Tight-Gas Sandstone Reservoirs: The 200-Year Path from Unconventional to Conventional Gas Resource and Beyond
Published:December 01, 2009
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James Coleman, 2009. "Tight-Gas Sandstone Reservoirs: The 200-Year Path from Unconventional to Conventional Gas Resource and Beyond", Unconventional Energy Resources: Making the Unconventional Conventional, Tim Carr, Tony D’Agostino, William Ambrose, Jack Pashin, Norman C. Rosen
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The evolution of tight-gas sandstones from unconventional to conventional gas reservoirs in the United States began with hydrocarbon exploration and production from the Appalachian Basin during the first half of the 19th century, when brines were the preferred product, and petroleum was the unconventional and generally undesired product. During the next 100 years, rapid development of petroleum extraction and delivery technology fed an increase in petroleum demand, such that low flow-rate reservoirs were uneconomic and unable to meet the national need. These low-flow rate reservoirs were rejected in favor of high flow-rate reservoirs in California, the Midcontinent, and the Gulf Coast. Even then, vast amounts of natural gas were flared off or vented, because no market existed for much of this produced gas.
With each successful discovery from these areas, the U.S. natural gas supply progressively exceeded demand and pipeline deliverability throughout the first half of the 20th century. In response to the “energy crisis” of the 1970’s, the Federal government removed price controls on interstate natural gas in 1978 and created new tax incentives in 1980 to help offset the cost of drilling and producing unconventional gas reservoirs, including tight-gas sandstones. These decisions helped spawn a new industry and prompted geoscien-tists to examine the geological conditions that created and preserved large volumes of natural gas in low-permeability reservoirs.
Tight-gas sandstone reservoirs exist in a wide variety of settings, ranging from simple one-well accumulations to complex montages of multilayered sand bodies requiring thousands of wells to develop. They may have a reasonably well-defined geologic limit or appear to have no spatial association with any easily discernible mappable geologic phenomena. Understanding the true nature and future potential of yet-to-be-developed, tight-gas sandstone reservoirs is essential for the nation to supply its annual need for gas for the 21st century.
The author acknowledges and appreciates Al Taylor, Cathy Enomoto, Brian Horn, Sharon Swanson, and Kathie Rankin for their reviews of this manuscript. Appreciation is also extended to my colleagues at USGS and former colleagues at Amoco and BP for years of enlightening discussion on a subject that still is not completely clear and offers many opportunities for future discussions.
Before beginning our review of the history of tight-gas sandstone reservoir discovery and development, it would be instructive to review a few key definitions as used herein.
Conventional: conforming or adhering to accepted standards; ordinary rather than different or original (www.dictionary.com); as used in U. S. Geological Survey (USGS) National Oil and Gas Resource Assessments: resource accumulations having a delineated, downdip hydrocarbon - water contact; usually associated with reservoirs having porosity greater than ∼8 % and permeability greater than 0.1 mD (Finley, 1984; Gautier et al., 1995);
Unconventional: “not conventional; not bound by or conforming to convention, rule, or precedent; free from conventionality”(www.dictionary.com); as used in USGS National Oil and Gas Resource Assessments: resource accumulations not having a delineated, down-dip hydrocarbon - water contact; usually associated with reservoirs having porosity less than ∼ 8 % and permeability less than 0.1mD; often considered synonymous with “continuous” (defined below) as applied by USGS; however such reservoirs do not always have continuous reservoir characteristics (Finley, 1984; Gautier et al, 1995; Schmoker, 2005);
Continuous sandstones: Applied to accumulations that are commonly down dip from water-saturated strata, do not have an obvious trap and seal, have a pervasive oil or gas charge, a large areal extent, low matrix permeability, abnormal pressure (either high or low), and a close association with source rocks; commonly have a large in-place petroleum volume, a low recovery factor, the absence of truly dry holes, a dependence on fracture permeability, and sweet spots within the accumulation that have generally better production characteristics than non “sweet spot” areas; commonly containing little movable water in the rock matrix, but can produce copious volumes of water from fractures (Schmoker, 2005; see also Schmoker et al., 1996).
Tight-gas reservoir: a reservoir “in which the expected value of permeability to gas flow would be less than 0.1 mD”; “a reservoir that cannot be produced at economic flow rates nor recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal wellbore or multilateral wellbores” (Holditch, 2006, p. 86). The reservoirs can occur in sandstone, siltstone, and conglomerate, as well as limestone, dolomite, and chalk (Spencer, 1989).
Tight-gas sandstone reservoir or tight-gas sand (in this report): a reservoir composed primarily of quartz and (or) other lithic grains that are primarily sand-sized (Wentworth, 1922), with low porosity (commonly less than 10 %) and permeability (less than 0.1 mD) that normally cannot be produced over a moderate to long period of time (i.e., years to tens of years) at economic flow rates without natural fractures and (or) hydraulic fracture stimulation either through vertical, horizontal, or multilateral well bores.
Basin-centered gas accumulations: “regionally pervasive accumulations that are gas saturated, abnormally pressured (high or low), commonly lack a downdip water contact, and have low-permeability reservoirs” (Law, 2002, p. 1891). Law (2000) divides these accumulations into two categories: Direct and indirect, distinguished on the basis of source rock quality. A direct basin-centered gas accumulation has a gas-prone source rock, whereas an indirect basin-centered gas accumulation has an oil-prone source rock.
Historical Evolution of Tight-Gas Sandstone Reservoirs
The discovery of natural gas in low porosity and permeability sandstones in North America probably preceded the discovery of oil by European-Americans, as bubbling, flammable gas was known to be associated with salt water springs discovered in Virginia and Pennsylvania before the onset of the American Revolutionary War (Beebe and Curtis, 1968). Salt-water drillers frequently encountered natural gas when drilling on anticlines. Sometimes a well would have to be abandoned, because the flow of natural gas was too large or of too long a duration to be controlled safely and prevented recovery of the main product -- brine. Although considered a nuisance, it was clear that natural gas had some useful properties, and the first natural gas well was drilled in 1821 in western New York (Beebe and Curtis, 1968). This well did not produce from a sandstone reservoir; rather, it produced from a black shale interval, perhaps foreshadowing the current phase of unconventional gas reservoir exploration and development in shale gas reservoirs. Salt workers employed the gas associated with their salt-water production to power their machinery. By the end of the first half of the 19th century, wells were purposefully being drilled for natural gas to supply to local industries and cities for street illumination (Beebe and Curtis, 1968). When Colonel Edwin Drake drilled his famous “discovery” well in 1859 in Pennsylvania, natural gas was no longer viewed as a hazard or nuisance, but probably an economically viable natural resource.
At about the same time (1864), a chemistry student, Ascanio Sobrero, made the first batch of nitroglycerine in Italy (McElwee et al., undated). A fellow student, Alfred Noble, took the formula home to Sweden to try to figure out how to make and use the highly explosive substance, which, in 1867 would become the first widely used, tight-gas reservoir fracturing technology. During those years, exploration and drilling strategies were based almost completely on an operator’s judgment and experience. Even though Andrews (1861, 1866) and Hunt (1862, 1865, 1867) stated that the most prolific production would be achieved on anticlines having fractures hosting the majority of the petroleum, from 1859 to 1909 science played little role in deciding where and how to drill and complete a well. White (1885) reiterated Andrew’s and Hunt’s ideas and is generally given credit for the anticlinal theory of oil and gas accumulations, a credit he routinely denied (Howell, 1934). White also, almost casually, mentioned that “very fair gas-wells may also be obtained for a considerable distance down the slope from the crest of the anticlines” (White, 1885, p. 522). Yet, adherence to the anticlinal theory controlled exploration and development thinking about petroleum distributions for over 50 years, even as geologists and drillers realized that gas could also be found in syn-clines (Emmons, 1921). The anticlinal theory and successes so overshadowed the facts of synclinal production that no alternative theory for these non-anticlinal accumulations was advanced in explanation (Meckel and Thomasson, 2005, 2008).
Natural gas was discovered in western Canada while drilling a water well near Medicine Hat, Alberta, in 1883. The first Canadian gas field was discovered in 1909 and developed for local use in 1912 for Calgary and Lethbridge, Alberta. By 1923, Edmonton, Alberta, had its own gas field (Edmonton Geological Society, 1968).
In 1901 in southeast Texas, the Lucas Gusher at Spindletop salt dome initiated the modern petroleum era and demonstrated that large volumes of petroleum could be found beneath the Gulf Coastal Plain. These reservoirs typically had the high porosity and permeability values that were needed to produce the volumes of oil and natural gas that the growing economy of the United States needed. It also brought about a major shift in investment interest, as the companies that had been formed in the Appalachian Basin shifted their focus southward. Gas field development and pipeline distribution to major individual cities were the main focal points for natural gas to places such as Cleveland and Toledo, OH, Pittsburgh, PA, and Buffalo, NY, in the northeastern United States. Huge gas reserves were found not only in Texas and Louisiana, but also in California, Kansas, and Oklahoma.
Through the next 40 years from 1901 to 1941, American industry drilled, developed, and marketed natural gas so that by the start of World War II, natural gas supplied approximately 12 percent of the nation’s energy needs with annual marketed production approaching 3 trillion cubic feet (TCF) (Beebe and Curtis, 1968; EIA, 2009, http://tonto.eia.doe.gov/dnav/ng/hist/n9050us2a.htm). With the increase in energy demand supporting the WWII effort, industrial demand for gas changed the rate of marketed production, which persisted through the end of WWII and into the Cold War, when marketed product peaked at more than 22 TCF in 1973 (EIA, 2009, http://tonto.eia.doe.gov/dnav/ng/hist/n9050us2a.htm).
The exponential ramp in marketed production from 1950 to 1973 put a significant strain on the gas exploration side of the business to meet the market demands. The Organization of the Petroleum Exporting Countries (OPEC) boycott of 1973 caused a rapid rise in oil prices and by association, natural gas prices (EIA, 2009b). In conjunction with national price controls, the rapid growth in natural gas use abated. National economic growth was stymied. In response to the energy crisis of the 1970’s, federal price controls on natural gas were removed in 1978, and new tax incentives were created by the U.S. Congress in 1980 to help offset the cost of drilling and producing low-permeability sandstones (and other unconventional gas) and to help promote more domestic natural-gas production. Because of past regulatory practices and high consumption, natural-gas reserves were limited. By the late 1970’s, projected prices for future oil and natural-gas delivery were in the range of $100/bbl and $10–12/mcf (substantially above the current wellhead price (January, 1979) of about $14/barrel and $1/mcf) (Coleman, 2008). This combination of circumstances, fears, economic forecasts, and tax incentives led to the development of exploration strategies to pursue previously uneconomic gas reservoirs.
As part of the tax credit legislation, legal definitions have been created for a tight-gas sandstone reservoir. By law, these reservoirs in the United States have an in-situ permeability of less than 0.1 mD (EIA, 1993). In addition, they commonly have a matrix porosity of 10% or less. Outside of the United States and Canada, tight-gas sandstone reservoirs are gas sandstone reservoirs that are noneconomic because of generally poor reservoir properties. In addition to tight-gas sandstones, financial incentives have been put in place in the United States to encourage natural gas production from coal beds and gas shale reservoirs.
Even with these incentives, many of the previously uneconomic tight-gas sandstone reservoirs had already been “discovered” in the western United States and Canada by drilling for oil prospects on large surface structures. Their low flow potential prevented them from widespread development. The ability of the Gulf Coast, the Midcontinent, and the Appalachian Basin to supply the national needs meant that these “discoveries” in the Rocky Mountain basins, California, and western Canada were either held in abeyance for the future or connected to pipelines to the U. S. Pacific Coast as they became available. The first trans-U.S. pipeline was completed in two parts from Texas to California in 1947 and Texas to New York in 1949. The Trans-Canada pipeline from Alberta to Montreal was completed in 1958, which provided a single eastern outlet for western Canada gas. By 1966, all Lower 48 states had natural gas service, and natural gas was no longer considered a luxury (Beebe and Curtis, 1968).
The “Modern Era” of Tight-Gas Sandstone Reservoirs
The development and successful implementation of hydraulic fracturing in 19481 can be called the beginning of the modern era of tight-gas sandstone development. Continuing technological developments of this critical component of tight-gas reservoir development in conjunction and in concert with developments in deviated hard-rock drilling made the future of these plays bright. However, without the rapid rise in oil prices (which were closely coupled to natural gas prices at the time) and the response by the U. S. Congress to remove price controls and to provide incentives for drilling and developing these non-economic and marginally-economic reservoirs in the late 1970’s, the critical advances in technology and science of tight-gas sandstone reservoirs probably would not have happened as quickly as they did.
Many oil and gas companies seized the opportunity and went back to their old files, looking for historic non-commercial gas wells or wells that flowed gas while drilling through low porosity and permeability rocks. Major new fields were discovered and developed; a brief listing gives a short historical overview:
Blanco-Mesaverde and Ignacio Blanco Mesaverde, San Juan Basin, Colorado and New Mexico: oil discovered 1911; gas discovered 1927; field discovery well was completed in 1952 (Peterson et al., 1965; Dugan, 1977; Fassett, 1978, 1991; Fassett and Boyce, 2005a, b);
Pinedale (Lance), Green River Basin, Wyoming: gas discovered 1939; field discovery well 1955; field development began 1997 (Jenkins, 1955; Law and Spencer, 1989; Sansone and Brown, 1992; Bickley and others, 2005; McDermott and Graham, 2005; Kneller et al., 2006; Rach, 2008);
Rulison (Williams Fork–Mesaverde), Piceance Basin, Colorado: gas discovered 1952, resources developed beginning mid-1980’s (Reynolds, 1977; Reinecke et al., 1991; Johnson, 1987; Hemborg, 2000; Cumella and Ostby, 2003; Johnson and Roberts, 2003; Cumella, 2006; Hood and Yurewicz, 2008; Yurewicz et al., 2008);
Many of the Rocky Mountain basins fields were low porosity and permeability reservoir fields. They were commonly developed in Cretaceous and lower Tertiary sandstones and were associated with coals or high organic content shales. Workers recognized that many of the Rocky Mountain fields produced very little water when flow tested (see discussion by Meckel and Thomasson, 2005, 2008). Berry (1959) first suggested that hydrodynamic forces were trapping the gas in the deeper part of the San Juan Basin (Fassett and Boyce, 2005a, b). Others embraced the theory, since it appeared to explain the observations.
During this initial period of exploration and attempted production, completion technology sought to liberate the gas from the reservoir that was being discovered by the drill bit. Hydraulic fracturing was attempted at many locations with highly variable (to no) success. In an effort to see if the large volumes of gas thought to be present in the tight sandstones could be freed from their host reservoir rock and exported out of the basins, an artificial fracturing technology alternative to hydraulic fracturing was developed and tested in the 1960’s and 1970’s. This alternative stimulation method was piloted under the name “Project Plowshare” by the U. S. Atomic Energy Commission (now Department of Energy) and was designed to fracture stimulate the reservoirs with nuclear explosives.
Project Plowshare was targeted at identified low permeability gas resources of up to 300 TCF (Toman et al., 1973). Three low-yield nuclear devices were detonated at GASBUGGY (29 kilotons), December, 1967, near Farmington, New Mexico, RULISON (40 kilotons), September, 1969, in Grand Valley, Colorado, and RIO BLANCO (3 shots, 33 kilotons, each), May, 1973, near Rifle, Colorado (https://www.osti.gov/opennet/reports/plowshar.pdf). Other reservoir stimulation projects were planned, but never executed, including a new test at Pinedale anticline (the EI Paso Natural Gas Company Wagon Wheel No.1; Shaughnessy and Butcher, 1974; Law and Spencer, 1989) and a follow-on test at Rio Blanco. The GASBUGGY test resulted in greater gas flow rates than conventional hydraulic fracturing in nearby wells. However, the gas stream was radioactive and had a lower BTU value (http://www.lm.doe.gov/documents/sites/nm/gasbuggy/gasbuggy.pdf). Similar results were obtained at Rulison and Rio Blanco (http://www.lm.doe.gov/documents/sites/co/rulison/rulison-factsheet.pdf; http://www.lm.doe.gov/documents/sites/co/rio/rioblancofactsheet.pdf). The U. S. Government and industry partners invested approximately 82 million dollars in the project from 1967 to 1974. Based on the results of the three tests, it was concluded that only 15 to 40 percent of the investment could be recovered even after 25 years of gas production. At the end of the project in 1975, when there was still no way to remove the radioactivity from the gas or the drill site, Project Plowshare was discontinued because of economic and environmental concerns (Lorenz, 2000; https://www.osti.gov/opennet/reports/plowshar.pdf).
In 1979 a paradigm shift in exploration occurred when Masters (1979, 1984) described a new play type and development strategy that did not involve drilling conventional structural or stratigraphic traps. Discovery of the Elmworth Field (1975; Sneider et al., 1983), Alberta Basin, western Canada, was announced in 1976 and was estimated in 1984 to contain 17 trillion cubic feet of gas and 1 billion bbl natural gas liquids in a 1946-mi2 area described as containing ‘‘gas in every stringer of porosity; in fact, the entire rock section [was] saturated with gas’’ southwest of a generalized gas–water contact (Masters, 1984, p. ix). After the discovery of Elmworth Field, many companies set out to explore for these types of fields, initiating a variety of large-scale leasing and drilling programs in the eastern United States, Rocky Mountain, and Midcontinent states. Previously drilled dry holes in gas-saturated basins were re-examined and, sometimes, redrilled. Geologically old provinces, such as the Appalachian, Black Warrior, Illinois, Michigan, Arkoma, and Anadarko basins, were re-evaluated with new eyes. Gas-charged, apparently water-free, ramp-dip areas of major basins quickly became major exploration play areas.
This renewed interest and drilling coincided with significant changes in tax incentives and price controls, which together prompted further improvements in completion techniques and new pipeline spurs and connections. With real, potential markets available, total project cost management became important and companies that normally handed off a discovery well from the exploration geologists to the production engineers began integrated efforts to work the project as a joint geological and engineer endeavor. Cultural battles ensued as geologists wanted more rock, fluid and pressure data, and engineers wanted more certainty, lower costs, and more systematic and clearer completion decision processes.
Industry, academic, and government geologists and engineers worked in teams and alone to unravel the keys to understanding the secrets of making tight-gas sandstones produce the gas that all of the assessments said were present. A review of producing reservoirs showed that all depositional environments, most major petroliferous basins, and most geologic ages were represented (Table 1A, Table 1B, Figure 1; Finley, 1984; Spencer and Mast, 1986; Dutton et al., 1993; Robertson et al., 1993).
Massive hydraulic fracture projects of millions of pounds of proppant (usually quartz sand) and millions of gallons of fluids evolved into multi-stage projects of several tens to hundreds of thousands of pounds of sand and proportionate volumes of fluid. While certainly not necessarily “routine,” the unconventional reservoirs made up of tight-gas sandstones were becoming more commonplace, if not exactly conventional.
With Masters’ (1979) discovery of the “basin-centered gas” play concept, many geologists reviewed old drilling reports and found that much of what Masters described could be found in other basins, especially those in the Rocky Mountains where similar aged Cretaceous sandstones were associated with gassy coals. Meissner (1979, 1982, and 1987) and Spencer (1987) postulated a critical link between basin-centered gas accumulations and mature, gassy source rocks, over-pressured reservoirs intervals, and observed gas saturations (Meckel and Thomasson, 2008). A variation on this theme would develop later as pervasive biogenic gas accumulations in relatively tight reservoirs were also discovered (see Condon, 2000).
At least in the Rocky Mountain Cretaceous basins, and with hints from older Paleozoic basins in the eastern U.S., it appeared that tight-gas sandstones that had an intimate association with a gas-generative source interval could be made economically productive. In the western basins, these were typically coaly intervals, whereas in the eastern basins, thick marine shales of Ordovician, Devonian, and Carboniferous age appeared to be the generative interval. Additionally, the presence of sandstones interbedded with coals in Penn-sylvanian strata in the Black Warrior and Appalachian basins suggested possible potential.
Somewhere along this path in history, the terms “tight-gas sandstone” and “basin-centered gas accumulations” became essentially synonymous (Law, 2002), although there are clearly tight-gas sandstone reservoirs that are not part of basin-centered gas accumulations, and there are basin-centered gas accumulations that include non-tight-gas sandstone reservoirs (i.e., conventional porosity and permeability sandstone reservoirs, with gas–water contacts). In developing its 1995 national assessment, the USGS classified basin-centered gas accumulations as a continuous-type, or unconventional, accumulation, which originally was defined for those resource assessment purposes as a geographically extensive gas accumulation generally lacking well-defined hydrocarbon–water contacts (Gautier et al., 1995). These were distinguished from “conventional resources,” which were those resources “that were generally trapped by hydrodynamic processes … with a well-defined, oil- or gas-water contact at the base of each accumulation, leading to discrete, countable accumulations” (Schenk, 2002, 2005). Continuous resources were accumulations that included basin-centered gas, shale gas, tight-gas, and coalbed gas and were not trapped by hydrodynamic processes (Schenk, 2002, 2005). Transition zones between the two types were identified and some accumulations were judged “hybrid accumulations” with conventional accumulations having some characteristics of continuous accumulations (e.g., Ryder and Zagorski, 2003).
“Regional in extent,
Existing ‘fields’ commonly merge into a single regional accumulation,
No obvious seal and trap,
No well-defined, oil- or gas-water contact,
Hydrocarbons apparently not held in place by hydrodynamics,
Commonly abnormally pressured,
Large in-place resource volume, but very low recovery factor,
Geologically controlled ‘sweet spots,’
Little free water production (except from coal-bed gas accumulations),
Water commonly found up dip from hydrocarbons,
Few truly ‘dry’ holes,
Reservoirs generally in close proximity to source rocks,
Estimated Ultimate Recovery (EUR) of oil or gas from wells is generally lower than EURs from wells in a conventional accumulation,
Reservoirs with very low matrix permeabilities, and
Natural reservoir fracturing common.”
Throughout the assessment process, it became evident that “sweet spots” controlled the economic development of these accumulations (Surdam, 1997). “Sweet spots” could be one or several of many favorable geologic factors, which caused increased porosity, permeability, and flow rates in an area of lower and therefore uneconomic flow potential. These “sweet spots” could be reservoir thickness, depositional environmental and (or) diagenetic controls on reservoir rock properties, increased fracture density, more favorable (higher or lower) thermal maturation history, or gas content. These “sweet spots” are conventionally describable, geologic features that may also be found in conventional reservoirs: facies changes (e.g., pinchouts, channel margins, relatively abrupt grain-size change and associated abrupt change in water saturation or cementation) and fracture zones, such that in a conventional, stratigraphically-trapped sandstone reservoir, they might constitute the main field extent having a potential low permeability “waste zone” rind surrounding the main producing wells.
In addition, the continuous gas accumulations were typically abnormally pressured. Most were over-pressured (i.e., in pressure gradients higher than hydrostatic, or greater than approximately 0.45 psi/ft). Some were underpressured (i.e., in pressure gradients lower than hydrostatic). It seems, then, some accumulations might be normally pressured, especially if there is a natural transition through geologic time between overpressured environments and underpressured environments (e.g., Camp, 2008). To-date, basin-centered gas accumulations are generally excluded from normally pressured conditions, more or less by definition.
At its completion, the 1995 USGS Survey National Assessment of United States Oil and Gas Resources (Gautier et al., 1995) identified 20 sandstone plays in eight basins with continuous-type gas accumulations. A follow-up study (Popov et al., 2001) focusing on basin-centered gas accumulations identified 34 potential basins with these types of accumulations (Table 2).
This study led to further USGS studies on tight-gas sandstones from which it became clear that there were a range of basin situations containing gas-productive, low-permeability, sandstone reservoirs. In order to better assess the resource potential of continuous-type accumulations, the USGS proposed a cell-based approach (Schmoker, 1999, 2002). The post-1995 studies found a variety of accumulations hosted in tight-gas sandstones: there were underpressured, normally pressured, and overpressured reservoirs. Also, possibly within each pressure category, there were both conventional (having a discernible or detectable gas/water contact or transition zone) and unconventional or continuous (not having a discernible or detectable gas/water contact or transition zone). There also appeared to be some basin accumulations that were “hybrid” in that a single stratigraphic interval would have both conventional and unconventional (continuous) play types. Successful finding and developing each reservoir type appeared to require a special understanding of the reservoir properties within each category. Subsequent assessment studies have concluded that 17 continuous gas provinces within the United States have mean probabilistic undiscovered gas resources from non-coal bed gas continuous accumulations of 272.75 TCF. Within this group of 61 reservoir units, 29 are predominately sandstone units and 32 are predominately shale, chalk, or limestone units (Table 3; Figure 2).
In 2000, the Rocky Mountain Association of Geologists (RMAG) hosted a symposium on basin-centered gas systems. In this symposium Law (2000, and later in a 2002 AAPG Bulletin article) explained the concept of a basin-centered gas system. In most instances, the reservoir intervals within these systems are (1) single or stacked reservoirs contained within regionally pervasive gas accumulations (hundreds to thousands of mi2 in extent); (2) abnormally pressured (either over- or underpressured); (3) gas saturated and downdip from normally-pressured, water-bearing reservoirs; (4) intervals with relatively low permeability (< 1.0 mD) and porosity (< 13%); and (5) intervals with measurably “high,” but irreducible, water saturations, because of low permeability and narrow pore throats. In some instances, regional accumulations may contain water bearing zones or even have downdip water contacts (Law, 2000, 2002). In many instances, gas-charged intervals appear to be spatially associated with gas-generative coals or thermally cracked oil-bearing intervals (Meissner, 2000).
In 2003, following the publication of the special AAPG Bulletin theme issue on unconventional petroleum systems (Law and Curtis, 2002), the RMAG hosted a symposium on “Petroleum Systems and Reservoirs of Southwestern Wyoming,” where major disagreements over the actual presence of basin-centered gas sandstone fields were presented. Shanley, Cluff, Byrnes, and Law presented arguments for and against the concept of basin-centered gas accumulations and their enclosed tight-gas sandstone reservoirs. During the discussion periods following several talks, a clear distinction was made: Law (2003) was talking about continuous gas systems (or accumulations) and NOT continuous gas reservoirs.
Reservoirs within continuous gas systems (a.k.a. “basin-centered gas”) may have conventional trap geometries, produce some water (or even a lot of water), and be interstratified with conventional reservoirs intervals (i.e., those with a clear, down-dip water leg). Shanley et al. (2003, 2004a, b) brought to the fore-front of the discussion a question of the reality of basin-centered gas and whether they really were widespread resource plays having very limited geologic risk of finding economic resources. Citing data and illustrations from several Rocky Mountain basins, these authors suggested that tight-gas resource assessments were “substantially overestimated” and “the risks associated with finding and recovering those resources [were] almost certainly…underestimated” (Shanley et al., 2004a, p. 24). In a more detailed treatment, Shanley et al. (2004b) reintroduced the concept of “permeability jail,” a term proposed by Byrnes in 1994 (referenced in Shanley et al., 2004b) that described “the saturation region across which there is negligible effective permeability to either water or gas” (Shanley et al., 2004b, p. 1092). In this situation, it is possible to detect gas while drilling, have logs through the formation that show high water saturation, and flow neither gas nor water due to relative permeability effects. Failure to understand this petrophysical concept led to a widespread misunderstanding of how tight-gas sandstones are manifested in low-permeability reservoirs (paraphrased from Shanley et al., 2004b, p. 1092). Fracture stimulation may accentuate linear zones of the formation permeability, connecting pore throats too small to produce naturally (i.e., without fracture stimulation) thereby releasing some of the formation’s gas charge.
In a follow-up volume, RMAG published a series of reports on “Gas in Low Permeability Reservoirs of the Rocky Mountain Region” (Bishop et al., 2005) that presented several regional and basin-scale studies of key tight-gas sandstones. These studies presented several overview syntheses of exploration and production history, hydraulic fracturing, and fluids and pressure regimes, as well as case studies in the Alberta, Denver, Green River, Piceance, San Juan, Uinta, and Wind River basins.
The AAPG hosted a Hedberg Conference in 2005 on “Understanding, Exploring, and Developing Tight-Gas Sands” (http://www.searchanddiscovery.net/documents/abstracts/2005hedberg_vail/index.htm) for the purpose of “encourage[ing] a free exchange of cross-disciplinary discussion among leading scientific and engineering experts leading to improved exploration models and development and completion strategies required to exploit the vast North American tight-gas sand potential” (Cumulla et al., 2008a). Some of the Hedberg Conference oral presentations were published later in Cumella et al. (2008b). These reports further demonstrated the wide variety of tight-gas sandstone reservoirs and the continued importance of the concept of basin-centered gas accumulations in explaining the presence of gas in low permeability sandstones down-dip from water saturated equivalent strata. Several articles from these proceedings summarize the extent of tight-gas reservoirs and debate concerning their true character and productive capabilities (Camp, 2008; Meckel and Thomasson, 2005, 2008). From the reservoir perspective, there appear to be two kinds of tight-gas sandstone reservoirs: (1) low permeability and porosity sandstones in “gas-saturated” (i.e., essentially water-free production) portions of basins, and (2) low permeability and porosity sandstones not in “gas-saturated” (i.e., essentially capable of high water production) portions of basins (producing both gas and water). Both present similar, yet different, challenges to achieving successful discovery and production. The first set produces gas during drilling and many wells produce gas after fracture stimulation, because the entire stratigraphic interval (main reservoir and surrounding non-reservoir strata) have a high gas charge and low water production potential. The second set may produce gas during drilling and may produce gas after fracture stimulation. However, in this second case the gas is generally restricted to pore spaces within the reservoir, and the reservoir interval may produce substantially high volumes of water.
The Future of Tight-Gas Sandstone Reservoirs
The future is always in front of us, more or less by definition. By the time we fully recognize its content, it is the present and we are experiencing it, or it is the past and hopefully we have learned something to apply forward. So, what challenges are we facing related to tight-gas sandstone reservoirs? Most, if not all, natural gas supply-and-demand forecasts show tight-gas sandstones being a key supply component of the nation’s gas needs for the next decades. In fact, as high volume and rate conventional gas fields continue their rapid decline, the demand for equivalent replacement volume from unconventional sources becomes a significant challenge to meet with current resource availability and flow rate.
Nehring (2008) summarized the situation as of 2005. The growth in U.S. gas production from 16.9 TCF in 1990 to 18.0 TCF in 2005 was possible only because of the growth in unconventional gas production, which became almost half of the national production in 2005. Of this, tight-gas sandstones provided almost one-quarter of the nation’s total natural gas output. Most of this production was from Cretaceous reservoirs of the Rocky Mountain basins (42% of 2005 tight-gas production), Jurassic and Cretaceous reservoirs of the onshore Gulf Coastal Plain of east Texas and north Louisiana (27% of 2005 tight-gas production), and Tertiary Paleogene reservoirs of south Texas (14% of 2005 tight-gas production). The remaining 17% is shared by the West Texas Permian and Val Verde basins and the Midcontinent Anadarko Basin. Data were not available for the Appalachian Basin, which has a long history of tight-gas sandstone production.
A Department of Energy - Energy Information Agency (EIA) analysis in 2009 (http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/historical/2007/cr2007.html) revealed that 49.4 % of the U.S. natural gas production in 2007 came from fields whose main reservoirs were tight-gas sandstones (Table 4, Figure 3). Forty-seven of the top 100 gas fields produced substantial volumes from tight-gas sandstone reservoirs. At this level of production it is easy to see that tight-gas reservoirs may still be classified as “unconventional,” but they are becoming very commonplace.
Tight-gas sandstone reservoir developments in Canada and the United States have led the way, technologically, for similar developments in the rest of the world. Current tight-gas sandstone reservoir development projects are currently underway in many countries, including Mexico, Venezuela, Argentina, England, Ireland, Germany, Hungary, Romania, Russia (CIS), Algeria, Egypt, Saudi Arabia, Oman, India, China, Indonesia, South Korea, and Australia.
In order to effectively meet the nation’s future gas supply needs, successful tight-gas sandstone ventures must address the key issues that they have always addressed:
Assess the marketplace
There are strong political, environmental, and market forces which clearly indicate that natural gas will be the energy resource of choice for the coming decades. Most future supply and demand charts for natural gas show conventional gas resources to be declining and national demand to be rising. Most analysts expect all unconventional gas resources (tight-gas sandstones, coal bed methane, gas shale, and methane hydrates) collectively to meet that demand and even fill the forecast gap between rising demand, falling conventional resource supply, and rising unconventional resource supply. Liquefied natural gas (LNG) imports and Alaskan North Slope and Canadian Arctic gas availability and destinations also will be factors in the overall economics of tight-gas sandstone exploration and development.
One of the continuing challenges to understanding tight-gas reservoirs has been to spend just enough money to collect just enough data to understand the reservoir adequately enough to continue to operate at a profit. Tight-gas reservoirs have routinely been marginal economic ventures through time. Maintaining a narrow profit margin requires identifying pay intervals using sparse open-hole logs and development well cased-hole logs, completing each and every potentially productive well exactly as planned, accurately predicting EUR based on very few pressure measurements, and maintaining well flow for the most of their economic lifespan.
Understand the host basin
With very few exceptions, most basins containing tight-gas sandstone reservoirs have reasonably well understood stratigraphy. Some basins do not have ultradeep wells, but these will likely come as high temperature–high pressure drilling systems improve and become more available and less costly. Distinguishing conventional from unconventional (or “continuous”) gas resources in mature basins continues to be a challenge in many areas. Charpentier and Cook (2005) illustrated three examples of tight-gas sandstone reservoir fields on the spectrum from nearly conventional to, in essence, purely continuous. Understanding the nuances within this spectrum will be essential for effective resource management.
The current understanding of the post-depositional history of a prospective tight-gas basin may need refinement as reservoir development follows discovery. Structural evolution, especially in basins having some measure of inversion, may be critical to defining early migration pathways and trapping elements. Most reservoir units probably had higher porosity and permeability during their early life, such that initial fluid buoyancy and reservoir heterogeneity may have had a significant impact on “sweet spot” development (Shanley et al., 2007; Banfield et al., 2008). Following an early (earlier than previously recognized) hydrocarbon migration episode into reservoirs having initially higher reservoir porosity and permeability, the area may have continued to subside and be deeply buried. The original reservoir with higher porosity and permeability is most likely degraded during this burial, resulting in a coeval redistribution of original gas into adjacent stratal units. With later uplift of the basin, gas distribution, column height, and saturation adjust to new fluid dynamic pressures. In some basins, some gas may have leaked out of the early-charged reservoir intervals into more favorable higher porosity and permeability and usually shallower intervals. In other basins, some (or possibly most) of the early gas accumulations are retained by depositional and possibly structural elements that formed the early trap components. Diagenesis further reduces pore size, setting up the conditions where present-day reservoirs have low porosity and permeability, relatively high water saturation, and difficult to determine producible gas concentrations.
The origin of the gas in many basins, especially deep and ultradeep basins, may not be as well understood as the stratigraphic and structural history. Recognizing whether the gas comes from initial conversion of gas-prone kerogen or thermal cracking of previously generated oil or a combination of the two may help estimate the long-term viability of a tight-gas sandstone play. Understanding this component runs in tandem with understanding the origin of basin pressure and the distribution of pressure cells within the basin. A clear comprehension of the full scope of the structural history of a basin and the timing of possible basin inversion, repressurization, and regional fracturing will aid in estimating the full potential of the basin.
With the growing national dependence on unconventional reservoirs to fill the forecast natural gas demand “gap,” it is important to translate basin knowledge into an estimate of the gas resource assessment. The USGS is tasked with conducting undiscovered resource assessments in the United States (onshore and state waters) on a regular basis. The current assessment methodology for continuous accumulations involves a cell-based approach, wherein each cell within a continuous gas accumulation (be it a tight-gas sandstone, coal bed, or gas shale) is given a resource value. The total resource for an assessment unit (or play area) is the sum of all cell values in that area.
As the USGS looks to the future of continuous gas resource assessment, it is investigating ways to improve its understanding of these resource types and ways to understand the potential resource accumulation volumes. Attanasi (2005) and Coleman and Attanasi (2009, this volume) illustrate a way to examine the size of future tight-gas sandstone discoveries by looking at the discovery size over time in a tight-gas sandstone play area. In all seven of the plays examined, the discovery size decreases over time in a fashion similar to that of conventional sandstone plays, suggesting that resource depletion may proceed in a relatively predictable fashion as with conventional sandstone plays. Olea et al. (2009) present a geospatial approach which addresses the three-dimensionality of gas-saturated basins with multiple reservoir levels, incorporating dry holes (whether they be an uneconomic discovery, a mechanical failure–drilling or completion–or a “true” dry hole that missed the reservoir target), and areas that have no well control. This approach starts to incorporate the three-dimensional heterogeneity of tight-gas accumulations.
Find the “sweet spot”
From the beginning of exploration and development of tight-gas sandstones, the first objective has been to find the “sweet spot” that was almost as good as a “conventional” reservoir and that with technology, patience, hard work, and luck that “sweet spot” could be made into an economic reservoir. Sometimes industry had to wait for the market and the pipeline to come to the accumulation. Sometimes industry had to wait for technology to improve and the costs of application to go down. Yet, truly understanding the “sweet spot,” or “sweet spots,” has remained illusive.
The presence of fractures has always been thought to be essential for economic tight-gas sandstone production. Yet, in enough fields to be significant, the presence of bonafide, open fractures is not clearly evident. In addition to fractures, “sweet spots” are also apparently due to better-than-average reservoir rock matrix porosity and permeability. With the progressive improvement in seismic acquisition and imaging from the mid-1970’s to the present, it has become possible to look for and acoustically image fractured strata at reservoir depths.
Application of advanced three-dimensional, multi-component seismic acquisition and processing shows promise in illuminating those “sweet spots” that are fracture-dominated (e.g., Natali et al., 2000; Evans et al., 2001; Hart et al., 2002; Pennington, 2002; Davis, 2007). Yet, illuminating those “sweet spots,” which are not fracture-dominated but are sedimentological or dia-genetic, is still a major challenge. Petrophysical studies suggest that thin (1-ft ±), high(er) porosity-permeability stringers within the reservoir bodies may contribute a substantially disproportionate volume of gas to that produced by the entire reservoir (Byrnes, 2005). Will seismic programs that successfully image fracture “sweet spots” be able to successfully image high porosity and permeability stringer “sweet spots”? Some 3-D seismic has shown the potential for delineating sedimentary features at the systems track and depositional element scales (e.g., Bunge, 2003), but these may be insufficient to map clearly and economically the target high porosity–permeability zones in the near future. Seismic imaging has shown an ability to discriminate between water saturated zones and gas saturated zones. However, in many instances, tight-gas sandstones display a pervasive, high water saturation having no clear gas–water contact. In this case, it may be difficult to map with confidence the gas-bearing intervals using seismic imaging and discriminating between essentially mobile water free reservoir matrix and water-productive fracture zones.
In truly continuous, resource gas plays, in which all strata (interbedded sandstones, siltstone, shale, coal, and possibly limestone) are essentially gas saturated and productive of gas, then the “sweet spot,” or indicator strata, for the resource play may be the most porous and permeability unit, be it coal or sandstone or, perhaps, fractured shale. If there is no reducible water component, then all lithologies within the accumulation will produce gas IF the appropriate technology is applied. If there is mobile water, then of course, that water must be co-produced in order to permit the gas to be produced.
Understand the heterogeneity of a tight-gas reservoir
Finley (1984), Spencer and Mast (1986), Dutton et al. (1993), and Gas Technology Institute (2001) demonstrated that tight-gas sandstone reservoirs occur in essentially all siliciclastic paleodepositional environments: fluvial, fan delta, deltaic barrier/strandplain, shelf, and slope and basin. A quick examination of conventional reservoirs from these environments shows that the trap geometries and heterogeneities are highly variable, because each reservoir inherits its shape, size, ultimate reservoir properties, and continuity from its depositional (primarily) and diagenetic (secondarily) environment. Heterogeneity is both lateral (i.e., bed length, bed continuity, possible bioturbation, and laterally variable petrophysical properties potentially resulting from original depositional current properties) and vertical (i.e., single- or multi-storied reservoirs, which may be thinly or thickly bedded and dis- or interconnected by faults, fractures, or sedimentary features, such as incised channel bodies). The application of depositional geomorphologic data to constrain sedimentary body dimensions will help improve the statistical prognosis for distribution of “sweet spot” size and spatial distribution (e.g., Saucier, 1994; Slatt, 1998; Reynolds, 1999; Tye, 2004). This heterogeneity extends to the microscopic, grain- and pore throat-size scale. At some point in the continuum and at a scale typically less than a legal spacing unit, the heterogeneity of a reservoir interval becomes so pervasive that the overall interval appears homogenous and locally continuous. Although hard or impossible to detect with conventional geological and geophysical tools, the production-governing heterogeneity is still present; however, it is below the scale of seismic recognition and is discernible only with careful well production tests and time-series profiles.
Understanding the non-“sweet spot” (or background geology) is just as important as understanding the “sweet spot.” As with almost any gas field, there are some wells that are more highly productive than others. This difference is caused by some individual or combination of geological and/or engineering factors that result in higher effective reservoir to borehole transmissivity. These factors can be porosity, permeability, reservoir thickness, few or no baffles or barriers, open and coalescing fractures, structural height, structural closure, facies change, or depositional pinchout/truncation. With low permeability reservoirs, a second combination of factors from hydraulic fracture stimulation may also induce “sweet spot” characteristics into the local area around the borehole.
Those reservoir intervals having high lithologic or rock property heterogeneity will, in all likelihood, have more, but smaller, “sweet spots” than those reservoir intervals which are more or less homogeneous. Unraveling the nature, size, distribution, and extent of “sweet spots” by drilling is currently the regular practice of operators. Seismic illumination of reservoir character is developing rapidly, but confirming the non-unique seismic solutions requires essentially drilling all of the areas that are predicted to contain economic volumes of gas. Sometimes the operators find more surprises than gas (e.g., Norris and McClain, 2005; Norris et al., 2005). Higher levels of reservoir heterogeneity require more and smaller vertical well spacing units than reservoirs with lower levels of heterogeneity. This is clearly seen in Rocky Mountain basin tight-gas development of meandering fluvial Upper Cretaceous reservoirs where spacing units are commonly in the 10 to 20 acre size (e.g., Jonah, Grand Valley-Rulison–Parachute–Mamm Creek).
This future, down-spacing prudency may also be seen in other channelized reservoirs such as the slope gravity flow channelized Upper Pennsylvanian reservoirs at Red Oak Field (Oklahoma) and possibly Upper Pennsylvanian–Lower Permian reservoirs at Ozona Canyon Field (Texas). Larger spacing units may be developed in more homogeneous reservoirs, such as the Upper Jurassic Cotton Valley massive sandstone fields (40 to 160 acres Texas and Louisiana) and the Upper Cretaceous Almond marine bar sands at Wamsutter Field (80 acres, Wyoming). Fracture-essential tight-gas reservoirs require a different approach to spacing unit development than non-fractured versions of the two reservoir types above. The development and deployment of horizontal drilling in tight-gas sandstone reservoirs have radically overturned three decades of conventional development philosophy, whereby one set of well bores (multi-laterals) from a single surface location should be able to intercept and drain small channel-body reservoirs and intercept fractured rock volumes multiple times.
Pay recognition within tight-gas sandstone reservoirs has always been a challenge. The relatively high irreducible water saturations, coupled with potential variability in the chemistry of that water and reservoir sand grain content, make confident pay determination challenging. When the only logs available for analysis are run through cased holes, the challenge is even greater. With these logs, successful pay identification requires a good understanding of rock properties and grain constituents across the prospect or field area, as well as an understanding of the content and reliability of the data transmitted by wireline log and other down-hole measuring tools.
Accurate reserve determination begins with good pay determination (porosity, permeability, clay content, etc.), bottom hole virgin reservoir pressure, temperature, and depth range. Determining how much of the calculated log-based water saturation (assuming that the appropriate logs are run) is genuinely irreducible, especially when drilling fractured reservoirs, is essential. Is it possible to determine a relationship between the gas produced and the observed reservoir characteristics? Can PUDs (proven, undiscovered reserves) be confidently demonstrated until those units are drilled and actually proven? In a hypothetical world, where tight-gas sandstone reservoir production is expected to replace conventional gas production, a single, rapidly declining Gulf of Mexico gas well that is producing on average 1,000,000 cubic feet of gas a day will need to be replaced with two to three equally reliable tight-gas wells that can cumulatively make up the decline as the high performance Gulf of Mexico well depletes.
Getting the resource out of the ground
Even when the standard fracture treatment involved nitroglycerine, it was imperative to design and implement the proper (“correct”) fracture treatment. A “Goldilocks” (“just right”) solution was always needed: just the right amount of the right mixture of fluids (no adverse reactions; little or no retention within the reservoir), the right amount of the right kind (and mixture) of proppant, the right pressure and rate, and the right clean up. Successfully recovering the frac fluid and surplus proppant from an effective frac in a prudent fashion should encourage and allow the reservoir to flow efficiently for many years with minimum intervention. Each well should be treated as a unique opportunity and the tendency to employ the one-size-fits-all approach should be suppressed. The goal is to keep costs at a minimum and knowledge at a maximum from permitting to abandonment.
The necessary logical offshoot of minimizing costs and maximizing knowledge leads to rapid advances in stimulation and completion technology. Today, multi-stage hydraulic fracture treatments, sometimes with rather exotic cocktails of fluids and proppants, are used in high-angle, horizontal, or multilateral boreholes to improve access to reservoir gas and accelerate production. In many areas, old, presumably exhausted fields have been rejuvenated or certainly their life has been prolonged by the introduction of advanced drilling and completion technology.
Summary and Conclusions
As more and more conventional gas sandstone reservoirs are depleted and abandoned, more and more of today’s so-called unconventional gas reservoirs will be called upon to take their place in the national supply. With continued development and deployment of new technology, the uncertainty around predicted well performance should diminish and new ways to get gas out of old (or at least tight) rocks should increase in number.
As with any conventional field, we will really never have a full knowledge of tight-gas sandstone reservoirs until the last well is drilled. In the case of tight-gas sandstone reservoirs, each well must be hydrauli-cally fractured and flow tested. Yet, applying our learning from the past 150 years of drilling, “frac’ing,” and producing, some general observations can be made.
Explore for the source interval; develop the reservoir interval. Hydrocarbon gas volume and charge are the keys.
To generate the maximum hydrocarbon gas volume, regionally extensive, gas-prone source intervals at peak gas thermal conditions are preferred. They should be either at peak or just past peak gas generation or peak oil cracking-to-gas thermal conditions, producing the maximum amount of gas possible from the source rock in the kitchen area (as used by Magoon and Dow, 1994) and displacing the maximum amount of water in all stratigraphic units above, below, and updip from source interval.
In some areas, locally significant gas generative intervals (including relatively recent(?) biogenic gas generative intervals) may create continuous gas accumulations. However, the volume of gas generated and pressure exerted during generation and migration may not fully displace all of the water in the reservoir system.
Gas generation, migration, and entrapment (retention) results in a set of conditions with these arbitrary points along a spectrum:
“Fully charged”: most water is displaced by initial migration and then possibly by later uplift (gas expansion).
“Partially charged”: not all of the water is displaced by initial migration and later uplift (gas expansion); some gas may have escaped to shallower, conventional reservoirs or the surface along fractures, faults, and leaky seals. This condition results in a proportion of reservoirs having no or merely partial gas charge and high water saturation.
“Inadequately charged”: only local accumulations develop or remain. Only a few of these may be significantly large. The reservoir system will probably appear to be mostly water saturated.
“No Charge”: “no” gas accumulations exist.
The optimum, or best, source rock situation for migration and charge is where source rocks are strati-graphically adjacent to, within, or in very close proximity to main reservoir interval(s). Many of the Rocky Mountain Laramide basins have this setting (i.e., Cretaceous Mesaverde Group/Formation of the Greater Green River Basin and the Unita-Piceance basins; Cretaceous Lewis Shale of the Greater Green River Basin and San Juan Basin).
The next best source rock situation for migration and charge is where source rocks are stratigraphically below and only slightly older than the main reservoir interval(s) (i.e., both mature together at about the same rate). Examples of this situation may be found in the Devonian Catskill and Silurian Clinton-Medina sand-stone reservoirs of the Appalachian Basin and the various Mississippian sandstone reservoirs of the Black Warrior Basin.
There are probably several worst-case source rock situations for migration and charge. The potential source interval could be absent, substantially older (or more mature), or substantially younger (or less mature) than the main reservoir interval such that generation and migration is substantially different temporally from deposition and preservation of the main reservoir interval. Any charge would have to be result of remigration of previously generated gas from a temporary holding reservoir to the final reservoir. Possible examples of this situation are found in the Cambrian sandstones of north Florida (source absent, no charge), Cretaceous sandstones of north Florida (Silurian source interval; charge, but hydrocarbons lost at Paleozoic–Mesozoic unconformity before potential reservoir deposition), and Pennsylvanian sandstones of Louisiana and East Texas (Cretaceous source interval; charge, but no downward migration).
Taking all aspects of a petroleum system together (Magoon and Dow, 1997), the best basin situation occurs when a major phase of basin subsidence takes place during both reservoir interval deposition and source rock deposition and maturation. Much of the water is displaced from potential reservoir rocks during hydrocarbon generation, migration, gas disassociation, and expansion. Later the basin undergoes partial uplift to help displace water through gas expansion. Local fracture networks may develop and yet still be sealed by an upper level, unfractured sealing strata.
The next best basin situation potentially occurs when basin subsidence takes place during reservoir interval deposition and source rock deposition and maturation. Substantial uplift follows subsidence along with possible re-tilting of the basin, and degasification (or leaking) of some reservoir intervals (areas). Fractures which develop throughout these events may become both friend (high gas rates) and foe (high water rates).
Most likely, the worst basin situation occurs when the basin subsides after reservoir and source interval deposition leading to maturation of source interval. Following complete maturation and hydrocarbon generation and migration, the basin undergoes complete uplift (inversion), and there is a long period of exposure before possible reburial/resealing. Natural fractures are probably well developed and store large quantities of water.
The presence of tight-gas sandstone reservoirs without a proximal or geochemically associated source rock should be examined more rigorously than tight-gas sandstones with a clearly associated source rock. Like-wise, the presence of proximal sandstone beds, yet no productive reservoirs, clearly within or adjacent to a favorable source rock interval should be examined carefully to see if a play has been missed.
Gas accumulations in tight-gas sandstones can be either a conventional or a continuous (unconventional) accumulation. A continuous accumulation should have multiple reservoir rock types (e.g. tight-gas sandstone reservoirs, coal beds, shale intervals), only some of which may produce economic volumes of gas. Abnormally pressured compartments will contain both the reservoirs and boundary elements that separate it from the adjacent compartment. Tight-gas sandstone reservoirs will probably have geologically describable features that control and contain the main producing facies (or “sweet spot”). Hence, “sweet spots” within the full stratigraphic extent of tight-gas reservoirs will probably look and perform like low porosity and low permeability conventional reservoirs and will be the predominant contributor to a basin-centered or continuous gas play.