low permeability gas reservoirs

8/12/2019 Low Permeability Gas Reservoirs

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SPE 35577OW PERMEABILITY GAS RESERVOIRS: PROBLEMS, OPPORTUNInES & SOLU110NSFOR DRILLING, COMPLE110N, STlMULA TlON AND PRODUcnON1

Eachof thesecategorieswill now be reviewed n more detail.1.PoorReservoirQuality- Period The saying You cannotmakea silk purseout of a sows ear" has definite applicabilityto the field of tight gas exploitation. Through the use ofappropriatedrilling, completion and n somecases arge scalefracturing techniques,some operatorshave been amazinglysuccessful n obtaining economic production rates fromformationsexhibiting n-situ matrix permeabilities f as ow as10-6D. Some eservoir applications,however,are doomed ofailure by the simple virtue of the fact that, no matter howsuccessfuland low damaging our drilling and completionoperations, ufficient n-situ permeability,pressure,eserves rall of the aboveare not present o obtain economicallyviablewells. The prime objective of this paper is to identifycandidatesof this type, in comparison o those where thejudicious applicationof the appropriate echnologycan obtaineconomicwells. In general,no documented vidence xistsofeconomic production from formations having aninterconnectivematrix permeability of less han 10-6D (evenin the presence f successfularge scale racturing reatments).If an extensivemicro or macrofracture ystemexists and thewell can be completedwithout impairing the conductivity ofthe natural ractures, hen documented ases xist whereviableproduction has been obtained from source matrix of lowerpermeability values than 10-6 D. Penetration of a lessextensivemicrofracturesystemby a conventional ydraulic oracid fracturing treatment, o augment nflow, has also beensuccessful n some sub microDarcy reservoir applications.Well successesn thesesituationshavebeenhighly dependenton geologicalcontrol and being able o effectively predict thelocation of and penetratehe pre-existingnatural ractureswiththe wells or fracture treatments.Where such penetrationhasnot occurred, he wells have generallybeennon viable.

-Accurate data s often unavailable or these onnations asdue o high capillary trapping effects,many of thesezonesdonot produce mobile free water to facilitate accuratcompositionaland~ measurements.- Water saturationsevaluated rom cores drilled with watebased fluids are often elevated due to core flushing andspontaneousmbibition effects. Water saturations obtaineusing air or nitrogen as coring fluids are often lower then truein-situ values due to localized heating during the coringprocess ndcoredesiccation.Oil-basedcoring fluids can esulin goodwatersaturation etenninations, ut flushing canaffecthe accuracyof the measurement f the magnitude of anytrapped nitial liquid hydrocarbon saturation which may bepresent n the reservoir.A variety of techniques re available o measuren-situ wateand oil saturations,he best and most reliable being specialitcoring programs n the producing zone of interest. In zonecontainingonly an nitial water saturation, adioactively race(deuterium or tritium) coring fluids can provide an accuraevaluationof initial water saturationwhen coupled with lowinvasion coring technology Ref. 1). When both an initial oiand water saturationare presentand we desire o evaluate htrue magnitude of the "free" gas saturation available foreserves valuationand ecovery,sponge oring, when couplewith a radioactively raced water basedcoring systemand low invasioncoring ool can give good results,as llustrated nFig. 1. It canbeen seen rom Fig. 1 that with this data whethe oil volume is adjusted for gas solubility and swellineffects)one can accuratelyevaluate he free gassaturationandetennine f sufficient reserves nd relative penneability existo obtain a viable and exploitableplay. These echniques avbeen used in the past to ascertain initial saturations ifonnations such as the Montney, Gething, Rock CreeOstracod,Viking, Cardium and JeanMarie in Canadaand ia number of low penneability PennianBasin gas ields in thUnited States. Although highly related o reservoir quality, a free gassaturationof lower than 25-30% exists n the medthis reduces oth reserves nd effective gaspenneabilitybelowhat would typically be quantifiedas economicallyproducibvalues.3. Formation Damage During Drilling and CompletionTight gas eservoirsare very susceptible o-fonnation damagThis is due to the generally unforgiving nature of lopenneability rock in that we can tolerate only a minimamount of damage, due to the already inherently lopenneability, and o the fact that low permeability ormatiogenerally experiencemuch more severe damage han thehigher permeability counterpartsdue to a high degree sensitivity to capillary retentive effects, rock-fluid and fluidfluid compatibility concerns.In general, he degreeof significanceof fonnation damaassociated ith a tight gas eservoirduring the drilling procewill be related to the nature of the fmal completi

2. Adverse initial saturation conditions. In many cases, asexists in low penneability fonnations of "acceptable"penneability according o the previous criterion, but, due toadversecapillary forces, high in-situ saturationsof trappedwater, and n somecases, iquid hydrocarbons re present. Ifthese saturationsare too high, economic production of gasfrom the zone s often difficult due to:- Limited reserves vailable or productiondue o the majorityof the porespace eing occupiedby an mmobile trapped luid.- Adverse elative penneability effects caused y the presenceof high immobile fluid saturations rendering economicproduction ates mpossible.One of the first steps n ascertaining f gas s economicallyproducible rom a low penneability fonnation is the accuratedeterminationof initial fluid saturations. his process s oftendifficult due to the fact that:- Water saturationscalculated rom logs are often inaccuratedue to limited availability of accurate "a", "m" and "n"electrical property data o calibrate ield resistivity logs.


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D.B. BENNION, F.B. mOMAS, R.F. BIETZSPE35577A largenumberof tight gasbearing ormationsaresusceptiblto phase rapping and luid retentioneffectsdue o the fact thamany of the economically producible formations would beconsidered o be "subirreducibly saturated"where the initialwater saturation s at some value considerably ess han whawould be considered o be the "irreducible" liquid saturationThis, in fact, is the major reasonwhy many tight gas eservoirare exploitation candidatesas this sub rreducible saturatiocondition createssignificant in-situ reservesand reduces headverse elative permeability effects present n the systemtherebysignificantly ncreasing he productivity of the wells ifthey can be completed n a non damaging ashion. Most gareservoirsof this type exhibit high log resistivities,producenofree water (other than fresh water of condensation rom theproducedgas), are not in direct communicationwith activaquifers or high water saturation zones and have a distincpropensity o retain he majority of any ntroducedwaterbasefluid, much ike a very large sponge. The basicmechanism an aqueous hase rap is illustrated n Fig. 4. Fig. 5 illustratethe interplay of invasion depth and pressurewith the severiof aqueous hase rapping. Equation 2 (Ref. 3) is used as predictive tool to provide an estimate of the significanceopotential problemsassociated ith aqueousphase rapping;

= 0.25[10810ka;r in mD)]+2.2(SWi-ini1ill~.'. .APT; (2

contemplated. Due to the low permeability nature of thematrix, unless huge losses of clear fluid to the matrix occur,due to poor fluid rheology and high hydrostatic overbalancepressures, the zone of extreme permeability impairment isgenerally contained in a fairly localized region adjacent to thewellbore. If hydraulic fracturing is the contemplated fmalcompletion technique, which is often the case in many lowperm vertical gas wells, shallow invasive damage induced bydrilling, cementing and perforating may not be significant asa well propagated and placed frac will penetrate far beyond thezone of drilling induced invasion and damage during thefracturing treatment will become the major issue of importance(to be discussed later). Exceptions would include failed orsmall frac treatments where short fracture half length does noteffectively penetrate the zone of drilling induced damage, ahigh concentration of invaded fines which may subsequently beproduced into and plug the high conductivity fracture directlyadjacent to the wellbore, or simple mechanical problemsinitially propagating the frac due to high near wellboretortuosity induced by formation damage (a problem oftenaddressed with a small pre-frac HCl or HCl/HF acid squeezeto reduce tortuosity).Drilling induced formation damage becomes more of an issuewhen open hole non-fractured completions are contemplated.When considering low permeability gas reservoirs, these typesof completions are generally only successful if a large surfacearea of the formation can be accessed,such as in a horizontalwell, a large vertical pay zone with a conventional well, or anopenhole completion in a shorter but naturallymicro/macrofractured zone of the formation.Fluid Retention Effects. The single greatest enemy of tightgas, whether during drilling, completion, fracturing orworkover operations, is fluid retention effects. These canconsist of the permanent retention of both water orhydrocarbon based fluids or the trapping of hydrocarbon fluidsretrograded in the formation during the production of the gasitself. This phenomena is commonly referred to as aqueous orhydrocarbon phase trapping and has been discussed n detail inthe literature (Ref. 2&3). Capillary pressure forces which existin the porous media are the dominating factor behind fluidretention.Capillary pressure forces, are defmed as the difference inpressure between the wetting (generally water in most gasreservoirs) and non-wetting (gas) phases that exist in theporous media. This capillary pressure can be expressedby thefollowing equation:

Fig. 6 provides a pictorial representation f Equation 2. Avalue of the aqueousphase rap index (APT;) of greater ha1.0 is generally an indication that significant problems witpermanent queous hase rapping n the formation shouldnobe apparent although non permanent nvasion and transiepermeability mpairmentor aqueous hase oading (APL) mastill occur (Ref. 3)]. Values of APT; between 0.8 and 1indicate potential sensitivity to aqueousphase rapping, anvalues ess han 0.8 generally ndicate significant potential odamage ue o permanent luid retention f water based luidare displacedor imbibed nto the formation. The smaller hvalue of the APT; index, he more significant the potential oa serousaqueousphase rapping problem. Examination oFigure 6 indicates hat the permeability and initial saturaticonditions n which many ight gas eservoirsexist render heprime candidatesor aqueous hase rapping.Countercu"ent Imbibition. Underbalanced rilling, whitouted as a means of minimizing formation damage (Re4&5), may actually increase he severity of near wellboaqueous hase rap problemswhen t is usedwith water basfluids in horizontal wells which will be completedopen hoin tight gas formations. Fig. 7 provides a schemaillustration of the mechanism of countercurrent mbibitiowhich can occur during an underbalancedoperation in subirreducibly water saturated formation. Due to tdiscrepancy etween he "initial" and "irreducible" saturatioone can see that there is a tremendouscapillary force thexists between the initial water saturation level and t

p. (I)=Pnw-Pw= (Interfacial Tension)o-s or oW 1/R1 + 1/R2)This mechanism s pictorially illustrated in Fig. 2. Fig. 3illustrates how this mechanism s operative n low and highquality porousmedia and why capillary pressure nd retentioneffects are more significant in low vs high permeabilityformations.


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LOW PERMEABILITY GAS RESERVOIRS:PROBLEMS, OPPORnJNmES & SOLU110NSFOR DRILLING, COMPLE110N, SllMULA TlON AND PRODUCllON SPE 35577

irreducible saturation level (where the capillary pressure curvebecomes vertically asymptotic). In a properly designedoverbalanced operation the use of appropriate bridging andfilter cake building agents can establish a near zeropermeability filter cake on the face of the formation whichmay impede spontaneous imbibition effects. In anunderbalanced drilling operation, if any free water saturationis present in the circulating fluid system, this is similar toestablishing a gas-water contact directly adjacent to thewellbore face and continuous countercurrent imbibition effectsinto the formation can occur, even when a continuouslyunderbalanced condition is maintained. The problem withaqueous invasion is attenuated if the underbalanced conditionis lost or periodically compromised, or if a well drilledunderbalanced is hydrostatically killed for completion, due tothe fact that there is no protective filter cake to impede thelarge scale invasion of fluids into the formation in anoverbalanced condition. Laboratory studies describing thisphenomena are presented in detail in Ref. 4.Mud Solids Invasion. The physical invasion of natural and

artificial solids may occur during drilling, completion,workover or kill treatments if operating in hydrostaticallyoverbalanced conditions. Due to the very small pore throatsnormally associated with low permeability gas reservoirs, anysignificant depth of invasion of mud solids into the rock is notnormally observed (unless fractures or extremely small solids,which can sometimes be generated by PDC bits, are present).Once again, this is usually only a concern in situations whereopen hole completions are contemplated due to the shallownature of the damage.Glazing. Glazing, mashing or wellbore polishing can be aproblem in some open hole tight gas completions, particularlyif pure gas is used as the drilling media. Due to the extremelypoor heat transfer capacity of gases, f no fluid is present in thecirculating drilling media, extremely high rock-bit temperaturescan be generated. This can result, when combined withconnate water and rock dust generated from the drilling processin conjunction with high temperatures and the polishing actionof the bit, in the formation of a thin but very low permeabilityceramic pottery like glaze on the face of the formation. Thisphenomena can be observed on the face of sidewall cores cutin such situations and on the face of air drilled core. Likemud solids invasion, due to it's extremely localized depth,glazing tends to be problematic specifically in open holecompletion scenarios. Mashing, caused by poorly centralizedstrings and tripping, refers to mechanical damage caused byfriction and motion of the string and centralizers, collars etc.,against the formation face and results in the intrusion of apaste ike layer of fmes and drill solids into the formation facedirectly adjacent to the wellbore. Once again, a localized formof damage usually problematic only in open hole completions.

Rock-Fluid Interactions.Clays. The low permeability associated with many tight gaformations is generally caused by small grain size insandstonesor limited intercrystalline porosity development incarbonates,but in some formations, predominantly clastics, thepermeability is also reduced by significant concentrations oclay. A variety of different types of clay can be present.Highly fresh water sensitive expandable clays such as smectiteor mixed layer clays can occur in shallower tight gaformations. Examples include the Viking, Basal ColoradoBelly River and Milk River formations in Western CanadaWhen contacted by fresh or low salinity water these claysexpand in size due to substitution of water into the clay lattice(Ref. 6). The physical expansion of the clay (up to 500%depending on the type of clay under consideration) can resulin near total permeability impairment. Other types of claysuch as kaolinite are susceptible to electrostatic deflocculation(Ref. 6), where abrupt changes n salinity and pH can cause hclay to disperse and migrate to pore throat locations where ibridges, blocks and can cause permanent reductions inpermeability (Cardium, Belly River, Glauconite, Halfway,Bluesky, Basal Quartz, Gething, Ostracod, Viking, Rock Creeand Monmey are some formation types in Western Canadwhere this phenomena has been observed). Since filtrateinvasion can extend a significant distance into the formation ifluid losses are appreciable, this type of damage may be osufficient radius of penetration to partially impair thproductivity of limited scale subsequent fracture treatments icertain situations. If fresh water sensitive or reactive clays arpresent, care should obviously be taken to use inhibitive fluidsor low f luid loss systems to minimize the depth of invasion.Chemical Adsorption. Physical adsorption of high moleculaweight polymers or oil wetting surfactants can reducpermeability significantly in low quality formations opreferentially elevate permeability to water if a free watesaturation is present in the formation. The relative size of thlarge polymer chains, when adsorbed on the surface of thporous media, is significant in comparison to the relativdiameter of the pore throats allowing gas to flow from thmedia. Thus a film of adsorbed polymer, which may onlmoderately reduce the permeability in a higher qualitformation, can totally occlude available permeability in a lowequality zone. Once again, this is a wellbore localizephenomena. Adsorbed polymer can often be removed usinoxidizing agents, but care should be taken to ensure thainvasion of the oxidizing agent, and subsequent entrapmendoes not occur when the sealing effect of the polymer filtecake is degraded by oxidant contact.Fines Migration. Fines tend to move preferentially in thwetting phase and hence when only gas is flowing migratioof particulates in the porous media should be minimizedProblems can occur when fluid invasion occurs due trelatively high spurt losses potentially encountered during thdrilling or fracturing process, due to motion of invaded fluid


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D.B. BENNION, F.B. mOMAS, RF. BIETZ $PE35577during high drawdowncleanupoperations, r if the formationproducesiquid at ratesabove he critical migration rateduringunderbalanced rilling operations.Fluid-Fluid Interactions. Problems with fluid-fluidincompatibilities would include the formation of insolublescalesor precipitatescausedby adverse hemical eaction ofinvadeddrilling or completion luid filtrates and n-situ water.The potential for stable emulsion formation also exists ifhydrocarbondrilling and completion fluids are used, or ifwater based luids are used in formations which contain aninitial irreducible liquid hydrocarbon saturation. Acidcompatibility issuesmay alsobe apparentf acid s used n thepresence f an immobile liquid hydrocarbonsaturation.

modelling, plus considerable field experience, has indicatedthat this is not the case in many reservoir situations. Thesmaller the size and effective cross sectional area of thefracture treatment, the more significant the damage occurringon the frac face in impairing the ultimate productivity of thfrac treatment. Large, (100-200 tonne for example) fracs, catolerate a significant amount of permeability impairment on thefracture face, perhaps in excess of 95%, without appreciablyreducing the productivity of the frac. A permeability reductionof 100%, however, cannot be tolerated. Some of the damagmechanisms mentioned previously, particularly fluid retentionare capable of causing 1000/0permeability reductions in tightgas formations and have been the result of significanreductions in well productivity. Companion tight gas well fracof identical size (150 tonnes) have been placed in tighformations in the Permian basin in identical quality pay withthe only variable being the break time and rheology of thcross linked water based fracture fluid used. When thcrosslink was preserved to propagate the frac, followed bsubsequentbreaking, lab tests indicated a fracture face invasiodepth into this 0.01 mD, 12% SWj ormation of less than 2 mmwith over 80% fluid recovery in the field and 7,000,00scf/day flow rates. Wells in which premature breaking of thfrac fluid occurred exhibited over 6 cm of invasion in the labless than 10% fluid recoveries in the field and uneconomic posfrac flow rates of less than 50,000 scf/day.For this reason, fracture fluid compatibility, from both potential invasion depth and retention point of view, as well afrom a chemical and mechanical point of view must bcarefully considered to ensure that, not only can a viable frabe propagated, but that invasion into the formation at the higdifferential pressure gradients occurring during all fratreatments, particulary in pressure depleted formations, minimized. If invasion does occur to a limited extent camust be taken that the invading fluids are compatible with thformation and designed with maximum ease of recovery imind.S. Formation Damage During Kill/Workover Treatments.Mechanisms of damage to perforated, open hole or fracturewells that can occur during hydrostatically overbalanced kill oworkover treatments are similar to those described previouslfor drilling and completion. Damage and invasion may bmore severe in these cases as, similar to an underbalancedrilling operation, these formations lack any type of protectivor sealing filter cake to prevent wholesale invasion of thwater or oil based kill/workover fluid. so a significant amouof fluid invasion and damage may be incurred before hydrostatic kill condition is achieved.

4. Formation Damage During Fracturing of Tight GasFormations. The majority of tight gas fonnations, by theirnature, equire hydraulic or acid fracturing in order o obtaineconomically viable production rates. Although it has beensuggested y various authors hat fracture acescan olerateahuge amount of damage and that the productivity of thetreatment s still limited by the amountof fractureconductivitypresent, here is significant lab and field evidencepresent oindicate that formation damage occurring during fracturingtreatmentss still a major issue. If we consider actorswhichmay inlpair the productivity of a fracture treatment, thesewould include;- Physicalmechanicalproblemswith the fracture reatment- Fonnation damage o the high conductivity fracture tself- Formation damage o the fracture acePhysicalproblems with the racture treatment Thesewouldinclude such problemsas poor mechanicalpropagationof thefrac, sandoffs, racturing out of zone or channelling behindcasing,etc.Formation damage o the high conductivity racture itseltNo matter how large he treatment, f a very high conductivityfracturechannel s not maintained,particularly f permeabilityis lost in the portion of the fracture directly adjacent o thewell, the benefit of hydraulic fracturing is severelycompromised. A variety of mechanisms can result inimpairmentof the penneability of fractures n proppedor acidfracture reatments, ncluding- nlproper breaking of linear or crosslinkedgels-polymer adsorptionand entrainment-entrainmentof produced ormation fines/solids n

the fractures-emulsion blocks in the fractures- compactionof the fractureand embedment ffectsassociatedwith plastic formations and increasingoverburdenpressuresduring the depletion process- physical production of proppant from the high conductivityfracturecausinga loss n fracture conductivityA common misconception s that fracture treatments areinlpervious to formation damageon the fracture face itselfduring the fracture treatment and it is only the fractureconductivity which must be maintained. Mathematical

6. Formation Damage During Production OperationsPotentialdamagewhich could occur during nonnal productiooperationsof tight gas formations nclude;-Physical mes migration-Retrograde condensatedropout phenomena (rich gas system


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7B. BENNION, F.B. rnOMAS, R.F. BIE1ZSPE3SS77appropriate luid additives o prevent osses o the formationunder hydrostatic overbalance onditions. The use of crosslinked fracture luids with appropriatebreakerpackages nd asrapid recovery times as possible after fracturing, foamedsystems r poly-emulsions houldbe consideredf waterbasefrac fluids are considered.

andproduction. This sectionattempts o identify drilling andcompletion practices which may be useful in tight gasscenarios,as well as remediation echniques or wells withexisting damage.Fluid trapping/retent ion problems. This is a majormechanism of damage in many tight gas reservoirs. If weconsider methods of minimizing the impact of this type ofdamage, they would include:A void the introduction of water based fluids into theformation during the drilling and completion operation intotality. This would include straight gas drilling or the use ofhydrocarbon based drilling and completion fluids. Oil basedfluids may also phase trap to a certain extent in the formationand reduce permeability, but due to the fact that the liquidhydrocarbon will generally be the non-wetting phase in mostgas reservoirs, where no pre-existing liquid hydrocarbonsaturation is present, the physical amount of trapping of thehydrocarbon phase may be significantly less than would beencountered if water was used in an equivalent situation and alarge increase in gas phase relative permeability may beapparent. This phenomena is illustrated in Fig. 9. If a pre-existing liquid hydrocarbon phase saturation is containedinitially within the porous media (as is common in manyMontney, Rock Creek, Ostracod, Gething, Viking and Cardiumformations) it is possible that the formation may be partially ortotally wetted by the hydrocarbon phase, or the small pre-existing hydrocarbon phase saturation may act as a spontaneousadhesion site to trap additional hydrocarbons. In these types ofreservoirs, oil based fluids may not be advantageousover waterbased systems as they may have equal or more trapping anddamage potential. The use of straight CO2 or highly CO2energized hydrocarbons has been successful as a frac fluidmedium in some reservoirs of this type as an alternative towater. Alcohol fracs (i.e. gelled methanol) have been usedwith success n some situations. Care must be taken with theuse of alcohol in very low 0.1 mD) formations as adversecapillary pressure effects can also physically trap the alcohol.Low molecular weight alcohols, such as methanol, have a verylow degree of miscibility with liquid hydrocarbons and canoften suffer from incompatibility problems with respect tosludge formation with many crude oils. For these reason, theiruse should be avoided in most situations where a liquidhydrocarbon saturation is known to exist in the reservoir infavour of higher molecular weight mutual solvents (i.e. - IF A,EGMBE) which exhibit significantly greater miscibility withliquid hydrocarbons and fewer compatibility problems.If water based fluids must be considered for technical oreconomic reasons, nvasion depth should be minimized to themaximum extent possible to avoid significant aqueous phaseretention problems. For drilling fluids this would includeminimization of overbalance pressure, f possible, and rheologyand bridging agents, if appropriate, to eStablish a protectivefilter cake to act as a barrier for significant fluid loss into theformation. Kill or workover fluids should be designed with

Remediation of fluid retention problems. A numberof basiapproaches an be taken to removing existing phase rapsthesewould include:1. Increasing capillary drawdown. Trapped saturation s adirect function of applied capillary gradient, the higher theavailable capillary gradient, the lower the obtainable watesaturation. Therefore, in the absenceof fines migrationproblems, water coning potential or retrograde condensadropout potential (rich gas systems) he higher the drawdowpressurewhich can be applied across he phase rappedzonethe lower the water saturation which will be able to bobtained. In a practical application,unless he invasion deptof the infiltrated aqueous phase is very shallow, or threservoir pressure s extremely high, due to the verticallyasymptoticnatureof most gas-liquid capillary pressure urvenear the irreducible saturation,extreme drawdown gradientwhich cannotbe realized n most normal field applications, rrequired o obtain an effective reduction n the trapped iquidsaturation. For this reason his method doesnot tend to be ogreat efficacy in most situations.2. Reduced1FT between he water-gas or oil-gas systemCapillary pressure,which is the prime mechanism or thentrapmentof the oil or water based luid within the porsystem, s a direct linear function of the interfacial tensio(IFf) between he trappedphaseand he gas n the bulk of thpore space Equation 1). If some means can be found treduce he 1FT between he gas and liquid phase, hen at thavailable eservoirdrawdown t may becomeeasier o mobilisand producea portion or all of the entrapped luid. A varieof treatments re available o reduce he 1FT n situationssuas this:a) Chemicalsurfactants avebeenused n somecases, ut duto the disparatemolecular nature of gas and liquids, it difficult to find liquid soluble chemical surfactantswhich aeffective in obtaining the multiple orders of magnitureduction in 1FT (from say 70 to 0.1 dyne/cm) required order to effectively mobilize a significant amount of trappfluid from the system.b) Mutual solvents, such as methanol or higher molecuweight alcoholsor materialssuchas EGMBE can significanreduce1FT betweengas and liquid and are mutually miscibin the trapped iquid phaseand tend to reduceviscosity aincreasevolatility and vapour pressureextractive effectsremove a portion of the trapped liquid. As mentionpreviously, careful selectionof a mutual solvent s importato ensuremiscibility and compatibility if a liquid hydrocarbsaturation s presentwithin the porous media.c) Liquid carbondioxide hasbeenused or aqueous hase ra


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LOW PERMEABILnY GAS RESERVOIRS:PROB~, OPPOR11JNmFS &. SOLU11ONSFOR DRIWNG, COMPLrnON, SnMULA 1l0N AND PRODUcnON SPE3SS7

due to its ability to reduce 1FT, dissolve in the trapped liquidphase, physically extract a portion of the trapped water as adesiccant and provide a zone of localized high reservoir energyto obtain a high instantaneous capillary gradient on blowdownwhich might not normally be present in the fonnation(particulary in low pressure zones).d) Liquid CO2, LPG, Liquid ethane and dry gas have all beenused as techniques to remove hydrocarbon traps in porousmedia. Depending in the available treatment pressure,temperature and gravity of the trapped hydrocarbons, one ormore of these liquids will often be miscible with the entrappedhydrocarbons. The treatment is designed to either misciblydisplace the trapped hydrocarbon a sufficient distance into theformation so that cross sectional flow area is increased to theextent that the zone of trapped fluid does not substantiallyreduce productivity, or produce the hydrocarbon saturatedliquid back out of the fonnation at sufficient backpressure tokeep the extracted hydrocarbons in solution to physically"scrub" a portion of the fonnation adjacent to the wellbore orfracture face clean of entrapped hydrocarbon. High treatmentpressures are required for this treatment to be effective withconventional dry gas (natural gas or nitrogen) injection,generally in excess of 35 MPa. The treatment may beeffective at much lower pressures (8 - 20 MPa) with gasessuch as liquid CO2 or ethane, and at very low pressure (3- 5MPa) with very rich low vapour pressure gases such as LPG.In the case of a retrograde condensate rap, the treatment maybe of only temporary utility as, if the well is continued to beproduced in a high drawdown condition, further entrapmentwill occur as additional condensate is retrograded as the gascontinues to be produced from the well.3. Physical chGllges ill the pore geometry. Since capillary

pressure is also a direct function of the radii of curvature ofthe immiscible interfaces which are present in the porousmedia (Eq. I), which are forced by the geometry of theconfining porous media (Fig. 3), if the radii of curvature canbe increased, by making the pore spaces less constrictive,capillary pressure will be reduced and it may become possibleto mobilize the trapped fluid. While generally difficult toaccomplish in clastic fonnations, unless HF acid is considered,this can be accomplished in some cases n tight carbonateswithappropriate acid treatments. These stimulation treatments,however, are in some respects the proverbial "two edgedsword" in that when the acid spends we simply have morewater in the fonnation. If the spent acid is squeezed past thezone of effective reaction, it may become entrapped like anyother invaded aqueous fluid and, in some cases, aggravate theproduction problem it was intended to cure. This is evident inmany acid squeeze reatments in tight gas reservoirs where acidrecoveries have been exceptionally poor and well productivityhas often been further impaired, rather than improved, by theacid treatment. The use of nitrified or foamed acids has beenuseful in some situations of this type as the total volume ofliquid introduced into the fonnation is reduced and localized

charge energy to recover the acid is inttoduced into theformation by the gaseous agent (often COJ used to foam thacid. Caution is required in implementing this procedure treduce a hydrocarbon trap, as many acids are incompatiblewith hydrocarbons and de-asphalting or the formation of stabemulsions, particularly in the presence of high concentrationof unsequestered ron, could occur.4. Direct physical removal of the trapped watn o

hydrocarbon saturation. This encompassesa rather wide rangeof potential techniques which include:a) Dry gas injection. A common misconception is that merelflowing the reservoir gas for an extended period of time wilresult in evaporation and removal of a portion of the trappewater or hydrocarbon saturation. Since the produced reservogas s saturated with both water vapour (in all cases) and heavhydrocarbons (for a rich gas reservoir) at reservoir temperaturand pressure conditions as it passes by the trapped liquid, can be seen that no additional water or hydrocarbon could beffectively absorbed into the gas phase. If pressure can belevated significantly, some hydrocarbon liquid marevaporize, but this is obviously much easier accomplished ian injection rather than a production scenario. Drydehydrated, pipeline spec gas injection will result in thgradual desiccation of a portion of the reservoir directladjacent to the injection zone, a phenomena well known imany gas storage wells. The objective of a dry gas injectiotechnique is to inject dry gas for a short period of time (3 t10 days at I to 3 MMscf/day typically) to attempt to dehydrasome of the higher conductivity channels in the reservoir anestablish a conductive flow path to the bulk of the undamagereservoir. The technique is relatively easy to apply and haparticular application in damaged horizontal wells where largexposed pay zones may render other types of penetratintreatments impractical. Dry gas njection has been successfulcombined, in some situations, with mutual solvents such amethanol to increase the potential extractive power of thtreatment. Variations of the procedure would include the usof alternative dry gases such as nitrogen, oxygen contereduced air, dehydrated flue gas or carbon dioxide. Figure 1provides a schematic illustration of the dry gas injectioprocess. If highly saline brine is the trapped phase (i.e. weighted drilling, completion or kill fluids or spent acidlaboratory investigation of this technique is often warranted precipitation of the soluble salts from solution as evaporatiooccurs in the pore system can result in significant residupermeability impainnent which may counteract the benefit the removal of the trapped water saturation.b) Formation heal treatment. This is a relatively neexperimental treatment which has been specifically designed remove both aqueous phase traps as well as thennalldecomposing potentially reactive swelling or deflocculatabclays (Ref. 10). The treatment is applied using a specialdesigned coiled tubing conveyed downhole treating tooElectrical heaters in the downhole tool are used to he


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O.B. BENNION, F.B. mOMAS, R.F. BIE'JZPE35577straightgasdrilling, or using a hydrocarbonbased luid as hedrilling fluid medium (if the formation is water-wet). Sincehydrocarbon s the non-wetting phase, no impetus will bepresent for spontaneous mbibition to occur. If theunderbalancepressureondition s compromised,nvasionandtrapping of the hydrocarbonbased luid could still occur andbe problematic.

nitrogen, injected down the CT string, to very hightemperatures which is then subsequently injected directly intothe fonnation. If downhole temperatures can be elevatedaboveSOOOC, upercritical olatilization of water, egardless fthe reservoir pressure, occurs as well as partial or total thennaldecomposition and desensitization of reactive clays. In lab teststhe technique has resulted in over 10 fold improvements inpenneability in damaged zones. The technique has particularapplication to relatively shallow tight gas reservoirs wherevertical wells penetrate thin, highly damaged sand layers.Treatment area s generally approximately two metres in lengthby I to 2 metres in radius in a single application. The mostcommon application is potentially stimulating secondary targetgas zones which were badly damaged using conventional waterbased fluids when targeting deeper primary zones. Fig. 11provides an illustrative schematic of the FHT process.c) Localized Combustion. This has been a method suggestedto remove hydrocarbon phase raps in tight gas. The techniqueinvolves short tenD air injection. If downhole temperature issufficient, spontaneous ignition will occur, com busting thecondensatesaturation whi Ie simultaneously generating ocalizedheat which may also vaporize a portion of the trapped connatewater saturation and thennally decompose reactive clays.Wellbore flashback effects and extreme potential corrosionconcerns are potential problems associated with the use of thismethod.d) Time. Nature abhors a steep capillary gradient. Thus, whena zone of high water saturation is induced into a water-wetfonnation, natural capillary action will tend to have adispersing effect in gradually imbibing a portion of the watersaturation away from the wellbore or fracture face. Thisphenomena is illustrated in Fig. 12. Due to the limitations ofthe capillary imbibition, the water saturation in the flushedzone will only be able to imbibe down to the irreduciblesaturation dictated by the capillary geometry of the system,therefore a significant residual aqueous phase trapping effectmay still be apparent. This phenomena has been observed inmany caseswhere tight gas wells have been drilled, tested andsubsequently shut in or abandoned. After an extended periodof t ime some of these wells have been retested and producedat- order of magnitude or more greater rates that observedinitially. Production of the well obviously counteracts, to anextent, this phenomena and may slow the speedof this process.

Mud Solids Invasion. As mentioned previously, this igenerally only a significant problem if an non-stimulated opehole completion is contemplated for the well undeconsideration. If this is the case, care must be taken in thdesign of the drilling fluid to ensure that significant invasioof solids into the formation does not occur. In general solidlarger than about 300/0of the median pore throat size will noinvade a significant depth into the formation. Due to the smapore throat size associated with most tight gas reservoirsnatural exclusion of the majority of artificial (barite, bentonitebridging agents, natural drill solids, etc.) occurs. Pore sizdistribution data (and fracture aperture sizing if fractures arpresent) should be obtained in this type of situation to allowmud engineers to ensure that the expected size distribution osolids present in the fluid system are appropriate to avoiinvasion.Due to the very small pore throat size, nonnal mud solids atoo large to form a low permeability sealing filter cake in molow permeability gas reservoirs. This results in the solidbeing retained from invading into the fonnation, but becauthe filter cake is relatively coarse (in comparison to the smapore throats the cake is attempting to block) a considerabamount of fluid seepage nto the pore system can still occuwhich can initiate a damaging phase trap or other fluid-fluidincompatibility problems. Proper sizing of the suspendparticulate matter can generate a much lower permeability filtecake than would be obtained using naturally occurring solidand can act as an efficient barrier to damaging filtrate invasioSizing criteria vary depending on the system, but would rangfrom 10-40010 f the pore throat size for matrix systems an10-100% of fracture aperture for fractured reservoirs. Specifsize distribution for a fluid bridging agent can generally onbe quantified after a detailed evaluation of the system undconsideration.Underbalanced drilling may also be considered as a techniqto prevent this type of damage if a heterogenous formatioexists where formulation of a single fluid system with effectivbridging characteristics is impractical.Countercurrent Imbibition. Countercurrent imbibitionproblems during underbalanceddrilling operations can be

minimized by increasing the magnitude of the apparentunderbalance pressure to act as a greater deterrent toimbibition. If a significant differenceexistsbetweenhe nitialand rreduciblewater saturations, owever,suchas n the caseof many tight gas reservoirs, this technique is generallyinsufficient to counteract the extremely adverse capillarypressure radientspresent n the porousmedia f a water basedfluid is used. Better results are obtained n situationssuchasthis by avoiding the use of water based luids through either

Glazing. Classic glazing in generally motivated by heassociatedwith pure gas drilling operations n open holcompletions in uniform, low permeability clastics ocarbonates.Glazing can generallybe avoidedby the inclusioof a small amountof compatible luid (i.e. mist drilling) in thsystem o increase ubricity and heat ransfer rom the bit.


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LOW PERMEABllJTY GAS RESERVOIRS:PROBLEMS, OPl'OR11JNmES &. SOLlmONSFOR DRIlliNG, COMPLE110N, S11MULAll0N AND PRODUCfiON SPE3557

2000 metres,dependingon tubing/casingsize)Kill/Workover Treatments. Many wells have been drilledwith great carepaid to fonnation damage,only, at some aterdate, o havepoorly conceived ill jobs conductedwhich werevery effective n achievingnot a only temporarybut pennanenwell control results. Water-based ill fluids generally reacpoorly in most tight gas situations and significant invasiongenerallyoccursdue to the unprotected ature of the fracturefaces or open hole wellbore after production has beenoccurring for some period of time. Oil-based fluids withappropriatebridging agentsmay be a better choice for killagents n some situations. Careful care with respect thecomposition, heology, bridging character, ilter cakebuildingpotential and removability should be taken n kill fluid designin a manner similar to designing a drilling fluid. In manycaseshe useof CT or snubbingequipmentmay be viable andthe workover or recompletioncan be conductedwith the wellin a live mode, underbalanced,o avoid significant additionadamageeffects.

Rock-Fluid and Fluid-Fluid Interactions. Initial analysis ofthe fonnation to investigate the presence of any potentiallyreactive clays (smectite, mixed layer clays, mobile kaolinite),is essential in tight gas reservoirs. This is generally conductedusing a combination of thin section, XRD and SEM analyses.If reactive clays are present, this should act as a warning flagfor the use of fresh or low salinity water in most situations.Detailed compatibility testing should be conducted, if waterbased fluids are to be used, to quantify inhibitors (i.e. - KCI,CaCI2, etc.) which may Stabilize reactive clays if invasion doesoccur. Chemical Stabilizers (i.e. - high molecular weightpolymers), while potentially efficient at stabilizing reactive andmobile clays, often may cause more damage due to physicaladsorption of the polymer on the rock surface which mayocclude the minuscule area available for flow in tight gasfonnations and hence should only be used after detailed labevaluation has been conducted to ascertain their usefulness anddegree of damage that they may cause.Similar tests should be conducted between potential invadingfiltrates and fonnation fluids to ensure hat they are compatiblewith respect to scale, precipitate or emulsion fonnation within-situ water and liquid hydrocarbons which may be present inthe porous media. If acid treatments are to be used inreservoirs which contain a trapped liquid hydrocarbonsaturation, compatibility tests to ensure that asphaltenes,sludges and emulsions do not fonD between the acid and thein-situ oil should be conducted. Rock solubility tests shouldalso be conducted in this case to ensure that a largeconcentration of insoluble fines (i.e. - quartzose rockfragments, pyrobitumen, anhydrite, etc.) are not released byacidization and allowed to subsequently be squeezed deeperinto the fonnation where they may reduce penneability.

Production Problems. A large majority of productionproblems with tight gas reservoirs, including fines migrationretrograde condensate dropout and solids precipitation are aassociatedwith large pressure drops or rates associatedwith thelow permeability nature of the reservoir. Means of reducinrate or pressure drop, including physical rate reduction or aincrease in flow area by horizontal drilling, open holecompletions or fracturing are the best techniques to counteracthese problems.Dual completions using downhole ESP's to pump off water iwet zones can prevent the premature coning of water in somgas reservoir situations, which may have adverse relativepermeability and fmes migration effects.Solids precipitation problems are difficult to prevent, beininherent to the nature of the produced gas itself. But can ofte

be minimized by judicious selection of the correct downholoperating temperature and pressure and the selective use of variety of chemical inhibitors or treating agents (solidprecipitation inhibitors, organic solvents, crystal modifiersetc.). Detailed work has also been conducted recently iinsulated and heat traced tubing, coupled with detailenumerical wellbore heat loss models for paraffin deposition, toptimize the production of deep waxy retrograde condensagas reservoirs.Canadian Formations Susceptible to Various Tight GasDamage Mechanisms. This section provides an incompletsummary of a number of low permeability formations inCanada hat have been investigated recently for tight gadamagemechanismsn the lab and the field. The results arsite specific and can, of course,vary regionally with reservoquality and saturation onditions,but provide some dea of thetype and scope of this problems in some common field

Fracturing Operations. Detailed modelling andgeomechanicalmeasurementsan be undertaken o attempt oensure hat the mechanicalpropagationof hydraulic and acidfracturing reatments reacceptably chieved. Fluid retention,particularly water retention, s a significant problem in manytight gas fracturing operations. A variety of techniqueshavebeenutilized to attempt o reduce luid losses o the formationin situationswherewater rapping s problematic ncluding heuseof pure oil fracs,CO2energized il fracs,crosslinkedwaterbased racs, poly-emulsion racs and water based oam fracs.The selectionof the appropriate luid will be highly dependanton the size of the frac, formation characteristics nd phasetrapping potential and available drawdownpressure.In formationswhich contain a pre-existingoil saturationandwhich may (or may not be) oil-wet, oil based luids may reactas adverselyor worse than water. Pure CO2 fracturing hasbeenusedsuccessfully n some ormations of this type (i.e. -Rock Creek, Ostracod, Gething, Montney), but obviouslimitations exist with respect o the size of frac which can beeffectively propagated generally less than 20 tonnes withCurTentechnology)and depth constraints generally ess han


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D.B. BENNION, f B. nIOMAS, R.f. BIE1ZPE35577 IIapplications n Canada.Nornenc88tureCCI = CountercurrentmbibitionFFI = Fluid-Fluid Interactions (precipitates, scales,

emulsions,acid incompatibility)PM = Fines MigrationGL = GlazingMI = Mud Solids InvasionRFI = Rock-Fluid Interactions reactiveclays)OR = Oil Retentionpp ~ Production Problems (Condensatedropout, solidsprecipitation)WR = Water Retention

include understanding he wettability and initial saturationconditions of the reservoir and then minimizing invasionthrough he use of gas or gas energized luids, ultra low fluidloss conventional systems or underbalanceddrilling andcompletion echniques.4. Significant damage an occur during fracturing treatmentin tight gas due to improper fluid selection or mechanicaproblemswith the frac. Fluid retentionnear he frac facesandfracture permeability impairment are major damagmechanismsn these ases.The smaller he fracture reatmenthe more significant the effect of frac face damage onproductivity. In some casesoil based,gas energizedoil orpure CO2 fracs have proven useful in minimizing damageSuccess as also beenachievedwith very low fluid loss croslinked water based el systems n somevery low permeabilitformations which were highly susceptible o fluid retentioneffects.5. Reducingdrawdown atecan esult n minimizing problemwith retrogradecondensation,water coning, fines migrationand a variety of solids precipitation problems. This can beaccomplished y reducingproduction ate, or more commonlyby increasing cross sectional flow area by open holecompletions,horizontal drilling or fracturing.AcknowledgmentsThe authors wish to express appreciation to the Hycal EnergResearch Laboratories for the database o publish this papeThanks also to Maggie Irwin and Vivian Whiting for theassistance n the preparation of the manuscript and figures.

Formation Name and Potential Damage MechanismSusceptibilityBakken- WR, GL, CCIBaldonnel- WR, OR, MI, CCI, FFIBasalColorado WR, OR, MI, GL, RFI, PMBasalQuartz- WR, OR, MI, GL, RFI. PM. ppBelly River- WR, MI, GL, CCl, RFl, FMBluesky- WR, MI, GL, CCI, RFI, PMCadomin WR, MI, GL, CCI, RFI, FMCadotte- WR, MI, GL, CCI, RFI, FMCardium- WR, OR, GL, CCI, RFI, FMDoig - WR, GL, CCl, RFI, FMGething- WR, OR, GL, CCI, RFI, FMGlauconite- WR, GL, CCI, RFI, FMHalfway- WR, OR, GL, CCI, RFI, FM, PPJeanMarie - WR, GL, CCI, RFI, FFIMedicine Hat - WR, GL, CCI, RFI, PM, PPMilk River - WR, GL, CCI, RFI, FM, PPMoomey- WR,OR. GL, CCI, RFI, FM, PPOstracod- WR, OR, GL, CCI, RFI, FM, PPPaddy- WR, CCI, RFIRock Creek- WR, OR, MI, GL, CCI, RFI. FM, PPTaber - WR, GL, CCI, RFI, FMViking - WR, OR, GL, CCl, RFI. PM. PPWhiteSpecks WR, OR, GL, CCI, RFI

References1. Bennion, D.B., Thomas, F.B., Crowell, E.C., Freeman, B"Applications For Tracers n ReservoirConformancePredictionand Initial SaturationDeterminations",presentedat the 1995 I-Annual International Conference on Reservoir ConformancProfile Control Water & Gas Shutoff, August 21-23, 199Houston, Texas.2. Bennion, D.B.; Cimolai, M.P.; Bietz, F.R.; Thomas, F.B"Reductions n the Productivity of Oil and GasReservoirsDue toAqueousPhaseTrapping., JCPT, November, 1994.3. Bennion,D.B., Thomas,F B., Bietz, R.F., Bennion, D. W. "Wateand HydrocarbonPhaseTrapping in Porous Media- DiagnosisPreventionand Trcabnent., CIM PaperNo. 95-69 presented t th46th Annual Technical Meeting at Banff: Alberta. May 14-11995.4. Bennion, D.B., Thomas, F B. "Underbalanccd Drilling oHorizontal Wells- Does t Really Eliminate Formation DamagePaperSPE27352 presented t the 1994 SPE Formation DamaSymposium,Feb. 9-10, 1994, Lafayette, Louisiana.5. Bennion, D.B., Thomas, F B., Bietz, RF.. Bennion, D.W"Underbalanced rilling, Praises nd Perils", presented t the firinternationalUnderbalancedDrilling Conferenceand ExhibitionThe Hague,Netherlands,Oct. 2-4, 1995.6. Bennion,D.B.; Bennion,D.W; Thomas,F B.; Bietz, R.F. "InjectioWater Quality: A Key Factor o SuccessfulWaterflooding", PapCIM 94-60, presented t the May 1994Annual Technical meetinof the PetroleumSociety of CIM.

Concklslons1. Significant reserves f natural gas and condensateiquidsexist in low permeability formations dtroughout the world.Good engineering and evaluation is required in order tounderstandhe nitial reservoirquality andsaturation onditionsand accuratelyassess, t the current level of technology, freserves exist and if those reserves are economicallyrecoverable.2. With advanced echnology gas has been effectively andeconomicallyproduced rom many tight gas formations withpermeabilitiesof less han 0.1 mD.3. Tight gas formations are very susceptible o formationdamage.Fluid retention is a major mechanismof damage nmanyof these ituations. Meansof minimizing damage ffects


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LOW PERMEABIUIY GAS RFSERVOIRS:PROB~, ~TUNmFS &. SOLU1l0NSFOR DRIWNG, COMPlEnON, SnMULA110N AND PRODUcnON SPE 35577

7. Eng, J.H., Bennion, D.B. and Strong, J.B.: "Velocity Profiles inPerforated Completions," Journal of Canadian PetroleumTechnology. October 1993) pp 49-54.8. Thomas, F.B., Bennion, D.B. and Bennioo, D.W. "Experimentaland Theoretical Studies of Solids Precipitation From ReservoirFluids," Journal of Canadian Petroleum Technology, January1992).

9. Thomas, F.B., Bennion, D.B., Bennion, D.W. and Hunter, B.E."Solid Precipitation From Reservoir Fluids: Experimental andTheoretical Analysis," Paper presentedat 10th SPE TechnicalMeeting, Port of Spain, Trinidad and Tobago (June 27, 1991).10. Jamaluddin,A.K.M., Vandamme,L.M., Nazarko,T. W., Bennion,D.B. "Heat Treatment or Clay-RelatedNear Wellbore FormationDamage",presented t the 46th Annual Technical Meeting of thePetroleumof CIM in Banff, Alberta, Canada,May 14-17, 1995.81 Metric Conversion Factors1m = 0.3048 ft.IMPa = psi


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