instances, the GHT may obviate theneed for the center-sample radioactive fluid-density tool,because the GHT obtains gas holdup directly.



The conventional center-sample radioactive fluid-densitytool employs a cesium-137 source and a Geiger-Muellercounter to measure the attenuation of the gamma rays inthe volume between the source and the detector, ameasurement that may not be representative of the entirewell cross-section. This limitation could lead to measure-ment inaccuracies, particularly in deviated and horizontalwells, where stratified flows are common.

The GHT has a gas holdup accuracy of 3% and a resolu-tion of 1% in two-phase flow, given the pressure andtemperature as an input. It has a vertical resolution ofapproximately 1 ½ in.

Another feature of the GHT is its insensitivity to the well-flow regime. The tool makes an accurate gas holdupmeasurement, regardless of how the gas is mixed withwellbore fluids. For a given fractional volume of gas,approximately the same fraction is measured whether thegas bubbles are floating on top of the liquid phase or aremore uniformly mixed. This characteristic makes mixingfluids unnecessary and provides a more accurate mea-surement independent of the well conditions. Thisinsensitivity to well flow patterns is especially importantbecause exploitation of a reservoir requires recognition ofthe gas and its entry points.

Two holdup devices are required to obtain the informa-tion necessary for three-phase flow calculations. Thefluid density tool is normally used in conjunction withthe capacitance tool to calculate holdups for each phase.The example logs in Figures 3.26 (Page 3-43) and 3.27(Page 3-44) will show that capacitance tools are inaccu-rate during high water holdup, which causes short-circuiting between the measurement plates. The newtechnique capitalizes on the capability of the gas holduptool to determine the gas holdup, independent of fluiddensity. Once the gas holdup is determined, a gas-freefluid density can be calculated, leading to determinationof the water and oil holdups. This technique, using GHTand fluid-density sensors only, has been successfullyused on several wells throughout the world, providingcalculated surface production rates that agree withactual production rates.

Below XX900, the raw data log (Figure 3.26, Page 3-43)shows that the hydro (capacitance) tool is short-circuited,and offers only a straight-lined reading. The FDEN shows

a small degree of activity, while the GHT shows moreactivity than the other tools. Very little gas production isseen below XX850. Above XX850, the logs show gasand fluid entry in both the raw data log (Figure 3.26) andthe computed log (Figure 3.27). The computed analysislog shows that a consistent bubble flow regime is present,composed of oil and water.

The temperature deflection at XX840 shows a heatinganomaly, indicative of fluid entry, as confirmed byincreased spinner rates. The raw data shows that the wellhas not been stabilized, as indicated at approximatelyXX840. Here, the curves from each of the three tools(FDEN, HYDRO, and GHTCO) diverge betweendifferent passes, showing a different depth for the fluid-entry zone with each logging pass.

GHT-computed analysis uses PVT correlations toaccurately calculate volumes of free gas and solution gasfor the total gas flow-rate analysis. The Gas Flow Ratestrack displays free gas in solid red, while using pinkbubbles to show solution gas. Computer analysis empha-sizes the difference in interpretation of data gained bycenter-sample tools versus the fullbore GHT.

Gas entry is indicated on the raw data log from XX788 toXX795 by a slight temperature decrease accompanied byincreased spinner rate. With typical center-sample tools(fluid density and hydro), the major oil/gas entry point atdepth X788 to X795 could easily be misdiagnosed as amajor gas/water entry point. The Fluid Density/Hydroanalysis indicates an increasing water and gas flow rate atX788, as indicated on the computer analysis (Figure 3.27,Page 3-44) by an increase in the QLIQN curve, whichshows the water production rate. However, the Fluid FlowRates track, which uses GHT and Fluid Density readings,shows a consistent QLIQ (water production rate curve),thereby indicating no water entry. Instead, it actuallyindicates increased oil production.

This example highlights some of the problems faced inconformance work. Conformance treatments may bedeemed a failure due to continued fluid production. Inreality the problem could be misdiagnosing of theconformance problem and an incorrect solution beingapplied to the reservoir or well.


Figure 3.26—PL raw data with GHT. Zones 1,3,5, indicate that the hydro is inactive, due to the high waterholdup. Zone 9 shows that all three sensors are now working properly.

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Figure 3.27—Interpretation of the raw data of Figure 3.26. The interpretation on the left uses the GHT/fluiddensity, and the one on the right uses the hydro/fluid density combination. The hydro/fluid density comboindicates water entry from Zone 8 while the GHT/fluid density combination indicates that the water is enteringfrom Zone 6.

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Capacitance Array Tool and FloImager Applications

The Capacitance Array Tool (CAT™) greatly enhancesthe ability to gather reliable holdup data (gas, oil andwater) in highly deviated and horizontal wells. Thisapplication is extremely useful in highly deviated andhorizontal wells with multiphase flow. Applications fordetecting three-phase fluid entry can be performed at anyangle. Combined with the FloImager and FloImager3Dsoftware packages, this service provides the highestresolution three-phase fluid entry detection and flowimage at a broad range of well angles.

This is the latest advancement in the production monitor-ing capabilities that Halliburton provides. Using datafrom the CAT, FloImager identifies fluid entry and fluiddistribution in a borehole cross-section and reliablycalculates water holdup in horizontal, highly deviated,and undulated wells.

FloImager uses data from the CAT, which consists of anarray of 12 micro-capacitance sensors that are radiallydistributed in the wellbore to accurately measure fluidholdup. Because this holdup measurement is fullbore,tool position does not affect the readings in horizontalwells as compared to a center-sample device. The armsare retracted going downhole, then extended whenlogging up, and the process is repeated as often asnecessary. Readings are taken with the tool stationary atany depth or with continuous up-logs. It can be run incombination with Reservoir Monitoring tools and otherconventional production logging sensors.

FloImager improves interpretation of the flow patterns inall wells due to the increased number of sensors at thesame depth. Since the relative position of the CAT isknown at all times, the images and logs are corrected tothe high side of the hole, allowing accurate holdups to bedetermined.

CAT and the FloImager software offer the followingbenefits:

• FloImager provides more value because it reducesclient operating expenses by increasing confidence inwell problem diagnostics.

• Excellent wellbore coverage with array of 12sensors allows superior data and improved flowcharacterization.

• FloImager provides continuous holdup curves, fluiddistribution mapping, and a view of the fluid distri-bution in cross-section.

• FloImager can obtain reliable holdup measurementsand high resolution fluid entry detection, locationand orientation in deviated and horizontal wells

• FloImager can obtain fluid-phase distribution mapsfrom 12 sensors in a cross section and enable qualityand speedy decision making.

A multitude of applications exist for the FloImager andFloImager3D. In addition to measuring fluid holdup, theFloImager can be used to detect water entry and itsorientation relative to high side of pipe at any welldeviation. FloImager can successfully show three-phasefluid segregation since each fluid has its own log re-sponse. FloImager provides an accurate visualization ofthe undulating horizontal wellbore when TVD data iscombined with the CAT data. Combining the calculatedfluid holdup with additional PL sensors allow an accurateand complete three-phase analysis.

Figure 3.28 (Page 3-46) is an example log of the CATdata and FloImager software. This well is a horizontalwell that produces approximately 30 Mscf/day gas, 300STB/day oil and 12 bbl/day water.

• Track 1 provides correlation data gamma ray (GR),pressure (P), temperature (T), spinner rate (SR),cable speed (CS), and relative bearing (RB).

• Track 2 is the horizontal image generated inFloImager. This image is corrected for relativebearing so that the high side of the hole is on the leftand right while the low side is in the middle. Thewhite curve shows the low side or center of theimage. The spectrum grades from blue (water), togreen (oil) to gas (red), so naturally the lighterphases should be on the upper side of the wellbore.

• Track 3 is holdup data from the three tools run in thiswell. The fluid density and hydro are center-sampledevices while the ACAPN is the average of the 12sensors from the CAT. Notice how tool positionaffects the readings especially around X418-X430and X454-X468.

• Track 4 is the vertical image generated from theFloImager software. Because relative bearing isrecorded, determining each sensor position relativeto the vertical plane is possible. The image from leftto right is going from low side to high side of thehole. The yellow curve is the calculated waterholdup while the black curve is the calculated gasholdup. Again, the white line shows the verticalcenter of the image.



Figure 3.28—FloImager presentation of an horizontal well. This shows the ability of the CAT tool to locateentry points of the wellbore fluids.

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• Track 5 is the calculated holdup from the FloImagersoftware. This holdup is determined by the verticalposition of each sensor and is not just a straightaverage of the sensor response.

FloImager3D allows the user to view, rotate, and manipu-late the CAT data to understand the flow patterns andcharacter of the well.

FloImager3D allows complete a complete picture orprofile of the downhole holdup pattern. FloImager3Dallows the user to view, rotate, and manipulate the CATdata to understand the flow patterns and character of thewell. Since the sensors are normalized in FloImager, thesame color pallet can be used for each sensor providing aprecise image. FloImager3D provides a superior techniqueto both calculating and displaying multiphase holdup.

Because the CAT records both sensor data and relativebearing, the resultant logs can be corrected to the high sideof the hole, allowing accurate visualization of the fluidsegregation. However, because this segregation dependsupon total fluid flow, each sensor has the capability tomeasure phase holdups of gas, oil, and water. BothFloImager3D and FloImager have several options tocalculate total holdup of the wellbore, allowing the user todetermine the best possible solution to this complicatedissue. The final holdup then can be used in the PLAprograms to help determine both the downhole and surfaceflow rates for each phase. Although the 3D imaging

capabilities of FloImager are difficult to show in a twodimensional figure, one of the outputs is the cross-sectionaldisplay shown in Figure 3.29. This correlates to the depthsA425 and B523 shown in Figure 3.25.

Flowmeter Logs

Continuous, fullbore, and basket flowmeter tools accu-rately measure velocity and direction of flow in thewellbore.

The continuous flowmeter consists of an impeller mountedon sapphire jewels and surrounded by a cage that ismounted on the bottom of the logging tool. The sapphirejewel mountings of the impeller minimize friction,allowing the tool to make accurate low-velocity measure-ments. The impeller turns at a rate proportional to thespeed of the borehole fluid in the center of the pipe.

The fullbore flowmeter consists of multibladed spinnersthat extend in casing to encompass the entire wellbore.This tool is designed for specific casing sizes and must bechosen accordingly. The design allows for fluid-velocitymeasurement across the entire wellbore and is efficient inboth deviated and low-velocity wells.

The basket flowmeter is a stationary measurement toolthat funnels the wellbore fluids to a small spinner. Thistool is designed for deviated wells and segregated flow.The maximum flow rate for this tool is approximately2,000 B/D.

Figure 3.29—Cross-sectional display showing depth and holdup calculation from the log in Figure 3.28.

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Pressure Logs

Pressure tools continuously measure pressure in theborehole. Two types of tools are available: the strain-gauge pressure tool (SPT) and the quartz pressure tool(QPT). The SPT uses a strain gauge to measure thedownhole pressure, and the tool is designed to minimizethe effects of temperature. The QPT uses quartz sensorsspecifically designed for gas and oil wells. The ruggedquartz sensors have high-resolution measuring capabili-ties. A temperature sensor built into the quartz sensorsection accurately compensates for temperature effects.

Temperature Logs

Temperature logging tools continuously measure tem-perature in the borehole and can detect liquid or gasmovement behind pipe. A highly sensitive resistancethermometer in the tool provides reliable temperaturemeasurements.

Since the temperature tool detects changes in boreholetemperature, it can locate cement tops and gas-entrypoints. When it is near curing cement, the tool senses theincreased temperature caused by the heat of hydration. Atgas-entry points, the tool detects reduced temperaturescaused by the gas expanding as it enters the wellbore.

Depending on the temperature of fluid entering thewellbore, the tool may be capable of indicating whether thefluid is from the adjacent formation or if it has channeledfrom above or below. A temperature that is cooler thanexpected may indicate channeling from a cooler formation,which is normally higher in the wellbore. Similarly, atemperature that is warmer than expected can indicate achannel from below the formation.

Temperature abnormalities can also indicate possible flowbehind casing or tubing. These abnormalities are high-lighted when the temperature gradient is compared to thenormal temperature gradient that was observed with thewell shutin. Increased temperatures indicate flow frombelow the formation. Reduced temperatures indicate eitherflow from above the formation or the presence of gas.

Examples

Well 1

Well 1 was a gas-production well with high water produc-tion. This well was logged with fluid-density, temperature,pressure, and spinner tools that provided information forthe production logging analysis (PLA) program.

The fluid-density log indicates the type of fluid present.Figure 3.30 (Page 3-49) consists of the fluid-density log, awellbore schematic, and temperature, gamma, and collarlogs. Below X077 ft, the fluid density read 1.03 g/cm3,indicating that the wellbore fluid was all water. From X073to X077 ft, the density decreased to 0.73 g/cm3, whichindicated gas production. Between the perforation depthsof X055 to X060 ft, the fluid density again decreased from0.73 g/cm3 to 0.62 g/cm3, suggesting additional gasproduction.

Figure 3.31 (Page 3-50) presents the temperatureinformation in the forms of amplified and differentialtemperature logs. The amplified temperature log is thetemperature log presented with a more sensitive scale thatallows analysts to identify minute differences. At X100 ft,the amplified temperature log shows a warming anomaly,which indicates that liquids are entering the wellbore.Temperature decreases indicate gas entry caused by thegas expansion. According to the amplified temperaturelog, gas is entering the wellbore at X090 and X060 ft.

The differential temperature is the difference between twotemperature measurements at a set interval. The differentialtemperature log showed differences in the geothermalgradient, providing an excellent indicator of fluid move-ment. The differential temperature log indicates a normalgeothermal gradient below X105 ft. Between X105 andX091 ft, the log becomes negative, which indicates thatliquid is entering the wellbore. At the depth of X090 ft, thedifferential temperature becomes positive, which suggeststhe cooling temperatures that indicate gas entry.

By overlaying the fluid-density and temperature logs,analysts can determine additional information. Forexample, in Figure 3.32 (Page 3-51) the density log byitself does not indicate fluid movement at X100 ft. Thetemperature log, however, indicates water production.Multiple sensors provide additional valuable informationfor analysts to determine downhole performance.

Production logging analysis uses the available data toprovide the answers shown in Figure 3.33 (Page 3-52).The fluid density is used to calculate holdup, the area ofthe pipe occupied by the phase. Below the bottom set ofperforations, the wellbore is completely filled with water.Above the top set of perforations, the pipe contains 60%water and 40% gas.


Figure 3.30—Fluid-density log with a wellbore schematic and temperature, gamma, and collar logs.

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Figure 3.31—Temperature information in the forms of amplified and differential temperature logs.

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Figure 3.32—Combination of fluid-density and temperature logs.

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Figure 3.33—Production log anaylsis (PLA).

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The flow rates at surface conditions show water produc-tion of 475 STB/D and gas production of 450 Mscf/D.Further analysis of the data indicates that from X094and X103 ft, more than 250 STB/D of water is beingproduced. Therefore, a treatment in this zone wouldeliminate most of the water without significantlyreducing gas production.

Well 2

Well 2 was a producing well that had a three-phase flowof gas, oil, and water. For proper analysis, operators ranfluid-density and Hydro tools on the well to calculatefluid holdups. They also used a continuous spinner todetermine fluid velocity and temperature and pressuretools to calculate reservoir properties.

Fluid-density and hydro tools must both be run whenthree-phase flow occurs below the bubble point. Figure3.34 (Page 3-54) shows the data from these tools. BelowX700 ft, both holdup tools indicate only water in thewellbore. At X697 ft, the decreased fluid density and theincreased hydro count rate indicate hydrocarbons enteringthe wellbore. Since the fluid-density measurement is0.62 g/cm3, the hydrocarbons are probably primarily gas.A slight decrease in the hydro count above the top set ofperforations at X640 ft indicates that either water or oil isentering from those perforations.

Figure 3.35 (Page 3-55) presents the raw spinner dataand the cable logging speed. Negative cable speedsindicate that the tool is logging up the hole; positive cablespeeds indicate that the tool is logging down. Higherspinner count rates should occur when the tool is loggedagainst flow, as shown in Figure 3.35. Analysts examinedata from multiple passes of the tool to calculate fluidvelocities, which they use to determine flow rates. Bystudying the raw data, analysts can determine where fluidis entering the wellbore. Below X721 ft, the spinnersshow very little change, suggesting that no flow exists.Between X718 and X721 ft, and again between X692 andX698 ft, the large changes in spinner response indicatefluid entry. The other regions show very little change inspinner response, indicating neither production nor lossof fluids.

Figure 3.36 (Page 3-56) provides the PLA analysis of thelogging data. Again, the holdups are calculated from thefluid-density and hydro data. The data show 100% waterbelow the bottom set of perforations and about 45%water, 15% oil, and 40% gas above the perforations.The flow rates indicate the surface production of each

phase (2,000 STB/D of water, 500 STB/D of oil, and 900Mscf/D of gas). Zonal analysis of the well indicates thatmost of the water comes from the bottom perforatedinterval, with smaller amounts produced uphole. Gas isbeing produced primarily from the second perforatedinterval, while oil is produced almost equally from theupper two zones. Therefore, treatments on the lower zonewould likely decrease the amount of water productionwithout adversely affecting hydrocarbon rates.

Downhole Video Services

Real-time downhole video services allow analysts to(1) identify wellbore problems, (2) plan reservoir andwellbore treatments, (3) monitor well treatments whilein progress, and (4) confirm post-treatment of wellconditions. The video images permit viewers todetermine exactly where reservoir fluids and particu-late matter enter the wellbore. The images also revealfluid turbulence and flow direction to help viewersidentify fluid migration through the wellbore and intothief formations.

When used with other reservoir analysis tools, downholevideo visually confirms analysis models about reservoirbehavior. It can also reveal low-volume fluid entry thatconventional well-data acquisition methods may notnormally detect.

Application in Oilwell Environments

A common misconception is that oil entry into a wellborecauses turbulent fluid mixing, resulting in the formationof opaque emulsions. In reality, at low to moderate flowrates, crude oil generally enters into the wellbore asamorphous bubbles of oil that float through standingwater to the water/oil interface. This reaction results in a“lava-lamp” effect, where the fluids remain distinct andseparate rather than being mixed in an emulsion. Theresulting medium has proven to be very adequate for theuse of video; in fact, the possibility of the camera flowingup the well is more likely to constrain the use of videothan the degree of fluid emulsification.

Video services are also effective in low water-cut oilwells. Sometimes a low water-cut oil well is assumed tohave a proportionately low percentage of water in thewellbore. If this assumption were true, video servicecould be performed in an oil well only after the well wasshut in and the target viewing interval was displaced witha clear fluid.



Figure 3.34—Fluid-density and hydro tool data.

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Figure 3.35—Flowmeter with raw spinner data and cable logging speed.

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Figure 3.36—PLA analysis of logging data.

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Actually, the water-oil ratio in the well can be muchgreater than the water-oil ratio produced because the oiltends to flow to the surface more readily than water. Theoil bubbles travel to the top, where they are produced,while the water ascends more slowly. As a result, a highpercentage of water may appear to be standing in thewellbore. This water provides an excellent medium forthe video system to monitor the flow activity in the well.Video services have been effective in wells producing aslittle as 7% water cut.

Detection of Fluid and Particulate Entry

Oil can bubble into the wellbore gradually withoutsignificantly disrupting the well fluids. As a result, oil entrycan be difficult or impossible to detect if the perforationinterval cannot be visually observed. If the oil graduallyenters the wellbore over a significant length of perforatedcasing, much of the perforated interval actually producingthe oil can be mistakenly assumed to be nonproductive. Bymonitoring the perforated interval with a downhole videocamera, viewers can easily determine where oil is enteringthe wellbore. In Figure 3.37, oil is identified as blackbubbles rising through standing water.

Gas entry into the wellbore is usually more turbulent.Depending on the velocity and condensate content of thegas, gas entry may appear as a spray of bubbles, a smoke-like jet or plume, or waves of distortion in otherwise clearfluid. If the turbulence is strong enough, the fluids canbecome locally stirred so that any bubbles of oil couldmix with the water to cause a semitransparent or opaqueemulsion. The emulsion will generally be isolated to theturbulent-flow area. Above the turbulence, the fluids tendto separate.

In localized areas of emulsion, operators can detect fluidentry by observing the motion of particulate matter that issuspended in the fluid. Fluid entry is detected as theparticulate matter moves sideways or in circular eddies inresponse to a sideways flow disturbance.

Oil entry into an existing emulsion is more difficult todetect if the oil is bubbling in at a low rate. Although thedark oil bubbles themselves are easy to identify, theirsource can be more difficult to determine. If the well isshut in for a short time, the emulsion should stratify intocomponents, allowing the targeted viewing interval toclear. Alternatively, well fluids can be displaced to shiftclear fluids into the targeted viewing interval. Once clearfluids are established in the target viewing area, the wellcan be allowed to flow, permitting viewers to observefluid entry before emulsification occurs.

The entry of sand and particulate matter into the wellboreis easily recognizable and helps trace the entry andmovement of clear fluids, such as water. Similarly,changes in the movement of falling sand and suspendedmatter near fluid entry points can signal entry of clearfluids into the wellbore.

Viewers can further track the motion of clear fluids in thewellbore by monitoring the motion of flexible members,such as a piece of string fastened in front of the camera.In injection wells, operators can use dyes to locate fluidentry points in the producing wells and to better under-stand the water migration patterns between the injectionand producing wells.

Logging

Wells are generally shut in for 24 hours before a video logis run so that any opaque fluids can separate into distinctfluid layers. This shut-in increases the probability of wateror clear liquid existing in the interval of most interest. Ifopaque fluid is located in the interval targeted for viewing,the fluid in the wall may have to be partially displaced withfiltered water, brine, production gas, or some other clearfluid to provide a clear viewing medium. Frequently, theopaque fluid layer is above the interval of interest.

To begin video logging, operators run the downholevideo camera on cable or coiled tubing to the lowestpoint in the well. If necessary, the well can be brought onat this point as the camera ascends. The entry of fluidsand solids can be observed as the camera passes perfora-tions or other fluid entry locations.

Figure 3.37—Downhole video camera picture.

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Depth and temperature displays are superimposed on thevideo monitor during video operations so that the viewercan correlate the observed well features and conditions tothe well tally.

Problem Identification and Remedial Treat-ment Planning

Because so many effective conformance control methodsare available, engineers must thoroughly understand theexact nature of fluid entry to determine the target treat-ment area and select the best treatment. Downhole videoservices reveal wellbore conditions and help viewerspinpoint locations requiring treatment.

In-Progress Monitoring

If the treatment medium is relatively clear and thephysical operating limits of the camera and cable are notexceeded, video can successfully monitor well andreservoir treatments. For example, operators could usedownhole video cameras during a fracturing job to verifythe location of the proppant.

Post-Treatment Confirmation

After a reservoir or wellbore treatment, a video run canconfirm that the treatment accomplished the intendedresult. By using video to confirm treatment conditions,the viewer can learn more about treatment effectiveness.

Operating Limits

Clear Fluid Medium

Video service requires a relatively clear fluid medium inthe viewing area. Most wells, however, have enoughstanding water or gas to accommodate video. Whenopaque fluids, such as crude oil and mud, are displaced,the video camera can clearly show the target areas of thewell. Coiled tubing can also be used to displace the localtarget interval without displacing the entire well.

Pressure and Temperature

The camera, cable system, and all wetted components aredesigned for operation at 10,000 psi and 225°F. Videologging has been successfully performed at temperaturesgreater than 250°F, although the picture quality wascompromised. All components exposed to well tempera-tures can withstand temperatures over 250°F withoutpermanent damage.

Depth

The maximum operating depth for the cable-deployedsystem is 17,000 ft. This depth can be achieved becausethe 7/32- or 1/4-in. diameter cable permits the cameraassemblies to be run against pressure without the need forweight bars.

When it is deployed on coiled tubing, the video systemmaximum depth depends on the coiled-tubing system depthcapability. Coiled tubing deployment provides two advan-tages over cable: (1) it allows operators to use downholevideo services in deviated wells, and (2) operators can pumpnitrogen through it to bring on the well during videooperations.

Regardless of depth, the picture quality remains excep-tional because the video images are transmitted through afiber optic member to the surface. The cable assemblyalso contains electrical conductor wires to power thecamera and lights.

Chemical Resistance

The cable armor design is similar to electric conductorline because both are resistant to wear and chemicals.Special polishes with surfactant wetting agents are usedon the camera lens and light sources to cause oil bubblesto slide off without leaving an opaque film, and chemical-resistant coatings and treatments for the cable areavailable for special applications.

Other Applications

In addition to conformance control, downhole video canalso be used for the following applications:

• Inspecting casing, tubing, and downhole equipment

• Performing corrosion surveys

• Detecting fractures and their orientation

• Verifying well treatments and other service operations

• Locating and identifying fish

• Performing well-appraisal analysis


ConclusionsThe examples of logging tools and computer softwareshow how conformance problems can be properlydiagnosed. Conformance treatments not properly chosenfor the well or reservoir conditions fail. Correct inter-pretation of the downhole environment can removeerrors in the treatment of the conformance problem. Inthis vein, a composite log called ConformXpert wasdeveloped to highlight the entire well from openholeimages to casing/cement evaluation to reservoir moni-toring. Lack of a cement evaluation log could besignificant if a water-bearing zone is nearby, so properanalysis of the entire system could justify acquisitioncosts. Figure 3.38 (Page 3-60) provides an example ofthe ConformXpert presentation:

• The depth track shows a pay flag generated from theopenhole logs along with a zonal number used in theproduction logging analysis.

• Track 1 provides an amplitude image from theCAST-V of the openhole section. This will highlightrock textures, fractures, and other reservoir featuresthat could influence conformance applications.

• Track 2 is a standard volumetric analysis of theopenhole logs. Rock types and lithologies could alsodetermine the proper conformance treatment applied.

• Track 3 provides comparisons of the initial openholewater saturation and later reservoir monitoring watersaturation. If the zones are adequately swept, the besttreatment may be abandonment of the zone.

• Track 4 consists of the openhole fluid analysis. Thiswill highlight water vs. producing zones.

• Track 5 consists of the openhole permeabilitycalculations. This will highlight zones or formationsthat might have a premature water breakthrougheither through water flooding or natural water drives.

• Track 6 provides a typical CBL log that shows thecondition of the cement sheath. This will allowoperators to determine whether zonal isolation is theconformance problem.

• Track 7 consists of the CAST-V cement imageproviding detail about the cement-to-casing bond.The Tracks 6 and 7 when examined together provideaccurate information regarding the zonal isolation ofthe well.

• Track 8 is the pipe inspection data from the CAST-V.If casing damage is present, the conformancetreatment could be simple or complex, depending onthe type and cause of the damage.

• Track 9 provides production logging data. Thisshows the what and where of fluid production.

Reservoir conditions can be more accurately determinedthrough the use of tracers, logging tools, and downholevideo. Once conditions are known, design teams can usecomputer programs to identify conformance problemsand recommend effective treatments. Chapter 4 providesinformation regarding Halliburton’s XERO Water-Control Expert System.



Figure 3.38—ConformXpert log combines all the available well log data into one easy to use image. Missingsegments are shown to allow determination of the proper conformance treatment. Further data acquisitioncould make the correct conformance treatment selection easier and the treatment results could be excellent.

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Computer Programs 4-1Chapter 4

Chapter 4

ComputerPrograms

IntroductionThis chapter describes two softwarepackages recommended for conform-ance solutions—the QuikLooksimulator and the XERO water controlexpert system. The QuikLooksimulator can be used to design aconformance treatment, while theXERO system is used to help diag-nose problems from a productionprofile. The QuikLook simulatorsection of this chapter includes basicbackground, features, and testing ofthe simulator. To learn how to run thesimulator, refer to the QuikLooksoftware user manual.

QuikLook SimulatorThe QuikLook simulator is a new toolprimarily intended for reservoir fluidmanagement. It is the first simulatordesigned specifically for conformanceapplications and for use by practicingengineers. QuikLook is a “black-oil”three-dimensional, three-phase, four-component, non-isothermal reservoirsimulator that numerically solves thedifferential equations for multidimen-sional fluid and heat flow through aporous medium.

The simulator is used to optimize thedesign of a conformance treatmentand to evaluate the efficiency of theconformance solution. Specifically,the simulator can be used to helpperform the following tasks:

• Predict the effect of a conform-ance treatment on reservoirperformance

• Forecast results of treatmentsapplied to complex reservoirsand/or complex wells

• Reduce economic operationalrisk by employing better candi-date selection

• Achieve a better understandingof reservoir mechanics

• Reduce cycle time by shorteningthe decision-making process

• Optimize the design of a con-formance treatment to maximizevalue to customers

• Investigate new placementtechniques

• Train engineers in conformancetechnology

The QuikLook simulator has a user-friendly graphical user interface(GUI) that allows users to enter data,launch the simulation, monitor thesimulation run, and analyze theresults. It also provides a convenientway to enter the complex datarequired for numerical simulationwith the help of interactive graphics,consistency checks, supplementalplots, and other simple tools.

Several important features make theQuikLook simulator especiallyvaluable for helping solve conform-ance problems. These features do notusually exist in conventional black-oil simulators.

• In addition to numericallysolving the partial differentialequations that govern 3-D flowof oil, gas, water, and theconformance fluid, QuikLookalso numerically solves theenergy balance (heat flow)equation. This feature is critical


4-2 Computer Programs Chapter 4

to conformance applications intwo respects: (1) simulating theinjection of conformancematerial into a formation thatmay have been cooled down bycirculation and (2) in calculatingand understanding the process ofpolymer gelation as a function oftime and temperature.

• In addition to calculating theflow of oil, gas, and water,QuikLook contains a fourthphase that represents theinjection and flow of theconformance fluid. This phaseenables the software to track thelocation of the conformancefluid, leading to significantlybetter solutions and predictionsof reservoir performance thanthe conventional black-oilsimulators. This option alsoallows the user to modify theplacement technique to maxi-mize the return and benefit ofthe conformance treatment.

• QuikLook simulates the con-formance fluid rheology andpolymer thickening (gelation)with time and temperature.

• Several Halliburton conformancefluids are built in to QuikLook,eliminating the need to enter theproperties of those fluids.

• QuikLook is linked to theWELLCAT wellbore simulator.

• QuikLook is designed to have auser-friendly GUI.

QuikLook capabilities are accessedthrough its GUI (Figure 4.1), intowhich all data are entered. The GUIcontrols the processing of the data byQuikLook and WELLCAT softwarepackages. The QuikLook solver andWELLCAT model are completelyintegrated to simulate a flow of fluidsin the wellbore and the reservoir.

WELLCAT can be turned off so thatwellbore calculations cannot bemade. When WELLCAT is turnedoff, the data assumes no change intemperatures, pressures, and compo-sitions of fluids traveling from thesurface to the bottom of the hole orvice versa.

Purpose and Philosophyof QuikLook

The main purpose of QuikLook is toprovide Halliburton Engineers with asoftware tool designed to investigatethe feasibility of applying aHalliburton proprietary conformancetreatment to oil or gas wells thatexhibit conformance problems. Thesoftware simulates the application ofconformance treatments for a givensituation and provides guidance forchoosing among options for conform-ance fluids and treatment design. Theprogram is designed to enable theuser to identify a problem, quicklyinvestigate the effects of various

remedies, and choose an optimaltreatment. The effect investigatedhere is in terms of reservoir response(rate and total production). QuikLookis designed to help engineers estimatethe value of a project as illustrated inFigure 4.2 (Page 4-3).

The basic philosophy behind thesimulator is to sacrifice some of theaccuracy to gain speed in bothsimulation and turnaround rate. Thegoal is to achieve at least 85%accuracy but reduce the turnaroundrate to four hours or less. However,the user should recognize that some ofthe features incorporated in QuikLookare truly unique and do not exist in thecommercially available simulators.Some of these features include theheat flow, a fourth component, and thelinkage with a wellbore simulator.With the addition of these features, itmay be argued that the QuikLookresults may be more accurate than theresults from a conventional simulator.

Figure 4.1–QuikLook Graphical User Interface

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QuikLook Theory

QuikLook is a sophisticated numeri-cal simulator. Like all numericalsimulators, QuikLook solves a set ofdifferential equations that describeflow of fluids and heat through awellbore and porous media. Theseequations are solved by first convert-ing the differential equations into aset of difference equations for eachcell in the reservoir. The differenceequations would form a set of linearalgebraic equations. This set ofequations is solved numerically usingmatrix solution techniques. Descrip-tions of how the difference equationsare formulated and solved areprovided in other literature.1,2

Conformance FluidsModeled by QuikLook

The chemical sealants that are usedfor conformance are normallydesigned to be placed at a lowviscosity and react in situ to form amore viscous (usually highlycrosslinked) gel. In the QuikLooksimulator, conformance fluids areassumed to consist of a monomer andan activator that catalyzes theconversion of the monomer to agelled or partially gelled polymer.The following Halliburton conform-ance fluids are built into QuikLook:

• H2Zero

• Injectrol

• PermSeal

• PermTrol

Some of these general types ofconformance fluids include sub-typesthat differ by the type of activatorused. Chapter 5 of this book providesa detailed discussion of these fluids.

WELLCAT Software

WELLCAT is a Landmark Graphicssoftware package that includesseveral modules that can model avariety of wellbore applications. Onlythe WS-PROD module is used in theQuikLook simulator. The WS-PRODmodule simulates fluid flow and heattransfer in wellbores during comple-tion, production, stimulation, testing,and well-servicing operations. Ithandles both steady state andtransient single and multiphase flow.The WS-PROD module ofWELLCAT software is used tocalculate pressure and temperatureprofiles in a wellbore for bothflowing and shut-in conditions.

The WELLCAT capability inQuikLook is required to helpdetermine the true state of theconformance fluid as it enters theformation at the bottom of the well.In practice, conformance fluidpressure, temperature, and relatedproperties are measured only at thesurface during treatment. Conform-ance fluid properties at bottomholeconditions where fluid goes from thewellbore into the reservoir and/orbehind casing should be calculated.These calculations are the mainfunction of WELLCAT softwarewithin the QuikLook simulator.

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General Data Requirements

The QuikLook simulator requires thefollowing basic engineering data:

• Geological reservoir characteris-tics (e.g. porosity, permeabilityand thickness of the producingformation)

• Rock properties such as relativepermeability and pore volumecompressibility (cr)

• Well drainage radius, currentreservoir pressure, oil-water andgas-oil contacts

• Fluid properties for the reservoirfluids (e.g. viscosity, density andcompressibility of the reservoiroil, gas and water)

• Historical production andinjection data for the well orwells to be treated (e.g. oilproduction rates, pressures)

• Tubular goods configuration(e.g. casing, tubing, packers) andcompletion intervals

The simulator has default values forcertain fluid and rock property data.In general, these default values willnot be appropriate for all situations,so at least approximate values for allof the data should be available. Inaddition to the data listed for conven-tional petroleum reservoir simulation,QuikLook requires fluid properties ofthe conformance fluids.

Validation of the QuikLookSimulator

This section attempts to validate theQuikLook simulator by comparingthe output of the simulator to outputfrom existing commercial simulators.Two different sets of runs wereimplemented. In the first set ofexamples, the basic validity of thesimulator was confirmed by compar-

ing its results to results reported intwo SPE comparative simulationstudies. In these two studies, theQuikLook simulator was run as aconventional black-oil simulator. Inthe second set of examples, thevalidity of QuikLook as a conform-ance simulator was investigated usinga commercially available simulator.

Among available simulators, onlySTARS and QuikLook could simulatethe performance of a conformancetreatment. The QuikLook simulatorhas a distinct advantage of consider-ing both the wellbore and tempera-ture effects. However, both simula-tors have a fourth component tosimulate the presence of a conform-ance fluid. After the validity of thesimulator was established, thefeatures specially developed tosimulate conformance studies wereused in a series of runs.

Example 1—First SPEComparative study

In an article that was published in1982,3 seven operating, software andconsulting companies participated ina study to compare the results of their

three-dimensional black-oil simula-tors. These companies were Amoco,Exxon, Mobil, Shell, IntercompResource Development, ComputerModeling Group (CMG), andScientific Software Corp.

The reservoir geometry was simple: arectangular reservoir consisting ofthree layers. Both a producer and agas injector are in this reservoir. Theinjection well was located in onecorner of the reservoir and completedin the top layer only, while theproduction well was placed in theopposite corner and perforated in thebottom layer.

Table 1 lists the reservoir propertiesand constraints specified for thestudy. PVT data and detailed descrip-tions of the problem can be found inReference 3. This reference alsogives descriptions of the variousmodels used by the participatingcompanies. All simulators were 3-D,three-phase black-oil simulators, andnone of the simulators consideredheat flow.

The 10 × 10 × 3 reservoir grid systemused for this first SPE comparativestudy is shown by the areal view in

Initial reservoir pressure (psi) 4,800Depth (ft) 8,400Gas injection rate (MMCF/D) 100Maximum oil production rate (STB/D) 20,000Minimum oil rate (STB/D) 1,000Minimum flowing pressure (psi) 1,000Maximum saturation change during 0.05Porosity at 14.7-psi base pressure 0.3Wellbore radius (ft) 0.25Skin factor 0Capillary pressure (psi) 0Reservoir temperature (°F) 200Gas specific gravity 0.792Maximum project time (yr) 10Maximum GOR (SCF/STB) 20,000

Table 4.1–Data and Constraints for Example 1


6,000 STB/D at about 10 years fromstart of production. Although theQuikLook simulator was not exactlyan average of the simulators, itsresponse was excellent. It agreedmore with Shell’s simulator.

Figure 4.6 (Page 4-7) shows the howthe gas-oil ratio (GOR) changed withtime. For a little more than threeyears the GOR was constant andequal to the solubility of gas in oil,indicating that up to that point thereservoir pressure was above bubblepoint pressure. When the flowingpressure fell below the bubble pointpressure, gas began to come out ofthe solution, building up the gassaturation inside the formation, whichin turn led to the building up offormation permeability to gas.

This effect is seen in the very fastincrease in GOR. In the QuikLooksimulator, the flowing pressurereached the bubble point pressure atabout the same time as for mostsimulators. In addition, the GORprofile was comparable to the othersimulators.

Figure 4.3. Figure 4.4 shows thecross-sectional view of the near-wellbore area of the injector and theproducer.

The QuikLook simulator was run tosimulate the conditions specified inthe article3 and results were comparedto those reported. First the initializa-tion results (i.e. the calculated fluid inplace from the QuikLook simulator)were in excellent agreement with thesimulators used in the first SPEcomparative study. Results from thissimulation run are shown in Figures4.5 through 4.9.

Figure 4.5 (Page 4-6) presents the oilproduction predicted by the varioussimulators. All the simulators initiallyproduce at the maximum allowablerate of 20,000 STB/D. Productionrate starts declining at the minimumallowable flowing pressure of 1,000psi. At this point the simulatorswitches to a constant flowingpressure, allowing the rate to decline.

As Figure 4.5 shows, all simulatorsreached this point approximately fouryears from the start of production.They all show decline in productivitywith time reaching a rate of about

Figure 4.3–Cartesian grid system for SPE Comparative Project 1

Figure 4.4–Cross-sectional view of the near wellbore area of (a) injector and (b) producer

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Figure 4.5–Oil production ratio vs. time for SPE Comparative Solution 1

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Figure 4.6–GOR vs. time for SPE Comparative Solution 1D

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Figure 4.7 (Page 4-8) provides theproducing pressure vs. time for thevarious simulators. Although theQuikLook simulator reached a littlehigher peak at a slightly later time, itgenerally agreed with the rest of thesimulators throughout the life of theproject.

Figure 4.8 (Page 4-8) presents the gassaturation history at the bottom layerwhere the production well is located.(The simulators are in generalagreement.) Figure 4.9 (Page 4-9)shows the pressure profile at theinjection well. (The simulators are ingeneral agreement.) However, similar

to Figure 4.7, the peak pressurereached by the QuikLook simulator isa little higher than the rest. Theseresults could be caused by thedifferences in how the individualsimulators handle the wellboregeometry.



Figure 4.7–Gridblock 10, 10, 3 pressure vs. time for SPE Comparative Solution 1

Figure 4.8–Gridblock 10, 10, 3 gas saturation vs. time for SPE Comparative Solution 1

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Example 2—Second SPEComparative Study

In an article that was published in1986,4 eleven companies partici-pated in a study to compare theresults of their three-dimensionalblack-oil simulators. Thesecompanies were Arco, Chevron,Gulf, Shell, Intercomp ResourceDevelopment, Scientific SoftwareCorp, D&S Research and Develop-ment, Franlab Consultants,Harwell, McCord Lewis EnergyServices, and J. S. Nolen &Associates. LGC’s VIP is based ona simulator developed by J. S.Nolen, while the QuikLooksimulator is based on a simulatorthat was owned by D&S. As in the

case of the first study, many ofthese companies no longer exist.

The problem submitted to thevarious companies was essentially awater-coning problem. Figure 4.10(Page 4-10) shows a cross-section ofthe 15-layer reservoir. Basic reser-voir properties are presented inTable 4.2 (Page 4-10). Detailedreservoir, fluid, and simulation dataare listed in Reference 4.

The problem is obviously artificial inseveral aspects.4 The plannedproduction rate changes wereunlikely to occur in real situations,and the GOR was very high for thespecified oil. This makes the problemdifficult to solve and possibly a bettertest for the various simulators.

The given reservoir dimensionsrepresent a drainage area of approxi-mately 303 acres, or 3,634 ft ×3,634 ft square drainage area. Thecorresponding drainage area isshown by the Cartesian grid systemin Figure 4.11-a (Page 4-10). Half ofa vertical cross-section along thegridblocks in which the well islocated is presented in Figure 4.11-b(Page 4-10), showing the location ofthe perforations.

As in the first study, the initializa-tion results (i.e. calculated theamount of fluid in place) from theQuikLook simulator agreed with thesimulators used in the first SPEcomparative study.

Figure 4.9–Gridblock 1, 1, 1 pressure vs. time for SPE Comparative Solution 1



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Figure 4.10–Reservoir model for SPE Comparative Solution 2

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Figure 4.11–Cartesian grid system and cross-sectional view of vertical layers

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Initial reservoir pressure (psi) 3,600Depth (ft) 9,035Radial extent (ft) 2,050Number of layers 15Minimum flowing pressure (psi) 3,000Wellbore radius (ft) 0.25Skin factor 0Capillary pressure (psi) 0

Table 4.2–Data and Constraints


Figure 4.12–Oil production rate vs. time (SPE Comparative Solution 2)

Figure 4.13–Water cut vs. time (SPE Comparative Solution 2)

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Figure 4.12 presents oil productionrate as a function of time. TheQuikLook simulator is not differentfrom the rest of the simulators.Although the predicted the water cutfollowed the general trend of thevarious simulators (Figure 4.13) itsvalue was underpredicted by a small

margin. For example, after 400 daysthe various simulators predicted awater cut ranging from 0.335 to 0.36;the QuikLook simulator predicted awater-cut of 0.322.

Figure 4.14 (Page 4-12) presents theGOR vs. time for all the simulators.

Results of the QuikLook simulatorare consistent with the majority ofthe simulators. The same observa-tion applies to the bottomholeflowing pressure vs. time profileshown in Figure 4.15 (Page 4-12)and the pressure drawdown vs. timein Figure 4.16 (Page 4-13).



Figure 4.14–GOR vs. time (SPE Comparative Solution 2)

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Figure 4.15–Bottomhole pressure vs. time (SPE Comparative Solution 2)

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Figure 4.16–Pressure drawdown vs. time (SPE Comparative Solution 2)

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QuikLook as a Conform-ance Simulator

In this section, the capabilities of theQuikLook simulator as a conformancesimulator are demonstrated. Thesecapabilities are first matched againstSTARS, then examples of QuikLookused for simulating channeling andconing problems are illustrated. Theexamples demonstrate the use of theQuikLook engine, thermal model, andits linkage to WELLCAT for design-ing and optimizing the size andplacement of a conformance treatmentso that reservoir performance ismaximized.

For this comparison, the followingthree specialized data sets were used.Each data set reflects the applicationof sealants for controlling theproduction of unwanted water fromboth oil and gas reservoirs.

1. Water channeling betweeninjector/producer in a black-oilreservoir (PermSeal solution)

2. Water coning of a single gasproducer (H2Zero and PermSealsolutions)

3. Water coning of a single oilproducer (PermSeal solution)

Case 1–Water Channelingin an Injector-ProducerSystem (PermSeal Solution)

Case 1 is an example of a five-yearproduction and water injection in a13-layer black-oil reservoir system.Figure 4.17 (Page 4-14) shows the 21× 21 × 13 ft Cartesian grid system,with the two wells in this reservoir,and a vertical cross-section across thewells illustrating the refined grids inthe near-wellbore area.

This reservoir has an impermeablelayer at the middle of the productivezone (Layer 7), with high-permeabil-ity layers at the top of this barrier andlow-permeability layers below it. Across-sectional view of the produc-tion and injection intervals is shown

in Figure 4.18-a (Page 4-14). Thetreatment interval is shown in Figure4.18-b (Page 4-14).

This producer was flowed at initialoil rate of 1,000 STB/D simulta-neously with water injection in theinjector. The injection pressure wasmaintained at a maximum value of2,000 psia. Oil, gas, and waterproduction histories are presented inFigure 4.19 (Page 4-15) and arecompared with STARS results for thebase case using the simulators asblack-oil simulators. The comparisonis excellent.

Additionally, the predicted pres-sures, both flowing and averagepressure, show a very good matchbetween the two simulators. Figure4.20 (Page 4-15), a plot of averagepressure and bottomhole pressureprofiles for both QuikLook andSTARS simulation runs, shows avery good comparison betweenQuikLook and STARS results.



Figure 4.17–Cartesian grid system used for Case 1 and cross-sectional view across the wells

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Figure 4.18–Cross-sectional view of (a) producing and injection intervals and (b) treatment interval for Case 1

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Figure 4.19–QuikLook and STARS oil, gas, and water production rates (base case)

Figure 4.20–QuikLook and STARS average reservoir and bottomhole pressures vs. time (Case 1)

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As expected, a major portion of theinjected water flooded the highlypermeable layers located at the top,with water breakthrough in thisregion occurring about 200 days fromthe beginning of production. Thissituation is graphically illustrated inFigure 4.21, which shows very highwater saturation in the high-perme-ability layers. Figure 4.21 also showsthe water breakthrough at approxi-mately 200 days as manifested by the

jump in water production fromessentially zero to over 400 bbl/Dand remaining almost constantthereafter. Meanwhile, the layers withlow formation permeability remainedunswept, causing the oil rate toremain low.

Because the preferred path of theinjected water, in this case, is thealready swept high-permeabilitylayers, conformance treatment

Figure 4.21–2-D QuikLook water saturation profile at water breakthrough

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intervention is necessary to produceoil from the lower-permeabilitylayers. An appropriate treatment inthis case is to inject PermSeal intothe high-permeability layers.PermSeal will form a barrier that willprevent injected water from gettinginto the high-permeability layers.Instead, injected water will bediverted into the lower-permeabilitylayers, sweeping these layers.


For the treatment case, the upperlayers in the injector were treatedwith 100 bbl of PermSeal. The wellwas then shut in for five days toallow the polymer to set, and laterput back on injection. Figure 4.22shows that this conformance treat-ment forced the injected water tosweep the bottom layers, therebymodifying the injection profile inthis injector.

QuikLook may be also used tographically illustrate the placement ofthe treatment in greater detail. Figure4.23-a (Page 4-18) shows a 2Dpolymer gel profile in the near-wellbore area of the injection welljust after the conformance treatment.The conformance gel profile isuneven across the treatment interval,as shown in the expanded graph inFigure 4.23-b (Page 4-18). Layers 3and 4, which have lower

permeabilities of approximately 60md, had a shallow gel penetration.Layers 1 and 2 with permeabilities of140 md, and Layers 5 and 6 withpermeabilities of 100 md, hadrelatively deeper gel penetration.

The post-treatment production ratespredicted by both QuikLook andSTARS simulators are plotted inFigure 4.24 Page 4-18). The graphshows an excellent agreementbetween the two simulators.

Figure 4.22–QuikLook water saturation profiles four years after the conformance treatment

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Figure 4.23–QuikLook conformance fluid saturation profiles five days after treatment

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Figure 4.24–QuikLook and STARS oil, gas, and water production rates (treatment case)

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QuikLook simulation of reservoirperformance with and without theconformance treatment is presentedin Figure 4.25. This graph shows thesignificant impact of the polymer geltreatment for reducing waterproduction from 400 bbl/D to almostzero; oil production rate did notsignificantly change. In addition, theplot demonstrates the QuikLooksimulation capability of profilingmodification jobs.

Figure 4.25–QuikLook oil, gas, and water production rates (with and without treatment)

The main objective in this examplewas to reduce water production.Using PermSeal to shut down theupper layers that have already beenswept stopped the water fromchanneling through the reservoir.From that point on, all injected waterwent into the lower zone. Because ofthe injection pressure limitation, theinjected water rate going into thelower zones was not increased.

Consequently, oil rate was notincreased. In this case, a constant oilproduction rate was achieved with asignificantly lower water injectionrate and lower water production. Thelower cost of water injection andsurface processing of produced fluidsvery favorably impacted the econom-ics of the project.

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Case 2–Water Coning of aSingle Gas Producer(H2Zero and PermSealSolutions)

Case 2 involves a 640-acre dry gasreservoir with a producer located atthe center. In this case, the effect ofH2Zero and PermSeal conformancetreatments on reservoir performanceis examined. Figure 4.26-a shows theCartesian grids used in the simulationof the reservoir system. A cross-

section along the well showing boththe areal and vertical grid refinementis presented in Figure 4.26-b.

The producing interval (perforations)is placed at the very top of the forma-tion so as to minimize water produc-tion, as shown by Figure 4.27-a. The5-ft injection zone, used for conform-ance treatment of this well, is shownby the cross-sectional view in Figure4.27-b. This treatment interval wasplaced almost 10 ft below the bottomof the perforations–as close as

possible to the lowest perforationswhile avoiding invasion of conform-ance fluid into the producing intervalduring treatment.

This well was produced at an initialgas rate of 10 MMcf/D. As shown inFigure 4.28 (Page 4-21), waterconing began approximately twomonths after the start of gas produc-tion. The comparison betweenQuikLook and STARS water-production histories is quite good.However, following coning, the

Figure 4.27–Cross-sectional view of (a) producing interval and (b) injection interval for Case 2

Figure 4.26–Cartesian grid system with locally refined grids used for Case 2

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QuikLook simulator shows a fasterincrease in water production, finallyreaching the water production limit of100 bbl/D approximately a year fromthe start of production. STARSreached that same level about threemonths later. The difference in resultsbetween the two simulators is withinthe range for simulation discussed inthe SPE comparative studies.

On the other hand, the predictedpressure values (both the average andflowing bottomhole pressure) fromQuikLook and STARS match verywell. This match is illustrated inFigure 4.29.

To solve the coning problem,approximately 170 bbl of H2Zero wasused to treat this gas producer. Figure4.30 (Page 4-22) presents the gas andwater production rates for both thebase and treated cases. The polymerwas injected into the formation twomonths after the start of production.This event appears as a discontinuityin the water and gas rates, reflectingthe change in condition from produc-tion water and gas to injection ofpolymer and back to injection.

The graph clearly shows the effectof H2Zero on gas and water produc-tion. The treatment increased bothgas rate and gas cumulative produc-tion while delaying water productionfor five years. Although not investi-gated in this chapter, the simulatorcan also be used to investigate thetiming of the treatment.5

In this reservoir, the ratio of vertical-to-horizontal permeability is 0.2.Lower ratios are sometimes seen. Thelower the vertical-to-horizontalpermeability ratio the less severe theconing problem will become, and thewider the polymer barrier will becomefor the same injected volume.

Figure 4.28–QuikLook and STARS gas and water production rates vs.time (base case)

Figure 4.29–QuikLook and STARS average reservoir and flowingpressures vs. time (Case 2)

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The QuikLook simulator may be usedto study fluid saturation inside thereservoir, providing an insight intothe potential optimization of place-ment and reservoir performance.Figure 4.31 shows the water satura-tion distribution inside the reservoirbefore and after the conformancetreatment. In Figure 4.31-a, whichshows the fluid saturation after 60days and just before the conformancetreatment was placed, large pressuredrawdown in the reservoir causedwater coning into the perforatedinterval. In other words, within twomonths of reservoir depletion, waterfrom the aquifer reached the perfo-rated interval, resulting in early waterproduction in this well. Figure 4.30–QuikLook gas and water production rates vs. time after

H2Zero treatment

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Figure 4.31–QuikLook water saturation profiles (before and after the H2Zero treatment)

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Figures 4.31-b and 4.31-c show watersaturation profiles in the reservoir justafter the conformance treatment (65days) and approximately five yearsafter the treatment, respectively. In thewater saturation profile in Figure 4.31-c the bottomwater appears to movearound the gel barrier into the openperforations, indicating that a widerbarrier (larger injected volume) wouldproduce even better results.

One observation that can readily bemade from the H2Zero results inFigure 4.31 is that the treatment waseffective within an approximately28-ft diameter around the wellbore.Although low concentrations of theconformance fluid are presentbeyond that region, Figure 4.31-aclearly demonstrates that the

effective gel barrier controlling thebottomwater coning is limited to the28-ft diameter barrier.

As mentioned in previous sections,the QuikLook simulator uniquelyintegrates the temperature andwellbore calculation into thereservoir simulation. The near-wellbore temperature profiles beforeand after the H2Zero gel treatmentare calculated and presented inFigure 4.32. The initial reservoirtemperature of 150°F is reflectedthroughout the reservoir duringprejob production period (Figure4.32-a). The surface temperaturewas only 80°F. The wellboresimulator WELLCAT calculated adownhole temperature of 130°Fduring the conformance treatment.

Figure 4.32-b shows the temperatureprofile immediately after the H2Zeroand displacement fluid injections.The cooler injected fluids cause areduction in reservoir temperature inthe locations where they contactedreservoir fluid. The subsequentincrease in the temperature of theinjected gel during the productionperiod after the treatment is demon-strated by Figure 4.32-c. This figureshows that after the treatment nearlya month passed before the reservoirtemperature was restored to originalconditions.

The reservoir temperature in this caseis low enough to allow for theinjection of H2Zero without anyproblem, but this is not always the

Figure 4.32–Temperature profiles before and after H2Zero treatment

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case. In cases where reservoirtemperature is fairly high, somecooler fluid may need to be injectedor circulated to reduce the reservoirtemperature enough to allow forpolymer injection without prema-ture gelling.

To investigate the effect of othertreatments, the same well was alsotreated with approximately 300 bbl ofPermSeal. Later, the well was treatedwith 960 bbl of PermSeal. Conform-ance fluid distributions in the near-wellbore area for the H2Zero and thetwo PermSeal treatments are pre-sented in Figure 4.33.

As seen in the previous H2Zero resultsgiven in Figure 4.31, the treatment

Figure 4.33–QuikLook conformance fluid profiles

was effective within a 28-ft diameteraround the wellbore. In the case of thelarger PermSeal jobs, Figure 4.33-bshows an increase in the dimensions ofthe gel barrier, 32 ft and 60 ft indiameter for the 300- and 960-bbltreatments, respectively. In the lattercase, however, the bulk of theadditional PermSeal (over the initial300 bbl) went to expand the barrierthickness as a result of the relativelyhigh vertical to horizontal permeabil-ity ratio. A lower permeability ratiowould cause the barrier to be thinnerand wider.

Another important observation isthat the injected PermSeal pluggedthe formation around the lower part

of the perforated interval (Figure4.33-c). This action reduced theeffectiveness of the treatment,indicating that the conformancetreatment design in such a situationshould not only include the type andamount of conformance treatment tobe injected, but also where thisvolume should be injected.

Gas and water production historiesfor the two PermSeal treatments areplotted in Figure 4.34 (Page 4-25),along with the base case. The largertreatment (960 bbl) considerablyimproved reservoir performance; gasproduction increased significantly asthe water production rate decreased.

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Case 3–Water Coning of aBlack-Oil Producer(PermSeal Solution)

This last case is similar to Case 2,except that the reservoir fluid is ablack-oil system. In this example, theinitial reservoir pressure was 1,800psi. The reservoir was exploitedusing a single well located at thecenter of 160-acre drainage area,shown in Figure 4.35-a (Page 4-26).

The well is produced under a con-straint of 1,000 bbl/D maximum liquidproduction rate. A vertical cross-section showing the refined grids usedin the near-wellbore area is presentedin Figure 4.35-b (Page 4-26). Figures4.36-a and 4.36-b (Page 4-26) showthe locations of the producing andtreatment intervals, respectively.

A summary of the simulation resultsfor the base case (without treatment)

is shown in Figure 4.37 (Page 4-27).For the base case, fluid predictionsby the QuikLook and STARSsimulators compare quite well exceptthat QuikLook predicts slightlyhigher produced water than STARS,which also reflected on the slightlylower oil production rates.

Water saturation distribution insidethe reservoir is shown in Figure 4.38(Page 4-27). Additionally, waterconing is evident very early in the lifeof this oil well. Figures 4.38-b and4.38-c show water saturation profilesjust after the conformance treatment(65 days) and roughly five years afterthe treatment, respectively.

As in the previous coning example,the water tends to bypass the gelbarrier over time. This phenomenonoften calls for a large conformancetreatment to ensure an extensive gelbarrier. However, as noted in the

previous case, increasing the size ofthe conformance treatment couldresult in an unintended additionalrestriction near the perforatedinterval. Similar to the previousexample, in reservoirs with highvertical permeability, the potentialexists for some of the injectedconformance fluid to move up in theformation and invade the originalperforations.

Three conformance treatmentoptions were considered in this case:120 bbl, 300 bbl, and 1,000 bbl ofPermSeal conformance fluid. Theeffect of the injected volume wasexamined, along with the effect ofthe location of injection. In the firstset of treatments the conformancematerial was injected throughperforations in a 5-ft interval located10 ft below the bottom of theproducing interval.

Figure 4.34–QuikLook gas and water production rates vs. time (with and without PermSeal treatment)

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Figure 4.35–Cartesian grid system with local grid refinement used for Case 3

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Figure 4.36–Cross-sectional view of (a) producing interval and (b) injection interval for Case 3


Fig. 4.37–QuikLook and STARS oil, gas, and water production rates (base case)

Fig. 4.38–QuikLook water saturation profiles (before and after conformance treatment)

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Figure 4.39 shows a typical plotfrom optimization runs based onjob size. The extensions tr1, tr2,and tr3 represent treatment volumesof 120 bbl, 300 bbl, and 1,000 bbl,respectively. All the treatmentsmitigated the coning problem in thiswell. The 120-bbl conformance jobappears to be the best treatment forthis case.

Figure 4.39 also indicates thatincreasing the size of the conform-ance treatment results in worse oiland water production during the 5-year period. Although these resultsmay initially appear to be illogical,examination of the conformance fluiddistribution inside the reservoir helpsclarify the results.

Conformance fluid distributions in thenear-wellbore area for these threetreatments with different treatmentvolumes are presented in Figure 4.40(Page 4-29). This figure shows only alimited gel barrier with a diameter ofapproximately 20 feet for the 120-bblconformance job.

Although the larger treatments resultin barriers with larger diameters, thebarriers were also larger in height anddamaged part of the perforatedinterval. Therefore, the larger treat-ments did not perform as well as thesmaller treatment.

When the treatment was injected15 ft below the producing perforatedinterval instead of just 5 ft, thesituation significantly changed asshown in Figure 4.41 (Page 4-29).In this figure, the extensions tr4, tr5,

and tr6 correspond to treatmentvolumes of 120 bbl, 300 bbl, and1,000 bbl of PermSeal, respectively.

Figure 4.42 (Page 4-30) showsconformance fluid distributions in thenear-wellbore area for these samethree treatments. The graphs illustratethe conclusions.

Figure 4.41 shows that increasingthe volume of the injected conform-ance fluid from 120 to 300 bblimproved the performance of thetreatment. Increasing the volume to1,000 bbl still caused the wellperformance to decline, indicatingthat for this reservoir injecting thatmuch volume merely 15 ft below theproducing perforated interval is notadvised. Therefore, an optimizedtreatment size always exists forevery reservoir situation.

Figure 4.39–QuikLook oil and water production rates (with and without treatment)

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Figure 4.40–QuikLook conformance fluid profiles – Case 2

Figure 4.41–QuikLook oil and water production rates (treatment interval is 15 ft below bottom of originalperforations)

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Figure 4.42–QuikLook conformance fluid profiles (treatment interval is 15 ft below bottom of originalperforations)

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Based on the information the user enters, the system candetermine the probability of one or more of the followingconformance problems existing in the well:

• Bottomwater

• Bottomwater coning

• Casing leaks

• Channel behind pipe

• High-permeability streaks

• Injection out of zone

• Interwell communication

• Stimulation into water

Figure 4.43—XERO main screen showing Problem Identification andTreatment Design options

The XERO ProgramOnce data has been collected and analyzed, engineers canuse Halliburton’s XERO Water-Control Expert System toverify problem identification and determine possibletreatments (Figure 4.43). XERO, a Greek term meaning“no water,” is a Microsoft® Windows™-based system thathas two processing phases: the problem identificationphase and the treatment design phase. This chapterprovides a general overview of the XERO System.

Phase 1: Problem Identification

During the problem identification phase, the systemprompts the user to enter reservoir and well information.



Figure 4.44—Customer Information screen

During the problem identificationphase, users will be prompted toprovide the following information.

The Customer Information screen(Figure 4.44) requires the user toprovide information about thecustomer and the well that will beevaluated. After the user provides theavailable information and presses theGO! button, the first ReservoirInformation screen appears.

Figure 4.45—Reservoir Information I screen

The Reservoir Information screens(Figures 4.45 and 4.46, Page 4-33)allow the user to enter as muchrelevant reservoir information aspossible. Much of this informationcan be omitted if it is not available orif its accuracy is questionable. Theminimum data required are thecompleted interval depth range(Figure 4.45) and the bottomholestatic temperature (BHST) (Figure4.46, Page 4-33). Obviously, how-ever, the more information the userenters, the more accurately XEROcan identify potential reservoirproblems.


After choosing GO! from theReservoir Information II screen, theuser advances to the Well Informa-tion screen (Figure 4.47). Thisscreen again prompts the user toanswer a series of questions and toenter available data. The onlyrequired information is the averagepermeability and the hole size.

Figure 4.47—Well Information screen

Figure 4.46—Reservoir Information II screen



Figure 4.49—Injection Information screen

If production and permeability data isavailable, a Production Well Profilescreen will next appear (Figure 4.48).

Figure 4.48—Production Well Profile screen

After entering the pertinent data forthis screen, the user advances to theInjection Information screen (Figure4.49). The only required informationfor this screen is the injection rate.


If the user enters a maximum re-corded bottomhole injection pressure(BHIP), an Injection Well Profilescreen will appear (Figure 4.50)

Figure 4.50—Injection Well Profile screen

Figure 4.51—Workover History screen

After entering the pertinent data, theuser advances to the WorkoverHistory screen (Figure 4.51). Thisscreen asks several questionsregarding past workovers, includingprevious conformance controltreatments. All the treatments listed inFigure 4.51 are Halliburton-specifictreatments.



To enter non-Halliburton treatments,the user would click on the OTH-ERS button to display the genericwater control treatments listed inFigure 4.52.

Figure 4.53—Well Performance screen

Figure 4.52—Other Water Control Treatments screen

After choosing a generic water controltreatment and advancing to the nextscreen, the user must enter wellperformance data (Figure 4.53). Theonly information required for the WellPerformance screen is the currentwater production rate, which in thecase of the example is 650 B/D.


After entering all available wellperformance data, the user advancesto the Water Production Data screen(Figure 4.54), which requests waterproduction data for up to 10 years.

Figure 4.54—Water Production Data screen

Figure 4.55—Water Production Plots screen

Based on the information the userenters, the system creates a waterproduction plot (Figure 4.55), andasks the user to select up to twopatterns that most closely match thecurrent water production plot.



After completing this screen, the useradvances to a series of recommenda-tion screens, the first of which listspossible problems and their percent-ages of likelihood (Figure 4.56).

Figure 4.57—List of Reasons and Unknowns

Figure 4.56—Possible Problems screen

By clicking on any of the possibleproblems listed, the user will receivea list of reasons and unknowns(Figure 4.57). The Reason(s) listcontains data that contributed to theidentification of the problem. TheUnknown(s) list contains data that, ifavailable, would help the systemmore accurately identify the waterproblem.


To learn more about each reason orunknown, the user can click on theitem and another window will appearwith additional information aboutthat particular reason or unknown(Figure 4.58).

Figure 4.58—Window providing more information about unknowns

Figure 4.59—XERO main screen showing active Treatment Design button

Phase 2: Treatment Design

During the treatment design phase,the user chooses one or more of thepotential water problems that thesystem identified as likely and enterstreatment design information into thesystem. The system then determinesfluid systems that can be used basedon current well information anddisplays a selection list of thetreatments. The user can choose fromany of the treatments for each waterproblem from the selection list.

Once the system has identifiedpotential problems, the TreatmentDesign button becomes active on themain screen (Figure 4.59). To beginthe fluid selection process, the usermust first select at least one of thepotential problems and advance tothe next screen.



The Design Information I screenrequires the user to enter specificwellbore geometry and previousstimulation information for the well(Figure 4.60).

Figure 4.61—Design Information II screen

Figure 4.60—Design Information I screen

Once the user enters this informationand selects GO!, the Design Infor-mation II screen appears (Figure4.61). On this screen, the user mustinput the appropriate operatorconstraints on the treatment andother pertinent information as shownon the screen. The “tripping out”option on this screen gives the userthe option of using cement as part ofthe treatment design. Depending onwell conditions, the user may wantto use the program to make twodesigns: one with cement and onewithout cement.


Figure 4.62—Fluid Selection screen

Figure 4.63—Job Design screen

After the Design Information IIscreen is completed, the useradvances to the Fluid Selectionscreen (Figure 4.62), which showsthe recommended fluid, as well asprimary and secondary alternatives.Any of the listed choices could beused for the treatment, but therecommended fluid is the one thatbest fits the requirements of thecandidate well that was evaluated.To select the fluid, the user mustplace the mouse pointer over theappropriate box and click the leftmouse button.

Once a fluid is selected, the systemcalculates a job schedule, includingestimated fluid volumes, a list of thematerials required, and recommendedplacement techniques for the selectedfluids (Figure 4.63).



To see additional information aboutHalliburton products, the user canchoose Product Description from thedropdown menu at the top of themain screen, as shown in Figure 4.64.

After the treatment design phase,users can print a report containingall the data the system used toidentify the problem and generatepossible solutions.

Figure 4.64—Product Description screen for Injectrol Service

• Relative permeability modifier(RPM) simulation

• Radial grids for efficient coningsimulation

Finally, through the use of programssuch as XERO, users can identify andverify conformance problems. Theycan also choose from several meansof improving well conditions.Chapter 5 provides specific informa-tion about the many treatments andtreatment methods available tocontrol conformance problems.

linkage to a wellbore simulation, andaccurate representation of polymerinjection and setting. The linkage ofthe simulator to Halliburton conform-ance fluids makes the simulator anespecially easy tool to use.

Several interesting features have beenconsidered for future implementationinto the simulator to enhance thesimulator’s conformance simulationcapabilities. These features include:

• Polymer adsorption model,which will be calibrated carefullywith specific field cases fromsuccessfully executed jobs

• Irreversible gelation model

Summary andConclusionsThis chapter provided three examplesand SPE comparative studies thatvalidated QuikLook as an excellentreservoir simulator for predicting theperformance of black-oil, volatile,and gas reservoirs. The preprocessor,solver, and post-processor have beenimproved significantly and are quitestable. As a conformance simulator,the last three cases show thatQuikLook predictions compare quitewell with STARS results.

The software is unique in the industrybecause of features such as a veryuser friendly GUI, thermal affect,


References1. Crishlow, Henry, B.: “Modern Reservoir

Engineering: A Simulation Approach,”Prentice Hall, 1977.

2. Khalid Aziz: “Petroleum ReservoirSimulation,” Chapman & Hall, 1979.

3. Odeh, Aziz S.: “Comparison ofSolutions to a Three-Dimensional BlackOil Reservoir Simulation Problems,”JPT, January, 1981, 13-25

4. Weinstein, H. G., Chappelear, J. E., andNolen, J. S.: “Second ComparativeSolution Project: A Three-Phase ConingStudy,” JPT, March 1986, 345-353.

5. Soliman, M. Y., Creel, P., Rester, Sigal,R., Everett, D., and Johnson, M. H.:“Integration of Technology SupportsPreventive Conformance ReservoirTechniques,” SPE 62553 presented atthe 2000 SPE/AAPG Western RegionalMeeting held in Long Beach, California,19–23 June.

6. Dawson, Rapier: “Drillpipe Buckling inInclined Holes,” JPT (Oct. 1984) 1734.

7. Hammerlindl, D. J.: “Basic Fluid andPressure Forces on Oilwell Tubulars,”JPT (Jan. 1980) 153-59.

8. Hammerlindl, D. J.: “Movement, Forcesand Stresses Associated with Combina-tion Tubing Strings Sealed in Packers,”JPT (Feb. 1977) 195-208.

9. Hammerlindl, D. J.: “Packer to TubingForces for Intermediate Packers,” JPT(March 1980) 515-27.

10. Lubinski, A.: “Helical Buckling ofTubing Sealed in Packers,” JPT (June1962) 655-670.

11. Lubinski, A.: “Influence of Tension andCompression on Straightness andBuckling of Tubular Goods in Oil Wells,”Proc., 31st Annual Meeting, API, Prod.,Vol. 31, Sec. IV (1951), 31-56.

12. Mitchell, R. F.: “Buckling Behavior ofWell Tubing: The Packer Effect,” SPEJ(Oct. 1982) 616-24.

13. Mitchell, R. F.: “Numerical Analysis ofHelical Buckling,” paper SPE 14981presented at the 1986 SPE Deep Drillingand Production Symposium, Amarillo,TX, 6-8 April.

14. Muskat, M. and Wycoff, R. D.: “AnApproximate Theory of Water Coning inOil Production,” Trans., AIME (1935),114: 114-161.

15. Wu, F. H., Chiu, T. H., Dalrymple, E.D., Dahl, J. A., and Rahimi, A. B.:“Development of an Expert System forWater Control Applications,” paper SPE27552 presented at the 1994 EuropeanPetroleum Computer Conference,Aberdeen, Scotland, 15-17 March.

Treatment Options 5-1Chapter 5

Chapter 5

TreatmentOptions

The chemical methods that arecurrently available for controllingwaterflow range from a variety ofwater-based polymer systems tohydrocarbon-based, ultrafine Portlandcement slurries.

In injection wells, the success of atreatment is measured by the incremen-tal oil recovered from offset producers.The response time in the producersranges from immediate to severalmonths, depending on treatmentvolume, well spacing, and formationproperties. Engineers may use othertechniques such as fluid-entry surveysand pressure testing to determine thesuccess of the treatment.

In production wells, the success of thetreatment is generally measured bychanges in the well’s water produc-tion. After a treated production wellhas been shut-in for the recommendedtime, production is slowly resumed. Ifthe treatment was designed to seal acasing leak, pressure testing to therequired pressure determines jobsuccess or failure. For all otherapplications, a successful treatmentshould decrease the amount ofproduced water.

When designing a conformanceproject, engineers must first carefullyconsider the purpose of the program.Specifically, they must make certainthat the physical and chemicalcharacteristics of the solutions used

will not contradict with any immedi-ate or future plans for the reservoir.The following questions should beexplored:

What is the treatment expected todo? When success is not explicitlydefined, well data must be thoroughlyreviewed to determine how produc-tion should change after the targetzone is treated. For example, zonesthat were not producing water beforethe treatment might begin producingwater after the treatment. Thesesituations can be predicted bymaterial-mass equations.

What bottomhole conditions canthe treatment withstand?Bottomhole conditions includetemperature, pressure, reservoir-fluidcomposition, and lithology.

For example, design engineers wouldnot recommend injecting anInjectrol® treatment into an interval ifthey were planning an improved oil-recovery job in that same interval at alater date. Instead, they would choosea material that would not permanentlyseal the zone, such as PermTrol.

Regardless of the treatment planned,engineers should always orderlaboratory-scale tests to evaluaterecommended treatment formulationsbefore the actual treatment is per-formed.


5-2 Treatment Options Chapter 5

Water-BasedPolymer SystemsThe following water-based polymer systems havesuccessfully limited the flow of produced formation waterinto the wellbore:

• PermSeal service

• PermTrol service

• H2ZeroSM service

• Injectrol® service

• Relative permeability modifiers,including Kw-FracSM stimula-tion service

Table 5.1 shows the various water-control uses for eachchemical.

PermSeal Service

PermSeal service reduces or plugs permeability to waterand/or CO

2 in hydrocarbon wells. After the water-thin

gelation system is batch-blended and pumped into theisolated water-bearing permeability, the well is shut in, andthe fluid polymerizes into an elastomeric gel. The systemuses a temperature-activated initiator to induce a phasechange from a liquid to a solid at predictable times.PermSeal can be used in temperatures from 70° to 200°F(21° to 93°C). The PermSeal service provides conformancecontrol without heavy metal crosslinkers such as chrome. Itis acid-resistant and compatible in CO

2 environments.

For production wells, PermSeal is recommended for thetreatment of bottomwater coning problems or for treat-ment of zones with a high degree of permeability varia-tion. For injection wells, PermSeal is used for thetreatment of high-permeability streaks in wells with

Injectrol®

SealantPermTrol Service

PermSeal Service

H2ZeroSM

Service

Relative Permeability

ModifiersMOC/One

Acid job went to water X X X X

Bottomwater coning X X X

Bottomwater shutoff X X XCasing leaks X X

Channel behind casing X

Channel from injector X X X

Early water breakthrough X X X

Frac job went to water X X X X

High-permeability streaks X X

No shale barrier X X X

Plugging well X X X

Seal high-pressure zone X X X

Casing leaks X X

Channel behind casing X

Channel to producer X X X X

High-permeability streaks X X X X X

Injection out of zone X X X

Plugging well X X X X

Lost circulation X

Table 5.1—Recovery Effeciency Problems and Solutions

Problems

Drilling Wells

Injection Wells

Producing Wells

Solutions


channeling problems or for injection out of zone.PermSeal treatment volumes can vary considerablydepending on the application. Because the treatment is aporosity-fill-type sealant, engineers can use simplevolume-fill calculations to estimate the treatment size.

PermTrol Service

PermTrol service is used in injection wells to treat high-permeability streaks or poor injection profiles forwaterfloods and CO

2 water-alternating-gas (WAG) floods.

To improve waterflood efficiency, operators pump thetreatment as a water-thin monomer solution at normalinjection conditions to help ensure that the monomerplacement is proportional to the amount of injectionwater entering each zone. After placement, the well isshut in to allow the fluid to polymerize. Once waterinjection is resumed, the resulting high-viscosity polymerincreases volumetric sweep efficiency by divertinginjection water from the most highly permeable zones topreviously unswept oil-bearing zones.

The injection water following a PermTrol servicetreatment will slowly finger through the thick, water-soluble PermTrol service polymer slug. This waterbecomes viscous as it solubilizes the polymer, yielding amore favorable water-oil mobility throughout the reser-voir. The viscosified water behaves as a polymer fluidtreatment with the associated increase in volumetric andunit displacement efficiency.

A typical PermTrol treatment volume ranges from 25 to30% of daily injection. The minimum recommendedPermTrol service treatment volume is 4,000 gal or avolume sufficient to provide 5 ft of radial penetration inthe net pay interval, whichever is greater.

H2ZeroSM Service

H2ZeroSM is a crosslinkable polymer system that forms a

rigid gel capable of permanently sealing the target zone,effectively preventing water and gas flow.

The H2Zero system can provide the following benefits

over chrome-crosslinked gel systems:

Depth of Penetration. H2Zero penetrates deeper intothe formation than chrome-crosslinked gel systems(Figure 5.1). At temperatures above 158°F (80°C) inmatrices containing carbonate, chrome crosslinkers donot remain in solution. As a result, the amount ofchrome-complexed gel placed may not provide asufficient seal. For example, placing a volume of achrome-crosslinked gel that should be sufficient forextending a 5-ft seal around the wellbore may actually

only provide a 3-ft seal, wasting large amounts of gel andmoney. However, the organic crosslinker in H2Zerosealant remains in solution during injection, resulting in astrong seal throughout the entire treated interval.

Temperature Stability. H2Zero is applicable in high-temperature formations. This system can be used attemperatures as high as 320°F (160°C). Chrome-crosslinked systems have limited success at temperaturesabove 225°F (107°C).

H2Zero consists of two components: a base polymer(HZ-10) and an organic crosslinker (HZ-20). HZ-10 is alow-molecular-weight polymer solution that can becrosslinked with either organic or metallic crosslinkers.It is an acrylamide copolymer with enhanced thermalstability that forms strong covalent bonds with thesystem’s organic crosslinker, HZ-20.

Because both components of the H2Zero system are insolution, they can be diluted in the mixing brine. There-fore, system formulations can be batch-mixed or blendedon-the-fly. The two blended components are placed as asingle, low-viscosity fluid (3 to 35 cP) that is thermallyactivated to form a solid gel. H2Zero can be used forpreventing or treating water-management problems orgas-management problems.

H2Zero system treatment solutions contain HZ-10polymer and HZ-20 crosslinker diluted in treatmentwater. The quality of the treatment design increases withthe amount of available information, and treatementdesigns are based on two interrelated parameters:polymer formulation and treatment volume. Volumerequirements are based on how far a gelant must enterinto a formation and how much pore space it must fill.Polymer formulation depends on strength requirementsand placement times.

10000

1000

100

10

10 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

H2Zero SystemTest 2

H2Zero SystemTest 3

Chrome-crosslinked SystemTest 1

Penetration Depth (ft)

RR

F

Gel Damage (RRF) vs. Distance from Injection Face

Figure 5.1—Penetration depth of the H2Zero system.



Injectrol® Service

Injectrol® service is an internally catalyzed silicate systemthat achieves intermediate depth-of-matrix penetration.Injectrol is primarily used to decrease water-to-oil ratiosand water-injection profiles. The internal catalyst allowsoperators to pump a low-viscosity solution (1.2 cp) intothe formation matrix before the material sets to a stiff gel.The stiff gel formed in the matrix seals the formationpores and diverts or blocks water production.

This sealant can be used alone or with a tail-in cementsqueeze. When run with the cement, the Injectrol chemi-cal reacts with the cement to become a gel, while thecement hydrates almost immediately. The resultingcement has a high compressive strength near the wellborewhere the differential pressure is the highest.

Example

In the well shown in Figure 5.2, the oil is in lenses ofvarying permeability. Under waterdrive conditions, the k

4

lens produces the most volume (oil and some water). Outof the total of 206 barrels of fluid per day (BFPD), 6 bblis water, all produced from the k

4 lens at the bottom. With

time, the water production in this well should increase.The harder the well is drawn, the faster the water produc-tion increases.

In an advanced stage in the life of a waterdrive reservoir,water production through the high-permeability lensdominates (Figure 5.3). Because of its high mobility,water is easily drawn up through the k

4 lens. The in-

creased hydrostatic pressure from the water-dominated

column in the tubing tends to choke off oil flow from thek1 through k3 lenses. Therefore, without an effectivecorrection treatment, such as Injectrol, large volumes ofoil can be left in place.

Typical reservoir conditions assist the effectiveness of alarge-volume Injectrol treatment to correct thebottomwater production described. Usually, verticalpermeability is lower than horizontal permeability. As thedistance away from the wellbore increases, less pressuredrop is available to drive the fluid vertically through thezone. For example, at 40 ft from the perforations, 60% ofthe pressure drop is lost. Therefore, Injectrol sealant isplaced in the bottom few feet of the zone, extending 20 to40 ft from the casing to form a long-lasting barrieragainst water production (Figure 5.4).

TypicalBOPD 200BWPD 6

k1 < k2 < k3 < k4

k4

k3

k2

k1

Figure 5.2—Initial oil production from a waterdrivereservoir

5 10 20 30 40

30 40 50 55 60Percent of Pressure Drop

8 in.

k4

k3

k2

k1

Figure 5.4—Water production corrected with a large-volume Injectrol treatment

TypicalBOPD 50

BWPD 180

k1 < k2 < k3 < k4

k4

k3

k2

k1

Figure 5.3—Secondary oil production from a waterdrivereservoir


Treatment Procedure

A generalized treatment procedure used for allInjectrol systems includes (1) isolating the problemzone if possible, (2) pumping preflush fluids whereindicated, (3) pumping the Injectrol® sealant withspacers, and (4) tailing-in with cement slurry (mostgenerally used in producers).

Other features common with all Injectrol treatmentsinclude (1) low injection rates, (2) injection pressure wellbelow fracturing pressure, and (3) exact displacementinto the formation or a small underdisplacement.

Injectrol Sealants and Services

By selecting one of three Injectrol catalysts, operatorscan control the gel time of the Injectrol from a fewminutes to several hours at temperature ranges of 60° to300°F (16° to 149°C).

Injectrol G Sealant

Injectrol G is a three-component system consisting of anInjectrol concentration, an activator, and water. Theactivator controls the wide range of gel (pumping) times.The gel times include a temperature range of 70° to150°F (21° 66°C) BHIT. Pump times of a few minutes to600 minutes are possible at 74°F (23°C) BHIT. Pumptimes of a few minutes to 180 minutes are possible at150°F (66°C) BHIT.

Injectrol IT

Injectrol IT service uses a different activator to providefield-suitable pump times within an injection BHIT rangeof 120° to 180°F (49° to 82°C). At higher temperatures,the gel quality of Injectrol IT is better than Injectrol G.Injectrol IT can be mixed as a single solution. Because ofslight variations in chemicals and mixing waters, engi-neers must order laboratory-scale tests before making jobrecommendations to ensure that pump times are accurate.

Injectrol U

Injectrol U sealant is used only when temperatures of180°F (82°C) or higher are encountered. It can besuccessfully used in wells with BHITs as high as 300°F(149°C). The activator for Injectrol U sealant provideswidely variable set times and precipitates particles ofhard solids when this time has elapsed. Laboratory testingshows it is an effective plugging agent in rock matrices.

Relative Permeability Modifiers

Relative permeability modifiers (RPMs) have propertiesthat help reduce water flow from the treated area of awater-producing zone into the wellbore. In the treatedzone of a hydrocarbon-producing layer, the RPMs shouldresult in little or no damage to the flow of hydrocarbon. Auniversally accepted concept of exactly how RPMsfunction has not been agreed upon. Although severaltheories have been proposed to describe the RPMmechanism, detailed testing has indicated that many ofthese theories are invalid. Perhaps the best explanation isthat no single factor determines the success of an RPM.Rather, an RPM’s success depends on many well/reservoir characteristics, including

• chemistry

• lithology

• problem type

• pore-throat size

• permeability

• saturation

• wettability

• capillary pressure

• adsorption

• gravity effects

RPMs are primarily applied in layered, heterogeneousreservoirs with distinct barriers between higher permeabil-ity hydrocarbon-producing zones (Figure 5.5, Page 5-6). IfRPMs are placed in homogeneous zones that produce bothwater and hydrocarbon, the RPM may tend to decreaseboth water and hydrocarbon permeability substantially.

Kw-FracSM Stimulation Service

Kw-FracSM service combines Halliburton’s RPM technol-ogy with Delta Frac service treatments to provide controlof produced water resulting from fracture growth intowater-productive layers. A special polymer in the prepadportion of the Delta Frac treatment limits water influxinto the created fracture during post-treatment produc-tion. Because the polymer can alter the relative perme-ability to water, it is classified as an RPM.



Reducing the matrix relative permeability to water allowsoil-saturated intervals to produce with higher drawdownpressures. The polymer system does not seal the matrixpore throats, and some continued water production shouldbe expected.

The Kw-FracSM service uses a special prepad treatment aspart of a Delta Frac treatment. A portion of the prepad fluidcontains two polymer components, KW-1 and KW-2, thatpenetrate the created fracture-face matrix and react in situto form an RPM polymer. The RPM polymer will attach topore throats in the rock matrix in both sandstone andcarbonate reservoirs. The reacted polymer has hydrophilicpolymer “branches” that create resistance to water flow ina high-water-saturation matrix. The apparent permeabilityof the rock to oil or gas is affected very little, but thematrix permeability to water is significantly reduced. Thesystem is compatible with CO

2, H

2S, and high-salinity

brines after in-situ formation of the RPM polymer.

The Kw-Frac system has four primary benefits:

• Only minor changes to the Delta Frac system arerequired.

• No complicated procedures are required formixing materials on location that can affect theperformance of the polymer, such as crosslinkingagents or gelling agents.

• Formation brines can be used as a base fluid fordiluting the KW concentrate.

• The treatment can be removed, if desired, with astrong oxidizer such as OXOL II or CAT-1.

Kw-Frac service is recommended for reservoirs withpermeabilities ranging from 0.1 to 1,000 md, andbottomhole static temperatures (BHSTs) below 200°F.

The Kw-Frac system most successfully reduces flow inintervals with high water saturation (Figure 5.6, Page 5-7).

Therefore, the most likely candidates for the treatmentinclude the following:

• wells with water-coning problems in nonfractured,water-drive, homogeneous reservoirs with highvertical permeability (Figure 5.7, Page 5-7)

• layered reservoirs with distinct vertical permeabil-ity barriers (Figure 5.5)

The system will have the poorest oil production results inwells that have been swept and are producing oil andwater through the matrix at high water-saturation levels(Figure 5.8, Page 5-8). Unfavorable results could alsooccur if the system is used on

• wells with interwell communication(Figure 5.9, Page 5-8)

• reservoirs with a high mobility ratio, resulting infingering (Figure 5.10, Page 5-8)

Oxol II RPM Removal System

If removal of an RPM is required, Oxol II is recom-mended. Oxol II treatments break down the backbone ofthe polymer, reducing the effect of the damage caused bypolymer blockages in the pore throats.

As a solid, Oxol II service offers several handlingadvantages. It is safer to work with than comparableconcentrated liquid systems, and it has a shelf life of atleast one year.

Generally, operators run a tubular cleanup ahead of OxolII treatment to remove as much rust as possible. Oxol IIservice spends on rust, resulting in lower effectiveconcentrations downhole. Spacers between acids andOxol II solutions are required. Treatment volumes canrange from 50 to 100 gal/ft of net pay. Oxol II cleaner isgenerally slightly overdisplaced and left in place for 12 to48 hours.

��

��

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��

��

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Figure 5.5—Vertical permeability isolation results in unsweptlayers with low water saturation.


��

��

��

��

��

��

Figure 5.6—Under optimum treatment conditions, oil flows through a density-segregated portion of the reservoir that has low watersaturation. The treated region resists water flow into the fracture; oil and water flow through the reservoir together only in thetransition zone. This condition requires high vertical permeability

��

��

��

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� ��

Figure 5.7—Good vertical permeability allows density segrega-tion of oil and water

Squeeze CementingMany of the previously described chemical systems canbe enhanced with water-based or hydrocarbon-basedcement slurries as a tail-in to the chemical treatment. Thissection describes basic cement slurry designs andprovides specific information about MOC/One dieselcement slurry systems.

General Design Principles

Two of the most important and useful pieces of informa-tion needed for the design of a successful zone isolationcementing treatment are formation pressure and fractur-ing pressure. With this information, Halliburton can(1) design a cement job that will not lose a large volumeof cement slurry into the formation, (2) determine arealistic column height for recementing treatments, and(3) control cement fallback. Pressure buildup andinjectivity tests indicate whether a well can hold a fullcolumn of fluid.



��

��

��

��

��

Figure 5.8—Streaks of high horizontal permeability allow oil and water to flow through the matrix together. No vertical permeabilitybarriers are present. A Kw-Frac treatment would allow oil to flow to the wellbore, but an envelope of high water saturation would resultaround the treated interval. Over time, lower total production would result

��

��

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��

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Figure 5.9—A high mobility ratio could result in channelingfrom the injector to the producer, making this formation a poorcandidate for Kw-Frac treatment

��

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��

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Figure 5.10—In this formation, water and oil are flowing throughthe reservoir with little vertical permeability isolation. Thisformation would be a poor candidate for a Kw-Frac treatment


If a job requires circulating cement into the openannulus, Halliburton uses formation pressure data and aseries of “rate-in, rate-out” circulation tests to evaluate(1) perforation location, (2) a realistic cement columnheight, and (3) the need for additional cleaning, flushes,or the application of ultralight cements.

Most commonly, a squeeze job fails because operatorsfail to place enough slurry in the areas where it couldhave been effective, and they do not hold the cement inthe area long enough to form a permanent seal. The mostcommon contributors to squeeze job failure and field-proven methods of handling each problem are discussedin the following paragraphs.

Lack of Proper Fluid Control

Improper fluid-loss control can result in either a prema-ture squeeze (slurry dehydration) or no squeeze (causedby fluid loss being too low). Either condition can blockan uncemented annulus and force cement into the wrongzone or prevent sufficient slurry from entering aninjection zone. The degree of fluid-loss control duringsqueeze jobs depends mostly on the types of fluid-lossadditives used in the slurry. Fluid loss can be reduced bylarge precharge volumes and reactive flushes pumpedahead of the cement.

Improper Perforation Cleanup

Many squeeze jobs fail because the perforations were notcleaned properly. For example, if a mud-filled casing isperforated with a pressure differential to the formation,the perforations are likely to be plugged with mud,crushed formation material, and debris. The zone shouldbe tested to ensure cleanliness.

Low Placement Rates

A low injection rate simply allows more time for aspecific volume of cement slurry to lose fluid and becomea solid mass. In effect, the placement rate supplies thetime factor for fluid loss.

No Knowledge of Where Cement Is Needed

Some squeeze jobs are apparently performed with littlemore knowledge than the approximate depth of the casingleak. If more than one formation is open in anuncemented annulus, the slurry enters the formation withthe lowest fracture gradient, which frequently is not theformation that produced the brine.

Poor Injection Point Control

Slurry entrance into at least one formation is normallyrequired for a successful squeeze treatment. Simplyisolating a hole in the casing with packers does not ensurethat the slurry can be forced into the formation at thatpoint. In some instances, a zone cannot be successfullysqueezed until the uncemented annulus below it isblocked.

Effect of Bottomwater

If naturally induced fractures extend into lower zones,bottomwater control problems will occur. To combatbottomwater, Halliburton may recommend injecting alow-viscosity, temporary blocking material into the upperzone before squeezing the bottom zone. The success ratioof this type of treatment is greatly improved whenreactive preflushes are used ahead of the cement.

Crossflow

High-volume water flow in an uncemented annulus (oftenreferred to as crossflow) can dilute a cement slurry until itcan no longer seal effectively. To control this condition,operators must eventually squeeze off the brine-produc-ing zone with treatment pressures greater than theproducing-zone pressure. If a weak zone is open in thesame uncemented area, special materials, such as foamcements, thixotropic cements, and reactive preflushesmay be needed. A multiple-stage cement job withselective injection can also prevent crossflow if the slurryinjection points can be controlled.

Poor Bonding

Poor bonding to the formation is common in salt forma-tions. Salt-saturated slurries are necessary for goodbonding, but these slurries can have long thickening timesand may set at low to moderate temperatures. This dualproblem can complicate squeeze procedures. The slurrymust remain static from the placement time to the initialset time. High-pressure water can easily enter and disruptthe integrity of a cement during its transition from a fluidto a solid.

Cement Flowback

When pumping stops, the downhole pressure is initiallyequal to the hydrostatic pressure and any remainingsurface pressure. If no squeeze pressure is obtained, someformations continue to take slurry until the hydrostaticpressure is equal to the fracture extension pressure. As thecement gels and fluid is lost from the slurry (to permeable



formations), the pressure in the cement rapidly decreases.This pressure decrease allows gas or brine to enter thecement column, migrate upward, mix with the cementslurry, or form-flow channels for the brine or gas. Foamcement, Gas-Chek, GasStop, and thixotropic cements canoften effectively control this phenomenon.

Multiple Injection Zones

Difficulties of squeezing more than one area with a singlejob are mostly self-evident. However, treating multipleinjection points or paths in a single zone is less under-stood. For instance, a reactive preflush or pad ahead ofthe slurry can result in complete blockage of one flowpath, yet the following slurry meets very little addedrestriction and no squeeze pressure is evident.

This condition is best solved with either multiple-stagesqueeze jobs with a Flo-Chek® component preflush aheadof each stage or treatment with a large volume of anInjectrol® solution that reacts with the formation brineand has time-dependent gelation.

MOC/One Cement

The one disadvantage of using DOC as a treatmentmethod is that the standard cement’s larger particle size(up to 120 µm) limits its penetration into the leak. As aresult, a job may have to be repeated several times beforeit is even marginally successful.

In these situations, the use of the MOC/One service couldprovide more positive results. MOC/One consists ofMicro Matrix cement, diesel or kerosene, and MOC-Asurfactant. MOC-A, when used at the recommendedconcentration by volume of diesel, yields a densifiedslurry, which when contacted by water, delivers a low-permeability slurry with high compressive strength.

With a maximum particle size of 10 µm or less, MicroMatrix cement can penetrate areas in the wellbore andsurrounding formation that would otherwise be inacces-sible. When this cement is used, MOC-A is necessary toprevent the immediate oil-wetting of the ultrafinecement. Like a standard DOC slurry, the ultrafine,hydrocarbon-based slurry only sets when it contactsmobile water. Since ultrafine slurries have a delayedgelation, however, they usually penetrate fractures moredeeply before they set. The system can be used up totemperatures of 400°F (204°C).

For example, a well with an initial production of 10BOPD and 300 BWPD was first treated with hydrocar-bon-based, standard cement. Only 470 to 940 lb of

standard cement could be placed in the formation, andwater production did not decrease. A 4,000-gal, complexedpolyacrylamide treatment was then placed in the zone.Again, water production remained the same. Eventually,production increased to 10 BOPD and 600 BWPD. At thistime, operators placed 2,500 lb of ultrafine cement in adiesel slurry behind a 1,500-gal MOC-A treatment. Aftertwo months, the well stabilized at 17 BOPD and only200 BWPD.

When MOC-A contains 20 gal/Mgal of hydrocarbon-carrying fluid, the resulting Micro Matrix cement slurryhas a delayed gelation that allows it to be placed intowater-bearing formation fractures some distance from thewellbore. The small size of the Micro Matrix cement alsoallows for placement into near-wellbore microchannelsthat may be communicating with adjacent water-bearingformations.

Conclusions

Once a treatment design has been established, engineersmust determine the proper placement technique foroptimal treatment results. Chapter 6 provides informa-tion regarding placement methods and mechanicalequipment.

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Crook, R.J., Lizak, L.F., and Zeltmann, T.A.: “PermianBasin Operators Seal Casing Leaks with Small-Particle Cement,” paper SPE 23985, presented at the1992 Permian Basin Oil and Gas Recovery Confer-ence, Midland, TX, March 18-20.

Dahl, J. and Harris, K.: “Uses of Small Particle SizeCement in Water and Hydrocarbon Based Slurries,”presented at the 1991 9th Tertiary Oil RecoveryConference in Wichita, KS, May.

Dalrymple, D., Maughmer: “Treatment Helps DecreaseWater and Reduce Costs,” American Oil and GasReporter (June 1992) 114.

Dalrymple, D., Sutton, D., and Creel, P.: “ConformanceControl in Oil Recovery,” presented at the 1985Southwestern Petroleum Short Course, Lubbock, TX,April.

Dalrymple, E. D. et al.: “A Selective Water ControlProcess,” Presented at the 1992 Rocky MountainRegional SPE Meeting in Casper, WY, May 18-21.

Dalrymple, E.: “Two Stage Treatment Reduces Water/OilRatio,” Oil & Gas J (Sept. 10, 1990) 73.

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Ewert, D.P., Almond, S.W., and Bierhaus, W.M.: “SmallParticle Size Cement,” paper SPE 20038, presented atthe 60th California Regional Meeting, Ventura,CA, April 4-6, 1990.

Ewert, D.P. et al.: “Squeeze Cementing,” U.S. Patent5,121,795, June 16, 1992.

“General Rules and Regulations of the Oil and GasConservation Division,” Oklahoma CorporationCommission, 1986 Edition.

Great Britain Patent 2,099,412A, U. S. Patent 4,466,831,Canada Patent 1,201,274.

Hanlon, D. J., Fulton, S., and Beny, M.: “New Chemicaland Mechanical Technology for Injection ProfileControl,” presented at the 1987 SouthwesternPetroleum Short Course, Lubbock, TX, April.

Harris, K.L. and Johnson, B.J.: “Successful RemedialOperations Using Ultrafine Cement,” presented at the1992 Mid-Continent Gas Symposium, Amarillo, TX,April 13-14.

Harris, K.L. et al.: “Repairing Leaks in Casings,” U.S.Patent 5,123,487, June 23, 1992.

Harris, S.H.: “Control of Water Production Using Cross-Linked Polymers,” 1988 United States Dept. ofEnergy Improved Oil Recovery Conference, Abilene,TX, Sept. 11-13.

Heathman, J.F. and East, L.E. Jr.: “Case Histories Regard-ing the Application of Microfine Cements,” paperSPE/IADC 23926 presented in 1992 in New Orleans,February 18-21.

Herring, G.D., Milloway, J.T., and Wilson, W.N.:“Selective Gas Shut-Off Using Sodium Silicate in thePrudoe Bay Field, AK,” paper SPE 12473 presentedat the 1984 Formation Damage Control Symposium,Bakersfield, CA, February 13-14.

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Himes, R.E. et al.: “Low Damage Fluid Loss Control forWell Completions,” paper SPE 22355 presented at the1992 International Meeting on Petroleum Engineering,Beijing, March 24-27.

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Rensvold, R.F., Ayres, H.J., and Carlile, W.C.:“Recompletion of Well to Improve Water-Oil Ratio,”paper SPE 5379 presented at the 45th AnnualCalifornia Regional Meeting, Ventura, CA,April 2-4, 1975.

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Placement Techniques and Equipment 6-1Chapter 6

Chapter 6

PlacementTechniquesandEquipment

Placement TechniquesPlacement techniques used in treatingunwanted water and/or gas productionshould be chosen on a well-by-wellbasis. This section discusses place-ment differences between injectionand production wells, the nature offluid movement, and the followingplacement methods:

• bullheading

• mechanical packer placement/inflatable packer placement

• dual-injection placement

• chemical packer placement

• isoflow placement

• transient placement

Placement in Injection vs.Production Wells

Injection Wells

Treatment placement in injectionwells is relative to the ongoing water,steam, CO

2, water-alternating-gas

(WAG), or other flooding methodused to maintain formation pressure,replace volumetric removal, andsweep the reservoir to the bestmobility efficiency. To alter the in-depth injection profile of these wells,engineers strive to change the flowthroughout the reservoir to modifyexisting inefficient patterns or paths.

Generally, the conformance-controltreatment is performed based on thesame injection method (pressure-rate)currently used on the well. If pos-sible, even the fluid used should besimilar to the one used to flood thewell. Logically, if the same injectionmethod and fluid are used, thetreatment should enter the formationin the same path. The injectionpressure must remain below partingpressure; if injection pressureapproaches fracture initiationpressure during treatment, a ratedecrease will be necessary. Althoughresults are rarely immediate, treat-ments of injectors can have asignificant effect on the long-termproduction and the ultimate volumeof oil produced from a reservoir.

Production Wells

Generally, placement in productionwells is based on the idea that anaqueous fluid will enter the formationin the same area through which anaqueous fluid is being produced. Forexample, once produced water hasbroken though, the mobility ratio ofthe aqueous solution in the water-bearing strata is much more favorablethan the mobility ratio of the aqueoussolution in the oil-bearing strata. As aresult, at reasonable pressures andrates, the solution treatment shouldpreferentially enter the water-producing portion of the zone.


6-2 Placement Techniques and Equipment Chapter 6

Controlling Fluid Movement

To effectively use the conformance technology pro-cesses available, engineers must consider the followingconditions:

• Unless the formations are highly stratified withlittle or no vertical permeability and no randomfracture systems, the corrective materials mustpenetrate deeply into the formation to influencefluid flow for a significant time in injection orproducing wells.

• The best fluid to perform deep formation place-ment is a low-viscosity, solids-free fluid thatimproves mobility or has a high resistance toextrusion in a controlled manner.

• When injection wells are treated at less thanparting pressure with a fluid that has viscositycomparable to the floodwater viscosity, selectiveinjection may result. The rate and pressure ofinjection should be maintained at or less than therate and pressure of injection of the floodwater.The same may hold true for producing wells if thefluid is comparable to produced water, andfracturing rates and pressures are avoided.

K-MaxSM Service

The K-MaxSM service is a water-based polymer system thatcan limit the flow of produced formation water into thewellbore. K-Max service involves the use of a cross-linkable hydroxyethyl cellulose (HEC) in the form of aliquid gel concentrate (LGC). K-Max forms a highlycomplexed gel downhole that prevents completion ortreatment fluids from flowing into the isolated areas.Specifically, K-Max is used as a temporary pill to shut offproduction or injection at various depths. This applicationallows engineers to pinpoint water- or gas-producing zonesand determine production effects that might occur after thezone is treated.

The K-Max base fluid is mixed, hydrated, and allowed topartially or fully crosslink on the surface before it ispumped. The fluid is allowed to complex fully beforefinal placement of the uncrosslinked polymer into theformation matrix.

K-Max service fluid can be prepared in brines havingdensity ranges from 8.33 to 15.2 lb/gal of fresh water.These brines include KCl, NaCl, NaBr, CaCl

2, NH

4Cl,

seawater, and CaCl2 - CaBr

2. Brine formulations and

polymer fluid mixing procedures must be strictlyobserved.

To prevent uncrosslinked polymer from entering theformation, operators must hold the polymer fluid in themixing container until the crosslinking reaction is wellunderway. If crosslinking is completed before thematerial is pumped out of the blender, it will still bepumpable and control fluid loss when placed.

The crosslink reaction rate depends on a variety offactors, such as brine type, brine weight, and polymerfluid temperature. Usually, higher-weighted solutionshave a faster complexation rate. The rate is fluid/tempera-ture-dependent. A warmer polymer fluid crosslinks fasterthan a cooler one. As the polymer fluid is heated by theformation temperature during placement, the reaction rateaccelerates.

When coiled tubing is used to place K-Max, the frictionpressures through the smaller-diameter coiled tubingrestrict the gel concentration of the K-Max treatment.Under these conditions, a 60-lb/Mgal formulation isrecommended. Pumping rates are restricted by thepressure rating on the tubing (a maximum of approxi-mately 0.5 bbl/min is expected for 1 1/

4-in. tubing).

Figure 6.1 (Page 6-3) shows typical friction pressuresthrough coiled tubing.

Bullheading

The simplest, most economical treatment placementmethod is the bullheading technique, in which operatorsinject the treatment through existing tubulars. Thistechnique can be used effectively for entry into zones thatwill take 100% of fluids or for entry into perforationswhere a permeability decrease is necessary. Bullheadingis seldom recommended, however, because without zonalisolation, the treatment may seal not only the intendedwater zone but the oil zone as well. Figure 6.2 (Page 6-3)shows a bullhead treatment that has sealed both zones.Bullheading can be performed with slickline tool isola-tion, sand plugs, etc.

To design an effective placement procedure and respon-sive treatment, engineers must carefully consider wellconditions and reservoir characteristics. Specifically, theymust analyze injectivity profiles and perform a multi-rateinjection analysis to determine variances in entry that areassociated with variances in injection pressures/rates. Thepossibility of static condition crossflows that mightcontinue after placement should also be considered.

The profile entry logs generated during these tests arevisuals for near-wellbore entry only, and analysts mustalways consider the possibility that conditions may differdeeper in the formation.


Injection profile entries for wells can often change overthe life of a well. For example, damage such as scaling,paraffin buildup, and plugging caused by fines can divertfluid movement. Frequently, this damage is actually anasset to treatment placement, because it prevents treat-ments from entering into possible preferred floodintervals. Once the solution treatment is in place, thisdamage can be removed through stimulation.

If available, computer simulators can also interpolatepressure responses. Specifically, engineers can use themaximum bottomhole injection pressure (BHIP) deter-mined during the multi-rate injection/profile analysis toestablish the limits for a treatment.

10

1.0

0.1

Fric

tion

Pres

sure

(psi

/ft)

10 20 30 40 50 60 70 80

Flow Rate (gal/min)

60 lb/Mgal K-Max

90 lb/Mgal K-Max

Figure 6.1—Typical friction pressures through coiled tubing.

Cement

Oil Zone

Water Zone

Figure 6.2—Bullhead placement technique.



Mechanical/Inflatable Packer Placement

For added control, operators can use mechanical packers,bridge plugs, or selective zone packers to isolate perfora-tions or a portion of an openhole completion into which atreatment will be placed (Figure 6.3). This methodprotects critical perforations in the adjacent oil sandsfrom sealant invasion.

When selecting tools, engineers should consider how thetreatment materials could affect the performance of thetool. Depending on the circumstances, the tools couldalso be left in the well as a control for injection orproduction. To determine the packer’s degree of place-ment control on the zone, engineers must test forinjectivity and communication aspects.

Dual-Injection Placement

When performing dual-injection placement (Figure 6.4),operators use the well’s tubulars to inject fluids down thetubing and down the annulus. Packers, bridge plugs, sandplugs, chemical plugs, chemical packers, and othermechanical means are usually used with this technique.By isolating intervals with tools or covering intervalswith sand backfill, operators can more accurately targetthe preferred treatment intervals.

The dual-injection placement technique offers efficientplacement control. To protect critical perforations in theadjacent hydrocarbon-producing zone from the treatmentsolution, operators inject a nonsealing fluid that iscompatible with the formation. Frequently, the fluid usedto protect the adjacent intervals from the influx oftreatment solution is reactive to the sealant fluid. There-fore, when the treating pressure increases, the fluidinterface builds a reacted seal between the formationintervals, creating a barrier that may allow the treatmentto be placed farther into the formation.

Ideally, dual-injection placement directs fluids along theinterface away from the wellbore and far enough into theformation to change the injectivity or the production.After considering the density, viscosity, and frictionalpressure differences of the two injection streams, engi-neers normally equalize the BHIP to control placementwhen using this technique.

Dual-injection placement techniques can also be designedbased on injectivity profiles and multi-rate injectionanalyses used for determining variances in entry associ-ated with variances in injection pressure/rates. The profileanalysis can provide percentages of fluid entry through-out the entire interval and can help analysts determine the

Cement

Oil Zone

Water Zone

Figure 6.3—Mechanical packer placement technique.

CompatibleNongelling Fluid

Oil Zone

Sealant Sealant

Water Zone

Figure 6.4—Dual-injection placement technique.

tubular and annular rates for performing a dual-injectionplacement technique. The possibility of static conditioncrossflows or transient flow that might continue afterplacement can be determined by profile analysis, but theprofile entry logs generated during these tests only applyto near-wellbore entry; conditions deeper in the formationcould differ. If pressure responses vary from the initialanalysis, the control materials could be placed into thewrong interval.

Operators can also use dual-injection techniques to placetreatments in which two incompatible fluids must bepumped separately into the well through the tubingannulus before they are injected into the interval. If thetwo systems cannot be mixed and pumped through thetubing annulus from the surface, they are pumpedseparately down the tubing and intermixed at the treat-ment interval.


Chemical Packers

In gravel-packed or openhole completions, mechanicalpackers or straddle systems cannot provide the isolationthat is required for placing a treatment into the selectedzone. To overcome this problem, chemical systems havebeen developed that can temporarily or permanentlyisolate a section of open hole behind the slotted screen orgravel-pack screen.

For example, in a horizontal open hole with a slottedliner, zones exist that should be protected above andbelow the water-producing zone. Chemical packers canbe placed in the annulus above and below the zone to betreated. Once in place, a mechanical system can be usedto isolate inside the liner to allow the upper and lowerzones to be properly sealed, and coiled tubing can beused to place the conformance treatment between thechemical packers.

Isoflow Placement

When using the isoflow placement technique (Figure 6.5),operators direct the treatment solution into the selectedinterval(s) while protecting the hydrocarbon-producing orhydrocarbon-bearing zone by simultaneously injecting anonsealing, formation-compatible fluid that contains aradioactive “tag” down the annulus.

Before the treatment is run, a gamma-ray detection tool isrun down the well inside the tubing and placed at theinterface between the upper nonsealing and lower sealingpoint in the well. During the initial analysis and sometimesduring the sealant placement, engineers analyze the outputfrom the tool to regulate tubing and annulus pump rates. Toadjust the location of the interface, operators can manipu-late the pump rate of the tubing and annulus fluids.

During normal isoflow placement operations, the sealingsolution is placed at a rate based on daily injection. Thisrate should be proportional to the interval’s percentage offluid entry based on profile analysis. Before placement,engineers must also consider differences in eachchemical’s viscosity and density.

When adjusting to maintain the location of the fluidinterface, engineers should use only the annular fluid’srate if possible. The tubular fluid should remain constant.To save time, operators generally spot the annular fluiddown near the preferred interface before the analysis isperformed, because annular volumes are based on thedaily injection volume for the upper interval.

Rate adjustments can control the interface during treat-ments. As the location of the fluid interface is beingtracked, rate, not pressure, controls these jobs; pressurerestrictions of the casing are the only pressure consider-ation. To locate the interface and track the stationaryinjectivities for each annular rate adjustment, operatorscan move the gamma-ray logging tools to differentlocations in the wellbore.

The isoflow method is uniquely suited to wells withnegative surface pressures and wells in which the fluidstands static when they are shut in. On wells that flowback and have a charged-up bottomhole pressure,engineers may recommend the isoflow method to performtests that will establish the appropriate rates for conduct-ing a conformance job. This solution treatment should beperformed with a stripper for the casing and a downholeflapper valve for the tubing, which both serve to negatethe use of gamma ray tools and interface analysis duringthe actual treatment. If the treatment solutions do notcause a problem with the removal of the tubular from thewell, the jobs are performed as in static-condition wellsor low-pressure, vacuum-pressure injection wells.

Transient Placement

When the injectivity profile and shut-in crossflow onmany wells are analyzed, it may become apparent that thewell could produce fluid during static conditions fromone interval into another. The analysis may also indicatethat the well may be crossflowing at a particular rate fromother intervals while injection is being performed at aparticular rate. Once a sufficiently high rate is estab-lished, these wells may not show a crossflow.

Figure 6.5—Isoflow placement technique.

RadioactiveCompatible Fluid

Oil Zone

SealantSealant

Bottomwater Production

Gamma RayLogging Tool

Wireline



Transient placement techniques (Figure 6.6) usecrossflow to help eliminate entry into unwanted intervalsas treatments are injected into the zones that will besealed. The fluids from the treatment and crossflow areallowed to intermix in this placement procedure.

While designing treatments, engineers must perform teststo determine if compatibility and sealant concentrationwill seriously affect the treatment. For example, sincetransient flow and injection flow intermixing will occur,engineers must analyze injectivity profiles by performingmultirate tests to determine the concentration of thetreatment solution fluid.

Service EquipmentHalliburton uses a variety of equipment to place andmonitor conformance technology treatments. Thisequipment includes process monitoring and controlsystems, treating-fluid filtration systems, mixing systems,and high-pressure pumping systems.

This section describes some of the different types ofHalliburton equipment available for this service.

Monitoring Systems

Halliburton’s INSITE™ for Stimulation portable dataacquisition system (Figure 6.7, Page 6-7) is an IBM®

PC-compatible laptop computer that records andprocesses data from proprietary data acquisitionhardware. The basic INSITE for Stimulation system canmonitor one density input, one temperature input, threepressure inputs, and three flow inputs. While monitoringthe basic transducer inputs, the system can simulta-neously acquire up to 80 different pressures, flows,temperatures, and densities from multiple remote digitalpanel meters, such as Halliburton Unipros.

Filtering Systems

Several filtering systems are available for cleaningtreating fluids. Figure 6.8 (Page 6-7) shows a low-pressure diatomaceous earth filter that can filter fluids atrates as high as 15 bbl/min. High-pressure filters that canwithstand pressures up to 10,000 psi with a maximumflow rate of 2 bbl/min are also available.

Tubularand Crossflow

Placement

Crossflowfrom Interval

SandPlugback Fill

Cement

Figure 6.6—Transient placement technique

Mixing and High-PressurePumping Systems

Mixing and high-pressure pumping systems are availableas individual, standalone systems or as integrated systemsthat have been combined and mounted on a skid, truck, ortrailer. Halliburton mixing systems incorporate the latesttechnology in high-energy mixing with computer con-trols. Fluids can be mixed continuously while beingpumped downhole, or they can be mixed in batchesbefore pumping.

Pumping Equipment Example

The HCS Advantage skid (Figure 6.9, Page 6-7) hasmixing and high-pressure pumping capabilities. This unitincorporates the RCM® II mixing system. This mixingsystem uses Halliburton’s patented Axial Flow Mixer(Figure 6.10, Page 6-8) and microprocessor-based controlsystem. The unit has a 25-bbl tank that can be used as partof a continuous mix system or as part of a batch-mixsystem. It also includes Halliburton’s high-pressure HT-400 pumps.

The CMR-100R (Figure 6.11, Page 6-8) batch-mixingtrailer contains two 50-bbl tanks and the RCM® IImixing system. This unit is suitable for mixing batchesup to 100 bbl.


Figure 6.7—INSITE for Stimulation Portable Data Acquisition System

Figure 6.8—Halliburton Filtering System

Figure 6.9—Halliburton HCS Advantage Skid



Figure 6.10—RCM® Axial Flow Mixer flow schematic

Bulk CementInlet

Bulk CementControl Valve

MixingWater

R/ADensometer

Screen

Slurry toDisplacement Pumps

RecirculatingCentrifugal Pump

BulkCement

H2O

VentRubberSplashSheath

RecirculatingFluid

Diffuser

TurbineAgitator

Figure 6.11—Halliburton CMR-100R Batch-Mixing Trailer


Figure 6.12—Halliburton Coiled Tubing Services

Coiled Tubing

The coiled tubing unit (CTU) (Figure 6.12) is a self-contained, easily transported, hydraulically poweredworkover unit that injects and retrieves a continuousstring of tubing into a larger string of tubing or casing.The unit can be used on live wells and allows operatorsto inject fluids or nitrogen while continuously movingthe pipe.

When used to place conformance treatments, coiledtubing has the following advantages:

• Coiled tubing isolates treatment materials fromcontaminants in the tubulars.

• Because of the smaller tube capacity, requiredpumping times are shorter.

• Treatments can be more accurately placed.

• The smaller diameter of coiled tubing minimizesthe intermixing of the staged treatments.

To prevent the treatment fluid from flowing past theproper point, operators can use inflatable straddlepackers, single packers, and bridge plugs.

Inflatable straddle packers can be used in selectivechemical treatments for water-zone shutoff or for squeezecementing or locating leaks. Inflatable packers can beused for selective chemical treatments, cement squeezejobs, and zonal isolation in horizontal wells. Inflatablebridge plugs can be used to temporarily shut off waterproduction from lower zones, or for selective chemicaltreatments or selective squeeze cementing.

ConclusionsAfter the selected treatment has been placed in the hole,engineers must perform tests on the well to determine thesuccess of the treatment. Chapter 7 provides conform-ance treatment evaluation methods and calculations.

Conformance Treatment Evaluations 7-1Chapter 7

Chapter 7

ConformanceTreatmentEvaluationsandCalculations

IntroductionEngineers can evaluate conformancetreatments using many of the sametechniques that they initially used toidentify the problem, including welllogs, production logs, well testing,downhole video, reservoir descrip-tion, reservoir monitoring, productionperformance, tracer surveys, andfield-wide reservoir simulations.These topics were covered in detail inChapters 2 and 3.

This chapter briefly discusses thefollowing additional methods that canbe used as a part of a treatmentevaluation:

• numerical methods

• production data

• injection well data (Hall plots)

Numerical MethodsTo properly quantify the effect of atreatment, engineers must carefullyevaluate sophisticated well test dataand use numerical simulation pro-grams. Well test data evaluationprograms simplify the complex resultsgained from numerical simulators toseveral equations. These equationsinclude a mathematical definition ofrate, pressure, and time behavior indimensionless form and account forflow-rate variation based on theprinciple of superposition. A matchingalgorithm modifies the reservoirmodel parameters to provide calcu-lated pressures that match thoserecorded during the well test.

The time required for a numericalsimulation is directly proportional tothe number of factors that will beconsidered. The more factorsinvolved in the test, the morecomputer time will be required. Otherfactors that can greatly complicatenumerical solutions include reservoirboundaries, aquifer influence, gascap, layering, partial penetration, andheterogeneities.

Production DataProduction data provide an accessiblesource of information for evaluatingconformance projects. Comparisonsof water-oil ratio, gas-oil ratio, oilproduction rate, and wellheadpressure and temperature data topretreatment values can providequantitative means of evaluatingtreatment success.

Injection Well Data(Hall Plot)

If the cumulative volume of injectedfluid and a good record of injectionpressures are both available, engineerscan use a Hall plot to evaluate injectionwell performance. This methodassumes a series of steady-stateinjections, which means that dimen-sionless pressure, p

D, is time-indepen-

dent. This assumption is valid only aslong the pressure transient has notencountered external boundaries, fluidcontacts, and reservoir heterogeneities,and the rate variation is not frequent.The Hall plot provides an acceptableapproximation over a reasonableperiod and is a simple means ofmonitoring injection-well performance.


7-2 Conformance Treatment Evaluations Chapter 7

Based on the constant pD assumption, Eq. 7.1 can be

derived:

Eq. 7.1

where

ptf

= wellhead pressure in the injection well, psi

pe

= reservoir pressure, psi

∆ρtw

= hydrostatic pressure inside the wellbore, psi

t = injection time, D

Bo

= formation volume factor, RB/STB

µ = injected fluid viscosity, cp

s = skin factor

k = permeability, md

h = formation height, ft

Wi

= the cumulative water injected, STB

When (pe - ∆ρ

tw)t is small compared to the integral, a plot

of this integral, commonly approximated by the summa-tion, Σp

tf ∆t, vs. cumulative water injected, W

i, will result

in a straight line, the slope of which is given by

Eq. 7.2

For a radial flow pattern, Equation 7.2 changes to

Eq. 7.3

where

Bo

= formation volume factor of injected fluid, RB/STB

re

= drainage radius, ft

rw

= wellbore radius, ft

If re/r

w is known and s has been determined through a

pressure transient test, k/µ can be estimated from Eq. 7.3.Likewise, if k/µ has been determined through a pressuretransient test and r

e/r

w is known, s can be estimated.

When a successful conformance treatment has beenperformed, the graph should display two straight-lineportions with the slope of the second line, m

H2, which

reflects conditions after the conformance treatment. Thisslope should be greater than the slope of the first line,m

H1, which reflects pretreatment conditions.

To evaluate injection performance before and after aconformance treatment, engineers can estimate the ratioof the new flow efficiency to the old flow efficiency:

Eq. 7.4

where

Ef1

= old flow efficiency

Ef2

=new flow efficiency

A successful conformance treatment results in a flowefficiency ratio less than 1.

The skin resulting from the treatment, s2, can be calcu-

lated from

Eq. 7.5

where s1 is the pretreatment skin value.

A wellbore will have a higher skin value after a success-ful conformance treatment. In addition to reflectingchanges in permeability around the wellbore, this higherskin value also reflects changes in fluid properties andoffset production, and the accumulation of skin damageon the wellbore face.

The value of k/µ used in Eqs. 7.1 through 7.3 andEquation 7.5 is determined from conventional well tests,such as a pressure buildup test.

Treatment Placement CalculationsThe modified Hall plot provides a method for monitoringthe effectiveness of a permeability reduction treatment.The following is a step-by-step procedure for placing atreatment using the modified Hall plot technique.

1. Plot cumulative injection pressure (psi) with respectto time (Σp

tfdt) on the y axis, vs. cumulative injection

volume in bbl (on the x axis). Determine the slope ofthe best-fit straight line through the data. Calculatethe current skin factor for the well from:


Eq. 7.6

where:

s1

= initial skin factor,

mH1

= slope of the best fit line, psi-D/bbl,

k = formation permeability, md,

h = height of open interval, ft,

Bo

= formation volume factor of produced orinjected fluid, RB/STB,

m = fluid viscosity, md,

re

= drainage radius, ft, and

rw

= wellbore radius, ft.

2. Perform a step-rate test on the well, and plot the dataas p

tf (y axis) versus injection rate (x axis). Fluid

entry into the lower permeability zones is indicatedby changes in the slope of the plotted data. Calculatethe ratio of the slope of first straight line portion tothe slope of the second.

The step-rate test can be performed during thepreflush stage of the treatment.

3. During placement of the polymer, create a Hall plotfor the treatment. For each data point taken,

a. Plot Σptfdt in psi-D (on the y axis) versus

cumulative injection volume in bbl (on the xaxis) on the graph.

b. Determine the slope of the plot at the data point.

c. Using the slope determined in Step 3b and theslope and skin factor determined in Step 1,calculate the current skin factor from:

Eq. 7.7

where:

s2 = skin factor at current data point,

mH2

= slope at current data point, psi-D/bbl,

B = formation volume factor of polymer fluid,RB/STB, and

µ = viscosity of treating solution, cp.

d. Estimate the depth of polymer penetration, rp,

from:

Eq. 7.8

where:

frr = residual resistance factor. (Note: Determine f

rr in

the laboratory using formation samples and thetreatment polymer.)

e. Determine the ratio of mH2

for the current point tothe initial value of m

H2 for the treatment. If this

value equals or exceeds the slope ratio deter-mined for the step-rate test of Step 2 before therequired penetration radius is reached, go to theflush/overdisplacement stage of the treatment.Such a slope ratio change indicates fluid entryinto the lower-permeability portion of the interval.

Pressure-Transient Testing to DetermineTreatment Volume

Given any two of (1) treatment volume, (2) degree ofmobility reduction, or (3) resulting skin damage, thethird factor can be calculated, if formation porosity andheight are known. This is seen through the followingrelationships.

Assuming uniform invasion of the treatment polymer anda penetration radius much greater than the wellboreradius, the volume of polymer treatment injected, V

p, can

be volumetrically related to penetration radius, rp, from:

Eq. 7.9

or, equivalently,

Eq. 7.10

where φ is the formation porosity, and h is the height ofthe treated formation. Skin factor, s, is related to thepenetration radius and the mobility of the treated zone,(k/µ)

p by:



Eq. 7.11

Where (k/µ) is the initial reservoir mobility and rw is the

wellbore radius.

This can be rewritten as:

Eq. 7.12

To examine the relationships between the parameters,plots of r

p and s versus V

p/fh can be generated for several

reduced mobility ratio values.

These relationships can be used in different ways. Forexample, if it is beneficial to achieve a certain skin factorand the degree of permeability or mobility reduction isknown, Eq. 7.11 can be rearranged and used to determinethe penetration radius required. Once r

p is known, Eq. 7.9

or 10 can be used to determine the treatment volume.

In another potential application, well testing methodscan be used to determine the skin factor resulting from aconformance treatment. The penetration radius of thetreatment is determined from the treatment volume usingEq. 7.10. Once skin factor and penetration radius areknown, Eq. 7.12 can be used to determine the mobilityin the treated region. The mobility and the penetrationradius can be subsequently used in a numerical simula-tor to model the expected well behavior with thetreatment in place.

The following is an example of how these equations,coupled with Halliburton’s well test design software,RESULTS (REServoir ULtimate Test Simulator), areapplied to identify water coning.

Table 7.1 presents the reservoir data used for this study.This reservoir has a permeability of 100 md, which wasreduced to 1 md out to a radius of r

p by polymer injec-

tion. Bottomwater influx is represented by a constant-

pressure lower boundary on the formation. In the simula-tions, the well is put on production. Then the time thebottom boundary is detected at the wellbore is observed.Plots of water breakthrough time versus r

p or V

p/fh for

several reduced mobility ratio values can be generated.

Eq. 7.10 was used to calculate the minimum treatmentvolumes required to penetrate radii of 10, 25, and 100 ft.Table 7.2 presents these chemical volumes with equiva-lent radial flow skin values calculated from Eq. 7.11.

Flow rate (STB/D) 20

Net pay thickness (ft) 20

Reservoir temperature (°F) 250

Porosity 0.2

Invaded zone permeability (md) 1

Formation permeability (md) 100

Vertical permeability (md) 0.2

Wellbore radius (ft) 0.4

Skin 0

Wellbore storage (bbl/psi) 0.000183

Connate water saturation 0.2

Oil gravity (API) 40

Gas gravity 0.75

Solution gas-oil ratio (scf/STB) 300

Formation volume factor (RB/STB)

1.218

Total formation compressibility (1/Mmpsi)

10.78

Oil viscosity (cp) 0.736

Table 7.1—Reservoir Data for Study

rp

(ft)Vp/φh

(gal/ft)se

10 2,350 318.725 14,687 409.450 58,748 478

100 234,991 546.6

Table 7.2—Calculated Values for Example


Reservoir Simulation to Determine Treat-ment Volumes

The pressure-transient testing approach is a quick andapproximate representation of the coning phenomena. Aproper reservoir simulator, which can duplicate the flowof the individual phases through the formation, generatesgraphs of water-cut or gas-oil ratio versus treatmentvolume for several reduced mobility values.

Coning and Cresting CalculationsThis section presents several relatively simple methodsfor estimating oil and gas coning and cresting behaviorin vertical and horizontal wells. These methods cannotreplace a detailed numerical simulation of a specificwell in a specific reservoir but are much simpler to useand provide some reasonable estimates of coningbehavior in several situations. The section includesmethods for calculating (1) critical rate, i.e., the maxi-mum rate a well can produce without water or gasbreakthrough, (2) breakthrough time, i.e., the time thecone or crest breaks through to the well at a particularproduction rate, and (3) water cut, i.e., the fraction ofproduction that is water at a particular point afterbreakthrough occurs.

This section also includes methods for determining theoptimal vertical position of a horizontal well, i.e., the depthwater and gas break through simultaneously. For morespecific information on the methods, refer to the originalworks from which the correlations were taken. Joshi alsodiscusses many of the methods with example calculations.

Vertical Well Coning Calculations

Critical Rate Calculations

Meyer, Garder2 and Pirson3 MethodMeyer and Garder developed approximate analyticalsolutions to water and gas coning based, among otherthings, on the assumptions that (1) the potential distribu-tion in the oil phase is not influenced by the cone shapeand (2) critical rate is determined when the water conereaches the bottom of the well. Pirson extended thisanalysis to simultaneous coning of both water and gas.

Eq. 7.13: Gas Coning

Eq. 7.14: Water Coning

Eq. 7.15: Simultaneous Water and Gas Coning

where the well completion is optimally placed so thebottom of the completion is at:

Eq. 7.16

Chaperon4 MethodThis method, based on an approximate analytical solu-tion, assumes the perforated interval is negligibly smallcompared to the reservoir height.

Eq. 7.17

The quantity qc* is given by1:

Eq. 7.18

where the dimensionless drainage radius, reD

, is given by:

Eq. 7.19

If vertical permeability is unknown, qc* can be reasonablyapproximated as 1.

Chaney et al.5 MethodChaney et al. developed curves relating critical produc-tion rate to the oil-zone thickness and the height of theperforated interval using mathematical analysis andpotentiometric model techniques. Kuo and DesBrisay6

performed a least squares fit on Chaney’s curves to putthem in equation form. Because the curves were devel-



oped for one particular set of fluid and rock characteris-tics, corrections must be applied to generalize them toother conditions. The resulting correlation is:

Eq. 7.20

Schols7 MethodThe Schols Method is an empirical correlation based onexperiments performed in Hele-Shaw models.

Eq. 7.21

Chappelear and Hirasaki8,9 MethodThis theoretically derived model accounts for perforatedintervals that do not extend to the top of the oil zone. Itcan account for moderate anisotropy and down-coning ofoil into water.

Eq. 7.22

where the average of the natural logarithm of the radiuswith an effective radius correction is given by:

Eq. 7.23

and the effective radius is given by:

Eq. 7.24

If the perforated interval extends to the top of the oilzone, Eq. 7.24 simplifies to:

Eq. 7.25

The average height of the oil zone can be determinedfrom a material balance as:

Eq. 7.26

Høyland, Papatzacos, and Skjaeveland10

MethodThe correlations of this method are based on more than 50critical rates determined using a numerical reservoir model.

Eq. 7.27: Isotropic Reservoirs

For critical rate calculations in anisotropic reservoirs, twodimensionless quantities are used, dimensionless critical

rate, qHPS

ocD, defined by:

Eq. 7.28: Anisotropic Reservoirs

and dimensionless radius, as defined by Eq. 7.19.

The procedure for calculating critical rate is:

1. Determine dimensionless radius, reD

, using Eq. 7.19.

2. Determine dimensionless critical rates, qHPS

ocD, for

several fractional well penetrations using Fig. 7.1.

3. Plot dimensionless critical rate as a function of wellpenetration (Høyland, Papatzacos, and Skjaevelanduse a semilogarithmic scale).

4. Calculate fractional well penetration.

5. Interpolate in the plot produced in Step 3 to deter-mine dimensionless critical rate.


6. Determine the critical rate using the followingequation:

Eq. 7.29

Yang and Wattenbarger MethodUnlike most previous correlations, that of Yang andWattenbarger, developed from numerical simulations,assumes a no-flow outer boundary. The perforated intervaldoes not need to extend to the top of the pay interval.

Eq. 7.30

where the dimensionless critical rate is computed from:

Eq. 7.31

Guo and Lee12 MethodAssuming a three-dimensional, combined radial-sphericalflow pattern, Guo and Lee developed an analyticalmethod that, unlike most previously developed correla-tions, accounts for the effect of limited wellbore penetra-tion on oil productivity. And, unlike previous correlationsthat show that the greatest critical flow rate occurs with awellbore penetration length of zero, they determined arelationship that gives a finite optimum completion lengthfrom the top of the formation.

An excellent approximation of their critical rate equation is:

Eq. 7.32

The optimum well penetration can be solved for numeri-cally from:

Eq. 7.33

where:

Eq. 7.34

Eq. 7.35

Eq. 7.36

and:

Eq. 7.37

Once xopt

is determined, the maximum achievable water-free rate can be calculated by substituting x

opth for h

p in

Eq. 7.32.

Additional MethodsAdditional methods for calculating critical rates arederived from breakthrough time calculations, such asthose of Sobocinski and Cornelius13 and Bournazel andJeanson.14 These are presented with the breakthroughcalculations in the following section.

Wheatley15 developed an analytical solution that consid-ers the influence of the cone on the potential distributionbut requires an iterative procedure for determining thecritical rate in oil-water coning. Piper and Gonzalez16

extended the method to determine the optimum comple-tion interval in the presence of bottomwater and a gascap. Both methods can be easily programmed on acomputer, but they are too involved to present here.



ComparisonsMuskat and Wycoff’s analytical solution17 is generallyagreed to give too high critical rates, 6,10,15 a conclusionextended to the Chaney et al. method.5 In contrast, Meyerand Garder’s method2 was found to underestimate criticalrates,1,7,10 a conclusion extended to Pirson’s method.3

Schols’ method7 also underestimates critical rate whencompared to the Høyland et al. or Wheatley methods,1,10,15

but not by as much. Høyland et al. found their methodagrees very closely with the analytical solution ofWheatley for well penetrations in the r

D interval from 2 to

50. Wheatley’s theory gives slightly higher values at theupper end of the interval and lower values at the lowerend. The trade-off between these two methods is using agraph or performing iterative calculations. The Guo andLee method12 differs from the others in that critical ratesapproach zero as the fractional well penetration goes tozero, which suggests an optimal penetration depth exists.

The Chappelear and Hirasaki8,9 and Yang and Watten-barger11 methods were developed primarily for use inlarge-scale reservoir simulators, but they can make coningcalculations for a single well. No comparisons have beenfound in the literature for these particular models.

Breakthrough Time Calculations

Sobocinski and Cornelius13 and Bournazeland Jeanson14 MethodsSobocinski and Cornelius developed a breakthrough timecorrelation based on a combination of experimental workand a computer finite difference model. Bournazel andJeanson’s later work is based solely on laboratory results.

1. Calculate the dimensionless cone height, z, according to:

Eq. 7.38

2. Calculate the dimensionless breakthrough time fromeither of the following:

Eq. 7.39: Sobocinski and Cornelius

or:

Eq. 7.40: Bournazel and Jeanson

3. Use the dimensionless breakthrough time and thefollowing equation to calculate, t

bt, the time of

breakthrough in days:

Eq. 7.41

where:

Eq. 7.42a: Sobocinski and Cornelius

Eq. 7.42b: Bournazel and Jeanson

The breakthrough time and the dimensionless break-through time are infinite if the denominator of therelationship between dimensionless breakthrough timeand dimensionless cone height is infinite, a condition metfor the Sobocinski and Cornelius correlation if z = 3.5and for the Bournazel and Jeanson correlation if z = 4.3.By plugging these values of z into Eq. 7.38, the definitionof z, and solving that equation for q

o, the critical rates

predicted by these methods are:

Eq. 7.43: Sobocinski and Cornelius

and:

Eq. 7.44: Bournazel and Jeanson


Wang and Wattenbarger Method11 (no-flowouter boundary)

Eq. 7.45

where:

Eq. 7.46

Eq. 7.47

and:

Eq. 7.48

Water Cut/Water-Oil Ratio CalculationsFor any of these methods or those presented for horizon-tal wells, water cut and water-oil ratio can be determinedfrom each other according to:

Eq. 7.49

and:

Eq. 7.50

Chappelear and Hirasaki8,9 MethodThis theoretically derived model accounts for perforatedintervals that do not extend to the top of the oil zone. Itcan account for moderate anisotropy and down-coning ofoil into water.

In this method, solving the following quadratic equationfor the water cut is necessary. Of the two roots to theequation, the one that falls between 0 and 1 is the correctvalue of fw.

Eq. 7.51

where the mobility thickness ratio, Nmt, is found according to:

Eq. 7.52

the depth-averaged oil relative permeability is given by:

Eq. 7.53

the depth-averaged water relative permeability is given by:

Eq. 7.54

and the critical rate is given by Eq. 7.22.



Kuo and DesBrisay6 MethodThe procedure for calculating the water cut at any timeafter breakthrough is:

1. Calculate the breakthrough time, tbt, in days using

either the method of Sobocinski and Cornelius orBournazel and Jeanson.

2. Determine the dimensionless water cut time, twcD

from the following equation:

Eq. 7.55

3. Calculate the limiting water cut for the reservoir from:

Eq. 7.56

where:

Eq. 7.57

Eq. 7.58

and

Eq. 7.59

4. Determine the dimensionless water cut, fwD

from thefollowing:

Eq. 7.60

5. Calculate the actual water-cut fraction as

Eq. 7.61

Yang and Wattenbarger Method11 (no-flowouter boundary)This method assumes downhole production rate remainsconstant.

Before breakthrough:

Eq. 7.62

After breakthrough:

Eq. 7.63

where:

Eq. 7.64

and

Eq. 7.65

The (qoB

o+q

wB

w) term in Eq. 7.65 represents a set

downhole production rate. To approximate a constantsurface rate, approximate the downhole rate or iteratethe calculations of Eqs. 7.63 through 7.65 until suffi-cient accuracy is attained. (A few iterations should besufficient.)


Effect of Horizontal BarrierMeyer and Garder2 derived a relationship for adjustingthe critical rate if an impermeable barrier of some radius,r

b, is placed at the bottom of the perforated interval for

water coning or at the top of the perforated interval forgas coning.

Eq. 7.66

Karp, Lowe, and Marusov,18 recognizing the smallpermeability such a barrier can have and that water isproduced through the barrier, derived an equation fordetermining the produced water-oil ratio if the oilproduction rate is high enough to maintain a water coneunder the entire barrier without producing any wateraround it.

Eq. 7.67

Karp et al. also present an equation for the shape of themaximum stable water cone in a radial system.

Horizontal Well Cresting Calculations

Critical Rate Calculations

Chaperon4 MethodBased on approximate analytical solutions, this methodassumes the horizontal well is placed at the top (forwaterdrive) or bottom (for gas-cap drive) of the oil zoneto minimize coning.

Gas Cap or Bottomwater Drive with ConstantReservoir Pressure

where1:

Eq. 7.68

where1:

Eq. 7.69

and:

Eq. 7.70

A quick estimate of qoc can be made for L » 2ye by settingF = 4.

Pseudo-Steady State (Pressure Depletion)

Substitute ye/2 for y

e in Eq. 7.68.

Efros19,20 Method

Eq. 7.71

Joshi suggests ye, rather than 2ye, should appear in thedenominator of Eq. 7.71.



Giger and Karcher et al.20-22 MethodThis method is based on an analytical solution thatassumes the well is located near the top of the reservoirfor bottomwater and edgewater drives and near thebottom for gas-cap drive.

Eq. 7.72

Joshi23 Method (Gas Coning)This method is simply an extension of the Meyer andGarder method for gas coning in vertical wells. It is madeby substituting an effective vertical wellbore radius.

Eq. 7.73

where the effective wellbore radius, r, is calculated as:

Eq. 7.74

and the major half-axis of the drainage ellipse, a, iscalculated as:

Eq. 7.75

Dikken24 Method (Edgewater Drive)Similar to other methods, this one assumes the well isplaced at either the top or the bottom of the reservoir,depending on whether water or gas is present.

Eq. 7.76

where:

Eq. 7.77

Yang and Wattenbarger11 MethodUnlike most previous correlations, that of Yang andWattenbarger, developed from numerical simulations,assumes a no-flow outer boundary.

Eq. 7.78

where:

Eq. 7.79

Breakthrough Time and Calculations

Ozkan and Raghavan25 MethodOzkan and Raghavan developed a theoretical correlationto calculate water breakthrough time for a horizontal wellin a bottomwater drive reservoir by assuming the pressureat the oil-water interface is constant. Because the calcula-tion involves graphically determining sweep efficiency,with different graphs for different relative placements ofthe well from the oil-water interface, it is advisable torefer to the original work for more information.

Papatzacos et al.26,27 MethodsGas Cap or Bottomwater

Papatzacos et al. developed a breakthrough time correla-tion using a semi-analytic method and assuming the wellis located at either the top or the bottom of the oil zone tominimize water or gas coning. The problem was solvedusing two methods.


In both methods, dimensionless production rate, qP

D, is

determined from the relationship in Eq. 7.80:

Eq. 7.80

and the breakthrough time, tbt, is calculated from the

dimensionless breakthrough time, ttD

, according to:

Eq. 7.81

The first method of solution used the assumption that the topgas or bottomwater can be represented as a constant pressureboundary. This leads to the relationship between dimension-less breakthrough time and dimensionless rate of:

Eq. 7.82

The second method considered gravity equilibrium withinthe cone, giving the relationship:

Eq. 7.83

The two methods give very similar results for qP

D³ 1.

Comparison with a numerical simulator shows theanalytical solution has reasonable accuracy for all gas

viscosities with qP

D£ 0.3. For gas viscosities greater than

0.15, reasonable accuracy is expected with qP

D£ 0.6.

Gas Cap and Bottomwater

Papatzacos et al. also presented methods to calculatebreakthrough time for both top gas and bottomwater andthe optimum well placement, i.e., the vertical position

where gas and water breakthrough should occur simulta-neously. These techniques involve the following steps:

1. Calculate the ratio of density contrasts, y, according to:

Eq. 7.84

2. Determine the coefficients cWP,i

and cbt,i

from Tables7.3 and 7.4 (Page 7-14).

3. Calculate the dimensionless production rate usingEq. 7.80.

4. Calculate the optimum well placement and thedimensionless breakthrough time from:

Eq. 7.85

and:

Eq. 7.86

where:

Eq. 7.87

5. Calculate the actual breakthrough time from Eq. 7.81using ∆ρ

og for ∆ρ.

Yang and Wattenbarger11 Method (no-flowouter boundary)

Eq. 7.88

where:

Eq. 7.89



Eq. 7.90

and:

Eq. 7.91

Water Cut/Water-Oil Ratio Calculation

Yang and Wattenbarger11 Method (no-flowouter boundary)This method assumes that the downhole production rateremains constant.

Before breakthrough:

Eq. 7.92


After breakthrough:

Eq. 7.93

where:

Eq. 7.94

and:

Eq. 7.95

The (qoB

o+q

wB

w) term in Eq. 7.95 represents a set

downhole production rate. To approximate a constantsurface rate, approximate the downhole rate or iterate thecalculations of Eqs. 7.93 through 95 until sufficientaccuracy is attained. (A few iterations should be sufficient.)

Chapter Abbreviations

Nomenclature

A = areal extent of well or reservoir, ft2

Bo

= formation volume factor, RB/STB

fw

= water cut

H = initial zone thickness, ft

h = zone thickness, ft

hh

= height of horizontal well from top of oil zone, ft

hcb

= height of completion bottom from top of oil zone, ft

hct

= height of completion top from top of oil zone, ft

k = effective permeability, md

kr

= relative permeability

L = horizontal well length, ft

lH,go

= distance between horizontal well and gas-oil interface, ft

lH,wo

= distance between horizontal well and water-oil interface, ft

lV

= distance between perforated top of a vertical well and gas-oil interface, ft

M = water-oil mobility ratio

= [mo(k

w)

or/m

w(k

o)

wc] where (k

w)

or is the effective

permeability to water at residual oil saturation, and (k

o)

wc is the effective permeability to oil at connate

water saturation

Ms

= surface-corrected water-oil mobility ratio

= M´Bo/B

w

N = initial oil in place, STB

Np

= cumulative oil production, STB

q = production rate, STB/D

re = drainage radius, ft

rw

= wellbore radius, ft

Swc

= connate water saturation, fraction

Sor

= residual oil saturation, fraction

t = time of production, D

xe

= distance between horizontal well and constant pressure boundary, ft

xopt

= optimum fractional penetration of wellbore

ye

= half drainage length (perpendicular to horizontal well), ft

µ = viscosity, cp

ρ = density, g/cm3

∆ρ = density difference, g/cm3

φ = porosity, fraction

Subscripts

b = barrier

bt = breakthrough

c = critical

D = dimensionless

g = gas

H = horizontal

i = initial

o = oil

p = perforated (from top of sand)

t = total

V = vertical

w = water

wc = water cut

Superscripts- = average



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