Warwink West field: New Delaware basin Bone Spring area

Scott L. Montgomery
Petroleum Consultant
Seattle
Larry Brooks
Pioneer Natural Resources
Midland, Tex.
David Scolman, Ralph Nelson
EEX Corp.
Houston

Warwink West field represents an important new area of discovery and development in the Delaware basin of West Texas. Officially opened in November 1996, the field produces from the Third Bone Spring sandstone member of the Bone Spring formation (Leonardian).

The Bone Spring formation is a regional carbonate and clastic reservoir up to 3,200 ft thick in the northern half of the basin and is approximately 3,000 ft thick at Warwink.

The new field is located approximately 40 miles south-southeast of the nearest significant Third Bone Spring field, the Red Hills complex (Fig. 1 [157,590 bytes]) in southern Lea County, N.M., opened in 1993. Reservoirs in both fields have low permeability (avg. 0.5 md) but after stimulation produce at rates of up to 750 b/d of oil. Together, these two fields define a potential exploration fairway approximately 400 sq miles in size within the deepest portion of the Delaware basin. Recognition of this new fairway has spurred recent leasing in Loving County, Tex., with bids as high as $900-$1,000/acre.

This article presents an introduction to the geology and producing characteristics of the Bone Spring reservoirs in Warwink West field. It is meant to emphasize how exploration in "mature" areas continues to have the potential to yield significant new discoveries.

Background

The significance of Warwink West needs to be understood in light of activity in the Bone Spring formation elsewhere in the basin.

Early exploration during the 1960s-70s focused mainly on sandstone reservoirs in the belief that the Bone Spring offered a possible equivalent to the highly productive Dean-Spraberry interval of the Midland basin. Production rates were relatively low, however, and the low-resistivity, low-permeability, clay-rich nature of the Bone Spring sands helped dissuade large exploration programs.

More significantly, the 1970s-80s brought high-volume discoveries in carbonate debris-flow deposits of the Bone Spring,^1-2 thus further shifting attention away from the clastic intervals. In addition, stratigraphic studies showed that the Bone Spring clastic intervals were not equivalent to the Dean-Spraberry but represented conditions specific to the Delaware basin.³

During the 1990s, a resurgence of interest occurred in the submarine-fan sandstone reservoirs of the Bone Spring.^4-5 This began as a result of serendipitous discoveries and subsequent recompletions along the slope in Lea and Eddy counties, N.M., and was soon expanded into full development programs at fields such as Old Millman Ranch,⁶ Young North,⁴ and Red Tank.

New interest in the Third Bone Spring sand, in particular, commenced with the discovery of Red Hills field in late 1993. Wells in Red Hills exhibit significantly higher productivity than do First and Second Bone Spring sand producers. Good producers at Red Hills have yielded 175,000-220,000 bbl in their first 2-3 years of production with only minor decline. Significantly, most wells in the field produce flowing (i.e. they are not on pump) from depths of 12,000 ft or greater, indicating good reservoir pressures and successful fracs.

Discovery at Warwink West was based mainly on a combination of subsurface mapping and re-evaluation of existing well data, both of which indicated significant sand development with productive potential west and downdip from Warwink South. In particular, a well drilled by Phillips Petroleum in 1976 showing two oil-bearing intervals (Fig. 2 [227,744 bytes]) was observed to have produced approximately 80,000 bbl of oil and 300 MMcf of gas without any reservoir stimulation.

The official discovery well at Warwink West, the 1 University 18-34 (Sec. 34, Block 18, University Lands), was located about 11/4 miles south-southeast and slightly down- dip of the Phillips well, in a location predicted to have equal or better sand development. The 1 University 18-34 well encountered the same two pay intervals between 11,410-11,550 ft depth and, after frac, was completed at a rate of 720 b/d of oil and 700 Mcfd of gas on a 7/64 in. choke with 3,700 psi flowing tubing pressure. Subsequent development has included the drilling of 18 wells with only one dry hole. Initial oil production rates have varied from 250-750 b/d. Plans called for an additional 20 or more wells in late 1997 and 1998.

Setting, stratigraphy

The Warwink area lies about 7 miles west of the Central Basin platform (CBP) margin, in the southern portion of the Delaware basin depocenter. This part of the basin is typified by complex, basement-involved reverse and strike-slip faulting^7-8 related to uplift of the CBP and that locally affects strata as young as lower Leonardian. Warwink field is broadly associated with a fault-bounded structure that exhibits approximately 300-400 ft of relief at the top of the Wolfcamp. Some of this relief, however, appears due to depositional factors and/or differential compaction.

Stratigraphically, the Bone Spring formation lies between lowermost Leonardian carbonates and shales (unnamed) and uppermost Leonardian carbonates and clastics of the Cutoff formation or, where absent, the deepwater clastics of the Brushy Canyon formation (Delaware Mountain Group).^1-2 Traditional assignment of the Bone Spring to the entire Leonardian interval has been proven erroneous by fusulinid biostratigraphic studies⁹ and detailed slope-to-basin correlations.¹⁰

Internal stratigraphic divisions of the Bone Spring are based on major lithologic divisions. The formation consists of an alternating series of three carbonate- and three clastic-dominated intervals, respectively (top to bottom) termed First, Second, and Third Bone Spring carbonate/sandstone. Carbonate intervals consist of nonreservoir spiculitic limestones, black laminated dolomitic mudstones, and reservoir dolomitized debris-flow deposits. Debris-flow material occurs in lenticular bodies along the lower slope and toe-of-slope and includes both a coarse, breccia lithofacies and bioclastic packstone facies. Bone Spring clastic intervals consist of nonreservoir pelagic shales and siltstones and reservoir sands deposited in submarine fan systems.

At Warwink, the Third Bone Spring sandstone has been variably divided into several or more informal units. For purposes of general correlation, it is helpful to identify two main reservoir zones, shown on Fig. 2 as "Warwink sands" and "Red Hills sands" (Fig. 2). However, for more detailed mapping, five individual pay sand units (unnamed) are identified (Fig. 2).

Reservoir character

Third Bone Spring sandstone reservoirs, like those of the First and Second Sandstone intervals, are very fine to fine-grained subarkoses showing moderate to good sorting and containing 4-12% clay by volume. Cementation is a result of quartz overgrowths and microcrystalline dolomite, the latter comprising up to 20% of the rock volume. Sedimentary structures include horizontal and parallel inclined lamination, ripple cross-lamination, convoluted bedding, trace fossils, and bioturbation. Many of the productive sands at Warwink are massive in texture and show excellent lateral continuity.

Porosities and permeabilities in these sandstones are 12-18% and 0.01-0.15 md. Core analysis indicates higher porosities are associated with better permeabilities; thus log porosity can be broadly employed as a first-order indicator of reservoir quality. Gamma ray profiles commonly show a coarsening-upward type signature, especially in thicker sand zones. Core study indicates this to be a result of an upward increase in bioturbation by organisms that consumed organic material within the original deposit. While such "cleansing" may be occasionally responsible for increased reservoir quality, this is not generally the case: porosities and permeabilities typically show little change upward within these sand layers.

At Red Hills field, thin section and scanning electron micrograph (SEM) imagery reportedly suggests that moderate to good porosities reflect a relatively high storage capacity but that pore throats are substantially reduced in size by a combination of quartz overgrowth, dolomite cement, authigenic clay (mixed layer illite/smectite), and fines. This may be the case at Warwink, also.

Because some wells, such as the Phillips 1 University BB, flow significant (if economically marginal) amounts of oil without stimulation it is assumed that natural fracturing plays a role in reservoir quality distribution. However, the nature of such fracturing, as well as its genesis and orientation, are not known, and thus the identification of "fracture sweet spots," if such may exist, is speculative.

Sandstone distribution

The cross section of Fig. 3 [144,270 bytes] and the net sand maps for the Red Hills (Fig. 4 [160,994 bytes]) and Warwink (Fig. 5 [175,386 bytes]) zones are meant to suggest the general distribution and continuity of productive intervals at Warwink, West.

Several important conclusions are suggested by Fig. 3. First, eastward onlap of the Red Hills sand zone onto the Warwink South high is clearly indicated. Rapid thickening in this zone to the west and northwest is easily seen in correlations between the Warwink South field wells and the Phillips 1 University BB. It should be noted that the 1 University 18-34 discovery well for Warwink West is located roughly midway between the Phillips well and the Superior 1-A University 32-18. Net sand thickness data for the Red Hills pay zone, meanwhile, highlight rapid eastward pinchout but suggest a blanket-type geometry to the west (Fig. 4).

Significant thickening of the Warwink pay zone is shown in the Union Texas 1 University 18-20, along the flank of the structure (Fig. 3). Fig. 5 appears to show that these sands filled a structural/bathymetric low with up to 20 ft of local relief. Thickness patterns in Figs. 4 and 5 imply transport from the east-northeast.

Fig. 3 also reveals that many of the individual sand layers productive at Warwink exhibit good to excellent continuity over distances of several miles or more. Log signatures for these sands, which range from 4-17 ft in thickness, are highly consistent. Local increases in the thickness of massive, good porosity sands are possibly related to better development of submarine channel facies. The blanket-type geometry of most sands, however, with gradual tapering to the southwest, argues for deposition across a broad submarine fan lobe.

Reservoir quality

The porosity-model cross section of Fig. 6 [122,847 bytes] indicates five separate pay sands in Warwink West, including three in the Warwink pay zone and two in the Red Hills zone. Of these pay sands, the most continuous are the B, C, and D, which exhibit density log porosities of 14-20% and consistent neutron-density cross over. The thickest high-porosity sand zone (18-20%) is in D, and this is generally the case across the whole central portion of the field (Secs. 33, 34, 37, and 38). Thickening of this interval and the increased porosity values (20%) apparent in well 1 University 18-33A may reflect the presence of channel facies at this location.

Separating these pay sands from each other are zones of siltstone and shale. Apparent sand lenses (12-14% porosity) within these non-reservoir zones are thinner and more discontinuous, suggestive of overbank deposits interbedded with distal fan silts and pelagic shales.

These non-reservoir zones are better developed in the 1 University 18-34B and rapidly increase in thickness to the east-northeast of this well. The noted sand lenses are not considered exploration targets due to their thinness and insufficient reservoir quality.

Completion, production

Wells in Warwink West field are completed using clean-up acid and frac treatments employing roughly 150,000-175,000 lb high-strength proppant. Initial production rates have varied from 300 b/d to over 750 b/d. Allowables for the field have been set at 679 b/d for 160 acre spacing and 339.5 b/d for 80 acre spacing. Current rules dictate 160 acre spacing for the field, with an option to re-space at 80 acres. In most cases, production has been held to 300-350 b/d in order to minimize frac sand flowback. Flowing tubing pressures in these wells can exceed 3,000 psi.

Decline curves exhibit hyperbolic flattening, with projected well life in the range of 15-20 years. Recoverable reserves for most wells are estimated at 275,000-500,000 bbl/well. As development is still in a relatively early stage, no fieldwide reserves estimates have been released.

Conclusions

Third Bone Spring sandstone reservoirs represent deepwater slope to basin floor submarine fan deposits, frequently with blanket-type geometry. Sandstone composition, grain size distribution, lateral continuity, and other factors suggest deposition in channel and levee/overbank settings, with channels perhaps more locally developed than in the First and Second Bone Spring sandstone intervals of the northern Delaware basin.⁴

Net sand mapping of individual sand packages within the overall pay zone is considered far more effective as a tool for field definition or exploration than is mapping of gross sand data. Seismic data in the area is generally of poor quality due to near-surface problems (statics and velocity distortion) related to upper Permian evaporites. However, when used in conjunction with subsurface mapping and well log data, seismic information can help confirm or delineate Third Bone Spring anomalies.

References

Gawloski, T.F., Nature, distribution, and petroleum potential of Bone Spring detrital sediments along the northwest shelf of the Delaware basin; in Cromwell, D and Mazzullo, L.J., eds., The Leonardian facies in West Texas and Southeast New Mexico and Guidebook to the Glass Mountains, West Texas; SEPM Permian Basin Section Publication 87-27, 1987, pp. 85-105.
Saller, A.H., Barton, J.W., and Barton, R.E., Slope sedimentation associated with a vertically building shelf, Bone Spring formation, Mescalero Escarpe field, southeastern New Mexico; in Cromwell, P.D., and Mazzullo, L.J., eds., The Leonardian facies in West Texas and southeast New Mexico and Guidebook to the Glass Mountains, West Texas; SEPM, Permian Basin Section Publication 87-27, 1989, pp. 275-288.
Mazzullo, S.J., Permian stratigraphy and facies, Permian basin (Texas-New Mexico) and adjoining areas in the Midcontinent U.S., in Scholle, P.A., Peryt, T.M., and Ulmer-Scholle, D.S., eds., The Permian of northern Pangea, Vol. 2, Springer-Verlag, Berlin; 1991, pp. 41-60.
Montgomery, S.L., Permian Bone Spring formation: Sandstone play in the Delaware basin, Part I-Slope; AAPG Bull., Vol. 81, No. 8, 1997, pp. 1,239-58.
Montgomery, S.L., Permian Bone Spring formation: Sandstone play in the Delaware basin, Part II-Basin; AAPG Bull., Vol. 81, No. 9, 1997, pp. 1,423-34.
Hayes, M.D., 1995, Old Millman Ranch Bone Spring; A symposium of the oil and gas fields of southeastern New Mexico (1995 supplement), Roswell Geological Society, 1995, pp. 302-305.
Shumaker, R.C., Paleozoic structure of the Central Basin uplift and adjacent Delaware basin, West Texas; AAPG Bull., Vol. 76, No. 11, 1992, pp. 1,804-24.
Yang, K-M. and Dorobek, S.L., The Permian Basin of West Texas and New Mexico: Tectonic history of a "composite" foreland basin and its effects on stratigraphic development; in Dorobek, S.L., and Ross, G.M. Ross, eds., Stratigraphic evolution of foreland basins, SEPM Spec. Pub. 52, 1995, pp. 149-174.
Mazzullo, L.J., and Reid, Jr., A.M., Stratigraphy of the Bone Spring formation (Leonardian) and depositional setting in the Scharb field, Lea County, N.M.; in Cromwell, D., and Mazzullo, L.J., eds., The Leonardian facies in West Texas and Southeast New Mexico and Guidebook to the Glass Mountains, West Texas; SEPM, Permian Basin Section Publication 87-27, 1987, pp. 107-111.
Gardner, M.H. and M.D. Sonnenfeld, Stratigraphic changes in facies architecture of the Permian Brushy Canyon Formation in Guadalupe Mountains National Park, West Texas; in DeMis, W.D. and A.G. Cole, eds., The Brushy Canyon Play in Outcrop and Subsurface: Concepts and Examples, Permian Basin Section, SEPM, Publication 96-38, 1996, pp. 17-40.

The Authors

Scott L. Montgomery is a petroleum consultant and author residing in Seattle. He is lead author of the "E&P Notes" series in the AAPG Bulletin and the quarterly monograph series "Petroleum Frontiers" published by Petroleum Information/Dwights LLC.
Larry Brooks is a staff geologist with Pioneer Natural Resources and Delaware basin lead explorationist for the company. He is a certified/registered petroleum geologist with over 20 years' experience in the Permian basin region. Main areas of interest and expertise include siliciclastic turbidite systems, carbonate debris flow deposits, shelf carbonates, and fluvio-deltaic depositional environments.
David Scolman is a staff geophysicist for Enserch. His current responsibilities include E&D for the Permian and Anadarko basins. He has 16 years' experience in oil and gas exploration and exploitation with an emphasis on sequence stratigraphy and computer-aided seismic data interpretation.
Ralph Nelson is a staff geologist for Enserch. His current responsibilities include Permian basin E&D. He has 22 years' experience in the oil and gas business with an emphasis on prospect generation and evaluation.