OPTIMIZING PRODUCnON FROM LOWPERMEABILITY GAS RESERVOIRS

D. Brant Bennion, F. B. Thomas, R.F. BietzHycal Energy Research Laboratories Ltd

Presented at the Calgary Section of the Petroleum Society of CIM Technical MeetingDecember 13, 1995

IntroductionAbstract

As the industry seeks to increasingly exploitreserves of natural gas contained in low penneabilityintercrystalline sandstone and carbonate fonnations«20 mD in penneability) many questions have arisenas to the optimum practices to drill and completehorizontal and vertical wells in these systems as wellas the best techniques to hydraulic or acid fracturethese formations to obtain economic production rates.

Vast reserves of valuable natural gas and associatedliquids exist trapped in low permeabilityintercrystalline and microfractured carbonate andsandstone fonnations throughout the world. Due tothe low inherent viscosity of gas, conditions can besuch that these reserves can be recovered from theseJow penneability strata in situations where theeconomic recovery of conventional liquidhydrocarbons would be impossible. This paperdescribes various mechanisms which can influence theeffective recovery of gas from low permeabilityfonnations and presents a variety of drilling,completion, production and remediation techniquesthat have proven useful recently in optimizing therecovery of gas from formations of this type.

This paper provides a summary of recent workwhich has been conducted in the diagnosis andremediation of problems associated with tight gasreservoirs. Infonnation on the importance ofreservoir quality assessment and initial saturationdetennination is presented as well as a detaileddiscussion of common damage mechanisms which canaffect the productivity of tight gas formations. Theseinclude fluid retention problems, adverse rock-fluidand fluid-fluid interactions, countercurrent imbibitioneffects during underbalanced drilling. glazing andmashing, condensate dropout and entrainment fromrich gases, fines mobilization and solids precipitation.The impact of these problems during drilling,completion, workover and kill operations is reviewedand suggestions presented for the prevention andpotential remediation of these problems.

The definition of a "low" permeability reservoir issomewhat arbitrary, but for the purposes of this paperwould be considered to be formations which have asurface routine average air absolute permeability ofless than 20 InD. In-situ reservoir conditionpermeabilities of these types of reservoirs aregenerally less than I mD and can range down into themicro Darcy range (10-6 D) in many situations.

Although the emphasis in this paper is specificallyon low penneability gas reservoirs, much of theiofonnation presented is also applicable to higherpenneability gas bearing forDlations.

Specific examples of where these problems havebeen observed in 23 different common WesternCanadian lower permeability gas horizons arepresented in a summary format for informative

purposes.

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What is the Challenee? effectively predict to location of and penetrate thepre-existing natural fractures with the wells orfracture treatments. Where such penetration has notoccurred, the wells have generally been non viable.

If we consider what could cause uneconomicproduction rates from a low permeability gas bearingforDlation. the options generally will fall into sixcategories, these being; 2. Adverse initial saturation conditions

I. Poor reservoir quality - period!2. Adverse initial saturation conditions3. Damage induced during drilling and completion4. Damage induced during hydraulic or acid

fracturingS. Damage induced during kill or workover

treatments6. Damage induced during production operations

Each of these categories will now be reviewed inmore detail.

In many cases, gas exists in low penneabilityfonnations of "acceptable" permeability according tothe previous criterion, but. due to adverse capillaryforces, high in-situ saturations of trapped water, andin some cases, liquid hydrocarbons are present. Ifthese saturations are too high, economic production ofgas from the zone is often difficult due to;

- Limited reserves available for production due tothe majority of the pore space being occupied byan immobile trapped fluid

- Adverse relative permeability effects caused bythe presence of high immobile fluid saturationsrendering economic production rates impossible1. Poor Reservoir Quality - Period!

The saying "You cannot make a silk purse out ofa sows ear" has definite applicability to the field oftight gas exploitation. Through the use of appropriatedrilling, completion and in some cases large scalefracturing techniques, some operators have beenamazingly successful in obtaining economicproduction rates from formations exhibiting in-situmatrix permeabilities of as low as 10-6 D. Somereservoir applications, however, are doomed to failureby the simple virtue of the fact that, no matter howsuccessful and low damaging our drilling andcompletion operations, sufficient in-situ permeability,pressure, reserves or all of the above are not presentto obtain economically viable wells. The primeobjective of this paper is to identify candidates of thistype, in comparison to those where the judiciousapplication of the appropriate technology can obtaineconomic wells. In general, no documented evidenceexists of economic production from formations havingan interconnective matrix permeability of less dlan10-6 D (even in the presence of successful large scalefracturing treatments). If an extensive micro ormacrofracture system exists and the well can becompleted without impairing the conductivity of thenatural fractures, then documented cases exist whereviable production has been obtained from sourcematrix of lower permeability values than 10-6 D.Penetration of a less extensive microfracture systemby a conventional hydraulic or acid fracturingtreatment, to augment inflow, has also been successfulin some sub microDarcy reservoir applications. Wellsuccesses in these situations have been highlydependant on geological control and being able to

One of the first steps in ascertaining if gas iseconomically producible from a low permeabilityfonnation is the accurate determination of initial fluidsaturations. This process is often difficult due to thefact that;

- Water saturations calculated from logs are ofteninaccurate due to limited availability of accurate"a", "m" and "n" electrical property data tocalibrate field resistivity logs

- Accurate Rw data is often unavailable for theseformations as, due to high capillary trappingeffects, many of these zones do not producemobile free water to facilitate accuratecompositional and Rw measurements

- Water saturations evaluated from cores drilledwith water based fluids are often elevated due tocore flushing and spontaneous imbibition effects.Water saturations obtained using air or nitrogenas coring fluids are often lower then true in-situvalues due to localized heating during the coringprocess and core desiccation. Oil-based coringfluids can result in good water saturationdeterminations, but flushing can affect theaccuracy of the measurement of the magnitudeof any trapped initial liquid hydrocarbonsaturation which may be present in the reservoir.

A variety of techniques are available to measurein-situ water and oil saturations, the best and mostreliable being speciality coring programs in theproducing zone of interest. In zones containing onlyan initial water saturation, radioactively traced(deuterium or tritium) coring fluids can provide an

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accurate evaluation of initial water saturation whencoupled with low invasion coring technology (Ref 1).When both an initial oil and water saturation arepresent and we desire to evaluate the true magnitudeof the "free" gas saturation available for reservesevaluation and recovery, sponge coring, when coupledwith a radioactively traced water based coring systemand a low invasion coring tool can give good results,as illustrated in Figure 1. It can been seen fromFigure I that with this data (when the oil volume isadjusted for gas solubility and swelling effects) onecan accurately evaluate the free gas saturation anddetermine if sufficient reserves and relativepermeability exist to obtain a viable and exploitableplay. These techniques have been used in the past toascertain initial saturations in formations such as theMonmey, Gething, Rock Creek, Ostracod, Viking,Cardium and Jean Marie in Canada and in a numberof low permeability Permian Basin gas fields in theUnited States. Although highly related to reservoirquality, if a free gas saturation of lower than 25-300/0exists in the media this reduces both reserves andeffective gas permeability below what would typicallybe quantified as economically producible values.

beyond the zone of drilling induced invasion anddamage during the fracturing treatment will becomethe major issue of importance (to be discussed later).Exceptions would include failed or small fractreatments where short fracture half length does noteffectively penetrate the zone of drilling induceddamage, a high concentration of invaded fines whichmay subsequently be produced into and plug the highconductivity fracture directly adjacent to dte wellbore,or simple mechanical problems initially propagatingthe frac due to high near wellbore tortuosity inducedby fonnation damage (a problem often addressed widta small pre-frac HCI or HCI/HF acid squeeze toreduce tortuosity).

Drilling induced fonnation damage becomes moreof an issue when open hole non-fractured completionsare contemplated. When considering lowpenneability gas reservoirs, these types of completionsare generally only successful if a large surface area ofthe fonnation can be accessed, such as in a horizontalwell, a large vertical pay zone with a conventionalwell, or an openhole completion in a shorter butnaturally micro/macrofractured zone of theformation.

3. Formation Damage During Drilling andCompletion Fluid Retention Effects

The single greatest enemy of tight gas, whetherduring drilling, completion, fracturing or workoveroperations, is fluid retention effects. These canconsist of the permanent retention of both water orhydrocarbon based fluids or the trapping ofhydrocarbon fluids retrograded in the formationduring the production of the gas itself. Thisphenomena is commonly referred to as aqueous orhydrocarbon phase trapping and has been discussed indetail in the literature (Ref 2&3). Capillary pressureforces which exist in the porous media are thedominating factor behind fluid retention.

Tight gas reservoirs are very susceptible tofonnation damage. This is due to the generallyunforgiving nature of low penneability rock in thatwe can tolerate only a minimal amount of damage,due to the already inherently low penneability, and tothe fact that low penneability fonnations generallyexperience much more severe damage than theirhigher penn counterparts due to a high degree ofsensitivity to capillary retentive effects, rock-fluid andfluid-fluid compatibility concerns.

In general the degree of significance of fonnationdamage associated with a tight gas reservoir duringthe drilling process will be related to the nature of thefinal completion contemplated. Due to the lowpermeability nature of the matrix, unless huge lossesof clear fluid to the mabix occur, due to poor fluidrheology and high hydrostatic overbalance pressures,the zone of extreme permeability impairment isgenerally contained in a fairly localized regionadjacent to the wellbore. Ifhydraulic fracturing is thecontemplated final completion technique, which isoften the case in many low perm vertical gas wells,shallow invasive damage induced by drilling,cementing and perforating may not be significant asa well propagated and placed frac will peneb'ate far

Capillary pressure forces, are defmed as thedifference in pressure between the wetting (generallywater in most gas reservoirs) and non-wetting (gas)phases that exist in the porous media. This capillarypressure can be expressed by the following equation;

P =p -pc n.. w

= (lntafaciaI TeDSiaJ)D-I""""

This mechanism is pictorially illustrated inFigure 2. Figure 3 illustrates how this mechanism is

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operative in low and high quality porous media andwhy capillary pressure and retention effects are moresignificant in low vs high permeability fonnations.

penneability and initial saturation conditions in whichmany tight gas reservoirs exist render them primecandidates for aqueous phase b"apping.

A large number of tight gas bearing fonnations aresusceptible to phase trapping and fluid retentioneffects due to the fact that many of the economicallyproducible fonnations would be considered to be"subirreducibly saturated" where the initjal watersaturation js at some value considerably less thanwhat would be consjdered to be the "jrreducjble"liqujd saturatjon. This, in fact, js the major reasonwhy many tight gas reservoirs are exploitatjoncandidates as this subirreducjble saturation conditioncreates significant in-situ reserves and reduces theadverse relative permeability effects present in thesystem, thereby significantly increasing theproductjvity of the wells if they can be completed ina non damaging fashion. Most gas reservoirs of thistype exhibjt mgh log resjstivjties, produce no freewater (other than fresh water of condensatjon fromthe produced gas), are not in djrect communicatjonwith active aquifers or mgh water saturation zonesand have a distinct propensity to retain the majority ofany introduced water based fluid, much like a verylarge sponge. The basic mechanism of an aqueousphase trap is illustrated in Figure 4. Figure 5illustrates the interplay of invasion depth and pressurewjth the severity of aqueous phase trapping.Equation 2 (Ref 3) is used as a predictive tool toprovide an estimate of the significance of potentialproblems associated with aqueous phase trapping;

Countercurrent Imbibition

Underbalanced drilling, while touted as a means ofminimizing fonnation damage (Ref 4&5), mayactually increase the severity of near weUbore aqueousphase trap problems when it is used with water basedfluids in horizontal wells which will be completedopen hole in tight gas fonnations. Figure 7 providesa schematic illustration of the mechanism ofcountercurrent imbibition which can occur during anunderbalanced operation in a subirreducibly watersaturated formation. Due to the discrepancy betweenthe "initial" and "irreducible" saturations, one can seethat there is a tremendous capillary force that existsbetween the initial water saturation level and theirreducible saturation level (where the capillarypressure curve becomes vertically asymptotic). In aproperly designed overbalanced operation the use ofappropriate bridging and filter cake building agentscan establish a near zero permeability filter cake onthe face of the fonnation which may impedespontaneous imbibition effects. In an underbalanceddrilling operation, if any free water saturation ispresent in the circulating fluid system, this is similarto establishing a gas-water contact directly adjacent tothe wellbore face and continuous countercurrentimbibition effects into the formation can occur, evenwhen a continuously underbalanced condition ismaintained. The problem with aqueous invasion isattenuated if the underbalanced condition is lost orperiodically compromised, or if a well drilledunderbalancedis hydrostatically killed for completion,due to the fact that there is no protective filter cake toimpede the large scale invasion of fluids into theformation in an overbalanced condition. Laboratorystudies describing this phenomena are presented indetail in Reference 4.

~ = O.25[loglo (1".. ill mo,]+ 2.2($wl--.l..,.) (2)

Figure 6 provides a pictorial representation ofEquation 2. A value of the aqueous phase trap index(APT J of greater than 1.0 is generally an indicationthat significant problems with permanent aqueousphase trapping in the formation should not beapparent [although non permanent invasion andtransient permeability impairment or aqueous phaseloading (APL) may still occur (Ref 3)]. Values ofAPT I betweenO.8 and 1.0 indicate potential sensitivityto aqueous phase trapping, and values less than 0.8generally indicate significant potential for damage dueto permanent fluid retention if water based fluids aredisplaced or imbibed into the formation. The smallerthe value of the APTj index, the more significant thepotential for a serous aqueous phase trapping problem.Examination of Figure 6 indicates that the

Mud Solids Invasion

The physical invasion of natural and artificial solidsmay occur during drilling, completion, workover orkill tteatments if operating in hydrostaticallyoverbalanced conditions. Due to the very small porethroats normally associated with low perm gasreservoirs any significant depth of invasion of mudsolids into the rock is not normally observed (unlessfractures or extremely small solids, which cansometimes be generated by PDC bits, are present).Once again, this is usually only a concern in

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susceptible to electrostatic deflocculation (Ref 6),where abrupt changes in salinity and pH can cause theclay to disperse and migrate to pore throat locationswhere it bridges, blocks and can cause permanentreductions in penneability (Cardium, Belly River,Glauconite, Halfway, Bluesky, Basal Quartz, Gething,Osb'acod, Viking, Rock Creek and Montney are someformation types in Western Canada where thisphenomena has been observed). Since filtrateinvasion can extend a significant distance into thefonnation if fluid losses are appreciable, this type ofdamage may be of sufficient radius of penetration topartially impair the productivity of limited scalesubsequent fracture treatments in certain situations.If fresh water sensitive or reactive clays are present,care should obviously be taken to use inhibitive fluidsor low fluid loss systems to minimize the depth ofinvasion.

situations where open hole completions arecontemplated due to the shallow nature of thedamage.

Glazin!!

Glazing, mashing or wellbore polishing can be aproblem in some open hole tight gas completions,particularly if pure gas is used as the drilling media.Due to the extremely poor heat transfer capacity ofgases, if no fluid is present in the circulating drillingmedia, extremely high rock-bit temperatures can begenerated. This can result, when combined withconnate water and rock dust generated from thedrilling process in conjunction with high temperaturesand the polishing action of the bit, in the formation ofa thin but very low permeability ceramic pottery likeglaze on the face of the formation. This phenomenacan be observed on the face of sidewall cores cut insuch situations and on the face of air drilled core.Like mud solids invasion, due to it's extremelylocalized depth, glazing tends to be problematicspecifically in open hole completion scenarios.Mashing, caused by poorly centralized strings andtripping, refers to mechanical damage caused byfriction and motion of the string and centralizers,collars etc., against the formation face and results inthe intrusion of a paste like layer of fines and drillsolids into the formation face directly adjacent to thewellbore. Once again, a localized form of damageusually problematic only in open hole completions.

Chemical Adsorption

Physical adsorption of high molecular weightpolymers or oil wetting surfactants can reducepermeability significantly in low quality formations orpreferentially elevate permeability to water if a freewater saturation is present in the formation. Therelative size of the large polymer chains, whenadsorbed on the surface of the porous media, issignificant in comparison to the relative diameter ofthe pore throats allowing gas to flow from the media.Thus a film of adsorbed polymer, which may onlymoderately reduce the permeability in a higher qualityformation, can totally occlude available permeabilityin a lower quality zone. Once again, this is awellbore localized phenomena. Adsorbed polymercan often be removed using oxidizing agents, but careshould be taken to ensure that invasion of theoxidizing agent, and subsequent entrapment, does notoccur when the sealing effect of the polymer filtercake is degraded by oxidant contact.

Rock-Fluid Interactions

Clays

The low peJDleability associated with many tightgas fonnations is generally caused by small grain sizein sandstones or limited intercrystalline porositydevelopment in carbonates, but in some foJDlations,predominantly clastics, the permeability is alsoreduced by significant concentrations of clay. Avariety of different types of clay can be present.Highly fresh water sensitive expandable clays such assmectite or mixed layer clays can occur in shallowertight gas formations. Examples include the Viking,Basal Colorado, Belly River and Milk Riverformations in Western Canada. When contacted byfresh or low salinity water these clays expand in sizedue to substitution of water into the clay lattice(Ref 6). The physical expansion of the clay (up to5000/0 depending on the type of clay underconsideration) can result in near total penneabilityimpainnent. Other types of clay, such as kaolinite are

Fines Migration

Fines tend to move preferentially in the wettingphase and hence when only gas is flowing migrationof particulates in the porous media should beminimized. Problems can occur when fluid invasionoccurs due to relatively high spurt losses potentiallyencountered during the drilling or fracturing process,due to motion of invaded fluids during highdrawdown cleanup operations, or if the fonnationproduces liquid at rates above the critical migrationrate during underbalanced drilling operations.

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Fluid-Fluid Interactions

Problems with fluid-fluid incompatibilities wouldinclude the fonnation of insoluble scales orprecipitates caused by adverse chemical reaction ofinvaded drilling or completion fluid filtrates andin-situ water. The potential for stable emulsionfonnation also exists if hydrocarbon drilling andcompletion fluids are used. or if water based fluidsare used in formations which contain an initialirreducible liquid hydrocarbon saturation. Acidcompatibility issues may also be apparent if acid isused in the presence of an immobile liquidhydrocarbon saturation.

treatments, including- improper breaking of linear or crosslinked gels- polymer adsorption and entrainment- entrainment of produced fonnation fines/solids

in the fractures- emulsion blocks in the fractures- compaction of the fracture and embedment

affects associated with plastic fonnations andincreasing overburden pressures during thedepletion process

- physical production of proppant from the highconductivity fracture causing a loss in fractureconductivity

A common misconception is that fracturetreatments are impervious to fonnation damage on thefracture face itself during the fracture treatment andit is only the fracture conductivity which must bemaintained. Mathematical modelling, plusconsiderable field experience, has indicated that thisis not the case in many reservoir situations. Thesmaller the size and effective cross sectional area ofthe fracture treatment, the more significant thedamage occurring on the frac face in impairing theultimate productivity of the frac treatment. Large,(100-200 tonne for example) fracs, can tolerate asignificant amount of permeability impainnent on thefracture face, perhaps in excess of 95%, withoutappreciably reducing the productivity of the frac. Apermeability reduction of 10001., however, cannot betolerated. Some of the damage mechanismsmentioned previously, particularly fluid retention, arecapable of causing 1000/0 penneability reductions intight gas formations and have been the result ofsignificant reductions in well productivity. Companiontight gas well fracs of identical size (150 tonnes) havebeen placed in tight formations in the Permian basinin identical quality pay with the only variable beingthe break time and rheology of the cross linked waterbased fracture fluid used. When the crosslink waspreserved to propagate the frac, followed bysubsequent breaking, lab tests indicated a fracture faceinvasion depth into this 0.01 mO, 12% SWI fonnationof less than 2 mm with over 80% fluid recovery inthe field and 7,000,000 scf/day flow rates. Wells inwhich premature breaking of the frac fluid occurredexhibited over 6 cm of invasion in the lab, less than100/0 fluid recoveries in the field and uneconomic postfrac flow rates of less than 50,000 scf/day.

4. Formation Damage During Fracturing ofTight Gas Formations

The majority of tight gas foIDlations, by theirnature, require hydraulic or acid fracturing in order toobtain economically viable production rates.Although it has been suggested by various authorsthat fracture faces can tolerate a huge amount ofdamage and that the productivity of the treatment isstill limited by the amount of fracture conductivitypresent, there is significant lab and field evidencepresent to indicate that foIDlation damage occurringduring fracturing treatments is still a major issue. Ifwe consider factors which may impair theproductivity of a fracture treatment, these wouldinclude;

- Physical mechanical problems with the fracturetreatment

- Formation damage to the high conductivityfracture itself- Formation damage to the fracture face

Physical oroblcms with the fracture treatment

These would include such problems as poormechanical propagation of the frac, sandoffs,fracturing out of zone or channelling behind casing,etc. .

Formation dama2e to the him conductivitY fracture~

No matter how large the treatment, if a very highconductivity fracture channel is not maintained,particularly if penneability is lost in the portion of theftacture directly adjacent to the well, the benefit ofhydraulic ftacturing is severely compromised. Avariety of mechanisms can result in impairment of thepermeability of fractures in propped or acid fracture

For this reason, fracture fluid compatibility, fromboth a potential invasion depth and retention point ofview, as well as from a chemical and mechanicalpoint of view must be carefully considered to ensure

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that, not only can a viable ftac be propagated, but thatinvasion into the formation at the high differentialpressure gradients occurring during all frac treabnents,particulary in pressure depleted formations, isminimized. If invasion does occur to a limited extentcare must be taken that the invading fluids arecompatible with the formation and designed withmaximum ease of recovery in mind.

high rate cleanup of invaded water based drilling,completion, stimulation or workover fluids from theformation, may result in a condition of mobile watersaturation and hence movement of the wetting phase.This results in conditions where, if loosely attachedparticulate matter is present in the pore system andthe critical rate for migration is exceeded, thatmobilization of the fines and damage may occur.Many examples of this phenomena are present wherewells produce at high gas rates until the first sign ofwater breakthrough. At this point massive reductionsin gas rate, which cannot be solely attributed torelative permeability effects, can occur, including, insome cases, physical sand production and formationcollapse (some higher quality Gulf Coast formationsin the USA exhibit this phenomena).

5. Formation Damage During Kill/WorkoverTreatments

Mechanisms of damage to perforated, open hole orfractured wells that can occur during hydrostaticallyoverbalanced kill or workover treatments are similarto those described previously for drilling andcompletion. Damage and invasion may be moresevere in these cases as, similar to an underbalanceddrilling operation, these formations lack any type ofprotective or sealing filter cake to prevent wholesaleinvasion of the water or oil based kilVworkover fluid,so a significant amount of fluid invasion and damagemay be incurred before a hydrostatic kill condition isachieved.

Retroe:rade Condensation Phenomena

Figure 8 provides a schematic illustration of apressure-temperature diagram for a hydrocarbonsystem. A "dry" gas formation (typically a gashaving a liquid yield of less than about 10 to 15 bblcondensate per MMscf of gas) follows the depletionpath A to B. It can be seen that this depletion pathnever intersects the two phase envelope and hence thistype of system is not prone to problems associatedwith downhole condensate dropout effects. Thesetypes of reservoirs may still produce liquidcondensate at surface as the depletion path throughthe production tubing often follows the path A to Cwith the separator temperature being sufficiently lowthat production at surface conditions is well within thetwo phase envelope.

6. Formation DamageOperations

During Production

Potential damage which could occur during noIDlalproduction operations of tight gas foIDlations include;- Physical fmes migration

- Retrograde condensate dropout phenomena (rich

gas systems)- Paraffin deposition problems (waxy rich gas

systems)- Oiamondoid and hydrate plugging problems- Elemental sulphur precipitation (high HzS

concentration systems)

"Rich" gas systems, being those with liquid yieldsof greater than approx 15 bbl of condensate perMMscf, fall more to the left on the P- T diagram(Figure 8), and it can be seen at reservoir temperatureconditions that during the depletion operation (path Dto E) these systems will pass through the dewpointline and liquid hydrocarbon condensate, which oftenmay represent the most valuable fraction of thereservoir gas, condenses out of solution in the gas. Ina manner analogous to an aqueous phase trap, becausethese tight gas fonnations do not generally contain apre-existing hydrocarbon saturation, a sufficienthydrocarbon saturation to build a continuous liquidfilm to allow flow of the liquid condensate to thewellbore must occur. This is commonly called thecritical condensate saturation and the value is verydependant on reservoir lithology, wettability,condensate composition and drawdown pressure andcan vary from a very sma" value (less than 2%) to

Fines Migmtion

Considerable research (Ref 7) has indicated thatfmes generally tend to preferentially migrate in thewetting phase. For most gas reservoir systems thiswould be water (the exception being sub-dewpointrich gas systems or gas reservoirs containing an initialimmobile conventional or heavy oil saturation inwhich case the liquid hydrocarbon phase may partiallyor totally wet the surface of the fonnation) andsignificant problems with fines migration do not occurduring normal production operations unless theinterstitial shear rate caused by extreme gas flow ratescauses mobilization of the connate water. Waterconing, caused by excessive production rates, or the

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very large values in excess of 400/0. Tight gassystems, due to adverse capillary effects, often tend toexhibit higher critical condensate saturations than theirhigher permeability counterparts making them moresusceptible to this particular mechanism of damage.The presence of the trapped condensate saturation hasa blocking effect. identical to that describedpreviously for the aqueous phase trap, and cansubstantially reduce near wellbore gas permeability.

Techniques to Avoid Dama2e and RemediateExistin2 Dama2e to Low PermeabilitY GasReservoirs

Many of the types of damage described previouslycan be avoided or their effect greatly reduced if aproper understanding of the reservoir and the types ofproblems which may be encountered is obtained priorto drilling, completion and production. This sectionattempts to identify drilling and completion practiceswhich may be useful in tight gas scenarios, as well asremediation techniques for wells with existingdamage.

In many rich gas systems, gas cycling schemes areimplemented as a mechanism to recover the majorityof the condensate liquids from the formation. Inthese systems condensate dropout, although mitigatedin the bulk of the reservoir volume due to a properlyexecuted cycling operation, can still significantlyimpair the productivity of the production wells as inmany tight rich gas systems, even with large fractreatments in place, drawdown below the dewpointpressure of the gas in the near wellbore region isrequire to obtain economic production rates.

Fluid trapping/retention problems

This is a major mechanism of damage in manytight gas reservoirs. If we consider methods ofminimizing the impact of this type of damage, theywould include;

A void the introduction of water based fluids intothe fonnation during the drilling and completionoperation in totality. This would includestraight gas drilling or the use of hydrocarbonbased drilling and completion fluids. Oil basedfluids may also phase trap to a certain extent inthe forDlation and reduce perDleability. but dueto the fact that the liquid hydrocarbon willgenerally be the non-wetting phase in most gasreservoirs. where no pre-existing liquidhydrocarbon saturation is present. the physicalamount of trapping of the hydrocarbon phasemay be significantly less than would beencountered if water was used in an equivalentsituation and a large increase in gas phaserelative perDleability may be apparent. Thisphenomena is illustrated in Figure 9. If a pre-existing liquid hydrocarbon phase saturation iscontained initially within the porous media (asis common in many Monmey. Rock Creek.Ostracod. Gething. Viking and CardiumforDlations) it is possible that the forDlation maybe partially or totally wetted by the hydrocarbonphase, or the small pre-existing hydrocarbonphase saturation may act as a spontaneousadhesion site to trap additional hydrocarbons. Inthese types of reservoirs, oil based fluids maynot be advantageous over water based systemsas they may have equal or more trapping anddamage potential. The use of straight CO2 orhighly CO2 energized hydrocarbons has beensuccessful as a frac fluid medium in some

reservoirs of this type as an alternative to water.

a)Solids Precioitation Problems (paraffins. Hydrates.Oiamondoids. Elemental Sulohur)

A detailed discussion of these phenomena iscomplex and beyond the scope of this paper, but isdiscussed in the literature (Ref 8 & 9). The fonnationof all of these solid precipitates are generally initiatedby reductions in temperature, and are also in somecases weaker functions of reductions in pressure. Inmost situations this results in the generation of theseelemental solids being more of a production problemin tubing and surface equipment, rather than directlyin the formation itself. Near wellbore problems areencountered in some waxy condensate systems whichare producing at high rates, due to a significant Joule-Thompson effect occurring at the perforations or inthe fractures. The rapid expansion of gas in thesezones, due to high drawdown effects, results in asignificant localized temperature drop which canaggravate problems with solids precipitation.Diamondoids are granular solids, similar to their oilreservoir counterparts, asphaltenes, which are directlyprecipitated from natural gases (generally rich gases).These hard granular solids can result in erosion andplugging problems, most often in surface equipment.Elemental solid sulphur production can also occurdownhole and in production equipment under certaintemperature and pressure conditions in very sour gassystems which can result in both corrosion andplugging problems.

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Alcohol fracs (i.e. gelled methanol) have beenused with success in some situations. Care mustbe taken with the use of alcohol in very low«0.1 mD) formations as adverse capillarypressure can also physically trap the alcohol.Low molecular weight alcohols, such asmethanol, have a very low degree of miscibilitywith liquid hydrocarbons and can often suffer&om incompatibility problems with respect tosludge formation with many crude oils. Forthese reason, their use should be avoided inmost situations where a liquid hydrocarbonsatwation is known to exist in the reservoir infavour of higher molecular weight mutualsolvents (i.e. - IPA, EGMBE) which exhibitsignificantly greater miscibility with liquidhydrocarbons and fewer compatibility problems.

vertically asymptotic nature of most gas-liquidcapillary pressure curves near the irreduciblesaturation, extreme drawdown gradients, whichcannot be realized in most normal fieldapplications, are required to obtain an effectivereduction in the trapped liquid saturation. Forthis reason this method does not tend to be ofgreat efficacy in most situations.

2.

If water based fluids must be considered fortechnical or economic reasons, invasion depth shouldbe minimized to the maximum extent possible toavoid significant aqueous phase retention problems.For drilling fluids this would include minimization ofoverbalance pressure, if possible, and rheology andbridging agents, if appropriate, to establish aprotective filter cake to act as a barrier for significantfluid loss into the formation. Kill or walkover fluidsshould be designed with appropriate fluid additives toprevent losses to the formation under hydrostaticoverbalance conditions. The use of cross-linkedfracture fluids with appropriate breaker packages andas rapid recovery times as possible after ftacturing,foamed systems or poly-emulsions should beconsidered if water based frac fluids are considered.

Remediation of fluid retention problems

A number of basic approaches can be taken toremoving existing phase traps, these would include;

Increasing capillary drawdown - trapped

saturation is a direct function of appliedcapillary gradient, the higher the availablecapillary gradient, the lower the obtainable watersaturation. Therefore, in the absence of finesmigration problems, water coning potential orretrograde condensate dropout potential (rich gassystems) the higher the drawdown pressurewhich can be applied across the phase trappedzone, the lower the water saturation which willbe able to be obtained. In a practicalapplication, unless the invasion depth of theinfiltrated aqueous phase is very shallow, or thereservoir pressure is extremely high, due to the

Reduced 1FT between the water-gas or oil-gassystem - Capillary pressure, which is the prime

mechanism for the entrapment of the oil orwater based fluid within the pore system, is adirect linear function of the interfacial tension(1FT) between the trapped phase and the gas inbulk of the pore space (refer to Equation I). Ifsome means can be found to reduce the 1FTbetween the gas and liquid phase, then at theavailable reservoir drawdown it may becomeeasier to mobilise and produce a portion or allof the entrapped fluid. A variety of treatmentsare available to reduce the 1FT in situations suchas this;a) Chemical surfactants have been used in some

cases, but due to the disparate molecularnature of gas and liquids, it is difficult tofind liquid soluble chemical surfactantswhich are effective in obtaining the multipleorders of magnitude reduction in 1FT (fromsay 70 to 0.1 dyne/cm) required in order toeffectively mobilize a significant amount oftrapped fluid from the system.

b) Mutual solvents, such as methanol or highermolecular weight alcohols or materials suchas EGMBE can significantly reduce 1FTbetween gas and liquid and are mutuallymiscible in the trapped liquid phase and tendto reduce viscosity and increase volatilityand vapour pressure extractive effects toremove a portion of the trapped liquid. Asmentioned previously, careful selection of amutual solvent is important to ensuremiscibility and compatibility if a liquidhydrocarbon saturation is present within theporous media.

c) Liquid carbon dioxide has been used foraqueous phase traps due to it's ability toreduce 1FT, dissolve in the trapped liquidphase, physically extract a portion of thetrapped water as a desiccant and provide azone of localized high reservoir energy toobtain a high instantaneous capi lIary gradienton blow down which might not normally bepresent in the formation (particulary in low

10 -

pressure zones).d) Liquid CO~ LPG, Liquid ethane and dry gas

have all been used as techniques to removehydrocarbon traps in porous media.Depending in the available treabnentpressure, temperature and gravity of thetrapped hydrocarbons, one or more of theseliquids will often be miscible with theentrapped hydrocarbons. The ueabnent isdesigned to either miscibly displace thetrapped hydrocarbon a sufficient distanceinto the formation so that cross sectionalflow area is increased to the extent that thezone of trapped fluid does not substantiallyreduce productivity, or produce thehydrocarbon saturated liquid back out of theformation at sufficient backpressure to keepthe extracted hydrocarbons in solution tophysically "scrub" a portion of the formationadjacent to the wellbore or fracture faceclean of entrapped hydrocarbon. Hightreabnent pressures are required for thistreatment to be effective with conventionaldry gas (natural gas or nitrogen) injection,generally in excess of 35 MPa. Theueatrnent may be effective at much lowerpressures (8 - 20 MPa) with gases such asliquid CO2 or ethane, and at very lowpressure (3 - 5 MPa) with very rich lowvapour pressure gases such as LPG. In thecase of a retrograde condensate trap, thetreatment may be of only temporary utilityas, if the well is continued to be produced ina high drawdown condition, furtherentrapment will occur as additionalcondensate is retrograded as the gascontinues to be produced from the well.

in that when the acid spends we simply havemore water in the fonnation. If the spent acidis squeezed further than it has effectively reactedinto the fonnation, it may become enb'apped likeany other invaded aqueous fluid and, in somecases, aggravate the production problem it wasintended to cure. This is evident in many acidsqueeze treatments in tight gas reservoirs whereacid recoveries have been exceptionally poor andwell productivity has often been furtherimpaired, rather than improved, by the acidtreatment. The use of nitrified or foamed acidshas been useful in some situations of this type asthe total volume of liquid introduced into thefonnation is reduced and localized chargeenergy to recover the acid is introduced into thefonnation by the gaseous agent (often COJ usedto foam the acid. Caution is required inimplementing this procedure to reduce ahydrocarbon b'ap, as many acids areincompatible with hydrocarbons andde-asphalting or the fonnation of stableemulsions, particularly in the presence of highconcenb'ations of unsequestered iron, couldoccur.

Direct physical removal of the trapped water orhydrocarbon saturation - This encompasses arather wide range of potential techniques whichinclude;

4

a) Dry gas injection - A commonmisconception is that merely flowing thereservoir gas for an extended period of timewill result in evaporation and removal of aportion of the trapped water or hydrocarbonsaturation. Since the produced reservoir gasis saturated with both water vapour (in allcases) and heavy hydrocarbons (for a richgas reservoir) at reservoir temperature andpressure conditions as it passes by thetrapped liquid, it can be seen that noadditional water or hydrocarbon could beeffectively absorbed into the gas phase. Ifpressure can be elevated significantly, somehydrocarbon liquid may revaporize, but thisis obviously much easier accomplished in aninjection rather than a production scenario.Dry, dehydrated, pipeline spec gas injection,however, wilt result in the gradualdesiccation of a portion of the reservoirdirectly adjacent to the injection zone, aphenomena welt known in many gas storagewelts. The objective of a dry gas injection

Physical changes in the pore geometry - Sincecapillary pressure is also a direct function of theradii of curvature of the immiscible interfaceswhich are present in the porous media (seeEquation I), which are forced by the geometryof the confining porous media (Figure 3), if theradii of curvature can be increased, by makingthe pore spaces less constrictive, capillarypressure will be reduced and it may becomepossible to mobilise the trapped fluid. Whilegenerally difficult to accomplish in clasticformations, unless HF acid is considered, thiscan be accomplished in some cases in tightcarbonates with appropriate acid treabnents.These stimulation treatments, however, are insome respects the proverbial "two edged sword"

3.

technique is to inject dry gas for a shortperiod of time (3 to 10 days at 1 to 3MMscf/daytypically) to attempt to dehydratesome of the higher conductivity channels inthe reservoir and establish a conductive flowpath to the bulk of the undamaged reservoir.The technique is relatively easy to apply andhas particular application in damagedhorizontal wells where large exposed payzones may render other types of penetratingtreatments impractical. Dry gas injection hasbeen successfully combined, in somesituations, with mutual solvents such asmethanol to increase the potential extractivepower of the treatment. Variations of theprocedure would include the use ofalternative dry gases such as nitrogen,oxygen content reduced air, dehydrated fluegas or carbon dioxide. Figure 10 provides aschematic illustration of the dry gas injectionprocess. If highly saline brine is the trappedphase (i.e. - weighted drilling, completion orkill fluids or spent acid) laboratoryinvestigation of this technique is oftenwarranted as precipitation of the soluble saltsfrom solution as evaporation occurs in thepore system can result in significant residualpenneability impairment which maycounteract the benefit of the removal of thetrapped water saturation.

vertical wells penetrate thin, highly damagedsand layers. Treatment area is generallyapproximately two metres in length by I to2 metres in radius in a single application.The most common application is potentiallystimulating secondary target gas zones whichwere badly damaged using conventionalwater based fluids when targeting deeperprimary zones. Figure 11 provides anillustrative schematic of the FHT process.

c) Localized Combustion - This has been amethod suggested to remove hydrocarbonphase traps in tight gas. The techniqueinvolves short tenD air injection. Ifdownhole temperature is sufficient,spontaneous ignition will occur, combustingthe condensate saturation whilesimultaneously generating localized heatwhich may also vaporize a portion of thetrapped connate water saturation andthennally decompose reactive clays.Wellbore flashback effects and extremepotential corrosion concerns are potentialproblems associated with the use of thismethod.

d) Time - Nature abhors a steep capillarygradient. Thus, when a zone of high watersaturation is induced into a water-wetfonnation, natural capillary action will tendto have a dispersing effect in graduallyimbibing a portion of the water saturationaway from the wellbore or fracture face.This phenomena is illustrated in Figure 12.Due to the limitations of the capillaryimbibition, the water saturation in theflushed zone will only be able to imbibedown to the irreducible saturation dictated bythe capillary geometry of the system,therefore a significant residual aqueous phasetrapping effect may still be apparent. Thisphenomena has been observed in many caseswhere tight gas wells have been drilled,tested and subsequently shut in orabandoned. After an extended period oftime some of these wells have been retestedand produced at order of magnitude or moregreater rates that observed initially.Production of the well obviously counteracts,to an extent, this phenomena and may slowthe speed of this process.

b) Formation heat treatment - this is a relatively

new experimental treatment which has beenspecifically designed to remove both aqueousphase b'aps as well as thermally decomposingpotentially reactive swelling ordetlocculatable clays (Ref 10). Thetreatment is applied using a speciallydesigned coiled tubing conveyed downholetreating tool. Electrical heaters in thedownhole tool are used to heat nitrogen,injected down the CT string, to very hightemperatures which is then subsequentlyinjected directly into the formation. Ifdownhole temperatures can be elevatedabove SOOOC, supercritical volatilization ofwater, regardless of the reservoir pressure,occurs as well as partial or total thermaldecomposition and desensitization of reactiveclays. In lab tests the technique has resultedin over 10 fold improvements inpermeability in damaged zones. Thetechnique has particular application torelatively shallow tight gas reservoirs where

12 -

Countercurrent Imbibition sizing of the suspended particulate matter can generatea much lower permeability filter cake than would beobtained using naturally occurring solids and can actas an efficient barrier to damaging filtrate invasion.Sizing criteria vary depending on the system. butwould range from 10-400/0 of the pore throat size formatrix systems and 10-100% of fracture aperture forfractured reservoirs. Specific size distribution for afluid bridging agent can generally only be quantifiedafter a detailed evaluation of the system underconsideration.

Countercurrent imbibition problems duringunderbalanced drilling operations can be minimizedby increasing the magnitude of the apparentunderbalance pressure to act as a greater deterrent toimbibition. If a significant difference exists betweenthe initial and irreducible water saturations, however,such as in the case of many tight gas reservoirs, thistechnique is generally insufficient to counteract theextremely adverse capillary pressure gradients presentin the porous media if a water based fluid is used.Better results are obtained in situations such as this byavoiding the use of water based fluids through eitherstraight gas drilling, or using a hydrocarbon basedfluid as the drilling fluid medium (if the formation iswater-wet). Since hydrocarbon is the non-wettingphase, no impetus will be present for spontaneousimbibition to occur. If the underbalance pressurecondition is compromised, invasion and trapping ofthe hydrocarbon based fluid could still occur and be

problematic.

Underbalanced drilling may also be considered asa technique to prevent this type of damage if aheterogenous formation exists where formulation of asingle fluid system with effective bridgingcharacteristics is impractical.

Glazing

Classic glazing in generally motivated by heatassociated with pure gas drilling operations in openhole completions in unifomt, low pemteabi I ity clasticsor carbonates. Glazing can generally be avoided bythe inclusion of a small amount of compatible fluid(i.e. mist drilling) in the system to increase lubricityand heat transfer from the bit.

Mud Solids Invasion

As mentioned previously, this is generally only asignificant problem if an unstimulated open holecompletion is contemplated for the well underconsideration. If this is the case, care must be takenin the design of the drilling fluid to ensure thatsignificant invasion of solids into the formation doesnot occur. In general solids larger than about 300/0 ofthe median pore throat size will not invade asignificant depth into the formation. Due to the smallpore throat size associated with most tight gasreservoirs, natural exclusion of the majority ofartificial (barite, bentonite, bridging agents, naturaldrill solids, etc.) occurs. Pore size distribution data(and fracture aperture sizing if fractures are present)should be obtained in this type of situation to allowmud engineers to ensure that the expected sizedistribution of solids present in the fluid system areappropriate to avoid invasion.

Rock-Fluid and Fluid-Fluid Interactions

Initial analysis of the fonnation to investigate thepresence of any potentially reactive clays (smectite,mixed layer clays, mobile kaolinite), is essential intight gas reservoirs. This is generally conducted usinga combination of thin section, XRD and SEManalyses. If reactive clays are present, this should actas a warning flag for the use of fresh or low salinitywater in most situations. Detailed compatibilitytesting should be conducted, if water based fluids areto be used, to quantify inhibitors (i.e. - KCI, CaCI2,etc.) which may Stabilize reactive clays if invasiondoes occur. Chemical stabilizers (i.e. - highmolecular weight polymers), while potentiallyefficient at stabilizing reactive and mobile clays, oftenmay cause more damage due to physical adsorption ofthe polymer on the rock surface which may occludethe minuscule area available for flow in tight gasfonnations and hence should only be used afterdetailed lab evaluation has been conducted toascertain their usefulness and degree of damage thatthey may cause.

Due to the very small pore throat size, nonnal mudsolids are too large to form a low permeability sealingfilter cake in most low permeability gas reservoirs.This results in the solids being retained from invadinginto the formation, but because the filter cake isrelatively coarse (in comparison to the small porethroats the cake is attempting to block) a considerableamount of fluid seepage into the pore system can stilloccur which can initiate a damaging phase trap orother fluid-fluid incompatibility problems. Proper

Similar tests should be conducted between potential

invading filtrates and foJDlation fluids to ensure that

13.

they are compatible with respect to scale, precipitateor emulsion fonnation with in-situ water and liquidhydrocarbons which may be present in the porousmedia. If acid treatments are to be used in reservoirswhich contain a trapped liquid hydrocarbon saturation,compatibility tests to ensure that asphaltenes, sludgesand emulsions do not fonD between the acid and thein-situ oil should be conducted. Rock solubility testsshould also be conducted in this case to ensure that alarge concentration of insoluble fines (i.e. - quartzose

rock fragments, pyrobitumen, anhydrite, etc.) are notreleased by acidization and allowed to subsequentlybe squeezed deeper into the formation where theymay reduce penneability.

due to the unprotected nature of the fracture faces oropen hole wellbore after production has beenoccurring for some period of time. Oil-based fluidswith appropriate bridging agents may be a betterchoice for kill agents in some situations. Careful carewith respect the composition, rheology, bridgingcharacter, filter cake building potential andremovability should be taken in kill fluid design in amanner similar to designing a drilling fluid. In manycases the using of CT or snubbing equipment may beviable and the workover or recompletion can beconducted with the well in a live mode,underbalanced, to avoid significant additional damageeffects.

Fracturing Operations Production Problems

Detailed modelling and geomechanicalmeasurements can be undertaken to attempt to ensurethat the mechanical propagation of hydraulic and acidfracturing treabnents are acceptably achieved. Fluidretention, particularly water retention, is a significantproblems in many tight gas fracturing operations. Avariety of techniques have been utilized to attempt toreduce fluid losses to the formation in situationswhere water trapping is problematic including the useof pure oil fracs, CO2 energized oil fracs, crosslinkedwater based fracs, poly-emulsion fracs and waterbased foam fracs. The selection of the appropriatefluid will be highly dependant on the size of the frac,formation characteristics and phase b'apping potentialand available drawdown pressure.

A large majority of production problems with tightgas reservoirs, including fines migration, retrogradecondensate dropout and solids precipitation are allassociated with large pressure drops or ratesassociated with the low penneability nature of thereservoir. Means of reducing rate or pressure drop,including physical rate reduction or an increase inflow area by horizontal drilling, open holecompletions or fracturing are the best techniques tocounteract these problems.

Dual completions using downhole ESP's to pumpoff water in wet zones can prevent the prematureconing of water in some gas reservoir situations,which may have adverse relative permeability andfmes migration effects.

In formations which contain a pre-existing oilsaturation and which may (or may not be) oil-wet, oilbased fluids may react as adversely or worse thanwater. Pure CO2 fracturing has been usedsuccessfully in some formations of this type (i.e. -Rock Creek, Ostracod, Gething. Monmey), butobvious limitations exist with respect to the size offrac which can be effectively propagated (generallyless than 20 tonnes with current technology) anddepth constraints (generally less than 2000 metres,depending on tubing/casing size).

Solids precipitation problems are difficuh toprevent, being inherent to the nature of the producedgas itself. But can often be minimized by judiciousselection of the correct downhole operatingtemperature and pressure and the selective use of avariety of chemical inhibitors or treating agents(solids precipitation inhibitors, organic solvents,crystal modifiers, etc.). Detailed work has also beenconducted recently in insulated and heat traced tubing,coupled with detailed numerical wellbore heat lossmodels for paraffin deposition, to optimize theproduction of deep waxy retrograde condensate gasreservoirs.

KilVWorkover Treatments

Many wells have been drilled with great care paidto fonnation damage, only, at some later date, to havepoorly conceived kill jobs conducted which were veryeffective in achieving not a only temporary butpermanent well control results. Water-based killfluids generally react poorly in most tight gassituations and significant invasion generally occurs

Canadian Formations Susceptible to Various TightGas Damage Mechanisms

This section provides an incomplete summary of anumber of low permeability formations in Canada thathave been investigated recently for tight gas damage

14 -

mechanisms in the lab and the field. The results aresite specific and can, of course, vary regionally withreservoir quality and saturation conditions, butprovide some idea of the type and scope of thisproblems in some common field applications inCanada.

to understand the initial reservoir quality andsaturation conditions and accurately assess, atthe current level of technology, if reserves existand if those reserves are economicallyrecoverable.

2. With advanced technology gas has beeneffectively and economically produced frommany tight gas formations with permeabilitiesofless than 0.1 mD.

Abbreviation Definitions

3, Tight gas fonnations are very susceptible tofonnation damage. Fluid retention is a majormechanism of damage in many of thesesituations. Means of minimizing damage effectsinclude understanding the wettability and initialsaturation conditions of the reservoir and thenminimizing invasion through the use of gas orgas energized fluids, ultra low fluid lossconventional systems or underbalanced drillingand completion techniques.

Water Retention - WROil Retention - ORMud Solids Invasion - MIGlazing - GLCountercurrent imbibition - CCIRock-Fluid Interactions (reactive clays) - RFIFluid-Fluid Interactions (Precipitates, scales,emulsions, acid incompatibility) - FFIFines Migration - FMProduction Problems - (Condensate dropout, solidsprecipitation) - PP

Formation Name andMechanism Susceptibility

Potential Damage4. Significant damage can occur during fracturing

treatments in tight gas due to improper fluidselection or mechanical problems with the frac.Fluid retention near the frac faces and fracturepenneability impainnent are major damagemechanisms in these cases. The smaller thefracture treatment, the more significant theeffect of frac face damage on productivity. Insome cases oil based, gas energized oil or pureCO2 fracs have proven useful in minimizingdamage. Success has also been achieved withvery low fluid loss cross linked water based gelsystems in some very low penneabilityfonnations which were highly susceptible tofluid retention effects.

Bakken - WR, GL, CCIBaldonnel - WR, OR, MI, CCI, FFIBasal Colorado - WR, OR, MI, GL, RFI, FMBasal Quartz - WR, OR, MI, GL, RFI, FM, PPBelly River - WR, MI, GL, CCI, RFI, FMBluesky - WR, MI, GL, CCI, RFI, FMCadomin - WR, MI, GL, CCI, RFI, FMCadotte - WR, MI, GL, CCI, RFI, FMCardium - WR, OR, GL, CCI, RFI, FMDoig - WR, GL, CCI, RFI, FMGething - WR, OR, GL, CCI, RFI, FMGlauconite - WR, GL, CCI, RFI, FMHalfway - WR, OR, GL, CCI, RFI, FM, PPJean Marie - WR, GL, CCI, RFI, FFIMedicine Hat - WR, GL, CCI, RFI, FM, PPMilk River - WR, OL, CCI, RFI, FM, PPMontney - WR,OR, GL, CCI, RFI, PM, PPOstracod - WR, OR, OL, CCI, RFI, FM, PPPaddy - WR, CCI, RFIRock Creek - WR, OR, MI, GL, CCI, RFI. FM, PPTaber - WR, GL, CCI, RFI, FMViking - WR, OR, GL, CCI, RFI, FM, PPWhite Specks - WR, OR, GL, CCI, RFI

s. Reducing drawdown rate can result inminimizing problems with retrogradecondensation. water coning, fmes migration anda variety of solids precipitation problems. Thiscan be accomplished by reducing productionrate, or more commonly by increasing crosssectional flow area by open hole completions,horizontal drilling or fracturing.

AcknowledemenuCon~lusions

The authors wish to express appreciation to theHycal Energy Research Laboratories for the databaseto publish this paper. Thanks also to Maggie Irwinfor her assistance in the preparation of the manuscriptand figures.

Significant reserves of natural gas andcondensate liquids exist in low penneabilityformations throughout the world. Goodengineering and evaluation is required in order

IS-

References 9. Thomas, F .B., Bennion, O.B., Bennion, O. W .and Hunter, B.E.: "Solid Precipitation FromReservoir Fluids: Experimental and TheoreticalAnalysis," Paper presented at 10th SPETechnical Meeting, Port of Spain, Trinidad andTobago (June 27, 1991).

1 Bennion, D.B., Thomas, F.B., Crowell, E.C.,Freeman, B.: "Applications For Tracers InReservoir Confonnance Predictions and InitialSaturation Determinations", presented at the1995 I"' Annual International Conference onReservoir Conformance, Profile Control Water& Gas Shutoff, August 21-23, 1995, Houston,Texas.

10. Jamaluddin, A.K.M., Vandamme, L.M.,Nazarko, T.W., Bennion, D.B.: "HeatTreatment for Clay-Related Near WellboreFormation Damage", presented at the 46thAnnual Technical Meeting of the Peb'oleum ofCIM in Banff, Alberta, Canada, May 14-17,1995.

Bennion, O.B.; Cimolai, M.P.; Bietz, F.R.;Thomas, F.B.: "Reductions in the Productivityof Oil and Gas Reservoirs Due to AqueousPhase Trapping", JCPT, November, 1994.

2.

3. Bennion, D.B., Thomas, F .B., Bietz. R.F.,Bennion, D. W.: "Water and Hydrocarbon PhaseTrapping in Porous Media - Diagnosis,Prevention and Treatment", CIM Paper No. 95-69 presented at the 46th Annual TechnicalMeeting at Banff, Alberta, May 14-17, 1995.

Bennion, D.B; Thomas, F .B.: "UnderbalancedDrilling of Horizontal Wells - Does It ReallyEliminate Formation Damage?" Paper SPE27352 to be presented at the 1994 SPEFormation Damage Symposium, Feb. 9-10,1994, Lafayette, Louisiana.

4.

Bennion, O.B., Thomas, F .B., Bietz, R.F.,Bennion, O. W.: "Underbalanced Drilling,Praises and Perils", presented at the firstinternational UnderbalancedDrilling Conferenceand Exhibition, The Hague, Netherlands. Oct. 2-4, 1995.

s.

Bennion, D.B.; Bennion, D.W; Thomas, F.B.;Bietz, R.F.: "Injection Water Quality: A KeyFactor to Successful Waterflooding", Paper CIM94-60, presented at the May 1994 AnnualTechnical meeting of the Petroleum Society ofCIM.

6,

Bng. J.H., Bennion, O.B. and Strong. J.B.:"Velocity Profiles in Perforated Completions,"Journal of Canadian Petroleum Technology,(October 1993) pp 49-54.

7

Thomas, F.B., Bennion, D.B. and Bennion,D. W., "Experimental and Theoretical Studies ofSolids Precipitation From Reservoir Fluids,"Journal 01 Canadian Petroleum Technology,

(January 1992).

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