6.11. Placement of Unconventional Gas in the Energy Picture
This section is aimed at developing a protocol for scientific characterization of unconventional gas. Instead of following conventional protocol of delineating reservoirs based on permeability, a new approach is taken. In this, US reserves are used as a prototype and USGS report (2008) on US reserve growth is used as starting point. Both siliciclastic (largely sandstone) and carbonate (limestone and dolomite) reservoirs in North America are considered. Initial division is made based on geological environment, namely:
1. Eolian environments (Jurassic Norphlet Formation of the Gulf Coast and Pennsylvanian–Permian Minnelusa Formation of the Powder River Basin);
2. Interconnected fluvial, deltaic, and shallow marine environments (Oligocene Frio Formation of the Gulf Coast and the Pennsylvanian Morrow Formation of the Anadarko and Denver basins);
3. Deeper marine environments (Mississippian Barnett Shale of the Fort Worth Basin and Devonian-Mississippian Bakken Formation of the Williston Basin);
4. Marine carbonate environments (Ordovician Ellenburger Group of the Permian Basin and Jurassic Smackover Formation of the Gulf of Mexico Basin);
5. Submarine fan environment (Permian Spraberry Formation of the Midland Basin);
6. A fluvial environment (Paleocene-Eocene Wasatch Formation of the Uinta-Piceance Basin).
Reservoirs in each formation were further subdivided into categories, as appropriate, where the reservoirs had sufficiently different geological attributes to warrant separate treatment. For each category, the potential of unconventional gas and oil is considered. Important variables considered are source rock, depositional setting and then postdepositional alteration. Type of traps or seals is left under a different category that is responsible for engineering decisions, rather than scientific characterization.
As discussed in previous chapters, origin of fluid as well as rock must be tracked in order to characterize gas resources. In order to determine origin of fluids, the connection between petroleum history and geological background is highlighted. This analysis also helped refine basis for reservoir heterogeneities that have different impacts on gas trapping as well as gas quality. Production heterogeneity itself serves as an indicator to the origin of fluid and helps one determine protocol for developing delinearized history of petroleum.
Conventionally, reserve growth has been attributed to homogeneity of production history as well as reservoir rocks. It is perceived that reserve growth in existing fields is most predictable for those in which reservoir heterogeneity is low and thus production differs little between wells, probably owing to relatively homogeneous fluid flow. In fields in which reservoirs are highly heterogeneous, prediction of future growth from infill drilling is notably more difficult. If the same criterion is used to determine potential reserve of unconventional gas or to characterize such reservoirs, one is faced with inherent flaws. Unconventional resources thrive in heterogeneous formations as well as fluids of previously undefined origins. As discussed in previous chapters and in previous sections of this chapter, scientific characterization is all about paradigm shift and the conventional paradigm places unconventional reserves at a disadvantage and falsifies predictions. This section is aimed at lifting that barrier and determining true potential of unconventional resources.
6.11.1. Reserve Growth Potential of Unconventional Gas
Historically, the majority of additions to oil and gas reserves are attributed to growth of existing fields and reservoirs. In fact, from 1978 to 1990, growth of known fields in the United States accounted for more than 85% of known additions to proven reserves (Root and Attanasi, 1993; McCabe, 1998). Thus, field growth and reserve growth are essentially synonymous for discussions of domestic resources. The exception occurred when unconventional resources became exploitable. However, it would be illogical to apply the principle of conventional reserve growth to unconventional reserves that have little in common with the conventional reserves in terms of technology. Even though, it is promoted that unconventional gas and oil are of lesser quality and are in need of more expensive technology for future development, previous chapters demonstrated that notion to be false. In fact, the quality of gas improves as the quantity of the resource increases, the case in point being hydrate. It is also true, vast amount of unconventional gas can be exploited with little or no exploration. In addition, many existing conventional reservoirs have links to unconventional resources and even the abandoned fields can be accessed for tapping the unconventional resources.
While evaluating the nature of growth in fields requires understanding of both geologic and nongeologic factors that affect growth estimations, geology is the pivotal factor in determining accumulation, quality, and producibility of petroleum resource. Fields may grow when
1. additional geologic data on existing reservoirs become available and are used to identify new reservoirs or to guide infill drilling;
2. there are annual updates of reserves data;
3. field boundaries are extended;
4. recovery technology is improved; and/or
5. nongeologic factors such as economics, reporting policies, or politics favor expanded production and development.
Past reserve estimates and characterization both used mathematics and not science as the basis. Attanasi et al. (1999) wrote:
“…the modeling approach used by the USGS (U.S. Geological Survey) to characterize this phenomenon is statistical rather than geologic in nature.”
Islam et al. (2010) discussed in details the short-comings of these statistical models and characterized them as unscientific. Yet, volumetric estimates of reserve growth are calculated by using these mathematical approaches and large data bases that record field reserves through time. Crovelli and Schmoker (2001), Verma (2003), and Klett (2003) present details of various methods used to estimate reserve growth. Application of these models to unconventional gas is of particular concern. It is because one of the most important basis for statistical models is the past history, which is practically nonexistence for unconventional reserves.
Geologists tend to think in terms of entire reservoirs, in some cases down to facies level, whereas reservoir engineers deal with measurements at the wellbore. To fully understand the geologic factors that affect growth in reserves, this gap in investigative approaches must be bridged. It has become increasingly important to integrate different scales and different observational techniques as secondary and tertiary recovery methods are applied more frequently in mature petroleum provinces.
Fluid-flow pathways, governed predominantly by rock porosity and permeability, are a reflection of heterogeneities of varying scales within a reservoir. Because these reservoir heterogeneities are fundamentally geologic in 2nature (Hamilton et al., 1998; Dyman et al., 2000), an adequate understanding of the reservoir architecture, obtained through evaluation of geologic, engineering, or production data, or a combination of these data sets, can provide the basis for scientific characterization of unconventional gas reservoirs.
Proper estimates and growth potential of unconventional gas depends on geological classification and linking of conventional resources with unconventional ones through scientific characterization. This is done in the following sections.
6.11.2. Reservoir Categories in the United States
US Geological Survey (2008) evaluated the geologic factors that affect reserve growth in both siliciclastic (largely sandstone) and carbonate (lime- stone and dolomite) reservoirs. This study included 10 formations in the United States (one of which extends into southern Canada) that represent various depositional environments in both siliciclastic and carbonate settings. This is shown in Table 6.24.
Reservoirs were then categorized based on geological criteria, such as source rock, depositional setting, and postdepositional alteration. The following environments were studied:
1. Eolian environments—Norphlet Formation of the Gulf of Mexico Basin (Figure 6.40) and Minnelusa Formation of the Powder River Basin (Figure 6.41);
2. Interconnected fluvial, deltaic, and shallow marine environments—Frio Formation of the Gulf of Mexico Basin (Figure 6.42) and Morrow Formation of the Anadarko and Denver Basins (Figure 6.41);
Table 6.24
Depositional Environments and Rock Units Selected for Study of Reserve Growth, and Geologic Age and General Location of Units
3. Deeper marine environments—Barnett Shale of the Fort Worth Basin (Figure 6.42) and Bakken Formation of the Williston Basin (Figure 6.41);
4. Marine carbonate environments—Ellenburger Group of the Permian Basin (Figure 6.42) and Smackover Formation of the Gulf of Mexico Basin (Figure 6.40);
5. Submarine fan environment—Spraberry Formation of the Midland Basin (Figure 6.42); and
6. Fluvial environment—Wasatch Formation of the Uinta-Piceance Basin (figure 6.41).
6.11.2.1. Eolian Reservoirs
6.11.2.1.1. Norphlet Formation
The Middle to Upper Jurassic Norphlet Formation of the Gulf of Mexico Basin consists largely of eolian sandstones, with minor black shale, conglomerate, and red beds; thicknesses are as much as 100 ft. The Norphlet produces oil and gas largely in Alabama, offshore in Mobile Bay, and in Mississippi (Figure 6.40). Principal reservoirs in the Norphlet are eolian sandstones (Table 6.25), which are known to have excellent porosity (as much as 20%) and permeability (as much as 500 mD).
Figure 6.40 Gulf of Mexico Basin region, the petroleum-producing region of the Norphlet and Smackover Formations. Both formations produce in both onshore and offshore locations; the Norphlet produces from Mobile Bay. From USGS, 2008.
As can be seen from Table 6.25, broad similarities in reservoir characteristics throughout the area of production suggest that only a single reservoir category is warranted. This reservoir was considered to be a single one with homogeneous rock and fluid properties. While such reservoir is not considered to be a source of unconventional gas, this reservoir offers the least expensive access to vast resource that is not conventionally included in all analyses. For instance, any cutoff point of shale in shale breaks or caprocks eliminate as much as 10% of the reserve that lies within low-permeability, low effective-porosity formations. As conventional reserves become insensitive to infill drilling or other means (including enhanced oil/gas recovery), the potential of unconventional gas increases. Figure 6.43 shows general trend in reserve for conventional reservoirs. Previously, extensive exploration has kept the growth part active. In United States, however, main contributor to reserve growth has been infill drilling and enhanced oil recovery. In the infill drilling scheme, one must acknowledge 90% of the new wells are horizontal. This means the role of horizontal well technology has been embedded in this reserve growth. However, despite best efforts the reserve will decline, particularly for the “homogeneous” formations.
Figure 6.41 General region from which petroleum is produced from formations discussed in this paper, including the Minnelusa (Powder River Basin), Morrow (Anadarko and Denver Basins), Bakken (Williston Basin), and Wasatch (Uinta and Piceance Basins) Formations. From USGS, 2008.
Figure 6.42 Area from which petroleum is produced from the Frio Formation, Barnett Shale, Ellenburger Group, and Spraberry Formation. Extent of depositional environments in the Frio (such as the Norias delta complex or the Buna barrier–strandplain) (From Galloway et al. (1982)). For the Barnett, the locations of the Llano uplift and Ouachita thrust belt mark the southern and eastern limits of the Fort Worth Basin, respectively. Horseshoe Atoll is a Pennsylvanian structure that effectively separates productive rocks of the Spraberry Formation (to the south) from nonproductive rocks (to the north). From USGS, 2008.
Figure 6.43 Three phases of conventional reserve.
For such reservoirs, a vast amount of unconventional reservoirs are associated and are accessible readily. This has been the case for shale gas as well as tight gas, as has been evidenced in recent gas boom in the United States. However, the use of horizontal wells and hydraulic fracturing as the sole mode of reservoir development will lead to similar stagnation as in conventional reservoirs (Figure 6.44). This can be given a boost by accessing reserve that was previously considered to be part of conventional reservoirs and was excluded through the use of “cutoff” points. The dotted line in Figure 6.44 shows how immediate boost can be invoked. This can be followed by subsequent use of enhanced gas recovery schemes, as outlined in previous chapters of this book. Ironically, the greatest potential for most economic recovery of unconventional gas lies within high productivity, “homogeneous” formations as exemplified in this category of Norphlet Formation.
Figure 6.44 Unconventional reserve growth can be given a boost with scientific characterization.
Table 6.25
Norphlet Formation, Gulf of Mexico Basin—Summary of Geological Characteristics and Reserve Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Norphlet | Sand sea | Eolian sands | Overlying and interbedded marine shale and interdune sediments | Sandstone | Primary intergranular and secondary intergranular and moldic | Dissolution of early authigenic cements and authigenic chlorite | Local quartz, anhydrite, halite, illite. Intense quartz cementation may seal some accumulations | As much as 20% in onshore reservoirs and 12% in deeper offshore reservoirs |
| Reservoir characteristics–Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| Generally high; as much as 500 mD | May be complexity faulted | Overlying marine shale of Smackover Formation; interbedded or interfingering organic-rich shale in Norphlet Formation | Updip pinchout against basement complex | Overflying shale and interbedded interdune, sabkha, or playa units | Reservoir rocks thicken in basement controlled grabens and are absent or thin over basement controlled highs | Anticlines, faulted anticlines, faults associated with basement structures, and halokinesis of Louann Salt | Dominantly nonassociated gas (cracked) and minor oil |
6.11.2.1.2. Minnelusa Formation
The Pennsylvanian to Early Permian Minnelusa Formation of the Powder River Basin, northeastern Wyoming, consists largely of eolian sandstones, with minor shale and carbonate; thicknesses are as much as 1200 ft. Most production is in the north–central and northeastern parts of the basin; lesser production is in the southerly and southeastern parts (Figure 6.41). Principal reservoirs are the eolian sandstones (Table 6.26), which can have excellent porosity (as much as 47%) and permeability (as much as 830 mD).
Reservoirs in the Minnelusa Formation are placed into two categories, Minnelusa and Leo (Table 6.26). This twofold division was necessary because of differences in stratigraphic position, depositional environment, and geographic distribution of producing wells; in addition, reservoirs in the two categories may have different source rocks. Reservoir rocks of the Leo category have been variously referred to by previous workers as the “Leo sandstone” (Hunt, 1938), “Leo section” (Desmond et al., 1984), “Leo Formation” (Morel et al., 1986), or the “Leo sandstone of the Minnelusa Formation” (Dolton and Fox, 1995).
Table 6.26
Minnelusa Formation, Powder River Basin—Summary of Geological Characteristics and Reserve Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Minnelusa | Coastal sand sea | Eolian dunes | Overlying shallow marine shales, anhydrite, and carbonate rocks | Sandstone, quartz arenite, sublitharenite | Primary and secondary intergranular; moldic | Dissolution of early authigenic cements and of some unstable denial grains | Quartz, carbonates minerals, and anhydrite/gypsum where not dissolved. Cemented zones may act as seals | Averages 12–24% but may be as high as 47% |
| Leo | Coastal dunes | Eolian dunes | Overlying shallow marine shales, anhydrite, and carbonate rocks | Sandstone, quartz arenite, sublitharenite | Primary and secondary intergranular; moldic | Dissolution of early authigenic cements and of some unstable denial grains | Quartz, carbonates minerals, and anhydrite/gypsum where not dissolved. Cemented zones may act as seals | Averages 12–24% |
6.11.2.2. Interconnected Fluvial, Deltaic, and Shallow Marine Reservoirs
6.11.2.2.1. Frio Formation
The Oligocene Frio Formation of the Gulf of Mexico Basin consists largely of sandstone and shale deposited in various environments; it is as much as 15,000-ft thick. The Frio produces largely from onshore and offshore locations in Texas. Principal reservoirs in the Frio are sandstones (Table 6.27), which are known to have good to excellent porosity (as much as 35%) and variable permeability (as much as 3500 mD).
Reservoir categories defined in the Frio Formation are fluvial, deltaic, strandplain-barrier, and shelf sandstones (Table 6.27). These four categories were selected principally because reservoirs within them differ in terms of their broad depositional and geographic settings, structural setting, proximity to structures and potential source rocks, and reservoir characteristics.
These reservoirs contain thick shale deposits that are always excluded in conventional reserve calculations. However, these shales are the source of unconventional gas and are accessible through current development schemes. As these conventional resources are subject to enhanced oil recovery, unconventional resources should be considered because often such resources would contain higher saturation of oil and gas than the conventional reserve, particularly for matured reservoirs.
6.11.2.2.2. Morrow Formation
The Lower Pennsylvanian Morrow Formation of the Anadarko and Denver Basins consists largely of sandstone and shale; it is as much as 1500-ft thick. The Morrow produces oil and gas in Oklahoma, Texas, Kansas, and Colorado (Figure 6.41). Principal reservoirs in the Morrow are sandstones (Table 6.28), which are known to have good porosity (as much as 22%) and permeability (as much as several darcies).
Petroleum reservoirs in the Morrow Formation were placed into three categories—incised valley-fill, deltaic, and shallow marine (Table 6.28). These categories were selected because reservoirs within them differ in terms of their broad geographic and depositional setting. The differing depositional settings of the reservoir categories have led to differing reservoir-rock characteristics, such as porosity and permeability, which bear directly on the reservoir properties and contained resources. The shallow marine category offers the greatest potential for unconventional gas reserves. However, caprock of high-porosity reservoirs also contain large volume of natural gas.
Table 6.27
Frio Formation, Gulf of Mexico Basin—Summary of Geological Characteristics and Reserve Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Fluvial, chiefly the Gueydan and Chita/Corrigan fluvial systems | Chiefly fluvial with associated channel fill, point bar, crevasse splay, and floodplain sediments | Channel sands, point bars, and crevasse splay sands | Floodplain and lacustrine muds | Feldspathic litharenite, litharenite, and sublitharenite sandstone | Intergranular and moldic | Dissolution of unstable detrital grains and earlier formed cements, resulting in secondary pore space | Quartz, calcite, and clay cements; mechanical compaction | 15–35% |
| Deltaic; chiefly the Norias and Houston delta complexes | Delta-plain, delta-front, and delta-flank environments of a prograding continental margin in the Gulf Basin. Norias contains more sediment and more sand, and was less influenced by marine processes than Houston | Distributary channel, delta-front and delta-flank, and channel-mouth bar sands | Prodelta and shelf shales | Feldspathic litharenite, litharenite, and sublitharenite sandstone | Intergranular and moldic | Dissolution of unstable detrital grains and earlier formed cements, resulting in secondary pore space | Quartz, calcite, and clay cements; mechanical compaction | 10–35% |
| Strandplain-barrier; chiefly the Buna and Greta/Carancahua barrier strandplains | Shoreface, beach, barrier, and lagoonal deposits adjacent to deltaic depocenters | Shoreface, beach, and barrier sands | Marsh and lagoonal muds | Feldspathic Litharenite, litharenite, and sublitharenite sandstones | Intergranular and moldic | Dissolution of unstable detrital grains and earlier formed cements, resulting in secondary pore space | Quartz, calcite, and clay cements; mechanical compaction | 20–35% |
| Table Continued | ||||||||
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Shelf: off-shore Gulf Coast Basin | Shelf, slope, and perhaps submarine fan environments in deeper parts of the Gulf Coast Basin | Shelf, slope, and possibly fan sand-stones | Marine shales and siltstones | Feldspathic Litharenite, litharenite, and sublitharenite sandstones | Intergranular and moldic | Dissolution of unstable detrital grains and earlier formed cements, resulting in secondary pore space | Quartz, calcite, and clay cements; mechanical compaction | As much as 30% |
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| 20–1500 mD | Important in hydrocarbon migration from source to reservoir | Shales that underlie reservoirs | Gueydan system largely a single drainage; leads to stacked channels and lateral amalgamation of channels. Chita Corrigan largely multiple channels with somewhat less stacking of sands | Stratigraphic component of trap is the interval where facies change to mud-rich floodplain rocks; mud-rich rocks are seals | Production best where fluvial and splay sands cross anticlines, faulted anticlines, or growth-fault trends, and faults served as conduits for upward petroleum migration | Rollover anticlines, particularly on downdip side of Vicksburg growth fault | Oil and gas |
| Table Continued | |||||||
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| 10–2400 mD | Important in hydrocarbon migration from source to reservoir; also juxtapose reservoirs and seals | Shales that underlie or are basinward facies of reservoirs | Abundant sediment supply and single fluvial system input lead to vertically stacked sandy deltaic lobes (Norias), whereas Houston delta fed by several smaller fluvial systems that led to numerous small dispersed lobes with less continuous sands | Stratigraphic component of trap is at abrupt facies changes from reservoir to fine-grained rocks; mud-rich rocks are seals | Syndepositional movement on growth faults and salt diapirs but no thickening of deltaic sediments, including reservoir rocks | Anticlines and faulted anticlines, some of which are associated with growth faults (Noria and Houston) or salt diapirism (Houston); also growth faults juxtapose reservoirs with seals or compartmentalize reservoirs | Associated gas and oil from more proximal parts, and nonassociated gas from more distal parts |
| 8–3500 mD | Important in hydrocarbon migration from source to reservoir; also juxtapose reservoirs and seals | Shales that underlie or are basinward facies of reservoirs | Greater marine influence on Houston delta led to greater redistribution of sands into strandplain systems than on sands that originated in Norias delta | Stratigraphic component of trap is the interval where facies change to mud-rich floodplain rocks; mud-rich rocks are seals | Vertical stacking of sands and strike-parallel orientation of sands greatly influenced by orientation and movement of growth faults | Anticlines, rollover anticlines, and faulted anticlines | Associated gas and oil |
| As much as l500 mD | Important in hydrocarbon migration from source to reservoir; also juxtapose reservoirs and seals | Shales that interbed with or underlie reservoir rocks | Stratigraphic controls on reservoir location unclear | Stratigraphic component of trap is at abrupt change from reservoir to fine-grained rocks; fine-grained rocks serve as seals | Sediment accumulation in submarine canyons or intraslope basins that formed from active faulting or salt diapirs (or both) | Faulted anticlines and salt-related structures. Seals formed by fault-related juxtaposition of reservoirs with impermeable rocks | Largely gas |
Table 6.28
Morrow Formation, Anadarko and Denver Basins—Summary of Geological Characteristics and Reserve Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Incised valley fill | Braided streams that grade upward into meandering and estuarine environments | Dominantly in coarser grained fluvial sands that fill incised valleys | Floodplain, estuarine, and marine mud-stone | Sandstone; varies from quartz arenite to litharenite or arkosie | Intergranular; variable volume of moldic porosity due to dissolution of detrital grains | Secondary pore space from dissolution of early formed authigenic cements and some unstable detrital grains | Extensive cement in lower parts of channel sands with calcite or iron carbonate minerals, or both | 12–21% |
| Deltaic | Lower delta plain | Point bar, meander channel, stream-mouth bar, and distributary channel sands | Overbank, backswamp marsh, prodelta, and marine mudstone | Sandstone; varies from quartz arenite to litharenite or arkosie | Secondary pore space from dissolution of early formed authigenic cements and some unstable detrital grains | Late-stage calcite or iron carbonate minerals, or both | 12–22% | |
| Table Continued | ||||||||
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Shallow marine | Near-shore and marginal marine | Beach, barrier island, and shoreline parallel sandbar sands | Marine shale and siltstone | Sandstone; varies from quartz arenite to litharenite or arkosie; locally fossiliferous | Secondary pore space from dissolution of early formed authigenic cements and some unstable detrial grains | Late-stage calcite or iron carbonate minerals, or both; mechanical compaction | 4–20% | |
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seal | Reservoir location | Traps or seals | ||
| As much as several darcies | Could have helped hydrocarbons to migrate from any overlying or underlying sources | Possibly marine muds of the Morrow Formation, where mature in Anadarko Basin; other organic-bearing formations outside the Morrow | Downcutting and formation of palcovalleys localized fluvial channel-reservoirs, dominantly in upper part of Morrow | Underlying marine limestone or shale and overlying floodplain muds | Palcostructures and perhaps subsidence from dissolution of underlying evaporates may have localized areas of downcutting and incision | Anticlines may influence but are secondary to stratigraphic controls | Associated gas and oil |
| Table Continued | |||||||
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seal | Reservoir location | Traps or seals | ||
| 1–100 mD | Could have helped hydrocarbons to migrate from any overlying or underlying sources | Possibly marine muds of the Morrow Formation, where mature in Anadarko Basin; other organic-bearing formations outside the Morrow | Unclear | Lateral pinchout of sands into fine-grained marine muds | Unclear | Anticlines may influence but are secondary to stratigraphic controls | Dominantly gas |
| <1–200 mD | Could have helped hydrocarbons to migrate from any overlying or underlying sources | Possibly marine muds of the Morrow Formation, where mature in Anadarko Basin; other organic-bearing formations outside the Morrow | Location of sands in part a function of longshore currents, dominantly in lower part of Morrow | Lateral pinchout of sands into fine-grained marine muds | Unclear | Anticlines may influence but are secondary to stratigraphic controls | Dominantly nonassociated gas |
6.11.2.3. Deeper Marine Shales
6.11.2.3.1. Barnett Shale
The Middle to Late Mississippian Barnett Shale of the Fort Worth Basin, Texas, consists largely of black marine shales with some limestone; it is as much as 650-ft thick. Most production is of nonassociated gas, principally in the northeastern part of the basin (Figure 6.42). Reservoirs of this self-sourced unit are marine shales in the Barnett (Table 6.29), which have very low porosity (less than 6%) and extremely low permeability (a few nanodarcies).
Reservoirs in the Barnett Shale are grouped in a single category termed the shale (unconventional) category (Table 6.29). Until recently, the lower shale member has been the more productive, although considerable production is now being realized from the upper shale member as well (Bowker, 2002). Both members characteristically have a high content of organic material, which is largely Type–II (Jarvie et al., 2001; Hill et al., 2007). In general, the current average content of organic material in both members is four–5% (Jarvie et al., 2007), although in places the Barnett is thought to have contained as much as 20% total organic carbon when it was deposited (Bowker, 2002). The organic material serves as the source of the gas, thereby defining these reservoirs as self-sourced and unconventional.
This formation is characteristically categorized as unconventional gas reserve. However, this formation makes up for only a fraction of total unconventional reserve that would be evident through scientific characterization.
6.11.2.3.2. Bakken Formation
The Late Devonian to Early Mississippian Bakken Formation (of the Williston Basin of North Dakota, Montana, and the Canadian provinces of Saskatchewan and Manitoba (Figure 6.41)) consists largely of marine shale with minor sandstone; it is as much as 140-ft thick. The Bakken produces mostly oil, principally in North Dakota and Montana and lesser amounts in Saskatchewan and Manitoba. Reservoirs in the Bakken are principally marine shales, although smaller reservoirs are found in interbedded near-shore to shoreface sandstones (Table 6.30). Porosity of the shales is very low (typically less than 5%) as is their permeability (<0.01–60 mD). Porosity of sandstone reservoirs is higher (as much as 10%) as is permeability (<0.01–109 mD).
Table 6.29
Barnett Shale, Fort Worth Basin—Summary of Geological Characteristics and Reserve-Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Shale (unconventional) | Offshore marine | Marine shale | Dense limestone | Organic-rich shale | Matrix, but very low | Uncertain | Calcite along fractures | Very low, typically <6% |
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | ||||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | |||
| Very low, typically in the range of nanodarcies | Naturally fractured in deeper parts of basin and over structures; fractures reduce productivity | Organic-rich shale in the Barnett that also serves as reservoir rock | Uncertain | Gas trapped by fine grained nature of shale reservoir | Best production away from fractured areas | Open faults tended to leak gas out of formation, whereas calcite filled faults prevented gas migration | Non-associated gas | |
Table 6.30
Bakken Formation, Williston Basin—Summary of Geological Characteristics and Reserve-Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Shale (unconventional) | Deep marine, below wave base | Black, organic-rich mudstone | Overlying shallow marine carbonates and shales | Black mudstone | Fracture | Little or none | Little or none | Very low, typically <5% |
| Siltstone-sandstone (unconventional) | Near-shore and shoreface | Siltstone and very fine to medium-grained sandstone | Enclosing black mudstone | Dolomitic siltstone and sandstone | Fracture | Dissolution of carbonate cement | Carbonate cement | Can be >10% but typically 3–10% |
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| <0.0l–60 mD | Critical for production | Black, organic-rich mudstone; is also the reservoir rock | Apparently not important | Apparently not important | Fracture zones overlying anticlinal or monoclinal folds and solution fronts in underlying salts | Minimal; reservoirs unconventional | Oil |
| Table Continued | |||||||
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| <0.01–109 mD | Critical for production | Organic-rich mud in Bakken, interbedded with or perhaps downdip from reservoirs | Local thickening owing to subsidence associated with dissolution of underlying salts | Overlying shales of the Bakken | Fracture zones overlying anticlinal or monoclinal folds and solution fronts in underlying salts | Updip against enclosing mudstone strata | Oil |
Two categories of reservoirs were defined in the Bakken Formation—shale (unconventional) and siltstone sandstone (unconventional) (Table 6.30). These two categories were selected because they have different characteristics, stratigraphic positions, and geographic distributions. In each, however, the petroleum is thought to be generated within the Bakken, so both categories are considered to be unconventional, similar to those in the Barnett Shale. Recent success in producing from these unconventional sources with conventional technology (e.g., horizontal well and fracturing) point out that there is tremendous potential for expanding this resource base.
6.11.2.4. Marine Carbonate Reservoirs
6.11.2.4.1. Ellenburger Group
The Early Ordovician Ellenburger Group of the Permian Basin (Figure 6.43) consists largely of marine carbonate rocks; the group is as much as 1500-ft thick. Units in the Ellenburger produce oil and gas chiefly in Texas. Principal reservoirs in the Ellenburger are in karstified parts of a carbonate platform and in dolomitized carbonate muds (Table 6.31). Reservoirs in karstified rocks have low but variable porosity (2–7%) and moderate but variable permeability (2–750 mD). Reservoirs in dolomitized muds have higher porosity (2–14%) but lower permeability (1–44 mD) than karstified reservoirs.
Reservoirs in the Ellenburger Group are placed into three categories (Table 6.31)—karstified, platform, and tectonically fractured—based primarily on differences in the nature and volume of porosity and permeability, geographic distribution, produced petroleum, and the degree to which structure influenced reservoir development. This threefold division is similar to that presented by others (Kerans et al., 1989; Kosters et al., 1989c; Holtz and Kerans, 1992) and is also consistent with that presented by Ball (1995). This is the category rarely connected to unconventional gas. However, significant amount of oil and gas exists within such reservoirs that fit the description of unconventional oil and gas, including in low-permeability patches, caprock, and volcanic rocks. Some of these resources are in high pressure and temperature conditions. They form a special candidate for reverse thermal recovery. It involves injection of cold water in order to induce thermal fracturing owing to large temperature gradient. In most reservoirs, this is easy to accomplish. These formations typically are not suitable for hydraulic fracturing for reasons described in previous chapters.
Table 6.31
Ellenburger Group, Permian Basin—Summary of Geological Characteristics and Reserve-Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Karstified, principally in Central Basin platform and Midland Basin | Shallow aggrading marine carbonate platform | Inner platform | Reef, forereef, supratidal | Dolo mitized mudstone | Interbreccia fragment and within fractures | Dissolution of lime mud leading to karstification and brecciation; intercrystalline owing to dolomitization of muds | Late-stage saddle dolomite | Average, 3% Range, 2–7% |
| Platform, dominantly in southern and eastern pans of Midland Basin | Shallow aggrading marine carbonate platform | Middle to outer platform | Reef, forereef, Supratidal | Dolomitized packstone and muds tone | Intercrystalline | Intercrystalline porosity owing to dolomitization | Late-stage saddle dolomite | Average, 14% Range, 2–14% |
| Table Continued | ||||||||
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Tectonically fractured, dominantly in the eastern Delaware Basin | Shallow aggrading marine carbonate platform | Inner platform | Reef, forereef, supratidal | Dolomitized mudstone | Fracture (tectonic) | Dissolution of lime mud leading to karstification and brecciation; intercrystalline owing to dolomitization of muds | Late-stage saddle dolomite | Average, 4% Range, 1–8% |
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| Mean, 32-mD Range, 2–750 mD | Channeled pore fluids that allowed vertical infiltration of dissolving waters into various stratigraphic horizons to promote karstification | Overlying Ordo vician Simpson Group | Lime muds remaining after early dolomitization, which became horizons subject to dissolution leading to karstification | Traps and seals include overlying Simpson Group and unkarsted Ellenburger dolomite. Seals also include impermeable cave-fill sediments and collapse zone adjacent to reservoirs | Anticlines, faulted anticlines, and fault-bounded anticlines | Uncertain | Principally oil with some associated gas and gas condensate |
| Table Continued | |||||||
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| Average, 12-mD range, <1–44 mD | Focused early dolomitizing fluids, which resulted in intercrystal-line porosity and permeability | Overlying Devonian Woodford Shale? | Lime muds that were dolomitized | Traps and seals include overlying Simpson Group | Anticlines, faulted anticlines | Uncertain | Largely oil |
| Average, 4-mD range, 1-100 mD | Early fracturing promoted karstification, whereas later fracturing improved porosity and permeability of the reservoir | Overlying Ordovician Simpson Group | Lime muds that were dolomitized | Traps and seals include overlying Simpson Group | Fractured anticlines and faults critical | Uncertain | Nonassociated gas |
6.11.2.4.2. Smackover Formation
The Upper Jurassic Smackover Formation in onshore parts of Texas, Arkansas, Louisiana, Mississippi, Alabama, and Florida, as well as offshore in the Gulf of Mexico Basin, consists largely of carbonate rocks with minor black shale and siltstones; it is as much as 1000-ft thick. Most oil and gas is produced from onshore locations in the above-listed states (Figure 6.40). Principal reservoirs in the Smackover are in carbonate rocks deposited in a ramp setting (Table 6.32) that have good to excellent porosity (as much as 35%) and variable permeability (<1–4100 mD). Reservoir categories in the Smackover Formation are salt structure, basement structure, graben, stratigraphic, and updip fault (Table 6.32). These categories, which were defined or later refined through regional studies by other workers (for example, Bishop, 1973; Collins, 1980; Moore, 1984; Mancini et al., 1990; Kopaska-Merkel and Mann, 1993; Tew et al., 1993) were selected because of differences in their geographic extent and in the role that structures played in both source-rock deposition and petroleum trapping.
This type of formations is not typically considered to generate unconventional gas. However, significant amount of gas is present in these formations in caprcoks, salt domes, and other locations. Salt domes have not been included in this book as a source of potential unconventional gas. However, they do contain natural gas in many instances and each case should be investigated in order to access unconventional gas with minimal cost (see for instance, Dronkert and Remmelts, 1996).
6.11.2.5. Submarine Fan Reservoir
6.11.2.5.1. Spraberry Formation
The Early Permian Spraberry Formation of the Midland Basin consists largely of turbiditic sandstones, with minor black shales, silty dolostones, and argillaceous siltstones; it is as much as 1000-ft thick. Most production of oil is in west-central Texas, in the Midland Basin (Figure 6.42). Principal reservoirs in the Spraberry are the tubiditic sandstones (Table 6.33), which have good porosity (as much as 18%) but relatively low permeability (maximum, 10 mD). A single reservoir category, submarine sand, was defined for the Spraberry Formation.
Table 6.32
Smackover Formation, Gulf Coast region—Summary of Geological Characteristics and Reserve-Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Salt structure. dominantly in southern and eastern Texas, southern Arkansas, southern and central Mississippi, southwestern Alabama, and northern Louisiana | Slow regressive to stillstand marine carbonate ramp | Ramp, higher energy shoaling facies | Subtidal mudstone, wackestone, supratidal units, and outer ramp dolostones | Largely dolomitic oolitic grainstones and packstones | Dominantly intercrystalline where dolomitized, oomoldic in, updip regions, intergranular in basinal regions | Intercrystalline owing to dolomitization; ooid dissolution; late calcite dissolution; diagenesis most pronounced on structural highs | Late-stage saddle dolomite, anhydrite, and calcite | 2–35% |
| Basement structure, primarily in eastern Texas, central Mississippi, southern Arkansas, and southwestern Alabama | Slow regressive to stillstand marine carbonate ramp | Ramp, higher energy shoaling facies | Subtidal mudstone, wackestone, supratidal units, and outer ramp dolostones | Largely dolomitic oolitic grainstones and packstones | Principally oomoldic; minor primary interparticle and intercrystalline where dolomitized | Principally oomoldic; minor intercrystalline owing to minor dolomitization; diagenesis pronounced on structural highs | Late-stage calcite and dolomite | As much as 20% |
| Table Continued | ||||||||
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Graben, principally along Arkansas–Louisiana border | Slow regressive to stillstand marine carbonate ramp | Ramp, higher energy-shoaling facies | Subtidal mudstone, wackestone, supratidal units, and outer ramp dolostones | Oolitic limestone, locally dolomitic | Considerable interparticle pore space preserved; also oomoldic | Some interparticle and intercrystalline owing to dolomitization; some oomoldic | Partial cementation by calcite | 4–19% |
| Stratigraphic, principally in southern Arkansas | Slow regressive to stillstand marine carbonate ramp | Ramp, higher energy shoaling facies | Subtidal mudstone, pelloid packstone, wackestone, supratidal units, and outer ramp dolostones | Oolitic, oncolitic, or skeletal, grainstone limestone minimally dolomitized | Considerable interparticle; some oomoldic and intercrystalline where dolomitized | Some inter particle and intercrystalline owing to dolomitization; considerable early- and late-stage dissolution of particles and late-stage cement | Cements such as early and late stage calcite and anhydrite; some compaction | 3–30% |
| Updip fault, principally in eastern Texas, southern Arkansas, central Mississippi, southwestern Alabama and Florida Panhandle | Slow regressive to stillstand marine carbonate ramp | Ramp, higher energy shoaling facies | Subtidal mudstone, wackestone, supratidal units, and outer ramp dolostones | Oolitic limestone, locally dolomitic | Principally oomoldic | Ooid dissolution common; some dolomitization | Early calcite cement | 10–20% |
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| <1–4100 mD | Large-scale open fractures not now widespread: however, fractures probably served as conduits for hydrocarbon migration | Organic-rich units in lower part of Smackover Formation | Shoaling sequences best developed on positive features formed by salt diapirism during deposition | Fine-grained beds in overlying Buckner Formation acted as seals | Salt anticlines, faulted salt anticlines, faulted salt-pierced anticlines | Faults seal some reservoirs | Dominantly oil and associated gas with minor condensate |
| 60–350 mD | Faults now act as seals owing to impermeability of fault zones but earlier probably served as conduits for hydrocarbon migration | Organic-rich units in lower part of Smackover Formation | Facies changes up on basement highs; shoaling on positive basement highs during deposition. Little evidence of halokinesis | Stratigraphic and structural trap with overlying Buckner Formation; pinchouts on basement highs serve as seals | Regional fault zones, anticlines, faulted anticlines | Downdip fault zone served as reservoir seal | Dominantly oil in updip areas; associated gas or gas condensate in basinal areas |
| <1–1000 mD | Faults now act as seals owing to impermeability of fault zones but earlier probably served as conduits for hydro-carbon migration | Organic-rich units in lower part of Smackover Formation | Shoaling sequences best developed on horst blocks adjacent to grabens | Structural and stratigraphic trap; overlying Buckner Formation serves as seal | Fault zones and faulted anticlines | Faults seal some reservoirs | Dominantly oil |
| Table Continued | |||||||
| Reservoir characteristics—Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| 1–250 mD | Faults probably- served as conduits for hydrocarbon migration | Organic-rich units in lower part of Smackover Formation | Facies changes and regressive units overlying reservoirs | Structural and stratigraphic trap; overlying Buckner Formation serves as seal | Likely; structures limited deposition of reservoir rocks or facilitated pinchouts | Faults seal some reservoirs | Dominantly oil; some associated gas |
| 3–280 mD | Faults now act as seals owing to impermeability of fault zones but earlier probably served as conduits for hydrocarbon migration | Organic-rich units in lower part of Smackover Formation | Near updip limit of Smackover deposition | Dominantly structural trap; fault systems serve as seals | Uplift on faults juxtaposed reservoirs and impermeable beds | Fault zones | Dominantly oil; some gas or gas condensate |
Table 6.33
Spraberry Formation, Midland Basin—Summary of Geological Characteristics and Reserve-Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Submarine sand | Deep water submarine basin and fan | Submarine fan and turbidite sandstone | Silty dolostone, organic-rich shale, and argillaceous sandstone | Sandstone | Largely intergranular but some minor moldic | Dissolution of preexisting authigenic cements and unstable detrital grains | Mechanical compaction and authigenic cements such as illite, chlorite, quartz, and dolomite | Matrix porosity usually 5–15% but may be as high as 18% |
| Reservoir characteristics–Continued | Source rock | Stratigraphic controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| Average matrix permeability low, <1 mD, but may be as high as 10 mD | Very common; multiple orientations observed; fractures cemented to various degrees | Interbedded organic-rich shales | Most reservoirs downdip from the ancient Horseshoe Atoll at mouth of sub-marine canyons or where facies change from channel to interchannel deposits | Pinchouts of reservoir rocks updip and downdip into fine-grained rocks serve as traps. Shales seal reservoirs | Uncertain | Mostly stratigraphic traps; one small field on an anticline | Largely oil |
Even though not explicitly recognized, these reservoirs form an excellent candidate for unconventional gas. These are thick formations that can have very high reserve once the cutoff point for porosity is removed.
6.11.2.6. Fluvial Reservoir
6.11.2.6.1. Wasatch Formation
The Paleocene–Eocene Wasatch Formation of the Uinta-Piceance Basin of Utah and Colorado consists largely of overbank and lacustrine mudstones with some fluvial and fluvial-dominated deltaic sandstones; it is as much as 5000-ft thick. The Wasatch produces oil and associated gas mostly in the Uinta Basin of northeastern Utah, although minor gas is also produced in the Piceance Basin of Colorado (Figure 6.41). Principal reservoirs in the Wasatch are the fluvial sandstones (Table 6.34), which are known to have good porosity (maximum, 15%) but low permeability (maximum, 40 mD).
Reservoirs in the Wasatch Formation are categorized as Green River source and Mesaverde source (Table 6.34). The two categories are distinguished by (1) the source of the petroleum produced from each, (2) the nature of the petroleum produced from each, and (3) the geographic distribution of production. This division is important because it recognizes that petroleum produced from the Wasatch comes from two different source rocks; hence, two petroleum systems generated economic amounts of petroleum within the greater Uinta-Piceance Basin.
In addition to unconfirmed patches of unconventional plays, these formations contain three types of continuous-type unconventional sources. They are (Spencer, 1995)
• oil in fractured Upper Cretaceous marine shale;
• gas in tight sandstone;
• coalbed methane.
Other unconventional gas may be present in heavy oil and tar sand formations.
6.11.3. Quantitative Measures of Well Production Variability
Production history offers a powerful tool for scientific characterization of a formation. It is not because it offers refinement of statistical tools, but because any history is evidence that can be used to refine a scientific model. USGS (2008) produced a detailed analysis of production history. This analysis was aimed at identifying origin of both fluid and rock systems. This report (USGS, 2008) compared historical well production data of the five formations by use of proprietary information. In addition, it considered data from two specific reservoir categories in the Ellenburger Group (karst and platform, Table 6.35), which are based on gross geologic differences, to evaluate the possible intraformational variability in production within that formation. Because in most wells production declines exponentially or hyperbolically as a function of time, cumulative production from older wells (those for which current monthly production is less than 10% of initial monthly production) asymptotically begins to approximate ultimate recovery. This is typical of conventional reserve analysis. In such wells, variations in cumulative production reflect variations in the volume of reservoir rocks accessed by the wellbore. The slopes of the probability distributions for cumulative production (Figure 6.45) are direct indicators of the variability as shown by the data set. For example, steeper slopes reflect greater production heterogeneity (Figure 6.45), whereas a horizontal line represents uniform production characteristics. A dimensionless parameter that is proportional to the slopes of the four probability distributions of Figure 6.45 would provide a quantitative numerical representation of production heterogeneity. Such a parameter, referred to here as a variation coefficient (VC), can be calculated by using a measure of the dispersion (range) of the data set divided by a measure of central tendency such as the mean or the median (Stell and Brown, 1992; Dyman et al., 1996; Schmoker, 1966; Dyman and Schmoker, USGS Report, 2008).
Table 6.34
Wasatch Formation, Uinta-Piceance Basin—Summary of Geological Characteristics and Reserve-Growth Potential of Reservoirs
| Reservoir category | Depositional characteristics | Reservoir characteristics | ||||||
| Environment | Reservoir facies | Nonreservoir facies | Lithology | Porosity (bulk rock) | ||||
| Principal pore space | Diagenetic enhancement | Diagenetic occlusion | Porosity | |||||
| Green River source | Fluvial, deltaic, and lacustrine | Fluvial, channel sandstone, and sands deposited in lacustrine deltas | Overlying and interbedded overbank, floodplain, delta plain, and lacustrine mudstone and claystone | Sandstones, lithic arkoses, or feldspathic litharenites | Intergranular, principally secondary; some minor moldic | Dissolution of early authigenic cements and unstable detrital grains | Some quartz and carbonate cements and authigenic clays | Ranges up to 15% at shallow (<4000 ft) depths but <10% at greater depths (>8500 ft) |
| Mesaverde source | Fluvial, deltaic, and lacustrine | Fluvial, channel sandstone, and sands deposited in lacustrine deltas | Overlying and interbedded overbank, floodplain, delta plain, and lacustrine mudstone and claystone | Sandstones, lithic arkoses, or feldspathic litharenites | Intergranular, principally secondary; some minor moldic | Dissolution of early authigenic cements and unstable detrital grains | Some quartz and carbonate cements and authigenic clays | Ranges up to 15% at shallow (<4000 ft) depths but <10% at greater depths (>8500 ft) |
| Reservoir characteristics–continued | Source rock | Stratigraphics controls | Structural controls | Oil or gas | |||
| Permeability | Fractures | Reservoir location | Traps or seals | Reservoir location | Traps or seals | ||
| Generally low; as much as 40 mD but commonly <0.1 mD | Reservoirs may be complexly faulted; faults allow production | Organic-rich lacustrine mad-stones of Green River Formation, which largely interfingers with the Wasatch | Reservoir rocks deposited adjacent to and in deltas within ancient Lake Uinta | Overlying and interbedded shales, mudstones, and claystones trap and seal reservoirs | Uncertain | Secondary to stratigraphic traps or seals | Dominantly oil; some associated gas |
| Generally low; as much as 40 mD but commonly <0.1 mD | Reservoirs may be complexly faulted; faults allow production; migration along fractures | Coals and organic-rich shale of the Mesaverde Group, which underlies the Wasatch | Reservoir rocks deposited adjacent to and in deltas within ancient Lake Uinta | Overlying and interbedded shales, mudstones, and claystones trap and seal reservoirs | In areas where gas could migrate up fractures that cut from source to reservoir rocks | Secondary to stratigraphic traps or seals | Nonassociated gas |
The different parts of the distribution behave differently—that is, a single straight-line fit does not adequately describe the behavior of the entire distribution of production data. Of interest from conventional perspective is the central part of the distribution because it represents production from the vast majority of wells. Extreme production behavior, categorized by wells in the upper 5 and lower 20 percent of the production distribution, forms excellent candidates for unconventional recovery. They either include old wells that would invariably have vast gas content that is deemed uneconomical with conventional analysis or they include low-permeability formation, suitable for unconvetional gas development.
Figure 6.46 lists wells that were sorted by production from lowest to highest and subdivided into two size classes: a central class representing a productive range of 20–60% along the distribution and an upper class representing a productive range of 80–95%.
Figure 6.46 shows fields producing oil from the reservoirs representing the (1) fluvial category of the Frio Formation, (2) incised valley-fill category of the Morrow Formation, (3) Green River–source category of the Wasatch Formation, (4) Minnelusa category of the Minnelusa Formation, and both the (5) platform and karst categories of the Ellenburger Group. Table 6.35 contains the basic data used in calculating production variability for each reservoir category. A minimum of 35 producing wells were used to describe the production behavior for each category and to calculate upper class and central class rates of recovery and slope ratios for each. We also identified a well productive life of at least 10 years on the basis of data in the IHS Energy Group production file. For example, 6301 wells were selected from IHS data as Frio Formation producers in all or parts of Starr, Hidalgo, Brooks, Jim Hills, and Kleburg Counties, Texas (Table 6.35). A computer program then calculated upper and central class rates of recovery and slope ratios on the basis of a subset of these wells that met our selection criteria. The six reservoirs analyzed have produced more than 2 billion bbl of oil and 12 trillion cubic feet of gas from nearly 13,000 producing wells. The results are plotted in Figure 6.46. Of interest is the role of depositional environment, diagenesis, and lithology on reservoir productivity. Comparing the slope ratios and variation coefficients of reservoirs with different geologic characteristics may provide insight into productivity analysis and ultimately into estimating field growth through time. An opposite trend will be followed by unconventional oil and gas. Whenever conventional resources hit stagnation, unconventional resource potentials increase.
Figure 6.45 Probability distributions for production from wells of an oil or gas field (distributions based on hypothetical data—peak monthly production, peak yearly production, or cumulative production). Each point represents a well, and four fields (VC1–VC4) are depicted. In this type of plot log normal distributions plot as straight lines, and steeper slopes of lines correspond with a greater range of production and thereby greater production variability. The variation coefficient VC = (F5–F95)/F50 provides a dimensionless numerical value for the variability of each data set, and its value increases as slope increases. From USGS, 2008.
Table 6.35
Location of, Number of Fields and Wells in, Cumulative Production of, and Largest Fields in Each Reservoir Category Analyzed in This Study
| Reservoir category | Location | No. fields | No. wells | Cum. oil (MMBO) | Cum. gas (BCF) | Largest oil fields | Cum. oil (MMBO) | Cum. gas (BCF) |
| Frio | Texasa | 272 | 6301 | 534.4 | 11,193.0 | Seeligson | 238.1 | 2306.0 |
| Tijerina-Canales-Blucher | 87.0 | 753.8 | ||||||
| Stratton | 41.8 | 1841.5 | ||||||
| Morrow | Coloradob | 38 | 386 | 74.7 | 116.8 | Arapahoe | 23.2 | 35.7 |
| Mt. Pearl | 13.6 | 41.2 | ||||||
| Sorrento | 12.6 | 8.5 | ||||||
| Wasatch | Utahc | 24 | 436 | 89.9 | 139.2 | Altamont | 48.6 | 74.5 |
| Bluebell | 34.9 | 48.6 | ||||||
| Cedar Rim | 4.4 | 6.6 | ||||||
| Ellenburger (karst) | Texasd | 141 | 2784 | 1155.8 | 1042.5 | Andector | 178.4 | 70.2 |
| TXL | 129.3 | 29.8 | ||||||
| Pegasus | 96.3 | 361.2 | ||||||
| Ellenburger (ramp) | Texase | 134 | 928 | 65.0 | 29.0 | Barnhart | 16.7 | 11.9 |
| Swenson-Barron | 5.8 | 1.2 | ||||||
| Swenson-Garza | 4.2 | 0.7 | ||||||
| Minnelusa | Wyomingf | 315 | 1936 | 586.8 | 14.9 | Raven Creek | 44.2 | 0.03 |
| Timber Creek | 16.2 | 1.2 | ||||||
| Dillinger Ranch | 16.2 | 1.6 |
Figure 6.46 Production data of gas wells in fields in the Ellenburger Group karst and platform categories, Frio Formation fluvial category, Morrow Formation incised-valley category, Minnelusa Formation Minnelusa category, and Wasatch Formation Green River–source category. From USGS, 2008.
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