John B. Comer

Recognizing and Quantifying Expulsion of Oil from the Woodford Formation and Age-Equivalent Rocks in Oklahoma and Arkansas

Accumulations of oil in fractures, stylolites, burrows, sandstone lenses, and chert nodules, deeply embedded within organic-rich, mature oil source beds of Late Devonian-Early Mississippian age are considered prima facie evidence of internal migration and expulsion. Most oil migrated internally and was expelled as a separate phase. Within a given section in which chert and black shale are interbedded, contain the same type of organic matter, and have reached the same level of thermal maturity, black shales typically contain less hydrocarbons per weight percent TOC than cherts. The observed differences represent the amount of oil expelled from the black shales and range from 10 to 15 mg/g TOC for total bitumen, 7 to 8 mg/g TOC for saturated hydrocarbons, and 11 mg/g TOC for volatile hydrocarbons. Approximately 27-33% of the oil generated in these source rocks was calculated to have been expelled. In the main oil-producing region of central and southern Oklahoma, 22 billion bbl of bitumen and 16 billion bbl of saturated hydrocarbons were estimated to have been expelled from the Woodford formation. Relatively efficient, separate-phase oil expulsion may be characteristic of very rich oil source rocks like those reported here. Such rocks would reach effective oil saturation and begin to expel oil as a separate phase at a relatively early stage of generation. Timing and efficiency of oil expulsion must then be influenced by the concentration and type of organic matter in the source rock, because these factors determine the volume of oil generated and, hence, the time when a source rock becomes oil saturated.

A Reaction-Transport-Mechanical Approach to Modeling the Interrelationships Among Gas Generation, Overpressuring, and Fracturing: Implications for the Upper Cretaceous Natural Gas Reservoirs of the Piceance Basin, Colorado

Predicting reservoir characteristics in tight-gas sandstone reservoirs, such as those of the Upper Cretaceous units of the Piceance basin, is difficult due to the interactions of multiple processes acting on sediments during basin development. To better understand the dynamics of these systems, a forward numerical model, which accounts for compaction, fracturing, hydrocarbon generation, and multiphase flow (BasinRTM) is used in a one-dimensional simulation of the U.S. Department of Energys Multiwell Experiment (MWX) site in the Piceance basin. Of particular interest is the effect of gas generation on the dynamics of the system.

A subtle diagenetic trap in the Cretaceous Glauconite Sandstone of Southwest Alberta

Abstract Despite the long history of research which documents many studies involving extensive diagenesis, there are a few examples of a fully documented diagenetic trap. In the context of this paper, a trap is a hydrocarbon-bearing reservoir with a seal; because a reservoir without a seal acts as a carrier bed. The difficulty in the proper documentation of diagenetic traps is often due to the lack of: (a) extensive field records on the perforation and production histories, which assist in providing the depth of separation between hydrocarbon production and non-hydrocarbon or water production; and (b) the simultaneous availability of core data from these intervals, which could be studied for the extent and nature of diagenesis. This paper provides documentation for the existence of a diagenetic trap, based on perforation depths, production histories and petrologic data from the cored intervals, in the context of the geologic and stratigraphic setting. Cores from 15 wells and SP logs from 45 wells were carefully correlated and the data on perforated intervals was also acquired. Extensive petrographic work on the collected cores led to the elucidation of a diagenetic trap that separates water overlying and updip from gas downdip. Amocos Berrymore-Lobstick-Bigoray fields, located near the northeastern edge of the Alberta Basin, are prolific gas producers. The gas is produced from reservoir rock consisting of delta platform deposits formed by coalescing distributary mouth bars. The overlying rock unit is composed of younger distributary channels; although it has a good reservoir quality, it contains and produces water only. The total thickness of the upper, water-bearing and lower gas-bearing sandstone is about 40 ft. The diagenetic seal is composed of a zone 2 to 6 ft thick, located at the base of distributary channels. This zone is cemented with 20–30% ankerite cement, which formed the gas migration and is also relatively early compared to other cements formed in the water zone. In addition to this barrier to vertical flow, a barrier to lateral flow is formed by the merging of the upper sandstone containing 14% kaolinite and the lower sandstone containing 20% siderite. The measured core permeabilities in these zones vary from 0.0002 to 0.001 milli-darcies. This spatial configuration of diagenetic cements causing porous and non-porous zones is a result of the process of geochemical self-organization. The spatial and temporal patterns of diagenesis are a complex result of coupling of natural processes involving fluid flow, fluid composition, mineral composition and mineral dissolution rates under the conditions of varying pressure and temperature in the subsurface.

Source Rock Potential of Upper Devonian-Lower Mississippian Formations in Oklahoma and Western Arkansas: ABSTRACT

In central and southern Oklahoma, Upper Devonian-Lower Mississippian strata are rich oil source beds (mean = 7% TOC) at an early stage of generation. The major accumulations of oil in this region have been documented as coming from the Woodford formation. Equivalent-age source rocks in the deep part of the Anadarko basin have matured to or beyond the gas generation stage and significant generation is still occurring within parts of the basin. Around the Ozark uplift, age-equivalent rocks contain less organic matter (mean = 3.5% TOC) and more terrigenous clastic sediment than in central and southern Oklahoma. Both oil- and gas-generating types of kerogen are present and the organic matter has reached the early to main stages of oil generation. Upper Devonian-Lower Mississippian source rocks in the Ouachita core area are metamorphosed and no longer have significant hydrocarbon-generating capability. Age-equivalent rocks in the frontal zone are rich oil source beds at an early stage of generation. Significant hydrocarbon accumulations are possible at depth within the frontal zone and from frontal zone rocks that have been overthrust by metamorphosed Ouachita core-area rocks, particularly in the northwestern part of the Ouachita province.

Deposition and Diagenesis of Glauconite Sandstone, Berrymore-Lobstick-Bigoray Area, South-Central Alberta: ABSTRACT

The depositional environments of the Glauconite sandstone in the Berrymore-Lobstick-Bigoray area are distributary channels, delta platform, distributary mouth bars, and interdistributary bays. The diagenetic mineralogy is consistent with the formation water chemistry . A simplified model for evolution of Glauconite sandstone water compositions includes (1) original derivation in a deltaic setting giving composition of early pore waters as brackish to normal marine, (2) alteration due to inorganic and organic chemical diagenesis, and (3) dilution through time due to meteoric water recharge. The formation waters now evolved have such a composition as to be (1) oversaturated with respect to hematite, kaolinite, and illite (late-stage cements); and (2) near equilibrium to undersaturated with respect to quartz, calcite, siderite, and dolomite. The early diagenetic mineralogy is a function of early pore waters and thus the subenvironment. For example, ankerite cement forms early at the base of distributary channels. The intermediate to late diagenetic cementation is a function of early diagenetic mineralogy. For example, hematite is formed by the oxidation of siderite due to meteoric water recharge. Oxidation of pyrite is quantitatively unimportant. Occurrence of late stage hematite is associated with structural highs which are most affected by meteoric water recharge. Delta platform deposits contain gas, and distributary channel and distributary mouth bar deposits contain water. Delta platform deposits are isolated from distributary channel and distributary mouth bar deposits by a vertical permeability barrier of ankerite cement and a lateral permeability barrier of siderite and kaolinite cement, respectively. End_of_Article - Last_Page 606------------