Abstract Pinedale field, located in Sublette County, Wyoming, is one of the largest natural gas fields in the United States. The discovery and commercialization of this field covers a period of nearly 60 years. During this time, many different companies and people were involved in bringing Pinedale to the point of commercial production. The field produces from the Upper Cretaceous Lance Formation on the Pinedale anticline. The Lance Formation is a series of stacked sandstones interbedded with siltstone, mudstone, and shale. The sandstones typically average about 7% porosity with permeabilities in the single-digit micro-Darcy range. In much of the Pinedale field, the Lance reservoir section is over 5500 ft (1700 m) thick, and it is typically overpressured throughout the section. The commercialization of the field was made possible through the convergence of a better understanding of the geology of the reservoir rocks and the nature of the field’s structure as revealed through the use of modern three-dimensional (3-D) geophysical data. This understanding permitted the development and utilization of modern drilling and completion practices that were developed during the drilling of the adjacent Jonah field and that continue to evolve today.

Abstract The Green River and Hoback Basins of northwest Wyoming contain very large, regionally pervasive, basin-centered gas accumulations (BCGAs). Published estimates of the amount of in-place gas resources in the Green River Basin range from 91 to 5036 trillion cubic feet (tcf). The Hoback Basin, like the Green River Basin, contains a BCGA in Cretaceous rocks. In this chapter, we make a distinction between regionally pervasive BCGAs and BCGA sweet spots. The Pinedale field, located in the northern part of the Green River Basin, is one of the largest gas fields in America and is a sweet spot in this very large BCGA. By analogy with the Pinedale field, we have also identified a similar BCGA sweet spot in the Hoback Basin. BCGA sweet spots probably always have characteristics in common with conventional accumulations but are different in that they are always contiguous with the underlying more regional BCGA. In this way, they are inseparable from the more regionally pervasive BCGA. We conclude that the probability of forming sweet spots is highly dependent on the presence of faults and/or fractures that have served as conduits for hydrocarbons originating in regional BCGAs. Finally, we propose that the Paleocene “unnamed unit” overlying the Lance Formation be renamed the Wagon Wheel Formation.

Abstract The giant Pinedale gas field in the Green River Basin of Wyoming produces from a 5500–6000 ft (1700–1800 m) interval of Upper Cretaceous fluvial sandstones in the Lance Formation, the Upper Mesaverde interval just above the Ericson Sandstone, and the Paleocene Wagon Wheel Formation. Typical porosities for the field are <10% with micro-Darcy permeability. Over 4000 ft (1220 m) of core have been examined to better characterize facies for correlation to rock properties for reservoir modeling and decisions on optimizing field development. The main types of reservoir sandstones are river channel deposits and overbank splay or sheet sands. Channels display fining-up sequences typical of river bar deposits. These sequences have been subdivided into four facies: (1) channel base lags, (2) lower bar or active thalweg fill, (3) upper bar, and (4) soil-modified bar top and abandonment fill. Splay sandstones are typically finer grained and more cemented, with lower reservoir quality. Overbank mudrocks display pervasive features consistent with incipient soil formation, including roots, peds, and insect burrows. Despite an overall similarity in facies character, there are variations in facies and stacking patterns both vertically and laterally around the anticline. The Upper Mesaverde interval has fewer sandstones; thinner, dominantly single-story channels; thicker intervals of splay sands; and more carbonaceous and burrowed overbank mudstones. This suggests a higher accommodation, lower coastal plain setting with poorly drained floodplains. The Lance Formation contains thicker channel deposits with varying amalgamation and more multistory channels, indicative of intervals with a higher ratio of sediment supply to accommodation. The upper Lance Formation also has more oxidized mudstones and calcite nodules in floodplain deposits, indicating better drainage and/or possibly drier climate. Log response is sensitive to many subtle geologic features, such as cemented zones and mud-clast lags, and can be used to differentiate depositional facies. There is a good correlation between porosity and permeability in appropriately stress-corrected core measurements. There is a clear depth relationship to porosity and permeability with the Upper Mesaverde sandstones having lower porosity and permeability than the Lance sandstones. Despite significant compaction and cementation leading to low porosity and permeability, there is a good correspondence of core and log petrophysical properties to facies with larger grain size and higher energy facies having generally greater porosity and permeability. Porosity and permeability within channel facies are broadly similar between single-story and multistory channels, but multi-story channels have thicker intervals of the highest quality channel facies because of erosional amalgamation. Relationships regarding story thickness, facies characterization, porosity, and permeability are used to construct detailed numerical models to study various aspects of field development decisions.

Abstract The giant Pinedale gas field in the Green River Basin of Wyoming produces from up to 6000 ft (1800 m) of the Upper Cretaceous fluvial sandstones of the Lance Formation, the Upper Mesaverde Group, and the Paleocene Wagon Wheel Formation. The Wagon Wheel Formation is approximately 1300 ft (400 m) thick and differs in character from the underlying Lance and Mesaverde Formations in having conglomerates and significant feldspathic components. This lithologic change has previously been attributed to the unroofing of the crystalline core of the Wind River Mountains. The distinct lithology and mineralogy causes different log and rock property relationships than those seen in the Lance and Mesaverde. A recent core in the Wagon Wheel Formation has allowed modern core analysis techniques to be applied, increasing our understanding of the reservoir characteristics for this interval. Porosity and permeability are higher in sandstones and conglomerates of the Wagon Wheel Formation as compared to the sandstones of the Lance Formation. Upper and lower intervals within the Wagon Wheel Formation have distinct lithologies and are separated by an unconformity. A distinct gamma-ray log shift, the “gamma-ray marker,” is present at the unconformity and is caused by an increase in potassium and thorium related to increases in feldspar and chlorite above the unconformity. The lower interval contains both lithic sandstones similar to the Lance and also feldspathic conglomerates. The upper interval contains feldspathic coarse sandstones and conglomerates but is dominated by greenish-gray debrites containing poorly sorted mixtures of chlorite-rich clay, sand, and pebbles. The upper interval is water bearing, whereas the lower interval contains and can produce gas, albeit with higher water saturation than that found in the Lance Formation.

Abstract Routine core analysis techniques used on the very low permeability “tight” sandstone reservoirs in Pinedale field failed to give reliable results sufficient to design and justify field development or to calculate gas productivity and the field’s original gas in place. In part these problems arose because of the complex variety and textures of the clay minerals lining the pores in the producing intervals. Early in the core evaluation program, it became apparent that mineralogy, clay composition and texture, and the rock’s low porosity and permeability warranted an unconventional approach to core analysis. Thus, new core analysis protocols had to be developed and tested to provide representative, meaningful data in a timely fashion. Examination of the effects of cleaning and drying core samples led to the adoption of “fresh state” core analysis methods. Core tests were employed to provide not only thorough characterization of clay-bound water but also an understanding of how this clay-bound water affected various rock and petrophysical properties. Almost every rock property was examined by multiple techniques, including well-documented traditional core analysis methods and newly introduced technologies and methods. Triplicate core plug sampling and fresh-core screening tests expedited the test programs. Rapid and extensive clay characterization resulted from simple staged drying. Routine core water saturations were supported with corrections via filtrate tracers, mainly tritium, in some wells. Special core analyses included updated core water salinity determinations with additional fresh-state tests for electrical properties, capillary pressure, and relative permeability. Fortunately, operators in Pinedale field understood the importance of reliable core analyses and provided 21 conventional cores, each 4 in (10 cm) in diameter, totaling more than 1000 ft (300 m) in length from 10 wells distributed along the anticline. These cores were cut from 2002 to 2005 early in the development of the field using a water-based mud system. Results of the core analysis program greatly improved understanding of the field’s reservoir system, and allowed for quantitative and petrophysical characterization of the reservoir rocks. Fresh-state analysis techniques provided both routine and special core data to develop log models for gas in place. Furthermore, special core analysis revealed that the formation-water salinity typically ranged from 30,000 to 40,000 mg/l NaCl, which is substantially higher than earlier estimates of about 13,000 mg/l. All else being held equal in a resistivity model, these higher salinity values very favorably impacted the estimate of the field’s gas in place.

Abstract Pinedale field is a giant gas field producing from extremely low porosity and permeability sandstones. Wireline log data from 127 wells covering the entire field were studied to characterize the porosity, permeability, and water saturation of the Lance and Upper Mesaverde reservoirs. The logs were environmentally corrected and normalized, shale volume and porosities were calculated, water saturations were determined by the Dual Water model, and net pay was calculated using field-specific pay criteria. Within the entire Lance Formation, which ranges from 3580 to 4780 ft (1090–1460 m) in thickness, the average well has 1890 ft (580 m) of net sandstone (less than 75 api units on the gamma-ray log) with an average log-determined effective porosity of 5.7%. The average permeability of all sandstones, estimated from core data-derived equations, is only 20 microdarcies (0.02 mD). The average water saturation of all sandstones is 52%. Using 5% porosity and 60% water saturation as absolute net pay cutoffs, the average net pay thickness of the Lance reservoirs at Pinedale is 1050 ft (320 m). A substantial section of Upper Mesaverde sandstones is also gas productive at Pinedale. Out of a total section ranging from 80 to 800 ft (25–225 m) in thickness, the average well has 420 ft (130 m) of net sandstone of which 200 ft (60 m) is net pay using the same cutoffs used in the Lance. This represents just 15% of the gross Upper Mesaverde section. The average porosity of the Upper Mesaverde sandstones is 5.0% with an average water saturation of 42%. The major difference between Jonah and Pinedale fields is the total interval thickness saturated with gas, which is almost 2.5X greater at Pinedale than at Jonah. Although the porosity and gas saturations at Pinedale are on average lower than at Jonah, the greater net thickness more than compensates for the difference in reservoir quality accounting for the very high productivity of wells at Pinedale. Evaluation of water saturation trends versus structural elevation, both determined from as–received cores and from log modeling, shows no systematic trend in gas saturation with height. Although the apparent gas saturated section at Pinedale is over 7000 ft (2130 m) in thickness, water saturation does not decrease consistently up section as might be expected. This, combined with pressure versus depth profiles based on mud weights, indicates Pinedale is not a simple single gas column but rather is a series of separate and overlapping reservoir compartments separated by imperfect seals. The saturation attained in any given reservoir compartment is likely set by the capillary pressure characteristics of the overlying sealing facies, so that the minimum saturations observed in the field reflect only a few hundred to not more than 2000 ft (610 m) of gas column.

Abstract The northern Pinedale field is a complex set of stacked gas-bearing sandstones in a section approximately 6000 ft (1800 m) thick. The main reservoirs occur in the Upper Cretaceous Lance Formation and the Upper Mesaverde interval above the Ericson Sandstone. Gas-charged sands are first penetrated at the top of overpressure in the Wagon Wheel Formation of Paleocene age. The pressure gradient increases with depth through the Lance and Upper Mesaverde sections. The maximum pressure gradient in the Mesa area (T31N, R109W) is 0.8 psi/ft in the Upper Mesaverde interval. In the Stewart Point area at the north end of the anticline (T32N, R109W), the maximum pressure gradient approaches 0.85 psi/ft over the same interval. The reservoir consists of fluvial sandstones classified as litharenites. Mineralogy is dominated by quartz, chert, and clay with minor components of feldspar, calcite, and dolomite. Clays form from 6 to 19% of the rock volume and are illite, kaolinite, and chlorite. Ten wells were cored in the study area, including three for special core analysis. Two wells were cored with tritium-traced mud to quantify the filtrate invasion. Special core analyses were performed on preserved samples. These include partition of fluids, formation factor, resistivity index, capillary pressure, and relative permeability of gas to water. Porosity ranges from 4 to 13% and permeability ranges from 0.0001 to 0.1 mD in reservoir sandstones under in situ conditions. The average net-to-gross for pay sandstones in the field is 21%. The Mesa area generally has more sandstone than the Stewart Point area. Average porosity and water saturation for pay sandstones are 8.7% and 34%, respectively. At in situ reservoir conditions of 1000 to 2000 psi net mean stress, the porosity reduction is less than 6% compared to laboratory conditions of 800 psi. Permeability reduction is 5 to 60% from laboratory conditions and up to 80% during late stage depletion. The permeability reduction as a result of increasing net mean stress is governed by original permeability and clay content. Relative permeability of gas with respect to water saturation is important in tight sandstones. Water saturations exceeding 50% in clean sandstones significantly reduce gas permeability by one to two orders of magnitude. Capillary pressure curves indicate that columns heights range from 200 to 1000 ft (60–300 m) in individual reservoir sandstones. These limited column heights combined with the increasing pressure gradients with depth indicate a series of stacked gas columns rather than a single continuous column.

Abstract The Pinedale anticline and Jonah field in the northwest part of the greater Green River Basin produce natural gas and gas condensate from a thick succession of Upper Cretaceous and earliest Tertiary strata in the Lance Pool. Both producing areas are simple structural traps made more complex by the interbedded nature of the reservoir sandstones and sealing mudstones. In neither area is there a distinct top seal. The unusual pressure gradient exhibited by these two areas indicates that the mudstones intercalated with the reservoir sandstones are partially sealing and that there are sealing beds distributed vertically throughout the reservoir complex. Leakoff has been complete near the top of Lance Pool and is progressively less so deeper below the top of the Lance Pool. The Pinedale anticline is a classic anticlinal structure formed by thrusting along the Pinedale thrust fault on the southwest flank and folding above the thrust. Jonah field is delineated by two main sub-vertical bounding faults and several internal faults that subdivide the field into smaller compartments. In both areas, high pressure occurs in the structural closure and is coincident with increased gas saturation and a subtle increase in porosity relative to outlying areas. Despite the low fraction of porous pay sands to gross interval, the great thickness of the Lance Pool combined with significant overpressure has resulted in world class accumulations of gas in place. Low permeability in both fields has driven development drilling to a high density (close spacing) to facilitate recovery of a significant portion of the high concentration of gas in place.

Abstract The giant Pinedale gas field in the Green River Basin of Wyoming produces from a 5500 to 6000 ft (1700–1800 m) interval of Upper Cretaceous and lowermost Tertiary sediments. The reservoir comprises discontinuous, lenticular fluvial sands intercalated with overbank sand, silt, and mud. Average porosity in reservoir sandstone is <10% with permeability in the micro-Darcy range. A typical well may have 50 channel sand packages, bundled into 15 to 20 frac stages and commingled. Modeling to date has focused on the interaction of complex fluvial sand geometry with hydraulic fractures, increasing pore pressure with depth, and variable water saturation. Although natural fractures have been recognized, their demonstrable impact to production is localized. Despite significant compaction and cementation, we can demonstrate good correspondence of core and log petrophysical properties to facies. Because of this, it is desirable to use facies to populate reservoir models. A multi-step approach was used to populate small (approximately one square mile [2.6 sq km]) “sector” models of different parts of the field. Logs were used to determine facies via neural nets and petrophysical cutoffs. Facies were distributed via object modeling, and then petrophysical properties were distributed within facies using sequential Gaussian simulation. Gross channel ribbons and bar objects were placed first, guided by interpolated V-shale, which is a proxy for sand correlation. Detailed facies bodies were then distributed within those elements. Because net/gross, sand thickness, sand correlation, and overbank character change throughout the section, different zones were modeled using different body dimensions in consideration of analogs. In dynamic reservoir simulation, acceptable history matches were attained despite the architectural complexity using production data, bottom-hole pressure, production logging tools, and distributed permanent pressure gauges. These models were used to help assess incremental recovery related to increased well density.

Abstract The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, located north of the giant Jonah field. Gas production is from overpressured fluvial channel sandstones of the Upper Cretaceous Mesaverde and Lance formations and the lower Tertiary “unnamed Tertiary” formation. To date, most studies have focused on the regional geology and potential hydrocarbon economics. This chapter discusses an integrated approach for reservoir modeling to reduce uncertainty in this tight-gas field development. In this study, fluvial facies were defined using wireline logs. Object-based modeling was used to integrate well-log facies, object dimension, channel sinuosity, and orientation in building the three-dimensional facies model. The facies model was then used to guide petrophysical property modeling. Dependencies between rock properties were modeled using a geostatistical method. The final model honors the fluvial depositional characteristics and dependencies between the rock properties and was used for better uncertainty management in reservoir simulation and performance forecasting. The Pinedale anticline (PDA) is located in the northwestern Greater Green River Basin in southwestern Wyoming (Figure 1A ). Although the Jonah field, located just south of Pinedale in the same basin, has been extensively studied ( Dubois et al., 2004 ; Robinson and Shanley, 2004 ; Apaydin et al., 2005 ), few studies have been published on Pinedale. Hydrocarbon analysis at the basin scale is limited to traditional geologic descriptions, including structural geology, stratigraphy, core description, and petrophysics ( Law, 2002 ). Because the interwell facies and petrophysical property heterogeneities on the PDA significantly impact volumetrics assessment, drainage, new well placement, and depletion strategy, developing accurate models of the subsurface heterogeneities was very important. To achieve optimal hydrocarbon depletion, an integrated study on small-scale heterogeneities was required. Reservoir modeling was conducted because it could incorporate uncertainty analyses on rock properties, including geologic facies, pore space, fluid saturation, and permeability. An area of 1.5 mi 2 (3.9 km 2 ) was selected in the southern part of Pinedale for detailed reservoir study and to determine well drainage areas, new well placement, and production forecasting. To mitigate boundary effects for dynamic simulation, the geocellular model was enlarged to an area of more than 2 mi 2 (>5 km 2 ), located on the crest of the anticline. Twenty-three wells with a full suite of petrophysical logs were available in the enlarged modeling area (Figure 1B ).

Abstract The Fremont Lake area is at the southwest base of the Wind River Range, northeast of the town of Pinedale in Sublette County, Wyoming, (Fig. 1). It is included in the Fremont Lake South Quadrangle (scale 1:24,000) for which a topographic map, a geologic map (Richmond, 1973), and a soils map (Sorenson, 1986) are available. The area is accessible from Pinedale on U.S. 191, about 100 mi (160 km) north of Rock Springs and 70 mi (112 km) southeast of Jackson. County Road 23-111 (paved) leads northeast from Pinedale into the area. Most of the terrain is in Bridger National Forest, but some is private land. All maintained roads are accessible by passenger car. Many unimproved roads require four-wheel drive. Obtain permission to enter gated roads. Respect signs; close all gates unless found open; and do not drive into areas under irrigation. For a short tour, take County Road 23-11 f from the east end of Main Street in Pinedale toward Fremont Lake. The road leads up a terrace front, passes a cemetery, and extends northeast across gently rolling Bull Lake end moraines to an S-curve 2.2 mi (3.5 km) from U.S. 191. Here, the road ascends the steep, very bouldery front of the outermost Pinedale end moraine. Park at the bottom and walk 50 yd (46 m) up the road to a cut where Pinedale Till is well exposed (locality A, Fig. 1). Drive on to the moraine crest, from which an out standing overview of Fremont Lake, the enclosing Pinedale

Clay-mineralogy, mean random vitrinite reflectance (R m ), and fluid inclusion homogenization temperature (T h ) from host-rock and vein samples in cored intervals from 5,000–18,000 ft (1500–5500 m) indicate that paleotemperature was higher than the temperature currently measured in siliciclastic rocks of the Pinedale anticline, Green River basin, Wyoming. The cored intervals are from lower Tertiary and Upper Cretaceous rocks in the El Paso Natural Gas Wagon Wheel no. 1 well. Compositional analyses of mixed-layer illite/smectite (I/S) clay from sandstone and shale in the Wagon Wheel core show a progressive increase in ordering and the number of illite layers with depth (and temperature). Temperatures determined from changes in the composition and ordering of I/S, and R m data, imply that the rocks of Wagon Wheel reached about 200°C at 18,000 ft (5500 m). Uncorrected log temperature at this depth is about 135°–150°C. The thermal gradient calculated at maximum burial temperature (25°C/ km), however, is similar to the thermal gradient established by present-day borehole temperature (24°C/km). These data suggest that maximum temperature was 30°–50°C higher than present-day uncorrected borehole temperature. The apparent temperature decrease can be explained by erosion of about 5,600 ft (1700 m) of section, as calculated from a surface R m intercept of 0.33%, with a geothermal gradient that has remained constant since maximum burial. Major uplift of the Pinedale anticline occurred after apparent maximum burial and temperature were established in the Neogene. T h of 130°–150°C from aqueous fluid inclusions in quartz within calcite and quartz veins at 17,000 ft (5200 m), however, conform to the present temperature regime. Fractures probably formed during uplift of the Pinedale anticline and were later mineralized in a temperature regime much like that of the present. Primary, hydrocarbon-bearing fluid inclusions in veins from 8,000–17,000 ft (2,400–5200 m) are evidence for petroleum migration occurring during the filling of these late fractures. Secondary oil fluid inclusions, trapped in healed mierofractures that crosscut authigenic quartz in these veins at a depth of 17,000 ft (5200 m), indicate that petroleum migration continued sometime after these deep fractures were mineralized.

Abstract The Pinedale field, a giant gas and gas condensate field, is located in the northwest part of the Green River Basin in southwest Wyoming. This field has an estimated ultimate recovery (EUR) of 39 trillion cubic feet of gas equivalent (tcfe), making it the third largest gas field in the United States based on 2009 statistics from the U.S. Energy Information Administration. Additionally, the natural gas condensate production makes it the 49th largest oil field in the same study. Production is principally from overpressured, gas-saturated, tight gas sandstones and siltstones of the Lance Pool comprised of the Upper Cretaceous Upper Mesaverde interval, the Upper Cretaceous Lance Formation and the lowermost part of the lower Tertiary Wagon Wheel Formation. The presence of natural gas in the Pinedale anticline area has been known for decades. The California Company drilled the first well within the current Pinedale field production limits in 1939 and encountered gas but completion attempts failed. Despite numerous wells drilled over the ensuing years, it was not until the late 1990s that the first commercial production was achieved in Pinedale field. This success was largely the result of improved multistage fracture stimulation techniques, which had been successful in nearby Jonah field’s tight gas, low-permeability Lance Pool sandstones and siltstones. Pinedale field is a complex accumulation and still has some disagreements as to its true nature. The trapping mechanism within the field has both stratigraphic and structural components and the reservoir has further been shaped in areas by natural fracturing. The field is coincident with the thrust-bounded Pinedale anticline, which is situated approximately 5 mi (8 km) west of the west edge of the Wind River Mountains, another thrust-fault-bounded feature. The Wyoming thrust belt is located approximately 30 mi (48 km) to the west. The town of Pinedale, Wyoming, is at the northeast end of the field. Jonah field, also a giant gas field producing from the interval equivalent to the Lance Pool in Pinedale, is adjacent to and just west of the southern limit of Pinedale field. The absolute field limits of Pinedale are still being defined, but the current field is about 30 mi long (48 km) and up to 5 mi wide (8 km) in places. Producing rocks in the Lance Pool mainly consist of alluvial plain deposits. The source sediments were Paleozoic and Mesozoic sedimentary rocks eroded from surrounding uplifts and deposited in a rapidly subsiding basin. The Lance Pool hydrocarbon-bearing sandstone, siltstone, and shale column locally exceeds 6000 ft (1829 m) in total thickness. The primary reservoirs in the interval are fluvial channel sandstones deposited by migrating rivers, which flowed generally from northwest to southeast across the depositional area. The resulting reservoir bodies are complex laterally and vertically stacked discontinuous multistory and single-story channel-fill and overbank deposits with as much as 1600 ft (488 m) of net productive sandstone and siltstone in the Lance Pool. Total drill depths range up to 15,000 ft (4572 m) subsurface. Average porosity in these gas-bearing sandstones is about 7% with just 0.005 mD (5 microdarcies) of permeability. The reservoir is overpressured from about 0.57 pounds per square inch per foot (psi/ft) at the top of the Lance Pool gradually increasing to 0.85 psi/ft near the base of the productive interval. The source of the abundant gas in the Lance Pool at Pinedale field has been the subject of much discussion. The Lance Formation itself contains relatively little organic matter and has never been hotter than the oil-generation window. The top of the dry gas window occurs at a depth of about 15,000 ft (4572 m) in the Rock Springs Formation. The Upper Mesaverde interval has some carbonaceous shale layers and thin coals that were in the wet-gas window and could have generated a relatively small amount of gas. Isotopic analyses of the produced gas in the Lance Pool indicates higher thermal maturity (R o >2%), which imply a source deeper than the deepest depth penetrated to date by drilling to the upper Hilliard Shale in the field. These potential deep source beds include the lower portions of the upper Cretaceous Hilliard Shale, and the lower Cretaceous Mowry Shale, possibly with a relatively minor contribution from coals in the lower part of the Upper Cretaceous Rock Springs Formation. Hydrocarbon generation and migration into the reservoir rocks of the Lance Pool at rates in excess of the rate of leak-off charged the section and resulted in the overpressured, gas-saturated reservoir. To date more than 2000 wells have been drilled in the field with cumulative production through the end of 2011 at 3.3 trillion cubic feet (tcf) of natural gas and 25.4 million barrels (MMBLS) of gas condensate.