Daniel M. Jarvie

Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment

Shale-gas resource plays can be distinguished by gas type and system characteristics. The Newark East gas field, located in the Fort Worth Basin, Texas, is defined by thermogenic gas production from low-porosity and low-permeability Barnett Shale. The Barnett Shale gas system, a self-contained source-reservoir system, has generated large amounts of gas in the key productive areas because of various characteristics and processes, including (1) excellent original organic richness and generation potential; (2) primary and secondary cracking of kerogen and retained oil, respectively; (3) retention of oil for cracking to gas by adsorption; (4) porosity resulting from organic matter decomposition; and (5) brittle mineralogical composition. The calculated total gas in place (GIP) based on estimated ultimate recovery that is based on production profiles and operator estimates is about 204 bcf/section (5.78 × 10 9 m 3 /1.73 × 10 4 m 3 ). We estimate that the Barnett Shale has a total generation potential of about 609 bbl of oil equivalent/ac-ft or the equivalent of 3657 mcf/ac-ft (84.0 m 3 /m 3 ). Assuming a thickness of 350 ft (107 m) and only sufficient hydrogen for partial cracking of retained oil to gas, a total generation potential of 820 bcf/section is estimated. Of this potential, approximately 60% was expelled, and the balance was retained for secondary cracking of oil to gas, if sufficient thermal maturity was reached. Gas storage capacity of the Barnett Shale at typical reservoir pressure, volume, and temperature conditions and 6% porosity shows a maximum storage capacity of 540 mcf/ac-ft or 159 scf/ton.

Mississippian Barnett Shale, Fort Worth basin, north-central Texas: Gas-shale play with multi–trillion cubic foot potential

The Mississippian Barnett Shale serves as source, seal, and reservoir to a world-class unconventional natural-gas accumulation in the Fort Worth basin of north-central Texas. The formation is a lithologically complex interval of low permeability that requires artificial stimulation to produce. At present, production is mainly confined to a limited portion of the northern basin where the Barnett Shale is relatively thick (>300 ft; >92 m), organic rich (presentday total organic carbon > 3.0%), thermally mature (vitrinite reflectance > 1.1%), and enclosed by dense limestone units able to contain induced fractures. The most actively drilled area is Newark East field, currently the largest gas field in Texas. Newark East is 400 mi 2 (1036 km 2 ) in extent, with more than 2340 producing wells and about 2.7 tcf of booked gas reserves. Cumulative gas production from Barnett Shale wells through 2003 was about 0.8 tcf. Wells in Newark East field typically produce from depths of 7500 ft (2285 m) at rates ranging from 0.5 to more than 4 mmcf/day. Estimated ultimate recoveries per well range from 0.75 to as high as 7.0 bcf. Efforts to extend the current Barnett play beyond the field limits have encountered several challenges, including westward and northward increases in oil saturation and the absence of lithologic barriers to induced fracture growth. Patterns of oil and gas occurrence in the Barnett, in conjunction with maturation and burial-history data, indicate a complex, multiphased thermal evolution, with episodic expulsion of hydrocarbons and secondary cracking of primary oils to gas

Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch–Fort Worth Basin, Texas

This article describes the primary geologic characteristics and criteria of the Barnett Shale and Barnett-Paleozoic total petroleum system (TPS) of the Fort Worth Basin used to define two geographic areas of the Barnett Shale for petroleum resource assessment. From these two areas, referred to as assessment units, the U.S. Geological Survey estimated a mean volume of about 26 tcf of undiscovered, technically recoverable hydrocarbon gas in the Barnett Shale. The Mississippian Barnett Shale is the primary source rock for oil and gas produced from Paleozoic reservoir rocks in the Bend arch–Fort Worth Basin area and is also one of the most significant gas-producing formations in Texas. Subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the Barnett Shale is organic rich and thermally mature for hydrocarbon generation over most of the Bend arch–Fort Worth Basin area. In the northeastern and structurally deepest part of the Fort Worth Basin adjacent to the Muenster arch, the formation is more than 1000 ft (305 m) thick and interbedded with thick limestone units; westward, it thins rapidly over the Mississippian Chappel shelf to only a few tens of feet. The Barnett-Paleozoic TPS is identified where thermally mature Barnett Shale has generated large volumes of hydrocarbons and is (1) contained within the Barnett Shale unconventional continuous accumulation and (2) expelled and distributed among numerous conventional clastic- and carbonate-rock reservoirs of Paleozoic age. Vitrinite reflectance (Ro) measurements show little correlation with present-day burial depth. Contours of equal Ro values measured from Barnett Shale and typing of produced hydrocarbons indicate significant uplift and erosion. Furthermore, the thermal history of the formation was enhanced by hydrothermal events along the Ouachita thrust front and Mineral Wells–Newark East fault system. Stratigraphy and thermal maturity define two gas-producing assessment units for the Barnett Shale: (1) a greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit, encompassing an area of optimal gas production where dense impermeable limestones enclose thick (300 ft; 91 m) Barnett Shale that is within the gas-generation window (Ro 1.1%); and (2) an extended continuous Barnett Shale gas assessment unit covering an area where the Barnett Shale is within the gas-generation window, but is less than 300 ft (91 m) thick, and either one or both of the overlying and underlying limestone barriers are absent.

Oil and gas geochemistry and petroleum systems of the Fort Worth Basin

Detailed biomarker and light hydrocarbon geochemistry confirm that the marine Mississippian Barnett Shale is the primary source rock for petroleum in the Fort Worth Basin, north-central Texas, although contributions from other sources are possible. Biomarker data indicate that the main oil-generating Barnett Shale facies is marine and was deposited under dysoxic, strong upwelling, normal salinity conditions. The analysis of two outcrop samples and cuttings from seven wells indicates variability in the Barnett Shale organic facies and a possibility of other oil subfamilies being present. Light hydrocarbon analyses reveal significant terrigenous-sourced condensate input to some reservoirs, resulting in terrigenous and mixed marine-terrigenous light hydrocarbon signatures for many oils. The light hydrocarbon data suggest a secondary, condensate-generating source facies containing terrigenous or mixed terrigenous-marine organic matter. This indication of a secondary source rock that is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to define petroleum source rocks. Gases in the Fort Worth Basin are thermogenic in origin and appear to be cogenerated with oil from the Barnett Shale, although some gas may also originate by oil cracking. Isotope data indicate minor contribution of biogenic gas. Except for reservoirs in the Pennsylvanian Bend Group, which contain gases spanning the complete range of observed maturities, the gases appear to be stratigraphically segregated, younger reservoirs contain less mature gas, and older reservoirs contain more mature gas. We cannot rule out the possibility that other source units within the Fort Worth Basin, such as the Smithwick Shale, are locally important petroleum sources.

Hydrocarbon potential of the Barnett Shale (Mississippian), Delaware Basin, west Texas and southeastern New Mexico

The Barnett Shale (Mississippian) in the Delaware Basin has the potential to be a prolific gas producer. The shale is organic rich and thermally mature over large parts of the basin. Depths to the Barnett range from 7000 ft (2133 m) along the western edge of the basin to more than 18,000 ft (5486 m) along the basin axis. The Barnett Shale began generating petroleum about 250 Ma and reached its maximum temperature about 260 Ma. Present-day thermal maturity is indicative of maximum burial and temperature. Wells in northern Reeves County are in the gas window based on measured vitrinite reflectance values and kerogen transformation ratios. The shale can be divided into an upper clastic unit and a lower limy unit by changes in resistivity. The lower unit can be subdivided into five subunits by distinctive well-log markers. Preliminary analyses suggest that intervals in the lower Barnett marked by high resistivity and high neutron porosity readings on well logs have high gas contents. Areas in which to focus the future exploration in the lower Barnett can be delineated by mapping a net resistivity greater than 50 ohm m. The Barnett Shale contains significant gas resources in the Delaware Basin. Realizing the potential of these resources depends on the current efforts to optimize drilling and completion techniques for this shale-gas play.

The fate of diamondoids in coals and sedimentary rocks

Diamondoids were detected in the extracts of a series of coals and rocks varying in maturity, lithology, source input, and depositional environment. At the same maturity level, diamondoids are generally about a magnitude more abundant in source rocks than in coals. The concentrations of diamondoids are maturity dependent. However, while diamondoids become more abundant with the increasing thermal maturity, a diminution in diamondoid concentrations is observed at the maturity value of about R{sub o} = 4.0% in both coals and rocks. The occurrence of diamantane destruction at 550{sup o}C during pyrolysis suggests that diamondoids may be eventually destroyed at high temperatures in the Earth. Here we propose three main phases of diamondoid life in nature: diamondoid generation (phase I, R{sub o} 4.0%).

Effect of evaporation on C7 light hydrocarbon parameters

Abstract Light hydrocarbons are commonly used to evaluate crude oils to determine oil families, in-reservoir alteration processes such as evaporative fractionation, water washing, incipient biodegradation, maturity, and temperatures at which oil is expelled from source rocks. Light hydrocarbons in the C7 range will evaporate under ambient conditions, and losses can occur during sample collection, handling, or storage. However, the impact of partial evaporation on interpretation of light hydrocarbon data has not been reported previously. Laboratory evaporation experiments show that the rate of evaporation of each C7 hydrocarbon is different, and these differential rates will affect the measured concentrations of these compounds, certain ratios, and other calculations or plots using these data. The paraffinicity/aromaticity ratio of Thompson [Marine Pet. Geol. 5 (1988) 237], parameters utilized in the transformation and correlation star diagrams of Halpern [AAPG Bull. 79 (1995) 801], and the oil typing ternary plot of Jarvie [The Mountain Geologist 38 (2001) 19] are affected by evaporation. Other interpretive schemes such as P2 versus N2/P3 and the invariant ratio [Science 273 (1987) 514; Geochim. Cosmoschim. Acta 54 (1990) 1315] are not grossly affected by partial evaporation because these parameters are primarily controlled by the concentration of methylhexanes or by offsetting rates of evaporation in certain compounds. By careful evaluation of these parameters and various interpretive plots, the extent of evaporation can be qualitatively assessed and discrimination of oil types, alteration effects, and evaporative artifacts can still be reasonably ascertained. This study demonstrates that preservation of crude oils from evaporation is essential for accurate application of all light hydrocarbon parameters, although some parameters may still be utilized when partial evaporation has occurred.

ABSTRACT: Hydrocarbon Charge Assessment, Gulf of Mexico: Rates of Oil/Gas Generation from Source Rocks and Oil Asphaltenes

Analysis of petroleum systems from oil geochemistry in the Gulf of Mexico has provided inferences regarding sources for hydrocarbons. Source rocks from the Tertiary and Cretaceous have been have been reported in Mississippi Canyon. Other Cretaceous source rocks have been described from cores at DSDP Site 535. While these data and inferences from inversion of oil geochemistry provide very solid evidence as to the formations that are sourcing oil and gas deposits, they do not provide the data necessary to predict accurately hydrocarbon charge. Hydrocarbon charge is dependent not only on identification of the effective source of oil and gas deposits, but also the timing of hydrocarbon generation, expulsion, and entrapment. The timing of hydrocarbon generation is a function of the rate of source rock decomposition (kinetic parameters) under a given burial and thermal history. Bulk and compositional kinetic parameters measured on Tertiary source rocks show very broad hydrocarbon generation rates and much higher yields of dry and wet gas. DSDP Site 535 Cretaceous source rocks show considerable variation in the rates of hydrocarbon generation. Jurassic source rocks also show variable hydrocarbon generation rates that appear to be a function of the sulfur content. These kinetic data provide the ability to accurately model hydrocarbon charge - oil and gas - using sophisticated models appropriate for the Gulf of Mexico.