Play analysis and leading-edge oil-reservoir development ... · This papergeologicallydefines and...

AUTHORS

Shirley P. Dutton � Bureau of EconomicGeology, Jackson School of Geosciences, Universityof Texas at Austin, Austin, Texas 78713-8924;[email protected]

Shirley Dutton is a senior research scientist at the Bureauof Economic Geology with research interests in sedi-mentology, reservoir characterization, sedimentary pe-trology, and clastic diagenesis. She received a B.A. degreefrom the University of Rochester and an M.A. degreeand a Ph.D. from the University of Texas at Austin, all ingeology. She has been an AAPG Distinguished Lecturer.

Eugene M. Kim � Bureau of Economic Geology,Jackson School of Geosciences, University of Texas atAustin, Austin, Texas 78713-8924; present address:Wood Mackenzie, 5847 San Felipe, Suite 100,Houston, 77057; [email protected]

Eugene Kim is a specialist on North America gas supply.Prior to joining Wood Mackenzie, he was a researchassociate at the Bureau of Economic Geology, involvedin play analysis, resource assessment, and reserveevaluation. He holds a B.S.E. degree in mineral andpetroleum engineering from Seoul National Universityand an M.A. degree in energy and mineral resourcesand a Ph.D. in geological sciences, both from theUniversity of Texas at Austin.

Ronald F. Broadhead � New Mexico Bureauof Geology and Mineral Resources, New MexicoInstitute of Mining and Technology, Socorro, NewMexico 87801-4681; [email protected]

Ron Broadhead received his B.S. degree in geology fromthe New Mexico Institute of Mining and Technologyand his M.S. degree in geology from the University ofCincinnati. He worked for Cities Service Company inOklahoma and has been with the New Mexico Bu-reau of Geology and Mineral Resources at the NewMexico Institute of Mining and Technology since 1981,where he is currently a principal petroleum ge-ologist and adjunct faculty.

William D. Raatz � New Mexico Bureau of Geol-ogy and Mineral Resources, New Mexico Instituteof Mining and Technology, Socorro, New Mexico87801-4681; present address: Oxy Permian, 5Greenway Plaza, Houston, Texas 77046;[email protected]

Bill Raatz is a Permian basin sequence stratigrapher.Formerly, he worked on international explorationand Alaska development with Arco and Phillips andworked as a researcher and adjunct faculty withthe New Mexico Bureau of Geology and MineralResources and the New Mexico Institute of Miningand Technology. He received his Ph.D. from theUniversity of Wisconsin and his M.S. and B.S. de-grees from the University of Iowa, and he nowserves on the AAPG Grants-in-Aid Committee.

Play analysis and leading-edgeoil-reservoir developmentmethods in the Permian basin:Increased recovery throughadvanced technologiesShirley P. Dutton, Eugene M. Kim, Ronald F. Broadhead,William D. Raatz, Caroline L. Breton, Stephen C. Ruppel,and Charles Kerans

ABSTRACT

The Permian basin of west Texas and southeast New Mexico remains

an important oil-producing province, accounting for 17% of United

States production (327 million bbl) in 2002. With a resource base

of such size, increased understanding of reservoir geology and im-

proved use of enhanced-recovery practices in the basin can have

a substantial impact on United States oil production. Thirty-two

oil plays covering both the Texas and New Mexico portions of the

Permian basin were defined on the basis of reservoir stratigraphy,

lithology, depositional environment, and structural and tectonic

setting. One thousand three hundred and thirty-nine significant-

sized reservoirs (cumulative production of >1 million bbl [1.59 �105 m3] of oil through 2000) were assigned to a geologic play.

Cumulative production from these reservoirs was 28.9 billion bbl

(4.59 � 109 m3), or 95% of the basin’s total. Examples of success-

ful reservoir-development practices are listed by play because meth-

ods demonstrated to work well in one reservoir should be appli-

cable to other reservoirs in the play.

The Permian basin is dominantly a carbonate province. Carbon-

ate reservoirs account for 75% of total oil production; clastics, 14%;

mixed clastics and carbonates, 8%; and chert, 3%. The plays having

the largest cumulative production are the Northwest shelf San Andres

platform carbonate play (4.0 billion bbl; 6.31 � 108 m3), the Leonard

restricted platform carbonate play (3.3 billion bbl; 5.25 � 108 m3), the

Pennsylvanian and Lower Permian Horseshoe atoll carbonate play

E&P NOTES

AAPG Bulletin, v. 89, no. 5 (May 2005), pp. 553–576 553

Copyright #2005. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received September 10, 2004; provisional acceptance November 3, 2004;revised manuscript received December 3, 2004; final acceptance December 7, 2004.

DOI:10.1306/12070404093

(2.7 billion bbl; 4.29 � 108 m3), and the San Andres platform

carbonate play (2.2 billion bbl; 3.42 � 108 m3). The Permian

system dominates production, accounting for 73% of cumulative

production, followed by the Pennsylvanian (13%) and the Or-

dovician (6%). The estimated remaining reserves from that com-

ponent of the resource base that is already discovered and pro-

ducing is 3.25 billion bbl (5.17 � 108 m3).

INTRODUCTION

The Permian basin of west Texas and southeast New Mexico

(Figure 1) has produced oil for more than 80 yr, and it is still the

third largest petroleum-producing area in the United States after

the offshore Gulf of Mexico and Alaska. In 2002, it accounted for

17% of the total United States oil production (327 million bbl;

5.20 � 107 m3), and it contains an estimated 22% of the United

States proved oil reserves (5 billion bbl; 7.95 � 108 m3) (Energy

Information Administration, 2003). Moreover, this region has the

greatest potential for production growth in the country, contain-

ing 29% (17.6 billion bbl; 2.80 � 109 m3) of estimated future oil

reserve growth (Root et al., 1995). Original oil in place (OOIP) in

the Permian basin was estimated to be 106 billion bbl (1.69 �1010 m3) (Tyler and Banta, 1989); the 30.4 billion bbl (4.61 �109 m3) of oil produced through 2000 represents only 29% of the

OOIP. An estimated 30 billion bbl of unrecovered mobile oil re-

mains (Tyler and Banta, 1989).

Because of the substantial amount of oil remaining in the basin,

a new oil play portfolio of the Permian basin was developed as part

of the U.S. Department of Energy Preferred Upstream Management

Practices Program (Dutton et al., 2004). The portfolio geologically

defines 32 oil plays in the Permian basin and assigns all reservoirs

that had cumulative production of greater than 1 million bbl (1.59 �105 m3) through the year 2000 to a play. This new, comprehensive

characterization of oil plays includes the entire Permian basin in

Texas and New Mexico. Successful reservoir-development prac-

tices used in the Permian basin are summarized because in this

mature area, much of the future production will result from im-

proved recovery from existing fields.

A simple but effective method of increasing recovery in a res-

ervoir is to apply methods that have been successful in similar reser-

voirs. To do so, however, it is necessary to understand how reservoirs

group naturally into larger families or plays. A play is an assemblage

of geologically similar reservoirs exhibiting the same source, reser-

voir, and trap characteristics (White, 1980). Reservoirs in a play are

related geologically and commonly have similar production char-

acteristics (Galloway et al., 1983), thus allowing characteristics of

better known reservoirs to be extrapolated with relative confidence

to other reservoirs in the same play. Reservoir-development methods

that have been demonstrated to work well in one reservoir should

therefore be applicable to other reservoirs in the play.

Caroline L. Breton � Bureau of EconomicGeology, Jackson School of Geosciences, Universityof Texas at Austin, Austin, Texas 78713-8924;[email protected]

Caroline Breton is currently working as a researchassociate at the Bureau of Economic Geology, Uni-versity of Texas at Austin. She graduated with a B.A.degree in geography from the University of Texasat Austin in 2000. Her research interests includeGeographic Information Systems and cartography.

Stephen C. Ruppel � Bureau of Economic Geol-ogy, Jackson School of Geosciences, University ofTexas at Austin, Austin, Texas 78713-8924;[email protected]

Steve Ruppel is a senior research scientist at theBureau of Economic Geology at the University ofTexas at Austin, where he specializes in the charac-terization of Paleozoic carbonate-reservoir successions.His current research is focused on identifying thestratigraphic and diagenetic controls of reservoirdevelopment in outcropping and subsurface Permiancarbonates in the Permian basin.

Charles Kerans � Bureau of Economic Geology,Jackson School of Geosciences, University of Texasat Austin, Austin, Texas 78713-8924

Charles Kerans has been a senior research scientistat the Bureau of Economic Geology, the University ofTexas at Austin, since 1985. His research emphasisis on the construction of sequence-stratigraphic frame-works for carbonate-reservoir characterization. He hasbeen an AAPG Distinguished Lecturer and has wonseven awards for best paper, including those from thePermian Basin Section–SEPM and the West TexasGeological Society, and the Pratt Memorial Awardfrom AAPG.

ACKNOWLEDGEMENTS

This research was funded by the U.S. Departmentof Energy under contract number DE-FC26-02NT15131under Daniel F. Ferguson, project manager. Supportwas also provided by the Bureau of Economic Geology’sUniversity Lands Project and the Characterizationof San Andres and Grayburg Reservoirs Project, as wellas by the New Mexico Bureau of Geology andMineral Resources. Mark H. Holtz and F. Jerry Luciagenerously provided to the project their expertise onPermian basin geology and hydrocarbon production.Jianhua Zhou performed the Geographic InformationSystem mapping of New Mexico oil fields. Wegratefully acknowledge the constructive comments ofpeer reviewers Wayne M. Ahr, Salvatore J. Mazzullo,and Emily L. Stoudt and AAPG Editor Ernest A. Mancini.Lana Dieterich edited the manuscript. Published bypermission of the director, Bureau of Economic Geology,John A. and Katherine G. Jackson School of Geosciences,University of Texas at Austin.

554 E&P Notes

This paper geologically defines and describes 32 oil

plays of the Permian basin, lists reservoir-development

practices that have been used in various plays, and pro-

vides an overview of the basin-production history. It is

intended as a summary reference to Permian basin oil

plays and a guide to published examples of best practices.

More extensive details and data from the study can be

found in Dutton et al. (2004). Although this study is

specific to the Permian basin, its insights into mature

basin development may help guide development of

other maturing basins worldwide.

Geologic Setting

The Permian basin is a foredeep basin that developed

during the late Mississippian and early Pennsylvanian

(Hills, 1984; Frenzel et al., 1988) at the south margin

of the North American plate, north of the present-day

Marathon–Ouachita thrust belt (Figure 1). Prior to de-

velopment of the Permian basin, a shallow, intracra-

tonic, downwarped area named the Tobosa basin (Galley,

1958) was present in west Texas and southeast New

Mexico. Oil production in the Permian basin has come

predominantly from reservoirs of Ordovician to Perm-

ian age (Figure 2).

Methods

We defined 32 Permian basin oil plays (Table 1) on the

basis of reservoir stratigraphy, lithology, depositional

environment, and structural and tectonic setting. This

new play analysis builds on and revises earlier play as-

sessments of the Permian basin by Galloway et al. (1983),

Kosters et al. (1989), Tyler et al. (1991), Holtz and

Figure 1. Major subdivisionsand boundaries of the Permianbasin (shaded area) in westTexas and southeast New Mex-ico (modified from Silver andTodd, 1969; Hills, 1984; Frenzelet al., 1988; Kosters et al., 1989;Ewing, 1990; Tyler et al., 1991;Kerans and Fitchen, 1995).

Dutton et al. 555

Figure 2. Stratigraphic nomenclature for thePaleozoic section in the Permian basin. Agesare based on Harland et al. (1989), Tucker andMcKerrow (1994), and Bowring et al. (1998).Source rock identification is from J. A. Williams(1977, personal communication) and Hill et al.(2004).

556 E&P Notes

Kerans (1992), Holtz (1993), New Mexico Bureau of

Mines and Mineral Resources (1993), Ruppel and Holtz

(1994), Holtz and Garrett (1997), and Dutton et al.

(2000), as well as unpublished studies by the authors.

We identified 1339 significant-sized oil reservoirs

in the Permian basin, defined as reservoirs having

cumulative production of greater than 1 million bbl

(1.59 � 105 m3) through the year 2000, and assigned

each of them to a play. Cumulative production infor-

mation for reservoirs in Texas was taken from produc-

tion records of the Railroad Commission of Texas

(RRC, 2001). Cumulative production for reservoirs in

New Mexico was calculated by taking the annual pro-

duction from 1994 to 2000 and adding it to the cumu-

lative production data obtained from the 1993 annual

report (New Mexico Oil and Gas Engineering Com-

mittee, 1993). We calculated cumulative production for

each play by summing production from the significant-

sized reservoirs. We drew play boundaries for each play

to include areas where oil reservoirs in that play occur but

are smaller than 1 million bbl (1.59 � 105 m3) of cumu-

lative production. We used decline-curve analysis to esti-

mate remaining reserves of each play in the Permian basin.

PLAY SUMMARIES

A brief definition of each oil play in the Permian basin

is given in this section. More extensive information

and references about each play are included in Dutton

et al. (2004).

Ordovician Plays

Three oil plays in the Permian basin produce from

Ordovician reservoirs (Table 1; Figure 3). The Lower

Ordovician Ellenburger Group (Figure 2) consists of

thick (up to 1700 ft [520 m]), areally extensive se-

quences of mud-dominated carbonates, with localized

grainstones deposited on a restricted carbonate ramp

(Kerans, 1990). Sea level fall at the end of the Early

Ordovician resulted in the exposure of the ramp and

the development of widespread karst terrain (Kerans,

1990). Subsequent multiple karst events, erosion, and

compressive tectonism from the Ordovician to the Penn-

sylvanian also affected Ordovician rock characteristics

(Holtz and Kerans, 1992).

The carbonates of the Ellenburger selectively dolo-

mitized ramp carbonate play reflect a range of environ-

ments from inner to outer ramp (Figure 3). Reservoirs

include both dolomitized and undolomitized (limestone)

intervals. Subtidal carbonates are locally common, re-

flecting the more basinward setting (Holtz and Kerans,

1992). Ellenburger rocks in this play experienced sev-

eral episodes of exposure, karstification, and fracturing

(Combs et al., 2003). Main influences on reservoir char-

acter are variable dolomitization and karstification.

Pervasively dolomitized reservoirs of the Ellen-

burger karst-modified restricted ramp carbonate play

(Figure 3) were deposited in an inner-ramp setting

(Kerans, 1990). The main controls on porosity distri-

bution are extensive erosion and karstification that

occurred during the early Middle Ordovician low-

stand (Kerans, 1988). Reservoir heterogeneity results

from extensive dissolution, cave formation, and

subsequent cave infilling (Kerans, 1988; Loucks, 1999),

which formed a pervasive breccia-fracture system (Holtz

and Kerans, 1992).

Middle Ordovician transgression of the area re-

sulted in the deposition of shales, carbonates, and sand-

stones of the Simpson Group (Figure 3). These deposits

accumulated in a broad depocenter commonly referred

to as the Tobosa basin (Galley, 1958). Reservoirs in the

Simpson cratonic sandstone play are found in three re-

gionally extensive sandstones, the Connell, Waddell,

and McKee (Galley, 1958). The Connell sandstone is

interpreted as having been deposited in a range of

environments, from high-energy shoreface and near-

shore environments to more distal and lower energy

marine environments (Suhm and Ethington, 1975).

Silurian Plays

Reservoirs productive from Silurian rocks can be sub-

divided into two distinct lithologic successions: the

Fusselman Formation (Upper Ordovician to middle

Silurian) and the Wristen Group (middle to Upper

Silurian) (Figure 2). The reservoirs of the Fusselman

shallow-platform carbonate play (Figure 4) are com-

posed of limestones, dolostones, and cherty dolostones

that were deposited on an open-marine, shallow-water

carbonate platform that extended over much of the

mid-continent region (Ruppel and Holtz, 1994; Maz-

zullo, 1997). Reservoir facies are pelmatozoan pack-

stones and grainstones and ooid grainstones. Also

included in this play are reservoirs that produce

from shallow-water limestones and dolostones of

the Upper Ordovician Montoya Formation (Behnken,

2003).

Rocks of the Wristen Group (Figure 2) reflect de-

position in a spectrum of platform-to-basin settings

Dutton et al. 557

Table 1. Production in 2000 and Cumulative Production Through December 31, 2000, of Oil Plays in the Permian Basin, Listed by

Reservoir Age

Play State

2000 Production

(bbl)

Cumulative Production

(bbl)

PermianGuadalupian

Artesia platform sandstone Texas and New Mexico 6,526,676 1,855,409,025

Queen tidal-flat sandstone Texas 1,517,501 179,600,166

Delaware Mountain Group basinal sandstone Texas and New Mexico 9,208,247 351,912,395

Grayburg high-energy platform

carbonate–Ozona arch

Texas 1,968,685 298,378,769

Grayburg platform carbonate Texas 10,104,204 1,271,232,325

Grayburg platform mixed clastic-carbonate Texas 7,806,840 669,727,337

San Andres–Grayburg lowstand carbonate Texas 9,357,241 681,131,877

Upper San Andres and Grayburg platform

mixed–Artesia Vacuum trend

New Mexico 11,392,997 796,416,386

Upper San Andres and Grayburg platform

mixed–Central Basin platform trend

New Mexico 5,790,360 808,957,693

San Andres platform carbonate Texas 26,420,818 2,151,296,650

San Andres karst-modified platform carbonate Texas 11,460,129 1,567,103,814

Eastern shelf San Andres platform carbonate Texas 6,613,837 706,897,011

Northwest shelf San Andres platform carbonate Texas and New Mexico 50,666,870 3,969,256,500

158,834,405 15,307,319,948Leonardian

Spraberry–Dean submarine-fan sandstone Texas 27,576,283 1,287,098,237

Bone Spring basinal sandstone and carbonate New Mexico 2,455,154 70,703,460

Leonard restricted platform carbonate Texas and New Mexico 49,928,957 3,297,197,998

Abo platform carbonate Texas and New Mexico 6,105,583 541,459,683

86,065,977 5,196,459,378Wolfcampian

Wolfcamp–Leonard slope and basinal carbonate Texas and New Mexico 9,093,948 195,077,551

Wolfcamp platform carbonate Texas and New Mexico 4,012,646 457,405,339

13,106,594 652,482,890PennsylvanianUpper Pennsylvanian and Lower Permian slope

and basinal sandstone*

Texas 1,802,373 271,448,389

Pennsylvanian and Lower Permian Horseshoe

atoll carbonate

Texas 13,686,639 2,699,242,936

Pennsylvanian platform carbonate Texas 2,076,281 340,469,274

Northwest shelf upper Pennsylvanian carbonate New Mexico 4,883,971 353,848,173

Northwest shelf Strawn patch reef New Mexico 1,539,376 70,337,831

Pennsylvanian and Lower Permian

reef and bank**

Texas 315,183 92,104,283

Upper Pennsylvanian shelf sandstone# Texas 426,556 7,264,141

24,730,379 3,834,715,027MississippianMississippian platform carbonate Texas 91,765 15,110,822

91,765 15,110,822DevonianDevonian Thirtyone ramp carbonate Texas 1,747,319 110,249,504

558 E&P Notes

Devonian Thirtyone deepwater chert Texas and New Mexico 6,786,521 785,929,988

8,533,840 896,179,492SilurianWristen buildups and platform carbonate Texas and New Mexico 4,773,912 888,757,885

Fusselman shallow-platform carbonate Texas and New Mexico 2,046,889 356,268,389

6,820,801 1,245,026,274OrdovicianSimpson cratonic sandstone Texas and New Mexico 420,651 103,228,356

Ellenburger karst-modified restricted ramp carbonate Texas and New Mexico 2,802,096 1,487,309,287

Ellenburger selectively dolomitized ramp carbonate* Texas 537,120 163,734,910

3,759,867 1,754,272,553

Total 301,943,628 28,901,566,384

*Includes all reservoirs in this play, including ones in north-central Texas geologic province.**Production listed here represents only the 10 reservoirs in the Permian basin portion of the play.#Production listed here represents only the five reservoirs in the Permian basin portion of the play.

Table 1. Continued

Play State

2000 Production

(bbl)

Cumulative Production

(bbl)

Figure 3. Play boundariesof Ordovician oil plays in thePermian basin. Play outlinesare, in part, derived from out-lines previously published byHoltz and Kerans (1992) andHoltz and Garrett (1997).

Dutton et al. 559

following the downwarping and drowning of the pre-

existing Fusselman shallow-water platform during the

middle Silurian (Ruppel and Holtz 1994). The middle

Silurian (Wristen) platform margin trended east-west

across southern Andrews and northern Midland

counties and marks the southern limit of the Wristen

buildups and platform carbonate play (Figure 4). Wristen

production is derived almost entirely from carbonates

deposited either in platform-margin buildups or in

shallow-water facies of the platform interior (Ruppel

and Holtz 1994).

Devonian and Mississippian Plays

A major rise in relative sea level occurred in the Early

Devonian in west Texas and southeast New Mexico.

The Lower Devonian Thirtyone Formation (Figure 2)

records infilling of the Silurian (Wristen Group) basin

(Ruppel and Holtz 1994). Reflecting this fact, the north-

ern boundary of the Thirtyone closely approximates

the position of the Wristen platform margin. The Thirty-

one Formation contains two end-member facies, (1) car-

bonate packstones and grainstones and (2) spiculitic

chert (Ruppel and Holtz 1994). Carbonates deposit-

ed as in-place accumulations on the Early Devonian

shallow-water platform and as resedimented skeletal

sands on the outer ramp to slope form the Devonian

Thirtyone ramp carbonate play (Figure 4). Reservoir

rocks in this play are skeletal packstones and grain-

stones composed primarily of pelmatozoan debris

(Ruppel and Holtz 1994; Weiner and Heyer, 1999).

Reservoir quality is a function of diagenesis; both silic-

ification and local leaching of carbonate mud are im-

portant in reservoir development.

Cherts that accumulated in deeper water in areas

of reduced carbonate deposition form the Devonian

Thirtyone deepwater chert play (Figure 4). Thick-bedded

laminated chert, commonly called ‘‘tripolitic chert,’’ is

the most important reservoir facies in the Thirtyone

Formation (Ruppel and Holtz 1994; Saller et al.,

2001). The chert is highly porous and contains vary-

ing amounts of carbonate. Thirtyone Formation chert

Figure 4. Play boundariesof Silurian, Devonian, andMississippian oil plays in thePermian basin. Silurian andDevonian play outlines are, inpart, derived from outlinespreviously published by Ruppeland Holtz (1994).

560 E&P Notes

strata accumulated in deepwater slope and basin set-

tings by submarine gravity flow and hemipelagic

sedimentation (Ruppel and Holtz 1994; Ruppel and

Barnaby, 2001).

The Mississippian platform carbonate play extends

across much of the Permian basin (Figure 4). Upper Mis-

sissippian platform carbonates are shelf equivalents of

the Barnett Shale, which was deposited in the deeper

water to the south and east (Hamilton and Asquith,

2000). Mississippian fields in eastern Gaines and west-

ern Dawson counties are interpreted as occurring in

Chesterian ooid grainstones that developed landward of

the platform margin (Hamilton and Asquith, 2000).

Pennsylvanian Plays

Present structural features of the Permian basin, in-

cluding the Central Basin platform and Midland and

Delaware basins (Figure 1), began forming in the early

Pennsylvanian (Frenzel et al., 1988). Most of the anti-

clines that form the traps for oil-producing reservoirs in

the area formed during Pennsylvanian faulting. The

thickness and distribution of Pennsylvanian rocks in the

Permian basin are quite variable because of nondeposi-

tion and erosion over positive areas such as the Central

Basin platform.

Five Pennsylvanian oil plays occur in the Permian

basin (Figure 5). Most Pennsylvanian reservoirs pro-

duce from ramp and platform carbonates, but sand-

stones deposited in slope and basin environments on

the east side of the Midland basin are also produc-

tive. Two additional plays, the Pennsylvanian and Lower

Permian reef and bank play and upper Pennsylva-

nian shelf sandstone play, are located mostly in north-

central Texas but extend into the eastern Midland ba-

sin. Production from only those reservoirs that are in

Permian basin has been included for these plays in the

total Permian basin oil production shown in Table 1.

Patch reefs in the Northwest shelf Strawn patch

reef play (Figure 5) grew on a south-dipping carbon-

ate ramp in the western Permian basin before it seg-

mented into the Northwest shelf and the Delaware

Figure 5. Play boundaries ofPennsylvanian oil plays in thePermian basin. Some play out-lines are, in part, derived fromoutlines previously publishedby Holtz and Garrett (1997)and Dutton et al. (2000) andfrom the work of Mazzullo(1997).

Dutton et al. 561

basin. Reservoirs are principally bioherms composed

of phylloid algal, coralgal, and foraminiferal wacke-

stones and packstones (Harris, 1990). Bioherm growth

was localized on preexisting structures having bathy-

metric expression.

Later in that area, upper Pennsylvanian and earliest

Wolfcampian reservoir rocks of the Northwest shelf

upper Pennsylvanian carbonate play (Figure 5) were de-

posited on a shallow-water carbonate shelf and at the

shelf margin. Traps in the play are primarily stratigraph-

ic, with reservoirs formed by phylloid-algal mounds

and associated grainstones and packstones (Cys, 1986).

Massive, dolomitized, phylloid-algal mound reservoirs

grew at bathymetric breaks at or near the shelf edge

(Wahlman, 2001).

Pennsylvanian carbonates deposited on the Cen-

tral Basin platform and in the Midland basin (Figure 5)

compose the Pennsylvanian platform carbonate play.

Atokan and Desmoinesian carbonates were deposited

on low-relief ramps at a time of relatively low regional

subsidence, whereas Missourian and Virgilian carbonates

were deposited on higher relief carbonate platforms at

a time of higher rates of regional subsidence (Hanson

et al., 1991; Mazzullo, 1997). High-frequency glacioeu-

static sea level fluctuations during the Pennsylvanian

resulted in highly cyclic successions of shallow-water

carbonate-platform facies (Heckel, 1986; Reid and Reid,

1999; Wahlman, 2001). Porosity in these rocks is devel-

oped primarily in thick grainstones and phylloid-algal

boundstones (Saller et al., 1999).

The Pennsylvanian and Lower Permian Horseshoe

atoll carbonate play produces from reservoirs on the

Horseshoe atoll, a nonreefal isolated carbonate plat-

form system in the northern Midland basin (Figure 5).

Production is from stacked Strawn through Wolfcamp

limestones and dolomitic limestones that aggraded

from the floor of the basin in a northward-opening

arc (Galloway et al., 1983). Deposition of the Horse-

shoe atoll began on a broad Strawn carbonate plat-

form (Vest, 1970), with later development of iso-

lated carbonate knolls and pinnacles. Exposure and

erosion at sequence boundaries during the late Mis-

sourian through Virgilian produced a series of trun-

cation surfaces and local development of erosionally

generated slope wedges associated with major eustatic

sea level falls (Reid and Reid, 1991, 1999; Kerans,

2001).

The Cisco to Wolfcamp clastic rocks of the upper

Pennsylvanian and Lower Permian slope and basinal

sandstone play (Figure 5) were deposited as submarine

fans that accumulated basinward of the Eastern shelf

as it prograded westward (Galloway and Brown, 1972).

Reservoir-quality sand bodies were deposited in the

lower portions of slope wedges along a broad north-

south–trending belt during sea level lowstands (Brown

et al., 1990). Production is from turbidite sandstones

deposited in submarine-fan channel, lobe, and overbank

and levee environments (Neuberger, 1987).

Lower Permian Plays

During the Early Permian (Wolfcampian and Leonar-

dian), carbonate deposition occurred on the shelves

around the Midland and Delaware basins; carbonate

debris and siliciclastics were deposited in the basins.

Some portions of the western Central Basin platform

remained emergent throughout the Wolfcampian, but

by the Leonardian, this area was a stable, shallow-water

carbonate platform (Frenzel et al., 1988).

The Wolfcamp platform carbonate play (Figure 6)

lies along the east side of the Central Basin platform

and north of the east-west–trending Wolfcampian shelf

margin in New Mexico (Figure 1). The reservoirs in this

play are composed of cyclic, shallow-water carbonate

facies that are overprinted by diagenesis at and below

cycle tops formed during sea level fall (Saller et al.,

1994, 1999).

During the Wolfcampian and into the Leonardian,

carbonate debris was shed off the carbonate shelf mar-

gins rimming the Central Basin platform and Eastern

shelf and deposited in the Midland and Delaware ba-

sins. Reservoirs of the Wolfcamp–Leonard slope and

basinal carbonate play (Figure 6) are resedimented

carbonates deposited by debris flows and turbidity

currents on the lower slope and basin floor (Hobson

et al., 1985; Loucks et al., 1985; Mazzullo and Reid,

1987; Mazzullo, 1997). These rocks contain clasts of

shallow-water facies identical to those observed on

the platform, indicating that they were derived by

downslope transport from the platform margin. Res-

ervoirs in this play also contain a high proportion of

oolitic and skeletal grainstone deposited as massive

sediment-gravity flows, producing a superficial resem-

blance to shallow-water reservoirs (Ahr, 2000).

Abo deposition at the beginning of the Leonardian

(Figure 2) marks the transition from paleogeographically

complex late Pennsylvanian–Wolfcampian isolated build-

ups to more organized shelf-margin platforms (Kerans,

2000). Reservoirs in the Abo platform carbonate play

(Figure 7) are developed in shelf and shelf-margin fa-

cies along the south margin of the Northwest shelf.

562 E&P Notes

Platform-margin Abo successions are dominated by

grain-rich packstones and grainstones that under-

went significant karst-related diagenesis (Kerans, 2000;

Kerans et al., 2000) and are extensively dolomitized in

the New Mexico portion of the play.

Reservoirs of Leonardian age on the Central Basin

platform, Northwest shelf, and Eastern shelf are in-

cluded in the Leonard restricted platform carbonate

play (Figure 7). Leonardian rocks in this play were

deposited in restricted, low-energy depositional con-

ditions on a shallow-water, flat-topped carbonate plat-

form. The best reservoir quality is commonly associated

with grain-dominated, dolomitized, subtidal rocks

(Ruppel, 2002).

Reservoirs in the Bone Spring basinal sandstone

and carbonate play were deposited in a basinal setting

seaward of the Abo shelf edge in the Delaware basin

(Figure 7). Production is from deepwater carbonate

debris flows and fine-grained turbidite sandstones (Wig-

gins and Harris, 1985; Saller et al., 1989; Montgom-

ery, 1997).

Reservoirs of the Spraberry–Dean submarine-fan

sandstone play (Figure 7) were deposited as large basin-

floor submarine-fan systems in the Midland basin that

were fed by turbidity currents and debris flows (Hand-

ford, 1981; Tyler et al., 1997). Most of the production

is from very fine-grained sandstone and coarse siltstone

units in the Spraberry. Natural fractures cause high

rates of initial production, but the matrix contains most

of the oil and controls long-term recovery (Montgomery

et al., 2000).

Upper Permian (Guadalupian) Plays

Guadalupian reservoirs in the Permian basin (Table 1)

are developed primarily in San Andres and Grayburg

carbonates deposited on shallow-water shelves that

surrounded the Midland and Delaware basins and on

the Central Basin platform and Ozona arch. Deepwater

sandstones deposited in the Delaware basin and shelf

sandstones associated with sabkha carbonates and evap-

orites are also productive.

Figure 6. Play boundaries ofWolfcampian oil plays in thePermian basin. Some play out-lines are, in part, derived fromoutlines previously publishedby New Mexico Bureau of Minesand Mineral Resources (1993),Holtz and Garrett (1997), andDutton et al. (2000) and fromthe work of Mazzullo (1997).

Dutton et al. 563

The Northwest shelf San Andres platform carbon-

ate play (Figure 8a) represents a regressive series of cy-

clic deposits that prograded southward across the broad,

low-relief, shallow-water Northwest shelf. Restricted-

marine, subtidal dolostones in the lower and middle

San Andres form the main reservoir facies (Cowan and

Harris, 1986). Porous zones are offset basinward and oc-

cur in increasingly younger strata southward (Ramon-

detta, 1982; Cowan and Harris, 1986; Ward et al., 1986).

The Eastern shelf San Andres platform carbonate

play (Figure 8a) produces mainly from dolostones in the

San Andres and Grayburg formations, as well as sand-

stones in the Queen, Seven Rivers, and Yates formations

(Figure 2) (Mooney, 1982). The Eastern shelf prograded

westward into the Midland basin during the Permian.

Carbonate deposition ended on the Eastern shelf during

the middle Guadalupian, and upper Guadalupian rocks

are composed of cyclic deposits of sandstone, anhydrite,

and halite (Silver and Todd, 1969; Ward et al., 1986).

Reservoirs of the San Andres karst-modified plat-

form carbonate play produce from the structurally high

south end of the Central Basin platform (Figure 8a);

most production has come from Yates field. The main

reservoirs are dolostones characterized by thick accu-

mulations of grainstones at the top of a shallowing-

upward sequence (Tinker, 1996). Permeability was

greatly increased by open caves and solution-enlarged

joints that developed by karstification during multi-

ple subaerial exposure events during and following

San Andres deposition (Craig, 1988; Tinker et al., 1995).

Carbonates of the San Andres platform carbonate

play were deposited on the shallow-water Central Basin

platform during the early Guadalupian (Figure 8a).

Reservoirs in this play are developed primarily in thick,

dolomitized, subtidal portions of shoaling-upward cycles

(Ruppel and Cander, 1988; Garber and Harris, 1990).

Early, pervasive dolomitization preserved much of the

primary porosity in these San Andres reservoirs (Ruppel

and Cander, 1988).

Production is commingled from both dolostone and

clastic reservoirs in the upper San Andres and Grayburg

formations on the northwest portion of the Central

Figure 7. Play boundaries ofLeonardian oil plays in the Perm-ian basin. Some play outlinesare, in part, derived from out-lines previously published byNew Mexico Bureau of Minesand Mineral Resources (1993),Holtz and Garrett (1997), andDutton et al. (2000) and thework of Ruppel (2002).

564 E&P Notes

Basin platform and on the Northwest shelf. In the up-

per San Andres and Grayburg platform mixed–Central

Basin platform trend play (Figure 8a), reservoirs consist

of high-energy dolograinstones formed in shoal en-

vironments and shallow-marine dolomitic sandstones

(Garber and Harris, 1990; Lindsay, 1991). Similar res-

ervoirs in the upper San Andres and Grayburg platform

mixed–Artesia Vacuum trend play (Figure 8a) occur

along the Artesia-Vacuum arch, a shallow east-west–

trending structure that overlies the Abo shelf-edge trend.

In both plays, some karst development has occurred in

the San Andres (Pranter et al., 2004). Grayburg reservoir

sandstones were deposited in coastal, sabkha, sand-flat,

and eolian environments (Handford et al., 1996).

Reservoirs in the San Andres–Grayburg lowstand

carbonate play (Figure 8a) lie structurally and topo-

graphically below the San Andres and Grayburg shelf-

margin reservoirs on the Central Basin platform and

the Northwest shelf. The shallow-water facies in these

reservoirs are interpreted as having been deposited in

the Midland basin during periods of sea level lowstand.

In contrast to San Andres and Grayburg reservoirs on

the Central Basin platform, oolite grainstones are com-

mon reservoir facies in this play (Dull, 1994). The

oolite grainstones probably formed by focused tidal

energy when the Midland basin was restricted to the

center of the basin and shoreline was lowered.

Reservoirs in the Grayburg platform carbonate

play occupy the southeast side of the Central Basin

platform in Texas (Figure 8b). Depositional style and

petrophysical properties of Grayburg platform carbon-

ate reservoirs are similar to those of the San Andres,

being thick, dolomitized, subtidal portions of shoaling-

upward cycles (Bebout et al., 1987; Tyler et al., 1991).

Reservoir quality has been influenced strongly by dia-

genesis, particularly dolomite alteration and anhydrite

alteration and removal (Ruppel and Lucia, 1996).

The Grayburg platform mixed clastic-carbonate

play is located northwest of the Grayburg platform

carbonate play on the Central Basin platform in Texas

(Figure 8b). It has been designated a separate play be-

cause production comes from porous and permeable

lower Grayburg fine-grained sandstones and coarse silt-

stones, as well as from San Andres and Grayburg car-

bonates. Grayburg siliciclastics are interpreted to be eo-

lian facies deposited during sea level falls and reworked

during subsequent sea level rises (Ruppel, 2001).

By the time of Grayburg deposition, the Midland

basin was areally restricted and shallow, and the Ozona

arch was a shallow-water platform across which water

was exchanged between the open ocean to the south and

west (Sheffield Channel, Figure 1) and the restricted

basin to the north (Tyler et al., 1991). The Grayburg

high-energy platform carbonate–Ozona arch play

produces from upper San Andres and Grayburg

carbonate reservoirs (Figure 8b). The reservoir section

in these fields is composed of numerous shoaling-

upward cycles of fusulinid grain-dominated packstones

and ooid grainstones (Zahm and Tinker, 2000).

Reservoirs in the Delaware Mountain Group basin-

al sandstone play produce from deepwater sandstones of

the Bell Canyon, Cherry Canyon, and Brushy Canyon

formations (Delaware Mountain Group) (Figures 2, 8b).

Delaware sandstones are interpreted as having been

deposited by turbidity currents, possibly derived from

dunes that prograded to the shelf break during sea

level lowstands; eolian sands were then carried into

the slope and basin by turbidity currents (Fischer and

Sarnthein, 1988; Gardner, 1992). Bell Canyon sand-

stones, the most productive unit, were deposited in

a basin-floor setting by a system of leveed channels

having attached lobes and overbank splays (Barton and

Dutton, 1999; Dutton et al., 2003).

The Queen tidal-flat sandstone play on the east

and south margins of the Central Basin platform

(Figure 8b) produces from the middle Guadalupian

Queen Formation. The reservoir sandstones, which

form the bases of progradational, shoaling-upward

cycles, were deposited in intertidal-flat, tidal-channel,

and shoreface environments (Holtz, 1994; Price et al.,

2000). They are overlain by supratidal dolomudstones

and massive anhydrite at the top.

Siliciclastics, carbonates, and evaporites of the Ar-

tesia Group were deposited on a broad, shallow shelf in

a back-reef lagoonal setting located updip of the shelf-

margin reef carbonates that rimmed the Delaware basin

(Silver and Todd, 1969; Ward et al., 1986). Sandstones

in the Queen, Seven Rivers, and Yates formations of the

Artesia Group (Figure 2) make up the Artesia platform

sandstone play, located along the west edge of the

Central Basin platform and on the Northwest shelf

(Figure 8b). Dolostones of the Queen, Seven Rivers,

Yates, and Tansill formations form secondary reservoirs.

RESERVOIR-DEVELOPMENT METHODS

A variety of new reservoir-development techniques

have been applied to Permian basin reservoirs recently

because of the large remaining resource target. Tyler

and Banta (1989) estimated that conventional recov-

ery in the Permian basin using then-current technology

Dutton et al. 565

would be only 30% of OOIP. Advanced secondary

and tertiary production techniques can improve the

recovery ratio by targeting remaining mobile oil and

residual oil in mature fields. The Permian basin is es-

timated as having the greatest potential for additional

oil production in the United States, containing 29%

(17.6 billion bbl [2.80 � 109 m3]) of estimated future

oil reserve growth (Root et al., 1995). Most reserve

growth from the basin will result from application of

improved reservoir-development practices to existing

fields. Newly implemented reservoir-development

methods being used in the Permian basin are listed by

play in Table 2. Enhanced-recovery methods that have

been demonstrated to work well in one reservoir in a

play should be applicable to other reservoirs in that

play because they share production characteristics.

Because many reservoirs in the Permian basin

produce by solution-gas drive (Galloway et al., 1983),

primary recovery efficiencies are typically low. Aver-

age primary recovery in selected Permian basin reser-

voirs characterized by solution-gas-drive mechanisms

was 14.8% (Tyler et al., 1991). Secondary waterflooding

is the most common reservoir-development method

used in the basin. Typical waterfloods have evolved

from peripheral floods to line-drive floods to pattern

floods, such as five-spot or inverted nine-spot pat-

terns. In plays in which solution-gas drives have been

supplemented by waterfloods, recovery efficiencies have

increased to an average of 26% (primary and secondary)

(Tyler et al., 1991). Waterflooding is used so commonly

throughout the basin that it has not been included in

Table 2 unless a particular pattern realignment or other

modification enhanced recovery.

Recent reservoir-development approaches in the

Permian basin include CO2 injection, horizontal dril-

ling, and drilling targeted by seismic-attribute analysis

(Table 2). Carbon dioxide flooding has worked well in

plays such as the Pennsylvanian and Lower Permian

Horseshoe atoll carbonate, San Andres platform carbon-

ate, Grayburg platform carbonate, Devonian Thirtyone

Figure 8. Play boundaries ofUpper Permian (Guadalupian)oil plays in the Permian basin:(a) part 1, (b) part 2. Some playoutlines are, in part, derivedfrom outlines previously pub-lished by New Mexico Bureauof Mines and Mineral Resources(1993), Holtz and Garrett (1997),and Dutton et al. (2000).

566 E&P Notes

deepwater chert, and Delaware Mountain Group ba-

sinal sandstone. The reservoirs in these plays have clear

target intervals, such as stacked grainstone-rich car-

bonate cycles or sandstones, and good top and lateral

seals. Carbon dioxide flooding is less likely to be suc-

cessful in plays having strongly fractured, bottom-

water-drive reservoirs, such as the San Andres karst-

modified platform carbonate and the Ellenburger plays.

A variety of techniques have been applied at Yates

field (San Andres karst-modified platform carbonate

play), including gravity drainage assisted by nitrogen

and CO2 injection, water coproduction, and steam in-

jection (Table 2) (Snell and Close, 1999; Campanella

et al., 2000). High-pressure air injection, a tertiary oil-

recovery technology used in low-permeability reservoirs

(Kumar et al., 1995), was tested for the first time in the

Permian basin in a pilot project in Barnhart field (Ellen-

burger selectively dolomitized ramp carbonate play)

(Loucks et al., 2003). Artificially created, downhole high-

energy, low-frequency shockwaves designed to coalesce

and allow bypassed oil to be swept to producers are

being tested in the Wasson South Clearfork unit (Wasson

72 field, Leonard restricted platform carbonate play).

PERMIAN BASIN PRODUCTION ANALYSIS

Production analysis of this mature basin was conducted

to better understand production trends through time,

by reservoir age and by lithology. Production data com-

piled for the 1339 significant-sized reservoirs in the

32 oil plays in the Permian basin were used as the main

data source (Table 1). The remaining reserves in the

Permian basin were estimated by play.

Production History and Attributes

The first large oil field (Westbrook) was discovered in

the Permian basin in 1921, and other major discov-

eries followed in the 1920s and 1930s, including Yates

Figure 8. Continued.

Dutton et al. 567

Table 2. Newly Implemented Recovery Techniques Used in Permian Basin Oil Plays*

Play Name

Reservoir-Development

Techniques References

Artesia platform sandstone Improved waterflooding by drilling

infill wells, realigning patterns,

and increasing water injection

Ring and Smith (1995)

CO2 flooding Ring and Smith (1995)

Queen tidal-flat sandstone Drilling bypassed pay identified

by 3-D seismic-attribute analysis

Lufholm et al. (1996)

Delaware Mountain Group

basinal sandstone

CO2 flooding Pittaway and Rosato (1991);

Flanders and DePauw (1993);

Dutton et al. (2003)

Horizontal and vertical wells

drilled in areas identified by

3-D seismic-attribute analysis

Hardage et al. (1998a, b)



Infill drilling guided by a 3-D

reservoir model

Zahm and Tinker (2000)

Grayburg platform carbonate CO2 flooding Tucker et al. (1998)

Horizontal CO2 injection wells Phillips Petroleum Company (2002)

Drilling bypassed pay identified by

3-D seismic-attribute analysis

Weinbrandt et al. (1998);

Ferdinand et al. (2002)

Grayburg platform mixed

clastic-carbonate

Strategic plugbacks, infill drilling,

and horizontal drilling

Entzminger et al. (2000);

Petersen and Jacobs (2003)

San Andres–Grayburg

lowstand carbonate

CO2 flooding Dull (1994); Watts et al. (1998)

Upper San Andres and Grayburg

platform mixed–Artesia

Vacuum trend

CO2 flooding; multilateral serpentine

horizontal wells

Pranter et al. (2004)


platform mixed–Central Basin

platform trend

No information

San Andres platform carbonate CO2 flooding Magruder et al. (1990)

San Andres karst-modified

platform carbonate

Gravity drainage assisted by nitrogen

injection, water coproduction,

and steam injection

Snell and Close (1999);

Campanella et al. (2000)

Eastern shelf San Andres

platform carbonate

Tiltmeter fracture mapping to establish

waterflood pattern orientation,

spacing, and injection rates

Griffin et al. (2000)

Northwest shelf San Andres

platform carbonate

CO2 flooding Drozd and Gould (1991)

568 E&P Notes

Spraberry–Dean submarine-fan

sandstone

Waterflooding using

low-rate water injection

Schechter et al. (2001)

Bone Spring basinal sandstone

and carbonate

Limited entry, two-stage stimulation Montgomery (1997)

Leonard restricted platform

carbonate

Targeted 10-ac (4-ha) infill

development using a line-drive

waterflood pattern

Montgomery et al. (1998);

Nevans et al. (1999)

Drilling lateral waterflood wells

in unfractured intervals

Martin and Hickey (2002)

Sinusoidal horizontal drilling Johnson et al. (1997)

High-energy, low-frequency shockwaves

Abo platform carbonate Selective perforation to prevent

coning of gas cap into oil rim

Hueni and Schuessler (1993)

Wolfcamp–Leonard slope and

basinal carbonate

Drilling channel facies on the

basis of 3-D seismic data

Montgomery (1996)

Wolfcamp platform carbonate Horizontal drilling Martin et al. (2002)

Upper Pennsylvanian and

Lower Permian slope and

basinal sandstone

No information


Horseshoe atoll carbonate

CO2 flooding Raines et al. (2001);

Genetti et al. (2003)

Pennsylvanian platform carbonate No information

Northwest shelf upper

Pennsylvanian carbonate

No information

Northwest shelf Strawn

patch reef

No information

Mississippian platform

carbonate

No information

Devonian Thirtyone

ramp carbonate

Horizontal drilling Weiner and Heyer (1999);

Burkett (2002)

Devonian Thirtyone CO2 flooding Kinder Morgan (2004)

deepwater chert Tertiary infill drilling and

CO2 injection

Saller et al. (2001)

High-pressure, lean-gas

injection and infill drilling

Galloway et al. (1983);

Ebanks (1988)

Table 2. Continued

Play Name



Dutton et al. 569

field in 1926 and Wasson and Slaughter fields in 1937

(Figure 9). The late 1940s and early 1950s saw ad-

ditional major discoveries, including Kelly-Snyder field

in 1948. Fewer major oil reservoirs were discovered after

the late 1950s, when cumulative reserves discovered in

the Permian basin began to level off (Figure 9).

The Permian basin produced 30.4 billion bbl

(4.83 � 109 m3) of oil through 2000. Oil production

from all reservoirs in the Texas portion of the Permian

basin (RRC districts 7C, 8, and 8A) was 25.6 billion bbl

(4.07� 109 m3) (Railroad Commission of Texas, 2001).

Production from all reservoirs in the New Mexico por-

tion of the basin was 4.8 billion bbl (7.63 � 108 m3)

(Dutton et al., 2004).

A total of 1339 reservoirs in the Permian basin

had individual cumulative production of greater than

Wristen buildups and

platform carbonate

No information

Fusselman shallow-platform

carbonate

Recompletions and infill drilling Ball (2003)

Simpson cratonic sandstone No information

Ellenburger karst-modified

restricted ramp carbonate

Selective recompletions Kerans (1988)

Ellenburger selectively

dolomitized ramp carbonate

High-pressure air injection Loucks et al. (2003)

*Waterflooding is used so commonly throughout the basin that it has not been included unless a particular pattern realignment or other modification enhancedrecovery.

Table 2. Continued

Play Name



Figure 9. Permian basin cumulative oil production discovered by year. Bars show years in which reservoirs were discovered, withthe height of bar indicating volume of oil produced by those reservoirs through 2000. Data are for the significant-sized reservoirshaving cumulative production of greater than 1 million bbl (1.59 � 105 m3) through 2000.

570 E&P Notes

1 million bbl (1.59 � 105 m3) through 2000. These

significant-sized reservoirs produced 28.9 billion bbl

(4.59� 109 m3) ofoil through 2000 (Table 1): 24.4 billion

bbl (3.88 � 109 m3) from 1040 reservoirs in Texas

and 4.5 billion bbl (7.15 � 108 m3) from 299 reser-

voirs in New Mexico. Analysis of the characteristics

of these significant-sized reservoirs provides valuable

insight into Permian basin oil production because they

account for 95% of the total production of 30.4 billion

bbl (4.83 � 109 m3) through 2000.

Production data for the significant-sized oil res-

ervoirs in the Permian basin compiled from 1970 to

2000 show that oil production has steadily decreased.

Peak production of more than 665 million bbl/yr

(1.06 � 108 m3/yr) was reached in the early 1970s. By

2000, annual oil production from significant-sized

reservoirs was 301.9 million bbl (4.80 � 108 m3)

(Table 1) or less than half the peak production. Some

of the largest plays in the Permian basin, the North-

west shelf San Andres platform carbonate and the

Pennsylvanian and Lower Permian Horseshoe atoll car-

bonate plays, have experienced significant decline. By

contrast, the Leonard restricted platform carbonate

play has exhibited a relatively stable to slightly de-

clining production history, and the Spraberry–Dean

submarine-fan sandstone play has recorded a stable to

slightly increasing production history.

Guadalupian-age reservoirs dominate cumulative

oil production in the Permian basin (54%), followed

by Leonardian (18%) and Pennsylvanian-age reservoirs

(13%) (Figure 10a). In 2000, the proportion of oil pro-

duced from Leonardian reservoirs was 29% (Figure 10b).

The increased proportion of production from Leonar-

dian plays occurs because production from Guadalupian

and Pennsylvanian plays has declined since the early

1970s, whereas Leonardian plays have a stable produc-

tion trend. Carbonates are, by far, the most productive

reservoirs in the Permian basin, accounting for 75% of

the cumulative production. Sandstone reservoirs have

produced 14%, mixed sandstone and carbonate reser-

voirs have produced 8%, and chert reservoirs have

produced 3%. Approximately 80% of significant-sized

oil reservoirs in the Permian basin produce from depths

of less than 10,000 ft (<3050 m).

Remaining Reserves

The remaining reserves of significant-sized oil reser-

voirs in the Permian basin were estimated by play

using decline-curve analysis. Because most significant-

sized oil reservoirs in the Permian basin are in mature

stages of production and reaching depletion, exponen-

tial decline curves were used. Historical production

Figure 10. Permian basin production by geologic age: (a) cumulative production through 2000; (b) production in 2000.

Dutton et al. 571

profiles of the 32 oil plays in the Permian basin were

plotted using production data from 1970 to 2000.

The remaining reserves to be produced from the

32 oil plays in the Permian basin were calculated to

year-end 2015 (Table 3). The total remaining oil re-

serves from significant-sized oil reservoirs are calcu-

lated at 3.25 billion bbl (5.17 � 108 m3). The North-

west shelf San Andres platform carbonate and Leonard

restricted platform carbonate plays compose more than

41% (1.34 billion bbl [2.13 � 108 m3)]) of this total. It

should be noted that the remaining reserves to be pro-

duced to year-end 2015 are that component of the re-

source base that has already been discovered and is

currently being produced using the technologies pres-

ently in place. Most additional future production from

the Permian basin will be attributable to reserve growth

in existing fields.

CONCLUSIONS

The Permian basin of west Texas and southeast New

Mexico remains a significant oil-producing basin.

Thirty-two geologically distinct oil plays covering both

the Texas and New Mexico portions of the Permian

basin have been defined, and significant-sized reser-

voirs in the Permian basin having cumulative produc-

tion of greater than 1 million bbl (1.59 � 105 m3) of oil

through 2000 were assigned to plays. The remaining oil

reserves that will be produced through 2015 from the

currently producing component of the resource were

calculated to be 3.25 billion bbl (5.17 � 108 m3). Ap-

plication of successful reservoir-development practices

to analogous reservoirs will aid in future production in

this mature basin, most of which will come from im-

proved recovery from existing fields.

REFERENCES CITED

Ahr, W. M., 2000, Carbonate pore properties as indices of reservoirquality (abs.): AAPG Annual Meeting Program, v. 13, p. A3–A4.

Ball, B. C., 2003, Identifying bypassed pay in the Fusselman andMontoya reservoirs of the Dollarhide field, Andrews County,Texas, in T. J. Hunt and P. H. Lufholm, eds., The Permianbasin: Back to basics: West Texas Geological Society Publica-tion 03-112, p. 1–12.

Barton, M. D., and S. P. Dutton, 1999, Outcrop analysis of a sand-rich, basin-floor turbidite system, Permian Bell CanyonFormation, west Texas: Transactions, Gulf Coast SectionSEPM 19th Annual Bob F. Perkins Research Conference,December 5–8, Houston, p. 53–64.

Bebout, D. G., F. J. Lucia, C. R. Hocott, G. E. Fogg, and G. W.Vander Stoep, 1987, Characterization of the Grayburg reservoir,

Table 3. Permian Basin Remaining Reserves to 2015 By Play

Play

Million

Barrels

Northwest shelf San Andres platform carbonate 679.8

Leonard restricted platform carbonate 665.7

San Andres platform carbonate 331.9

Spraberry–Dean submarine-fan sandstone 277.3


Horseshoe atoll carbonate

139.5


platform mixed–Artesia Vacuum trend

128.0

San Andres–Grayburg lowstand carbonate 106.9

Grayburg platform carbonate 89.8

Devonian Thirtyone deepwater chert 89.2

Grayburg platform mixed clastic-carbonate 72.7

Wolfcamp–Leonard slope and basinal carbonate 72.4

Delaware Mountain Group basinal sandstone 69.0

Eastern shelf San Andres platform carbonate 66.9

Artesia platform sandstone 61.0


platform mixed–Central Basin platform trend

52.8

San Andres karst-modified platform carbonate 48.3

Wristen buildups and platform carbonate 44.7

Abo platform carbonate 43.4

Wolfcamp platform carbonate 41.3

Ellenburger karst-modified restricted

ramp carbonate

25.2

Devonian Thirtyone ramp carbonate 19.0

Fusselman shallow-platform carbonate 17.5

Pennsylvanian platform carbonate 17.3



17.2

Northwest shelf upper Pennsylvanian carbonate 17.2

Bone Spring basinal sandstone and carbonate 16.9

Upper Pennsylvanian and Lower

Permian slope and basinal sandstone

11.0

Queen tidal-flat sandstone 8.0

Northwest shelf Strawn patch reef 7.9

Ellenburger selectively dolomitized ramp carbonate 3.8

Upper Pennsylvanian shelf sandstone

(Permian basin portion only)

3.4

Simpson cratonic sandstone 3.2


reef and bank (Permian basin portion only)

1.8

Mississippian platform carbonate 0.8

Total 3250.9

572 E&P Notes

University Lands Dune field, Crane County, Texas: Universityof Texas at Austin, Bureau of Economic Geology Report ofInvestigations 168, 98 p.

Behnken, F. H., 2003, Montoya conventional core description,depositional lithofacies, diagenesis and thin section petrogra-phy from the Pure Resources, Inc., Dollarhide Unit 25-2-S,Andrews County, Texas, in T. J. Hunt and P. H. Lufholm,eds., The Permian basin: Back to basics: West Texas GeologicalSociety Publication 03-112, p. 13–35.

Bowring, S. A., D. H. Erwin, Y. G. Jin, M. W. Martin, K. Davidek,and W. Wang, 1998, U/Pb zircon geochronology and tempo ofthe end-Permian mass extinction: Science, v. 280, p. 1039–1045.

Brown, L. F. Jr., R. F. Solı́s-Iriarte, and D. A. Johns, 1990, Regionaldepositional systems tracts, paleogeography, and sequencestratigraphy, upper Pennsylvanian and Lower Permian strata,north- and west-central Texas: University of Texas at Austin,Bureau of Economic Geology Report of Investigations 197, 116 p.

Burkett, M. A., 2002, Application of horizontal drilling in low-permeability reservoirs: Transactions, Southwest Section,AAPG, Ruidoso, New Mexico, p. 139–146.

Campanella, J. D., E. E. Wadleigh, and J. R. Gilman, 2000, Flowcharacterization—Critical for efficiency of field operations andIOR: Society of Petroleum Engineers International PetroleumConference, Villahermosa, Mexico, SPE Paper 58996, 14 p.

Combs, D. M., R. G., Loucks, and S. C. Ruppel, 2003, LowerOrdovician Ellenburger Group collapsed paleocave facies andassociated pore network in the Barnhart field, Texas, in T. J.Hunt and P. H. Lufholm, eds., The Permian basin: Back tobasics: West Texas Geological Society Publication 03-112,p. 397–418.

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