John B. Curtis

Fractured Shale-Gas Systems

The first commercial United States natural gas production (1821) came from an organic-rich Devonian shale in the Appalachian basin. Understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have subsequently been the challenge of millions of dollars worth of research since the 1970s. Shale-gas systems essentially are continuous-type biogenic (predominant), thermogenic, or combined biogenic-thermogenic gas accumulations characterized by widespread gas saturation, subtle trapping mechanisms, seals of variable lithology, and relatively short hydrocarbon migration distances. Shale gas may be stored as free gas in natural fractures and intergranular porosity, as gas sorbed onto kerogen and clay-particle surfaces, or as gas dissolved in kerogen and bitumen. Five United States shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters: thermal maturity (expressed as vitrinite reflectance), sorbed-gas fraction, reservoir thickness, total organic carbon content, and volume of gas in place. The degree of natural fracture development in an otherwise low-matrix-permeability shale reservoir is a controlling factor in gas producibility. To date, unstimulated commercial production has been achievable in only a small proportion of shale wells, those that intercept natural fracture networks. In most other cases, a successful shale-gas well requires hydraulic stimulation. Together, the Devonian Antrim Shale of the Michigan basin and Devonian Ohio Shale of the Appalachian basin accounted for about 84% of the total 380 bcf of shale gas produced in 1999. However, annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed: the Devonian New Albany Shale in the Illinois basin, the Mississippian Barnett Shale in the Fort Worth basin, and the Cretaceous Lewis Shale in the San Juan basin. In the basins for which estimates have been made, shale-gas resources are substantial, with in-place volumes of 497‐783 tcf. The estimated technically recoverable resource (exclusive of the Lewis Shale) ranges from 31 to 76 tcf. In both cases, the Ohio Shale accounts for the largest share.

Coriolis and l-type interactions in the ν2, 2ν2, and ν4 states of 14NH3

High-resolution infrared spectra have been remeasured for the ..nu../sub 2/, 2..nu../sub 2/, and ..nu../sub 4/ bands of /sup 14/NH/sub 3/ using a vacuum grating infrared spectrometer and a diode laser spectrometer. Far-infrared spectra of /sup 14/NH/sub 3/ have been measured with microwave accuracy in the 700 to 1100 GHz region by employing a submillimeter wave spectrometer (RAD) with acoustic detection. The pure inversion and inversion-rotation transition frequencies in the ..nu../sub 2/ excited state of /sup 14/NH/sub 3/ have been determined for the first time. The vibration-inversion-rotation Hamiltonian of ammonia reported by Spirko, Stone, and Papousek has been used for a precise parameterization of the energy levels of ammonia. The ground state rotational and centrifugal constants of /sup 14/NH/sub 3/ have been determined using a modified method of combination differences. Coriolis and l-type interactions between ..nu../sub 2/, ..nu../sub 4/, 2..nu../sub 2/, ..nu../sub 2/ + ..nu../sub 4/, and 3..nu../sub 2/ states have been analyzed and the band parameters have been obtained which reproduce the transition frequencies within the accuracy of the experimental data.

Introduction to unconventional petroleum systems

Ben Law is a consultant and sole proprietor of Pangea Hydrocarbon Exploration LLC. His research interests include basin-centered gas and coalbed methane systems. Prior to his consulting position, he was a member and chief of the U.S. Geological Survey Western Tight Gas Sand Project and regional coordinator of South Asia for the U.S. Geological Survey World Energy Project. He received B.S. and M.S. degrees from San Diego State University, California.John B. Curtis is associate professor and director, Petroleum Exploration and Production Center/Potential Gas Agency at the Colorado School of Mines. He is an associate editor for the AAPG Bulletin and The Mountain Geologist. As director of the Potential Gas Agency, he works with a team of 145 geologists, geophysicists, and petroleum engineers in their biennial assessment of remaining United States natural gas resources. The collection of articles included in this theme issue of the AAPG Bulletin originated in the AAPG …

Evaluation of devonian shale with new core and log analysis methods

This paper discusses results of the study of Appalachian basin Devonian shale which show that all porosity exceeding 2.5% is occupied by free hydrocarbon (mostly gas). From analyses of logs and 519 ft of conventional core in four wells, reservoir porosity averages 5% and free-gas content averages 2% by bulk volume.

Effects of smectite on the oil-expulsion efficiency of the Kreyenhagen Shale, San Joaquin Basin, California, based on hydrous-pyrolysis experiments

The amount of oil that maturing source rocks expel is expressed as their expulsion efficiency, which is usually stated in milligrams of expelled oil per gram of original total organic carbon (). Oil-expulsion efficiency can be determined by heating thermally immature source rocks in the presence of liquid water (i.e., hydrous pyrolysis) at temperatures between 350°C and 365°C for 72 hr. This pyrolysis method generates oil that is compositionally similar to natural crude oil and expels it by processes operative in the subsurface. Consequently, hydrous pyrolysis provides a means to determine oil-expulsion efficiencies and the rock properties that influence them. Smectite in source rocks has previously been considered to promote oil generation and expulsion and is the focus of this hydrous-pyrolysis study involving a representative sample of smectite-rich source rock from the Eocene Kreyenhagen Shale in the San Joaquin Basin of California. Smectite is the major clay mineral (31 wt. %) in this thermally immature sample, which contains 9.4 wt. % total organic carbon (TOC) comprised of type II kerogen. Compared to other immature source rocks that lack smectite as their major clay mineral, the expulsion efficiency of the Kreyenhagen Shale was significantly lower. The expulsion efficiency of the Kreyenhagen whole rock was reduced 88% compared to that of its isolated kerogen. This significant reduction is attributed to bitumen impregnating the smectite interlayers in addition to the rock matrix. Within the interlayers, much of the bitumen is converted to pyrobitumen through crosslinking instead of oil through thermal cracking. As a result, smectite does not promote oil generation but inhibits it. Bitumen impregnation of the rock matrix and smectite interlayers results in the rock pore system changing from water wet to bitumen wet. This change prevents potassium ion () transfer and dissolution and precipitation reactions needed for the conversion of smectite to illite. As a result, illitization only reaches 35% to 40% at 310°C for 72 hr and remains unchanged to 365°C for 72 hr. Bitumen generation before or during early illitization in these experiments emphasizes the importance of knowing when and to what degree illitization occurs in natural maturation of a smectite-rich source rock to determine its expulsion efficiency. Complete illitization prior to bitumen generation is common for Paleozoic source rocks (e.g., Woodford Shale and Retort Phosphatic Shale Member of the Phosphoria Formation), and expulsion efficiencies can be determined on immature samples by hydrous pyrolysis. Conversely, smectite is more common in Cenozoic source rocks like the Kreyenhagen Shale, and expulsion efficiencies determined by hydrous pyrolysis need to be made on samples that reflect the level of illitization at or near bitumen generation in the subsurface.

Geochemistry of Strontium in the Scioto River Drainage Basin, Ohio

Ground water that emanates from carbonate bedrock in the Scioto River drainage basin is characterized by 87 Sr/ 86 Sr ratios in the range of 0.708 to 0.709; usually high Sr/Ca ratios in this water identify celestite lenses within the carbonate bedrock as the dominant source of strontium. Ground water from clastic bedrock, principally shale, has 87 Sr/ 86 Sr ratios that vary from about 0.710 to about 0.713 and shows low Sr/Ca ratios. Thus, there are two basic ground-water types that emanate from bedrock within the basin. They can be identified by these two parameters. Most ground water that has been in contact only with glacial till, which covers the northern two-thirds of the basin, has carbonate-type 87 Sr/ 86 Sr ratios as well as high Sr/Ca ratios. Celestite is apparently present in the till throughout much of the Scioto basin. Ground water that contains celestite-derived strontium, whether from the carbonate bedrock or the till, has so great a strontium content as to control completely the 87 Sr/ 86 Sr ratios of surface water northwest of the glacial boundary. This fact limits the usefulness of the 87 Sr/ 86 Sr parameter as a tracer in water studies within the basin.

Recoverable natural gas resource of the United States: Summary of recent estimates

A summary is presented between five recent estimates of the potential natural gas resource in the United States, including Alaska. Generated between 1995 and 2001 by both private and federal organizations, these estimates concern gas that is potentially recoverable under existing and foreseeable technological conditions. Proved reserves and cumulative production are not included. Thus, the assessments show estimated values for natural gas that remains to be found and developed. These assessments indicate an average total resource of 1549 tcf, or a 67 yr supply at current rates of consumption, approximately nine times the volume of proved reserves (177 tcf) in 2001. A considerable majority of each individual estimate (>70%) is interpreted by the respective organization to exist in conventional reservoirs. A significant percentage (average 17.8%) of each total resource is predicted to lie in tight gas sands, mainly within the coterminous United States. Both the scale and nature of the potential gas resource strongly suggest that a combination of economic incentives, long-term exploration, and improvements to recovery technology will be capable of greatly augmenting recoverable domestic reserves.

Accumulation of Organic Matter in the Rome Trough of the Appalachian Basin and Its Subsequent Thermal History

We used geochemical data to examine the origin and preservation of organic matter contained in the lower part of the Huron Member of the Ohio Shale formation and the Rhinestreet Shale Member of the West Falls Formation (Devonian) in Kentucky, Ohio, West Virginia, and Virginia. The thermal history of the organic matter was determined by relating relative temperatures experienced by the organic matter to the geologic setting. The organic matter in these formations is predominantly marine in origin and was most probably derived largely from algal organisms. Although the rate of production of marine organic matter may have been uniform within the basin, its preservation apparently was controlled by the existence of a set of fault-bounded anoxic subbasins associated with the Rome trough, a Cambrian structural complex. These subbasins apparently were anoxic because they limited oxygen recharge by circulating waters. Preservation of organic matter was also enhanced by periodic blooms of the alga Tasmanites and similar organisms in the waters above the subbasins during both early Huron and Rhinestreet deposition. A significant negative correlation was identified between the vitrinite reflectance peak temperature, an integrated measure of the thermal history of a rock, and the hydrogen index, a measure of the remaining hydrocarbon-generation potential of kerogen. Although peak temperatures were controlled by burial depth, excess heating occurred locally, perhaps by hot brines rising from depth through fractures associated with major structures in the study area.

How well do we know the size of the U.S. natural gas resource base

Published estimates of the US potential gas resource base vary considerably in magnitude. However, one finds a general agreement that a large, accessible natural gas resource base exists that both backs up the current inventory of proved gas reserves and is available to make a larger contribution to the nation`s energy supply. From a comparison of six such estimates by four industry and government organizations, this paper attempts to facilitate understanding of the differences in their (1) perceptions of the resource base, (2) data sources, and (3) analytical approaches. These differences lead directly to the differences in reported results. The apparent magnitudes of these differences diminish, however, on examination of the assumptions made by the organizations (particularly concerning the role of technology) and how they have defined the categories of assessed gas resources.

Interpretation of Natural Controls on Devonian Shale Gas Production from Seismic Data: ABSTRACT

Columbia Gas and the Gas Research Institute are studying a set of Devonian shale gas wells in southwestern West Virginia to determine the geologic controls on shale gas production. Approximately 25 line-mi of Vibroseis seismic data were recorded to (1) evaluate the regional geologic setting and structural style of the area; (2) evaluate relationships among the regional geology, a high producing shale gas area, and a postulated fault zone; (3) evaluate the local geologic setting of three study wells; and (4) attempt to recognize stratigraphic controls on shale gas production. Several initial conclusions concerning production controls have been reached. (1) Basement faulting extended up through the shale section, and resultant fracturing influenced gas production in the northern area of the seismic survey. (2) Reflection patterns in the shale contain information on the lithologic character of the shale. Local lenses of silt or sandy shale are probably present within the more fine-grained shale section. These lenses may be geologic features with increased permeability. (3) Areas of dimmed reflection energy on seismic lines correlate with areas of high gas reserves, suggesting that these areas are fractured shale. Information from the seismic survey is being integrated with core, log, and well-test data to understand the active controls on shale gas production in the study area. End_of_Article - Last_Page 1439------------