Layered Waterflood Surveillance in a Mature Field: The Long Beach Unit

Woodling, G.S.; Taylor, Pamela J.; Sun, Haohan; Nguyễn, Quang Ngọc; Brix, Timothy R.

doi:10.2118/26082-ms

Cited by 14 publications

(4 citation statements)

References 3 publications

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“…Other practices that have been applied in mature field development include the development plans through optimized waterflooding [154][155][156][157] and horizontal drilling [158][159][160][161] . The Wilmingon field waterflooding optimization study was performed by mapping the production gross and oil, and water cut bubble maps, injection streamline maps and pattern performance graphs after 55 years of production 154 .…”

Section: Reservoir Management Practicesmentioning

confidence: 99%

Mature Field Development - A Review

Babadagli

2005

Proceedings of SPE Europec/Eage Annual Conference

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDevelopment of mature oil fields has been, and will increasingly be, an attractive subject.Mature field development practices can be divided into two major groups:(1) well engineering and (2) reservoir engineering. This paper focuses on the reservoir engineering aspects.An extensive review of previously reported reservoir management practices for mature field development is provided. After the definition of mature field and an overview, different aspects of mature field development are outlined. The first issue covered is the estimation of remaining reserves focusing on the determination of the amount and location of the residual oil after primary and secondary recovery using field, log, and core data. After valuing the remaining oil, methods to recover it are classified. They include tertiary recovery, infill drilling, horizontals, optimal waterflooding design for mature fields, optimal well placement and other reservoir management practices. Suggested or implemented field application examples for big fields owned by majors and small fields owned by independents are presented.Special attention is given to tertiary oil recovery. An extensive review and critical analysis of tertiary recovery techniques covering the theoretical, practical, and economical aspects of it are provided. The emphasis is on their applicability in mature field development in terms of effectiveness (incremental recovery) and efficiency (cost and recovery time). Laboratory and field scale applications of different tertiary recovery techniques, i.e., gas (double displacement, WAG, and miscible-immiscible HC, CO 2 , and N 2 ), chemical (dilute surfactant, polymer, and micellar injection), and thermal (air and steam) injection, conducted to develop mature fields are included. Specific examples of big/giant fields, fields producing for decades, and mid to small size fields were selected.Differences in reservoir management strategies for majors, independents, and national oil companies are discussed.

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Section: Reservoir Management Practicesmentioning

confidence: 99%

Mature Field Development - A Review

Babadagli

2005

Proceedings of SPE Europec/Eage Annual Conference

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“…18,19 This technique divides the U-P Ford East areally into pattern elements bounded by injection wells and faults. Historically, similar techniques have been applied to the Ranger and Terminal zones for waterflood management.…”

Section: Waterflood Surveillancementioning

confidence: 99%

Forty Years of Improved Oil Recovery: Lessons from Low-Permeability Turbidites of the East Wilmington Field, California

Creties¹,

Shahin²,

Randy³

et al. 2004

Proceedings of SPE International Petroleum Conference in Mexico

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe U-P Ford zone in the Long Beach Unit of the East Wilmington Field consists of low-permeability (2-50 millidarcies) turbidites that have been waterflooded since field start-up. Forty years of successes and failures have provided valuable insights into how to best waterflood these reservoirs given their thin-bedded nature, lateral and vertical changes in reservoir quality, formation damage susceptibility, and sand control problems. Multiple techniques and technologies have been applied to describe their reservoir architecture, quantify reservoir performance, and extract the oil. This work has become more challenging as the waterflood has matured and will require the close integration of all disciplines to identify and exploit remaining opportunities.The gross thickness of U-P Ford zone is about 2100 feet, and depths to the top of the zone range from about 4200 to 4800 feet. The U-P interval is about 900 feet thick and consists of the AE, AF, AI, AK1, AL1, and AM subzones. The U-P has an average net-to-gross ratio of 0.25 and contains many thin sands separated by shales, as well as some thicker sands. The Ford interval is about 1200 feet thick and underlies the U-P interval. The Ford consists of the AO, AR, AU, AU2, AV, AW, AX, AX1, AY, AT, and AZ subzones. It has an average net-to-gross ratio of 0.45 and contains thicker sand units than the U-P, although many of the sand-rich intervals are frequently found in the aquifer. The major sandstone units show an overall thickening and higher net-to-gross values from west to east.Depositional Setting and Rock Properties. The interbedded sands and shales of the U-P Ford zone formed in a progradational, submarine-fan system trending from northwest to southeast 2 . The sands were deposited by sediment gravity flows that were funneled basinward by submarine canyons. These flows spread laterally across the surface of the fan to form lobes that exhibit compensating geometries. This pattern is characterized by the thick portion of an underlying lobe coinciding with the thin portion of an overlying lobe. Between

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“…Waterflood has been conducted in many high-viscosity reservoirs in the past, and several water-injection projects in high-viscosity reservoirs are ongoing and planned around the world (Oefelein and Walker 1964;Jennings 1966;Roark 1960;Nelson 1976;Woodling et al 1993;Jenkins et al 2004;Adams 1982;Edgson and Czyzewski 1985;Kasraie et al 1993;Smith 1992;Lim et al 1993;Ko et al 1995;Etebar 1995;Pallant et al 1995;Foerster et al 1997;Yang et al 1998;Forth et al 1996;Yao 1999;Hanafy 1999;Cook et al 2000;Jayasekera and Goodyear 2000;Capeleiro Pinto et al 2001). However, published data on HMRWF performance are limited, and results are sometimes conflicting.…”

Section: Introductionmentioning

confidence: 99%

“…Using the Buckeley-Leverett method and various conformance factors for different sand units, Nelson estimated the potential incremental recovery for the waterflood of approximately 14 to 25% OOIP. Woodling et al (1993) presented waterflood-surveillance efforts in the Ranger zone within the Long Beach unit in the east Wilmington field. The unit underlay the city of Long Beach, California, including the city's harbor area.…”

Section: Introductionmentioning

confidence: 99%

High-Mobility-Ratio Waterflood Performance Prediction: Challenges and New Insights

Kumar

Hoang

Satik

et al. 2008

SPE Reservoir Evaluation &Amp; Engineering

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This paper presents the results of a comprehensive study to improve our understanding of high-mobility-ratio waterfloods (HMRWFs) and to improve performance prediction. Published data on heavy-oil water-injection field projects are limited. Several successful HMRWF projects have been reported, and they show significant oil recovery at high water cut. However, the range of reported recovery is large-waterflood (WF) recoveries of approximately 1-or-2% to 20% of original oil in place (OOIP) have been reported for similar reservoirs. Higher viscosities result in lower recovery.Mechanistic studies using fine-scale simulations show that the viscosity (or mobility) ratio primarily controls oil-recovery response, and that the recovery is lower at higher viscosity ratios. Further, viscous fingers dominate high-viscosity-ratio floods, and mobile water can reduce recovery significantly. Field-scale simulation results indicate that heterogeneity plays a more important role for an HMRWF than for conventional waterfloods. The amount of primary production before the start of the waterflood has a larger effect on incremental oil recovery for high-mobilityratio floods. Furthermore, highly correlated thin, thief zones reduce recovery of HMRWFs more severely, and rock wettability (relative permeabilties) strongly influences oil recovery. These results indicate that, in addition to reservoir geology, accurate viscosity and relative permeability measurements are essential for a reliable performance prediction. Field DataPublished and other available data were reviewed critically to ascertain field performance of heavy-oil projects under water injection. Although several published papers discuss heavy-oil field projects, only a few include actual production data (Oefelein and

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Layered Waterflood Surveillance in a Mature Field: The Long Beach Unit

Cited by 14 publications

References 3 publications

Mature Field Development - A Review

Mature Field Development - A Review

Forty Years of Improved Oil Recovery: Lessons from Low-Permeability Turbidites of the East Wilmington Field, California

High-Mobility-Ratio Waterflood Performance Prediction: Challenges and New Insights

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