ABSTRACT The Devonian Woodford Shale and Cretaceous Mowry Shale consist of relatively deep (below storm wave base) intracratonic basin deposits commonly referred to as “shales” because of their dark gray to nearly black color, very fine-grained nature, pelagic fossils such as radiolarians, and common amorphous marine kerogen. These shales typically contain less than 30% detrital clay by weight and more than 50% quartz (locally up to 80%). The quartz is a mix of biogenic grains, mainly radiolarians, and authigenic silica along with some detrital quartz silt of extrabasinal origin. The authigenic silica is dominantly microcrystalline (< 1 micron) and forms a major component of the matrix in these formations, but the rocks also contain authigenic pyrite, commonly as framboids, minor carbonates including magnesite, and quartz overgrowths, but together these authigenic minerals form less than 10% of the rock. Authigenic quartz in the Woodford and Mowry samples commonly takes the form of silica nanospheres, a type of microquartz less than a half micron in diameter. Textures of this microquartz are best observed directly with a high-resolution electron microscope. In many Woodford and Mowry samples, the silica nanospheres, which tend to be associated with organic matter, form more than 50% of the rock. The large volume of the authigenic quartz, together with “floating” detrital components and the close association with pyrite framboids, indicates that the silica nanospheres formed very early, perhaps in association with microbial activity on or in the seafloor sediments. These early silica nanospheres, which are only weakly luminescent, helped create a lithified sediment during or soon after deposition. Where the silicification process ceased prior to complete silica cementation, the early silica nanospheres are associated with up to 15% interparticle microporosity. This gives the Woodford and Mowry good potential reservoir quality, at least locally. The authigenic silica nanospheres also enhance the mechanical properties and brittleness of these siliceous mudrocks to a degree much greater than the presence of the detrital quartz particles alone.

Abstract Pinedale field is located in the northern part of the Green River Basin in western Wyoming about 90 mi (145 km) southeast of Jackson, Wyoming, near the town of Pinedale (Figure 1). It is one of the largest natural gas fields in the United States with ultimate recoverable reserves estimated to be about 39 trillion cubic feet (tcf) of methane-rich natural gas. Despite the huge gas reserves, the field’s productive areal extent is relatively small as it is only about 30 mi (48 km) long and less than 5 mi (8 km) wide. The field covers an area of about 84 mi 2 (220 km 2 ). In this sense, it is a very concentrated gas resource. Production at Pinedale comes from the Lance Pool, which is nearly 6000 ft (1800 m) thick and consists of multiple stacked discontinuous Upper Cretaceous Lance and upper Mesaverde sandstones and siltstones that were predominantly deposited by fluvial processes and are encased in shales and mudstones. The reservoir rocks in Pinedale field occur at depths of about 8500 to 14,500 ft (2600–4400 m) and are tight with fairly low porosity (mostly 10%) and very low (micro-Darcy) permeability. The tight nature of these reservoir rocks makes it difficult for gas to move laterally and vertically for significant distances. As a result, it is necessary to conduct multistage hydraulic fracturing in all of the field’s wells to create pathways for the gas to enter the wellbores at commercial rates. The tight nature of the reservoir rocks at Pinedale begs the question: “What makes Pinedale such a prolific natural gas field?” The field has some unique geologic characteristics.

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 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.

Abstract Geophysical data were fundamental in the economic development of the Pinedale field. Early exploration in Pinedale was prompted by the presence of a large thrust-faulted anticline, which could be better mapped with the use of both potential field geophysical data and seismic data. Because Pinedale is a complex field having attributes of both a stratigraphic trap and a structural trap, understanding the complexity of the accumulation involved extensive application of 3D seismic data. Microseismic and crosswell seismic data were utilized to provide details about the orientation and lateral extent of sand bodies and the behavior of hydraulic fractures used to stimulate the wells for enhanced productivity. Further, seismic data and analysis supplied information critical to the definition of the field limits both vertically and horizontally. This understanding of the field limits has evolved over time with increased well control and calibration to the currently defined field area to indicate a current reserve potential of 58.7 tcf of original gas in-place (OGIP) and 38.2 tcf of recoverable gas.

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 Pinedale field produces gas from the nearly 6000-ft (1800 m) thick “Lance Pool” composed mainly of fluvial sandstones in the Lance Formation and in the uppermost Mesaverde Group above the Ericson Sandstone. Below this thick gas-productive interval is another 10,000 ft (3000 m) of sedimentary section that has so far proved noncommercial but which has been penetrated by only three deep wells on the 35-mi-long (56 km), 2- to 3-mi-wide (3–5 km) anticline. All three of these deep wells yielded abundant gas shows from intervals in the Ericson, Rock Springs, and Hilliard Formations in the hanging wall of the thrust-fault that formed the Pinedale anticline. Considering the size of the anticline, the abundance of gas shows, and the major hydrocarbon source potential of the Cretaceous Mowry and Hilliard Shales now at depths below 18,000 ft (5500 m) on the anticline, it seems likely that it is only a matter of time before the proper confluence of improved understanding of the potential reservoir zones, improved completion techniques, and higher gas prices leads to commercial development of one or more of these deeply buried reservoirs. The three wells that are the focus of this study are the Wagon Wheel #1 drilled in 1969 and 1970 by El Paso Natural Gas, the Stewart Point 15-29 drilled by Questar (now QEP) in 2004 and 2005, and the Mesa 10D-33 drilled by Ultra Petroleum from 2006 to 2008. In the Wagon Wheel #1, the liner below intermediate casing at 12,086 ft (3684 m) was accidently filled with cement and no completion of the deeper intervals below the Lance Pool could be attempted. In the Stewart Point 15-29 well, reservoir pressures were so high following fracture stimulation of three stages in the uppermost Hilliard and lower Blair from 18,541 to 19,435 ft (5651–5924 m) that rock fragments were produced from the well bore, plugging it. When this plug of debris was eventually cleaned out months later, both reservoir pressure and production declined rapidly over a period of days. Additional fracture stages were then added up hole in the Rock Springs Formation, but these also had limited reservoir capacity, causing production to decline quite rapidly. This well was then completed in the Lance Pool and produced nearly 7 BCF of gas and 63,000 barrels of condensate between October 2006 and September 2013. Ultra’s Mesa 10D-33 well has the only current production from the Rock Springs, Blair, and Hilliard Formations. This well produced about 264 MMCFG and 57,500 barrels of water from June 2008 to December 2013 from a gross interval of 15,410 to 19,400 ft (4697–5913 m) and was still producing at a rate of 14 to 130 MCFGPD. The reservoir rocks include shaly and silty intervals in the Hilliard and very fine-grained marine and fluvial sandstones in the Blair and Rock Springs Formations. Extensive source rock analyses of cuttings from the SP 15-29 well including vitrinite reflectance work shows that the top of the oil generation window (R o = 0.6%) occurs in the Eocene Wasatch Formation at a depth of about 2600 ft (790 m), that the top of the wet gas window (R o = 1.0%) occurs near the top of the upper Mesaverde interval at about 12,500 ft (3810 m), and that the top of the dry gas window (R o = 1.4%) occurs in the Upper Rock Springs interval at a depth of about 15,000 ft (4570 m). In contrast, gas isotope analyses of both mud gas samples and head gas from cuttings isojars shows that the gas in the Lance Pool is dominantly dry gas with an equivalent vitrinite reflectance thermal maturity of 2 to 2.5%. This is even higher than the maximum vitrinite reflectance recorded in the deepest sample of the Hilliard Shale from 19,520 ft (5950 m) where the measured R o was 1.8%. This suggests that the gas in the Lance Pool migrated upward through more than 10,000 ft (3000 m) of sedimentary section from source beds in the Hilliard and possibly Mowry Shales at depths below 20,000 ft (6000 m). Significant amounts of isotopically distinct dry gas were also generated in the coal beds in the lower Rock Springs interval from 16,200 to 18,477 ft (4938–5632 m), but this gas mostly stayed within that interval rather than migrating into the overlying sandstone reservoirs in the upper Rock Springs interval and Lance Pool.

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 Open natural fractures commonly influence the production of natural gas by increasing permeability. To assess the abundance and orientation of natural fractures along the northern third of the Pinedale anticline, a suite of 14 cores totaling 1300 ft (400 m) in length from eight wells and 13,894 ft (4235 m) of image log data run over the upper 1300 to 4300 ft (400–1300 m) of the 6000-ft (1800 m) thick gas-bearing Lance Pool in four vertical wells were studied. Formation MicroImager™ (FMI) logs capable of distinguishing between open (conductive) and cemented (resistive) fractures were run in these four wells, all drilled with water-based mud, between 2000 and 2002 and reinterpreted as a group in 2010 for consistency. These image logs reveal that the total number of fractures per well ranged from 38 directly on the crest of the anticline to 74 a mile and a half (2.4 km) down the east flank of the anticline. Normalized values for the number of natural fractures, both open and healed, per 1000 vertical feet (300 m) of section ranged from 9.2 to 29.5 along the crest of the anticline with the eastern flank well having 17.1 fractures per 1000 ft (300 m) of image log data. For comparison, image logs run through the gas-productive Upper Cretaceous Mesaverde Group in the Piceance Basin average 42 natural fractures per 1000 ft (300 m) of section. In the wells on the crest of the Pinedale anticline, open and healed fractures occur in approximately equal numbers, but the northernmost study well on the north plunge of the anticline had 75% healed fractures whereas the eastern flank well had 58% open natural fractures. The dominant orientation of both the open and healed fractures is N60°W, which is oblique to the N15°W orientation of the northern axis of the Pinedale anticline. Based on both drilling induced shear fractures and borehole breakout patterns, Sigma 1 (σ 1 ), the direction of maximum principal stress along which artificially induced fractures are likely to trend, ranges from N26°W to N30°W about 30° off the trend of the sparse natural fractures with the northernmost study well on the north plunge of the anticline a bit less askew at N38°W. Image logs run in underbalanced wells show good to excellent gas entry into the well bore from sandstones but only minor or no entry from the natural fractures. However, comparing cumulative gas production for the first 21 months of each study well with the normalized number of total fractures determined from FMI logs revealed a strongly positive correlation (R 2 = 0.958) between the abundance of fractures and production. The two least fractured wells with less than 10 fractures per 1000 ft (300 m) of logged interval each yielded less than 1 BCF in their first 21 months of production whereas a well with almost 30 fractures per 1000 ft (300 m) of logged interval produced 2.2 BCF of gas. A highly fractured well at the south end of the Pinedale anticline, the Antelope 15-4, which had an image log showing 71 fractures per 1000 ft (300 m), produced 5.165 BCF in its first 21 months of production.

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.