Denver Basin Research Articles

The potential for intrinsic bioremediation of BTEX hydrocarbons in soil/ground water contaminated with gas condensate

Gas condensate liquids contaminate soil and ground water at two gas production sites in the Denver Basin, CO. A detailed field study was carried out at these sites to determine the applicability of intrinsic bioremediation as a remediation option. Ground water monitoring at the field sites and analysis of soil cores suggested that intrinsic bioremediation is occurring at the sites by multiple pathways, including aerobic oxidation, sulfate reduction, and possibly reduction Fe(III) reduction. Laboratory investigations were conducted to verify that the water-soluble components of the gas condensate (benzene, toluene, ethylbenzene, and xylene [BTEX]) are intrinsically biodegradable under anoxic conditions in the presence of alternate electron acceptors and soil from the field site. Slurry-phase experiments were conducted in which soil obtained from the field site was mixed with an aqueous phase containing nutrients and electron acceptors (nitrate, Fe[III], sulfate and carbon dioxide) in serum bottles. The aqueous phase also contained soluble components of gas condensate, at two different hydrocarbon concentrations, obtained from the field site. The soil was either pristine (native) soil or soil obtained from a condensate-contaminated region. The aqueous phase was sampled for electron acceptors, hydrocarbons, and possible products of hydrocarbon degradation. Toluene and xylenes were biodegraded with nitrate or sulfate as the electron acceptor. No degradation of benzene was observed under anoxic conditions.

Intrinsic bioremediation of gas condensate hydrocarbons

Condensate liquids have been found to contaminate soil and ground water at two gas production sites in the Denver Basin operated by Amoco Production Co. These sites have been closely monitored since July 1993 to determine whether intrinsic aerobic or anaerobic bioremediation of hydrocarbons occurs at a sufficient rate and to an adequate end point to support a no-intervention decision. Ground water monitoring, soil gas analysis, and analysis of soil cores suggest that bioremediation is occurring at these sites by multiple pathways, including aerobic oxidation, sulfate reduction, and methanogenesis. Results of over two years of monitoring of ground water and soil chemistry at these sites are presented to support this conclusion.

Abstract: Exploration Strategies for D Sandstone Reservoirs in Basin-Center Area, Denver Basin 

Abstract: Exploration Strategies for D Sandstone Reservoirs in Basin-Center Area, Denver Basin 

Abstract: 3-D Distribution of Gas Production across the Wattenberg Field, Denver Basin, Colorado 

Abstract: 3-D Distribution of Gas Production across the Wattenberg Field, Denver Basin, Colorado 

Abstract:  Integrated 3-D Seismic and Petroleum Engineering Reservoir Characterization of a Sealing Fault System, Hambert Field Terry Sandstone Reservoir, Denver Basin 

Abstract:  Integrated 3-D Seismic and Petroleum Engineering Reservoir Characterization of a Sealing Fault System, Hambert Field Terry Sandstone Reservoir, Denver Basin 

Abstract: Integration of Surface Geochemical and Seismic Methods in Exploring for D and J Sands in the Denver Basin 

Abstract: Integration of Surface Geochemical and Seismic Methods in Exploring for D and J Sands in the Denver Basin 

Abstract: Sequence Stratigraphy, D Sandstone, Denver Basin 

Abstract: Sequence Stratigraphy, D Sandstone, Denver Basin 

Abstract: The Impact of Synorogenic Strata on Hydrocarbon Generation in the Denver Basin 

Abstract: The Impact of Synorogenic Strata on Hydrocarbon Generation in the Denver Basin 

Abstract: Structural Compartmentalization and Reservoir Fluid Distribution in the Terry and Muddy (J) Sandstones, Denver Basin, Colorado 

Abstract: Structural Compartmentalization and Reservoir Fluid Distribution in the Terry and Muddy (J) Sandstones, Denver Basin, Colorado 

Sooner Unit, Denver Basin, Colorado: Improved Waterflooding in a Fluvial-Estuarine Reservoir  (Upper Cretaceous D Sandstone)

This report summarizes data produced as part of a U.S. Department of Energy (DOE) project to evaluate methods for improving waterflood response in the Upper Cretaceous D sandstone of the Denver basin. Historically poor performance of waterflooding in this widespread reservoir has meant total recoveries averaging less than 20% of original oil in place (OOIP), with considerable variation in local sweep efficiency. Detailed reservoir characterization of the D sandstone in the Sooner unit, integrating well-log, core, seismic, and engineering data, resulted in an updated reservoir model that included delineation of multiple reservoir compartments. This model was used as a basis for a field redevelopment plan whose initial stage involved realigning existing injectors/producers and drilling several infill locations to increase sweep efficiency on a compartment-by-compartment basis. Results of implementation included a 100% increase in daily unit production, an increase in proven reserves of 696,000 bbl oil equivalent to more than 10% of OOIP. On the basis of these results, ultimate recovery from the unit, with implementation of selective infill drilling, is projected at 32.6% OOIP. Success of the project © Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Petroleum Consultant, 1511 18th Avenue East, Seattle, Washington 98112. Grateful acknowledgment is expressed to Mark Sippel of Mark Sippel Engineering (Denver, Colorado) for providing data and expertise essential to the writing of this report. Appreciation is also extended to Floyd Bardsley for artwork.Send reprint requests to AAPG Publications Manager, P.O. Box 979, Tulsa, Oklahoma 74101-0979. M = million, G = billion.

Abstract: Shoreface Sequence Stratigraphy of the Upper Cretaceous Terry Sandstone in Denver Basin, Colorado 

Abstract: Shoreface Sequence Stratigraphy of the Upper Cretaceous Terry Sandstone in Denver Basin, Colorado 

Anomalous Pressure Regimes In the Cretaceous Sandstones of the Denver Basin, Colorado, Wyoming, and Nebraska: ABSTRACT

Anomalous Pressure Regimes In the Cretaceous Sandstones of the Denver Basin, Colorado, Wyoming, and Nebraska: ABSTRACT

Geology, Thermal Maturation, and Source Rock Geochemistry in a Volcanic Covered Basin: San Juan Sag, South-Central Colorado

The San Juan sag, concealed by the vast San Juan volcanic field of south-central Colorado, has only recently benefited from oil and gas wildcat drilling and evaluations. Sound geochemical analyses and maturation modeling are essential elements for successful exploration and development. Oil has been produced in minor quantities from an Oligocene sill in the Mancos Shale within the sag, and major oil and gas production occurs from stratigraphically equivalent rocks in the San Juan basin to the southwest and in the Denver basin to the northeast. The objectives of this study were to identify potential source rocks, assess thermal maturity, and determine hydrocarbon-source bed relationships. Source rocks are present in the San Juan sag in the upper and lower Mancos Shale (including the Niobrara Member), which consists of about 666 m (2184 ft) of marine shale with from 0.5 to 3.1 wt. % organic carbon. Pyrolysis yields (S1 + S2 = 2000-6000 ppm) and solvent extraction yields (1000-4000 ppm) indicate that some intervals within the Mancos Shale are good potential source rocks for oil, containing type II organic matter, according to Rock-Eval pyrolysis assay. Oils produced from the ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received August 23, 1995; revised manuscript received September 4, 1996; final acceptance February 4, 1997. 2Priority Oil & Gas, LLC, 633 17th Street, Suite 1520, Denver, Colorado 80202. 3U. S. Geological Survey, P.O. Box 25046, MS 977, Denver Federal Center, Denver, Colorado 80225. 4Platte River Associates, Inc., 2000 W. 120th Avenue, Suite 10, Denver, Colorado 80234. Use of product names is for descriptive purposes only and does not constitute endorsement by the U.S. Geological Survey. We are grateful to Waggoner-Baldridge Energy Co., Meridian Oil, and UP Resources for supplying samples and data for this study. Lynn Gries provided hours of picking clean shale samples and manuscript typing. T. A. Daws and A. Warden, U.S. Geological Survey, are gratefully acknowledged for performing Rock-Eval and carbon isotope analyses, respectively. We thank R. Walker, U.S. Geological Survey, and Ann Priestman, GeoGraphics, for drafting the figures. Reviews of earlier versions of the manuscript by Vito Nuccio, Chuck Chapin, P. Lillis, N. Bostick, P. Wagner, and an anonymous reviewer are appreciated.

A model of isotope fractionation in reacting geochemical systems

The authors present a numerical technique that predicts how the stable isotopes {sup 2}H, {sup 13}C, {sup 18}O, and {sup 34}S fractionate among solvent, aqueous species, minerals, and gases over the course of a geochemical reaction process. This model is based on mass balance techniques similar to those already presented in the literature but differs from previous techniques in that it allows minerals to be segregated form isotopic exchange instead of remaining in isotopic equilibrium. Such an approach allows us to simulate the fractionation of isotopes between rock and fluid resulting solely from mineral dissolution and precipitation. The technique was tested by modeling isotopic fractionation during several reaction processes, including (1) dolomitization of limestone by a migrating pore fluid, (2) diagenetic alteration of the Permian Lyons sandstone in the Denver basin, and (3) hydrothermal alteration of the Okanagan Batholith in southern British Columbia. The results of calculations in which minerals are segregated from isotopic exchange compare well to isotopic trends observed in nature but differ markedly from calculations that assume isotopic equilibrium. 54 refs., 4 figs., 3 tabs.

A case study of the natural attenuation of gas condensate hydrocarbons in soil and groundwater.

Condensate liquids have been found to contaminate soil and groundwater at two gas production sites in the Denver Basin operated by Amoco Production Co. These sites have been closely monitored since July 1993 to determine whether intrinsic aerobic or anaerobic bioremediation of hydrocarbons occurs at a sufficient rate and to an adequate end point to support a no-intervention decision. Groundwater monitoring and analysis of soil cores suggest that intrinsic bioremediation is occurring at these sites by multiple pathways, including aerobic oxidation, Fe(III) reduction, and sulfate reduction.

Evaluation of Kinetic Models for the Smectite to Illite Transformation

AbstractThree different models have been reported previously to describe the kinetics of the transformation of smectite to illite (Pytte 1982; Velde and Vasseur 1992; Huang et al. 1993). In order to evaluate the general utility of these models to calculate the timing and extent of this transformation, each model was applied to four different geologic settings (Denver Basin, Gulf Coast, the Salton Sea Geothermal System, and Paris Basin) in which the ages, geothermal gradients and potassium ion activities vary markedly. The model results are compared to the measured percentages of illite in illite/smectite (I/S) and the K/Ar ages of I/S (if available) to test the utility of a given model to a particular basin.Although individual models can be applied to study this transformation within a specific setting, none of these models was successful in simulating the transformation for all four basins. The Salton Sea was simulated best using the model by Huang et al. (1993), which incorporated an increased geothermal gradient during the last 20,000 years. These results indicate that a large fraction of illite formed due to this increased geothermal gradient, and underscores that temperature is a dominant kinetic factor in forming illite. The Denver Basin was simulated well by the models of Velde and Vasseur (1992) and Pytte (1982). The Gulf Coast was simulated very well by the model of Huang et al. (1993) using a term that terminates the transformation at 75% illite. For the Paris Basin, the results are mixed. The models can be refined by comparing the calculated and measured ages of illite such as the K/Ar ages of I/S to understand the thermal history of a particular basin. The calculated ages of illitization derived from these refined models can be used to indicate the time at which source rocks became thermally mature to form oil and gas.

Influence of Permian Salt Dissolution on Cretaceous Oil and Gas Entrapment and Reserve Potential, Denver Basin, Western Nebraska: ABSTRACT

Location and trap type of Cretaceous oil and gas fields in the D-J Fairway of Nebraska are related to the occurrence of 12 Permian salt zones. Salt distribution is controlled by the configuration of evaporate basins, truncation at a sub-Jurassic unconformity, and post-Jurassic subsurface dissolution. The Sidney Trough, which marks the eastern (regionally updip) limit of Cretaceous oil production in western Nebraska, is a rootless salt-dissolution collapse feature, whose location and origin is controlled by an abrupt linear facies change from thick, porous Lyons Sandstone to Leonardian salt. Eastward gravity-driven groundwater flow within the Lyons occurred in response to hydraulic gradient and recharge along the Front Range Uplift following Laramide orogeny. Dissolution of salt at the facies change caused collapse of overlying strata, producing fractures through which cross-formational flow occurred. Younger salts were dissolved, enhancing relief across the regional depression and subsidiary synclines. Timing of post-Jurassic dissolution influenced entrapment within D and J sandstone reservoirs. Where Early Cretaceous (pre-reservoir) dissolution occurred, structure at the D and J sandstone level is relatively simple, and stratigraphic traps predominate. Where Late Cretaceous - Tertiary (post-reservoir) dissolution occurred, structure is more complex, formation waters are more saline, oil and gas are localized on dissolution-inducedmore » anticlines, and per-well reserves are significantly higher.« less

Influence of Permian Salt Dissolution on Distribution of Shallow Niobrara Gas Fields, Eastern Colorado: ABSTRACT

Subsurface analysis of Permian salt and related strata in the shallow Niobrara gas area on the eastern flank of the Denver basin reveals that the location of faulted anticlines which produce gas from porous chalk is related to the occurrence of six Nippewalla Group (Leonardian) salt zones. Salt distribution is controlled by the configuration of evaporate basins during the Leonardian, truncation at a sub-Jurassic unconformity (which has completely removed Guadalupian salts), and post-Jurassic subsurface dissolution. Significant dissolution took place in response to Laramide orogeny and subsequent eastward regional groundwater flow within the Lyons (Cedar Hills) Sandstone aquifer. Initially, dissolution occurred along a regional facies change from sandstone to salt. Solution collapse allowed for cross-formational flow and removal of younger salts. Shallow Niobrara gas fields are situated above salt outliers or along regionally updip salt edges. No significant Niobrara production exists in areas where salt is absent. Structural relief across fields is related to Leonardian thickness variations, rather than subsalt offset. Seismic data reveal abrupt Leonardian thinning at the regionally updip limit of Eckley field, which has produced over 33 BCFG. Thickness of residual salt may be important in controlling the amount of gas trapped within the Niobrara. Where thick saltsmore » are preserved, structural relief is greater, the gas-water transition zone is thicker, and gas saturation is higher at the crests of faulted anticlines.« less

Structural and Stratigraphic Compartmentalization of the Terry Sandstone, and Effects on Reservoir Fluid Distributions, Latham Bar Trend, Denver Basin, CO: ABSTRACT

Structural and Stratigraphic Compartmentalization of the Terry Sandstone, and Effects on Reservoir Fluid Distributions, Latham Bar Trend, Denver Basin, CO: ABSTRACT

Structural and Stratigraphic Compartmentalization of the Terry Sandstone and Effects on Reservoir Fluid Distributions in Hambert-Aristocrat Fields, Denver Basin, Colorado: ABSTRACT

Structural and Stratigraphic Compartmentalization of the Terry Sandstone and Effects on Reservoir Fluid Distributions in Hambert-Aristocrat Fields, Denver Basin, Colorado: ABSTRACT