Changes

All basin-centered gas accumulations (BCGAs) reservoirs require carefully designed drilling programs and some type of artificial stimulation for commercial production rates. Reservoir continuity is an important consideration in the design of an appropriate drilling and completion program. Single, lenticular reservoirs have limited volume and are generally not commercial, whereas single, blanket reservoirs have much larger volumes and may be commercial, but, because blanket reservoirs commonly have better reservoir quality than lenticular reservoirs, they may be water bearing, as discussed previously.

All basin-centered gas accumulations (BCGAs) reservoirs require carefully designed drilling programs and some type of artificial stimulation for commercial production rates. Reservoir continuity is an important consideration in the design of an appropriate drilling and completion program. Single, lenticular reservoirs have limited volume and are generally not commercial, whereas single, blanket reservoirs have much larger volumes and may be commercial, but, because blanket reservoirs commonly have better reservoir quality than lenticular reservoirs, they may be water bearing, as discussed previously.

In lenticular, fluvial-dominated reservoirs, such as those in the Jonah field in the northern part of the Green River basin of Wyoming or the Rulison field in the Piceance basin of Colorado, it is imperative to stimulate as many reservoirs as possible to attain commercial rates of gas production. The completion practices in the Jonah field provide a good example of commingling production from multiple, lenticular reservoirs;<ref name=Finchetal_1997>Finch, R. W., W. W. Aud, and J. W. Robinson, 1997, Evolution of completion and fracture-stimulation practices in Jonah field, Sublett County, Wyoming, ''in'' E. B. Coalson, J. C. Osmond, and E. T. Williams, eds., Innovative applications of petroleum technology in the Rocky Mountain area: Rocky Mountain Association of Geologists, p. 13-24.</ref> <ref name=Eberhard_2001>Eberhard, M. J., 2001, The effect that stimulation methodologies ha(ve) on production in the Jonah field, ''in'' J. W. Robinson and K. W. Shanley, eds., Tight gas fluvial reservoirs: A case history from the Lance Formation, Green River basin, Wyoming: Rocky Mountain Association of Geologists Short Course Notes 2, unpaginated.</ref> as many as 28 sandstones are perforated and fractured.<ref name=Montgomeryandrobinson_1997>Montgomery, S. L., and J. W. Robinson, 1997, [http://archives.datapages.com/data/bulletns/1997/07jul/1049/1049.htm Jonah field, Sublette County, Wyoming: Gas production from overpressured Upper Cretaceous Lance sandstones of the Green River basin]: AAPG Bulletin, v. 81, p. 1049-1062.</ref> In a similar manner, gas production from multiple sandstone reservoirs in the Upper Cretaceous Williams Fork Formation in the Piceance basin of western Colorado is commingled following multiple fracture treatments in an interval about 2400 ft (732 m) thick (R. E. Mueller, 2002, personal communication).

In lenticular, fluvial-dominated reservoirs, such as those in the Jonah field in the northern part of the Green River basin of Wyoming or the Rulison field in the Piceance basin of Colorado, it is imperative to stimulate as many reservoirs as possible to attain commercial rates of gas production. The completion practices in the Jonah field provide a good example of commingling production from multiple, lenticular reservoirs;<ref name=Finchetal_1997>Finch, R. W., W. W. Aud, and J. W. Robinson, 1997, Evolution of completion and fracture-stimulation practices in Jonah field, Sublett County, Wyoming, ''in'' E. B. Coalson, J. C. Osmond, and E. T. Williams, eds., Innovative applications of petroleum technology in the Rocky Mountain area: Rocky Mountain Association of Geologists, p. 13-24.</ref> <ref name=Eberhard_2001>Eberhard, M. J., 2001, The effect that stimulation methodologies ha(ve) on production in the Jonah field, ''in'' J. W. Robinson and K. W. Shanley, eds., Tight gas fluvial reservoirs: A case history from the Lance Formation, Green River basin, Wyoming: Rocky Mountain Association of Geologists Short Course Notes 2, unpaginated.</ref> as many as 28 sandstones are perforated and [[fracture]]d.<ref name=Montgomeryandrobinson_1997>Montgomery, S. L., and J. W. Robinson, 1997, [http://archives.datapages.com/data/bulletns/1997/07jul/1049/1049.htm Jonah field, Sublette County, Wyoming: Gas production from overpressured Upper Cretaceous Lance sandstones of the Green River basin]: AAPG Bulletin, v. 81, p. 1049-1062.</ref> In a similar manner, gas production from multiple sandstone reservoirs in the Upper Cretaceous Williams Fork Formation in the Piceance basin of western Colorado is commingled following multiple fracture treatments in an interval about 2400 ft (732 m) thick (R. E. Mueller, 2002, personal communication).

Early attempts to produce from blanket reservoirs were mixed. Massive hydraulic fracturing techniques using 300,000 lb of proppant were used in an attempt to create long fractures. However, the large fracture treatments commonly resulted in shorter fracture lengths than predicted because of fracturing out of the reservoir into adjacent, nonreservoir rocks.<ref name=Spencer_1989a>Spencer, C. W., 1989, [http://archives.datapages.com/data/bulletns/1988-89/data/pg/0073/0005/0600/0613.htm Review of characteristics of low-permeability gas reservoirs in western United States]: AAPG Bulletin, v. 73, p. 613-629.</ref> This problem has, in some cases, been modified by adjusting pumping rates of the fracture fluids.

Early attempts to produce from blanket reservoirs were mixed. Massive hydraulic fracturing techniques using 300,000 lb of proppant were used in an attempt to create long fractures. However, the large fracture treatments commonly resulted in shorter fracture lengths than predicted because of fracturing out of the reservoir into adjacent, nonreservoir rocks.<ref name=Spencer_1989a>Spencer, C. W., 1989, [http://archives.datapages.com/data/bulletns/1988-89/data/pg/0073/0005/0600/0613.htm Review of characteristics of low-permeability gas reservoirs in western United States]: AAPG Bulletin, v. 73, p. 613-629.</ref> This problem has, in some cases, been modified by adjusting pumping rates of the fracture fluids.

Natural fractures are important factors in successfully completing a well. The probability of a vertically drilled hole intersecting fractures is considerably less than horizontal or slant holes. For example, at the U.S. Department of Energy Multiwell Experiment site in the Piceance basin of Colorado, a slant hole was drilled through lenticular gas reservoirs. The hole was then deviated to horizontal in a blanket reservoir. Fifty-two fractures were reported from 266 ft (81 m) of core taken from the slant hole part of the hole. In contrast, a nearby vertically drilled hole penetrating the same slant hole interval encountered one fracture, and, in the horizontally drilled part of the hole, 37 fractures were reported from 115 ft (35 m) of core.<ref name=Lorenzandhill_1991>Lorenz, J. C., and R. E. Hill, 1991, Subsurface fracture spacing: Comparison of inferences from slant/horizontal core and vertical core in Mesaverde reservoirs, ''in'' Rocky Mountain regional/low permeability reservoirs symposium: Society of Petroleum Engineers, p. 705-716.</ref> In a more recently drilled 14,950 ft (4557 m)-deep well in the Green River basin of Wyoming, more than 400 open fractures were detected on a Formation MicroImager log from a 1750 ft (533 m)-long horizontally drilled leg in the Upper Cretaceous Frontier Formation.<ref name=Krystinikandlorenz_2000>Krystinik, L. F., and J. C. Lorenz, 2000, Do you want the good news or the bad news? . . . New perspectives on basin-centered gas from horizontal drilling, Frontier Formation, SW Wyoming, ''in'' 2000 basin-centered gas symposium: Rocky Mountain Association of Geologists, unpaginated.</ref> In the same well, approximately 76 natural fractures were recorded from a 78.2 ft (23.8 m)-long core taken from the same horizontal leg.<ref name=Lorenzandmroz_1999>Lorenz, J. C., and T. H. Mroz, 1999, Natural fracturing in horizontal core near a fault zone: The Rock Island Unit 4-H well, Green River basin, Wyoming: Integrating geoscience and engineering data to characterize and exploit tight gas sand sweet spots: Gas Research Institute, GRI 99/0068, 81 p.</ref> From these two examples, the probability of encountering fractures in slant or horizontal wells vs. vertically drilled wells is well documented. The cost of drilling nonvertical wells, however, is considerably greater than the cost of drilling vertical wells.

Natural fractures are important factors in successfully completing a well. The probability of a vertically drilled hole intersecting fractures is considerably less than horizontal or slant holes. For example, at the U.S. Department of Energy Multiwell Experiment site in the Piceance basin of Colorado, a slant hole was drilled through lenticular gas reservoirs. The hole was then deviated to horizontal in a blanket reservoir. Fifty-two fractures were reported from 266 ft (81 m) of core taken from the slant hole part of the hole. In contrast, a nearby vertically drilled hole penetrating the same slant hole interval encountered one fracture, and, in the horizontally drilled part of the hole, 37 fractures were reported from 115 ft (35 m) of core.<ref name=Lorenzandhill_1991>Lorenz, J. C., and R. E. Hill, 1991, Subsurface fracture spacing: Comparison of inferences from slant/horizontal core and vertical core in Mesaverde reservoirs, ''in'' Rocky Mountain regional/low permeability reservoirs symposium: Society of Petroleum Engineers, p. 705-716.</ref> In a more recently drilled 14,950 ft (4557 m)-deep well in the Green River basin of Wyoming, more than 400 open fractures were detected on a Formation MicroImager log from a 1750 ft (533 m)-long horizontally drilled leg in the Upper Cretaceous Frontier Formation.<ref name=Krystinikandlorenz_2000>Krystinik, L. F., and J. C. Lorenz, 2000, Do you want the good news or the bad news? . . . New perspectives on basin-centered gas from horizontal drilling, Frontier Formation, SW Wyoming, ''in'' 2000 basin-centered gas symposium: Rocky Mountain Association of Geologists, unpaginated.</ref> In the same well, approximately 76 natural fractures were recorded from a 78.2 ft (23.8 m)-long core taken from the same horizontal leg.<ref name=Lorenzandmroz_1999>Lorenz, J. C., and T. H. Mroz, 1999, Natural fracturing in horizontal core near a fault zone: The Rock Island Unit 4-H well, Green River basin, Wyoming: Integrating geoscience and engineering data to characterize and exploit tight gas sand sweet spots: Gas Research Institute, GRI 99/0068, 81 p.</ref> From these two examples, the probability of encountering fractures in slant or horizontal wells vs. vertically drilled wells is well documented. The cost of drilling nonvertical wells, however, is considerably greater than the cost of drilling vertical wells.

Reservoir damage is another important aspect of formation evaluation. Spencer<ref name=Spencer_1985>Spencer, C. W., 1985, Geologic aspects of tight gas reservoirs in the Rocky Mountain region: Journal of Petroleum Geology, p. 1308-1314.</ref> listed several different types of reservoir damage, including (1) movement of secondary clays causing plugging of pore throats, (2) swelling of smectitic clays, (3) increasing water saturation with consequent reduction of relative permeability to gas, (4) fracturing gel compounds left in the reservoir, and (5) chemical additives causing precipitation of minerals and compounds during acidizing and hydraulic fracturing. The potential problem of swelling clays, in most cases, is minor, because most BCGAs occur in sequences where the level of thermal maturation is sufficiently high to convert swelling clays into nonswelling clays.

Reservoir damage is another important aspect of formation evaluation. Spencer<ref name=Spencer_1985>Spencer, C. W., 1985, Geologic aspects of tight gas reservoirs in the Rocky Mountain region: Journal of Petroleum Geology, p. 1308-1314.</ref> listed several different types of reservoir damage, including (1) movement of secondary clays causing plugging of pore throats, (2) swelling of smectitic clays, (3) increasing water saturation with consequent reduction of relative permeability to gas, (4) fracturing gel compounds left in the reservoir, and (5) chemical additives causing precipitation of minerals and compounds during acidizing and hydraulic fracturing. The potential problem of swelling clays, in most cases, is minor, because most BCGAs occur in sequences where the level of thermal [[maturation]] is sufficiently high to convert swelling clays into nonswelling clays.

==Exploration strategy==

==Exploration strategy==

The objective of any hydrocarbon exploration program is to progress from coarse, loosely defined ideas to refined, drillable locations. In the case of BCGAs, exploration strategies are no different and may be viewed as a four-step process that includes (1) reconnaissance, (2) confirmation, (3) delineation, and (4) sweet spot identification. The exploration phases are mostly applicable to direct BCGAs; as a consequence of the relatively new classification of BCGAs into direct and indirect types, strategies for indirect BCGAs have not been formulated, although it is obvious that source rock considerations, level of thermal maturation, and temporal relationships among hydrocarbon generation, expulsion, migration, and trap formation are very important considerations in the exploration for indirect BCGAs.

The objective of any hydrocarbon exploration program is to progress from coarse, loosely defined ideas to refined, drillable locations. In the case of BCGAs, exploration strategies are no different and may be viewed as a four-step process that includes (1) reconnaissance, (2) confirmation, (3) delineation, and (4) sweet spot identification. The exploration phases are mostly applicable to direct BCGAs; as a consequence of the relatively new classification of BCGAs into direct and indirect types, strategies for indirect BCGAs have not been formulated, although it is obvious that source rock considerations, level of [[thermal maturation]], and temporal relationships among hydrocarbon generation, expulsion, migration, and trap formation are very important considerations in the exploration for indirect BCGAs.

===Reconnaissance phase===

===Reconnaissance phase===

The reconnaissance phase entails the identification of basins that may contain BCGAs. In direct systems, identification of source rocks is critical. For example, the identification of humic, gas-prone coal beds is the most obvious source rock for direct BCGAs; in nearly every country with coal reserves, there are some published data concerning geographic distribution, rank, and thickness. The rank of coal beds must be greater than high-volatile C (greater than vitrinite reflectance values of 0.6% R_o) to initiate thermal generation of gas.<ref name=Hunt_1996>Hunt, J. M., 1996, Petroleum geochemistry and geology, 2nd ed.: New York, W. H. Freeman and Co., 743 p.</ref>

The reconnaissance phase entails the identification of basins that may contain BCGAs. In direct systems, identification of source rocks is critical. For example, the identification of humic, gas-prone [[coal bed]]s is the most obvious source rock for direct BCGAs; in nearly every country with [[coal]] reserves, there are some published data concerning geographic distribution, rank, and thickness. The rank of coal beds must be greater than high-volatile C (greater than [[vitrinite reflectance]] values of 0.6% R_o) to initiate thermal generation of gas.<ref name=Hunt_1996>Hunt, J. M., 1996, Petroleum geochemistry and geology, 2nd ed.: New York, W. H. Freeman and Co., 743 p.</ref>

The existence of reservoirs with appropriate quality is another important aspect to consider during the reconnaissance phase. In most cases, coal-bearing intervals are associated with interbedded sandstones that have low porosity and permeability, especially at diagenetic stages commensurate with thermal maturity levels greater than 0.6% R_o. Sandstones deposited in alluvial plain, coal-bearing environments typically have poor reservoir properties. High porosity and permeability in reservoirs are not desirable attributes for the development of a BCGA. In basins where some drilling activity has occurred, gas shows are also very helpful.

The existence of reservoirs with appropriate quality is another important aspect to consider during the reconnaissance phase. In most cases, coal-bearing intervals are associated with interbedded sandstones that have low porosity and permeability, especially at diagenetic stages commensurate with thermal maturity levels greater than 0.6% R_o. Sandstones deposited in [[alluvial]] plain, coal-bearing environments typically have poor reservoir properties. High porosity and permeability in reservoirs are not desirable attributes for the development of a BCGA. In basins where some drilling activity has occurred, gas shows are also very helpful.

===Confirmation phase===

===Confirmation phase===

|+ {{table number|1}}Attributes of direct and indirect basin-centered gas systems

|+ {{table number|1}}Attributes of direct and indirect basin-centered gas systems

|-

|-

! Type || Source rocks || Reservoir in-situ permeability (md) || Hydrocarbon migration distance || Reservoir pressure || Pressure mechanism || Seal || Seal quality || Nature of upper boundary || Thermal maturity top of BCGA || Occurrence

! Type || Source rocks || Reservoir in-situ permeability (md) || [[Hydrocarbon migration]] distance || Reservoir pressure || Pressure mechanism || Seal || Seal quality || Nature of upper boundary || Thermal maturity top of BCGA || Occurrence

|-

|-

| Direct || gas-prone type III kerogen || <0.1 || short || over-/underpressure || hydrocarbon generation || capillary || variable || cuts across stratigraphy || >0.7% R_o || downdip from water

| Direct || gas-prone type III [[kerogen]] || <0.1 || short || over-/underpressure || hydrocarbon generation || capillary || variable || cuts across stratigraphy || >0.7% R_o || downdip from water

|-

|-

| Indirect || liquid-prone types I/II kerogen || <0.1 || short/long || over-/underpressure || thermal cracking of oil to gas || lithologic/capillary || good || bedding parallel || highly variable || downdip from water

| Indirect || liquid-prone types I/II kerogen || <0.1 || short/long || over-/underpressure || thermal [[cracking]] of oil to gas || lithologic/capillary || good || bedding parallel || highly variable || downdip from water

|}

|}

[[File:BasinCenteredGasFig6.jpg|thumb|300px|{{figure number|1}}Cross section BB' showing spatial distribution of BCGA superimposed on structure through the Washakie basin (modified from Law et al.<ref name=Lawetal_1989 />). Shaded pattern shows overpressured, gas-saturated BCGA. Location of cross section shown on Figure 2.]]

[[File:BasinCenteredGasFig6.jpg|thumb|300px|{{figure number|1}}Cross section BB' showing spatial distribution of BCGA superimposed on structure through the Washakie basin (modified from Law et al.<ref name=Lawetal_1989 />). Shaded pattern shows overpressured, gas-saturated BCGA. Location of cross section shown on Figure 2.]]

In [[:file:BasinCenteredGasFig6.jpg|Figure 1,]] the top of overpressure and BCGA in the Washakie basin is shown as a fairly smooth, uniform line cutting across structural and stratigraphic boundaries. In this case, if very closely spaced pressure data were available along the line of section, the pressure boundary would most likely not be as smooth as shown but would probably be highly irregular, with significant areas of high relief. The areas of high, positive relief, or bumps, may be indicative of structural and/or stratigraphic sweet spots that occur at or near the upper boundary of the BCGA. In the absence of closely spaced pressure data, it is difficult to identify a sweet spot. However, some techniques can be used to identify and focus more expensive techniques such as three-dimensional (3-D) seismic surveys. Those techniques may include lineament, thermal maturity, and present-day temperature mapping. Aeromagnetic, gravity, and surface geochemical surveys also may be useful in the identification of potential sweet spots. Surdam<ref name=Surdam_1997 /> and Surdam et al.<ref name=Surdametal_1997 /> described methods employing sonic logs to identify sweet spots in several basins in Wyoming.

In [[:file:BasinCenteredGasFig6.jpg|Figure 1,]] the top of overpressure and BCGA in the Washakie basin is shown as a fairly smooth, uniform line cutting across structural and stratigraphic boundaries. In this case, if very closely spaced pressure data were available along the line of section, the pressure boundary would most likely not be as smooth as shown but would probably be highly irregular, with significant areas of high relief. The areas of high, positive relief, or bumps, may be indicative of structural and/or stratigraphic sweet spots that occur at or near the upper boundary of the BCGA. In the absence of closely spaced pressure data, it is difficult to identify a sweet spot. However, some techniques can be used to identify and focus more expensive techniques such as three-dimensional (3-D) seismic surveys. Those techniques may include lineament, thermal maturity, and present-day temperature mapping. Aeromagnetic, [[gravity]], and surface geochemical surveys also may be useful in the identification of potential sweet spots. Surdam<ref name=Surdam_1997 /> and Surdam et al.<ref name=Surdametal_1997 /> described methods employing sonic logs to identify sweet spots in several basins in Wyoming.

[[file:BasinCenteredGasFig3.jpg|thumb|300px|{{figure number|2}}Map of the Greater Green River basin, showing major structural elements and the locations of the Jonah field, the Belco 3-28 Merna and El Paso Natural Gas 1 Wagon Wheel wells, and cross section BB'.]]

[[file:BasinCenteredGasFig3.jpg|thumb|300px|{{figure number|2}}Map of the Greater Green River basin, showing major structural elements and the locations of the Jonah field, the Belco 3-28 Merna and El Paso Natural Gas 1 Wagon Wheel wells, and cross section BB'.]]

The best example of a BCGA structural sweet spot is the Jonah field in the northern part of the Green River basin, Wyoming ([[:file:BasinCenteredGasFig3.jpg|Figure 2]], [[:file:BasinCenteredGasFig4.jpg|Figure 3]]). As previously discussed, the Jonah field is a gas chimney, rooted in a regionally pervasive BCGA described by Law (1984) and producing from multiple sandstone reservoirs in the Upper Cretaceous Lance Formation. Alternatively, Cluff and Cluff<ref name=Cluffandcluff_2001>Cluff, R. M., and S. G. Cluff, 2001, Overpressure determination from sonic and resistivity log anomalies, Jonah field, northern Green River basin, Wyoming, ''in'' J. W. Robinson and K. W. Shanley, eds., Tight gas fluvial reservoirs: A case study from the Lance Formation, Green River basin, Wyoming: RMAG Short Course Notes 2, unpaginated.</ref> have interpreted the Jonah field to be a remnant of a larger, much more shallow BCGA than presently identified. The Jonah field is a wedge-shaped area with the north, south, and west boundaries of the field defined by westward converging faults ([[:file:BasinCenteredGasFig4.jpg|Figure 3]]). The eastern boundary is undefined. The geologic characteristics of the Jonah field are given by Montgomery and Robinson<ref name=Montgomeryandrobinson_1997>Montgomery, S. L., and J. W. Robinson, 1997, [http://archives.datapages.com/data/bulletns/1997/07jul/1049/1049.htm Jonah field, Sublette County, Wyoming: Gas production from overpressured Upper Cretaceous Lance sandstones of the Green River basin]: AAPG Bulletin, v. 81, p. 1049-1062.</ref> and Warner.<ref name=Warner_1998>Warner, E. M., 1998, Structural geology and pressure compartmentalization of Jonah field, Sublette County, Wyoming, ''in'' R. M. Slatt, ed., Compartmentalized reservoirs in Rocky Mountain basins: Rocky Mountain Association of Geologists, p. 29-46.</ref> <ref name=Warner_2000>Warner, E. M., 2000, Structural geology and pressure compartmentalization of Jonah field based on 3-D seismic data and subsurface geology, Sublette County, Wyoming: The Mountain Geologist, v. 37, no. 1, p. 15-30.</ref> According to Warner<ref name=Warner_2000 /> the top of overpressure (top of gas-saturated reservoirs) within the field occurs at depths of 7700 ft (2347 m) at the west end of the field (updip end of field) and 9500 ft (2896 m) at the east end of the field (downdip end of the field). Outside the field, the top of overpressure and gas-saturated reservoirs occur at depths ranging from 11,200 to 11,600 ft (3414-3536 m).<ref name=Warner_2000 /> Thus, there is 2500-3000 ft (726-914 m) of relief on the top of overpressuring from outside the field to inside the field ([[:file:BasinCenteredGasFig4.jpg|Figure 3]]). The gas chimney has subsequently been identified through the use of sonic velocity data.<ref name=Surdametal_2001 />

The best example of a BCGA structural sweet spot is the Jonah field in the northern part of the Green River basin, Wyoming ([[:file:BasinCenteredGasFig3.jpg|Figure 2]], [[:file:BasinCenteredGasFig4.jpg|Figure 3]]). As previously discussed, the Jonah field is a gas chimney, rooted in a regionally pervasive BCGA described by Law (1984) and producing from multiple sandstone reservoirs in the Upper Cretaceous Lance Formation. Alternatively, Cluff and Cluff<ref name=Cluffandcluff_2001>Cluff, R. M., and S. G. Cluff, 2001, Overpressure determination from sonic and resistivity log anomalies, Jonah field, northern Green River basin, Wyoming, ''in'' J. W. Robinson and K. W. Shanley, eds., Tight gas fluvial reservoirs: A case study from the Lance Formation, Green River basin, Wyoming: RMAG Short Course Notes 2, unpaginated.</ref> have interpreted the Jonah field to be a remnant of a larger, much more shallow BCGA than presently identified. The Jonah field is a wedge-shaped area with the north, south, and west boundaries of the field defined by westward converging faults ([[:file:BasinCenteredGasFig4.jpg|Figure 3]]). The eastern boundary is undefined. The geologic characteristics of the Jonah field are given by Montgomery and Robinson<ref name=Montgomeryandrobinson_1997>Montgomery, S. L., and J. W. Robinson, 1997, [http://archives.datapages.com/data/bulletns/1997/07jul/1049/1049.htm Jonah field, Sublette County, Wyoming: Gas production from overpressured Upper Cretaceous Lance sandstones of the Green River basin]: AAPG Bulletin, v. 81, p. 1049-1062.</ref> and Warner.<ref name=Warner_1998>Warner, E. M., 1998, Structural geology and pressure compartmentalization of Jonah field, Sublette County, Wyoming, ''in'' R. M. Slatt, ed., Compartmentalized reservoirs in Rocky Mountain basins: Rocky Mountain Association of Geologists, p. 29-46.</ref> <ref name=Warner_2000>Warner, E. M., 2000, Structural geology and pressure compartmentalization of Jonah field based on 3-D seismic data and subsurface geology, Sublette County, Wyoming: The Mountain Geologist, v. 37, no. 1, p. 15-30.</ref> According to Warner<ref name=Warner_2000 /> the top of overpressure (top of gas-saturated reservoirs) within the field occurs at depths of 7700 ft (2347 m) at the west end of the field (updip end of field) and 9500 ft (2896 m) at the east end of the field (downdip end of the field). Outside the field, the top of overpressure and gas-saturated reservoirs occur at depths ranging from 11,200 to 11,600 ft (3414-3536 m).<ref name=Warner_2000 /> Thus, there is 2500-3000 ft (726-914 m) of relief on the top of overpressuring from outside the field to inside the field ([[:file:BasinCenteredGasFig4.jpg|Figure 3]]). The gas chimney has subsequently been identified through the use of sonic velocity data.<ref name=Surdametal_2001 />

[[File:BasinCenteredGasFig14.jpg|thumb|300px|{{figure number|4}}Thermal maturity map of the Denver basin, Colorado, showing the large thermal maturity anomaly in the Cretaceous Muddy ("J") Sandstone in the Wattenburg field (modified from Higley et al.<ref name=Higleyetal_1992 />). The field is nearly coincident with the 0.9% isoreflectance contour.<ref name=Higleyetal_1992 /> The location of the anomaly is also coincident with the basinward projection of the Colorado Mineral Belt (CMB).]]

[[File:BasinCenteredGasFig14.jpg|thumb|300px|{{figure number|4}}Thermal maturity map of the Denver basin, Colorado, showing the large thermal maturity anomaly in the Cretaceous Muddy ("J") Sandstone in the Wattenburg field (modified from Higley et al.<ref name=Higleyetal_1992 />). The field is nearly coincident with the 0.9% isoreflectance [[contour]].<ref name=Higleyetal_1992 /> The location of the anomaly is also coincident with the basinward projection of the Colorado Mineral Belt (CMB).]]

A good example of a thermal maturity anomaly associated with a sweet spot is the Lower Cretaceous Muddy ("J") Sandstone in the Denver basin of Colorado. Regional thermal maturity mapping in the Denver basin of Colorado<ref name=Higleyetal_1992>Higley, D. K., D. L. Gautier, and M. J. Pawlewicz, 1992, Influence of regional heat flow variation on thermal maturity of the Lower Cretaceous Muddy ("J") Sandstone, Denver basin, Colorado, ''in'' The petroleum system-status of research and methods, 1992: U.S. Geological Survey Bulletin 2007, p. 66-69.</ref> shows the presence of an anomaly associated with a BCGA ([[:file:BasinCenteredGasFig14.jpg|Figure 4]]). The anomaly, defined by reflectance values greater than 0.9% R_o, is nearly coincident with the field boundaries of production from the Muddy Sandstone in the Wattenburg field. The anomaly is located north of the structurally deepest part of the basin and is coincident with the northeast projection of the Colorado Mineral Belt. The field is also coincident with a temperature anomaly mapped by Meyer and McGee.<ref name=Meyerandmcgee_1985>Meyer, H. J., and H. W. McGee, 1985, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0069/0006/0900/0933.htm Oil and gas fields accompanied by geothermal anomalies in the Rocky Mountain region]: AAPG Bulletin, v. 69, p. 933-945.</ref>

A good example of a thermal maturity anomaly associated with a sweet spot is the Lower Cretaceous Muddy ("J") Sandstone in the Denver basin of Colorado. Regional thermal maturity mapping in the Denver basin of Colorado<ref name=Higleyetal_1992>Higley, D. K., D. L. Gautier, and M. J. Pawlewicz, 1992, Influence of regional heat flow variation on thermal maturity of the Lower Cretaceous Muddy ("J") Sandstone, Denver basin, Colorado, ''in'' The petroleum system-status of research and methods, 1992: U.S. Geological Survey Bulletin 2007, p. 66-69.</ref> shows the presence of an anomaly associated with a BCGA ([[:file:BasinCenteredGasFig14.jpg|Figure 4]]). The anomaly, defined by reflectance values greater than 0.9% R_o (for better understanding of reflectance values correlation you can look at [http://thetermpapers.net thetermpapers.net]), is nearly coincident with the field boundaries of production from the Muddy Sandstone in the Wattenburg field. The anomaly is located north of the structurally deepest part of the basin and is coincident with the northeast projection of the Colorado Mineral Belt. The field is also coincident with a temperature anomaly mapped by Meyer and McGee.<ref name=Meyerandmcgee_1985>Meyer, H. J., and H. W. McGee, 1985, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0069/0006/0900/0933.htm Oil and gas fields accompanied by geothermal anomalies in the Rocky Mountain region]: AAPG Bulletin, v. 69, p. 933-945.</ref>

Because the top of a BCGA is determined, in part, by permeability variations and the ease with which gas may move through reservoirs, measured levels of thermal maturity at the top of a BCGA may provide indirect evidence of the presence of a sweet spot; relatively low values of thermal maturity (<0.8% R_o) at the top of an overpressured BCGA are indicative of a potential sweet spot, whereas relatively high values of thermal maturity (>0.8% R_o) are indicative of very low permeability in an overpressured BCGA. Based on vitrinite reflectance profiles from two wells within the Jonah field,<ref name=Warner_1998 /> the level of thermal maturity at the top of overpressured, gas-saturated reservoirs is less than 0.7% R_o, compared to 0.8% R_o outside the field. Thermal maturity indices, however, cannot be used to identify potential sweet spots in underpressured BCGAs. The level of thermal maturity at the top of an underpressured BCGA most likely is higher than the level of thermal maturity at the top of an overpressured BCGA because the dimensions, or size, of a BCGA are reduced during the transition from overpressure to underpressure. Consequently, the level of thermal maturity at the top of an underpressured BCGA reflects that size constriction.

Because the top of a BCGA is determined, in part, by permeability variations and the ease with which gas may move through reservoirs, measured levels of thermal maturity at the top of a BCGA may provide indirect evidence of the presence of a sweet spot; relatively low values of thermal maturity (<0.8% R_o) at the top of an overpressured BCGA are indicative of a potential sweet spot, whereas relatively high values of thermal maturity (>0.8% R_o) are indicative of very low permeability in an overpressured BCGA. Based on vitrinite reflectance profiles from two wells within the Jonah field,<ref name=Warner_1998 /> the level of thermal maturity at the top of overpressured, gas-saturated reservoirs is less than 0.7% R_o, compared to 0.8% R_o outside the field. Thermal maturity indices, however, cannot be used to identify potential sweet spots in underpressured BCGAs. The level of thermal maturity at the top of an underpressured BCGA most likely is higher than the level of thermal maturity at the top of an overpressured BCGA because the dimensions, or size, of a BCGA are reduced during the transition from overpressure to underpressure. Consequently, the level of thermal maturity at the top of an underpressured BCGA reflects that size constriction.

* In many basins, BCGAs occur at depths greater than 10,000 ft (3048 m). Artificial stimulation at these depths is difficult and expensive. Although there have been significant improvements in drilling and completion technologies within the past 20 yr, continued advances in technologies are essential to tap the very large gas resources at these depths.

* In many basins, BCGAs occur at depths greater than 10,000 ft (3048 m). Artificial stimulation at these depths is difficult and expensive. Although there have been significant improvements in drilling and completion technologies within the past 20 yr, continued advances in technologies are essential to tap the very large gas resources at these depths.

* In thick, gas-saturated reservoirs containing interbedded water-bearing reservoirs, improved techniques are needed to discriminate between gas-bearing and water-bearing reservoirs.

* In thick, gas-saturated reservoirs containing interbedded water-bearing reservoirs, improved techniques are needed to discriminate between gas-bearing and water-bearing reservoirs.

* The integrity of capillary pressure seals over long periods of geologic time needs to be determined.

* The integrity of [[capillary pressure]] seals over long periods of geologic time needs to be determined.

* More geologic research into the occurrence of BCGAs, especially indirect types, is desirable. Essentially no information is available concerning the nature of or exploration strategies for indirect BCGAs.

* More geologic research into the occurrence of BCGAs, especially indirect types, is desirable. Essentially no information is available concerning the nature of or exploration strategies for indirect BCGAs.

* Methods of identifying and characterizing natural fractures must be improved.

* Methods of identifying and characterizing natural fractures must be improved.