Abstract A core workshop entitled Tight-gas Fluvial Reservoirs: A Case History from the Lance Formation, Green River Basin, Wyoming , was held in conjunction with the 2001 AAPG Annual Meeting in Denver, Colorado. As part of that short course, a book containing nine chapters, totaling almost 200 pages, was distributed to participants. In 2002, the editors proposed to AAPG and the Rocky Mountain Association of Geologists (RMAG) an opportunity to copublish a Studies in Geology volume with a larger group of papers that would have broad appeal to geoscientists and engineers working in tight-gas fluvial reservoirs. Jonah field is the largest natural gas discovery in the onshore United States in the last 10–15 yr. Recoverable reserve estimates range from 8 to 15 tcf, depending on the method of analysis. By virtue of being a tight-gas reservoir, it is, in many respects, a nontraditional field. According to many of the recent U.S. and world resource assessments, most of the future gas resources will come from tight, low-permeability sandstones in the deeper portions of basins. The intent of this volume is twofold: (1) to provide readers with previously unpublished or proprietary data on the field, and (2) to integrate all aspects surrounding the field including geology, geophysics, reservoir engineering, drilling and completion, and regulatory affairs. As such, this volume is a definitive collection that provides a truly integrated perspective of this giant field. The list of topics addressed in this book is by no means complete; however, it does encompass the comprehensive field description

Abstract The following information was gathered from various sources and released for publication. Additional information exists among the many operators in Jonah field, but much of that data is considered proprietary. Data on the drilling and completion of individual wells can be found in Appendix A on the CD-ROM included with this volume. Dean DuBois of EnCana Oil and Gas (U.S.A.) Inc. reviewed and revised some of the data.

Abstract Home Petroleum Corporation drilled two wells in 1986 and 1987 to test the concept of a large, basin-centered gas accumulation in the Upper Cretaceous Lance Formation in a remote portion of the northern Green River basin. Although these first wells had excellent shows of gas and calculated log pay, the reservoir sandstones had extremely low permeability. Unfortunately for Home, fracture-stimulation techniques used in the late 1980s were unable to unlock this vast gas resource. In 1991, John Martin at McMurry Oil Company recognized the potential of the play and quietly amassed a controlling interest in the area. McMurry Oil and their partners brought the appropriate drilling and completion technology into the project, an effort that resulted in the ‘‘rediscovery’’ of Jonah field. Jonah field will ultimately have more than 350 producing wells and is poised to become the next multi-tcf gas field in the Rocky Mountain region. The rediscovery of Jonah field ignited interest in structurally trapped, tight-gas exploration in Upper Cretaceous strata and may stand as an analog for further exploration of vast, sparsely drilled areas of the Rocky Mountain region.

Abstract Jonah field in the northwestern part of the Greater Green River basin produces gas from the Lance Formation of Late Cretaceous (Maastrichtian) age. The Maastrichtian in the central Rocky Mountain region was a complex period of major transitions associated with the onset of the Laramide orogeny. This period of mountain building and basin development, which ultimately divided the central part of the Rocky Mountain foreland basin into much smaller Laramide basins and uplifts, began during latest Campanian and early Maastrichtian time and continued until near the end of the Eocene. The Maastrichtian section consists largely of continental rocks in the western part of the study area and interbedded continental and nearshore marine rocks in the eastern part. Marine shales deposited in the Maastrichtian seaway are effective seals of regional extent in many parts of the central Rocky Mountain region. Coaly source rocks occur throughout a broad area near the limit of maximum westward marine transgression during the Maastrichtian in this region. Jonah field, however, is located west of the marine shale seals and west of the area with significant Maastrichtian coaly intervals. Coaly intervals in the underlying Campanian Rock Springs Formation at Jonah may be the source of much of the gas, and a shale interval near the top of the Lance Formation may be the top seal for Jonah. An isopach map of Maastrichtian rocks reveals a complex pattern, including thickening trends toward newly developing Laramide uplifts as well as thickening toward areas of active thrusting along the Sevier orogenic belt. Jonah field is located in a deep, northwest-trending trough that developed southwest of the Laramide Wind River Range during the Maastrichtian. The Maastrichtian interval is overlain by lower Paleocene rocks throughout much of the study area, except near later Laramide uplifts. These thickening trends are the result of both variations in rates of subsidence during the Maastrichtian and differential erosion of Maastrichtian rocks prior to deposition of overlying Paleocene rocks. The Maastrichtian section is thin throughout a broad area in the southwestern part of the Greater Green River basin and Uinta basin. The lack of active thrusting and resultant thrust loading along the adjacent part of the Sevier orogenic belt during the Maastrichtian may be responsible for this thinning. Erosion of the Sevier highlands along this inactive portion of the orogenic belt may have instead produced broad uplift in the adjacent basin areas because of unloading. Paleocurrent studies in Maastrichtian rocks indicate that eastward-flowing drainage systems off the Sevier orogenic belt were maintained throughout the central Rocky Mountain region despite highly varying subsidence rates. Major Maastrichtian trunk streams tended to remain in place for extended periods of time, creating east–west-trending belts with thick stacks of fluvial sandstones surrounded by much less sandy intervals. Jonah field is located in a major southeast-flowing drainage system that was confined to the rapidly subsiding trough southwest of the Wind River Range. Stream systems that were flowing off rising Laramide uplifts appear to have been relatively short tributary streams to the major east-flowing trunk streams. These tributary streams were commonly mud choked as Cretaceous marine shale sequences were eroded off Laramide uplifts during the initial stages of uplift.

Abstract Jonah field is located in Sublette County, Wyoming, and lies in the southeastern portion of the Hoback basin, a northwestern extension of the Greater Green River basin. The field is confined by the intersection of two subvertical shear fault zones that form a wedge-shaped structural block. The updip termination at the southwest end of the field is the apex of the block. The downdip limit is somewhat arbitrarily defined as occurring along the synclinal axis separating the basin flank from the Pinedale anticline to the northeast. Within the wedge-shaped block, overpressure conditions exist near the top of the Upper Cretaceous (Maastrichtian) Lance Formation, 2000–3000 ft (610–915 m) above regional occurrence. Immediately to the west and south of the field, overpressure conditions are present near the top of the Upper Cretaceous (Campanian) Mesaverde Group. The trap at Jonah is described as combination structural-stratigraphic. The bounding fault zones form the lateral trap, and the top seal is comprised of the mudstones that are intercalated with the reservoir sandstones of the Lance. Sandstones in the Lance Formation are the principal reservoir at Jonah field. The Lance Formation is comprised of braided to meandering fluvial sandstones intercalated with overbank siltstones and mudstones. Similar sandstone facies in the upper Mesaverde Group are locally productive. The gross thickness of the Lance Formation increases toward the downdip limit of the field. Near the updip termination, the Lance is 2000 ft (610 m) thick, whereas at the northeastern side of the field, it attains a thickness in excess of 3000 ft (915 m). Overpressure increases storage capacity and gas saturation in the reservoir and allows for subtle preservation of better porosity relative to sandstones outside the field boundary. Original gas in place in the Lance Formation is estimated to be more than 8.3 tcf. Subcompartments formed by faults inside the field exhibit better per-well recovery near their updip edge; poorer performance is present in downdip regions of each compartment. Pore pressure in each compartment increases by about 1 psi/ft of depth or more than twice the normal hydrostatic gradient. Pressure data suggest that migration of hydrocarbons into the Jonah field compartment is occurring currently. Liquid condensate yield from the gas production increases with depth. Despite high pressures, production from the deepest sandstones tends to be poor because of low permeability and the impact of hydrocarbon liquids on relative permeability. The lenticular nature of the fluvial sandstones in the Lance has created highly complex reservoir architecture and is a significant challenge to the gas-recovery process. Connectivity is poor, as indicated by the difficulty in correlation of individual sand bodies between wellbores positioned on 40-ac (16-ha) spacing.

Abstract Jonah field, Wyoming’s second largest gas producer, is a structurally controlled trap located in the northwestern part of the Green River basin. Gas and condensate are produced from innumerable latest Cretaceous and early Tertiary overpressured tight-gas sandstones at depths of 7300–12,800 ft (2200–3900 m). Jonah field is remarkable for many reasons, including the large per-well reserves (relative to other tight-gas reservoirs), hundreds of feet of net pay, and a gross producing interval as great as 4000 ft (1220 m) thick. These superlative production characteristics exist, despite the fact that the structural trap is subtle and locally cryptic. Advanced seismic techniques define the Jonah trap boundaries and add value when they are used to position wells in proximity to the faults and on subtle structures. One of the main seismic techniques is a three-dimensional, broadband, amplitude-based coherency algorithm that has edge-detection capabilities. This algorithm analyzes the reflector amplitude gradient and records the lateral change in amplitude with azimuthal angle, which allows the interpreter to illuminate a particular feature from the optimal angle to reveal the maximum detail in the data. Gas entrapment at Jonah field is enabled by two bounding faults. Fault throw is variable but commonly less than 200 ft (60 m), and the major faults are nearly vertical. Two field-bounding fault zones, the west fault and south Jonah fault, intersect updip toward the southwest to create the overall wedge-shaped trap. The updip edge of a tilted fault block underlies the prolific Stud Horse Butte anticline and the Cabrito nose trends. The principal in-field faults terminate at the south Jonah fault to form four compartments, each comprised of a northeast-plunging, faulted nose or homocline bounded on the west and south by faults. The Jonah faults juxtapose high- and low-reserve wells; high-reserve wells are concentrated on the east side of the north- and northeast-trending faults, regardless of their sense of displacement. The south Jonah fault is probably a left-lateral, wrench-fault zone. The south Jonah fault was active concurrently with Lance Formation deposition, resulting in thicker Lance north of the fault in the center of the field and thin along the updip edge of the tilted block. Subsequent post-Paleocene motion on the fault caused formation of the Stud Horse Butte anticline, which is evident in the basal Tertiary strata. Jonah is a multipay field with numerous productive lenticular, fluvial sandstones. Whereas local structural features control the Jonah trap, regional structural elements shaped the fluvial system that deposited the reservoir sandstones. Regional structural features also affected the burial history that resulted in petroleum generation. Gas isotope composition and the thermal maturity of the producing strata indicate that the field produces hydrocarbons formed in deeper strata. The gas field shows evidence of paleostructural growth, which, in combination with the production pattern along the faults and the ‘‘bottoms-up’’ origin of the gas, may explain the enigmatic charging of these low-permeability sandstone bodies according to structural position, i.e., segregation by buoyancy. In this scenario, gas emplacement occurred before the reduction of sandstone permeability to the present condition.

Abstract The hydrocarbon accumulation at Jonah field is the result of a complex series of temporal and spatial geologic events. This chapter is a preliminary investigation using burial-history modeling and petroleum-systems analysis to evaluate the generative potential of source rocks in the Jonah and Pinedale anticline areas and determine the timing of generation and expulsion. To test the ability of the Lance to self-generate significant hydrocarbons through thermal maturation, burial-history models were constructed with source intervals containing type III kerogen and average initial total organic carbon values ranging from 1.00 to 1.25%. Models built using optimistic charge parameters show that in the Jonah area, the Lance is capable of generating 1.79 tcf gas and, depending on the saturation threshold applied, can only expel from 0 to 0.64 tcf gas. Source rock pyrolysis data indicate that the Lance does not contain sufficient organic material, and burial-history models calibrated with vitrinite reflectance data suggest that potential Lance source material was not exposed to the thermal conditions necessary to generate and expel the quantities of hydrocarbons estimated to be present in the Jonah trap. Generation, expulsion, and migration (vertical and/or horizontal) from the Mesaverde Group and Rock Springs Formation or deeper hydrocarbon sources such as the Mowry Shale are necessary to account for the in-place hydrocarbons. The source potential of the coal-bearing lower Mesaverde is significantly greater that that of the Lance, and modeling suggests that in the Jonah area, it is capable of generating 5.48 tcf and expelling 4.06–5.12 tcf gas. Modeling suggests that within the Jonah field area, the source rocks included in the Lance, upper Mesa-verde, and lower Mesaverde formations can only provide the Jonah trap with between 2.61 and 3.98 tcf gas in place. This gas volume is significantly less than current in-place estimates of 8.3 tcf and suggests that gas must be generated and migrated from either deeper sources such as the Hilliard Shale or Mowry Shale and/or have migrated to the Jonah trap from a larger fetch area.

Abstract Prolific production at Jonah field and many other fields in the Green River basin is dependent on the presence of overpressure. In the Gulf Coast and other areas, plots of shale resistivity and shale sonic transit time versus depth have been used to identify overpressured zones. The same technique has been proposed to map overpressure compartments and their boundaries in the Rocky Mountain region using well logs or, alternatively, interval velocities determined from seismic data. At Jonah field, the top of the overpressure (determined by continuous gas flaring during drilling) correlates within a few hundred feet to a drop in shale resistivity and increase in shale transit time. However, studies of nearby wildcat wells and detailed cross sections through both overpressured and normally pressured wells show that the log anomalies extend significantly beyond the overpressured area. Velocity and resistivity changes in the area around Jonah tend to follow a stratigraphic boundary near the base of the Tertiary Fort Union Formation instead of tracking the top of the overpressured volume. Early studies of Jonah field considered the hydrocarbons in the field to be derived from vertical migration of gas from regional overpressure conditions 2000–3000 ft (610–915 m) deeper. The upward migration was presumed to be controlled by the presence of extensive microfractures that form a leakage chimney between large sealing faults. This study suggests that the log anomaly both within and surrounding Jonah provides an alternative interpretation. Until the middle Tertiary, overpressure conditions extended up to the base of the Fort Union and resulted in undercompaction of Cretaceous shales, as reflected by resistivity and velocity anomalies. Late Tertiary relative uplift initiated slow leakage of the overpressure conditions wherever the system was not tightly sealed. As a result, the top of the overpressure has been dropping with time over most of the northern Green River basin. The sonic and resistivity anomalies are irreversible, and the logs reveal the signature of the former overpressured and undercompacted conditions. Based on this new model, Jonah field represents a high remnant of the former regional top of overpressure instead of a leakage chimney from a deeper overpressured generation cell. If this model is correct, exploration methods should focus on the seal conditions that prevent leakage instead of fracture models that promote leakage.

Abstract The giant Jonah gas field, located in western Wyoming, is a gas chimney rooted in a regionally pervasive, direct-type, basin-centered gas accumulation (BCGA). The field is an excellent example of a structural sweet spot in a BCGA. Basin-centered gas systems (BCGSs), of which BCGAs are products, are potentially one of the more economically important, unconventional gas systems in the world; in the United States, they contribute as much as 17% of the total annual gas production. These regionally pervasive gas accumulations are different from conventional accumulations in several respects. The BCGAs associated with BCGSs are typically characterized by regionally pervasive reservoirs that are gas saturated, abnormally (high or low) pressured, commonly lack a downdip water contact, and have low-permeability reservoirs. The accumulations range from single, isolated reservoirs a few feet thick to multiple, stacked reservoirs several thousand feet thick. Two types of BCGSs are recognized: a direct type, characterized by having gas-prone source rocks, and an indirect type, characterized by having liquid-prone source rocks. During the burial and thermal histories of these systems, the source rock differences between the two types of BCGSs result in strikingly different characteristics. Based on these criteria, gas in the Jonah field is interpreted to have been sourced from gas-prone, type III kerogen and is therefore a direct type of BCGA.

Abstract The Lance Formation at Jonah field comprises a thick succession, locally more than 3500 ft (1100 m), of low-permeability, fine-grained alluvial sandstones. These alluvial sandstones were deposited by modest rivers in a rapidly subsiding basin in the northern portion of the Greater Green River basin of southwest Wyoming. Stacking of these alluvial sand bodies has produced an extremely heterogeneous reservoir in which reservoir sand bodies are from 9 to 15 ft thick (3 to 5 m) and approximately 200–700 ft wide (60–210 m P 50 values). Because of the low net/gross of the overall Lance Formation (10–35% overall, 40–80% locally) and the comparatively small sand bodies, it is most likely that wells drilled on 40-ac (0.16-km 2 ) density (1320 ft [402 m] closest spacing between wells) will result in more than 75% reservoir additions and less than 25% rate acceleration. It is also quite likely that wells drilled on increased density, less than 40 ac (0.16 km 2 ), will result in significant reserve additions as well. Because the Lance Formation at Jonah field is dominated by intercalated, relatively thin alluvial sand bodies and alluvial-plain deposits, much of the reservoir-bearing interval is at or below seismic tuning. As a result, despite the presence of a high-quality, three-dimensional seismic survey, the reservoir cannot be consistently imaged or described from seismic data. In this chapter, a description of the reservoir at Jonah field is developed based on a sedimentological description of the available cores and the integration of well-log data. These data are then used to develop quantitative estimates of the sizes of fluvial systems that resulted in the sand bodies found in Jonah field as well as estimates of the lateral extents of the sand bodies themselves. Traditional techniques for estimating sand body geometry are compared with a probabilistic approach based on numerous analog sand body studies. For subsurface decision making, a probabilistic approach more accurately captures the range of likely outcomes than the more traditional approach of attempting to derive single-point estimates of fluvial dimensions.

Abstract The American Hunter Old Road unit 1 was drilled to test multiple, stacked sandstones in lower Tertiary and Upper Cretaceous sandstones but was completed in 1981 as a water well producing from a shallow aquifer. Poor fluid recoveries from a drillstem test in the middle Lance Formation indicated a low-permeability reservoir with probable formation damage. Two cores, totaling 106 ft (32 m), were cut in the middle and lower Lance Formation. The cored intervals consist of thin- to medium-bedded, fine- to medium-grained sandstone and chert pebble conglomerate interbedded with silty mudstone and shale. Conglomeratic beds are cross-bedded and massive to normally and inverse graded. Sandstones are trough cross-bedded, massive and ripple laminated, and locally root mottled. Mudstones are rooted and burrowed. Conglomerate and sandstone were deposited in fining-upward genetic units by small meandering rivers. Mudstones were deposited in flood plain, swamp, lacustrine, and brackish to normal marine environments. Sandstones consist of sublithic to lithic arenite and are cemented by moderate amounts of mixed-layer illite-smectite and quartz, sparse siderite, pyrite, ferroan calcite, and kaolinite. Feldspars are very sparse. Rock fragments are dominated by chert, with sparse limestone, dolomite, shaly and silty mudstone, reworked glau-conite, and phosphate grains. Porosity consists of moderate to sparse, modified primary intergranular, clay-lined and clay-filled intergranular, secondary intergranular and grain-moldic pores, and natural fractures. Most natural fractures are filled by kaolinite but retain some permeability. Core-measured in-situ porosities range from 4 to 13%. In-situ Klinkenberg permeabilities range from 0.001 to 2.66 md. ‘‘Irreducible’’ water saturations, representing water saturations at gas column heights of approximately 750 ft (230 m), range from 21 to 72%, in close agreement with log-derived data, indicating that most of the potential reservoir sandstones are at or near irreducible water saturation. Relative gas permeability at irreducible water saturation ranges from 46 to 99% of the absolute permeability. Common clay-filled microporosity is responsible for low measured permeability, relatively high values of irreducible water saturation, and moderate susceptibility to formation damage.

Abstract Jonah field is a giant gas field producing from extremely low-porosity and low-permeability sandstones. Wire-line–log data from 62 wells near the center of the field were studied to characterize the porosity, permeability, and water saturation of the Lance 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. Ultimate gas recovery per well was estimated by decline curve analysis of monthly production data. Within the upper 2500 ft (760 m) of the Lance Formation, which includes the entire productive interval in nearly all wells, the average well has 1000 ft (30 m) of net sandstone, having an average porosity of 6.4%. The average permeability of all sandstones, estimated from core data-derived equations, is an astonishingly low 6 μd. The average water saturation of all sandstones is 45%. Net pay criteria were determined from cumulative storage-capacity and cumulative flow-capacity plots. Although the average sandstone may have only 6% porosity, the low-porosity sandstones contribute an insignificant fraction of the reservoir flow capacity. We estimate that more than 95% of the flow capacity is from sandstones with greater than 6% porosity. A small percentage of high-porosity (>10%) and high-permeability rocks dominate the flow behavior of the reservoir and are probably critical to economic production. Using 6% porosity as an absolute net pay cutoff, the average net pay thickness at Jonah is 440 ft (130 m), with 9.3% porosity and 33% water saturation. The estimated average permeability of net pay is 25μd. Estimated ultimate recovery per well is approximately 4 bcf gas on current 40-ac (0.16-km 2 ) well spacing.

Abstract The southwest corner of Jonah field was targeted by Cabot Oil and Gas Corporation for an exploration program to extend the limits of established production. A reprocessed aeromagnetic survey was initially used as a cost-effective method to image this area (the Yellow Point area). However, the aeromagnetic survey did not provide the necessary resolution to convince Cabot to drill a well on their acreage. Subsequently, Cabot acquired a 16.1-mi 2 (42-km 2 ) high-resolution, three-dimensional (3-D) survey to evaluate their acreage and define the southwestern intersection of the two faults that form the trap at Jonah field. The Yellow Point area of Jonah field is a region of complex, structural relationships and outstanding gas production. Cabot used the high-quality, 3-D seismic data in combination with available well control and aeromagnetic data to delineate the updip structural limits of Jonah field. Based on this study, a high-risk, high-reward prospect was identified as a southern extension of the Yellow Point area. A wildcat well was drilled on this high-potential prospect with negative results. The wildcat well encountered a normally pressured Lance section outside of the main Jonah fault block.

Abstract The past decade has witnessed many changes in hydraulic fracture-stimulation technology and completion operation techniques used in the development of low-permeability reservoirs. Most of these changes have been effective in improving our ability to economically extract hydrocarbons from these unconventional reservoirs. By reviewing the stimulation and completion techniques used in Jonah field over the past decade, a best-practice methodology has emerged of how to treat these low-permeability gas reservoirs from both a hydraulic fracture-stimulation view and a completion practice perspective to identify damage mechanisms and to maximize productivity. The methods discussed here can be applied to low-permeability reservoirs in other basins. However, the techniques discussed here are evolutionary and will one day become dated as new innovations are developed. The Lance Formation in Jonah field consists of several hundred feet of stacked, lenticular sandstones with reservoir permeability to gas ranging from 1 to 20 μd. The completion of multiple sandstone packages requires 5 – 12 stages of hydraulic fracturing. Spatial sampling and artificial neural networks, guided by an understanding of the reservoir, were used to compare specific stimulation types and completion practices in a well to its immediate offsets. The results suggest the following best practices: (1) Never shut a well or a fracture stage in for extended periods of time. (2) Never kill a well or fracture stage with fluid once the hydraulic fracture treatment is cleaned up. (3) Use composite flowthrough fracture plugs instead of bridge plugs to isolate fracture stages. (4) Fracture stages should be no longer than 350 ft (110 m). (5) There should be no more than five entry points per fracture stage. (6) Completion fluid should be near neutral pH and low gel loading. (7) The stimulation treatment size should be based on the amount of net pay determined from wire-line logs.

Abstract Gas production in Jonah field is derived from more than 100 lenticular sandstone units that are interbedded with mudstones and siltstones over a 3000-ft (900-m) section of the Cretaceous Lance Formation. Productive sandstones average 12 ft (3.7 m) thick and are dispersed unevenly throughout the stratigraphic section. Historically, completion methods in Jonah have been costly and inefficient. Efforts to reduce completion costs while maintaining reserves in Jonah field required a new approach in evaluating and completing such thick productive zones. Analysis of fracture-simulation results for selected wells in the field suggests that stimulation of smaller, selected intervals would result in enhanced recovery by exploiting previously bypassed sandstone intervals. To obtain an optimal fracture-stimulation design, an enhanced petrophysical model was developed to provide reliable permeability, mechanical rock properties, fluid saturation, net pay, and net stress predictions. To further optimize the fracture stimulation, induced stress diversion was implemented. Induced stress diversion is a new technology that allows for multiple-stage stimulation without the use of a plug or mechanical device between stages. Using induced stress diversion, completion time was reduced by 4 weeks, and the percentage of producing sandstones in a treated interval increased from 60 to 90%. The net result was a 40% reduction in time and costs without negative impact on reserves. These optimization methods reduced development costs in Jonah field by 22%, from $2.8 million to $2.2 million per well, while achieving similar production and reserves.

Abstract Jonah field and the area around it have been the subject of an immense amount of environmental study since the field was discovered. Between 1993 and 2001, the Bureau of Land Management (BLM) completed one Environmental Impact Statement (EIS) and four Environmental Assessments (EAs) (Figure 1 ). In addition, another EIS for downspacing in Jonah field is currently in preparation by the BLM. Before any surface disturbance is authorized, each project component is also subject to an additional, site-specific EA prior to final site approval and construction. Each of these studies was conducted to comply with the requirements of the National Environmental Policy Act (NEPA), passed by Congress in 1969. NEPA-mandated environmental impact analysis and assessment is a discovery function for ascertaining the range of risks and benefits of proposed actions on public lands. Where practicable and technically feasible, the resulting decision recommends and requires various mitigation measures and alternatives designed to reduce project impacts. The NEPA was also written as a means to require the various agencies in the federal government to include the public in identifying issues and concerns and to disclose the estimated impacts of the proposed action under consideration.

Abstract The discovery of a giant natural gas field within a mature petroleum province is a significant event. Understanding the factors that control such an accumulation is important if the oil and gas industry is to continue to develop natural gas resources. Jonah field, in the Greater Green River basin of southwest Wyoming, is the largest natural gas discovery in the onshore United States in the last 10-15 years with recoverable reserves ranging from 8 to 15 tcf natural gas. Since beginning widespread field development in August 1992, Jonah has produced approximately 1 tcf gas, 10.3 million barrels of oil, and 3.7 million barrels of water. Field production is still increasing with daily production presently at 666 MMCFGPD, 5800 BOPD, and 4000 BWPD from approximately 600 wells. Active drilling continues within the field as operators consider widespread downspacing. By virtue of being a tight-gas field, Jonah is, in many respects, nontraditional. Recent assessments of natural gas potential, for both the U.S. and the world, strongly suggest that most future gas resources will come from low-permeability sandstones in the deeper portions of sedimentary basins, and from fields that will undoubtedly share characteristics with Jonah. The subtle structure, the low-permeability nature of the reservoir, the challenging petrophysics, and the environmental sensitivity surrounding Jonah may foreshadow what explorationists have to look forward to as the demand for natural gas increases, not only in the United States, but throughout the world. This volume brings together previously unpublished material on Jonah field and attempts to integrate all aspects including geology, geophysics, reservoir engineering, drilling and completion, and regulatory affairs. As such, this is a definitive collection that provides a truly integrated perspective of this giant field.