Mitchell E. Henry

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.

Material-balance assessment of the New Albany-Chesterian petroleum system of the Illinois basin

The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrous-pyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.

Timing and petroleum sources for the Lower Cretaceous Mannville Group oil sands of northern Alberta based on 4-D modeling

The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian–Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl).

Evaluation of undiscovered natural gas in the Upper Cretaceous Ferron Coal/Wasatch Plateau Total Petroleum System, Wasatch Plateau and Castle Valley, Utah

Abstract The Total Petroleum System approach was used to estimate undiscovered gas potential of the Wasatch Plateau and Castle Valley, central Utah. The Ferron Coal/Wasatch Plateau Total Petroleum System was geologically defined and subdivided into seven assessment units, six of which were formally evaluated. Geologic data considered in defining the assessment unit boundaries included thermal maturity, coal presence and thickness, overburden thickness, and faulting intensity. Historical production data were also used to estimate volumes of gas from undrilled areas. The one conventional assessment unit includes almost the entire area of the petroleum system and is characterized by known accumulations that occur in structural or combination traps in sandstone reservoirs. The estimated undiscovered conventional producible gas that may be added to reserves of this unit ranges from a low (F95) of 14.8 billion cubic feet (BCFG) [419 million cubic meters (Mm 3 )] of gas to a high (F5) of 82 BCFG [2321 Mm 3 ] and a mean value of 39.9 BCFG [1130 Mm 3 ]. Continuous gas accumulations are those in which the entire assessment unit is considered to be gas-charged. Within these assessment units, there may be wells drilled that are not economic successes but all are expected to contain gas. Coalbed gas is in this continuous category. Mean estimates of undiscovered gas for the five continuous assessment units are: (1) Northern Coal Fairway/Drunkards Wash—752.3 BCFG [21,323 Mm 3 ]; (2) Central Coal Fairway/Buzzard Bench—536.7 BCFG [15,194 Mm 3 ]; (3) Southern Coal Fairway—152.6 BCFG [4320 Mm 3 ]; (4) Deep (6000 feet plus) Coal and Sandstone—59.1 BCFG [1673 Mm 3 ]; (5) Southern Coal Outcrop—10.6 BCFG [300 Mm 3 ]; and Joes Valley and Musinia Grabens—not assessed. The mean estimate of undiscovered gas for the entire TPS is 1551.2 BCFG [43,914 Mm 3 ]. There is a 95% chance that at least 855.7 BCFG [24,225 Mm 3 ] and a 5% chance that at least 2504 BCFG [70,888 Mm 3 ] of undiscovered producible gas remain in the TPS.

C4-benzene and C4-naphthalene thermal maturity indicators for pyrolysates, oils and condensates

Abstract Determining the thermal maturity of light oils and condensates using chemical indicators can be difficult. Here we describe the use of C 4 -benzenes (C 10 ) and C 4 -naphthalenes (C 14 ) which are common constituents of oils and condensates as potential thermal maturity indicators. Using confined, dry pyrolysis of a saturate-rich Devonian oil from the Western Canada Sedimentary Basin, experiments were performed at 350–400°C, 650 bars and at time periods ranging from 3 to 33 days. The equivalent vitrinite reflectance (% R 0 ) for the pyrolysis products (1.02–1.67%) was calculated from experimental conditions using Easy R 0 software ( Geochim. Cosmochim Acta 53 , 1989, 2649–2657) to assess relative experimental thermal maturity. Ratios employing tetramethyl-, dime thy lethyl-, and methylisopropylbenzene isomers and tetrametnyl-naphthalene isomers correlate with calculated % R 0 from pyrolysis. Excellent correlation of all C 4 -benzene parameters and most C 4 -naphthalene parameters was observed. The thermal maturity parameters defined by pyrolysis were applied to oils in the Fort Worth Basin, Texas, USA to determine applicability in natural systems. All C 4 -benzene and C 4 -naphthalene parameters showed positive correlation with the triaromatic steroid (TAS) maturity parameter commonly used to assess oil maturity. C 4 -benzene and C 4 -naphthalene ratios extend beyond the range of biomarker applicability, especially TAS, and are more abundant than biomarkers and less volatile than C 7 hydrocarbons.

Marine Petroleum Prospecting with Airborne Fraunhofer Line Discriminator: ABSTRACT

Natural oil slicks from the Santa Barbara Channel, California, have been imaged using an airborne Fraunhofer Line Discriminator (FLD). The imaged distribution correlates well with aerial photographs, visual observations, and simultaneous television monitoring. However, the areal extent of the surface film mapped by the FLD is larger than that determined by the other methods, suggesting that the FLD is more sensitive to exceptionally thin films. Digital image-enhancement techniques applied to multispectral FLD data may provide general compositional information. The FLD may be useful to explorationists looking for evidence of hydrocarbons in frontier marine areas. End_of_Article - Last_Page 722------------