Reservoir Engineering Aspects of the Captain Extended Well Test Appraisal Program

Pallant, Miriam; Cohen, Dan; Lach, Joseph

doi:10.2118/30437-ms

Cited by 12 publications

(1 citation statement)

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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%

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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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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Reservoir characterization in the Captain Field: integration of horizontal and vertical well data

Rose¹

1999

PGC

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The Captain Field lies in UKCS Block 13/22. It is a large viscous oil field with an excellent quality Lower Cretaceous sandstone reservoir. Development of this high viscosity crude (88 cp at the in situ temperature, 87°F) in the offshore environment was possible only after the development of reliable horizontal drilling technology, combined with high volume down-hole electric pumps, and the ability to run long pre-packed sand control screens. As the first development of this type within Texaco, the development decision was helped by the extremely favourable reservoir conditions present in the Captain Field.The Captain reservoir is encountered directly beneath the chalk and consists of Late Aptian aged turbidite sandstones, with high porosity (av. 31 %) and permeability (av. 7 D). The sandstones were deposited on the feather edge of a large turbidite fan system derived from the East Shetland Platform to the north and which thins onto the Captain Ridge. The reservoir sequence consists of two principal sand bodies, the Upper and Lower Captain Sandstones with contrasting reservoir geometry. The Upper Captain Sandstone is developed in a continuous sheet that systematically thins and pinches out to the southeast whereas the Lower Captain Sandstone is concentrated in a sand fairway, interpreted to be a back-filled submarine canyon cutting across the Captain ridge. Core description show the sandstones to be predominantly massive suspension fall out sediments (S3 deposits, Lowe 1982) with rare intra-reservoir claystones.In this paper the reservoir geometry and sedimentology of the Captain Sandstone Member is described with particular attention being drawn to how horizontal drilling has tested and enhanced the geological model. Key reservoir parameters (e.g. connectivity, claystone distribution, grain size distribution, porosity, horizontal and vertical permeability) are discussed and their contribution to the success of the project evaluated.

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The Captain Field, Block 13/22a, UK North Sea

Pinnock¹,

Clitheroe

Rose

2003

Memoirs

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The Captain Field is located in Block 13/22a in the Western Moray Firth Basin of the UK North Sea, 80 miles NE of Aberdeen in a water depth of 340 ft. Hydrocarbons are trapped in two geographical regions, the Main and Eastern closures, both with a significant stratigraphic pinchout component. The principal reservoirs consist of turbidite sandstones of Lower Cretaceous age which have been informally subdivided into two stratigraphic units comprising the Upper and Lower Captain Sandstones. At the base of the preserved Jurassic section the Heather Sandstone, Oxfordian in age, provides a secondary reservoir. Reservoir quality is uniformly excellent in the Lower Cretaceous with in situ, Klinkenberg corrected permeability averaging 7 Darcies and porosity in the range 28-34%. The reservoir is generally poorly consolidated sandstone with the depth to the crest of the field at -2700 ft TVDss. The reservoirs contain a total oil-in-place of 1000 MMBO. The Upper Captain Sandstone has a small associated gas cap containing 16 BCF gas-in-place. The oil is heavy, by North Sea standards, with oil gravity ranging from 19° to 21° API and has high in situ viscosity, 150 to 47 cP, at the mean reservoir temperature of 87°F. The fluid properties and offshore location necessitate the employment of innovative horizontal drilling methods, completion design and artificial lift technology in order to achieve an economically viable field development. Extended reach horizontal wells, with reservoir completion lengths of up to 8000 ft, are drilled for all oil producers and water injectors. Development risks were significantly reduced following two appraisal drilling campaigns in 1990 and 1993 culminating with the successful drilling and extended testing of a prototype horizontal field development well (13/22a-10). The field is being developed in two phases, Area A and Area B. First oil production commenced from the Captain platform in March 1997 from Area A and the field now produces at between 50000 and 70000 BOPD. Area B development is now underway with first oil planned for December 2000. Completion of this phase of the development will increase the plateau production rate to 85000 BOPD.

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Reservoir Engineering Aspects of the Captain Extended Well Test Appraisal Program

Abstract: Texaco UK North Sea is operator and 100%

Cited by 12 publications

References 1 publication

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

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

Reservoir characterization in the Captain Field: integration of horizontal and vertical well data

The Captain Field, Block 13/22a, UK North Sea

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