Technical Sessions

The Mississippian Barnett Shale of the Fort Worth Basin is an organic-rich shale that is the reservoir trap and seal for a very large unconventional gas accumulation. The play has rapidly spread over a multi-county area.

The Barnett Shale is a spent oil-prone source rock. Porosity and permeability is developed upon thermal transformation from liquid to gas with resulting maturation-induced micro fractures. Gas is stored in these micro fractures, as well as being adsorbed in the solid organic matter (kerogen). The exploration fairway is defined by Barnett Shale isopachs, subcrop maps, source rock richness data (Total Organic Carbon), thermal maturity defined by vitrinite reflectance and the presence of reservoir quality Barnett Shale.

The Barnett Shale is one of the most active drilling targets of the past decade. Newark East Field is now the second largest gas-producing field in Texas. Drilling depths are less than 8,000 ft, and per well reserves in the expanding Newark East Field are 1-3 BCF. Gas-in-place is 145 BCF per square mile. The Barnett Play is estimated to have 10 TCF recoverable reserves (USGS, 1998).

Low proppant hydraulic fracturing technology ("water-fracs") has greatly improved play economics. This new technology has reduced total well cost by more than 20 percent and has resulted in much-improved rate and reserve profiles. Barnett Shale wells are typically re-fraced after several years resulting in producing rates superior to initial production rates.

In terms of monthly production, the Newark East (Barnett Shale) field recently became the largest gas field in Texas. Production has grown from 80 MMCF/D in January 2000 to over 560 MMCF/D at present because of accelerated new-well drilling and old-well reworks/refracs. There are over 2.5 TCF of booked proven gas reserves in the field at present. Newark East field is located in the northern portion of the Fort Worth Basin, just north of the city of Fort Worth. The Mississippian Barnett rests on an extensive angular unconformity. The Barnett must be stimulated to achieve economic flow rates. Currently, wells are hydraulically fractured, but good frac barriers must be present directly above and below the Barnett for this stimulation technique to be successful. Hence, the stratigraphy above and below the Barnett is important to economic production. The thermal history of the basin is an important reason for the success of the Barnett. The thermal history of the Fort Worth basin is directly related to the emplacement of the Ouachita system. Sections of the Barnett bordering the Ouachita front (regardless of depth) have the highest thermal maturity and, hence, the lowest BTU content of produced gas. In the late 1990s, work by Mitchell Energy had demonstrated the viability of water fracs in the Barnett play; this development has contributed to a huge acceleration in Barnett leasing and drilling activity during the past three years. Also in the late 1990s, Mitchell determined that the previous gas-in-place values for the Barnett were low by over a factor of three. There is approximately 150 BCF/mi2 of in-place gas in Newark East field. The realization that the primary completion was only recovering 7% of the gas in place per well spurred the current (and very successful) rework/refrac program underway in the field.

The history of the evolving geologic and engineering concepts that guided development of the Barnett is a tribute to rare perseverance in the oil patch. And the success of the Barnett play may provide a model for prospecting for other large shale-reservoirs.

Gas contained within unconventional shale gas reservoirs is stored by sorption within micro and mesoporosity of the rock matrix and by compression within the macroporosity and natural fracture porosity of the reservoir. Mitchell Energy cored the Kathy Keel #3 Barnett Shale well (Denton Co. Texas) with conventional and pressure coring equipment in the upper and lower Barnett to obtain core samples and data to obtain data required to estimate the gas-in-place volume stored by each mechanism. An extensive suite of data was measured that included desorption of samples to determine the sorbed gas content and gas composition as well as methane and ethane sorption isotherm data to estimate the sorbed gas storage capacity.These data were combined with other shale gas core analyses including TOC content, routine porosity, grain and bulk density, water saturation, capillary pressure, x-ray diffraction, and cation exchange capacity data to develop a log analysis model that combined log and core analysis data.

The estimates of the gas-in-place volume were significantly greater than past data measured and published in 1992 by Gas Research Institute (GRI) had indicated. The volume of gas stored by sorption within the pressure core interval was 120 scf/ton at an average TOC content of 5.2% compared to GRI's estimate of roughly 42 scf/ton. The sorbed gas volume accounted for 61% of the total gas-in-place volume that included both sorbed and free gas. Free gas volume in-place was determined by log analyses methods that were calibrated to core analyses to obtain in-situ estimates of porosity and water saturation.

While the gas-in-place volume is large, recovery of the gas volume is hindered by relatively low absolute permeability of the reservoirs. Recovery of the sorbed gas-in-place requires that operating pressures be kept low as possible to allow the gas to be released from the sorbed state. Recovery factor depends upon the decline in average reservoir pressure. Calculation methods for gas recovery factor will be discussed to illustrate that recovery factor may range from 10 to 25% of the total gas-in-place volume with conventional technology.

The Barnett Shale in North Texas is one of many tight shale plays across the country, however, over the last two years the Newark East (Barnett Shale) field has been the most active field in the United States. With an average of 35 drilling rigs running in the Fort Worth Basin, over 2000 wells have been drilled in Wise, Denton, and Tarrant counties for the ultra tight gas. The Barnett Shale is present in most of North Texas and has been tested in more than 12 counties by more than 50 operators.

How has the Barnett Shale play developed from a 1 rig uneconomic program to a stable, growing, gas producing field? Why has the light sand stimulation technology developed by Mitchell Energy been so successful here? Using microseismic and tiltmeter technology, an insight to the complexity and geometry of the created fracture is developed. Potentially some of the reasons why the LSFs are so successful are addressed as well.

The Barnett Shale in the Fort Worth Basin of Texas is an organic-rich black shale capable of producing large amounts of natural gas and natural gas liquids. Traditional log analysis methods have not yielded acceptable results when attempting to determine standard petrophysical properties. Therefore, log analysis alone is an impractical method of predicting production in the Barnett Shale. Production in the Barnett Shale is affected by several factors, only some of which may be measured or calculated using log data, making gas content a poor predictor of well performance. However, a neural network technique has been developed to successfully estimate reservoir potential that relies on log derived qualitative and quantitative parameters.

Log analysis in the complex lithology of the Barnett Shale is very difficult. The existence of several exotic minerals in the matrix along with significant amounts of organic material makes a algorithm-based solution virtually impossible. Using extensive core data, a neural network solution was developed to calibrate the logs to the needed petrophysical properties, and thus enable the foot-by-foot calculation of gas content of the Barnett Shale. Since any evaluation technique requires proper verification, examples will be shown to demonstrate the effectiveness of the calibration.

The logs required to perform the analysis are readily available on most wells in the Fort Worth Basin, making the solution a practical exploration/exploitation tool. Outputs from the analysis include porosity, total organic content, water saturation, lithology, and gas content, both in the sorbed and free states.

The Newark East, Barnett Shale Field is one of the largest producing gas fields in Texas. The initial development of the field was centered in the southeast quarter of Wise County, and, over the past 20 years the field has expanded to the north, west, to the east into Denton County and the the South in Tarrant County. With the development of the field came the increased knowledge of the nature of the reservoir, the frac gradients and the porosity zones, all of which was important in the economic development of the Barnett Shale play.

In the early development it was recognized that the Upper Barnett (+100') had a higher frac gradient (.70+) than the Lower Barnett (.50 to .60+) (+300'). As the field developed and expanded in aerial extent, it became apparent that in the north part of the field the Lower Barnett (+600') could be subdivided into five (5) ("A" thru "E") correlatable porosity units with limestones and non-bituminous calcareous shale separating the productive porosity units.

With further investigation and evaluation of the Lower Barnett it became apparent that the upper "A" and "B" porosity units could have a different frac gradient than the lower "C", "D" and "E" units in certain areas.

Even though the majority of the water frac treatments consist of two phases, one for Lower Barnett and another for Upper Barnett, certain areas of the field will require multi-stage fracs to adequately recover the true reserve potential of the Barnett Shale.

Production logs and radioactive tracer surveys have been used to evaluate the effectiveness of frac jobs covering 300' to 600' intervals, where each zone could have variances in frac gradient, fractures and/or porosities.

As the field continues to expand beyond the Viola/Ellenberger subcrop, additional new data will possibly dictate a change in frac procedure.

Organic-rich, Barnett Shale (Mississippian) is the primary source rock for oil and gas produced from Paleozoic reservoirs in the Bend Arch-Fort Worth Basin Province. Distribution and geochemical typing of hydrocarbons in this mature petroleum province indicates generation and expulsion from the Barnett at a depocenter coincident with a paleoaxis of the Fort Worth Basin. Barnett-sourced hydrocarbons migrated westward into reservoirs of the Bend Arch and Eastern shelf; however, some oil and gas was possibly sourced by a composite Woodford-Barnett petroleum system of the Midland Basin from the west.

Current U.S. Geological assessments of undiscovered oil and gas are performed on Total Petroleum Systems (TPS) that include mature source rock, known accumulations, and area(s) of undiscovered hydrocarbon potential. The TPS is subdivided into Assessment Units based on similar geologic conditions and accumulation type. Assessment of the Barnett-Paleozoic TPS focuses particularly on the continuous Barnett accumulation. Barnett shale gas will be assessed after mapping "sweet spots" and outlying areas of potential, and by defining distributions of drainage (cell) size and cell estimated ultimate recovery. An example of a Barnett "sweet spot" is the Greater Newark East area where thick, siliceous Barnett has reached the gas window, and overlain and underlain by impermeable limestones that serve as "frac" barriers. Assessment Units are also identified for mature conventional plays in Paleozoic carbonate and clastic reservoirs, such as the Chappel Limestone pinnacle reefs and Bend Group conglomerate, respectively. However, Barnett continuous gas is expected to add the greatest volume of undiscovered, technically recoverable resource.

The Bossier Sand Play in the 'mature' East Texas Basin has emerged as one of the premier basin-center gas plays in the onshore U.S. For almost 25 years, the Jurassic Bossier Sands were viewed as "bail out" zones in wells drilled for deeper targets in the Haynesville/Cotton Valley and Smackover Limestones. Prior to 1995, the average Bossier completion at 11,500 feet produced about 0.9 BCFG and was considered uneconomic as a primary objective. In 1996, following a failed Cotton Valley Limestone exploration program, Anadarko recognized the ingredients for significant gas reserves in the Bossier Sands. Favorable geologic conditions included a petroleum system with juxtaposed reservoir, source and seal over a broad, overpressured region. Economic hurdles included high drilling and completion costs for relatively low-rate gas production in "permeability-challenged" sandstones. Successive operational/cost improvements led to economically attractive results, even in a sub $2.00/mcf gas price environment. Average Bossier wells now take 55 days from spud to first sales with initial rates of 3-5 MMCFD and reserves of 3 BCFG. Exceptional wells produce up to 50 MMCFD with 10 BCFG reserves. As of August 2001, Anadarko's East Texas Bossier production was in excess of 300 MMCFD with proven reserves for the Dew/Mimms Creek Field of over 1.1 TCFG ("Giant Field" status). Ultimately, the Bossier Gas Play is expected to yield multi-TCF reserves from developing trends throughout East Texas. Anadarko's Bossier success can be tied to these key factors: 1) Recognition of the resource potential, 2) Improvements in drilling/completion costs and techniques, 3) Control of the play, and 4) Integration of midstream/marketing strategies. North American onshore basins have many more "sleeping giants" yet to be awakened by innovative explorers who recognize their potential!

Natural gas supply and demand, unlike that for crude oil, is controlled by domestic and sometimes, regional market forces. Currently, natural gas provides 25% of our total energy needs. United States produces one-fourth and consumes one-third of the world's daily supply. At current consumption levels, United States has a 9-year supply of proved reserves and almost a 60-year supply of potential resource. However, the supply and demand balance maintained by the market is such that a drop of less than three-week supply in the "system" can make the difference between markets being "flush" to markets being "short". Local and regional imbalances have led to huge swings in prices during the last couple of years.

Demand for "clean fuels" throughout the world is only going to increase the demand for natural gas. Increase in US demand because of economic expansion and environmental considerations would require a national effort to make capital, rigs, personnel and technology available to meet the needs. Although we are importing approximately 15% of our natural gas, shortages in domestic production cannot be easily met through increasing imports. Nevertheless, the domestic environment has not been the most favorable for increasing supply. Almost a 10-year supply in places such as Rocky Mountain Basins, Alaska and the Outer Continental Shelf is either "off limits" or has severe restrictions against development. In order to meet the nation's needs, a cooperative environment among industry, governmental agencies and the environmental community is required.

The Cretaceous Interior Seaway has been at the center of debates about the origin of elongate "shelf" sandstones encased in marine shales. Some of these basin-distal sandstones have been interpreted to be tidally-influenced incised-valley fill deposits. We suggest that many of these deposits are top-eroded lowstand deltas, as indicated by lobate to elongate geometries, upward coarsening facies successions, basinward dipping internal clinoform bedding, and radiating paleocurrents. Low abundance and diversity of ichnofacies and preponderance of non-marine derived microfossils indicate river-influence. Tidal sedimentary structures indicate tidal modulation during progradation.

Delta plain "topset" facies were eroded during transgression, placing marine mudstone on top of delta front sandstones. The capping erosion surfaces are the only stratal discontinuities that can be mapped regionally, versus an underlying erosional surface. A low accommodation setting left little room for sandstones to stack vertically, and successive episodes of delta progradation were offset along strike reflecting autocyclic controls. More tide- and river-influenced delta deposits formed within shoreline embayments defined by the topography of older wave-influenced delta lobes and subtle syndepositional deformation of the basin floor related to foreland tectonics.

Major discontinuities form by processes other than fluvial erosion and minor syndepositional deformation of the basin floor controls sediment deposition and preservation. Tidal facies may be found in lowstand deltas built onto undulating seascapes associated with tectonically produced embayments. Tidal facies are not limited to transgressive systems tracts and should not automatically be interpreted as being deposited within fluvially-incised valleys.

The Sin Nombre area sits astride the boundary between the Permian Basin to the south and the Tucumcari Basin to the north. It covers an area of approximately 7000 mi2 in DeBaca, northern Roosevelt, southern Curry, northern Chaves, northeastern Lincoln, and southwestern Guadalupe Counties, New Mexico. Approximately 100 BCF gas and 6 million bbls oil have been produced from 17 oil and gas pools in the southeast and south-central portions of Sin Nombre. Low-permeability sandstones of the Abo Formation (Permian) have yielded most of the gas but Pennsylvanian limestones and Silurian and Ordovician dolostones are also important gas reservoirs. Silurian dolostones and Pennsylvanian limestones have been the primary oil reservoirs.

Significant potential remains for additional, undiscovered and unproduced oil and gas resources. Marginal gas discoveries in the central part of the Sin Nombre area may have remained unproduced because of a paucity of pipelines along the northwestern fringe of the Permian Basin. Although drilling density is low, oil and gas shows encountered by unsuccessful exploratory wells indicate that large portions of the area have been at least partially charged by hydrocarbons. Hydrocarbons in the southern part of the Sin Nombre area would most likely have migrated north from source rocks in the Permian Basin. Hydrocarbons in the northern part of the Sin Nombre area would have migrated southward from source rocks in the Tucumcari Basin. Opportunities for traps included localized, basement-controlled structural highs throughout the stratigraphic section as well as northward pinchouts of lower Paleozoic reservoirs against east-west trending faults in the subsurface.

Since its discovery in 1937 and subsequent initiation of water flooding in 1973, the E. Cowden Grayburg Unit (ECGU) has been one of the most prolific producers of oil from Permian-age carbonates on the Central Basin Platform. To date over 34 million barrels have been produced from this 720-acre unit and remaining proved reserves are currently estimated at 7 million barrels of oil.

Our detailed stratigraphic and lithologic interpretation results from core description and a modern logging program that pays particular attention to the effect of lithology on porosity. The identification of siltstones and the presence of sulfates have affected our understanding of the efficiency of the existing waterflood in this unit. We believe that the multiple deposition cycles and flooding surfaces allow for the possibility of concentrating water injection in zones of higher remaining oil saturation. The combination of vertical producing wells and horizontal (water injection) laterals drilled from existing vertical wells provides a viable way to recover oil in an economically responsible way. Samples, logs, pressures, and rotary sidewall cores in our initial five well vertical infill program have thus far confirmed our interpretation, and are likely to be followed by an initial horizontal re-entry program as we attempt to apply this modern drilling technique successfully to the Grayburg.

RBI-Gearhart utilizes a stochastic modeling based software application for generating geologic interpretations, calculating rock strength properties to select optimum drill bit types. Interpretations from the application have significantly reduced drilling times and costs on multiple wells drilled in New Mexico. Data from offset wells were analyzed with stochastic modeling, based upon weighted least square error minimization, to derive the physical properties of the rocks. Since the logging suite from the offset wells did not include a Sonic log needed for computing the elastic properties and velocity ratios; the stochastic model was used to derive computationally the compressional and shear wave velocities. After calculating the dynamic elastic properties and deriving the compressive strength, engineering classification of the rocks was done to optimize the drill bit selection. Based on the interpretation and bit proposal, three wells were drilled by the operator using PDC bits for the first time in this geological environment of anhydrite, halite, sylvite, sand, clay, silt and limestone. The drilling time on the first well was reduced by 27% and with the new information gained, special drill bits were designed for the second and the third wells. The third well was completed with just two drill bits, compared with four earlier, to further cut the drilling time by 43.5%, a new record in the area. Even with significantly faster ROP, the caliper did not indicate any deterioration in the bore hole profile. The success of the project is attributed to the team effort realized between the operator and RBI-Gearhart.

Tansill shelf margin facies exposed in the quarry near the mouth of Dark Canyon are characterized by patchy dedolomitization, small vertical faults, collapse breccias associated with the faults, and abundant white coarse-crystalline blocky calcite cement filling breccia voids, fault planes, and intergranular porosity. Timing of these features is problematic. Collapse, dedolomitization, and breccia fabrics are commonly associated with the modern cycle of meteoric diagenesis and cave formation. Elsewhere in the Guadalupe Mountains (such as Walnut Canyon and Rocky Arroyo), Quaternary evaporite and meteoric dissolution is associated with a characteristic brown, transparent calcite cement, but this cement and the associated abundant open pore system is absent here.

Bedding-plane, vertical, and oblique stylolites are common near the mouth of Dark Canyon. Bedding-plane stylolites are crosscut by faults and rotated in breccia clasts, but dedolomite patches, breccia clasts, and cloudy, coarse-crystalline, white calcite are cross-cut by the tectonic and oblique stylolites. The oblique and tectonic stylolites show no systematic relationship to each other.

Vertical stylolites occur across trans-Pecos Texas. Orientation, intensity, and crosscutting relationships data indicate that these stylolites are cogenetic and date to Laramide (Late Cretaceous) deformation centered on the Chihuahua trough. The diagenetic features at Dark Canyon are therefore post-Permian and pre-Late Cretaceous in age.

The karst-related diagenetic features are probably related to the pre-Cretaceous unconformity, which lies about 70 m above the Dark Canyon quarry. Karsting and dissolution of shelf evaporites occurred along this surface long before the Quaternary cave-forming event.

The presence of Upper Wolfcamp/Lower Leonard age stratigraphic reefs, or bioherms, as a reservoir target in Pecos County has been proven to be a viable exploration objective.

This objective has been realized by utilizing the integration of geology and 3-D geophysics. A simple geologic model was created to understand the geophysical response of the play. Through this modeling, a focused exploration program for this reservoir target has resulted in eleven new field discoveries, three development wells, and five dry holes for an overall success rate of 74%. This reservoir objective has produced in excess of 400MBO and 5.7 MMCFG since the first discovery well was completed in January 1998.

The often poorly exposed Devonian section in southern New Mexico contains complex vertical and lateral ramp-to-basin facies changes that culminate in an elongate trough filled with up to 76 m of black shale. The trough trends east-west for over 350 km, and ranges from a width of ~30 km near Las Cruces to ~100 km near Deming. To the north, Middle-Late Devonian-aged ramp carbonates, sandstones, siltstones, and shales of the Oñate (Givetian), Sly Gap (Frasnian), and Contadero (Frasnian-Fammenian) formations outcrop in the San Andres and Sacramento mountains.

These formations grade southward into the Percha Formation black shale facies. Due to the largely barren nature of the shales, it is difficult to determine exact correlations. The Percha Formation is divided into two members, the black, fissile, barren Ready Pay and the more calcareous and fossiliferous Box. Fossils from the upper Box Member indicate a Fammenian age. South of the trough, the oldest Devonian units comprise the cherty shelf carbonate Canutillo Formation (Middle-Late Devonian) which is both overlain by and apparently a partial lateral facies equivalent to the Percha black shales.

Existing 1960's vintage isopach and facies maps are updated with more recent outcrop and subsurface data, and integrated with geochemical data and basin analysis models to better characterized the aerial extent, volume, richness, and maturity of the black shale facies. Public domain geochemical data show potential for the Devonian shales in south-central and southwestern NM to act as source rocks: TOC values locally reach 3.7% and thermal maturities are consistently in the mature to very mature range.

Three goals exist for this ongoing project: better constraints on formation correlations and facies relationships; improved characterization of Devonian shales for hydrocarbon source rock potential (richness and maturity trends, kerogen types, and expulsion timing); and description of the shales for shale gas reservoir potential.

We have constructed about 20 balanced structural cross-sections along the Frontal Ouachitas-Arkoma Basin transition zone between the Wilburton gas field and Wister lake, based on the wire line logs of 100's of wells, available seismic profiles, and surface geologic maps.

A well-developed triangle zone is present in the transition zone. It is flanked by the Choctaw fault to the south and the Carbon fault to the north. The footwall of the Choctaw fault contains a well-developed duplex structure. The Springer Detachment is the floor thrust and the Lower Atokan Detachment is roof thrust of the duplex structure. The roof thrust continues northward and displaces the Red Oak sandstone before reaching a shallower depth and forming the Carbon fault as a north dipping backthrust below the San Bois syncline. Northeast of the Wilburton field, the Carbon fault makes a lateral ramp to the east and becomes a blind backthrust. The triangle zone and the duplex structure are present throughout the transition zone from the Wilburton gas field to the Wister Lake area.

Southwest of Wilburton, the Main Choctaw fault forms a splay which is named here as the Northern Choctaw fault. The Lower Atokan Spiro sandstone is exposed on the hanging wall of the Main Choctaw. The fault wedge between the two faults contains no Spiro, suggesting that the Northern Choctaw is younger than the Main Choctaw. This indicates a break-forward thrusting between the two faults and implies that the imbricate thrusts on the hanging wall of the Main Choctaw were also developed by the same mechanism.

Depositional setting of the sandstone member of the Oil Creek Formation in the Arbuckle Mountains is problematic, because sedimentary structures are rarely preserved. The exception is the Barnes pit #1 quarry (south of Sulphur), where asphalt lithification enhances sedimentary structures in the upper part of the sandstone member and the lower part of the limestone member.

The sandstone section consists of two interstratified facies associations. One is thin-bedded with tabular crossbed sets, tabular ripples, and parallel lamina separated by dominantly planar bounding surfaces. This unit contains vertical burrows as well as escape structures and rare feeding traces. The other facies association becomes more dominant up section. It comprises festoons with southerly transport direction forming thicker, lenticular sandstone beds with concave-upward bounding surfaces. No biogenic structures were observed. The gradational contact with the limestone member is a structureless, medium-bedded calcareous sandstone with a few indistinct burrows. The lowest limestone is sandy, with probable algal laminations and sand-filled desiccation cracks. Higher limestone beds are bioturbated with variable sand and fossil content and some hardgrounds.

The sandstone is interpreted as a shallow neritic marine sand, where the sand was unstabilized, reducing the biodiversity and decreased biogenic structure preservation. The transition from sand to carbonate deposition appears to be related to stabilization of the shallow neritic sand flat, initially by algal mats. It is probable that the sand flat built to sea level (or sea level dropped), because the lowest carbonate intervals have characteristics of tidal flat deposits.

Fractures studied in four outcrops aid prediction of fracture characteristics in subsurface reservoirs. Outcrops are simple folds with shallow and deep maximum burial, complex secondary structures, and fault-bounded structural highs. The simple fold with shallow maximum burial shows dominant fracture sets sub-parallel and orthogonal to the fold axis. Most fractures terminate at bedding planes. Small thrusts within beds demonstrate the importance of layering slip. Tectonic stylolites are rare and indistinct. At greater maximum burial, fracture patterns are dip and strike oriented, but en-echelon shear fractures are locally important and tectonic stylolites are abundant. A prominent, near vertical fracture set cuts bedding sub-parallel to a regional normal fault trend. This fracture orientation may be related to regional rather than local deformation. Fracture sets within complex structures form a complex, heterogeneous fracture pattern. The heterogeneous fracture distribution within adjacent fault blocks makes their prediction in subsurface reservoirs difficult. Fractures in fault-bounded highs deformed at shallow burial depth show increasing intensity and geometric variability proximal to faults. These form a strongly deformed damage zone. Small fractures confined to single beds are not simply related to orientation of bounding faults or dip. Larger through-going fractures lie along the regional trend. Fractures in chert nodules are dilated, open and more closely-spaced than the surrounding limestone. Together, these results indicate that general characteristics of fracture systems can be predicted from structural style, lithology, and burial depth during deformation. Mineralization of fractures in this old fracture system is related to burial history since deformation.

Scattered, often poorly exposed, strata that can be correlated with the Upper Pennsylvanian Palo Pinto and Posidion formations (Lowery, 1962), Canyon Group, Brazos River Valley, occur in western Wise County, Texas. These northwest dipping rocks are unconformably overlain and often obscured by southeast dipping Lower Cretaceous (Comanche Series) sand and conglomerate. In the early 1900's, Bose, Plummer and Moore, and Scott and Armstrong proposed several names for these Pennsylvanian limestone strata (Bridgeport, Hudson Bridge, Martin Lake, Balsora, Sanders Bridge, Boone Creek, and Willow Point), mostly with brief descriptions and poorly located type sections.

Examination of exposures of these strata and their contained fusulinid and conodont faunas has demonstrated that (in descending order): (i) a conodont rich black mudstone (indicating maximum flooding) in the base of the Wolf Mountain Shale and just above the Wiles Limestone correlates to a similar interval just above the Willow Point Limestone, well exposed in the area around the south side of Lake Bridgeport; (ii) the Willow Point Limestone (= Bridgeport Limestone, no longer used) correlates to the Wiles Limestone (top of the Posideon Formation, Brazos River Valley); (iii) a conodont rich black mudstone present in the middle part of the Posideon Formation correlates to equivalent age strata in the Martin Lake area just south of Bridgeport; (iv) the Martin Lake (= Balsora) Limestone (fusulinid/algal grainstone indicating very shallow marine sediments) correlates with the top part of the Palo Pinto Formation; (v) the Sanders Bridge Limestone correlates with the middle part of the Palo Pinto Formation; (vi) the Hudson Bridge (= Boone Creek) Limestone correlates with the lower part of the Palo Pinto Formation.

The Fort Worth Basin formed during Early and Middle Pennsylvanian due to the oblique collision of the Afro-South American and North American plates. This tectonic activity not only affected deposition at that time but also affected the underlying formations. Depositional environments changed from shelf carbonates to shallow marine to deep marine then back to shallow marine during basin development. Eustatic cycles combined with tectonic activity have complicated mapping efforts and led to many misunderstandings about the basin. Much of the basin center is unexplored and has potential for enormous gas reserves. Reservoir mapping of just the basin-centered tight gas sediments indicate natural gas reserve potential in the tens of TCF. Is this another giant reservoir that can be "gas-farmed" much like the Barnett Shale?

A four-hundred-foot throw thrust fault extends through southern Parker County with open hole logs indicating repeat sections in the Barnett Shale, Atoka and Strawn formations. Due to the cyclicity of sediments during this time, most of these repeat sections can be mapped as separate deposits. It is also believed that due to the oblique collision of the plates, lateral fault movement and faults of different orientations complicate the understanding of tectonics during this time. This tectonic activity has the potential to have created additional "sweet spots" in the Barnett Shale similar to the Newark East gas field. Faulting and fracturing may have created potential permeability enhancement and hydrocarbon traps in the Ellenburger and Marble Falls making these formations exploration and development targets. Due to a lack of drilling, very little is known about these formations in most of the basin. The Fort Worth Basin is a new exploration frontier for combining the advances in geology and engineering technologies.

During the past 5 years, Chesapeake Energy has acquired over 3500 miles of recent 3D data in Oklahoma, concentrated in the prolific gas producing area established within the Anadarko Basin. This basin is characterized by the structural and stratigraphic complexities associated with multiple episodes of extensional, thrust, and wrench tectonics.

This complexity has provided the opportunity for 3D seismic to illuminate the potential for finding significant gas reserves under and between the existing production. Chesapeake currently has over 20 rigs actively drilling for these reserves at depths up to 25,000 feet; most of which are targeting prospects delineated by 3D.

Chesapeake's continued commitment to 3D in this area is reflected by a 2003 program that includes the acquisition of over 600 sqs of new proprietary and spec data.