Schowalter 1982 Show Interpretation 13020

8/13/2019 Schowalter 1982 Show Interpretation 13020

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Ihf -XniL'ricaii Associaiion of Petroleum Geologisis BulletinV *>6.No (St:PTEMKFR 1982). P. 1302-1327, 22 Figs,, 4 Tables

Interpretation of Subsurface Hydrocarbon Shows'TIM T. SCHOWALTER^ and PAUL D . HESS^

ABSTRACTHydrocarbons occur in the subsurface in four modes:(1) continuous phase oilorgas, (2)isolated droplets of oilor gas, (3) dissolved hydrocarbons, and (4) associatedwith kerogenousrocl


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Tim T.Schowalter and Paul D. Hess 1303can be used interchangeably. A quantitative estimate ofthe down dip oil-water contact in an oil field can be madeif the capillary prop erties, oil satu ration , oil-water inter-facial tension, oil-water densities, and hydrodynamicconditions are known. If subsurface saturations cannotbe calculated, estimates of the maximum and minimumoil column that must be present downdip from the wellcan be made by comparing the minimum oil columnrequired to explain a 10% saturation in oil or gas-saturated rocks and water-saturated rocks in the reservoir zone. This extrapolation of hydrocarbon show databeyond the well bore is useful in field development andexploration.

Shows in noncommercial wells can also be interpretedquantitatively. The minimum oil column necessary tomigrate hydrocarbons through the water-saturated porespace of any oil-saturated rock or to explain a given oilsaturation can be calculated based on the same principles(Smith, 1966; Berg, 1975; Schowalter, 1979). If the oilshow can be identified as a continuous phase oil occurrence, the show is directly associated with a trapped oilcolumn whose downdip limits can be estimated by thismethod.This paper is composed of two main parts. Part oneincludes the development ofashow classification and therecognition of show types. Part two reports case historyattempts to quantify the oil or gas column dow ndip fromoil and gas sho ws.

CLASSIFICATIONOF HYDROCARBONPHYSICALMODESOF OCCURRENCEAs stated in the introdu ction, oil or gas can occur in thesubsurface as: (1) continuous phase oil or gas in water-saturated porou s rock s; (2) isolated droplets of oil or gasin water-saturated porous rocks similar to waterfloodresidual oil or gas occurrence (hyd rocarbon residues arealso included in this group, which will be called residualoil shows for convenience); (3) molecular-scale dissolvedhydrocarbons; and (4) hydrocarbons incorporated inkerogen or directly associated with oil or gas sourcerocks. The physical modes for the convenience of classi-

MODE OFOCCURRENCE

ContinuousPha s o

R e s i d u a l

D i s s o l v e d

In Kerogen

S H O WT Y P E

1IIIIIIV

SI GNI F I IP r o d u c t i o nP r o d u c t i v e

Non

product ive

CANCEExploration

trappedoilmigrationpath

HCinsystemsourcerocl(

fication are referred to as type 1, type II, type III, andtype IV, respectively, in Figure 1. Any of these physicalmodes can be described during the drilling operation assubsurface hydrocarbon "show."A subsurface hy drocarb on show is defined as any indication of oil or gas observed while drilling or completinga well. The hydrocarbons can be directly seen in drillingfluids, in core or cutting samples, and in formation orproduction tests, or may be seen indirectly as "anomalies"on wireUne logs. Ea ch show type will be discussed asto the physical distribution of the hydrocarbons, howthis physical mode of occurrence can be manifested as ahydrocarbon show, and the production and explorationsignificance of each show type.

ShowTypesContinuous Phase Shows TypeI)

A continuous phase hydrocarbon occurrence is a filament of oil or gas with a continuous connection throughthe pore network of a water-saturated porous rock. Theminimum pore volume saturation of oil or gas needed toestablish a continuous hydrocarbon phase through thepore network of a water-saturated rock is approximately10% (Schowalter, 1979). Th us, the percent of pore volume saturated by hydrocarbons in a continuous phaseoccurrence can be as low as 10%; maximum saturationscan beashigh as90%. The ability ofoil or gas to flow in acontinuous phase mode of occurrence will depend on thepercentage of the po re space saturated by oil versus water(Arps, 1964). This relationship is referred to as relativepermeability and a typical oil-water relative permeab ilitycurve is illustrated in Figure2. In reservoir-quality rocks,continuous phase shows are thoug ht to represent trapped

FIG. 1Classification chart for subsurface hydrocarbonshows.W a t e r S a t u r a t i o n : P e r c e n t P o r e S p a c e

FIG. 2Typical oil and water relative permeability curves(after Core Laboratories).


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1304 S u b s u r fa c e H y d r o c a r b o n S h o wsaccumulations of hydrocarbons. Continuous phaseoccurrence may or may not be commercially produ ctive.Economic producibility will depend on the reservoirqualities of the rock, the depth, the oil saturation, andcorresponding relative permeability.

Residual Shows (Type II)Isolated droplets of oil or gas are referred to as type II,or residual shows, in the classification. Water displacement residual hydrocarb ons are isolated droplets ofoilorgas in the pore s of a rock like those left in a depleted reservoir. Another type of residual show is a hydrocarbonresidue. Hydrocarbon residues include viscous films ofoil or oil-degradation products coating the grains ofrock, or solid to semisolid bitumen or oil (devolatilized,pyrolyzed, or otherwise degraded) in the pores. Hydrocarbon residues are immobile films or particles, whereaswater-displacement residuals are liquid or gaseoushydrocarbons.Water-displacement residual hydrocarbons can be created by: (1) oil or gas migration through a reservoir orcarrier bed, (2) remigration of hydrocarbons from atrapped accumulation, or (3) by the production of a conventional oil or gas reservoir. Water-displacement residuals occur as disconnected droplets of oil erraticallydistributed throu gho ut the reservoir. M any pores initiallyfilled with oil will contain no residual oil after water displacement. The mechanics of secondary hydrocarbonmigration and entrapment (Leverett, 1941; Ho bson ,1962; Schowalter, 1979) suggest that any granular rockthrough which continuous p hase oil or gas has m igrated,or in which it has been trapp ed, will have a residual saturation. Studies by reservoir engineers on waterfloodingof oil-saturated reservoirs have determined some basicfacts that relate to the interpretation of water-displacement residual shows. The percentage of residualoil saturation compared to various initial oil saturationsis illustrated for a typical water-wet sandstone reservoirin Figure3 .This curve shows that the percent of the p orespace occupied by the residual hydrocarbons will vary,depending on the initial sa turatio n. Th e greater the initialsaturation, pore characterist ics being constant, thegreater the residual. The minimum residual saturationthat can occur is somewhat less than 10%. Maximumresidual saturations range from 30 to 40% of the pore

volume for water-wet sandstone reservoirs and from 30to 60% for non-oomoldic carbonate reservoirs. Because

FIG. 3Typical initial saturation verses residual saturationcurve.

oil occurs in water-displacement residuals as isolatedtrapped immovable droplets, residual oil shows of thistype would have no relative permeability to oil or gas;only water should be able to flow toward the well bore iff lu id product ion tests are a t tempted. Water -displacement residual occurrences ofoilare not commercially productive by conventional petroleum operations.Hydrocarbon residues of droplet-scale viscous, orsolid, heavy hydrocarbons occur in rocks as coatings ongrains and as pore-filling material. Hydrocarbon residues are the result of bonding of hydrocarbons to solidmineral surfaces and/or the degradation of oil to animmobile viscous crude (e.g., by aerobic bacteria) or aburne d-out c arbonace ous residue . These surface films ofheavy hydrocarbons on the rock framework can resultfrom both chemical and physical bondings of hydrocarbons on solid mineral surfaces. Chemisorption occurswhen a chemical bond is formed between a hydro carbonmolecule and a mineral surface. An example of such abondisthe sorption of naphthenic acids on the basic mineral surface in limestones. Physical adsorption occurswhere surface active, polar hydrocarbons are adsorbedby intermolecular forces on a high-energy mineral surface (such as qua rtz) . These processes can produce a surface film of oil coating the grains in the larger pores of areservoir rock (Salathiel, 1972).

Transformation of crudes can also produce a viscousimmobile heavy hydrocarbon residue in the subsurface.G. T. Philippi (personal commun.) has demonstratedthat the phase separation of oil and gas at high pressureproduces a viscous asphaltic residue. Deasphalting, theprocess where asphaltenes can be precipitated out ofsolution from liquid oils as increasing am ounts of gasesare dissolved, can also produce an immobile asphalticresidue (Evans et al, 1971). Water washing and biodegra-dation can alter a liquid crude to an immobile heavyhydrocarbon residue (Evans et al, 1971). Thermal maturation of a crude oil can eventually produce a burne d out(thermally dead), or partially burned out carbonaceousresidue (anthraxolite). It should be noted that waterwashing, biodegradation, and thermal ma turation couldact on both w ater-displacement residuals and continuo usphase oil occurrences.Hydrocarbon residues have no relative permeability tooil as they occur either as isolated grain coatings or asimmobile globs of viscous oil. Oil saturation s for hyd ro

carbon residues would generallybevery low if the residueoccurs as grain coatings or water-displacement residualsthat have been degraded to heavyviscousoil or anthraxo lite.Molecular-ScaleDissolved Hydrocarbon Phase (Type III)

Molecular-scale dissolved or dispersed hydrocarbonsare separate hydrocarbon molecules occurring in solution in pore fluids or sorbed on the rock framework.Hydrocarbons dissolvedinpore waterT his mode ofoccurrence is probably very widespread in petroleumprov inces . Buckley et al (1958) ma de an extensive investigation of the amounts and kinds of hydrocarbons dissolved in Gulf Coast formation waters. A significant


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Tim T. Sch owa lterand Paul D. Hess 1305finding ofthisstudy was that appreciable concentrationsof dissolved hydrocarbon gases occur in the waters ofmost sampled formations. Furthermore, the water insome formations was found to be essentially saturatedwith dissolved gas. The quantities of dissolved gas foundranged up to 14 standard ftVbbl of water. Dissolvedhydrocarbons can be reported as mud-log shows, tripgas, gas-cut fluids, and gas bubbles in samples.

Hydrocarbo ns sorted on mineral or organicmatterIsolated hydrocarbon molecules can be bonded bychemisorption or physical adsorption to the solid co nstituents of a rock. This mode of occurrence is probablyimportant mainly in rocks rich in organic matter, sinceorganic matter has a higher sorption capacity for hyd rocarbons than the main inorganic sedimentary constituents. Sorbed hydrocarbons, particularly the gaseoushydrocarbons, can be released from clays and organicmatter by grinding action d uring drilUng. These gases arecommonly seen as shows in the drilling fluids (e.g., tripgas, mud-log anomaUes, etc).

Molecular-scale hyd rocarbo n shows do not satura te therock pore space and have no capacity to flow to the wellbore as a single phase fluid. The significance of theseshows is only that hydroc arbons are present in the rocksdrilled. They do not indicate anything a bout the presenceof bulk phase migrating hydrocarbons or trapped oil orgas accumulations.Hydrocarbons IncorporatedinKerogen TypeIV)

Kerogen is defined as "the insoluble organic matterwhich occurs in sedimentary rocks an d w hich generally iscapable of generating oil and/or gas on heating."Kerogen in sediments is a potential source of hydrocarbon shows. Soluble hydrocarbons may be present prior

to drilling in the kerogen network of mature sourcerocks. These soluble hydrocarbons present in kerog-enous rock may be extracted by solvents normally used tocheck for shows and m ay be interprete d falselyas free liquid h ydrocarbo ns in the pore space of the rocks. Solublehydrocarbons may be created in organic-rich rocks by theheating effect of drilling or the sample examina tion proc ess. In this regard, two possible heat sources are (1) bitaction during the drilling or coring, and (2) retorting ofsamples in the laboratory. The retort method of determining fluid saturations involves heating the sample toabout 650C, which is sufficient to cause extensive thermal cracking of any kerogen present and the creation ofsoluble hydrocarbons that are then measured andimproperly a ttributed to oil saturation in the reservoir.

Hydrocarbon shows released by drilling kerogen-richrocks indicate only that potential source rocks may bepresent in the area. During drilling operations, subsurface hydroc arbons generated in kerogenous source rockscould be mistakenly interpreted as liquid oil or gas in thepore spaces of interbedded reservoir rocks and confusedwith continuous phase or residual shows.

Implication ofModesof OccurrenceFrom the standpoint of commercial production theonly mode of occurrence with any significance isthe continuous phase occurrence (Fig. 1). The continuous phasehydrocarbon show is the only physical mode of occurrence with any relative permeability to oil or gas and,therefore, the only show potentially comm ercial. Continuous phase h ydroca rbon occurrences will produce oil orgas commercially if they occur at reasonable depths inreservoir-quality rocks and have enough hydrocarbonsaturation and corresponding relative permeability to

AT SURF ACE %

I N CO RE B ARREL %

I N RESERV O IR %

O IL G A SWAT ER

CONTINUOUS PHASE RESI DUAL O I LFIG. 4Comparison cliart ofoil, gas, and water saturation for continuousphaseand residual hydrocarbonoilshows, from reservoir conditions to surface conditions (afterCoreLaboratories).


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1306 Subsur face Hyd roca rbon Showsproduce commercial quantities of oil or gas. Continuousphase shows can be commercially productive or uneconomic. Isolated droplets of oil or gas (residual shows),dissolved hydroca rbon shows, and shows associated withkerogen in source rocks cannot produc e liquid hydrocarbons and are uneconomic from the standp oint of conventional oil and gas production.The exploration implication of the physical modes ofhydrocarbon occurrence or show classification schemeare somewhat different from the prod uction impHcations(Fig. 1). Continuous phase shows in reservoir qualityrock indicate a trapped accum ulation of oil or gas. Noneof the other show types or m odes of occurrence indicate atrapped accumulation. Residual shows indicate that liquid hydrocarbons migrated through the oil- or gas-stained rocks. Dissolved hydrocarbons indicate thathydrocarbons are present in molecular form in the system but do not demonstrate bulk oil or gas is present.Hydrocarbons in kerogen indicate only that liquid oil orgas is potentially available to the system in the form of ahydrocarbon source rock, but indicate nothing about therelease migration or the entrapm ent of liquid-producibleoil or gas.

Identification ofTypeI ShowsExploration impHcations of each show type vary fromdirect indications that a trapped accumulation has beenlocated, to the identification of potential source rockzones. Total ramifications of each show type are beyondthe scope of this paper. However, from the standp oint ofdirect exploration ap plication, the single most im porta ntshow type is type I, continuous phase mode of occur

rence, which indicates the discovery of a trapped accumulation ofoilor gas of unkno wn size. Can type I showsbe identified? What data are necessary to differentiatebetween migration paths (type II shows) and trappedaccum ulations (type I)?Hydrocarbon shows in exploratorywellscan be dividedinto shows seen directly in cuttings or cores, shows of oilor gas recovered during testing or in the drilling fluids,and shows inferred from wireline or gas detector logs. Toexamine how type I shows can be separated from type II,we must determine what data each hydrocarbon indication provid es. A potential way of distinguishing betweenshow types is to determine the percentage of pore space

tha t must be occupied by oil or gas to positively identify acontinuou s phase mode of occurrence, and then, the typeof fluid recovery needed for a positive identification of atype I show.Hydrocarbon Saturation

A co ntinuous phase show was defined as a slug or filament of oil or gas with a continuous connection throughthe pore network of the rock. The minimum hydrocarbon saturation necessary to establish a continuous filament through a porous rock is approximately 10*yo(Schowalter, 1979). The minimu m saturation for a type Ishow then could beaslow as 10% . Maximum saturationsfor type I shows could be as high as 90%, depending on

the irreducible water saturatio n of the oil-saturated rockin question. The minimum saturation for a residual ordroplet-scale type II show is about 5 to 10% , dependingon the initial hydrocarbon saturation in the rock beforewater displacement (Fig. 3). The average maximum saturation for water displacement residuals in sandstone reservoirs is 35 % ; in carb ona te res ervoirs , residualsaturations can range from 30 to 60% and average 55%.Vuggy carbonates can have residual sa turations in excessof 60% and can approach 80% in oomoldic porosity.Based on saturation of pore spa ce, the only way to positively identify a type1 continuous phase show would beto determine from cuttings, cores, or logs that the rock inquestion had a hydrocarbon saturation in excess of 35%for a sandstone reservoir or 55% for a carbonate reservoir.

Whatisthe possibility of cuttings, co re, or log data pro viding accurate hydrocarbon saturation data that can beused to distinguish between type I and type II shows?Because of the normal rotary drilling process, neithercuttings nor cores can provide useful information concerning subsurface hydrocarbon saturation. Safe drillingprocedures require drilling fluid or mud column pressureto be greater than formation pressure, and water will befiltered from the drilling fluid into any permeable rock spenetrated by the drill bit. This filtration action is comparable to a waterflood process in reservoir rocks, andany mobile continuous phase oil or gas occurrence nearth ewellbore will be reduced towa rdawater displacementresidual saturation. F urth erm ore, as the rock core or cutting is moved to the surface, the reduced pressure environmen t at the surface causes gas to come out of solutionand to expel additional liquid hydrocarbons and waterfrom the rock pore space. Any data from cutting or coresamples, therefore, would not indicate the true subsurface satu ration and are useless in separating type I fromtype II shows, unless core saturations exceed 35% in asandstone reservoir or5 5% in a carbonate reservoir. Thisproblem is very clearly illustrated by a C ore Lab diagram(Fig. 4), which shows that a residual subsurface saturation of 30% oil could have, by laboratory analysis, thesame saturations of oil, gas, and water at the surface as acontinuous phase subsurface oil saturation of 70%.

The exception to this rule would be in the case of lowgravity, viscous oils with no associated gas. These typesof oil may not be flushed from the reservoir during drilling and may reflect subsurface oil saturations on coreanalysis.The one way to overcome the problem of core analysisnot being representative of subsurface saturation is tostop the mud filtration process by pressure coring. Pressure coring can provide saturations at subsurface conditions, bu t is expensive and not routinely use d.Bymeasuring reservoir porosity and resistivity, wirehnelogs can provide d ata on oil or gas satura tion in the reservoir. Oil or gas saturations from logs are generally basedon data obtained beyond the zone of mud filtration offlushing, and therefore, provide saturation data at subsurface conditions. Type I, continuous phase shows,then can be identified indirectly from log-calculated oilor gas saturations that are in excess of 35% for a sand-


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T i m T . S c h o w a l t e r a n d P a u l D . H e s s 1 30 7

stone reservoir or5 5%for a carbon ate reservoir. The reliability of these calculations and subsequent showclassification will be a function of the quality of log da ta,depth of filtration, and accuracy of the measured orinferred formation water resistivity. Such log calculations are subject to error and must be weighted, based onexperience in the area and trial and error. Recent loggingadvances that calculate the inferred presence of movableoil may also act as a positive indicator for type I shows.Residual, type II shows, by definition, have no movableoil because oil occurs as isolated unconnected dropletswith no permeability to oil. In con trast, type I shows areconnected filaments of oil or gas that would be movableupon being flooded by water from the mud filtrationprocess during drilling. Movable oil correctly interpretedon logs then is a positive indication of a type I oil occurrence.In general, hydrocarbon saturations of greater than35 % in sandstone and 55% in carbonates from cores orlogs and movable oil from log calculations, can be considered as positive indicators of type I hydrocarbonshows. Oil-stained cuttings, co res, and log-calculated oilsaturations less than 35% for sandstones and 55% forcarbonates cannot be used to separate type I or type IIshows.

FluidRecoveryA second poten tial method of distinguishing type I andtype II shows is by analyzing the type and amount offluid recovered from a reservoir zone that is oil stainedduring drilling or testing. From the standpoint of fluidrecovery, the main difference between type I and type II

shows is that type I shows have some relative perm eability to oil and type II shows have no relative perm eabilityto oil. By using this concep t, any indication of the movement ofoilfrom th e rock into the well bore during testingor drilling would be a positive indication of a type I, continuous phase, subsurface show. In contrast to the problems in differentiating show types by calculatedhydrocarbon saturation, the fluid recovery concept provides a direct way of identifying type I shows . Any significant recovery of free oil on drill-stem or produ ction testswould positively identify a type I show. T his indicationof free oil could be in the form of oil-cut mud, oil-cutwater, free oil, etc. Flecks or rainbows of oil in mud orwater are not reliable indications of type I shows. Thetotal amo unt of fluid an d percentage ofoilversus mud orwater is importa nt in determ ining if the oil show may beeconomic in the well bore being tested, but not in theidentification of a type I show.

Minor amounts of oil-cut mud recovered during drilling are not a decisive indicator of type I shows becausethe grinding action of the bit may create oil-cut mud byreleasing isolated drops of residual oil trapped in therock-pore spa ce. Significant volumes ofoilwhile drilling(e.g., oil on the pits) can be considered a conclusive indication ofatype I show, as the volume requ ired to explainthis type of show would be greater than the volume thatcould be liberated by drilling the cylindrical rock columnpenetrated by the bit.

Interpretations of gas shows while drilling or testing aremore difficult than oil shows. Gas-cut mud observedwhile drilling and mud-logging shows can result from anyof the four m odes of occurrence. G as can be liberated bythe grinding action of the bit from gas adsorbed on rockgrains, in coals, or in oil source rocks. Gas in solution inthe pore water of subsurface rocks can produce gas-cutmud while drilling, which may be seen as mud-loggingshows. The grinding action ofthebit can liberate residualgas droplets in the pore space of reservoir rocks, whichcan also create gas-cut mud and mud-logging shows.Drilling continuous phase gas occurrences will also liberate gas from the rock pore space and create gas shows.Indications ofgaswhile drilling cannot be used as an unequivocal indicator of type I shows. This is even true inhigh-pressure zones where mud weight m ust be increasedto prevent gas blowou ts, as this condition can be createdby gas in solution as well as from gas in a reservoir.Gas recovered during a formation test can result fromthree of the four types of subsurface gas occurrences: (a)continuous phase gas whereby gas inflow occurs duringthe test; (b) residual gas which expands due to a p ressuredrop at the well bore and forms a local continuous phasewith subsequent gas inflow; and (c) gas dissolved in formation water whereby water inflow occurs and the contained gas exsolves owing to the pressure drop at the wellbore.Positive indicators for a con tinuous ph ase type I occurrence from formation testing would be gas coming to thesurface a t a sustained measurab le rate . Residual gas andsolution gas occurrences should not be able to produce asustained free gas flow. An exception to this conceptwould be when a permea ble w ater-bearing reservoir, sat

urated with gas in solution, flows to the surface. Con tinuous measurable amounts ofgascould then be producedas a separate phase with the water. Gas-cut water or gas-cut mud during testing could indicate any of the threemodes of occurrence listed abo ve.The first key question in interpreting hydrocarbonshows in explo ratory wells is distinguishing between continuous phase type I and residual type II modes of occurrence. From the discussion, it is obvious that there arefew absolute identifiers for type I continuous phaseshows. Subsurface hydrocarbon saturation of greaterthan 35% for sandstone and 55% for carbonate fromcores or logs is an indirect indication of a type I occur

rence. Indications of movable oil from logs is also a positive indirect indicator of a type I show. For oil, any freeoil recovery during formation testing or significant volumes ofoilwhile driUing is an indicatio n ofatype I show.In the case of gas, a form ation test of gas coming to thesurface at a sustained mea surable rate is an indication ofa type I gas occurrence. IftypeI continuou s phase showscan be positively identified in an exploratory well, a trapof unknownsizehas been identified . E ven if the well borewhere this show is located is evaluated as noncommercial, significant ex ploration inform ation has been gainedby drilling the test and interpreting the show s.If a show has been identified as a type I show, it can be

interpreted q uantitatively to determine the size of the oilor gas column required to create the show. Produ cing oil


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1308 S u b s u r fa c e H y d r o c a r bo n S h o w sor gas reservoirs are, by definition, continuous phaseshows. As mentioned in the introduction, these showscan be used to estimate the oil or gas column required toforce oil in the pores ofa water saturated reservoir.In order to validate this exploration technique, a controlled field study was attempted. In the field case history, the hydrocarbon shows in the reservoir zone of aproducing well in Buffalo field, South Dakota, wereinterpreted quantitatively, and an estimate of the elevation of the oil-water contact was attempted and compared to the known oil-water contact in the field.

Extrapolation Case HistoryBuffalo FieldBuffalo field, Harding County, South Dakota, produces from the Ordov ician Red River " B " zone at depthsbetween 8,300 and 8,500 ft (2,530 and 2,590 m). This

siratigraphic trap is located on the east flank of a faultedanticline (Fig. 5). Dipiseastward across the field at about1. If the field is one continuou s accu mulation, the maximum vertical oil column in the field would be about 380ft (116 m). The field, discovered in 1954, has produced 4million bbl of oil and is still being d eveloped.The reservo ir at Buffalo field is a sucrosic , vuggy dolo mite. The main productive interval is 15 to 18 ft (4.6 to5.5 m) thick, consisting of an algal, laminated bound-stone to wackestone. Reservoir porosities range from 16to 29% and apparent air permeabilities range from lessthan1md to36md. T he reservoir is unde rlain by a vuggylime wackestone with 4 porosity and permeabilitiesless than 0.01 md . The lateral seal for the accu mulationappears to be a chalky-textured dolom itic limestone. Thecap rock and seat seal for the trapped accumulation arebedded anhydrite and lithographic Hmestone.

R 3 E R 4 E

C O N T O U R I N T E R V A L -100 FEETFIG. 5Structural contour map on top of Ordovician RedRiver Formation "B "porosity, Buffalo field, Harding County, SouthDakota.


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T i m T . S c h o w a l t e r a n d P a u l D . H e s s 1309The boundaries of Buffalo field are not yet clearlydefined. Wells updip from the field commonly test oil atnoncom mercial rate s, suggesting a gradual facies changefrom comm ercial reservoir to the updip lateral seal. Thetrapping edge can be mapp ed regionally by a thinning ofthe Red River "B " zone from a maximu m of20ft (6 m) in

Buffalo field to zero west of the field. The downdip limits of the field are also poorly defined; productionextends downdip to approximately the -5,600 ft contour(Fig. 5). Down dip, the Red River " B " tests mainly water,suggesting an oil-water contact at approximately -5,600ft (-1,706 m ).As a test case of estimating the oil column downdipfrom a commercially produc tive well, a cored well from

Buffalo field was studied and the shows in the reservoirzone were interpreted quantitatively. The well used in thestudy was the Kirkwood 14-31 Travers, located in Sec. 31,T21N, R4E, Harding County, South Dakota (Fig. 6).The well was drilled in 1978 and completed pumpingfrom the Red River "B " zone at a rate of180bbl ofoilperday and150bbl of water per day. The well was completedin June 1978 and had produced 70,764 bbl of oil as ofJan uar y 1981, with reservoir estimates of more than200,000 bbl of recoverable oil. The 14-31 well was coredbetween8,358 and 8,515 ft (2,547.5 and 2,595 m). Thecore description and log response for the Upper RedRiver interval are illustrated in Figure 6.The Red River " B " reservoir in the 14-31 core is sucro-

1 4 - 3 1 T R A V E R S

8 4 5 0 -D S T N o . : 1 3 1 4 'O I L & M U D D Y W A T E R

FIG. 6Core and log data from Red River Formation in Kirkwood 14-31 Travers well, Sec. 31,T21N, R3E, Harding County,South Dakota.


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1310 Subsur face Hyd roca rbon Showssic, vuggy dolomite that is uniformly oil-stainedthroughout. Four samples from the pay section weretested in the labora tory to determine their capillary pressure properties (Fig. 7). Log calculations for the "B"zone indicate an average water saturation of 20% and acorresponding oil saturation of80%.As in most log calculations, this saturatio n value represents an average saturation through the best8t o10ft (2.4 to3m) of the "B "reservoir. The shows in each sam ple were quantitativelyinterpreted by determining the mercury pressurerequired to explain an 80% mercury saturation of the

1500 8 0 %

Q .UJ(X.1/5I / )t ua.

Uon 500

100 90 80 70 60 50 40 3 0 20 10 0MERCURY SATURATION (% PORE VOLUME)

FIG.7Mercury capillary pressure curves from four samplesin Red River "B" productive porosity in 14-31 Travers well,Buffalo field, Harding County, South Dakota.

pore space. The me rcury pressure was then related to theoil column required to buoyantly produce the same oilsaturation in the sample in the subsurface (Schowalter,1979).The assu mptions used in the calculations w ere: (1) reservoir displacement p ressure at 10% saturation of 40 psimercury (Fig. 7), based on the displacement pressure ofthe best reservoir rock tested; (2) subsurface oil-waterinterfacial tension ofa20.4 dynes/cm , based on a laboratory measurement of a crude oil sample from the fieldand a simulated water sample at a temperature of 180F(this subsurface interfacial tension value results in a conversion factor of 0.055); (3) subsurface water density of1.01 g/cc, based on a salinity of 18,000 ppm; (4) subsurface oil density of 0.837 g/cc, based on a 32 API gravityoil with a gas-oil ratio of 100; (5) water-wet rocks; (6)hydrostatic c onditions ; (7) mercury interfacial tension of480 dynes/cm; (8) mercury-air-solid contact angle of40.The results of these calculations are listed on Table 1.As mentioned previously, the calculations are based onan 80% oil saturation for each sam ple, based on log calculations averaged through a 10-ft (3 m) interval. Logcalculations for each individual sample were notattempted because of the inaccuracies that would beinvolved in trying to c orrelate a 1-ft (0.3 m) zone in thecore to correlative log values, and the averaging effectinherent in the log values because of tool spacing. The80%oil saturation for the pay interval seems to correlatewith the fluids actually produced from that zo ne. After 1year, this well was producing oil at a rate of 100 bbl /da ywith17bbl water. Inspection ofatypical relative perm eability curve (Fig. 2) suggests that a rock with an 80% oil

saturation should produce 80 to 100% oil and 0 to 20%water.As calculated from the four samples tested, buoyancypressure required to force oil into 80% of the pores indicates an oil colum n in the rang e of 102 to 220 ft 31to 67m) and averaging 155 ft (47 m). If Buffalo field is onecontinuous oil column, the maximum oil column down-dip from the 14-31 Travers well is approximately 330 ft(100 m) (Fig. 5). Interpretation of the data from thesefour samples suggests that a minimum oil column on theorder of 102 ft (31 m) should be present downdip fromthe analyzed well and that an oil column of up to 220 ft

Table 1. Reservoir Data for Ordovician Red River Formation in14-31Travers Well, Buffalo Field, Harding County, South Dakota

Depth*(ft)8,372.58,374.58,378.58,380.5

Porosity(%)14.428.924.620.8

Permeability(md)5.88.62.57.5

Mercury Pressureat 80% MercurySaturation(psi)180220270340

OilColumn(ft)102132168220

Core d epths are adjusted to log depths. Core de pths are 6.5 ft shallow to log (Fig. 5).


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T im T . S c h o wa l te r a n d P a u l D . H e s s 1311(67 m) may be present. The calculations suggest that alarge oil column , u p to 220 ft (67 m), is present downd ipfrom the 14-31 well. This value isless than the inferred oilcolumn from sub surface studies of325ft (99 m) and mayindicate that Buffalo field is a complex trap consisting oftwo separate accum ulations.

If the 14-31 well had been the discovery well and if theoutlined procedure had been followed, the resultinginformation could have been valuable in defining thelimits of Buffalo field. The large oil column calculatedwould have allowed wells to be drilled d ownd ip as m uchas 220 ft (67 m) and would have spurred field development. The estimated downdip limits of the field can beadjusted with the addition of information from subsequent wells.App lication of these principles could be used in developing newly discovered fields. If the calculated oilcolumnissignificantly larger than the m apped structuralor stratigraphic closure for the pros pect, ad ditional wellsshould be drilled dow ndip to establish the field limits. Ifthe calculated oil columnissignificantlylessthan the predicted oil-water contact from structural or stratigraphicclosure, the prospect may be only partially filled anddowndip development dry holes could be avoided.The Buffalo field example suggests that the quantitative interpretation oftypeI, continuo us phase shows, canbe potentially quite useful in field development by estimating the oil-water or gas-water contact in the fieldfrom one well bore. The same approach is potentiallyapplicable to quantitative interpretation of type I showsfrom wells that are not commercial producers.Ifatype I show has been identified in a noncomm ercialreservoir, a trapped a ccum ulation of oil has been located.The dow ndip oil or gas column associated with the identified type I show can be calculated in an analogous fashion to the producing well examp le. This concept would bevery useful in an exploration setting where the showcould be used as quantitative proximity indicators tohydrocarbon accumulations.Before non comm ercial type I shows can be interpreted,a model for the complexities of oil-water and gas distribution in stratigraphic traps must be developed.EXPLORATION OF TYPE I SHOWSIN COMPLEX STRATIGRAPHIC TRAPS

Simple Stratigraphic Trap ModelFigure 8 illustrates a simplified model for a stratigraphic trap , which is used by many exp lorationists. Themodel consists of a reservoir bed overlain and underlainby sealing shales. The reservoir terminates updip by alateral facies change into an impermeable shale, and thegeometry in ma p view ofthislateral facies change is convex updip, forming a classic stratigraphic trap. In themodel, the facies change from reservoir to updip lateralsealisassumed to be abrupt and obvious. In the downdipdirection, the change from oil-bearing reservoir to waterbearing reservoir is assumed to be abrup t with no signifi

cant oil-water transition zone. Exploration efforts toexplore for the above-described model are focused on

mapping the geometry of the reservoir-seal boun dary.Once a stratigraphic p rospect has been defined by various exploration methods, a drilHng program is plannedto attempt to discover the inferred stratigraphic tra p. It isassumed that a well will be drilled either in or out of thefield. W ells drilled within th e inferred oil field are generally assumed to be easy to recognize. Wells that miss theeconomic part of the trap are assumed to be drilled in theseal facies or in water-saturated reservoir rock. Subsequent wells can then be located downdip from a sealfacies or updip from the water-wet reservoir until theaccumulation is located.

Complex Stratigraphic Trap ModelIn a simple stratigraphic trap model, the bo undary ofthe oil reservoir is sharp and clearly defined. Updip fromthe oil-bearing reservoir, reservoir-quality rock changesabruptly to the updip seal. Do wnd ip, the oil-bearing reservoir rock changes abrupt ly to water -saturatedreservoir-quality rock with no oil shows. An abruptchange from reservoir rock to the updip lateral sealoccurs in many stratigraphic traps and has been confirmed frequently by drilling. However, developmentdrilling of numerous other stratigraphic fields hasrevealed a gradual change updip from economic reservoir, to nonecon omic o il-stained roc ks, to a seal with nooil shows.Ab rupt d ownd ip changes from oil-productive reservoirto rocks that produce all water, forming sharp oil-watercontacts, occur in some oil fields. However, case historiesshow that in many other fields the downd ip change fromprimarily oil production to 100% water production maybe quite gradual and occur over a significant vertical distance (Aufricht andKoepf, 1957). This gradual changedownward through a zone of mixed oil and water production to the downdip Hmits of an accumulation iscalled the oil-water transition zone by reservoir engineers. The width of this zone is controlled primarily bythe average pore size and pore-size distribution of the reservoir rock. Reservoir rocks with pore systems consistingof large, connected, uniformly sized pores will havealmost no oil-water transition z one. Reservoir rocks witha heterogeneous distribution of pore sizes and primarilysmall pores can have very thick oil-water transition zone.The thickness of any oil-water transition zone can be esti-

D U N H A M , 1 9 73( P a r i o n a l C o m m u n i c a t io n ) S P I L L P O I N T

FIG.8Cross section and map view of simple stratigraphictrap.


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1312 S u b s u r f a c e H y d r o c a r b o n S h o w smated if reservoir capillary properties and relative permeability are known (Arps, 1964; Schowalter, 1979).This simple stratigraphic tra p model must then be modified to accommodate a facies change from reservoir toseal in the updip direction and from oil-productive towater-productive reservoir in the downdip direction. Amore complex stratigraphic trap model is illustrated inFigures9and 10.This model show s an oil-productive reservoir that changes gradually updip from reservoir rockto oil-stained noncom mercial roc ks. The sealiscalled the"trapping edge" of the accumulation. The boundarybetween the economically producible, oil-saturated reservoir rock and the noneconomic oil-stained rock iscalled the "economic edge" of the accumulation. Thearea between the trapping edge and economic edge of astratigraphic trap is termed the "waste zone " (Dun ham,personal commun.). The term "waste zone" is usedbecause the oil and /or gas cannot be produced economically and is therefore wasted. Definition of the wastezone is based on eco nom ics, and of c ourse will vary fromarea to area.

The model also shows a gradual transition downdipfrom water-free oil prod uction in the economic reservoirto downdip water production. This zone between thewater-free oil-productive reservoir and the downdipwater-productive reservoir rock is termed the "oil-watertransition zo ne." Both transition zone and waste zone areeconomic terms that can vary in identical reservoirs ifdepth or other factors significantly affect the economicsof production. The width and thickness of the oil-watertransition zone will depend on the pore sizes and pore-size distribution in the reservoir rock and the physical

properties of the oil and water in the reservoir (Arps,1964).The complex model has three zones in which shows willbe seen: (1) the oil-water transition zone, (2) the economic reservoir, an d (3) the waste zone . Two of the threezones in such traps will not be economic. Depending onthe width of the transition zone and the waste zone, theodds of drilUng into the uneconomic portions of atrapped oil accumulation may be greater than drillinginto the economic area of the trap. Where this type ofcomplex trap is encountered, then it is vital to identifywhere a type I show occurs in the complex m odel.It can also be demonstrated that if the transition andwaste zones are thicker than the total oil column th at canbe trapped by a given seal facies or t rap geom etry, theremay be no econom ic reservoir. Th e oil column tra pped inany stratigraphic accum ulation will depend on the geometry of the facies change (spillpoint) and the lateral sealcapacity of the updip trapping facies (leak point). Thewidth of the w aste zone will depend on the abruptn ess ofchange in facies from reservoir to sea l. The stratigraphicexplorationist then must be able to recognize the wastezone and the oil-water transition. W hat are the characteristics of these zones?To com pare and con trast these two zones, further a nalysis of the com plex stratigraph ic tra p m odel is necessary.Figure 10 shows a cross section of the complex m odel. Inthis diagram, the reservoir from point A to point B isassumed to be uniform and homogeneous. This meansthat the poresizeand th e pore-size distribution w ithin thereservoir are the same at any point from A to B, and ifcapillary pressure curves were run on multiple reservoir

T R A P P I N G E D G E -

E C O N O M I CE D G E .R E S E R V O I F T R A N S I TZ O N E

T R A N S I T I O NZ O N E

O I L -W A T E R C O N T A C T OR1 0 0 % W A T E R L E V E L

D U N H A M . 1 9 7 3( P e r s o n a l C o m m u n i c o t i o n )

P P I N G E D G EE C O N O M I C E D G E

FIG . 9Cross section and m ap view of complex stratigraphic tr ap .


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T i m T . S c h o w a l t e r a n d P a u l D . H e s s 1313rock samples between points A and B, the capillary pressure curves would be identical for all samples. For a completely uniform reservoir as illustrated, the oil saturationin the reservoir would gradually increase above the 100%water level as buoyant pressure in the oil columnincreases (Schowalter, 1979). The buoyant pressurewould be equivalent to the capillary pressure of the oiland water in the rock at any saturation. The solid hne inthe capillary pressure diagram th en can be considered thecapillary pressure curve for the uniform reservoir at anypoint from A to B , and the oil saturation in the reservoirat any point between the 100% water level point B in themodel.

From point B to point C , the reservoir zone graduallychanges facies and becomes a rock with pores smallenough to seal the accumulation. This facies change isassumed to be a linear reduction in pore size from point Bto C. Capillary pressure curves from rock samples alongline BC would all be different. T he gradu al reduction inpore size in the reservoir zon e would gradually decreasethe oil saturation in the reservoir zone from p ointBto C,as shown by the dashed line on the capillary pressure diagram. The oil saturation would become zero at the trapping edge of this facies change (Fig. 10). This change in

pore size could occur without a decrease in porosity fromB t o C .Transition Zone Characteristics

By analysis of Figure 10, we can discuss the potentialdifferences between the waste zone and the oil-watertransition zo ne. The type of fluid they produ ceisone wayof differentiating these zones. The oil saturation throughthe transition zone generally ranges from 10% tobetween 50 to 60% of the reservoir pore volume. Frominspection of typical oil-water relative permeabilitycurves (Fig. 2), the minimum oil saturation needed tohave any permeabiUty to oil can be as high as 20%.Toward the base of the oil-water transition, a fluid production test of oil-stained rocks in a trapped accumulation could produce 100% water. As the oil saturation inthe reservoir zone increases above som e minimum level,the transition zone can produce oil and water in variedpercentages up to the top of the transition zone where thereservoir would test 100% oil. The transition zone canthen produce all water or some combination of oil andwater. Form ation tests in the transition zone should yieldfluid at high rates because, by definition, the reservoir

\\ \\ \O i l Saturation (%Pore Space \ ^100 50 0 ' FLUID PRODUCTION

NA/ASTEZONE

100 50 0O i l Saturation (%Pore Space

ECONOMICRESERVO

TRANS W A T E RO l t - W A T E R C O N T A C

F R E E W A T

FIG. 10Cross section of complex stratigraphic trap illustrating relationship of oil saturation and pore size to fluid production(after Arps, 1964).


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1 3 1 4 Subsurface Hydrocarbon Showszone is general ly unifo rm from the o i l -produc t ive reserv o i r t h r o u g h t h e t r a n s i t i o n z o n e i n t o t h e w a t e r -product ive reservoir . High flu id-product iv i ty rates fromoil-s tained rocks m ay be indicat ive of an o i l -water t ransit ion .

Oil saturat ion in a t ransi t ion zone may vary in themodel from a h igh of 50% to a low of 10%. Oil saturat ions less than 50% in reservoir-qual i ty rock probablyindicate an o i l -water t ransi t ion zone. Any nonreservoirrocks with smaller pores and correspondingly h igher capi l lary pressures should be water saturated and have novisible oil stain in cores or other samples. Toward thebase of an o i l -water t ransi t ion zone, very s l ight changesin pore s izes or capi l lary propert ies of the rocks maycause errat ic d is tr ibut ion of o i l s tain ing. Vert ical changeof o il - s t a in pa t t e rn , in what ap pears to be un i fo rmreservoir-qual i ty rock, would be an indicator of an o i l -water t ransi t ion zone. Oil saturat ions can be related tothe o i l column required to create the saturat ion, i f thecapi l lary propert ies or pore s izes of the o i l -s tained sample can be determined. Calculat ions of o i l shows in thetransi t ion zone should suggest small columns. The oi lcolumn required to explain a low oi l saturat ion in areservoir-qual i ty rock should be on the order of 10 to 20ft (3 to 6 m) , as the m inim um oil colum n required tomigra te throu gh a n average reservoir is on the order of 10ft (3 m). Calculat ions of o i l columns required to explainoi l saturat ion in an unstained rock and adjacent to o i l -s tained reservoir rocks should also suggest small o i lco lumns and be ind ica t ive o f an o i l -wate r t rans i t ionzone.

Waste Zone C haracteristicsIn Figure 10, pore s ize decreases from point B to C.Above point B, the reservoir wil l cont inue to have water-free product ion unt i l the o i l saturat ion is reduced suffi cient ly to cause some relat ive permeabil i ty to water.Fro m th e base of the waste zone to the seal , the o i l saturat ion wil l gradual ly decrease from 50% to zero . Based oninspect ion of typical relat ive perm eabil i ty curves (Fig . 2),the waste zone with o i l saturat ion from 50% to zeroc o u l d p ro d u c e b o t h o i l a n d w a t e r d u r i n g a f l u i d -pro duc t ion te s t . As the o il saturat i on in the waste zone is

reduced to around 20%, the waste zone could produceonly water from oil-stained rocks. If the waste zone is lowperme abil i ty rock that has its perm eabil i ty further dam aged while dri l l ing , i t may produce only mud or o i l -cutmud. The waste zone, based on the model , can yield , atd ifferent t imes mu d, o i l , o il and water, and 100% water.The waste zone can produce the same type of f lu id asthe o i l -water t ransi t ion zone. The type of f lu id producedfrom an oi l -s tained rock is not d iagnost ic in determiningif an oil show is in a waste zone or a transition zone. Conventional explorat ion wisdom for s t rat igraphic t raps suggests moving updip from oi l-s tained rocks that producewater or o i l and water. This may be incorrect , as both awaste zone and a t ransi t ion zone may produce the sametype of f lu ids . How can we dis t inguish between the w astezone and the t ransi t ion zone i f the type of f lu ids produced can be the same?

As defined in the complex model , the pore s ize of thereservoir bed decreases from the reservoir to the seal . Aspore s ize is reduced, permeabil i ty is reduced and thewaste zone should no t be able to produ ce any flu id at economic rates . Fluid product iv i t ies in waste zones shouldbe low.

Calculat ions of o i l column based on oi l saturat ions androck capi l lary propert ies in the waste zone should indicate a large vert ical o i l column. Within the waste zone,any th in in terbedde d reservoir-qua l i ty rocks should be o ils tained and have high oi l saturat ions . Nonreservoir quali ty rocks or " t ight" rocks in the waste zone may be o i ls tained. This contras ts with the t ransi t ion zone wherenonreservoir quahty or " t ight" rocks should not be o i ls tained.Exploration Im plications of Transition and Waste Zones

The characteris t ics of the waste zone and the t ransi t ionzone are summarized in Table 2 . These two zones cannotbe d is t inguished rel iably by the type of f lu id they produce . They can be d ifferent iated by flu id product iv i ty ,the type of rocks that are o i l -s tained, and the calculatedoi l colum ns requ ired to explain o i l shows in cores or sam ples . Based on an analysis of the complex model , i tappears that sufficient d ifferences exis t between wastezones and oi l -water t ransi t ion zones to al low them to beTable2.Com parison of Transition Zone and Waste Zone

Characteristics Transition Zone Waste ZoneFluid ProductionType fluid

ProductivityOil and water, waterHigh

Oil and water, water,oil, oil-cut mudLowOil StainingReservoir rocksNonreservoir rocks Low oil saturationNo stain High oil saturationOil stainedCalculated Oil Columnof Oil-Stained Rocks Small Large


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T im T S c h o w a lt e r a n d P a u l D . H e s s 1315distinguished. Data generally available from exploratorywells should allow on e to relate oil shows in " tigh t" rocksto the complex stratigraphic model.If oil-stained samples can be identified as being in theoil-water transition, the o perator should drill updip fromthe oil shows. The amount of structural elevation gainneeded to move out of the oil-water transition zone intowater-free oil production can be quantified if the capillary properties of the reservoir and the oil saturation ofthe location of the first test well are known (Arps, 1964;Schowalter, 1979).If oil shows can be determined to be in the updip w astezone ofastratigraphic tra p, the total oil column downd ipin the trapped accum ulation can be calculated. If a largeoil column is calculated, the operator may have discovered an oil accum ulation or trap of significant ex tent. Ifreservoir quality rock s canbepredicted to occur dow ndipfrom the waste zone well, additional wells are justifieddowndip of the first test to locate the economic portionof the discovered field.

SHOW INTERPRETATION-EXTRAPOLATIONCASE HISTORIESWaste Zone

If oil or gas shows can be classified as type I, continuous phase shows, and placed in the complex stratigraphictrap model, exploration efforts can be guided by interpretations of hydrocarbon show data. What is the likelihood of classifying shows as to their mode ofoccurrence? If a show is classified as a type I con tinuousphase mode of occurrence, how can this show information be used to interpret the show in a complex stratigraphic model? If well shows indicate a waste zone hasbeen pen etrated, how accurately can the oil or gas showsbe related to the trapped hydrocarbon column? Canshows be characterized as being in the oil-water transition zone, and be quantitatively interpreted?

To attempt to answer these questions, four complexstratigraphic traps were studied. For the sake of brevityrepresentative field studies of a waste zone well and a

FIG. 11Structure contour and fluid production map of Pay Dirt field.


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1 31 6 S u b s u r f a c e H y d r o c a r b o n S h o w s

transition zone well will be documented. The geologicand geographic identifiers for each field have beenremoved from each case history at the request of Shell OilCo.PayDirt FieldGas Waste Zone

Pay Dirt field is a stratigraphic trap that produces oiland gas from a biohermal reef buildup located along aregional northeast-southwest-trending shelf edge. Thetrap at Pay D irt field is caused by a facies change crossinga slight structural nose (Fig. 11). The facies change isfrom porous and permeable reef rock to fine-grainedrock of lagoonal-origin and high displacement pressure.The present-day structural nose was formed by regionaltilting to the southeast of a curved organic reef buildupthat extended out from the shelf-edge barrier into alagoon to the northwest. Lithologies of the lateral sealare gray lime mu dstone , wackestone s, and black calcareous shales and lime mudstones. The trapped verticalhydroc arbon column at Pay D irt field is greater than 280ft (85 m), consisting ofa35-ft (10 m) oil colum n an d a gascolumn greater than245 ft (75m; Fig. 12). Regional dip is120 ft/mile to the southeast with no mappa ble faulting in

the field area. Pay Dirt field produces from 38 oil wellsand 7 gas-condensate wells, with a probable ultimaterecovery of 120 million bbl of Hquid hydrocarbons plus670bcfofgas.Based on distribution ofthe reservoir facies, lateral sealfacies, and shows (Fig. 11), it is inferred that the size ofthis stratigraphic accumulation is controlled by trapgeometry, and oil and gas have spilled up dip to the no rth.The field limits do not appear to be controlled by thelateral seal capacity of the updip lateral seal.The reservoir rock at Pay Dirt field is a vuggy limepackstone to boundstone facies. The rock matrix ischalky lime mudstone, with the amount of matrix porosity depending on intergranular cement. Scattered ooliticporosity interbedded with calcareous shales is presentalong the western edge of the reservoir. The most p roduc tive porosity is vugular, with vugs ranging from pinpointto 1.5 in. (3.8 cm). Porosities for the reservoir average16% and permeabilities average 108 md; the cut-offporosity for production is approximately 8%. The mainreef-building fossils a re rudistids, other pelecypods, gastropods , and stromatoporoids. The environment of deposition is interpreted to be a curved back-reef organicbuildup that extended off a linear shelf-edge barrier reef

N ORTHWEST- SOUTHEAST STRUCTURAL CROSS SECTIONNORTHWEST

ASOUTHEAST

APLACID PHILLIPSINTERNATIONAL HOWCOTT

PLACIDHEFNER

PLACIDEDENBORN

7300

- 7400

7500-

O ' 7 6 0 0 -

-7700

= 7 8 0 0 -

-7900

- 8 0 0 0 -

8100-

WASTEZONE

245'

-7300

-7400

- - 7 5 0 0

- 7600 gLU-7700 ^

Schowalter 1982 Show Interpretation 13020

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Transcript of Schowalter 1982 Show Interpretation 13020