SPECIAL CORE ANALYSIS DESIGNED TO MINIMIZE ... - … Damage... · cim 95-136 special core analysis designed to minimize formation damage associated with vertical/horizontal drilling

CIM 95-136

SPECIAL CORE ANALYSIS DESIGNED TOMINIMIZE FORMATION DAMAGE ASSOCIATED WITHVERTICAL/HORIZONTAL DRilliNG APPLICATIONS

By

Doane, R.D., Bennion, D.B., Thomas, F.B., Bietz, R, and Bennion, D.W.Hycal Energy Research Laboratories Ltd.

Abstract well drilling programs. This paper highlights testprocedures used in the past, describes some potentialproblems with these test procedures, and outlines thecurrent state of the art in laboratory technology withrespect to specialized laboratory testing to evaluate drillinginduced damage for vertical and horizontal wellapplications.

Laboratory testing of core material to attempt tooptimize drilling fluid composition and procedures hasbeen used for many years to attempt to minimize invasiveformation damage of a mechanical, chemical or biologicalnature which can occur during the drilling of horizontal orvertical wells. This paper discusses the deficiencies ofpast methods, such as the use of non-representative coreor fluids, non-preserved or non-restored state core,ambient conditions of temperature and overburdenpressure, direct injection of muds/filtrates into samples andunrealistically high drawdown gradients for cleanup. Thepaper describes the current state-of-the-art technologyused to eliminate many of these concerns and also toextend drilling fluid evaluation technology to extremelyheterogeneous carbonate and sandstone formations,fractured formations and specific test equipment andprocedures used to evaluate the effectiveness and utilityof underbalanced drilling programs.

Common Mechanisms of Formation Damage DuringOverbalanced and Underbalanced Drilling Operations

A number of authors have provided a detaileddiscussion of potential formation damage mechanismswhich may occur during overbalanced and underbalanceddrilling operations. A summary of this work is provided inthe Iiterature(1-6). These mechanisms would include:

Introduction

Formation damage occurring during the drilling ofhorizontal or vertical wells can be a significant mechanismof ultimate reduced productivity in both oil and gas bearingformations. In some cases a combination of petrographicand special core analysis techniques are used to evaluatethe potential effectiveness of proposed drilling fluids andprocedures, prior to the actual cost and risk ofimplementation. These tests are conducted to obtain abetter assessment of the risk associated with the use ofproposed drilling fluids and to optimize the fluid andprocedures which will be utilized in a given horizontal orvertical well operation to maximize ultimate productivity ofoil or gas. Considerable advances have been made inrecent years in both the execution and interpretation of theresults of laboratory coreflow tests to obtain representativeresults for effective field design of horizontal and vertical

1. Mechanically Induced Formation Damagea. Physical migration of in-situ fines and mobile

particulatesb. The introduction of extraneous solids of either an

artificial nature (ie. weighting agents, fluid lossagents, or artificial bridging agents) or naturallyoccurring drill solids generated by the milling actionof the drill bit on the formation.

c. Relative permeability effects associated with theentrainment of extraneous aqueous or hydrocarbonphases within the porous medium.

d. Formation damage effects associated with the useof extreme underbalance or overbalance pressuresand associated fines migration or spontaneousimbibition phenomena.

e. Direct mechanical glazing phenomena associatedwith bit-formation interactions. This particulardamage mechanism is usually associated with gasdrill operations where high bit-rock temperaturescommonly occur.

Early Core Flow Test Designs

Figure 1 provides a schematic illustration of an earlycoreflow test apparatus utilized to conduct a variety ofdifferent types of formation damage studies. Many of theearly studies concerned with drilling induced formationdamage focused primarily on damage associated with theinvasion of filtrate from the mud into the formation. Hence,many of these tests were conducted in a si~ljfied fashionusing extracted core samples into which fresh water orproposed mud filtrates were displaced and on whichevaluation of permeability reductions were based.However, as described in the previous section detailingdamage mechanisms, potential reactivity with clays orin-situ reactivity between invaded fluids and in-situ fluidsrepresents only a small fraction of the potentialmechanisms of damage which could be induced during atypical drilling operation.

Later test procedures attempted to mirror some of themore realistic effects associated with the drilling processby utilizing either whole drilling muds or synthetic mudscontaining synthetic solids. Many of these tests wereconducted in an erroneous fashion by directly displacingthese muds at an elevated pressure into the samples in aforced displacement or squeeze type mode. Since in anatural operation in the field the circulating fluid flows inthe annular space and a natural filter cake is built upwhich impedes the infiltration of both solids and mudfiltrate into the formation, this does not represent anaccurate simulation of what is occurring. In manysituations very erroneous results were obtained withindications of either stable filter cakes or significantinvasion depending on the way the tests were conductedand the injection pressures which were ultimately utilized.

2. Chemically Induced Formation Damage.a. Clay induced formation damage associated with the

reaction of low salinity or fresh invaded fluid filtrateswith potentially reactive clays (swelling clays ormixed layer clays). Low salinity or pH shocks mayalso result in clay deflocculatlon phenomena whichare a disruption of electrostatic forces which areholding clays in a flocculated state. Thisphenomena is common in some kaolinite richreservoirs.

b. The precipitation of waxes, solids, asphaltenes ordiamondoids caused by a reduction in temperatureor pressure associated with the drilling process, orincompatibility between introduced hydrocarbonfluids and in-situ hydrocarbon fluids resulting in adestabilization and precipitation of asphaltenes.

c. The formation of insoluble precipitates caused bythe blending of incompatible drilling and completionfiltrates with in-situ foreign waters.

d. The generation of high viscosity stable water in oilemulsions in the near wellbore region caused bythe invasion of incompatible water-based filtratesresulting in the formation of an emulsion block.

e. Wettability alterations associated with the use ofinvert drilling muds or other muds containing highconcentrations of polar surfactants or materials.Near wellbore wettability alterations can reduce therelative permeability of oil significantly and increaserelative permeability to water, causing a dramaticchange in the water-oil production characteristics ofa given completion.

In many cases extremely high drawdown pressures toconduct the regain permeability measurements after drillingfluid exposure were also applied (anywhere from 7000 to30000 kPa) across small core plugs a few centimetreslong in order to clean up invasive damage. Many differenttypes of formation damage are capillary pressuredominated and can be mobilized at very high impliedinstantaneous pressure gradients. However, in mostreservoir situations it is not possible or even feasible toapply as high of drawdown pressure gradients as werecommonly utilized in many laboratory core floodexperiments. For this reason the results of the regainpermeability measurements which may have Indicatednominal or no damage may have been entirely misleading.If realistic drawdown gradients which could normally havebeen applied in the reservoir were utilized, a significantamount of residual damage may have been retained.

3. Biologically Induced Formation Damage. The introductionof bacterial agents during drilling and completion is amajor concern as problems associated with bacterialgrowth in porous media can be of a delayed yetsignificant onset. Major problems associated withbacterially induced damage would include:a. Secretion of high molecular weight polysaccharide

polymers to fonn plugging bio- films or bio-slirnes.b. Colonization of bacteria onto conductive metal

surfaces resulting in pitting and corrosion.c. Propagation of sulphate reducing bacteria (a

classification of anaerobic bacteria which do notrequire oxygen to survive) and the resultingmetabollzation of sulphate present in naturallyoccurring fonnation or injection water to toxichydrogen sulphide gas.

Many of the problems associated with drilling inducedformation damage can be diagnosed through appropriatelaboratory simulation techniques and appropriateprocedures and fluids developed to mitigate or reducemany of the damage concerns previously mentioned.

The majority of the original tests were also conductedon extracted core samples and did not take intoconsideration many parameters such as restored state

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wettability or correct initial water or gas saturationconditions. These factors are key parameters, both incontrolling fluid loss and invasion rates into the formationand as a basis for the propensity for aqueous orhydrocarbon phase trapping during regain permeabilitymeasurements. Particularly troublesome is the fact thatmany reservoir evaluations targeted for gas reservoirapplication were not conducted using gas as adisplacement fluid but were conducted using synthetic oilsor water, which represent a totally foreign situation withrespect to representing the reservoir under consideration.

of production will ultimately occur from these zones andthe higher quality zones often tend to be susceptible to thegreatest degree of invasive damage. For this reasonmuch of the effort associated with typical formationdamage and evaluation programs often tends to becentred around what is considered to be better qualityreservoir. If the formation is heterogeneous (ie. a highlyvugular carbonate, fractured system or laminated sands),then special care must be taken in order to obtain sampleswhich are considered to be representative. In general, inthis type of formation standard 3.81 cm diameter plugscannot adequately capture a sufficient volume of the poresystem in order to allow for an accurate mud evaluationtest. Specific details on the selection and mounting ofsamples of this type are contained later in the paper whenthe technology for more sophisticated formation damagetests is discussed.

Therefore, in recent years a considerable effort hasbeen expended in attempting to obtain core samples ofrepresentative character and quality and duplicatingoriginal reservoir conditions such as wettability, saturation,temperature, pressure, flow rates, drawdown pressuresetc. in order to allow scaling and application of laboratorydata back to field conditions which are as realistic aspossible.

For all types of formation damage testing it is essentialthat correct initial conditions of wettability and watersaturation be instituted into the samples prior to thecommencement of the testing. For oil reservoirs thisnormally consists of utilizing native or preservednative-state core or cleaned and extracted core which hasbeen visually examined to ensure that no drilling-induceddamage has occurred. The core is subsequentlysubjected to documented wettability restoration proceduresconsisting of reservoir condition equilibration with producedbrine and unoxidized reservoir crude oil for an extendedperiod of time. In some situations wettability restorationcan be abbreviated by conducting multiple contact anglemeasurements during the restoration procedure todetermine if an equilibrium wetting condition has beenestablished in a shorter time period than the usual 6 - 8weeks required for normal restoration.

Parameters Which Must Be Taken Into Consideration inObtaining Representative Core Samples For DrillingMud Evaluation

A number of parameters are important in consideringthe design of a representative drilling fluid analysisprogram. One of the key parameters that should be takeninto consideration in the original design is advanceplanning and allowing sufficient timing for an adequatedrilling fluid evaluation program to be conducted. In manysituations preserved core material, which is the media ofchoice, is not available for testing. This necessitates usingextracted core material and going through extensivecleaning and wettability restoration procedures in order toobtain core material suitable for testing. Although theseprocedures are very successful and well documented, theydo take time and, in general, approximately six to eightweeks is required for an oil reservoir to adequatelyprepare core samples for representative reservoir conditiontesting. Therefore, if formation damage testing iscontemplated to optimize a given drilling fluid system,planning should be considered well in advance in order toensure that representative results can be obtained.

For gas reservoir applications, particularly if aqueousphase trapping is to be evaluated, and a sub-irreduciblewater saturation reservoir is under consideration, thecorrect initial water saturation must be instituted in thesamples. Simple saturation of the samples with formationwater followed by high pressure centrifuging or dynamicdisplacement techniques usually results in samples thatare at the correct irreducible water saturation for the givencapillary geometry, but not necessarily the correct initialwater saturation. This often results in erroneously highwater saturations when desiccated or dehydratedreservoirs are under consideration. For this reason specialsaturation institution, x-ray and tomography proceduresmust often be utilized in order to make sure that asub-irreducible saturation has been correctly placed in thecore system and uniformly distributed prior to testing.

The next fact which must be considered is obtainingrepresentative samples to test in the laboratory. This canoften be a difficult procedure, particularly if a formation isextremely heterogeneous in nature. For morehomogeneous carbonate or sandstone formations, typicallyroutine core analysis is used as a guideline to evaluate therange of lithofacies, permeability and porosity which existsover the pay zone. If a single dominant lithofaciesevaluation is indicated from petrographic and log analysis,then plug samples approximately 3.81 cm in diameter aretypically selected from what is considered to be the betterquality pay of the reservoir. This is because the majority

Occasionally, drilling programs are designed wherebylow invasion coring techniques are utilized to minimizeinvasion of filtrates into the full diameter core. Althoughthis is often successful and provides for true native-statecore material, parameters such as reservoir quality (low

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permeability, low porosity versus high permeability, highporosity), flow velocity and resultant hydrostatic pressure,rate of penetration, improper technique etc. can render thecore in a non-preserved state with a saturation hysteresisthat could skew the results of formation damage tests.

are utilized consisting of a number of plugs ofpetrographically and petrophysically similar propertiesstacked together in order to obtain a uniform stack(perhaps 20 - 40 cm in length). The plugs are generallyprecisely machined into right cylinders and sandwichedtogether with capillary contact membranes to eliminate thepotential for capillary discontinuities between the individualplug samples.

Where risk of filtrate loss is higher, advance preparationfor coreflow tests should incorporate the possibility ofhaving to re-institute representative wettability andsaturation conditions, and initiating a complete laboratoryrestoration program.

Revised Dynamic Leakoff Procedures

To overcome many of the deficiencies associated withprevious formation damage test procedures, technologyhas been developed in recent years to conduct fullreservoir condition dynamic leakoff experiments toevaluate the action of whole drilling fluids on the formation.Figure 2 provides a schematic of a typical apparatus usedfor reservoir condition drilling fluid evaluations for a typicaloverbalanced drilling operation. The apparatus isdesigned so that reservoir stressed and restored state coresamples can be subjected to initial baseline flow witheither reservoir crude oil or reservoir gas to determineoriginal undamaged permeability measurements. Thewhole drilling fluid containing drill solids, granular bridgingagents, etc. can then be turbulently circulated at aspecified overbalance pressure through an annular spacein the core flow head (illustrated in Figure 3) and suchparameters as fluid leakoff, filter cake build up, physicaldepth of invasion of filtrate and solids can be subsequentlymeasured.

Evaluation of the magnitude of filtrate invasion can beconducted by doping mud systems with isotopes such astritium or deuterium which can be scoped for and detectedin concentric sections in the core. Not only does thisprovide an indication of the depth of filtrate penetration, italso allows for determination of Swj which can later be re-instituted in the core during restoration after it has beencleaned and extracted.

Due to the fact that fluid rheology, wettability, and anumber of enzymatic and chemical breaking agents arestrongly affected by temperature conditions, it is essentialthat laboratory tests conducted to evaluate drilling muds beconducted at full reservoir conditions of bottomholetemperature (or what is thought to be the maximumpossible circulating temperature which would beencountered in any given situation). Net confiningoverburden pressure is also essential to allow the rock tobe re-stressed to obtain the proper capillary geometry thatthe formation will exhibit in a downhole stressed condition.This is particularly true in unconsolidated formations orformations containing open fractures, as that application ofoverburden pressure can cause a substantial change inthe permeability, porosity, and geometric character ofthese types of pore systems. Reservoir fluids should alsobe utilized wherever possible, particularly for oil reservoirs,as the use of refined oils, white oils, or synthetic oils canresult in wettability alterations and non-representative testresults. For gas reservoir applications, depending uponthe type of test under consideration, either actual reservoircondition gas, methane gas, or in some cases humidifiednitrogen gas is utilized as a displacement medium. For allof these tests, due to the elevated temperature andpressure conditions of the coreflood operations, the gasmust be 100% saturated with water vapour to ensure thatdesiccation of the in-situ water saturation in the pore spacedoes not occur. Desiccation could affect the test resultsdue to relative permeability effects associated with areduction in the in-situ water saturation.

Figure 4 provides a schematic illustration of acomparative set of fluid leakoff curves illustrating differentmud performance under these types of dynamic leakoffconditions. Once the drilling fluid leakoff phase has beencompleted, regain permeability measurements areconducted, either at a specified maximum pressuredrawdown gradient, or in a threshold pressure regain testmode, which shall be discussed in more detail shortly, toascertain the minimum liftoff pressure for the filter cakeand obse/Ve the effect of drawdown on permeabilityimpairment. The apparatus can also be utilized ifsignificant damage occurs to evaluate potential completionor stimulation alternatives such as acid washes orsqueezes, solvent squeezes, oxidants, microbial agents,etc. These fluids will be applied in either a squeeze orwash mode at specified overbalance pressure or staticexposure pressure at reservoir conditions and then regainpermeability to oil or gas evaluated to ascertain if theyhave been effective in removing a portion of the induceddamage. Petrographic studies, such as scanning electronmicroscopy and longitudinal thin section work are alsouseful techniques on a post-test basis for a specificquantification of exact mechanisms of formation damage.

For some test types, such as acid displacement testsfor stimulation work, single core displacement tests usuallyare insufficient length as the depth of penetration requiredfor formation of fluorine-based precipitates, etc. usuallyrequires a longer core length than that encompassed in asingle core plug. In this situation composite core stacks

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Advanced Technologies for the Evaluation and Designof Drilling Programs in Specific Situations

fracture along a primary stress plane within the corematerial. A combination of FMI and FMS log analysisand fractured core studies (if available) are then utilizedto ascertain the maximum potential fracture apertureconsidered for design for the mud. These fractures arethen shimmed to the desired aperture (ranging from 0.5up to 5000 microns) and mounted in a special core cellwhere presence of the shims insures that the fractureswill not close or heal when confining overburdenpressure is applied to the core material. Leakoff testsare then conducted in a normal fashion to evaluate thefluid-loss characteristics into the fracture system and toattempt to design an appropriate bridging system whichwill result in rapid plugging of the fracture, but create afilter cake which can be readily mobilized by eitherreverse flow or very localized chemical or mechanicalstimulation treatment. A schematic of the fractured coreleakoff apparatus appears as Figure 6. Obtaining lowdamage bridging mud systems in highly macrofracturedsystems at high overbalance pressures may bechallenging and in situations of this type someconsideration should be given to evaluating the potentialfor low overbalance or underbalanced drillingoperations.

Heterogeneous Formations. Many carbonate formationscontain significant large vugular or solution enhancedporosity which makes it impossible to accurately capturea representative sample in a typical 3.81 cm diameterplug. For this reason a possible solution to this problemin the past has been to simply use full diameter coresamples and run a conventional leakoff test along thevertical axis of the core sample. This is not necessarilyrepresentative, as in many carbonate formations ~ - k"anisotropic vertical permeability ratios exist which resultin a relatively low vertical permeability which can skewthe results of the potential drilling fluid evaluation. Forthis reason a technology was developed to constructwhat is called the crossflow leakoff apparatus. Thecrossflow leakoff apparatus is illustrated as Figure No.5. In the crossflow leakoff apparatus the full diametercore sample to be tested is specially machined to faceoff diametrically opposing sides of the core sample.The resulting sample is then mounted in a specialconfining sleeve which allows the circulation across theentire machined face. Depending on the length of theSarT1)les to be selected, this generally providesanywhere from 20 to 40 times the exposed crosssectional area which would normally be encountered ina conventional 3.81 cm diameter plug. This techniqueallows a much greater degree of accuracy in theinclusion of macroscopic porosity features, such asinterconnected vugs, fractures and dissolution porosityand has proven to be an accurate method for thedesign and evaluation of drilling and completionpractices for these types of formations. The basic testprocedures, other than the original core mounting, arevery similar to that described for the previous test withsimilar options being available if damage has occurredwith respect to the evaluation of stimulation orcompletion fluids.

2. Fractured Formations. Fractured fomlations present aparticular challenge with respect to the design ofappropriate drilling fluids as granular bridging agentsizing criteria is difficult and it is highly dependent uponthe actual obtained fracture aperture. In somesituations, fractured core is actually available and if thisis the case, these core samples can be mounted ineither a full diameter fashion, or using small plugs if thefracture can be adequately contained within the sample.In many situations actual fractured core material iseither too poorly consolidated to be utilized forlaboratory testing, or not obtained in typical coringoperations. However, potential fluid loss characteristicsin mud design can be evaluated for fractured reservoirsusing artificially fractured core.

3. Underbalanced Drilling - Laboratory Evaluation Tests.

Underbalanced drilling has been touted recently as asolution to many problems associated with invasiveformation damage. Bennion(S) discusses potentialformation damage mechanisms associated withunderbalanced drilling operations. The two majorpotential damage mechanisms commonly associatedwith underbalanced operations are failure to maintainunderbalanced drilling conditions 100% of the timeduring the drilling and completion operation (which canresult in very rapid and significant invasion into the poresystem and a high resulting degree of invasive damage)or spontaneous countercurrent imbibition which canoccur when drilling with water based fluids in some lowwater saturation gas reservoir applications. For thisreason a new generation of laboratory tests to evaluatepotential damage mechanisms associated withunderbalanced drilling has been developed. Theexperimental apparatus commonly utilized to conductunderbalanced drilling operations appears as Figure 7.The underbalanced drilling apparatus is designed sothat a dynamic underbalance condition can bemaintained while flowing either gas or oil while thedrilling fluid of interest, be it either a hydrocarbon orwater-based system, can be turbulently circulatedacross the core face while continuOus permeabilitymeasurements are conducted. In the absence ofspontaneous imbibition effects, permeability impairmentassociated with underbalanced drilling operations isusually relatively negligible. If spontaneouscountercurrent imbibition effects are apparent,reductions in permeability can be observed during thedisplacement test sequence. ExarT1)les of these two

Cores are artificially fractured using a special hydraulicfracturing apparatus which creates a non-uniform

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phenomenon are contained in Tables 1 and 2 whichprovide a set of underbalanced drilling data conductedunder a variety of underbalance pressures ranging from4140 kPa to a balanced condition. One set of tests wasconducted using an oil-based fluid with the second setconducted using a water-based fluid. Countercurrentimbibition damage effects are clearly apparent in thewater based fluid test.

operation and the effective underbalance pressure islost. If significant risk potential for formation damageduring underbalanced drilling is apparent whereasrelatively minor damage is obtained from conventionaloverbalanced drilling operations, it may be in theoperator's best interest to consider a conventionaloverbalanced low risk drilling operation for a certainapplication than a potentially high risk underbalancedoperation in the same situation.

A typical procedure for an underbalanced leakoff test isto initiate the sample at the maximum underbalancecondition thought to be achievable in the field. in thiscase approximately 4140 kPa. Long term exposure(generally anywhere from 16 to 24 hours at eachunderbalance pressure level) is allowed to evaluate Ifany spontaneous countercurrent imbibition phenomenaare occurring (which would spontaneously Imbibe awater or oil saturation into the matrix against theprevailing underbalance pressure). After a stabilizedcondition has been obtained, the underbalance pressureis degraded to a lower level to observe if there is acrucial level at which spontaneous countercurrentimbibition effects become dominant and will start toincrease the potential for formation permeabilityimpairment. During most underbalanced drilling tests aworst case scenario is also evaluated after a number ofunderbalanced pressure phases have been evaluatedin which the sample Is abruptly exposed to a fullhydrostatic pressure overbalance pulse. This simulateswhat would occur if the well had to be killed in anemergency situation due to mechanical problems orsimply due to operational constraints such as bit trips.logging considerations, etc. The overbalanced pulse isfollowed with a regain permeability measurement tocontrast the apparent damage between theoverbalanced and the underbalanced drilling operation.Due to that fact that in most underbalanced operationsa sealing and stable filter cake is not established, inmany cases a significantly greater degree ofpermeability impairment may occur during anoverbalanced pulse with an underbalanced system, thanif a well designed conventional mud system which hada tendency to form a stable and bridging filter cake isused in an equivalent situation. This is highlighted withthe results from Tables 3 and 4 which providecomparative results in a different situation with a welldesigned overbalanced system containing a carbonatebridging agent in comparison to an underbalancedoperation in the same system being exposed to anoverbalanced pulse which results in significant damage.

Threshold Pressure Regain Permeability Tests

Invasive formation damage, particular1y whenassociated with the retention of high hydrocarbon oraqueous-based fluid saturations or the near wellboreentrainment of solid materials, is strongly related tocapillary pressure effects. Usually the higher the apparentdrawdown gradient which can be applied the greater theamount of damage which can be physically mobilized andproduced from the reservoir, resulting in higher productivityto oil or gas. This phenomena is illustrated in Figure 8.Unfortunately in many laboratory evaluations extremelyhigh pressure gradients are utilized to mobilize damagefrom core samples which results in erroneously optimisticresults for a variety of different fluid systems. Therefore,it is advantageous to couple the results of drilling fluidinvasion tests (or other types of tests to evaluatecompletion or stimulation fluids) to a regain permeabilityprocedure called the threshold regain permeability test. Inthreshold regain permeability tests, rather than abruptlyapplying a higher instantaneous pressure differential to asample, the differential pressure across the core sample isslowly increased to determine: 1) the initiation point atwhich flow of oil or gas first penetrates through thedamaged porous media, 2) permeability as a function ofincreasing drawdown pressure, 3) the final maximumpermeability expected to be obtained at the maximumdrawdown gradient which could be realistically applied inthe field given the specific reservoir pressure and invasioncharacteristics in the porous media.

It should also be emphasized that it is the drawdowngradient which is crucial in these evaluations, not theabsolute drawdown pressure. If fluid invasion is a matterof a few millimetres into the formation and reservoirpressure is 10 000 kPa, it can be seen that a very highinstantaneous pressure gradient could be applied in thereservoir across the damaged zone, likely resulting in themobilization of the majority of potential invasive damage.However, if significant fluid invasion occurs (say 100- 200cm into the formation) it can be seen that the same 10 000kPa reservoir pressure will be applied in a much moredispersed and distributed gradient in the porous media,and it may be difficult or perhaps impossible to eveninitially mobilize these fluids and obtain initial production ofoil or gas back at the well bore. For this reason in thelaboratory the threshold pressure regains are useful inquantifying what is both the observed expected penetration

The use of underbalanced drilling tests allows one toquantify the potential severity of such damagemechanisms as countercurrent spontaneous imbibitionand provide a quantitative risk analysis as to thepotential damage which could be incurred if problemsare encountered during the underbalanced drilling

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depth of filtrates and coupling this data back to ascertainwhat types of maximum drawdown gradient would have tobe applied in the field to overcome and mobilize thesefluids from the porous media. A detailed discussion of thistype of phenomena appears in a paper by Bennion(6).

Formation Damage Tests and Their Effects on CapillaryPressure and Relative Permeability /Wettability

Considerable interest has been expressed in recentyears in trying to develop numerical simulation models toquantify the effects of near wellbore penneabilityimpairment on productivity of both horizontal and verticalwells. In order to accurately allow these models tofunction, it is necessary to quantify specific changes inrelative permeability, capillary pressure and wettabllityassociated with the contact of damaging fluids with theporous media. Research is currently ongoing in this areaand the coupling of formation damage tests withsophisticated special core analysis tests to determinerelative permeability and capillary pressure characteristicsallows the formulation of multi-parameter models toincorporate such diverse effects as solids entrainment,wettability alterations, fluid retention, changes In capillarypressure and pore geometry to physically quantify andmodel formation damage depth and i"1>airment effects. Itis expected that interest in this area will continue to growin the next few years providing additional impetus for thespecialized type of laboratory work required in order toquantify the specific effects of formation damage onproperties such as wettability, capillary pressure andrelative permeability.

Pressure Tapped Cores

Although not a new technology, pressure tapped coreshave been utilized more extensively in recent years toevaluate physical depth of formation damage, particularlyassociated with the invasion and entrainment of solids oracidization and precipitation induced damage. Figure 9provides a schematic illustration of a typicalpressure-tapped core apparatus. The use of pressuretaps allows the operator to evaluate sectionalpermeabilities and thereby compare the originalpermeability determined in an undamaged situation to atransient permeability profile which may be changing as afunction of time due to the entrainment of aqueous fluids,solids, potentially damaging fluid-clay interactions, theformation of precipitates, etc. These tests are particularlyuseful for long term tests in quantifying speed and rapidityof propagation of formation damage.

Petrographic Evaluation

More recently, petrographic analyses (thin section (TS),scanning electron microscopy (SEM). petrographic imageanalysis (PIA) and x-ray dlffractometry (XAD)) havebecome useful in both designing coreflow studies anddiagnosing potential damage mechanisms on a post-testbasis. Pre-test knowledge of mineralogy. pore body andthroat geometry, grain morphology and presence ofdetritus within the matrix can be used to specify whichformation damage tests are of use. or those that will notprovide sufficient information without additional more costlytesting. For example, where a petrographic evaluationexposes the presence of high concentrations of swelling ormixed layer clays, a less rigorous sensitivity test canindicate significant reductions in permeability due toexposure to non-saline filtrates. and therefore test fluids(without fresh water-bases) can be selected accordingly.PIA is a very useful tool in physically measuring poregeometry. and from this the selection of sized bridgingagents involves less guesswork and is more accurate.

Conclusions

This paper has reviewed a number of differentmechanisms of potential fom1ation damage associated withthe drilling process. A variety of different types oflaboratory equipment and procedures have been describedto illustrate state-of-the-art laboratory techniques utilized toobtain representative results for drilling fluids and othertypes of near wellbore fom1ation impairment evaluations.The critical parameters of interest to be considered whendesigning and evaluating formation damage laboratoryprograms include:

1. Obtaining representative samples of sufficient size andcharacter to incorporate natural reservoir scaleheterogeneities.

2. Insuring that correct wettability and saturation conditionsare utilized along with correct conditions of temperature,confining pressure, and reservoir fluids being utilized toconduct permeability measurements.Where the cause of permeability impairment is believed

to be entrainment of mud solids and/or microflnes, post-test petrographic evaluation is valuable in examining thepresence of solids, and confirming depths of solidsinvasion. By comparing pre-test and post-test petrographicImages, a complete image of the mud leakoff processbecomes available.

3. Displacement tests should be conducted in a fashion toapproximate the leakoff process occuning in the field,rather than a direct injection or squeeze process whichcan lead to erroneous results.

4. Specific formation damage equipment and procedureshave been designed in more recent years to evaluatemore complex reservoir scenarios such asheterogeneous formations, highly fractured formations,

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and to evaluate the potential problems associated withunderbalanced drilling.

TABLE 1UNDERBALANCED MUD LEAKOFF

WITH CRUDE OIL MUD WITH MICROFINESPERMEABILITY SUMMARY5. Invasive foRnation damage is highly related to capillary

retention effects. Therefore threshold pressure-regainpermeability tests are recommended as an essentialadjunct to any conventional foRnation damage coreflowprogram in order to adequately evaluate invasive fluidpotential and couple this with both available reservoirdrawdown pressure and invasion depth characteristicsof the porous media.

Permeability(mD)

% Change InPermeability

Test PhBse

lritia/ Crude 01 (Ck.caon 11) 1.58 .0.00

01 Permeability 0 4140 kPaUnderbaJan<» Pressure

1.58 0.00

Oil Permeability 0 1380 kPaUrxterbaJance Pressure

-1.915Acknowledgements

011 Permeability @ 345 kPalkxjerbaIence Pressure

1.51 -4.4The authors wish to acknowledge and express/IIappreciation to Hycal Energy Research Laboratories Ltd.for the permission to conduct the research documented inthis paper and present this paper.

01 Penneabllity 0 BalancedCondtk)n8

1.48 -8.3

4140 kPa ~ P\aeReferences

Regain Permeability 0 3ekPa Drawdown1. Bennion, D.B. et al: "Fluid Design to Minimize Invasive

Damage in Horizontal Wells", Paper CIM 93-16,presented at CIM ATM, Calgary, Canada (May 1993).

1.36 -14

Regain Permeability 0 345kPaDrawmwn 1.47 -7.0

2. Beatty, T., Bennion, D.B., Hebner, B. and Hiscock, R.,"Drilling Fluid Displacement Tests Through Core Plugs:A Means of Minimizing Formation Damage in HorizontalWells", Presented at the CADE/CADDC Spring DrillingConference, April 14-16, 1993, Calgary, Alberta.

Regain Penneability 0 690kPa Drawdown 1.50 -5.1

Regain Perm~lIty 0 1380kPa Drawdown 1.53 -3.2

Regain Penneability 0 4140kPa Drawdown3. Jones, W. and Bennion, D.B.: "Minimizing Drilling

Induced Damage: Laboratory and Field Case Studiesin the Virginia Hills Belloy Sand", presented at theCIM/SPE Third Annual one day conference onhorizontal well technology, November 1994.

1.58 0.0

. Baselk1e

4. Bennion, D.B. and Thomas, F .B.: .Effective LaboratoryCoreflood Tests To Evaluate And Minimize FormationDamage In Horizontal Wells., Paper Presented at theThird International Conference On Horizontal WellTechnology, Houston, Texas (Nov. 12-14, 1990).

5. Bennion, D.B; Thomas, F .B.: "Underbalanced Drillingof Horizontal Wells - Does It Totally Eliminate FonnationDamage?" Paper SPE 27352 presented at the 1994SPE Fonnation Damage Symposium, Feb. 9-10, 1994,Lafayette, Louisiana.

6. Bennion, D.B. et al: -Water and Hydrocarbon PhaseTrapping in Porous Media: Diagnosis, Prevention andTreatment", paper CIM 95-69 to be presented at theMay 1995 Annual Technical Meeting of the PetroleumSociety of CIM, Banff, Alberta.

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TABLE 2UNDERBALANCED MUD LEAKOFF

Wmt WATER-BASED MUD WITH MICROFINESPERMEABILITY SUMMARY

TABLE 3UNDERBALANCED MUD LEAKOFF

WITH WATER BASED MUD WITH MICROFINESPLUS EXPOSURE TO OVERBALANCED PRESSURE

PERMEABILITY SUMMARY

Permeability(mO)

% Change InPermeability

Test PhuePermeability

(mD)% Change InPenneability

TeatPhaM

IrVtial Crude 01 (Direction 11) 1.71 .0.00

IrVdaI Cn,Kje al (Direction 11) 1.72 -0.00

01 Permea~11ty 0 4140 kPaUI¥i8rbaIance Pressure

1,," 0.00UnderbaJarx:ed Mud Leakoff(Dlrectioo 12)

Oil Permeability 0 1380 kP£~erbaIarX:e ~~re

1.~ -21

Regain Petme8bHity To Crude01 (Directk>n 11)

0.001.68

011 Penneablity 0 345 kPaUOOelbaiance Pressure

0.83 -51

Overbalanced Mud LeakoffPulse (Direclloo 12)

01 PermeatXllty 0 BalancedCa1dOOns

0.83 -63Regain Penneabllity To CNdeOM (Direction 11)

0.91 -45.8

4140 kPa 0v8beI81C8 P\Me . BaseI~Regain Permeability 0 35 kPaDf8wdown 0.00 100 TABLE 4

OVERBALANCED LEAKOFF TESTWATER BASED POLYMER MUD + BRIDGING AGENTRegain Permeability 0 345

kPa Drawdown 0.55 -68

Permeability(mD)

% Change InPermeability

Regain Penneability 0 690kPaDrawdown

Teat Phase0.95 -44

1.51 0.0&I Initial Cnae (Dir8dQ\ 11)Regain Permeability 0 1380kPa Drawdown 1.22 .28

I OvelbaiancedLeakcAf

(Di~ 12)Regain Perm~11ty 0 4140kPaDrawdown .181.34

I FI,.I Regain Penneabllitym 01 (DI~ 1)

-2.8%1.54. BaselN

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