EFFECTIVE LABORATORYCORE FLOOD TESTS TO EVALUATE

AND MINIMIZE FORMATIONDAMAGE IN HORIZONTAL WELLS

By

D. Brant Bennion, Hycal Energy Research laboratories Ltd.F. Brent Thomas, Hycal Energy Research Laboratories Ltd.

Douglas W. Bennion, Hycal Energy Research laboratories Ltd.

Prepared for presentation at the Third International Conference on Horizontal WellTechnology, November 12-14,1991, Houston, Texas.

IntroductionAbstract

Formation damage is defined as any type of a processwhich results in a reduction of the flow capacity of an oil,water or gas bearing formation. Formation damage haslong been recognized as a source of serious productivityreductions in many oil and gas reservoirs and as a causeof water injectivity problems in many waterflood projects.This paper provides a brief overview of many of theprocesses which can cause formation damage anddiscusses laboratory techniques which can be used toevaluate potential formation damage problems before theyoccur in the reservoir and result in substantial damageand/or costly stimulation or workover treatments.

Formation damage causes substantial reductions in oiland gas productivity in many reservoirs. Due to themechanics of flow into horizontal wells and the fact thatmost horizontal wells remain as open hole completions,damage effects can be much more severe in horizontalwells than in equivalent vertical wells. Damage can becaused by mechanical effects (fines mobilization, solidsinvasion, emulsion formation, water blocking), chemicaleffects (clay swelling, clay deflocculation, solids and waxprecipitation, insoluble precipitates, acid sludges, chemicaladsorption, wettability alterations), the action of bacteria orextreme temperatures associated with thermal recoveryprocesses. Stimulation procedures required to removeformation damage in horizontal wells are costly and areoften unsuccessful or marginally successful. The use ofwell designed laboratory programs can allow thoseassociated with designing and conducting drilling,completion or stimulation programs to evaluate theeffectiveness of specific programs, prior to theirimplementation in the field. This paper provides a briefdiscussion of the mechanisms of formation damage, andthen provides details on recent advances in laboratorytesting and technology which allow almost any type ofdrilling, completion, workover, or stimulation program to becritically evaluated. The use of these techniques canreduce completion costs and greatly increase ultimaterecovery and productivity of horizontal wells in many oil orgas reservoirs.

Causes Of Formation Damage

Formation damage can potentially occur any-time non-equilibrium or solid bearing fluids enter a reservoir, or whenequilibria fluids are displaced at extreme velocities. Thus,most processes used to drill, complete or stimulatereservoirs have the potential to cause formation damage.Some of these processes might include:

1. Drilling2. Cementing3. Completions/Stimulation

a) Perforatingb) Acidizingc) Fracturing

1

a vertical well drilling fluid may only be in the pay zonea matter of hours while in a horizontal well the time maybe measured in weeks.

2. Most horizontal wells are not cased and perforated andremain as open hole completions. Relatively shallowlyinvaded damage which would be easily perforatedthrough on a standard vertical well, remains a majorsource of permeability reduction in many horizontal wells.

4. Workoversa} Kill fluidsb} Hot oil treatments

5. Waterflooding or water disposal6. Enhanced oil recovery processes

a} Miscible floodingb} Chemical floodingc} Thermal flooding {in-situ

co mbustion/steamflood i ng}7. Excessive injection or production rates

3. High drawdowns are difficult to obtain on horizontal wellsdue to the length of the well in the pay zone. Thismakes it much more difficult to clean up damage due toinvaded fluid and/or solids.

Whv Prevent Formation Damage?

The philosophy varies with respect to formation damage.Many are of the opinion that cheaper, easier to use drillingand completion programs should be utilized, as wells canalways be fractured or stimulated after the damage hasoccurred to increase productivity.

4. Stimulation of horizontal wells is extremely difficult andexpensive. Thus once formation damage occurs, it isusually permanent in nature and effect.

1. Reducing Formation Damage generally lowersultimate completion costs. If the extra cost of fracture,acidizing and other, often unsuccessful, stimulationprograms can be avoided, substantial savings arerealized. Often the cost of the design andimplementation of a more effective drilling andcompletion program is more than offset by savingsrealized by the greater productivity and lack of additionalstimulation work required to obtain an effective well.Also, once an effective program is designed, it cangenerally be applied to additional wells in the samereservoir without any extra design costs.

Well ProductivitY

The productivity equations which govern flow intohorizontal vs vertical wells are substantially different.

If certain simplifying assumptions are made, equationsfor calculating the production of a horizontal well can bemade. Joshi (1987), Ertekin et al (1988), Giger (1987),Joshi (1988), and Babu et al (1989) have all discussedhorizontal well productivity calculations.

The discussion of well productivity in this paper is takenfrom Joshi (1988).

2. Preserve Barriers. The success of many secondary andtertiary recovery process depends upon maintaining theintegrity of permeability barriers in the formation,especially when adjacent zones of widely contrastingpermeability are present. Large volumes ofhydrocarbons have been lost in waterfloods, misciblefloods and chemical floods in reservoirs where injectionor production wells have been fractured into highpermeability zones.

A vertical well generally drains volume in the shape of aregular cylinder while in a horizontal well of length L thedrainage volume is shaped like an elliptic cylinder due tothe variation in vertical vs horizontal permeability. In bothcases a reservoir of thickness h is being drained. To solvefor the rpessure distribution in both horizontal and verticalwells at steady-state conditions, the equation

:1)v2P=O3. Improved Sweep Efficiency. Sweep efficiency is

generally much higher in wells which have not beensubjected to fracture treatments due to much betterconformance of the injected or produced fluids.

must be solved. This will give the pressure distributionwhich can then be used in Darcy's law to calculate flowrates.

2nk,/l AP

. (PoBo)

1!:-.Eill1 + IJ!.Jk1 [ ~h) ]+. \M L1 ~+1)r.

ComDarison Of Formation DamaGe In Horizontal VersusVertical Wells

qN&

Horizontal wells are much more susceptible to damagethan their vertical counterparts due to a number of reasons,these being:

L2

(2)

Substantially longer contact time with the drilling fluid. In

2.

Mechanisms Of Formation Damaae

.-{t ).[~ + 11. +~J(0.5 Lf , slit.

(3)

,88 ~~~

(4)

Where:

~o = Formation Volume Factorh = Reservoir Thicknessk = PermeabilityL = Horizontal Well LengthAP = Pressure DropqH = Flow ratereH = Drainage Radiusrw = Well Bore Radius~ = ViscosityH = HorizontalV = Vertical

The well productivity depends on reservoir pay,horizontal well length and reservoir anisotropy. Theequation for steady-state flow with a vertical well is:

Formation damage falls into four broad categories basedupon the mechanism of it's origin, these being:

1. Mechanically Induced Formation Damagei) Fines migrationii) Solids entrainmentiii) Relative permeability (trapping) effects

2. Chemically Induced Formation Damagei) Clay swellingii) Clay deflocculationiii) Wax depositioniv) Solids precipitation (asphaltenes, sulphur,

diamondoids, hydrates, etc.)v) Incompatible precipitates and scalesvi) Acid sludgesvii) Stable emulsionsviii) Chemical adsorptionix) Wettability alteration

3. Biologically Induced Formation Damagei) Bacterial growthii) Bacterial slimesiii) Corrosion products due to H2S from sulphate reducing

bacteria (SRB's)

4. Thermally Induced Formation Damagei) Mineral transformationsii) Rock solubility and dissolution phenomenaiii) Wettability alterations

It is not possible to discuss all these phenomena indetail, although a brief description of some of the majormechanisms follow to allow a basic understanding of thetests, which will be discussed later, which are utilized toalleviate or diagnose specific formation damage problems.

(5)

Mechanlcallv Induced Damage

It has been long accepted that severe permeabilityimpairment can occur when fluid velocities become largeenough to physically shear interstitially bound particulatesloose and move them to bridging/blocking locations at porethroats. Gray and Rex (1966), Mungan (1965), Muecke(1979), Gabriel (1983), Gruesbeck (1982), Krueger (1986),Selby (1989) and Porter (1989) all provide more detaileddescriptions on the problems associated with finesmobilization.

To compare the effect of equivalent skin damage forhorizontal and vertical wells the following data was inputinto Equations 1 and 5.

ky = 10 mD~ = 100 mDL = 50ftr. = 1000ftrw = 0.3 ft130 = 1.25110 = 0.84P = 1000 psi

Figure 1 provides an illustration of the relative productionrates from horizontal vs vertical wells using theseassumptions. For an equivalent skin factor it can be seenthat formation damage causes more reduction inproductivity in a horizontal well than in a vertical well. Asthe severity of damage increases, the actual productivity ofthe horizontal well approaches that of the vertical well.

The injection of fluids containing solids (i.e. unfilteredinjection waters or corrosion products from degeneratingtubing strings or surface equipment) can also cause gradualplugging and loss of permeability. Barkman (1972) andPatton (1988) discuss this phenomena in greater detail.

Deleterious relative permeability effects can also oftenhave a severely reducing effect on effective permeability,

3

particularly in low penneability reservoirs. An example ofthis is illustrated in Figure 2. The reservoir (gas in thisexample) is initially at saturation Sw,. The near wellboreregion is then invaded by an aqueous based drilling fluid,resulting in a much high irreducible water saturation Sw,(due to capillary trapping phenomena) near the well bore.It can be seen that effective permeability to gas has beenreduced substantially due to the increased trapping of theinvaded aqueous phase.

Bacterial Growth

Entrainment of bacteria in injected fluid streams can bea source of severe formation damage and operationproblems. Bacterial formation damage can occur both withand without oxygen present (aerobic and anaerobic) and aparticular type of bacterial family, sulphate reducingbacteria, have been responsible for the souring of manypreviously sweet gas reservoirs. Hydrogen sulphide gascan create severe problems with corrosion, as well as itsextreme toxicity to living organisms (humans included). Thein-situ secretion of bacterial slimes by many types ofbacteria can be a cause of substantial permeabilityimpairment, so much so that various companies haveinvestigated the use of certain types of bacteria to plug highpermeability thief zones In certain wells.

Chemically Induced Damage

The phenomena of clay swelling, defined as the directsubstitution of water into hydratable clays such as smectiteis the .classic. type of formation damage which mostindividuals are commonly aware of. Discussion on thestructure and mechanism of swelling clays is presented byWang (1988). Expansion of swelling clays upon hydrationcan often cause severe reductions in formationpermeability.

Thennallv Induced Formation Damaae

This type of damage occurs almost exclusively attemperatures exceeding 150°C in hot water, steamflood orin-situ combustion projects and has been documented byauthors such as Bennion (1992), McCorriston (1981).Amaefule (1984). Waldorf (1965) and Hebner (1985). Themajor sources of damage can be attributed to thetemperature Induced transformation of inert clays such askaolinite into swelling smectitic clay, the physical dissolutionof portions of the rock matrix and release of encapsulatedfines due to high temperature solubility effects andwettability changes associated with steamflooding.

A much more prevalent, but less widely understood,cause of formation damage Is deflocculation. Deflocculationoccurs when the delicate ionic charge balance thatelectrostatically binds clays and particulates together and topore walls is disrupted resulting in migration and blockageof the clays, even though they may not classically bethought of as "swelling" clays. This phenomenon commonlyoccurs when a system is subjected to a salinity reduction or"shock" as illustrated in Figure 3. Mungan (1965) illustratesthis phenomenon in greater detail.

Solids and wax precipitation is often a problem inproduction wells, particularly in miscible flood projects,Thomas (1991, 1991) and Fischer (1973) discuss thesephenomena in greater detail. Other solids in the form ofinsoluble precipitates and scales can occur due to chemicalincompatibility between formation and injected fluids. Thesewould include insoluble precipitates such as barium orcalcium sulphate which can often cause severe long termpermeability impairment in injection and production wells.Many acids can also chemically precipitate insoluble acid"sludges" which can cause blocking and plugging of thepore system. Acids, and other aqueous fluids, can alsocause the formation of extremely high viscosity 011 externalemulsions which can become entrapped in the nearwellbore region and form a viscous and Immobile "EmulsionBlock",

Why Laboratory Testlna

The drilling of horizontal wells in oil or gas formations isan expensive proposition for any operator. Logically, anyprocess which will provide a reasonable chance forimproving the productivity or reducing the total cost of anyhorizontal well is economically viable and should beconsidered. Recent advances in laboratory testingprocedures allow for the in-depth simulation and evaluationof almost any type of drilling, completion or stimulationprogram considered for use in a horizontal well. Thisallows for considerable screening and optimization to beconducted, prior to implementing an expensive andpotentially unsuccessful program in the reservoir.

Mechanically Induced Formation DamageThe injection of various types of chemical additives

(surfactants, scavengers, inhibitors, polymers, stabilizers,etc.) can result in both wettability changes, which can alterpermeability, and also in physical adsorption which canpermanently impair permeability.

A combination of core displacement studies and particlesize distribution analyses are the major types of testsbeneficial in this area. Figure 4 illustrates the type ofequipment used for this type of study. The core sample isencased in teflon shrink tubing and placed in a heavy leador viton core sleeve. The shrink tubing is used to ensurethat no fluid slippage occurs between the sleeve and the

4

core and prevents direct fluid contact with the sleeve. Theductility of the sleeve allows a confining overburdenpressure to be transferred to the core to simulate reservoirpressure. The core, mounted within the sleeve is placedInside a 316 SS core holder which is capable of simulatingreservoir pressures of up to 68.9 MPa (10,000 psi). Thispressure is applied by filling the annular space between thelead sleeve and the core holder with light oil and thencompressing the oil with an hydraulic pump to obtain thedesired overburden pressure.

rates. Figure 5 provides a plot of this type of a flow phase.Figure 6 provides an illustration of a plot of Interstitialvelocity vs percent reduction in permeability. Mostreservoirs will demonstrate a critical velocity at which finesmigration occurs. Permeability may either increase or bereduced by fines mobilization, depending on the size andquantity of the migrated fines and the pore throat sizedistribution existing in the reservoir.

Since fines migrate only in the phase which wets them,the use of representative native-state or restored-state coresa~les is essential in these types of tests. Scaling of thelinear velocity data in the cylindrical coreplugs back to themore complex velocity pattern around a perforatedcompletion a typical vertical well can be facilitated by theuse of a near perforation numerical simulation model asdescribed by Eng (1991). The simulation in a typicalhorizontal well open hole completion can be accomplishedusing a less complex radial flow model.

The core holder ends each contain two ports. One ofthese ports is for fluid feed or production and the second isfor pressure measurement. The portions of the core holderdirectly adjacent to the injection and production ends of thecore are equipped with radial distribution plates to ensureevenly distributed fluid flow into and out of the corespecimen and eliminate areas of localized high velocity.

Pressure differential is monitored using a pressuretransducer. The transducer is mounted directly across thecore and measures the pressure differential between theinjection and production ends. The pressure transducerrange depends on the permeability of the sample beingevaluated. The signal from the pressure transducer isdirectly connected to a strip chart recorder which providesa continuous pressure profile of the test. A digital readoutalso appears on a multi-channel terminal from which thetest operator takes readings as a backup.

ii) Solids Entrainment

Equipment to evaluate solids entrainment is identical tothat described for fines mobilization tests, with the exceptionthat the in-line filtration system is removed to allow thedirect injection of the proposed injection fluid, complete withIts load of suspended solids. directly into the core sample.

Several hundred pore volumes of proposed injection fluidcan be dynamically injected into the core material andpermeability continuously monitored to note the gradualeffect of solids entrainment on the system. Various sizes ofin-line filtration can also be tested (i.e. 10 micron vs 5micron vs 1 micron, etc.) to determine the critical filtrationlevel required for long term sustained injectivity. Rgure 7provides a plot of the permeability profile from a criticalfiltration level study illustrating, for this test, a criticalfiltration limit of 2 microns.

A positive displacement pump is used to inject fluids intothe core. The pump is capable of injecting at rates from 1cm3/hr to 8,240 crn3/hr at pressures up to 68.9 MPa with anaccuracy of % 0.01 cm3. The pump is filled with distilledwater which displaces varsol. This varsol then displacesthe brine to be used in the test into the core. Thisarrangement is used to avoid placing corrosive brinesolutions directly into the pump. Positive displacementpumps such as this provide a very smooth displacing actionwhich eliminates pressure shocks to the core material. The coupling of laser refraction detennined suspended

particle size analysis with pore size distribution data canalso be an infonnative screening method for critical filtrationlimits. In general particulates must be less in size than 'Iato '/4 the diameter of the average pore throat not to causelong tenn bridging effects.

The entire system is contained in a temperaturecontrolled oven which duplicates precise reservoirconditions of temperature and eliminates complication ofdata analysis due to fluctuations in the external ani>ienttemperature. The use of the correct reservoir temperaturealso ensures that the correct fluid viscosities. which willoccur in the reservoir. are properly simulated.

iii) Relative Permeability Effects

Figure 8 provides a schematic of a typical reservoircondition relative permeability apparatus. The equipmentis very similar to the fines migration apparatus detailedpreviously (Figure 4) with the exception of the use of abackpressure regulator to allow reservoir pore pressure tobe maintained to facilitate the use of live gas chargedreservoir fluids. Bennion (1991) discusses recent advancesin techniques used for the determination of relativepermeability data. Information on phase blocking effects

i) Fines Migration Tests

The purpose of a fines mobilization test is to detenninethe critical interstitial velocity at which fines migration beginsto occur. This is expedited by displacing a non-damagingequilibrium brine through the core sample at geometricallyincreasing flow rates. Injection rate is reduced to thebaseline level after each elevated rate level to eliminateeffects of non-Darcy flow due to turbulence at elevated flow

5

can be obtained by analysis of the relative permeabilitycurves on a combined drainage-imbibition test. This wouldinclude:

asphaltic oils (Thomas, 1991). Detailed PVT experimentscan also be undertaken to determine critical concentration,pressure and temperature levels to obviate elementalsulphur, diamondoid or hydrate formation. Detailed studiesare specific to the type of system being studied, but oftenoperating conditions of temperature and pressure inproduction or injection systems can be optimized to reduceor in some cases eliminate phenomena associated withthese types of solids deposition.

a) Water trapping in a gas reservoir (waterfloodsequence from Sw, followed by a gasflood to Swr)

b) Water trapping in an oil wet reservoir (waterfloodsequence from Sw, followed by an oilflood to Sw,)

Many problems with solids precipitation occur in theproduction systems and surface facilities, rather thanactually in the formation, due primarily to the sensitivity ofsolids precipitation phenomena to lower temperatures andpressures. If in-situ problems in the reservoir areanticipated, detailed coreflow experiments which willduplicate the dynamic mixing of the fluids within thereservoir porous medium at full reservoir operatingconditions should be undertaken to quantify if permeabilityreductions will occur.

Chemical Iv Induced Formation Damaae

i & II) Clay Swelling and Clay Deflocculation

The coreflow equipment used for these types of tests isillustrated in Figure 9. The equipment is very similar to thatdescribed for the fines migration test with the exception thatthe inlet fluid manifold consists of multiple storage cylinderscontaining the different test brines to be evaluated. Thesefluids are in pressure equilibrium allowing for fluid changesto be conducted while under dynamic flow withoutdisturbing the system pressure equilibria.

v) Incompatible Precipitates and Scales

Incompatible solid precipitates and scales generally occurwhen foreign fluids (generally brines) are contacted withone another. Basic turbidity (bottle tests) are a goodpreliminary indicator of fluid incompatibility. Detailedcompatibility studies, complete with the calculation ofscaling coefficients, should be undertaken for any largescale water injection scheme. Fluids rich in divalent ionssuch as calcium, magnesium, barium and strontium oftentend to be the worst offenders in this area, even thoughtheir high divalent ion concentration may make themdesirable for inhibiting formation damage from a clayswelling or deflocculation viewpoint.

Both clay swelling and clay deflocculation tests areconducted by Initially establishing a baseline permeability toa non-damaging reference fluid, generally clean formationbrine, followed by displacement of the test fluid(s) and adynamic measurement of the resulting change inpermeability. Figures 10 and 11 illustrate typical results fortests for clay swelling and clay deflocculation respectively.Clay swelling is a mass transfer limited process and henceis more gradual than clay deflocculation which representsan abrupt rupture of electrostatic bonds. Thus tests whichexhibit clay swelling problems are generally characterizedby gradual reductions in permeability with time (Figure 10)in comparison to the case of clay deflocculation which isusually very abrupt and almost instantaneous (Figure 11).

Long te"" coreflow tests conducted using a co-injectionapparatus, such as illustrated in Figure 12, can quantify theeffects of long te"" exposure of the fo""ation toprecipitates. In this apparatus equal volumes of both theequilibrium fo""ation brine and the injection water aresimultaneously displaced through the core sample. The twobrines mingle directly at the sample face, allowing in-situprecipitate fo""ation. Co-injection can continue for anextended period of time (generally several hundred porevolumes) to note the long te"" effect of the precipitatedeposition on pe""eabllity.

iii) Wax Deposition.

Problems with wax deposition are commonly diagnosedon a preliminary basis by conducting a pour pointdetermination on the system. This provides a measurementof the temperature at which solid wax deposition begins tooccur. Operational strategies to keep the producingtemperature elevated or the use of chemical suppressionmethods to lower the pour point temperature can then beconsidered. vi) Acid Sludges

Solids Precipitation Many acid blends can cause the formation of insolublesludges. The formation of the sludge is dependant on thetype of oil, acid. acid concentration, iron content and otherfactors. Initial screening tests are generally conducted atbench conditions to note the effect of such phenomena onthe formation of sludges and/or emulsions. Tests for totalrock solubility in the acid are also vital as partial solubilitymay cause the large scale release of acid insoluble fines

Iv)

Depending on the type of system under consideration,tests to quantify and reduce solids precipitation vary widely.High pressure titrative and PVT techniques are useful fordetermining critical solvent concentration limits andcompositional li~ for incipient asphaltene precipitationdue to contact by miscible flood solvents or from naturally

6

Ix) Wettability Alterationwhich can migrate, plug and cause permeability impairment

Once a suitable acid blend has been formulated basedupon the results of the initial screening test it blend shouldbe evaluated on a core sample using a flow test. Simpletests would follow the pattern of the basic fluid sensitivitytest, with the acid substituted in place of the test brine.More complex tests to evaluate the actual effectiveness ofacid in the removal of formation damage are discussed laterin the paper in the 8Fluid Leakoff8 section.

Wettability alterations (from a water to oil wet state) cansubstantially reduce the permeability to 011, and substantiallyincrease the permeability to water, effectively lowering 011productivity. Since a large majority of chemical additives,particularly many surfactants and corrosion inhibitors, tendto cause shifts towards oil wetness, a good understandingof how these chemicals may alter productivity is essential.

Wettability can initially be screened on restored-state ornative-state core using simple methods such as contactangle determinations, or more sophisticated methods suchas an imbibition or combined Arnott/USBM wettability study.Oil-water relative permeability measurements can also oftenprovide a good estimate of initial wettability (Craig, 1971).The test samples can then be exposed to the test additivesand wettability re-evaluated to determine the effect of theproposed chemical additives. Figure 13 provides anillustration of this type of phenomena for a transition from awater wet to an oil wet system using the contact anglemethod. Figure 14 illustrates a similar phenomena for atest using comparative relative permeability curves. Therelative permeability evaluation also provides an indicationof how radically the flow characteristics of the system canbe altered by a shift in wettability.

Since CO2 gas is generally liberated during an acidreaction test with a core sample. it is recommended thatthese types of tests be conducted under full reservoirbackpressure. This will solubilize the produced CO2 gas inthe flowing aqueous stream and eliminate the formation ofa trapped residual gas saturation in the core material whichcould artificially reduce the effective fluid permeability dueto deleterious relative permeability effects.

vII) Stable Emulsions

The fo""ation of stable emulsions can cause up totenfold increases in fluid viscosity. This is a particularlyprevalent problem in low gravity crude oil reservoirs «25GAPI), but also can occur in medium gravity and waxy highgravity crude oil systems. The propensity for the formationof stable emulsions at both bench and reservoir conditionscan be dete""ined by dynamic mixing studies in thelaboratory. The use of various surfactants to break stableemulsions can also be investigated easily and inexpensivelyin a similar fashion. Dynamic coreflow tests, coupled withScanning Electron Microscope (SEM) work and precisepermeability measurements can ascertain whether the in-situ formation of emulsions within a given porous mediumwill have a reducing effect on permeability.

Leakoff Tests

Normal drilling, completion or stimulation practicesgenerally will involve a combination of damagemechanisms. For example, during drilling damage couldoccur due to a combination of solids entrainment, chemicaladsorption, relative permeability and clay swelling ordeflocculatlon effects induced by filtrate invasion. Figure 15provides an illustration of the fluid leakoff apparatus whichcan be utilized to simulate virtually any type of drilling,completion or stimulation operation at any overbalanced (orunderbalanced) pressure condition at full reservoir operatingconditions for a horizontal well.

viii) Chemical Adsorption

Many compounds. particulary polymers and polaradditives, can be physically adsorbed or the rock surface.Additive retention generally has a reducing effect onpermeability, particularly if the adsorbed compounds consistof large molecules such as long chain polymers.

Depending on reservoir heterogeneity either plug (3.81cm 00) or full diameter (up to 10.16 cm 00) core samplescan be utilized. Restored-state or native-state core isdesirable to preserve wettability as fluid leakoff rates can besignificantly Influenced by formation wettability. The systemis applicable to oil or gas reservoirs and is designed with atwin backpressure regulation system which allows any typeof overbalanced or underbalanced operating condition.

Simple coreflow tests consisting of baseline brine or oilpermeabilities, followed by exposure to a specified numberof pore volumes of test fluid (in the reverse direction),followed by a regain permeability to the initial oil or brinecan quantify the degree of damage associated with the useof a certain additive. Once damage has occurred the effectof various stimulation treatments (such as additives,oxidizing agents, enzymes, etc.) can be evaluated.

A normal test is conducted by determining an initialbaseline reference permeability to oil or gas at the initialwater saturation in the reverse flow direction at full reservoirconditions of temperature and pressure. This provides theinitial "undamaged" reference permeability. The leakoff testis conducted by circulating whole drilling mud (or frac fluid,acid, etc.) across the injection face of the core through a

'7

specially designed core head. The injection fluid iscontained in a temperature controlled piston which is undercontinuous agitation which facilitates the circulation of ahomogeneous fluid system, even when the test fluid maycontain suspended particulate bridging or fluid loss agents.Overbalance pressure can be precisely regulated by settingthe backpressure regulation system at the injection face ofthe core (which is being subjected to the circulating fluidflow) at the desired bottomhole pressure. Backpressure atthe production side of the core is set at the reservoirpressure value, thus duplicating the net overbalancepressure forcing fluid to leak off into the reservoir.

formation damage is occurring and also to facilitate testingsamples for compositional and bacterial analysis at differentlocations down the length of the sample. These tests aregenerally long term, low rate exposure runs (30 - 90 daysin length) with continual analysis of the sectionalpermeability as well as regular detailed analysis of theinfluent and effluent liquid streams for the presence ofbacterial agent products (pH changes, sulphide content,H2S content, etc.). Post test sectioning of these samples ina microbiological lab indicates how the bacteria propagates(i.e. whether is remains at the injection face or invades intothe formation) and how the bacterial colonies grow andblock the formation.

During the leakoff phase the dynamic leakoff rate as afunction of time can be determined, as well as the totaldepth of filtrate invasion and time to fluid seal off (if a fluidseatoff does in fact occur). Figure 16 provides examples ifsome typical profiles from a mud leakoff experiment on agiven rock type.

Thermally Induced Formation Damaae

Figure 19 provides a schematic of the apparatus used toconduct high temperature sensitivity studies. Specialcoreholders and alloy sleeves are utilized in these testswhich can facilitate running experiments at temperatures upto 340°C for hot water/ steamflood tests and up to 1,2000Cfor in-situ combustion runs.

Once the leakoff has been completed, the permeabilityto oil or gas is redetermined in the reverse flow direction tosimulate production back out of the reservoir after thetreatment. Figure 17 provides some sa~le plots of typicalregain permeability profiles. In this manner the amount oftotal formation damage associated with the use of a specificmud system can be determined.

Pe""eability reductions at elevated temperatures canoccur due to a combination of mineral transfo""ation,dissolution and wettability effects as discussed previously.Coreflood experiments at high temperatures at reservoirconditions using preserved or restored state core, reservoirfluids, reservoir injection rates and steam are the onlyaccurate methods of predicting a reservoir's potential forthe ""ally induced damage. Many high penneabilityreservoirs may produce reasonably well on primaryproduction, but perlo"" poorly under the""al stimulationdue to a combination of the above phenomena. Prior to theextensive capital investment for a the""al recovery projectit Is therefore essential that sensitivity testing In this area beconducted. Well designed tests of this type can also yieldvaluable additional info""ation with respect to residual oilsaturations and oil and water relative pe""eabilities as afunction of temperature. Figure 20 illustrates the effect oftemperature on water pe""eability for a high penneabilityconsolidated sandstone fo""ation.

This type of test is extremely useful for co~rativeevaluation of different drilling mud systems in that it allows:

a) Direct evaluation in field units of expected fluid loss

b) Evaluation of effectiveness of fluid loss agents

c) Determination of depth of filtrate invasion

d) Degree of permanent permeability impairment causedby mud invasion

Although specifically well suited to drilling fluids, theleakoff apparatus and test as described is applicable to anytype of invasive whole fluid system. This would includegelled fluids, CO2 charged fluids, etc. Also once formationdamage has occurred due to mud or another fluid invasion,acid leakoff or squeeze tests or other stimulation treatmentscan also be duplicated using this same type of apparatus toevaluate the effectiveness of specific stimulation programsin damage removal.

Conclusions

Formation damage is a significant problem that has thepotential for reducing productivity in horizontal wells in oiland gas reservoirs during almost any type of drilling,completion or stimulation operation. Through the use ofhigh technology laboratory studies, the effects and benefitsor disadvantages of various proposed drilling, completion orstimulation programs can be examined and weighed in thelaboratory, prior to the expense and risk of implementingthem in the reservoir. The careful use of well designedlaboratory programs can thus reduce costs and increaseproductivity in many oil and gas reservoirs.

Biologically Induced Formation Damaae

Rgure 18 provides a schematic of the apparatus whichcan be used to evaluate formation damage due to bacterialaction. This apparatus operates at reservoir conditions anduses rigorous sterilized lines and equipment to generaterepresentative growth profiles. The test core sample isgenerally pressure tapped in one or more locations todetermine the specific location in the sample where the

8

Fischer, P.W., Ellis, M.M. and Bond, L.L.: "New WaxInhibitor Shows Promise" Oil and Gas J. (May 28,

1973) 62-64.

10.Acknowledaements

The authors would like to express appreciation to HycalEnergy Research Laboratories Ltd. for the development ofthe technology described in this paper and for permissionto publish this data.

Gabriel, G.A. and Inamdar, G.R.: "An ExperimentalInvestigation of Fines Migration in Porous Media.,paper SPE 12168 presented at the 1983 SPE AnnualTechnical Conference and Exhibition, San Francisco,Oct. 5-8.

11

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2.Gray, D.H. and Rex, R.W.: "Formation Damage inSandstones Caused by Clay Dispersion andMigration", Clay and Clay Min., 26, 1966.

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Barkman, J.H. and Davidson, D.H.: "MeasuringWater Quality and Predicting Well Impairment", J.Pet.

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15.

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16.

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6.

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19.7.

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21

9

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Thomas, F.B., Bennion, D.B., Bennion, D.W., Hunter,B.E.: .Solid Precipitation From Reservoir Fluids:Experimental and Theoretical Analysis,. Paperpresented at 10th SPE Technical Meeting, Port ofSpain, Trinidad and Tobago (June 27, 1991).

25.

Thomas, F.B., Bennion, D.B., Bennion, D.W., Hunter,B.E.: "Experimental- Theoretical Studies of SolidPrecipitation From Reservoir Fluid," Paper No.CIM/AOSTRA 91-54, presented at CIM Conference,Banff, April 21-24, 1991.

26.

27. Waldorf, D.M.: .The Effect of Steam onPermeabilities of Water Sensitivity Formations., JPT,(Oct. 1965).

Wang, F .H.L.: -Effect of Wettability Alteration onWater/Oil Relative Permeability Dispersion andFlowable Saturation in Porous Media", SPE Res Eng,(May 1988).

28.

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