Implementation Challenges: DTS Injection Profiles in the Belridge Field, California

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163694, ’The Challenges of Full-Field Implementation of Fiber-Optic DTS for Monitoring Injection Profiles in Belridge Field, California,’ by Mahmood Rahman, SPE, Daniel A. Reed, and Malcolm E. Allan, SPE, Aera Energy, prepared for the 2013 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, 5-7 March. The paper has not been peer reviewed. The Diatomite reservoir in the Belridge field, California, has been under pressure-maintenance water injection to mitigate reservoir compaction and improve oil recovery. Accurate placement of the injection water across this 1,500-ft-thick reservoir is essential to balance voidage and reduce in-situ compaction. However, scale buildup and casing deformation have made monitoring the injection profile by use of conventional radioactive-tracer (RAT) technology a challenge because of the inability to access wellbores for logging. Field tests with fiber-optic (FO) distributed-temperature-sensing (DTS) systems confirmed that the technology had potential to replace the RAT surveys for continuous monitoring of the injection profile. However, moving from a successful pilot to full-field implementation presented many challenges, both technical and economic. Introduction Belridge, one of the largest oil fields in California, is approximately 150 miles north of Los Angeles (Fig. 1). There are two major producing horizons: The shallower Tulare sands produce heavy oil (13 to 15°API) by steamdrive, and the deeper Diatomite formation produces light oil (29 to 31°API). In 2012, the Tulare produced an average of 21,000 BOPD and the reservoir produced 41,000 BOPD. The Diatomite reservoir has very high porosity (50 to 70%), high compressibility (100 to 300×10−6 psi−1), and very low matrix permeability (0.1 to 3.0 md). The upper portion of the Diatomite formation in Belridge has a gross thickness of more than 1,500 ft (Fig. 2), with 21 major depositional cycles grouped into nine conformance units. Initially, the reservoir was produced on primary recovery by solution-gas drive. Because of the high rock compressibility, pressure-maintenance water injection was started in the late 1980s to combat reservoir compaction. The operator has been investigating methods to evaluate injector effectiveness. One solution was extensive use of openhole wireline formation tests (WFTs) that are run in replacement wells and provide a good indication of vertical-conformance effectiveness. However, WFT pressure profiles indicate only the effectiveness of past injection; they cannot show the current state of injection conformance.