Abstract

As professionals in the industry sometimes the direction of our employers and the role we will play in that future seems obscure. We can see what U.S. oil & gas companies are doing, but why are they doing it? What forces are driving their behavior? One might ask, “I know there are some really smart guys running the show, so why do I see them doing things that don’t seem to make sense, and avoiding others that could make a lot of money?” An analysis of broad industry trends gives possible explanations for current industry behavior.

Tim Dunn is currently CEO of CrownQuest Operating, a Midland-based independent company, but his career has spanned a wide range of experience, including working as an engineer for Exxon, serving in an executive capacity for a financial institution, serving on the board of a publicly traded company and functioning as a chief financial officer for a company that received a first time listing on the New York Stock Exchange.

Abstract

Investing in West Texas and Southeastern New Mexico is back in vogue with investors. Reasons for a return of investor interest in the Permian Basin are: 1) long-life reserves, 2) proven basins, 3) well-known infrastructure, 4) interest rates, and 5) down economy and markets.

Abstract

In February 2002, ChevronTexaco drilled the Mittie Weatherly #7 to a TD of 7600’ (Abo Formation). The well had excellent data to work with including a full suite of logs (Gamma Ray Neutron/Lithodensity, Dual Laterolog/Rxo, and Sonic), a mudlog, and 60 sidewall cores from various formations. Nine of those sidewall cores were in the Permian Glorieta/Paddock dolomite and had significant shows which agreed with the mudlog, yet analysis of the log data was calculating the formation to be water productive. Since this well was going to be perforated in several deeper formations, a decision was made to test Glorieta/Paddock in the Mattern NCT-C #11 which appeared to have the same Glorieta/Paddock zones, is on strike to, and 1405’ north of Weatherly #7. Therefore, all of the available data from #7 was used as an analog for #11.

Since nine rotary sidewall cores were taken in the Permian Glorieta/Paddock dolomite, we were given an opportunity to compare detailed well log data with detailed core data. Using an Rw of .055 @ 77° Fahrenheit, a=1, and m=n=2, Archie Water Saturations (Swa) range from 31.5% to 69.4% and

are consistently less than Ratio Water Saturations (Swr = 53.3% to 96.1%) indicating the presence of vuggy/moldic porosity. Both Sonic porosities (Øsonic = 12.1% to 17.2%) and Rxo porosities (Ørxo = 8.9% to 14.9%) are less than Neutron/Density porosity (Ønd = 13.8% to 26.0%), also indicating the presence of vuggy/moldic porosity. Lack of Moved Hydrocarbons (Sw/Sxo = 0.60 to 0.97), high Archie and Ratio Water Saturations, and high Bulk Volume Water (BVW) values (0.071 to 0.128) suggest the Glorieta/Paddock should produce water.

Core porosities of the nine Glorieta/Paddock sidewall cores range from 11.5% to 24.8% with permeabilities from 0.08 md to 77.35 md. Gas liberated from the cores ranged from 28 units to 561 units with bright yellow-green to dull gold-yellow fluorescence over 40% to 100% of the individual cores. Core Water Saturations (Swcore) range from 23.1% to 60.3% and Oil Saturations (So) range from 12.7% to 37.3%. Petrographic analysis of the nine cores revealed the Glorieta/Paddock lithologies are dolomudstones, peloid dolomudstones, and ooid dolograinstones with both intercrystalline and moldic porosity as predicted by well log data. Hydrocarbon shows of the nine cores suggest the Glorieta/Paddock is hydrocarbon productive.

Production testing (overall perfs 5238 to 5294) of the Glorieta/Paddock in Mattern NCT-C #11 initially tested 300 BWPD with a slight show of gas (at pump capacity with high fluid level). After a specialized treatment for water shutoff and more than 7 months of production, the #11 was producing 1 BOPD, 41 BWPD, and 13 MCFGPD before abandoning the zone. Therefore, the lack of moved hydrocarbons (Sw/Sxo > 0.6), high Archie (Swa = 31.5% to 69.4%) and Ratio (Swr = 53.3% to 96.1%) Water Saturations, and high BVW values (0.071 to 0.128) determined from log data were correct in predicting the non-hydrocarbon productive potential of the Glorieta/Paddock.

Abstract

The Permian Basin of west Texas and southeast New Mexico remains an important oil-producing province and contains an estimated 30 Bbbl of remaining mobile oil. Increased use of enhanced-recovery practices in the Permian Basin can have a substantial impact on U.S. oil production. A new digital oil-play portfolio has been compiled for oil reservoirs in the Permian Basin. A total of 1,339 significant-sized reservoirs in the basin had cumulative production of >1 MMbbl of oil through 2000; total production from these reservoirs was 28.9 Bbbl. Thirty-two oil plays covering both the Texas and New Mexico parts of the Permian Basin were defined on the basis of reservoir stratigraphy, lithology, depositional environment, and structural and tectonic setting. Each of the 1,339 significant-sized reservoirs was assigned to a play and mapped in a Geographic Information System (GIS). The play portfolio contains a summary description of each play, including key reservoir characteristics and successful reservoir development methods. Enhanced-recovery methods that have been demonstrated to work well in one reservoir in a particular play should be applicable to analogous reservoirs in that play.

The plays having the largest cumulative production are the Northwest Shelf San Andres Platform Carbonate play (4.0 Bbbl), the Leonard Restricted Platform Carbonate play (3.3 Bbbl), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.7 Bbbl), and the San Andres Platform Carbonate play (2.2 Bbbl). The Permian System dominates production, accounting for 21.2 Bbbl, followed by the Pennsylvanian (3.8 Bbbl) and the Ordovician (1.8 Bbbl). Carbonate reservoirs have produced 75% of the oil, elastics 14%, mixed elastics and carbonates 8%, and chert 3%. Remaining reserves are 3.25 Bbbl from that component of the resource base that is already discovered and producing. Additional future production from the Permian Basin will be attributable to reserve growth and undiscovered resources.

Abstract

Since it yielded its first barrel of crude oil in 1920, the area encompassing parts of West Texas and Eastern New Mexico known as the Permian Basin has provided a significant portion of the energy needed to fuel the U.S. to its status as the world’s only superpower. Oil and natural gas have been the life blood of the communities residing within the boundaries of this subterranean sea of black gold. But over the years, changes have occurred which have questioned the long-term viability of the Permian Basin as an area of economic opportunity.

The state of the U.S. energy industry reveals energy demand continuing to outpace supply. This is putting added pressure on the oil and gas industry to produce more while the industry itself is going through significant structural changes with its aging workforce and the diminishing opportunities to book new domestic reserves. Meanwhile, the push for energy independence grows with the higher levels of terror threats. This will provide for growth in the alternative and renewable energy sources.

All of this has its effects on the Permian Basin. Midland is seen as the lead community in the Permian Basin and has much of its local economy dependent on the energy industry. Although Midland’s population continues to rise as well as the number of employees and payroll dollars, the survival of any community is based on the growth of its businesses. In Midland County, the growth in the number of businesses over the last 10 years has remained flat while there is a noticeable decline in the number of mining establishments, which includes oil and gas extraction companies.

But it appears Midland as well as other counties in West Texas are going through a transition caused by a change in demographics. The Baby Boomers, the largest generation in American history, have helped grow the community and the industry to where it is today. The subsequent generation, Generation X, which is about half the size of the Boomers, simply does not have the numbers to maintain the growth. But the next generation, Generation Y or the Millennial, who number approximately 76 million, will be the generation to help return the Permian Basin back to a higher level of growth.

It will be this generation which could help further develop the next generation of energy extraction technologies and it will be this generation who will further develop the nascent alternative and renewable energies. It will be the efforts by the Permian Basin communities today to attract this generation to the area and to the industry that will maintain the survival and growth of the Permian Basin Energy Industry.

Abstract

The Maverick Basin is a Jurassic/Cretaceous aged basin in South Texas on the Mexico boarder. Interest has picked up over the last three years due to some high profile discoveries, and a deep exploration well to the Jurassic section. This is a review of a basin analysis done by Tom Brown Inc. in the fall of 2003 and highlights a number of the opportunities and challenges of the basin. Major currently producing intervals, current exploration targets, and Deep exploration opportunities will be examined. Also covered will be Tom Brown Inc.’s history in the basin and what was lessons where learned as part of that process.

Abstract

Carbonate reservoirs of Siluro-Devonian age have produced more than 440 MMBO in southeastern New Mexico, or 9.9 percent of the oil produced in southeastern New Mexico. Of the 48 reservoirs that have produced at least 1 MMBO from Siluro-Devonian strata, 47 are productive from strata and only one is productive from the Devonian. The Wristen Formation (Silurian), which covers a large part of southeastern New Mexico, has yielded 84 percent of the Siluro-Devonian oil.

Productive reservoirs are located on the Northwest Shelf, the Central Basin Platform, and in the Delaware Basin. Traps are formed primarily by anticlines bounded by high-angle faults of Late Paleozoic age. Paleostructure maps of the Northwest Shelf indicate major structural trends.

Reservoirs within the deep Delaware Basin produce primarily gas from depths of more than 17,000 ft. Most reservoirs on the Northwest Shelf and Central Basin Platform produce oil with associated gas from reservoirs shallower than 13,000 ft.

The vertical seal for most traps is provided by the Woodford Shale (Devonian). True thickness of the Woodford exceeds 250 ft. in southern Lea County and thins to the north and west to a regional pinchout in southern Chaves and Roosevelt Counties. The Woodford is absent from large portions of the Central Basin Platform where it has been removed by erosion following Late Paleozoic uplift.

The Woodford has good source character throughout its extent in southeastern New Mexico. TOC exceeds 1.5 percent in all places it was measured. TOC is highest is highest in southern Lea County and gradually decreases to less than 2 percent along the northwestern regional Woodford pinchout. Oil and gas accumulations have been discovered in Silurian strata northwest of the regional Woodford pinchout where the Silurian carbonates are overlain by Mississippian, and in places Pennsylvanian strata.

The Woodford Shale is thermally mature over its entire extent in the Delaware Basin. It is in the thermogenic gas and condensate window in the deeper parts of the Delaware Basin and is in the oil window on the Northwest Shelf and where present on the Central Basin Platform. Thermal maturity is not completely correlative with depth; maturity is high in the western, shallower portions of the Delaware Basin.

Abstract

Carbonate reservoir rocks are typically deposited in shallow marine environments, where variations in depositional setting produce tight and porous lithologies in lateral and vertical proximity. Additionally, carbonate minerals are strongly susceptible to diagenetic alteration, further enhancing porosity and permeability variations. The Leonardian/Guadalupian (Permian) San Andres Formation in Vacuum field, Lea County, New Mexico, is a good example of a carbonate reservoir that has been compartmentalized by depositional and diagenetic variations. Dolomitized oolitic/peloidal and fusulinid/peloidal packstones and grainstones constitute the productive reservoir facies. Interbedded within these porous units are zones that are clearly “tight”, as indicated by both log character and production tests. Early geologic models of the San Andres formation in Vacuum field were primarily generated from petrophysical data, with no core examination to clarify the nature of the “tight” zones. These models resulted in lithostratigraphic correlations that crossed time lines and flow units.

Examination of 3,000 feet of core accurately reveals reservoir lithologies, and the origin of nonporous intervals. Tight zones are anhydritic or quartzose dolomudstones to mud-rich dolopackstones and dolomitic sandstones. Textures, fabrics and grain types indicate that these intervals formed as either: (1) tidal flat (peritidal) deposits or (2) exposure (karst) overprinting of a variety of depositional facies. Karst features include collapse breccias, sinkholes, caves and vertical fractures plugged with quartz sand or anhydrite cement.

The “rock based”, updated reservoir model for Vacuum field includes: 1) recognition of localized tight tidal flat cycles in separate flow units in the youngest San Andres, 2) identification of by-passed pay in shelf margin, porous, strike-parallel dolopackstones, and 3) recognition of the presence of tight karst intervals in deeper flow units that compartmentalize the more continuous San Andres pay interval.

Abstract

The Barnett Shale gas and oil play of North Central Texas currently has over 1500+ wells completed, producing gas and in some cases condensate from the Barnett shale. There are also a limited number of pumping oil wells.

Because of the complexities of this reservoir/source rock (porosity less than 10 pu, perm less than a micro-darcie, changing hydrocarbon type, open and closed fractures to name a few), conventional log analysis, completion, and stimulation cannot be used. In late 1999, a reservoir model was developed to evaluate the Barnett Shale using resistivity, litho-density, neutron, Sonic, and electrical images. In 2003 the model was refined with the addition of dipole sonic and capture spectral measurements. Phase Two model has been enhanced to characterize the reservoir rock in terms of mineralogy, total organic carbon, hydrocarbon type, porosity, perm, natural fractures, rock stress, and other rock properties. With this information, a well’s potential can be forecast and a better completion design can be made.

This process has been used on 400+ wells. It has helped in determining offset locations, perforation placement, number of stimulation stages, gas deliverability, direction and placement of a horizontal lateral, and the potential of the overlaying beds in terms of water production and barrier strength. This presentation will highlight some of the results. Also included in this presentation will be how the Ft. Worth Basin compares to the West Texas area and how this model can be refined for this area..

ABSTRACT

Examination of a current production map of the Permian basin reveals trends of production and fields and their ages, but does not reveal whether those trends and fields are high stand or low stand. Examination of paleontological reports available reveal more refined ages of field, but does not address whether those fields and wells are high stand or low stand. Use of cross sections, detailed paleontological zonation using fusulinids and awareness of sequence stratigraphy and the existence of fields of the same age in high stand systems tracts and low stand systems tracts reveals trends to exploit for exploration. Hulldale and Neva West Fields in Schliecher County are only two examples of these types of fields.

Abstract

Four wells in the Luck Pot (Fusselman) Field in west central Borden County, Texas have been cored in the Fusselman (Upper Ordovician(?) or Lower Silurian), Sylvan Shale (Upper Ordovician) and Montoya (Upper Ordovician) Formations. The Luck Pot Field is one of a number of stratigraphic traps that produce along the eroded edge of the Fusselman in the eastern Midland Basin.

The Montoya Formation is composed of shallow subtidal, bioturbated dolowack-estones and, in one well, of skeletal rich dolopackstones with leach moldic porosity. Chert nodules with ¼”(+/-) thick tripolitic weathering rinds are also present. These chert nodules have previously been described in the Dollarhide Field located 90 miles to the west in Andrews County, Texas, where it has been interpreted they have been eroded from pre-existing sections, carried across the carbonate mud flats and deposited in the intertidal environment. At Luck Pot the chert nodules were possibly deposited in the bioturbated, peloidal, skeletal, subtidal dolowacke stones to dolopackstones during storm events. Also present are higher energy skeletal dolopackstones which are devoid of the chert nodules. The fact that these nodules are found 90 miles apart indicates that this phenomena is not restricted to the Dollarhide area. The source of the nodules has not been determined. The karst overprint on the Montoya includes vertical to subvertical breccia pipes. Some of the chert nodules were broken across the rinds during karstification supporting the model that the nodules were weathered prior to deposition in the interval.

The Montoya – Sylvan contact is unconformable. In addition to the vertical karst in the upper part of the Montoya, there is a lag deposit on the unconformity which is composed of rounded pebbles, some which are pyrite replaced.

The Sylvan is a thick bedded green shale with blocky to platy partings. The upper portion of the Sylvan is thinner bedded with increasing carbonate content, some bioturbation, and lacking the platy or blocky partings seen in the lower Sylvan.

The contact between the Sylvan and the Fusselman can best be described as transitional. There is no evidence of weathering of the Sylvan, nor a lag deposit or soil profile. The base of the Fusselman is designated as the point where the content of shale drops rapidly. The contact between the Sylvan and Fusselman lacks evidence of a significant hiatus, supporting previous biostratigraphic work which placing the Lower Fusselman in the Upper Ordovician.

The Lower Fusselman is composed of a series of shallowing upward wackestone to packstone cycles with leach moldic porosity in the higher energy skeletal packstones and interparticle porosity in the finer grained peloid wackestone. The top of the Fusselman is not seen in any of the cores.

Abstract

The technological advances made within the last decade have allowed the Barnett Shale to grow from a crazy prospect to being one of the largest onshore natural gas plays within the continental U.S. With an estimated 26.2 TCF gas in place, the Barnett has begun to attract worldwide attention (USGS, 2004). A Barnett well in the heart of the Newark East field has an average depth of 7500’, an Estimated Ultimate Recovery (EUR) of 1.25 BCF, the possibility of multiple fracture stimulations (refracs) and a cost of roughly only $600,000 per vertical well. But don’t get too excited yet...there are many hurdles we must understand to get good Barnett production.

We must know and try to understand several items of importance:

• The maturation pattern of the Barnett in North Texas

• The thickness of the Barnett across the prospective area

• Regional faulting and underlying Ellenberger karsting

• Fracture stimulation (frac) techniques designed to meet the needs of a given area

• A drilling and completion strategy so as not to inundate the Barnett with frac water

Each of these factors has a significant effect on ultimate reserves and must be appreciated with respect to each other.

Abstract

An integrated study of seismic data, cores, and wireline logs from the Fullerton Clear Fork field, Central Basin Platform, West Texas, suggests that deep-seated faults influenced reservoir architecture, facies patterns, diagenesis, and ultimately porosity distribution in this Leonardian reservoir. These faults, mapped from recent 3-D seismic and older 2-D lines, provided a mechanism, in addition to eustasy, for changes in accommodation and circulation, as well as postdepositional sediment transport.

Whereas most major faults and associated erosion occur below the middle Wolfcampian unconformity—a widely recognizable downlap surface in the Permian Basin—a number of faults show continued movement into the basal Leonardian composite sequence (L1: Abo and Wichita) and in some cases Leonardian composite sequence 2 (L2: Wichita and lower Clear Fork). L1 (Abo) clinoforms initiate close to fault boundaries and follow conduits coincident with deeper downthrown normal fault blocks toward the basin. Stratigraphic thinning of the lower Clear Fork is apparent on the high side of older fault blocks, suggesting continued or reactivated motion of older faults during L2 deposition. Slump and downslope transport features were observed in core located very close to the boundary of a downthrown fault block, suggesting that reactivation of this fault may have been the cause of sediment transport. Porosity trends in the reservoir share common boundaries with some of these structural elements, suggesting fault movement may also have exerted small but significant controls on paleotopography during deposition and postdepositional diagenesis of rocks as young as the Clear Fork.

These observations challenge previous assumptions of tectonic quiescence following the middle Wolfcampian unconformity and instead suggest continued, albeit diminished, tectonic activity at least into the Leonardian.

Abstract

Limited seismic data quality and complex tectonics make for less than ideal interpretation conditions. However, modern geometric attributes including coherence, coherent energy gradients, and curvature have shown to be effective in showing the lateral extents of subtle and small-scale geologic features not usually visible in conventional seismic sections.

These geometric attributes are better suited than older generation seismic attributes as they work on the full data volume and eliminate the need for pre-picked horizons for them to be implemented. We have applied these attributes to improve reservoir characterization of the Vacuum Field area, where seismic data quality is a significant factor in interpretation.

Workflows using geometric attributes to aid in the visualization and mapping of structure and stratigraphy are well established. However, little has been done to tie these newer attributes directly to reservoir properties. We therefore apply two well-established workflows used in estimating porosity from more conventional seismic attributes such as reflection envelope and frequency. In the first workflow, we determine which attributes are independent and classify the geometric attributes without well control (unsupervised learning) to obtain an enhanced image of the reservoir. In a subtle variation of this workflow called supervised learning, we find classes that correspond to lithologies seen in the well control. In the second workflow, we correlate these new attributes to well logs and production data to obtain a transform from the spatially well-sampled attribute data to predict the log properties throughout the reservoir. In both workflows, we compare the results of these predictions to those obtained by conventional attributes alone, and validate the results through well control that was not used in the training process.

Abstract

One of the primary structural controls for oil and gas accumulations in the Permian Basin are strike-slip, or wrench faults. Wrench faulting in West Texas began at least as early as Lower Permian (Hills, 1970, p. 1814). Wrench faulting is still active today in West Texas.

In West Texas there are four basic directions of wrench faults. The four fault directions also include relative movement direction, and average degrees measured clockwise from true North. They are listed in order of movement as follows: 1.) conjugate Riedel (R¢), right-lateral at 54°; 2.) Riedel (R), left-lateral at 90°; 3.) primary shear (P), left-lateral at 320°, and 4.) fold fault (F), right-lateral at 355°. The primary shear is a combination of R and R’. Primary shear faults are usually found as connected en echelon faults. Although these four basic fault directions are mostly straight lineaments, some are curvilinear. Many of the curvilinear faults are translatory faults, or faults around large rotated blocks. These variables usually change the direction of the originally straight lineaments.

The primary shear fault is left-lateral with the south side of the fault moving southeast. The conjugate Riedel fault is right-lateral with the south side of this fault moving southwest. Thus, a collision occurs south of the perpendicular intersection of these two faults resulting in the development of a compressional structure at that location. Area field examples include the Jaybird Field in Garza County, and the Anton Irish Field in Hale and Lubbock counties, Texas. A large example of a fold fault is the faulting on the west side of the Central Basin Platform.

Curvilinear features that are almost circular are considered to be probable flower structures, or pop-up blocks. These structures have been found between two primary shears or between two conjugate Riedel shears. Small examples of these structures are found in outcrops between Sanderson and Dryden, Texas. A larger example of a probable flower structure is the entire Horseshoe Atoll in the northern Midland Basin.

Small botryoidal features have a distinctive “bunch of grapes” appearance on high altitude photos. These features are found mainly over hydrocarbon accumulations in the subsurface. Along some primary shear faults, scissor faults may be found by detection of botryoidal features on the structure. Botryoidal features are seen on photos of Brown-B assert and JM Gas Fields. These fields are good examples of fields occurring on opposite sides of a scissor fault.

To prospect with wrench faults in West Texas, straight lineaments should be marked first on a clear acetate overlay covering the area of interest of a high altitude photograph. Next, curvilinear and other features should be marked on the overlay with a grease pencil. It is assumed that water and hydrocarbon leakage through fractures have caused changes in the surface soil chemistry and vegetation. These changes are readily visible on high altitude photos, and are the key factor in delineating all features, including the four basic directions of wrench faulting. High altitude photos may be ordered from the United States Geological Service, EROS Data Center, Sioux Falls, South Dakota, U. S. A., 57198. A scale of 1”= 1250’ (Code 66 – 36 inch in color) should be satisfactory for most interpretations.

Abstract

Guadalupian composite sequences (CS) and high frequency sequences (HFS) have been defined from outcrops in the Guadalupe and Delaware mountains by Kerans and Tinker (1999) and in the subsurface of the central Delaware Basin in Texas by Gardner (1992, 1997) and Loftin (1996). All of the sequences in the basin are considered deep water deposits and most reflect sea level changes. In this study of the Bell Canyon and upper Cherry Canyon Formations, we compare the published CS and HFS interpretations in west Texas to central basin and basin margin sections in adjacent New Mexico. Our analysis is based mostly on wireline log character which generally permits identification of depositional cycles of low stand siliciclastic units (locally with fine-grained sandstone oil reservoirs) overlain by highstand basinal carbonates or equivalent condensed sections that may form seals. In addition to gamma-ray and porosity logs, the SP, resistivity and caliper logs are useful in sequence analysis of these upper Wordian Stage and Capitanian Stage formations.

Our regional subsurface study concerns the basinal facies of outcrop-defined composite sequences (CS 12 - CS 14) and HFS (G 15 - G 28) of Kerans and Tinker (1999). At least four of these HFS generally can be recognized easily by wireline log character throughout the basin. Each includes lowstand to highstand phases and is informally named after well-known outcropping limestone members. Their equivalent shelf formations and other data are shown in parentheses. From top to bottom these easily correlated units are:

In the Bell Canyon Formation

Reef Trail HFS (= upper Tansill; G-28; at the basin margin may include a thick but rapidly thinning upper carbonate tongue)

Lamar HFS (= lower Tansill; G-27; includes the lowstand “trap” and “Ramsey sand” units)

Hegler HFS (= Lower Seven Rivers HFS; G-17; consists of the “Two finger Limestone” unit and uppermost Cherry Canyon Formation sand)

In the upper Cherry Canyon Formation

Manzanita HFS (= Shattuck Member, Queen Formation; G-15 and G-16; consists of five siliciclastic to carbonate cycles; Cycle Mz-3 contains two basin wide bentonite markers, and Cycle Mz-1 includes a thick lowstand siliciclastic unit equivalent to the basal Shattuck Member by-pass surface)

We have somewhat less confidence in precisely identifying the pre-Lamar Bell Canyon HFSs and cycles. In the more northern and eastern parts of the Delaware Basin we recognize more well developed cycles than in the western part of the basin in equivalent depositional settings. This may be due to differential subsidence and an increase in eolian derived siliciclastic supply from the east and north as suggested by trends of oil productive channel fill sandstone reservoirs. If most of these cycles are the result of sea level change, the cycles must be more amalgamated in the west, the location of most published sequence studies. Nevertheless, based on a regional grid of cross sections and using the Lamar and Hegler HFS as boundaries, we can generally identify the following HFS and cycles in New Mexico:

McKittrick Canyon HFS (= upper Yates: G-26; includes the “Ford” unit and “Olds sand”)

McCombs HFS (= middle Yates; may include 2 or more cycles)

Rader HFS (= lower Yates & upper Seven Rivers (?): may include 5 or more cycles including local thick basin margin debris flows which may not reflect sea level change)

Pinery HFS (= middle and upper (?) Seven Rivers; may include 3 or more cycles)

Oil production generally is found in very fine-grained, lowstand sandstone reservoirs commonly deposited as channel fills in some of the HFS. Most known oil reservoirs in the Bell Canyon and upper Cherry Canyon formations are in the Lamar, Hegler (= Lower Seven Rivers) and Manzanita HFS.

Extended Abstract

This presentation provides a conceptual regional geologic framework for unconventional gas exploration. Unconventional gas accumulations form when methane is transferred to an unconventional storage medium, such as organic matter (OM) sorption or tight gas-saturated sandstones. The transfer results from interaction of gaseous methane, dissolved methane, and sorbed methane during gas migration, water movement, and basin burial and exhumation. Many of these processes can be predicted or mapped on a regional scale. This provides a basic strategy for basin or regional evaluation of unconventional gas resources.

Methane’s high solubility in water causes significant methane storage in pore water along petroleum migration pathways, because undersaturated water can strip methane from migrating gas and oil. Methane solubility increases with depth and thermal gradient. The dissolved methane resource is large but dispersed (uneconomic). However, basin uplift or cooling will release methane from water, so the main effect of methane in water is methane storage during burial. A km of uplift will release approximately one STP volume of gas per volume of pore water. The newly exsolved gas can coalescence and migrate to late-formed conventional or unconventional accumulations.

Methane is readily sorbed onto organic matter (OM). The most familiar result is coal-bed methane (CBM), but methane also sorbs on dispersed organic matter. Sorption increases with pressure and decreases with temperature. OM sorption also increases with rank. In general, sorption decreases with depth where OM rank is constant (except for shallow in the basin). Increasing rank with burial increases sorption with depth. During uplift, the methane exsolved from water can be sorbed by OM. This process keeps OM close to saturation during basin exhumation.

With these concepts in mind, controls on potential occurrence of CBM, gas shale, and tight gas can now be evaluated. CBM requires shallow burial depth for economic production. Methane content is more likely to approach maximum theoretical capacity where the basin has recently been exhumed or where resurgent water with high methane saturation flows through the coal. In contrast, coal in areas with recent subsidence, static burial, or down-flowing, undersaturated water is likely to have gas concentrations significantly below saturation. Reservoir pressure must drop substantially before gas production initiates, and total methane resource will be lower.

There are two different types of shale-gas accumulations. The most common type is essentially a CBM diluted by a high shale content where almost all methane is sorbed. Reservoir depth must be shallow for depressurization and economic production. Matrix permeability is very low, so economic production rates are controlled by fractures. Like CBM, this type of shale gas is most likely to occur in areas of uplift, and it does not require structural closure for trapping. Methane may be of late thermogenic, early thermogenic, or microbial origin. The second gas-shale type is intermediate to tight-gas accumulations and is represented by the Barnett shale gas. This gas shale has matrix porosity with gas saturation, so methane storage is combined sorption and gas-phase storage. Where depth is great, most gas is stored as a sorbed phase, but most gas is produced from porosity storage. Matrix permeability is still low, but it is sufficient to contribute to production. This type of gas shale accumulation is also favored by uplift, because gas saturation rises as methane expands and exsolves from water. Uplift does not have to be recent. High reservoir thermal maturity decreases likelihood of high viscosity petroleum liquids, so it favors production from tight reservoirs. Unlike pure sorbed resource, structural closure may increase gas saturation, so economic accumulation is favored by structural closure.

The major control on tight-gas reservoirs in rocks with low organic carbon is reservoir quality, not charge. “Basin-center” type tight gases are probably productive either where gas charge predates diagenetic permeability reduction or where the reservoir has been exhumed. Gas expands during exhumation, so reservoir water saturation decreases and effective gas permeability increases. Large gas volumes in tight, Paleozoic, basin-center type accumulations probably require a thermogenic gas origin. Structural or structural-diagenetic trapping is probably required, and the trap must predate exhumation.

Overall, the key parameters for regional geological assessment of unconventional gas potential is burial history (exhumation favors most accumulations), thermal maturity of potential reservoirs and source rocks (high maturity is generally better), water flow (for sorbed unconventional resources) and time of charge relative to trap formation (for tight gas sands).

Abstract

Kinder Morgan and Z-seis combined to investigate the movements of CO₂ through the producing formation in the SACROC Unit of the Kelly-Snyder field located in Scurry County, Texas. The methodology was to utilize crosswell seismic data to reflection image the producing zones structure, and to time laps monitor tomography for CO₂ incursion through the reservoir. The overlying assumption being that as CO₂ replaces reservoir fluids, the formation velocities will decrease.

Previous 4-D crosswell monitoring studies have shown that velocity changes as low as 2 to 3% are readily observable. In addition, vertical resolution of a few feet and horizontal resolution equivalent to a small percentage of the well spacing was expected.

4-D monitoring utilizes crosswell seismic data collected before and during the CO₂ injection cycle. The data collected prior to CO₂ injection provides a baseline velocity model and a high resolution reflection image of the reservoir. Difference tomography is used to update the baseline velocity model utilizing data collected after CO₂ has been injected into the reservoir. The updated model is subtracted from the baseline model, exposing intervals where the velocity has changed. These results may be displayed in velocity differences or percentage changes.

Incorporating the 4-D tomographic results with well data from the injector wells and the production wells yields an internal picture of the reservoir and the movement of CO₂ through it.

Extended Abstract

A detailed understanding of permeability would greatly improve enhanced recovery strategies at many Permian Basin fields. However, unlike porosity, permeability cannot be measured by wireline tools and therefore is not widely available. As such, porosity is often used as a substitute for permeability, but this substitution can be very misleading because the relationship between porosity and permeability in carbonate reservoirs is typically complex. In order to accurately calculate permeability at Fullerton field, we used a rock-fabric approach that first determines, then applies, rock-fabric-specific porosity-permeability transforms throughout the reservoir.

The rock-fabric approach (described in Lucia, 1995) is based first on identifying rock fabrics and then grouping them into petrophysically similar classes. Petrophysical class 1 rock fabrics include grainstones and large crystalline dolostones; class 2 fabrics include grain-dominated packstones and medium crystalline dolostones; and class 3 fabrics include mud-dominated packstones, wackestones, and mudstones and fine crystalline dolostones. Previous studies have shown that each petrophysical class has a different porosity-permeability transform. Ideally, rock fabrics are described and petrophysical classes assigned using paired thin sections and high-quality core-plug analysis data collected on a foot-by-foot basis. However, these data are not always available. Herein, we describe how new petrophysical data from representative cores can be used to leverage preexisting data and model rock fabrics throughout a field.

To create a continuous rock-fabric profile of the Fullerton reservoir (Leonardian Lower Clear Fork and Wichita), we cut nearly 500 new plugs from two cores. Plugs were cut from each foot of selected core and a set of matching high-quality core analyses and thin sections obtained. Thin sections were described using the rock-fabric approach (Lucia, 1995) and assigned a petrophysical class that was then compared with the petrophysical class indicated from the porosity-permeability cross-plot (detailed results described in Jones et al., 2003).

Samples displaying disparate petrophysical class values were reexamined to determine the causes of the inconsistency and their stratigraphic position noted. Once rock-fabric changes were established in this continuous vertical profile, we related their distribution to cycles, systems tracts, and high-frequency and composite sequences. We observed that most major rock-fabric changes occur at the sequence or systems tract boundaries. However, some rock-fabric changes are diagenetic; in these cases, rock-fabric boundaries coincided with boundaries between limestone and dolostone.

In a shallow-water carbonate platform reservoir, such as that at Fullerton Clear Fork field, associations between rock fabrics and sequence stratigraphic elements can be expected to be relatively consistent throughout the reservoir. To test this assumption, we examined all other available thin sections and core analyses from the field. Once we were satisfied that our predictions of rock-fabric relationships were correct, we created porosity-permeability cross-plots from existing whole core analyses, making separate plots for each rock-fabric/sequence stratigraphic interval observed in the continuous rock-fabric profile. Because our continuous vertical rock-fabric profile demonstrated that several rock-fabric changes were coincident with mineralogy changes, we employed wireline logs (photoelectric factor, neutron and density) to map dolostone vs. limestone.

By integrating new, high-quality petrophysical data and a detailed sequence stratigraphic framework in a setting having relatively limited internal variation, we were able to maximize the utility of preexisting petrophysical data and map changes in rock fabrics on a field-wide basis. Our method of calculating permeability using rock-fabric-specific porosity-permeability transforms honors the widely varying pore types and degrees of pore connectivity present in Permian Basin carbonate reservoirs and thereby results in a more realistic 3-D estimation of matrix permeability than many single-transform techniques.

Abstract

Vitrinite reflectance (R_o) data from 70 well profiles were used to construct maturation trends for organic matter (OM) in sedimentary rocks within the Midland Basin, Delaware Basin, across the Central Basin Platform, and the northwestern shelf area of the Permian Basin. These maps were constructed representing 0.6, 1.3, and 2.0 percent R_o, level isoreflectance surfaces and correspond, generally, to the onset of oil generation, the onset of oil cracking, and the oil preservation limit.

The four physiographic provinces differ in overall depth, heating and tectonism, and the plots illustrate these differences. In the western Delaware Basin, higher maturation is observed at shallower depths resulting from eastward basin tilting starting in the Mississippian, which exposed older, thermally mature rocks. Maturity was further enhanced in this area by the emplacement of early and mid-Tertiary intrusives. Volcanic activity also appears to be a controlling factor for maturation of the southern part of the otherwise tectonically stable northwestern shelf area.

The isoreflectance surfaces are deepest in the eastern Delaware Basin and southern Midland Basin. This appears to be a function of tectonic activity related to the Marathon-Ouachita orogeny whose affects were widespread across the Permian Basin. The Central Basin Platform has been a positive feature since the mid-to-late Paleozoic where sedimentation has taken place along its flanks. This non-subsidence, along with the lack of supplemental heating (volcanism), implies lower maturation levels, and the contour lines across the platform indicate this.

Based on iso-reflectance surfaces, general trends in thermal maturity across the Permian Basin are mapped and potential petroleum kitchens identified.

Extended Abstract

Fullerton field is the largest and most productive Leonardian reservoir in the Permian Basin. With an OOIP of more than 1.2 billion barrels and a cumulative production of nearly 310 million barrels, this shallow-water platform carbonate reservoir is truly a giant. Like most Clear Fork reservoirs, however, recovery efficiency is low relative to other platform carbonate reservoirs. A critical issue to understanding the distribution of original and remaining oil resources, and thus unlocking the key to improving the recovery of the remaining oil, is a detailed understanding of the reservoir architecture. Here we report recent investigations into the facies, sequence stratigraphy, and diagenetic controls on reservoir development and heterogeneity in Fullerton Clear Fork field.

The Clear Fork reservoir at Fullerton, which is productive from parts of the Lower Clear Fork, Wichita, and Abo Formations, also contains one of the most extensive reservoir data sets in the Permian Basin. Our interpretations of the stratigraphy, facies, and diagenesis of these units comes from the description of more than 14,000 feet of core and 1,700 thin sections, correlation of 45-70 stratigraphic markers in nearly 900 wells, interpretation of more than 26 square miles of 3D seismic and 222 miles of 2D seismic, and integration of all data with analogous outcrop models.

Important conclusions of this study include the following:

• The Lower Clear Fork (which represents the upper part of Leonardian sequence L2) consists of a succession of three high frequency sequences (HFS), each of which records sea level rise (transgression) and fall (regression). Reservoir development is largely limited to subtidal facies (late transgression and early highstand).

• Highest porosity and permeability in the Lower Clear Fork is associated with incompletely dolomitized grain-rich packstones and grainstones.

• Lower Clear Fork facies are discontinuous at the cycle scale but facies tracts are widely correlative at the HFS scale.

• The Wichita, a thick (250 to 350 ft), succession of aggradational restricted tidal flat facies, includes both highstand system tract equivalents of the Abo (Leonardian sequence L1) and transgressive systems tract equivalents of the Lower Clear Fork (Leonardian sequence L2).

• Although the Wichita reservoir architecture is generally time parallel and flat, it is more a function of diagenesis than of depositional processes.

• Wichita rocks locally contain high porosity but usually contain relatively low permeability and display poor small scale continuity.

• Limestone intervals in the dominantly dolomitic Wichita display extremely low porosity and permeability and act as local fluid flow baffles.

• The Wichita and Abo are time-equivalent facies of one other. The facies contact is expressed on seismic by a prominent apparent top lap surface that is not a time line.

• The Abo consists largely of porous outer ramp fusulinid/crinoid facies whose clinoformal architecture is clearly expressed on seismic. Lateral facies continuity is poor.

• Karst features (including inclined beds and monomict and polymict cave fill breccia) are common in the Wichita and at the Abo Wichita contact. These features are primarily the result of karsting during platform emergence at the end of L1 deposition.

• Gamma ray logs are useful for general correlations only. Like other Leonardian reservoirs, high gamma ray is usually an indication of the presence of clays and silt in tidal flat facies; low gamma ray response indicates subtidal facies.

• A high resolution cycle stratigraphic framework can be defined in Lower Clear Fork rocks using combined core, log, and outcrop relationships. High resolution correlations are not possible in the Wichita and Abo.

• 3D seismic provides excellent resolution of both the reservoir architecture and the distribution of reservoir porosity at the HFS scale.

• Combined seismic, core, and log data demonstrate that depositional and diagenetic processes responsible for reservoir development were partly controlled by tectonic activity.

These findings provide important insights not only for more effective further development of Fullerton field but for Clear Fork reservoirs throughout the Permian Basin.