Dow, W. G., 1974, Application of oil-correlation and source-rock data to exploration in Williston basin: AAPG Bulletin., v. 59, p. 153-1262.
For a reader new to the Bakken shale play, this paper should be one of the first read for both historical and scientific insights into this play in particular, and shale reservoir oil plays in general. This early pioneering work identified three petroleum source rocks in the Williston Basin: the Pennsylvanian Tyler, the Devonian-Mississippian Bakken, and the Cambro-Ordovician Winnipeg. Each of these is separated from the others by sealing evaporite beds. The resulting basin compartmentalization defines three distinct petroleum systems, when respective reservoir rocks are taken into consideration as well. Of the three petroleum sources, the Bakken was identified as being the most important by far in terms of volumetrics. Ten billion barrels of generated oil, were calculated by Dow at the time of publication. By overlaying Bakken isopach and thermal maturity maps, the basin-wide area of effective Bakken source rock was mapped by the author. The efficacy of this map has been demonstrated over the past decades by many successful horizontal wells drilled predominantly within the effective Bakken source area mapped by Dow. Although the author wrote this paper to define the effective source rock areas for conventional reservoirs, the subsequent horizontal wells have proven that the effective Bakken source rock is an important reservoir as well. The paper has been cited 314 times (as of mid-2015).
Meissner, F. F., 1978, Petroleum geology of the Bakken Formation Williston Basin, North Dakota and Montana: Montana Geological Society 24th Annual Conference, p. 207-227.
Meissner, 1978 provided a very complete description of the Bakken petroleum system by combining multiple technical disciplines (mapping, well logs, geochemistry, sample description, rock fracturing, and petroleum engineering concepts). Meissner built upon Dow's 1974 (AAPG Bull., v. 58, p. 153-1262) paper documenting the Bakken shale as a significant source rock in the Williston basin, with many significant new observations and interpretations including recognition that the Bakken shale as both a source rock and a fractured shale reservoir. Meissner, 1978, expanding on the original observations by Murray, 1968 (AAPG Bull., v. 52, p. 57-65), related petrophysical changes in the Bakken source rock with increasing depth and thermal maturity, and used resistivity and sonic logs to map the extent of the thermally mature and over-pressured source rock. Meissner, 1978 also postulated that the origin of the oil productive fractures in the Bakken may be due to the generation of overpressure during hydrocarbon generation, rather than solely related to structural folding. This concept is still in vogue today. The paper provided the foundation for evaluating source rock formations and shale plays worldwide. The paper has been cited 291 times (as of mid-2015).
Masters, J. A., 1979, Deep basin gas trap, western Canada: AAPG Bulletin, v. 63, p. 152-181.
Masters, 1979 was first to introduce the now widely popular concept of the "resource triangle" (a principle adopted from the mineral mining and timber industry) to illustrate the potential for large, undiscovered hydrocarbon accumulations in low-quality reservoirs that could be profitably exploited with improved technology and higher commodity prices, particularly in mature basins where the higher quality oil and gas fields have largely been discovered. But more importantly, this paper developed a model to explain the occurrence of large (>1 tcf) gas fields in low porosity sandstone reservoirs occupying a unique structural position down dip from gas fields with established gas-water contacts in the same formation. Masters, 1979, thus ushered in a new exploration concept to explore for pervasive, gas saturated tight- sands in deep basin settings that has led to several subsequent gas discoveries and continued research in what are now typically referred to as basin-centered or continuous-type gas accumulations.
Masters, 1979 also proposed a controversial new type of lateral seal attributed to a potential "water block" phenomenon based on observations of gas-water relative permeability variations at Elmworth gas field in Alberta, Canada to explain deep basin, "unconventional" gas traps. The existence and effectiveness of this type of lateral seal continues to be debated.
Passey, Q. R., S. Creaney, J. B. Kulla, F. J. Moretti, and J. D. Stroud, 1990, A practical model for organic richness from porosity and resistivity logs: AAPG Bulletin, v. 74, p. 1777-1794.
Geochemical rock data required to evaluate source rock potential and shale reservoir plays are often lacking, even in mature explored basins. Passey et al., 1990 present a practical and easily applied method to estimate organic richness (total organic content) from more widely available well logs. The method employs a simple overlay technique using resistivity and porosity (sonic or density) logs to identify potential source rock intervals and to quantify total organic content where thermal maturity is measured or estimated from other data. This methodology is widely used in the industry today for shale reservoir exploration, and is applicable to both siliciclastic and carbonate mudstones. Sondergeld et al., 2010 (Society of Petroleum Engineers, Paper 131768, 34 p.) demonstrated that a slight modification to the original calibration is needed for the method to include gas mature (i.e., vitrinite reflectance > 1.0%Ro) reservoirs. The paper has been cited 478 times (as of mid-2015).
Shanley, K. W., R. M. Cluff, and J. W. Robinson, 2004, Factors controlling prolific gas production from low-permeability sandstone reservoirs: implications for resource assessment, prospect development, and risk analysis: AAPG Bulletin, v. 88, p. 1083-1121.
This paper provides an alternative to the basin-centered gas (BCG) model developed by Law, 2002 (AAPG Bull. v. 86, p. 1891-1919) following several papers on tight gas sands since the late 1970's. Shanley et al., 2004 argue that the little water produced from many BCG accumulations is not sufficient evidence to claim that buoyancy and traditional petroleum system concepts are not important factors in forming BCG accumulations. The authors demonstrate that the co-produced water from described BCG fields in the Greater Green River Basin of Wyoming is far in excess of the amount that can be explained as simply water-of-condensation. They also introduced the "permeability jail" concept to explain water and gas production from low-permeability reservoirs as a function of gas-water relative permeability variations in space and time.
Rather than assessing BCG accumulations as low-risk ventures with commercial exploitation essentially a function of drilling and completion technology, Shanley et al., 2004 offer an alternative paradigm that advocates for evaluating BGC prospects by considering traditional petroleum system risk elements, i.e. source, reservoir, trap, seal and timing. This work lead to a more recent publication by Shanley and Cluff, 2015 (AAPG Bull. v.99, p. 1957-1990) that examines the evolution of fluid saturation in low permeability sandstone reservoirs as a function of burial history.
Shanley et al., 2004 received the Wallace E. Pratt Memorial Award for best AAPG Bulletin article in 2006, and the Canada Society of Petroleum Geologists Medal of Merit for best paper in 2005. The paper has been cited 197 times (as of mid-2015).
Cumella, S. P., K. W. Shanley, and W. K. Camp, eds., 2008, Understanding, exploring, and developing tight-gas sands-2005 Vail Hedberg Conference: AAPG Hedberg Series No. 3, 250 p.
This AAPG special publication contains 13 solicited papers as an offshoot from the Vail, Colorado Hedberg Conference on tight-gas sands held April 24-29, 2005. The desire for a Hedberg Conference on tight-gas sands was proposed by the AAPG Unconventional Gas Research (UGR) subcommittee during the 2003 AAPG Annual Convention and Exhibition in Salt Lake City, Utah to address the great interest in unconventional petroleum systems and controversial aspects attributed to some tight-gas models. Contributions by the UGR should also be recognized for the AAPG Bulletin (v. 86) special theme issue on unconventional petroleum systems (Law and Curtis, 2002), including the paper by Law (2002) on basin-centered gas systems.
The Hedberg volume no. 3 summarizes the then current concepts and geology of basin-centered tight gas accumulations, including exploration and development case histories, and resource assessment methods. Although unconventional drilling activity in the U.S. has largely shifted focus away from tight-gas sands to shale gas plays with the development of horizontal drilling and multi-stage fracture stimulation, this volume continues to be an important resource for tight-gas sands, particularly with the increasing interest in exploiting tight-oil sand plays. In recognition of the contribution made by this publication towards a better understanding of tight-gas sand accumulations, it was awarded the AAPG R.H. Dott, Sr. Memorial Award for Best Special Publication in 2010.
Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007, Unconventional shale-gas systems: the Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment: AAPG Bulletin, v. 91, p. 475-499.
This paper is a geochemical assessment of the Mississippian Barnett Shale unconventional gas play of the Ft. Worth Basin, Texas. Because Newark East was the first giant unconventional shale gas field to be developed in the USA, this paper became a primary geochemical template for assessing unconventional shale plays in other basins, and remains so to this day. This paper should be among the first to be read when initiating an investigation of the nature of shale oil and gas reservoirs. The Barnett play fairway is in the eastern and deepest portion of the basin. This fairway has been named the Newark East Field. It was pioneered by Mitchell Energy (now Devon Energy). Using RockEval pyrolytic results of shale cuttings from numerous wells in the basin, the gas was characterized as thermogenic, produced from the transformation of Type II kerogen. Using average shale thickness of 350 ft, measured total organic carbon values and the pyrolysis results, a total generation potential of 820 BCFG/section was calculated. Using estimates of expulsed hydrocarbon, thermal maturity, and shale porosity, this figure was adjusted to obtain a maximum storage capacity of 540 MCFG/ac-ft. This is consistent with a world-class gas resource in place. At the time of publication, the authors stated that Newark East was the second largest gas field in the USA. The authors state that the best gas recoveries occur where the shale mineralogy is 45% quartz, and only 27% clay, due to elevated brittleness resulting in superior frac efficiencies. Also of interest, the authors show that gas flow rates markedly increase as Barnett thermal maturity increases. The paper has been cited 673 times (as of mid-2015).
Loucks, R. G., R. M. Reed, S. C. Ruppel, and D. M. Jarvie, 2009, Morphology, genesis and distribution of nanometer-scale pores in siliceous mudstones of the Mississippian Barnett Shale: Journal of Sedimentary Research, v. 79, p. 848-861.
Loucks et al., 2009 were first to identify and characterize various types of nanometer-scale pores important for hydrocarbon storage in shale reservoirs using a novel method of sample preparation utilizing argon-ion beam milling combined with scanning electron microscope imaging. This was the first identification of pores within organic matter in thermally mature organic-rich mudstones, which have now been recognized as a key attribute for shale gas reservoirs. As a result of this work, shale gas evaluations largely shifted away from the earlier coalbed methane inspired gas desorption measurements to measuring matrix porosity and free gas saturation. The authors also provided a model for the development of organic nanopores as a function of increasing thermal maturity in organic-rich mudstones. The recognition of the potential volumes of hydrocarbons that could be contained in the organic nanopores was a true paradigm shift in understanding the potential resource base in mudstone reservoirs. This paper has been cited 565 times (as of mid-2015).
Passey, Q. R., K. M. Bohacs, W. L. Esch, R. Klimentidis, and S. Sinha, 2010, From oil-prone source rock to gas-producing shale reservoir--geologic and petrophysical characterization of unconventional shale-gas reservoirs: Society of Petroleum Engineers, Paper 131350, 29 p.
Building on learnings about source rock occurrence and controls documented in previous papers, the authors have extended their work to define fundamental concepts for shale gas reservoirs. Sequence stratigraphic models were developed to better understand the geologic controls of the deposition and preservation of organic matter (total organic content) to improve source rock prediction. The geologic models are presented with state-of-the-art analytical laboratory techniques and petrophysical interpretation to illustrate a recommended integrated approach for unconventional shale reservoir evaluations. The paper also introduced an interpretative model for the distribution of water and gas in shale gas reservoirs, with free and adsorbed gas segregated to hydrocarbon-wet pores in organic matter, and water confined to various clay minerals. This gas-water saturation model is often used in petrophysical models to determine porosity and gas saturation in shale reservoirs. The paper has been cited 309 times (as of mid-2015), and downloaded 6886 times from One-Petro.
Sondergeld, C. H., K. E. Newsham, J. T. Comisky, M. C. Rice, and C. S. Rai, 2010, Petrophysical considerations in evaluating and producing shale gas resources: Society of Petroleum Engineers, Paper 131768.
This paper focuses on the laboratory and well log interpretation of gas-bearing mudstones, and specifically on the challenges presented in determining permeability due to gas sorption effects. One of the significant contributions is documenting the lack of industry standard protocols and inconsistent fundamental measurements by different commercial laboratories, even when measured on identical sample sets. They also are among the first to include laboratory and well log nuclear magnetic resonance (NMR) measurements for shale reservoir evaluation. As part of their petrophysical assessment approach, they provide a method to correct the Passey et al., 1990 (AAPG Bull., v. 74, p. 1777-1794) well log technique to estimate organic richness for high thermal maturity (i.e., vitrinite reflectance > 0.9 %Ro) shale gas reservoirs. This paper has been cited 199 times (as of mid-2015) and downloaded 8990 times from One-Petro.