Changes

The Appalachian Basin has a well-established history of shale-gas development (Figure 1). The discovery and commercial use of gas from Devonian shales in the early 1820s in Fredonia, New York, is generally recognized as the birthplace of the natural gas industry. This significantly predates the Drake oil discovery in Titusville, Pennsylvania, in 1859. By 1860, a series of shallow shale-gas fields were developed in a fairway along the Lake Erie shoreline extending from Fredonia, New York, southwest toward the city of Sandusky, Ohio (Harper, 2008). Accurate data for these wells are scarce, but the likely black shale formations produced include the Dunkirk, Rhinestreet, Middlesex, and to a lesser extent the Marcellus. The initial reported gas rates were commonly high, but actual production rates and pressures were low and are not considered commercial by today's standards. These shallow wells were used mainly for domestic and light industrial purposes and were extensively developed from the 1860s through the mid-1900s.

The Appalachian Basin has a well-established history of shale-gas development (Figure 1). The discovery and commercial use of gas from Devonian shales in the early 1820s in Fredonia, New York, is generally recognized as the birthplace of the natural gas industry. This significantly predates the Drake oil discovery in Titusville, Pennsylvania, in 1859. By 1860, a series of shallow shale-gas fields were developed in a fairway along the Lake Erie shoreline extending from Fredonia, New York, southwest toward the city of Sandusky, Ohio (Harper, 2008). Accurate data for these wells are scarce, but the likely black shale formations produced include the Dunkirk, Rhinestreet, Middlesex, and to a lesser extent the Marcellus. The initial reported gas rates were commonly high, but actual production rates and pressures were low and are not considered commercial by today's standards. These shallow wells were used mainly for domestic and light industrial purposes and were extensively developed from the 1860s through the mid-1900s.

FIGURE 1. A map depicting the historical trends of shale-gas production in the Appalachian Basin and the Marcellus Shale play trend. Map includes present boundaries and names of states, U.S.A. WI = Wisconsin; IL = Illinois; DC = District of Columbia; VT = Vermont; MA = Massachusetts; CT = Connecticut.

[[File:M97Ch4FG1.jpg|400px|thumb|FIGURE 1. A map depicting the historical trends of shale-gas production in the Appalachian Basin and the Marcellus Shale play trend. Map includes present boundaries and names of states, U.S.A. WI = Wisconsin; IL = Illinois; DC = District of Columbia; VT = Vermont; MA = Massachusetts; CT = Connecticut.]]

The first major shale discovery in the Appalachian Basin was in 1921 in northeastern Kentucky, which established the Big Sandy field. To date, a total of more than 21,000 wells have been drilled in the Big Sandy field in eastern Kentucky, southern West Virginia, southern Ohio, and southwestern Virginia. The primary target in the Big Sandy field is the Upper Devonian Huron Shale, with contributions from the Cleveland, Rhinestreet, and Marcellus Shale intervals. Two characteristics of the Big Sandy field are its significant underpressured profile and a well-established open natural fracture network. This distinguishes the Big Sandy field from modern shale plays such as the Barnett, Fayetteville, and Haynesville shales, which have higher pressure gradients combined with lower density open natural fracture networks. These modern shale-gas plays rely more on the creation of induced artificial fractures to achieve commercial production rates than production from existing open natural fractures. To date, more than 2.5 tcf has been produced from the Big Sandy field (de Witt, 1986), and it still represents one of the top 100 gas fields in the United States. The development of the Big Sandy field continues using both vertical and horizontal drilling (Morris, 2008).

The first major shale discovery in the Appalachian Basin was in 1921 in northeastern Kentucky, which established the Big Sandy field. To date, a total of more than 21,000 wells have been drilled in the Big Sandy field in eastern Kentucky, southern West Virginia, southern Ohio, and southwestern Virginia. The primary target in the Big Sandy field is the Upper Devonian Huron Shale, with contributions from the Cleveland, Rhinestreet, and Marcellus Shale intervals. Two characteristics of the Big Sandy field are its significant underpressured profile and a well-established open natural fracture network. This distinguishes the Big Sandy field from modern shale plays such as the Barnett, Fayetteville, and Haynesville shales, which have higher pressure gradients combined with lower density open natural fracture networks. These modern shale-gas plays rely more on the creation of induced artificial fractures to achieve commercial production rates than production from existing open natural fractures. To date, more than 2.5 tcf has been produced from the Big Sandy field (de Witt, 1986), and it still represents one of the top 100 gas fields in the United States. The development of the Big Sandy field continues using both vertical and horizontal drilling (Morris, 2008).

Figure 2 shows the regional stratigraphy of the Devonian shales and the Marcellus Shale Formation. The Middle Devonian Marcellus Shale Formation is located within the lower part of the Hamilton Group, which is bounded above by the Middle Devonian Tully Limestone and below by the Lower Devonian Onondaga Limestone (Onesquethaw Group). The Marcellus is divided into two members, the lower Marcellus/Union Springs Shale and the upper Marcellus/Oatka Creek Shale, which are separated by the Cherry Valley/Purcell Limestone. Lash (2008) interprets the Cherry Valley and the Purcell limestones to be equivalent, although other authors, including de Witt et al. (1993) and Werne et al. (2002), show the Cherry Valley and Purcell as separate members.

Figure 2 shows the regional stratigraphy of the Devonian shales and the Marcellus Shale Formation. The Middle Devonian Marcellus Shale Formation is located within the lower part of the Hamilton Group, which is bounded above by the Middle Devonian Tully Limestone and below by the Lower Devonian Onondaga Limestone (Onesquethaw Group). The Marcellus is divided into two members, the lower Marcellus/Union Springs Shale and the upper Marcellus/Oatka Creek Shale, which are separated by the Cherry Valley/Purcell Limestone. Lash (2008) interprets the Cherry Valley and the Purcell limestones to be equivalent, although other authors, including de Witt et al. (1993) and Werne et al. (2002), show the Cherry Valley and Purcell as separate members.

FIGURE 2. A generalized stratigraphic chart of the Marcellus Shale interval in West Virginia, Ohio, Pennsylvania, and New York. Modified from Patchen et al. (1985); Lash and Engelder (2008); and Piotrowski et al. (1977).

[[File:M97Ch4FG2.jpg|400px|thumb|FIGURE 2. A generalized stratigraphic chart of the Marcellus Shale interval in West Virginia, Ohio, Pennsylvania, and New York. Modified from Patchen et al. (1985); Lash and Engelder (2008); and Piotrowski et al. (1977).]]

Several unconformities have been identified within the Marcellus Shale by Lash (2008) in distal areas of the Appalachian Basin in western New York and northwestern Pennsylvania. These include unconformities that are the upper sequence boundaries for Union Springs and Oatka Creek shales. Lash (2009a, b) documents that the entire Union Spring Shale is removed by a regional disconformity in some of these areas. These unconformity surfaces below and above the Marcellus Shale are interpreted to become conformable to the southeast, into the deeper parts of the basin (Hamilton-Smith, 1993; Milici and Swezey 2006; Boyce, 2009). A major Middle Devonian unconformity above the Tully Limestone (Hamilton-Smith 1993) progressively removes stratigraphically older units from east to west. Moving west toward the Cincinnati arch, this unconformity truncates the entire Tully, Hamilton, and progressively older formations.

Several unconformities have been identified within the Marcellus Shale by Lash (2008) in distal areas of the Appalachian Basin in western New York and northwestern Pennsylvania. These include unconformities that are the upper sequence boundaries for Union Springs and Oatka Creek shales. Lash (2009a, b) documents that the entire Union Spring Shale is removed by a regional disconformity in some of these areas. These unconformity surfaces below and above the Marcellus Shale are interpreted to become conformable to the southeast, into the deeper parts of the basin (Hamilton-Smith, 1993; Milici and Swezey 2006; Boyce, 2009). A major Middle Devonian unconformity above the Tully Limestone (Hamilton-Smith 1993) progressively removes stratigraphically older units from east to west. Moving west toward the Cincinnati arch, this unconformity truncates the entire Tully, Hamilton, and progressively older formations.

The paleogeographic reconstruction by Ettensohn (1985b), Woodrow and Sevon (1985), and Blakey (2005) shows that the organic-rich deposition occurred in a large, nearly enclosed, three-sided embayment that likely would have served to enhance oceanic organic productivity. Figure 3 shows the paleogeographic reconstruction by Blakey (2005) of the Appalachian area about 385 Ma. The arid conditions that were likely present during deposition of the organic-rich facies led to a probable sediment starvation, as evidenced by the decrease in noneolian siliciclastic deposition in the organic-rich facies, preventing dilution of the accumulating organic material.

The paleogeographic reconstruction by Ettensohn (1985b), Woodrow and Sevon (1985), and Blakey (2005) shows that the organic-rich deposition occurred in a large, nearly enclosed, three-sided embayment that likely would have served to enhance oceanic organic productivity. Figure 3 shows the paleogeographic reconstruction by Blakey (2005) of the Appalachian area about 385 Ma. The arid conditions that were likely present during deposition of the organic-rich facies led to a probable sediment starvation, as evidenced by the decrease in noneolian siliciclastic deposition in the organic-rich facies, preventing dilution of the accumulating organic material.

FIGURE 3. Middle Devonian paleogeography showing the restricted Marcellus Shale depositional basin. Modified from Blakey (2005).

[[File:M97Ch4FG3.jpg|400px|thumb|FIGURE 3. Middle Devonian paleogeography showing the restricted Marcellus Shale depositional basin. Modified from Blakey (2005).]]

Wrightstone (2010) proposed that the Marcellus organic-rich units were deposited and accumulated in a perfect storm scenario of maximum organic production, noneolian sediment starvation, and maximum preservation. He proposed that algal blooms associated with periodic dust storms led to enhanced production of organics and possible basinwide anoxic events.

Wrightstone (2010) proposed that the Marcellus organic-rich units were deposited and accumulated in a perfect storm scenario of maximum organic production, noneolian sediment starvation, and maximum preservation. He proposed that algal blooms associated with periodic dust storms led to enhanced production of organics and possible basinwide anoxic events.

The major structural features of the Appalachian Basin, key shale production trends, and structural provinces of the Appalachian Basin are depicted in Figure 4. Key structural elements of the Appalachian Basin from west to east include the Waverly arch and Cincinnati arch to the west, the Cambridge arch and Burning Springs anticline farther eastward, the Rome trough, and the anticlinal fold belts in the Appalachian Plateau and Valley and Ridge province. To date, most economic productive Marcellus wells are located within the Appalachian Plateau physiographic province. This province is marked by generally gentle structures and a lack of intense faulting in the western parts of the province. Structural complexity increases to the east toward the structural front, where high-amplitude, detached, salt-cored anticlines are present trending northeast–southwest. Structural complexity may also occur in the synclines within the eastern parts of this province. The structural front represents the boundary between the plateau and the Valley and Ridge province, where the Devonian section rises quickly to the surface and crops out. The Valley and Ridge province represents the most structurally challenging area in which the Marcellus Shale is present. The area is structurally complex, with high-amplitude detached folds, repeated and overturned beds, and multiple thrust faults.

The major structural features of the Appalachian Basin, key shale production trends, and structural provinces of the Appalachian Basin are depicted in Figure 4. Key structural elements of the Appalachian Basin from west to east include the Waverly arch and Cincinnati arch to the west, the Cambridge arch and Burning Springs anticline farther eastward, the Rome trough, and the anticlinal fold belts in the Appalachian Plateau and Valley and Ridge province. To date, most economic productive Marcellus wells are located within the Appalachian Plateau physiographic province. This province is marked by generally gentle structures and a lack of intense faulting in the western parts of the province. Structural complexity increases to the east toward the structural front, where high-amplitude, detached, salt-cored anticlines are present trending northeast–southwest. Structural complexity may also occur in the synclines within the eastern parts of this province. The structural front represents the boundary between the plateau and the Valley and Ridge province, where the Devonian section rises quickly to the surface and crops out. The Valley and Ridge province represents the most structurally challenging area in which the Marcellus Shale is present. The area is structurally complex, with high-amplitude detached folds, repeated and overturned beds, and multiple thrust faults.

FIGURE 4. A map showing the primary structural features of the Appalachian Basin. Modified from Shumaker (1996). Decollement trends are from Colton (1970), Frey (1973), and Sanford (1993). VT = Vermont; CT = Connecticut.

[[File:M97Ch4FG4.jpg|400px|thumb|FIGURE 4. A map showing the primary structural features of the Appalachian Basin. Modified from Shumaker (1996). Decollement trends are from Colton (1970), Frey (1973), and Sanford (1993). VT = Vermont; CT = Connecticut.

A key regional component of the emerging Marcellus Shale play is its relationship to basement faulting. Figure 5 depicts the basement structure of the Appalachian Basin, together with major interpreted faults, the projected position of the Rome trough, and key Devonian shale and Marcellus Shale production trends. The mapped basement faults fall into two classifications: (1) those faults that are strike parallel to the basin and related to the Rome trough and (2) those faults that trend perpendicular to the strike of the basin and are interpreted as transform faults or cross-strike structural discontinuities (CSDs) (Harper and Laughrey, 1987). These basement faults represent zones of weakness believed to have been reactivated several times during the Paleozoic (Negus-DeWyss, 1979; Lee, 1980; Shumaker, 1993). In addition, reactivation caused significant structural inversion in some areas. It is likely that movement along these faults has continued well into the Quaternary, as the surface expression of several of these major features are clearly apparent on both topographic maps and satellite images.

A key regional component of the emerging Marcellus Shale play is its relationship to basement faulting. Figure 5 depicts the basement structure of the Appalachian Basin, together with major interpreted faults, the projected position of the Rome trough, and key Devonian shale and Marcellus Shale production trends. The mapped basement faults fall into two classifications: (1) those faults that are strike parallel to the basin and related to the Rome trough and (2) those faults that trend perpendicular to the strike of the basin and are interpreted as transform faults or cross-strike structural discontinuities (CSDs) (Harper and Laughrey, 1987). These basement faults represent zones of weakness believed to have been reactivated several times during the Paleozoic (Negus-DeWyss, 1979; Lee, 1980; Shumaker, 1993). In addition, reactivation caused significant structural inversion in some areas. It is likely that movement along these faults has continued well into the Quaternary, as the surface expression of several of these major features are clearly apparent on both topographic maps and satellite images.

FIGURE 5. A map showing the relationship of the Appalachian shale-gas plays to basement structure and position of the Rome trough. Modified from Shumaker (1996). DC = District of Columbia; MA = Massachusetts; CT = Connecticut.

[[File:M97Ch4FG5.jpg|400px|thumb|FIGURE 5. A map showing the relationship of the Appalachian shale-gas plays to basement structure and position of the Rome trough. Modified from Shumaker (1996). DC = District of Columbia; MA = Massachusetts; CT = Connecticut.]]

The Rome trough is a prominent structural feature of the Appalachian Basin, representing a failed rift system formed in the Middle Cambrian. The Rome trough has been extensively studied in West Virginia and eastern Kentucky, and it extends into Pennsylvania and New York (Harper and Laughrey, 1987; Shumaker, 1996; Scanlin and Engelder, 2003; Kulander and Ryder, 2005). Shumaker (1993) showed several areas where the Rome trough affected sedimentation of key Devonian organic shale members and also where reactivation of basement faults provided for enhanced areas of natural fracturing in the Cottageville and Midway Extra Shale fields in West Virginia. These basement faults are well documented to have been active during the Late Devonian, affecting deposition of reservoir sands along Rome trough-bounding faults in West Virginia and Pennsylvania (Boswell, 1985; Harper and Laughrey, 1987; Murin, 1988; Flaherty, 1994). Closer to the emerging Marcellus Shale play, Kulander and Ryder (2005) defined the boundaries of the Rome trough in southwestern Pennsylvania through a series of regional cross sections and regional seismic profiles. The Rome trough appears to delineate areas of maximum deposition of key organic shale beds in the Marcellus Shale as well as overlying beds such as the Tully Limestone. In addition, it is a critical feature related to both the burial and thermal maturity history of the Marcellus Shale.

The Rome trough is a prominent structural feature of the Appalachian Basin, representing a failed rift system formed in the Middle Cambrian. The Rome trough has been extensively studied in West Virginia and eastern Kentucky, and it extends into Pennsylvania and New York (Harper and Laughrey, 1987; Shumaker, 1996; Scanlin and Engelder, 2003; Kulander and Ryder, 2005). Shumaker (1993) showed several areas where the Rome trough affected sedimentation of key Devonian organic shale members and also where reactivation of basement faults provided for enhanced areas of natural fracturing in the Cottageville and Midway Extra Shale fields in West Virginia. These basement faults are well documented to have been active during the Late Devonian, affecting deposition of reservoir sands along Rome trough-bounding faults in West Virginia and Pennsylvania (Boswell, 1985; Harper and Laughrey, 1987; Murin, 1988; Flaherty, 1994). Closer to the emerging Marcellus Shale play, Kulander and Ryder (2005) defined the boundaries of the Rome trough in southwestern Pennsylvania through a series of regional cross sections and regional seismic profiles. The Rome trough appears to delineate areas of maximum deposition of key organic shale beds in the Marcellus Shale as well as overlying beds such as the Tully Limestone. In addition, it is a critical feature related to both the burial and thermal maturity history of the Marcellus Shale.

Figure 6 is the thermal maturity map of the Marcellus Shale using public and proprietary measured vitrinite and calculated vitrinite reflectance (Ro) data. Thermal maturity patterns in the Marcellus Shale generally increase in a southeasterly direction, ranging from 0.5% Ro in northwestern Pennsylvania and eastern Ohio to greater than 3.5% Ro in northeastern Pennsylvania and southeastern New York. Recent Marcellus Shale drilling activity and results indicate that the most significant hydrocarbon potential and production occurs approximately southeastward of the 1.0% Ro maturity contour in the western parts of Pennsylvania, West Virginia, eastern Ohio, and southern New York. At thermal maturity values of greater than 3.5% Ro, the potential from the Marcellus Shale may become problematic based on the limited drilling results released to date. Also shown on Figure 6 are major basement fault patterns and the Rome trough. Several major cross-striking basement faults appear to relate to discontinuities in the observed thermal maturity patterns. In addition to the observed influence of basement fault patterns, the Marcellus Shale play in northeastern Pennsylvania appears to have been subjected to greater depths of burial as well as increased sedimentation and subsidence rates (Faill, 1985), which also may have influenced thermal maturity patterns.

Figure 6 is the thermal maturity map of the Marcellus Shale using public and proprietary measured vitrinite and calculated vitrinite reflectance (Ro) data. Thermal maturity patterns in the Marcellus Shale generally increase in a southeasterly direction, ranging from 0.5% Ro in northwestern Pennsylvania and eastern Ohio to greater than 3.5% Ro in northeastern Pennsylvania and southeastern New York. Recent Marcellus Shale drilling activity and results indicate that the most significant hydrocarbon potential and production occurs approximately southeastward of the 1.0% Ro maturity contour in the western parts of Pennsylvania, West Virginia, eastern Ohio, and southern New York. At thermal maturity values of greater than 3.5% Ro, the potential from the Marcellus Shale may become problematic based on the limited drilling results released to date. Also shown on Figure 6 are major basement fault patterns and the Rome trough. Several major cross-striking basement faults appear to relate to discontinuities in the observed thermal maturity patterns. In addition to the observed influence of basement fault patterns, the Marcellus Shale play in northeastern Pennsylvania appears to have been subjected to greater depths of burial as well as increased sedimentation and subsidence rates (Faill, 1985), which also may have influenced thermal maturity patterns.

FIGURE 6. A map showing the thermal maturity patterns for the Marcellus Shale and major basement faults. Modified from Repetski et al. (2008). DC = District of Columbia; DE = Delaware; Ro = vitrinite reflectance.

[[File:M97Ch4FG6.jpg|400px|thumb|FIGURE 6. A map showing the thermal maturity patterns for the Marcellus Shale and major basement faults. Modified from Repetski et al. (2008). DC = District of Columbia; DE = Delaware; Ro = vitrinite reflectance.]]

Thermal maturity is a critical play element for the Marcellus Shale. Thermal maturity studies for the Appalachian Basin (Weary et al., 2000; Repetski et al., 2002, 2005; Rowan et al., 2004; Rowan, 2006) assume that the measured Ro values in the Marcellus Shale require greater depths of burial and higher temperatures than observed at the present day. The Rome trough and associated basement faults were critical to reaching the needed burial depths and pressures. The northwestern boundary of the Rome trough likely represents a hinge zone where rapid burial of the Marcellus Shale allowed it to reach the current observed thermal maturity levels.

Thermal maturity is a critical play element for the Marcellus Shale. Thermal maturity studies for the Appalachian Basin (Weary et al., 2000; Repetski et al., 2002, 2005; Rowan et al., 2004; Rowan, 2006) assume that the measured Ro values in the Marcellus Shale require greater depths of burial and higher temperatures than observed at the present day. The Rome trough and associated basement faults were critical to reaching the needed burial depths and pressures. The northwestern boundary of the Rome trough likely represents a hinge zone where rapid burial of the Marcellus Shale allowed it to reach the current observed thermal maturity levels.

Figure 7 is a map of the drilling depth to the base of the Marcellus Shale and illustrates the structural framework of the Appalachian Basin as one of a strongly asymmetric trough. The depth to the base of the Marcellus Shale increases gently to the southeast to more than 2752 m (gt8500 ft). The maximum drilling depths are encountered in synclines just basinward of the structural front. Most of the permitted and drilled Marcellus wells are located in areas where the drilling depth is in the 1375 to 2750 m (4500 to 9000 ft) range. In general, increased depth will result in higher gas-in-place (GIP) values because of the increase in pressure within an overpressured environment, thus providing the current bias toward drilling below 1200 m (4000 ft). To date, most drilling has been at depths of 1375 m (4500 ft) or deeper, although a review of historic drilling data indicates that the Marcellus Shale had significant natural shows at depths shallower than 1375 m (4500 ft). An analog for these shallower areas of the Marcellus Shale play is the Fayetteville Shale where large areas of commercial development exist between depths of 610 to 1980 m (2000–6500 ft).

Figure 7 is a map of the drilling depth to the base of the Marcellus Shale and illustrates the structural framework of the Appalachian Basin as one of a strongly asymmetric trough. The depth to the base of the Marcellus Shale increases gently to the southeast to more than 2752 m (gt8500 ft). The maximum drilling depths are encountered in synclines just basinward of the structural front. Most of the permitted and drilled Marcellus wells are located in areas where the drilling depth is in the 1375 to 2750 m (4500 to 9000 ft) range. In general, increased depth will result in higher gas-in-place (GIP) values because of the increase in pressure within an overpressured environment, thus providing the current bias toward drilling below 1200 m (4000 ft). To date, most drilling has been at depths of 1375 m (4500 ft) or deeper, although a review of historic drilling data indicates that the Marcellus Shale had significant natural shows at depths shallower than 1375 m (4500 ft). An analog for these shallower areas of the Marcellus Shale play is the Fayetteville Shale where large areas of commercial development exist between depths of 610 to 1980 m (2000–6500 ft).

FIGURE 7. A map depicting the vertical drilling depths to the base of the Marcellus Shale. DE = Delaware.

[[File:M97Ch4FG7.jpg|400px|thumb|FIGURE 7. A map depicting the vertical drilling depths to the base of the Marcellus Shale. DE = Delaware.]]

===Pressure Gradient for Marcellus Shale Play===

===Pressure Gradient for Marcellus Shale Play===

The locations of these identified pressure regimes are shown on Figure 8. As shown, three pressure regimes in the Marcellus Shale have been identified, including underpressured, transitional (still underpressured), and normal to overpressured. In southern and south-central West Virginia, the Marcellus Shale and other shallower reservoirs have a significantly reduced pressure gradient, ranging from less than 0.10 to 0.25 psi/ft. The low-pressure area negatively impacts the production performance of the Marcellus Shale. Most wells in this area have been completed by explosive stimulation, foam fracs, or straight gas fracs, and nearly all are commingled with shallower reservoirs. The transitional pressure area of the Marcellus Shale is postulated to trend through central West Virginia, with an estimated pressure gradient of 0.25 to 0.40 psi/ft. Most of the Marcellus wells in this area are completed with large slick-water fracs, although foam fracs are not uncommon. The production performance from the recent Marcellus Shale vertical wells in this transitional trend is also negatively impacted with first-year cumulative production averaging less than 20 mmcfe per well.

The locations of these identified pressure regimes are shown on Figure 8. As shown, three pressure regimes in the Marcellus Shale have been identified, including underpressured, transitional (still underpressured), and normal to overpressured. In southern and south-central West Virginia, the Marcellus Shale and other shallower reservoirs have a significantly reduced pressure gradient, ranging from less than 0.10 to 0.25 psi/ft. The low-pressure area negatively impacts the production performance of the Marcellus Shale. Most wells in this area have been completed by explosive stimulation, foam fracs, or straight gas fracs, and nearly all are commingled with shallower reservoirs. The transitional pressure area of the Marcellus Shale is postulated to trend through central West Virginia, with an estimated pressure gradient of 0.25 to 0.40 psi/ft. Most of the Marcellus wells in this area are completed with large slick-water fracs, although foam fracs are not uncommon. The production performance from the recent Marcellus Shale vertical wells in this transitional trend is also negatively impacted with first-year cumulative production averaging less than 20 mmcfe per well.

FIGURE 8. A map showing the relationships of Marcellus Shale pressure trends to the Rome trough and key Appalachian Basin decollement intervals. Modified from Milici (2005) and Wrightstone (2008). Decollement trends are from Colton (1970), Frey (1973), and Sanford (1993). NJ = New Jersey.

[[File:M97Ch4FG8.jpg|400px|thumb|FIGURE 8. A map showing the relationships of Marcellus Shale pressure trends to the Rome trough and key Appalachian Basin decollement intervals. Modified from Milici (2005) and Wrightstone (2008). Decollement trends are from Colton (1970), Frey (1973), and Sanford (1993). NJ = New Jersey.]]

Normal to overpressured gradients are proposed for much of the remaining parts of the Marcellus Shale play in north-central West Virginia and northward into Pennsylvania and the southern tier of New York. Pressure gradients in these areas are projected to range from approximately 0.43 to more than 0.80 psi/ft. It is also noted that a decline in the pressure gradient may exist along the eastern margins of the play, near the structural front, possibly caused by a combination of a lack of overlying seal integrity and/or a decrease in preserved organic material approaching the structural front. Based on the established successes of recent Marcellus Shale horizontal and vertical wells in northeastern Pennsylvania, southwestern Pennsylvania, and northern West Virginia, it is proposed that consistently high production volumes and high ultimate reserves in the Marcellus Shale will be mainly found in the areas that are normal to overpressured. The position of the Rome trough system is closely related to the areas of highest observed pressure gradients in the Marcellus Shale.

Normal to overpressured gradients are proposed for much of the remaining parts of the Marcellus Shale play in north-central West Virginia and northward into Pennsylvania and the southern tier of New York. Pressure gradients in these areas are projected to range from approximately 0.43 to more than 0.80 psi/ft. It is also noted that a decline in the pressure gradient may exist along the eastern margins of the play, near the structural front, possibly caused by a combination of a lack of overlying seal integrity and/or a decrease in preserved organic material approaching the structural front. Based on the established successes of recent Marcellus Shale horizontal and vertical wells in northeastern Pennsylvania, southwestern Pennsylvania, and northern West Virginia, it is proposed that consistently high production volumes and high ultimate reserves in the Marcellus Shale will be mainly found in the areas that are normal to overpressured. The position of the Rome trough system is closely related to the areas of highest observed pressure gradients in the Marcellus Shale.

Figure 9 is an overlay of the Tully Limestone isopach with the regional pressure gradient. This also shows an apparent correlation between the areas of normal or high pressure and the 20 ft thickness contour of the Tully Limestone. Based on the correlation between the Tully Limestone thickness and the limits of normal or overpressured Marcellus Shale, it can be proposed that the Tully Limestone may have been a factor in the trapping of the thermogenic produced gas from the Marcellus Shale. Alternately, this may be just a geologic coincidence, albeit an important one, where the deposition of the Tully Limestone was controlled by the position of the Rome trough. Recent tests of the shallower Rhinestreet, Genesee, and Burkett shales above the Tully Limestone have encountered overpressure gradients that suggest, at a minimum, that the seal is incomplete or that in some areas a separate hydrocarbon generation system exists above the Tully Limestone in the organic shales of the Genesee Group.

Figure 9 is an overlay of the Tully Limestone isopach with the regional pressure gradient. This also shows an apparent correlation between the areas of normal or high pressure and the 20 ft thickness contour of the Tully Limestone. Based on the correlation between the Tully Limestone thickness and the limits of normal or overpressured Marcellus Shale, it can be proposed that the Tully Limestone may have been a factor in the trapping of the thermogenic produced gas from the Marcellus Shale. Alternately, this may be just a geologic coincidence, albeit an important one, where the deposition of the Tully Limestone was controlled by the position of the Rome trough. Recent tests of the shallower Rhinestreet, Genesee, and Burkett shales above the Tully Limestone have encountered overpressure gradients that suggest, at a minimum, that the seal is incomplete or that in some areas a separate hydrocarbon generation system exists above the Tully Limestone in the organic shales of the Genesee Group.

FIGURE 9. A map showing the gross thickness of the Tully Limestone, the Rome trough, and key basement faults.

[[File:M97Ch4FG9.jpg|400px|thumb|FIGURE 9. A map showing the gross thickness of the Tully Limestone, the Rome trough, and key basement faults.]]

===Marcellus Thickness Trends===

===Marcellus Thickness Trends===

Several older studies from the EGSP provide good regional overviews of the general thickness trends of the Marcellus Shale across the Appalachian Basin. In general, the most current industry drilling activity is associated with areas having greater than 15 m (gt50 ft) of gross Marcellus Shale thickness. These earlier studies all show a general eastward thickening of the Marcellus Shale within, or near, the Rome trough.

Several older studies from the EGSP provide good regional overviews of the general thickness trends of the Marcellus Shale across the Appalachian Basin. In general, the most current industry drilling activity is associated with areas having greater than 15 m (gt50 ft) of gross Marcellus Shale thickness. These earlier studies all show a general eastward thickening of the Marcellus Shale within, or near, the Rome trough.

Figure 10 is a map of the gross thickness of the Marcellus Shale across the Appalachian Basin, as well as major mapped basement fault trends. The gross thickness of the Marcellus Shale as mapped is defined by the top of the first occurrence of organic shale near the base of the Mahantango Formation to the top of the Onondaga Limestone. The gross thickness of the Marcellus Shale increases generally eastward from the zero isopach in eastern Ohio and western West Virginia to a maximum thickness of more than 107 m (gt350 ft) in northeastern Pennsylvania. The trend of thickening generally parallels the Appalachian structural front, as shown in Figure 10. The gross thickness map has not been corrected for potentially repeated sections or areas that encounter significant bed dips. The gross depositional patterns of the Marcellus Shale appear likely to be influenced by basement fault patterns showing both a general strike-parallel thickening within the Rome trough and related strike-parallel basement faults. In addition, abrupt depositional terminations may exist at, or near, the cross-striking basement faults. Excellent reviews of the thickness trends of the Marcellus Shale and related intervals have been recently addressed by Lash and Engelder (2008) and Boyce (2009).

[[:File:M97Ch4FG10.jpg|Figure 10]] is a map of the gross thickness of the Marcellus Shale across the Appalachian Basin, as well as major mapped basement fault trends. The gross thickness of the Marcellus Shale as mapped is defined by the top of the first occurrence of organic shale near the base of the Mahantango Formation to the top of the Onondaga Limestone. The gross thickness of the Marcellus Shale increases generally eastward from the zero isopach in eastern Ohio and western West Virginia to a maximum thickness of more than 107 m (gt350 ft) in northeastern Pennsylvania. The trend of thickening generally parallels the Appalachian structural front, as shown in Figure 10. The gross thickness map has not been corrected for potentially repeated sections or areas that encounter significant bed dips. The gross depositional patterns of the Marcellus Shale appear likely to be influenced by basement fault patterns showing both a general strike-parallel thickening within the Rome trough and related strike-parallel basement faults. In addition, abrupt depositional terminations may exist at, or near, the cross-striking basement faults. Excellent reviews of the thickness trends of the Marcellus Shale and related intervals have been recently addressed by Lash and Engelder (2008) and Boyce (2009).

FIGURE 10. A map showing the gross thickness of the Marcellus Shale interval and major basement faults. DC = District of Columbia.

[[File:M97Ch4FG10.jpg|400px|thumb|FIGURE 10. A map showing the gross thickness of the Marcellus Shale interval and major basement faults. DC = District of Columbia.]]

===Core Analysis: Porosity and Permeability===

===Core Analysis: Porosity and Permeability===

Permeability data for the Marcellus Shale are very limited. As previously described, these early discoveries of high permeability, high porosity, and large gas storage capacity were important but did not generate significant industry interest in the Marcellus Shale as a viable reservoir target. Recent log and core data confirm that significant porosity and permeability are present across several large areas of the Marcellus Shale play. Observed porosity in the Marcellus Shale is much higher than that of the other Devonian shales in the Appalachian Basin, ranging from 5 to 15% in the southwestern parts of the play to 4 to 10% in the northeastern parts of the Marcellus Shale play. Data from wells drilled by Range Resources in Pennsylvania across the Marcellus Shale play have encountered a wide range of calculated permeabilities ranging from 130 to more than 2000 ηd. Most workers consider minimum values of commercial permeability in gas shales to be in excess of 100 ηd. Shale gas reservoirs with more than 500 ηd are considered very good. As such, the observed permeabilities in the Marcellus Shale play appear exceptional and unique compared with other North American gas-shale plays, with the exception of the Haynesville Shale play, where a similar high permeability is observed. Figure 11 shows an example of the pore structures from a core taken from the Marcellus Shale in southwestern Pennsylvania.

Permeability data for the Marcellus Shale are very limited. As previously described, these early discoveries of high permeability, high porosity, and large gas storage capacity were important but did not generate significant industry interest in the Marcellus Shale as a viable reservoir target. Recent log and core data confirm that significant porosity and permeability are present across several large areas of the Marcellus Shale play. Observed porosity in the Marcellus Shale is much higher than that of the other Devonian shales in the Appalachian Basin, ranging from 5 to 15% in the southwestern parts of the play to 4 to 10% in the northeastern parts of the Marcellus Shale play. Data from wells drilled by Range Resources in Pennsylvania across the Marcellus Shale play have encountered a wide range of calculated permeabilities ranging from 130 to more than 2000 ηd. Most workers consider minimum values of commercial permeability in gas shales to be in excess of 100 ηd. Shale gas reservoirs with more than 500 ηd are considered very good. As such, the observed permeabilities in the Marcellus Shale play appear exceptional and unique compared with other North American gas-shale plays, with the exception of the Haynesville Shale play, where a similar high permeability is observed. Figure 11 shows an example of the pore structures from a core taken from the Marcellus Shale in southwestern Pennsylvania.

FIGURE 11. A typical gamma-ray log of the Marcellus Shale interval in southwestern Pennsylvania with selected thin-section and SEM images showing the complex mineralogy and high organic content of key Marcellus Shale play intervals. G/C3 = matrix density ρmatrix (in grams per cubic centimeter); GAPI = gamma-ray API units; SEM = scanning electron microscope; TVD = true vertical depth (in ft); RLA3 = borehole corrected resistivity in OHMM; RLA5 = borehole corrected resistivity in OHMM.

[[File:M97Ch4FG11.jpg|400px|thumb|FIGURE 11. A typical gamma-ray log of the Marcellus Shale interval in southwestern Pennsylvania with selected thin-section and SEM images showing the complex mineralogy and high organic content of key Marcellus Shale play intervals. G/C3 = matrix density ρmatrix (in grams per cubic centimeter); GAPI = gamma-ray API units; SEM = scanning electron microscope; TVD = true vertical depth (in ft); RLA3 = borehole corrected resistivity in OHMM; RLA5 = borehole corrected resistivity in OHMM.]]

===Gas in Place===

===Gas in Place===

Unlike the Barnett Shale play that was characterized by a long period of vertical well drilling followed by a rapid expansion into horizontal drilling, the Marcellus Shale play appears to be characterized by a quick switch from vertical drilling to horizontal drilling. Nearly all horizontal wells drilled in the Marcellus Shale play are oriented along a northwest–southeast azimuth. Current direction of maximum horizontal principal stress (SHmax) for the Appalachian Basin is northeast to southwest based on numerous studies by the EGSP, the world stress map, microseismic studies, and observed direction of drilling-induced fractures observed in cores and FMI logs for the Marcellus Shale and other EGSP wells. These are shown in Figure 12. As such, the northwest–southeast azimuth is the primary orientation for most horizontal Marcellus wells.

Unlike the Barnett Shale play that was characterized by a long period of vertical well drilling followed by a rapid expansion into horizontal drilling, the Marcellus Shale play appears to be characterized by a quick switch from vertical drilling to horizontal drilling. Nearly all horizontal wells drilled in the Marcellus Shale play are oriented along a northwest–southeast azimuth. Current direction of maximum horizontal principal stress (SHmax) for the Appalachian Basin is northeast to southwest based on numerous studies by the EGSP, the world stress map, microseismic studies, and observed direction of drilling-induced fractures observed in cores and FMI logs for the Marcellus Shale and other EGSP wells. These are shown in Figure 12. As such, the northwest–southeast azimuth is the primary orientation for most horizontal Marcellus wells.

FIGURE 12. A stress map (modified from Heidbach et al., 2008) showing the observed SHmax trends, observed formation microimaging (FMI) features, and sample microseismic observations from the Marcellus Shale play in southwestern Pennsylvania. Attached FMI images include (1) drilling-induced fractures (green), (2) healed natural fractures (yellow), (3) partially healed fractures (purple), and (4) possible faults (blue). Microseismic examples show the primary fracture-growth direction in a northeast–southwest direction and good observed containment between the Tully Limestone and Onondaga Limestone intervals bounding the Marcellus Shale. Drill. induced frac. = drilling-induced fracture; geol. indicators = geologic indicators; NF = normal faulted regime; SS = strike-slip faulted regime; TF = thrust faulted regime; U = unfaulted regime.

[[File:M97Ch4FG12.jpg|400px|thumb|FIGURE 12. A stress map (modified from Heidbach et al., 2008) showing the observed SHmax trends, observed formation microimaging (FMI) features, and sample microseismic observations from the Marcellus Shale play in southwestern Pennsylvania. Attached FMI images include (1) drilling-induced fractures (green), (2) healed natural fractures (yellow), (3) partially healed fractures (purple), and (4) possible faults (blue). Microseismic examples show the primary fracture-growth direction in a northeast–southwest direction and good observed containment between the Tully Limestone and Onondaga Limestone intervals bounding the Marcellus Shale. Drill. induced frac. = drilling-induced fracture; geol. indicators = geologic indicators; NF = normal faulted regime; SS = strike-slip faulted regime; TF = thrust faulted regime; U = unfaulted regime.]]

It is anticipated that vertical wells will continue to be drilled in the future, particularly in northern West Virginia, because of a combination of severe topography that limits the size of locations and supporting infrastructure and also lease positions that include small tracts unsuited for horizontal drilling compounded by the lack of forced unionization.

It is anticipated that vertical wells will continue to be drilled in the future, particularly in northern West Virginia, because of a combination of severe topography that limits the size of locations and supporting infrastructure and also lease positions that include small tracts unsuited for horizontal drilling compounded by the lack of forced unionization.

Two major core areas are developing in the Marcellus Shale play. These include a southwestern region comprising parts of northern West Virginia and southwestern Pennsylvania and a second core area located primarily in northeastern Pennsylvania. Figure 13 shows the major part of the southwestern core area of the Marcellus with key wells, test rates, and thermal maturity. Well results in this area for vertical wells range from 0.100 mmcfepd to more than 5.0 mmcfepd, and horizontal well results range from 1.0 mmcfepd to more than 26.0 mmcfepd (Range Resources Corporation, 2010). In this southwestern area, the Marcellus Shale has a gross thickness of 18 to 45 m (60–150 ft) with high porosity, TOC percentage, and permeability and is located west of the major fold-belt structures of the Appalachian Basin. In the western parts of the southwestern play, thermal maturity is lower and significant natural gas liquid (NGL) production is associated with wells drilled in this area.

Two major core areas are developing in the Marcellus Shale play. These include a southwestern region comprising parts of northern West Virginia and southwestern Pennsylvania and a second core area located primarily in northeastern Pennsylvania. Figure 13 shows the major part of the southwestern core area of the Marcellus with key wells, test rates, and thermal maturity. Well results in this area for vertical wells range from 0.100 mmcfepd to more than 5.0 mmcfepd, and horizontal well results range from 1.0 mmcfepd to more than 26.0 mmcfepd (Range Resources Corporation, 2010). In this southwestern area, the Marcellus Shale has a gross thickness of 18 to 45 m (60–150 ft) with high porosity, TOC percentage, and permeability and is located west of the major fold-belt structures of the Appalachian Basin. In the western parts of the southwestern play, thermal maturity is lower and significant natural gas liquid (NGL) production is associated with wells drilled in this area.

FIGURE 13. A map of the southwestern part of the Marcellus Shale play depicting key discovery wells and selected well information. IP = Initial potential; SW PA = southwestern Pennsylvania; mmcfpd = million cubic feet (gas) per day; mmcfepd = million cubic feet (gas equivalents) per day.

[[File:M97Ch4FG13.jpg|400px|thumb|FIGURE 13. A map of the southwestern part of the Marcellus Shale play depicting key discovery wells and selected well information. IP = Initial potential; SW PA = southwestern Pennsylvania; mmcfpd = million cubic feet (gas) per day; mmcfepd = million cubic feet (gas equivalents) per day.]]

Figure 14 shows the major part of the northeastern core area of the Marcellus Shale with key wells, test rates, and thermal maturity. In the northeastern core area, vertical well performance has ranged from 0.100 to more than 7.0 mmcfpd, and horizontal well performance has ranged from 1.0 to more than 18.0 mmcfpd. In the northeast core area, the Marcellus Shale attains a gross play interval of 60 to 105 m (200–350 ft), has a Btu content of 1000 to 1050 because of the elevated thermal maturity levels, and is generally more structurally complicated than the southwestern play area. Both areas appear to be consistently overpressured and have relatively comparable reserve potential based on reported flow rates and estimated ultimate recovery estimates.

[[:File:M97Ch4FG14.jpg|Figure 14]] shows the major part of the northeastern core area of the Marcellus Shale with key wells, test rates, and thermal maturity. In the northeastern core area, vertical well performance has ranged from 0.100 to more than 7.0 mmcfpd, and horizontal well performance has ranged from 1.0 to more than 18.0 mmcfpd. In the northeast core area, the Marcellus Shale attains a gross play interval of 60 to 105 m (200–350 ft), has a Btu content of 1000 to 1050 because of the elevated thermal maturity levels, and is generally more structurally complicated than the southwestern play area. Both areas appear to be consistently overpressured and have relatively comparable reserve potential based on reported flow rates and estimated ultimate recovery estimates.

FIGURE 14. A map of the northeastern part of the Marcellus Shale play depicting key discovery wells and selected well information. IP = Initial potential; mmcfpd = million cubic feet (gas) per day.

[[File:M97Ch4FG14.jpg|400px|thumb|FIGURE 14. A map of the northeastern part of the Marcellus Shale play depicting key discovery wells and selected well information. IP = Initial potential; mmcfpd = million cubic feet (gas) per day.]]

The July 27, 2009, issue of the Gene Powell Newsletter identifying the top 868 Barnett Shale wells out of a database of 8266 wells indicated that the average peak 30-day actual production tests for these top tier wells range from 3.0 to more than 10.0 mmcfepd (Powell and Brackett, 2009). Although the Marcellus Shale play is in its infancy compared with the maturing Barnett Shale play, reported IP rates (commonly actual 30-day production tests) for the Marcellus range from 1.0 to more than 26.0 mmcfepd. This suggests that the extent of sweet spots in the Marcellus Shale play are considerably larger than the Barnett Shale play and that well performance on an average or playwide basis is at least equal if not superior to that of the Barnett Shale.

The July 27, 2009, issue of the Gene Powell Newsletter identifying the top 868 Barnett Shale wells out of a database of 8266 wells indicated that the average peak 30-day actual production tests for these top tier wells range from 3.0 to more than 10.0 mmcfepd (Powell and Brackett, 2009). Although the Marcellus Shale play is in its infancy compared with the maturing Barnett Shale play, reported IP rates (commonly actual 30-day production tests) for the Marcellus range from 1.0 to more than 26.0 mmcfepd. This suggests that the extent of sweet spots in the Marcellus Shale play are considerably larger than the Barnett Shale play and that well performance on an average or playwide basis is at least equal if not superior to that of the Barnett Shale.

The Marcellus Shale is a continuous-type gas accumulation and, when fully developed, will consist of a large continuous field or series of fields. Figure 15 is a listing of the top 15 gas fields in the world (Sandrea, 2006). The reserve potential for these top fields ranges from 40 to 1400 tcf. When even the lowest of the recent reserve estimates for the Marcellus are compared with these top worldwide fields, the true potential and scope of the Marcellus Shale are apparent.

The Marcellus Shale is a continuous-type gas accumulation and, when fully developed, will consist of a large continuous field or series of fields. Figure 15 is a listing of the top 15 gas fields in the world (Sandrea, 2006). The reserve potential for these top fields ranges from 40 to 1400 tcf. When even the lowest of the recent reserve estimates for the Marcellus are compared with these top worldwide fields, the true potential and scope of the Marcellus Shale are apparent.

FIGURE 15. Table of the top 15 gas fields of the world showing the relationship of the most recent reserve estimates for the Marcellus Shale gas play. Modified from Sandrea (2006). Reserve estimates from Engelder (2009). TX = Texas; OK = Oklahoma; KS = Kansas.

[[File:M97Ch4FG15.jpg|400px|thumb|FIGURE 15. Table of the top 15 gas fields of the world showing the relationship of the most recent reserve estimates for the Marcellus Shale gas play. Modified from Sandrea (2006). Reserve estimates from Engelder (2009). TX = Texas; OK = Oklahoma; KS = Kansas.]]

==Outstanding geologic issues==

==Outstanding geologic issues==