Case Study of an Upper Devonian Sandstone Oil Reservoir

Based on a workshop co-sponsored by PTTC's Appalachian Region, Appalachian Oil & Natural Gas Consortium, and West Virginia University on October 23, 2001 in Morgantown, West Virginia.

BOTTOM LINE

A case study of an old oilfield in West Virginia reinforces the need for multidisciplinary reservoir characterization to solve well performance problems so that maximum reserves can be produced from declining domestic fields. Reservoir characterization may also help identify areas within these oil fields where undiscovered oil may still exist.

PROBLEM ADDRESSED

An integrated reservoir characterization study of the Jacksonburg-Stringtown oil field, West Virginia, identified the relationships between permeability, logs, stratigraphic context, and porosity distribution in the Gordon Sandstone. Core studies provided information that, coupled with sequence stratigraphic analysis, could be correlated to electrofacies. Once the distribution of pay could be reliably mapped in the field, reservoir simulation using developed flow unit concepts and a relatively simple model provided good agreement with field history. The field operator can use this knowledge base to plan continued development of the reservoir.

KEY WORDS:

Jacksonburg-Stringtown Field, Gordon Sandstone, Late Devonian, Appalachian Basin, Reservoir Characterization

SPEAKERS

Reservoir Modeling & Simulation
Khashayar Aminian, West Virginia University

Field History
Katharine Lee Avary, West Virginia Geological and Economic Survey

Reservoir Characterization
Ilkin Bilgesu, West Virginia University

Appalachian Basin Devonian Clastic Wedge, Jacksonburg-Stringtown Oil Field
David L. Matchen, West Virginia Geological and Economic Survey

Electrofacies
Ronald R. McDowell, West Virginia Geological and Economic Survey

Reservoir Characterization
Michael E. Hohn, West Virginia Geological and Economic Survey

Permeability Prediction
Benjamin H. Thomas, West Virginia University

TECHNOLOGY OVERVIEW

Interdisciplinary (geological, geophysical, and reservoir engineering) characterization was used to more accurately define relationships among permeability, geophysical and other reservoir data in order to understand well performance in an old West Virginia oil field. The operator will use new information derived from the study to enhance production at the Jacksonburg-Stringtown Field located in Tyler, Wetzel and Doddridge counties. The field was discovered in 1895. Primary production from the Upper Devonian Gordon Sandstone reservoir in this field was 20 MMBO. Original oil in place was estimated to be 88.5 MMBO. A full-scale waterflood begun in 1990 was responsible for production of 1.8 MMBO.

The West Virginia University Research Corporation has developed a three-dimensional model of permeability for the Gordon Sandstone in order to overcome heterogeneity problems that would otherwise limit the enhanced production goals for this declining field.

Stratigraphic Analysis and Pay Distribution. In the Jacksonburg-Stringtown Field, the Gordon Sandstone is composed of three parasequences that formed along a Late Devonian shoreline. The parasequences comprise five lithofacies including featureless sandstone (pay), laminated sandstone, conglomeratic sandstone, a heterolithic-bioturbated facies and shale. Reservoir portions of the Gordon are restricted to the featureless sandstone facies in each of the three parasequences. Permeable sandstone is found in the laminated sandstone and conglomeratic sandstone lithofacies, but communication between reservoir compartments is generally poor and unpredictable in these facies.

Primary porosity is intergranular; secondary porosity is associated with moldic to partly leached potassium feldspars. Late stage siderite cement commonly occludes porosity. Siderite may be significant during secondary development of the Gordon reservoir because chemical reactions between the injection water and the siderite cement must be accounted for.

Core Analysis. Core studies have led to the following conclusions:

• Pay sandstone defined by log signature was found to have permeability ranging from 10 to 200 mD.
• Non-pay sandstone identified by log signature has less than 5 mD permeability.
• Distribution of permeability within the pay sandstones was fairly uniform.
• Permeable intervals in the non-pay sandstones were zoned parallel to bedding or had a "patchy" distribution.
• Conglomeratic material was problematic. It could have permeability similar, greater, or less than that of the enclosing lithofacies.
• Thin conglomeratic intervals are difficult to pick on geophysical logs and could provide either unexpected barriers to vertical flow or unexpected "thief" zones.

Comparing Electrofacies and Lithofacies. Four electrofacies that were defined by a linear combination of density and scaled gamma ray provided the best match for correlations made independently based on visual comparison of logs. Log-core correlations indicate that electrofacies 1 comprises the shale lithofacies. Electrofacies 2 and 3 comprise conglomeratic sandstone, laminated sandstone and the heterolithic-bioturbated lithofacies. Electrofacies 4 with a relatively high mean permeability (mean value greater than about 40 mD) comprises featureless sandstone and conglomeratic lithofacies. Electrofacies 4 contains the pay sandstone within the Gordon reservoir.

Although significant structural complexity is absent in the field, a small fault with 5 meters of displacement transects the southern end of the field. The displacement on this fault is enough to isolate the southern part of the reservoir.

Modeling the Reservoir. Core data from six wells in the reservoir were utilized to create an artificial neural network to predict permeability from Gamma Ray and bulk density logs. A three-layer, back propagation network with three slabs in the middle layer (each with different activation functions) could predict permeability values that correlated with observed values at an acceptable level. Similar results were obtained in the prediction of porosity from log and well parameters.

Two reservoir flow units were defined. The upper flow unit includes the lower part of the conglomerate-sandstone sequence and the upper part of the sandstone section. The second flow unit includes the lower part of the sandstone sequence and has higher porosity and permeability. A three-dimensional reservoir description including the flow units and injection pressure-rate information was then used as input for the reservoir simulator to predict oil production performance for the center producers in the pilot area. This description of the reservoir provided significantly better simulation results than that derived from a simple model of the pilot area based on well records, well logs and core analysis input alone.

To develop a reservoir model encompassing the entire field, it was necessary to establish criteria for identifying flow units based on Bulk Density and Gamma Ray logs. It was found that the second flow unit (the major producing flow unit) crosses stratigraphic units in the reservoir. A neural network was used to predict permeability values for the flow units. The reservoir simulator was utilized to predict the performance of two flood pattern located to the north of the pilot area. Considering the simple model utilized for simulation, the results are in very good agreement with the field history.

CONNECTIONS:

Dr. Khashayar Aminian
Dept. Petroleum & Natural Gas Engineering
West Virginia University
345 F Mineral Resources Building, P.O. Box 6070
Morgantown, WV 26506-6070
Phone: 304-293-5708 ext 3406 Fax: 304-293-5708
Email: khaminian@mail.wvu.edu

Dr. H. Ilkin Bilgesu
Dept. Petroleum & Natural Gas Engineering
West Virginia University
345 C Mineral Resources Building, P.O. Box 6070
Morgantown, WV 26506-6070
Phone: 304-293-7682 ext 3403 Fax: 304-293-5708
Email: hibilgesu@mail.wvu.edu

Speakers from West Virginia Geological and Economic Survey
PO Box 879
Morgantown, WV 26507-0879
Phone: 304-594-2331 Fax: 304-594-2575

Katharine Lee Avary
Email: avary@geosrv.wvnet.edu

David L. Matchen
Email: matchen@geosrv.wvnet.edu

Dr. Ronald R. McDowell
Email: mcdowell@geosrv.wvnet.edu

Dr. Michael E. Hohn
Email: hohn@geosrv.wvnet.edu


For information on PTTC’s Appalachian Region and its activities contact:
Dr. Douglas Patchen, Program Manager
Appalachian Oil and Natural Gas Consortium, West Virginia University
P.O. Box 6064, Morgantown, WV 26506-6064
Phone: 304-293-2867 ext. 5443 Fax: 304-293-7822
Email: dpatch@wvunrcce.nrcce.wvu.edu

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