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DOE's Unconventional Gas Research Programs 1976-1995
SOURCE: U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region






3.6.3. Major Results


Results from the SGR program indicated that:

  • Significant natural gas reserve appreciation opportunities exist where reservoirs are heterogeneous and compartmentalized.
  • Such compartmentalization, other than structural, is depositional and/or diagenetic in origin and can be defined through a geologically centered approach to understanding reservoir flow units.
  • Concept-driven integration of the four fundamental geo-scientific disciplines (geology, engineering, geophysics, and formation evaluation) is crucial to recognizing and exploiting reserve growth opportunities.
  • Although absolute rules on flow communication between facies are not apparent, as the size of the reservoir compartment decreases, stratigraphic variability often increases and secondary compartments are often encountered in the smaller size reservoirs.
  • The application of SGR approaches conducted with the cooperation of independent operators documented development costs in the range of $0.60 to $0.80/Mcf for incremental reserve appreciation.
  • In the Boonsville Field, a previously unrecognized karst collapse phenomenon identified by 3-D seismics may be a widespread influence on the deposition of younger sediments in the Midcontinent.
  • A reasonable approach to identifying new well locations in the Bend interval appears to be to focus 3-D seismic evaluation on multiple stacked completion opportunities. An alternative strategy would be to use 3-D data to identify fault-bounded blocks that have no penetrations in sub-regional or field-scale areas where the pre-Atoka time structure is low and total Atoka net reservoir isopachs are thick, increasing the potential for finding multiple vertically stacked completion opportunities.
  • Fractures associated with faults and with maximum flexure on positive structural features control the locus of highest Ellenburger reservoir quality. Accordingly, the requirement for siting productive wells is to place the wellbore where it will penetrate the maximum amount of fractured rock. Seismic attributes that show significant stratal movement and distortion are valuable indicators of fracturing.
The most important measure of the SGR Projectís success was the substantial increase in the assessed secondary natural gas resources and the increased production of gas in targeted districts of the Texas Gulf Coast.

Knowledge of the technologies applied by the project was transferred to industry through a program of 14 short courses and workshops conducted by the SGR team and attended by more than 600 individuals, primarily independent producers and consultants.

The incremental increase in national secondary gas production ascribable to the knowledge disseminated and the technologies developed and applied by the SGR project was estimated to be 30 percent, when comparing industry performance during pre-SGR time (1990-1992) with performance in 1996.

Extrapolating from the 1993 drilling rate to 2000 and ascribing only 20 to 30 percent of the incremental production to the SGR project, gross incremental production revenue by 2000 would range from $916 million to $1,374 million, at prices of no more than $2.51 (1994 dollars) per Mcf, for the Gulf Coast alone.

These revenues are as much as 60 times the entire SGR team investment. Moreover, based on the improved understanding of the relationship between among reservoir complexity, integrated technology assessments, and reserve growth potential, the 1996 GRI estimate of secondary gas resource grew to 508 Tcf for lower 48 onshore and state waters.



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TABLE OF CONTENTS

Cover Page

Executive Summary

1. Background

2. GRI Research into Unconventional Gas Resources

3. Structure of the Enhanced Gas Recovery Program (EGR)

  • 3.1. Eastern Gas Shales Program (1976-1992)

  • 3.1.1. Key Questions and Related R&D Goals
  • 3.1.2. Program Design and Overview of Major Projects
  • 3.1.3. Key Eastern Gas Shales Projects
  • 3.1.4. Highlights of Important Results
  • 3.1.5. Subsequent Developments in DOE and Other Research Related to Eastern Gas Shales

  • 3.2. Western Gas Sands Program (1978-1992)

  • 3.2.1. Key Questions and Related R&D Goals
  • 3.2.2. Program Design and Overview of Major Projects
  • 3.2.3. Key Western Gas Sands Projects
  • 3.2.4. Highlights of Important Results
  • 3.2.5. Subsequent Developments in DOE Research Related to Tight Gas Sands

  • 3.3. Methane Recovery from Coalbeds Program (1978-1982)

  • 3.3.1. Key Questions Related to Coal Seam Methane
  • 3.3.2. MRCP Program Design and Overview
  • 3.3.3. Key Methane Recovery from Coalbeds Projects
  • 3.3.4. Highlights of Important Results
  • 3.3.5. Subsequent Research Related to Methane Recovery from Coalbeds

  • 3.4. Deep Source Gas Project (1982-1992)

  • 3.4.1. Key Deep Source Gas Projects
  • 3.4.2. Highlights of Important Results

  • 3.5. Methane Hydrates Program (1982-1992)

  • 3.5.1. Methane Hydrates Workshop (March 1982)
  • 3.5.2. Key Questions and Related R&D Goals
  • 3.5.3. Program Design
  • 3.5.4. Major Contracted Gas Hydrates Projects
  • 3.5.5. Methane Hydrate Research Efforts of METC's In-House Organization
  • 3.5.6. Highlights of Important Results
  • 3.5.7. Subsequent Developments in Methane Hydrate Research

  • 3.6. Secondary Gas Recovery (1987-1995)

  • 3.6.1. Key Objectives and Program Design
  • 3.6.2. Major Projects
  • 3.6.3. Major Results

    4. Elements of Spreadsheet Bibliographies (by Program)

    Appendix A: Details of Major 1970-1980 Unconventional Gas Resource Assessments


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