Program Information


Summary of Technical Progress

Planned Activities





Cooperative Agreement No.: DE-FC22-95BC14936

Institution: Bureau of Economic Geology

The University of Texas at Austin

University Station, Box X

Austin, Texas 78713-7508

Date of Report: April 30, 2000

Award Date: March 31, 1995

Anticipated Completion Date for this Budget: August 31, 2000

Government Award for this Budget Period: $341,403

Program Manager: Daniel Ferguson

Principal Investigator: Shirley P. Dutton

Contracting Officer's Representative: Daniel Ferguson

Reporting Period: January 1, 2000 - March 31, 2000



The objective of this Class 3 project is to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost effective way to recover a higher percentage of the original oil in place through strategic placement of infill wells and geologically based field development. Project objectives are divided into two main phases. The original objectives of the reservoir-characterization phase of the project were (1) to provide a detailed understanding of the architecture and heterogeneity of two representative fields of the Delaware Mountain Group, Geraldine Ford and Ford West, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, (2) to chose a demonstration area in one of the fields, and (3) to simulate a CO2 flood in the demonstration area.

After the reservoir characterization and simulation of an area at the northern end of the Ford Geraldine unit were completed, the industry partner decided not to proceed to Phase 2, installation of a CO2 flood in the demonstration area. A new industry partner, Orla Petco, Inc., will participate in the remainder of the project, which includes a field demonstration in the East Ford unit. The East Ford unit is immediately adjacent to the Ford Geraldine unit and produces from the same Ramsey sandstone channel. The reservoir characterization phase of the project was expanded to include the East Ford unit. This additional reservoir-characterization task provided an excellent opportunity to test the transferability of the geologic model and log-interpretation methods developed during reservoir characterization of the Ford Geraldine unit to another Delaware sandstone field.

The objectives of the implementation phase of the project remain the same, to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from a demonstration area, (2) demonstrate that economically significant unrecovered oil can be recovered by a CO2 flood of the demonstration area, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. The goal is to develop a geologically designed CO2 flood and well-completion program in a representative Delaware Sandstone field that can serve as a model for other fields in the play. Through technology transfer, the knowledge gained in this study can be applied to increase production from more than 100 other Delaware Mountain Group reservoirs.


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Field Implementation

The project is now in Phase 2, field implementation of a CO2 flood. Tertiary recovery in the East Ford unit by CO2 injection began in July, 1995, and production response to the CO2 injection was observed in December, 1998 (fig. 1). In 1993 and 1994, before the CO2 flood began, annual production from the field was 12,000 to 14,000 bbl of oil. In 1998, annual production had increased to more than 30,000 bbl. In 1999 production has risen to 38,791 bbl. Daily production from the field increased from 30 bbl/day to more than 100 bbl/day (fig. 1).

Poor production response observed in well 4 suggests that a barrier restricts communication between this producing well and injector well 2; the barrier may be caused by geologic heterogeneity. Initial geologic interpretations suggested the presence of a channel—levee boundary between wells 3 and 4 in the Ramsey 2 sandstone. To overcome this restriction, well 3 was brought into production. Production from well 3, however, quickly became a mirror image of well 4, about 15 bbl of oil per day, approximately the same amount of water, and little gas. Well 3 was then shut in to run a pressure build-up test. The test indicates the presence of a flow barrier approximately 65 ft away. The nature of the barrier is unknown; it could be a low-permeability levee deposit or it may have been caused by deposition of solids in the formation over a long production time. The low volume of CO2 produced in well 3 suggests that the barrier occurs between wells 2 and 3 and not between wells 3 and 4. This evidence has caused us to remap the Ramsey 2 levee so that it passes between wells 2 and 3.

Some of the production problems in the East Ford unit may be caused by horizontal (or "pancake") fractures that were created in some of the wells during fracture stimulation. Evidence is not sufficient to say that all wells have horizontal fractures, but it is clear some of them do. Wells that were initially completed open hole in the Ramsey 2 and later deepened into the Ramsey 1 were able to recover cores of the Ramsey 1 sandstone, suggesting a horizontal fracture had been created in the Ramsey 2. In deeper Delaware fields where this has been done, only frac sand was recovered from the Ramsey 1, suggesting a vertical fracture had been created. Wells that were deepened in the East Ford unit, but not cored, drilled as if they were cutting formation, not frac sand, and the cuttings were from the formation and not frac sand. Tracer surveys on injection wells and some production wells also indicate some horizontal fractures.

As part of the Phase 2 field demonstration, a new well has been permitted and will be drilled as soon as a rig becomes available. The new well is located just northwest of well 41. Well 41 is being replaced because its casing parted during a workover to repair a casing leak. The new well will be logged with a density tool to measure the density of all the layers above the Ramsey sandstone. With this information, overburden pressure at the reservoir can be calculated and used to determine the pressure at which horizontal fractures will form. The goal is to design a fracture treatment for well 3 that stays below the pressure that would cause horizontal fracturing. We will then be able to determine if the flow restriction that occurs 65 ft from well 3 is caused by a levee or if it is due to deposition of solids. If it is caused by solids deposition, it should be possible to treat past the damage. If the restriction appears to be caused by a levee, another buildup test will be done.


Technology Transfer

The paper "Characterization of reservoir heterogeneity in slope and basin clastic reservoirs, Bell Canyon Formation, Delaware Basin, Texas" by S. P. Dutton, M. D. Barton, H. H. Zirczy, and W. A. Flanders was presented at the Southwest Section AAPG annual meeting in Midland, Texas on February 28. The authors have been notified verbally that their paper received the A. I. Levorsen Memorial Award for the best paper presented at the meeting. The paper will be published by the Southwest Section AAPG in the meeting transactions volume.

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The CO2 flood in the East Ford unit will continue next quarter, and a new well will be drilled to replace well 41. Evaluation of the results of the flood will continue and will be compared with the geologic interpretation of the field.

Figure 1. Total field production (a) and injection (b) in the East Ford unit.

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