Barry Jay Katz

Modeling of gas generation from the Barnett Shale, Fort Worth Basin, Texas

The generative gas potential of the Mississippian Barnett Shale in the Fort Worth Basin, Texas, was quantitatively evaluated by sealed gold-tube pyrolysis. Kinetic parameters for gas generation and vitrinite reflectance (Ro) changes were calculated from pyrolysis data and the results used to estimate the amount of gas generated from the Barnett Shale at geologic heating rates. Using derived kinetics for Ro evolution and gas generation, quantities of hydrocarbon gas generated at Ro 1.1% are about 230 L/t (7.4 scf/t) and increase to more that 5800 L/t (186 scf/t) at Ro 2.0% for a sample with an initial total organic carbon content of 5.5% and Ro = 0.44%. The volume of shale gas generated will depend on the organic richness, thickness, and thermal maturity of the shale and also the amount of petroleum that is retained in the shale during migration. Gas that is reservoired in shales appears to be generated from the cracking of kerogen and petroleum that is retained in shales, and that cracking of the retained petroleum starts by Ro 1.1%. This result suggests that the cracking of petroleum retained in source rocks occurs at rates that are faster than what is predicted for conventional siliciclastic and carbonate reservoirs, and that contact of retained petroleum with kerogen and shale mineralogy may be a critical factor in shale-gas generation. Shale-gas systems, together with overburden, can be considered complete petroleum systems, although the processes of petroleum migration, accumulation, and trap formation are different from what is defined for conventional petroleum systems.

Significance of microbial processes in gases of the South Caspian basin

Abstract The South Caspian basin has been a major petroleum-producing province for more than a century. While the basins oil has been the focus of a number of studies the regions gas has been largely understudied. This study examines 31 gas samples from 14 fields with the primary purpose of determining their mode(s) of formation and the role that microbial activity has had in their formation and alteration. The basins natural gas accumulations display significant differences in both molecular and isotopic composition. Gas wetness ranges from less than 1% at Absheron to greater than 12% at Guneshli. Methane carbon isotopic composition ranges from −57 to −37‰ relative to the PDB standard. The stable carbon isotopic composition of the wet gas (C 2+ ) components also displays a very broad range (e.g. C 2 ranges from −37 to −20‰; C 3 ranges from −31 to −10‰; and n C 4 ranges from −30 to −11‰). No strong depth-related trends were observed in any of the geochemical attributes. The absence of a trend implies that the gases have not been generated in situ but have migrated vertically, been altered, or represent a mixed product. Mixing is also suggested by the differences in the calculated thermal maturity levels between the C 2+ components and methane. In some accumulations (e.g. Karabagly) as much as 55% of the methane may have a biogenic origin. These data further indicate that among the gas samples studied those from Bakhar appear to be the most mature, with thermal maturity values consistent with the ‘condensate-window’. In several fields, including Guneshli and Neftchala, the wet gas components display evidence for microbial alteration. This is largely manifested in anomalously heavy isotopic compositions of propane, n -butane, and n -pentane.

Modeling of gas generation from the Cameo coal zone in the Piceance Basin, Colorado

The gas generative potential of the Cretaceous Cameo coal in the Piceance Basin, northwestern Colorado, was evaluated quantitatively by sealed gold tube pyrolysis. The H/C and O/C elemental ratios show that pyrolyzed Cameo coal samples follow the Van Krevelen humic coal evolution pathway, reasonably simulating natural coal maturation. Kinetic parameters (activation energy and frequency factor) for gas generation and vitrinite reflectance (Ro) changes were calculated from pyrolysis data. Experimental Ro results from this study are not adequately predicted by published Ro kinetics and indicate the necessity of deriving basin-specific kinetic parameters when building predictive basin models. Using derived kinetics for Ro evolution and gas generation, basin modeling was completed for 57 wells across the Piceance Basin, which enabled the mapping of coal-rank and coalbed gas potential. Quantities of methane generated at approximately 1.2% Ro are about 300 standard cubic feet per ton (scf/ton) and more than 2500 scf/ton (in-situ dry-ash-free coal) at Ro values reaching 1.9%. Gases generated in both low- and high-maturity coals are less wet, whereas the wetter gas is expected where Ro is approximately 1.4–1.5%. As controlled by regional coal rank and net coal thickness, the largest in-place coalbed gas resources are located in the central part of the basin, where predicted volumes exceed 150 bcf/mi^2, excluding gases in tight sands.

Alternative interpretations as to the origin of the hydrocarbons of the Guajira Basin, Colombia

Abstract The origins of the hydrocarbon gases recovered from the Chuchupa, Ballena, and Riohacha fields, located in the Guajira basin, northeast Colombia, are examined. These gases are composed of methane with trace amounts of wet gas components (C2+ The gases recovered at three onshore seep localities appear to include a thermogenic component. As a result of fractionation it is unclear whether they represent ‘pure’ thermogenic gases or a mixed thermogenic-biogenic origin similar to Chuchupa. An examination of oil microseepage observed in soil samples recovered from the onshore Guajira region point to another hydrocarbon system apparently not related to the three gas fields. Some of these microseeps include ‘fresh’ (nonbiodegraded) oils. These microseeps did not correlate with either of the Tertiary oil families from the Sinu Uraba basin located to the southwest of the study area or with Cretaceous oils from that basin. A better correlation was observed with the La Luna Formation, but significant differences remain implying that the source for the microseeps was less calcareous and deposited in a less restricted environment than associated with ‘classical’ La Luna facies. This could indicate either a facies change or that a different source unit is present within the region.

A review and technical summary of the AAPG Hedberg Research Conference on “Origin of petroleum—Biogenic and/or abiogenic and its significance in hydrocarbon exploration and production”

A research conference originally scheduled as a Hedberg Research Conference examining the origins of oil and gas was held in Calgary, June 2005. This report summarizes the 14 presentations made at the conference, which discussed data and evidence regarding the abiogenic and biogenic origins of petroleum. In addition, the postpresentation discussion is summarized. Multiple concepts for the abiogenic formation of petroleum were presented. These concepts fell mostly into two broad families: mantle degassing associated with the polymerization of low molecular weight compounds and serpentization in association with Fischer-Tropsch reactions. The Fischer-Tropsch reactions are catalyzed reactions in which carbon monoxide and hydrogen are converted into hydrocarbons. The presentations on the biogenic origin presented a uniform model in which sedimentary organic matter is thermally converted to oil and gas. Little common ground was found to exist between the abiogenic and biogenic schools of petroleum formation, with the possible exception of the importance of fluid flow in controlling the formation of hydrocarbon accumulations. Although few, if any, conference participants changed their perspectives, most concluded that the meeting was informative and a useful exercise.

Oil quality in deep-water settings: Concerns, perceptions, observations, and reality

As exploration migrates into deeper water, crude-oil quality becomes increasingly important. Variations in oil quality, which are reflected in such properties as API gravity, viscosity, sulfur content, and acid number impact both value and producibility. In fact, issues of oil quality in deep water may, in some cases, be more critical than issues of hydrocarbon volume. Problems associated with deep water are commonly thought to be amplified largely as a result of the expansion of the biodegradation window. The expanded window is a result of lower temperatures at the mud line. A review of data from the Gulf of Mexico and the Gulf of Guinea reveals that other factors may have a greater influence on oil quality. For example, in the Gulf of Mexico, strong evidence exists that the nature of the source rock is a major factor in establishing sulfur content and API gravity. Oils derived from an Upper Jurassic Oxfordian calcareous source rock generate oils with higher sulfur contents than those derived from Cretaceous argillaceous source rocks. In the Gulf of Guinea, although many of the newly discovered pools are shallowly buried and evidence for biodegradation exists, crude-oil quality is mitigated by multiple charging events. In both regions, evidence also exists for phase segregation, which introduces light oils and condensates into the shallow part of the sedimentary sequence. Both phase segregation and multiple charging events appear to be largely a result of an individual traps structural evolution. The available data, therefore, suggest that some of the risks associated with oil quality may be reduced through a more detailed assessment of a prospects filling history and structural evolution and an understanding of the nature of the source facies. However, there clearly are such situations as offshore Brazil, where the risks associated with oil quality appear more difficult to mitigate.

A review and technical summary of the AAPG/Associacion Mexicana de Geologos Petroleros Hedberg Research Conference on heavy oil: Origin, prediction, and production in deep waters

A joint AAPG/Associacion Mexicana de Geologos Petroleros (AMGP) Hedberg Research Conference was held to examine issues associated with heavy oil in deep water. This article reports on the meeting highlights. Deep-water exploration has become increasingly important over the last three decades. For the deep-water environment to be economically viable, these accumulations need to be both volumetrically significant and capable of maintaining high production rates. Largely independent of the rise in crude oil price, there has been an increasing number of economically viable deep-water discoveries, where the resource base now exceeds 100 billion bbl oil equivalent. A significant percentage of this resource is heavy oil, with heavy oil dominating the resource base in such settings as offshore Mexico and Brazil. Economic success in both exploration and commercialization requires integration across disciplines as well as across the value chain, integrating the upstream, midstream, and downstream operations. Basin models were commonly used as the integration tool for exploration programs. The exploration risks associated with the deep-water environment tend to be higher, in part as a result of oil quality. Risk reduction can be partially accomplished through a better understanding of the factors that control oil quality, including source rock facies, thermal maturity, and the alteration and migration histories. Although several factors may impact crude quality, the consensus was that biodegradation was the dominant factor controlling quality in most deep-water regions, Mexico being an exception, where source rock character has an important function. Biodegradation is controlled by such factors as charge and thermal history and the geometry of the oil-water contact. Where source facies is a key factor in establishing the presence of heavy-oil migration, distances tend to be more limited. Mixing of oils also appears to be an important factor in determining oil quality, often improving or maintaining oil quality, with the introduction of light oils into biodegraded oil. The production of these heavy oils introduces several challenges above and beyond those associated with similar accumulations onshore and in shallow waters. Lessons learned from these settings can, however, be very useful when working in the deep-water setting. The value of continuous data collection and updating reservoir models was made clear in case studies from both Angola and Brazil, where phased development or reservoir model recycling permitted the more efficient use of capital. Also of importance is the need for long-term planning because of the long lives of heavy-oil accumulations.

Integration of Basin Modelling, Uncertainty Analysis, HC Charge Volume Assessment in Petroleum Exploration Risk Evaluation

Recent developments in hydrocarbon (HC) exploration have necessitated the strengthening and greater integration of geologic model building. Robust basin modeling requires a two-step procedure consisting of constructing reliable input frameworks that are consistent with available data and geologic interpretations and related geohistory processes and conducting basin simulation tests to explore and determine the confidence level of modeling results. Integrating structural components such as faulting and salt movement is a key element and requires their restoration through time. These restorations impact our understanding of basin development, HC migration patterns, fetch areas, as well as the assessment of potential HC volumes. The granularity or resolution of the stratigraphic input may also alter the modeled migration pattern, including the relative importance of lateral and vertical components and distance. Key modeling input parameters include the source rock distribution through time and space. This input can be developed through the integration of geochemical data with stratigraphy, paleo-bathymetric framework, and other basin specific conditions (e.g., paleolatitude). As a result, a 3-D framework of organic richness and kerogen type can be developed. The restorations and interpretations are imbedded within the basin modeling workflow and iteratively interact with the basin’s burial history modeling. This iterative approach along with the numeric simulator accomplishes the integration and optimization of the input geologic model and directly yields more realistic modeling results consistent with the basin’s specific geology. 2 IPTC 16423 Finally, in order to capture the full range of uncertainty in the petroleum system and to objectively evaluate the hydrocarbon potential and risks in the basin, a suite of simulations need to be performed using a probabilistic approach to determine the confidence level to be placed on the HC volume potential and risks in the analyzed basin.