A Success Case of Mature Field Rejuvenation, Post-Tertiary CO2 Flood, Salt Creek Field, West Texas

Linda M. Price¹, Dave P. Smith², Pak Wong³, and Curtis Whitacker²
¹ExxonMobil Exploration Company, PO Box 4778, Houston, TX 77210, [email protected]
²ExxonMobil Production Company, [email protected]
³ExxonMobil International Limited, UK, [email protected]

The Salt Creek Field is a small (~31 km²) grain-dominated carbonate build-up along the eastern edge of a large (150 km in diameter) Pennsylvanian atoll. Discovered in 1950, this oil field has undergone multiple development phases including primary, waterflood and tertiary recovery operations. There are over 400 wells in the field, mostly at 20-acre spacing. Average unit production in early 2003 was 14,000 BOPD, 335,000 BWPD, 120 MCFD (85% CO₂), and 4,500 barrels/day NGL’s with cumulative oil production at 365 MBO. Recently, a reservoir characterization field study was initiated in order to stem volume decline and increase profitability through more effective reservoir management strategies. While the field study is not yet complete, results so far have already exceeded expectations in the immediacy of field production uplift.

The Salt Creek carbonate build-up consists of relatively steep-sided (see figure 1), 200 meter thick terraced stack of high frequency shoaling upward sequences. Two separate closures comprise the field, the South Main Body (SMB) and the Northwest Extension (NWE). The primary reservoir consists of Missourian and Virgillian 3rd order sequences all in pressure communication, with the secondary reservoir being a residual oil column in the Upper Strawn. The dominant reservoir facies are ooid-skeletal shoals and bars with moldic porosity averaging 11% and permeability ranging between 1-2000 md. The complex sequence stacking patterns and rapid facies changes present challenges for stratigraphic correlation, even with 300 meter well spacing. This reservoir heterogeneity causes differential processing rates in flow units, further complicating reservoir management.

Since its initial discovery, Salt Creek Field has employed consistent reservoir surveillance and development programs. Soon after field discovery, gas cap and water injection programs began to maintain reservoir pressure and optimize recovery. Since then, development drilling has taken spacing from 80-acres to 20-acres over most of the field. In 1993, an aggressive CO₂ flood began, which pushed the field to its peak Tertiary production rate. Subsequently, a residual oil (Sw ~50%) CO₂ flood program, accompanied by a gas plant expansion, continued to stem production decline. Given the reservoir complexity, effective survillance tools had to be developed to monitor flood maturity, mediate gas breakthrough, and restore/optimize pattern production. Maintaining profitable production rates involves a combination of capital programs, workover programs, facilities modifications, and control of operating expenses, which are interdependent and must be successfully coordinated. Proactive reservoir management and geoscience integration has been key to efficiently depleting these numerous reservoir flow zones.

In 2001, an extensive field study was initiated to further manage optimal resource recovery. Plans for the study included three-dimensional seismic acquisition, a rigorous sequence stratigraphic update, petrofacies analysis, geologic modeling and full-field reservoir simulation. Though this project remains on-going, daily production uplift increased over 10% after 18 months of its start date through renewed operations. The new three-dimensional seismic data had the highest and most immediate impact on the field, promoting a new development drillwell program, proving up additional reserves and providing improved structural control to optimally locate wells. Results from this program have added 1.2 MBO reserves to the field’s resource base, with a present value profit of $3.4 M (see figure 2). With the total cost of the seismic program at $2.5 M, profitability was attained at a reasonable cost. Additional sequence stratigraphic work has also had a production impact through reducing uncertainty in reservoir management. In particular, understanding the 3rd order sequence hierarchy elegantly illustrates the platform evolution and provides a solid framework for reservoir quality, continuity and connectivity predictions. Given the new framework, several workover programs and development well patterns have been optimized. Additionally, the integration feedback loop of facies prediction and production/injector performance added more accurately described capital and expense risk.

In summary, a new look at a very mature carbonate oil field increased reservoir understanding and proved to be a profitable venture. Key to this process has been the integration of stratigraphic, seismic, petrophysical, engineering and production/injection data. Even though not yet complete, the project has facilitated improved performance evaluations, analysis of problem areas and assimilation the large amounts of data inherently generated in a mature tertiary flood. Future plans include a geologic model incorporating these diverse datasets and reservoir simulation to optimize depletion scenarios.

Figure 1 The top carbonate (top reservoir) time dip surface on the 3D seismic cube. The entire field is 31 km².