Kuparuk Large-Scale Enhanced Oil Recovery Project

Hoolahan, S.P.; Mcduffie, G. S.; Peck, Dong‐Hyun; Hallam, R.J.

doi:10.2118/35698-pa

Cited by 8 publications

(4 citation statements)

References 13 publications

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“…Ultimate EOR from the pilot area is estimated to be 7 -10% OIIP. Field-wide implementation followed in 1996 (Hoolahan et al, 1997). Subsequent study work assessed the value of following IWAG with MWAG.…”

Section: Kuparukmentioning

confidence: 99%

“…Incremental recovery is expected to be 200 mmstb, based on injection of 1 Tscf of MI, making Kuparuk one of the world's largest miscible gas floods. Conventional WAG (WAG ratio = 1:1, MI slug = 30% HCPV) is used and the EOR from individual patterns is expected to be 4% -10% OIIP (Hoolahan et al, 1997). Only half the Kuparuk OIIP is currently subjected to the WAG EOR process; the potential for EOR expansion at Kuparuk is therefore significant.…”

Section: Kuparukmentioning

confidence: 99%

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Review of Gas Injection Projects in BP

Brodie

Jhaveri

Moulds

2012

SPE Improved Oil Recovery Symposium

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BP has developed a range of innovative techniques to maximize economic oil recovery from its global miscible gas floods and the results have been reported in a series of publications over the past three decades. The purpose of this paper is to provide an overview of BP's experience of establishing, managing and optimizing a miscible gas flood.Prudhoe Bay (Alaska) is the world's largest miscible gas project. Conventional and unconventional methods have been applied in a variety of different settings. An extensive surveillance program has facilitated a good understanding of the processes operating at field scale and surveillance data are used to optimize the flood. In 2000, a large-scale gas cap water injection project was implemented to slow the decline in field pressure. This project has made the vaporization process more efficient at higher pressure, resulting in additional recovery. Miscible gas injection has been extended to numerous other fields on the North Slope of Alaska.BP has two active miscible gas projects in the North Sea: Magnus and Ula. Tertiary miscible water-alternating-gas (WAG) flooding in Magnus field started in 2002 and its impact on reservoir performance is significant and well understood. Tertiary miscible WAG injection in Ula field started in 1998 and has played a key role in arresting production decline. The WAG scheme in Ula is currently being expanded. In addition to these projects, BP operates a CO 2 injection and storage project at In Salah, Algeria, where more than 3.2 million tonnes of CO 2 have been stored since 2004.Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so. The potential availability of large sources of CO 2 in the future, supplied by carbon capture, could help maintain a leading role for miscible gas injection for years to come. IntroductionMiscible flooding is a proven method for enhancing oil recovery. The principle is to reduce the interfacial tension between the displacing solvent and displaced oil and thereby achieve a significant reduction in the residual oil saturation compared to immiscible water flooding and primary depletion. Under ideal conditions, miscible flooding can recover almost 100% of the oil originally in place. Under field conditions, this limit is seldom achieved owing to imperfect volumetric sweep, incomplete displacement of oil in rock that is swept and inadequate capture of displaced oil (Stalkup, 1983). In addition, commercial factors may limit the amount of miscible gas that is available. Despite these limitations, there are many successful miscible gas projects around the world and the prospects for miscible flooding in the future look bright if new sources of CO 2 become available for enhanced oil recovery.

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Section: Kuparukmentioning

confidence: 99%

Section: Kuparukmentioning

confidence: 99%

Review of Gas Injection Projects in BP

Brodie

Jhaveri

Moulds

2012

SPE Improved Oil Recovery Symposium

View full text Add to dashboard Cite

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“…However, some field projects involving immiscible CO 2 or hydrocarbon flooding (e.g. Lick Creek, Kuparuk River, Forest Reserves, Brage and Gullfaks) showed that WAG could be applied in the immiscible mode also [3][4][5][6][7][8][9][10].…”

Section: Feasibility Studiesmentioning

confidence: 99%

Water-Alternating-Gas (WAG) Pilot Implementation, A First EOR Development Project in Dulang Field, Offshore Peninsular Malaysia

Nadeson¹,

Aidil²,

Singhal³

et al. 2004

Proceedings of SPE Asia Pacific Oil and Gas Conference and Exhibition

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSome of the older oil fields in Malaysia can be characterized as mature water floods. Schemes for enhancing and prolonging the already declining production and diminishing reserves strategically call for timely implementation of Enhanced Oil Recovery, EOR applications.Among various Enhanced Oil Recovery (EOR) processes and techniques, Malaysia's reservoirs appear especially amenable to gas injection. Feasibility studies showed that immiscible Water-Alternating-Gas (WAG) injection is potentially the most practical and viable option. Laboratory studies and numerical simulation study conducted on the applicability of immiscible WAG injection using high CO 2 content gas indicated that an additional 5-7% of OOIP can be recovered [1]. Such a gain will result in reserves growth and extended producing life of these reservoirs. WAG application is being field tested by implementing a pilot in a sub-block, South-3 of the Dulang field, which is isolated from other subblocks, by major faults. One in-fill well was drilled specifically for the current pilot. Upon drilling this infill well, several geological complexities were uncovered, that called for a thorough revisit of modelling and pilot conceptual plans. The pilot area contains 6 wells, three of which are being used as producers during WAG operations.This paper discusses detail of our first ever EOR pilot implementation (Immiscible WAG in Dulang oil field). It describes progression from conceptual design to various challenges, results and the lessons learnt during early periods of implementation.

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“…The field was put on production in 1981, with a field-wide waterflood recovery development initiated in 1983. Recoverable reserves in the field are in excess of 0.32 × 10 9 m 3 [2 billion bbl] with the first billion barrels having been produced by May 26, 1993 3 .…”

Section: Introductionmentioning

confidence: 99%

Application of Lévy Random Fractal Simulation Techniques in Modelling Reservoir Mechanisms in the Kuparuk River Field, North Slope, Alaska

Gaynor¹,

Chang

Painter

et al. 1998

Proceedings of SPE Asia Pacific Conference on Integrated Modelling for Asset Management

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIncorporating a suitable level of heterogeneity into reservoir simulations is necessary for accurate prediction of production rates and final recoveries. Spatial correlation of petrophysical properties, particularly permeability extrema, exerts a profound influence on flow underlying reservoir displacement and depletion processes. Common modelling techniques are founded on Gaussian assumptions for statistical distributions. Such Gaussian-based approaches can inadequately model the permeability extrema that can dominate reservoir performance. However, optimal reservoir management strategies at the Kuparuk River Field require that significant efforts be made to correctly model reservoir behaviour.This study utilises a new method, Lévy fractal simulation, for interpolating permeability at a former gas injection area now being targeted for oil production. The main producing interval is a diagenetically and mineralogically complex clastic unit. The diagenetic complexity causes difficulties in the lateral modelling of large changes in petrophysical properties observed in nearvertical wells, particularly permeability. Prior efforts at modelling the movement of gas, at typical interwell scales, have met with limited success. In this study, the Lévy technique employs automatic calibration with log and core data for the interwell interpolation of the spatially complex reservoir properties. The Lévy fractal simulations preserve the sharp jumps in reservoir properties observed at stratigraphic boundaries and within reservoir sub-zones. The spatially correlated petrophysical properties are consistent with geologic experience.A fine-scale permeability model incorporating well conditioning data was built using the Lévy fractal interpolation technique. This model encompassed not only the gas injection area but drillsite patterns immediately adjacent. The model preserves the geometry of the reservoir units so that truncation and onlap relationships are preserved. The permeability extrema in the model are characterised by lateral continuities extending over many grid blocks away from control locations. Porosity was modelled using sequential Gaussian simulation (SGS) in which well porosity logs were used as the primary conditioning data, and the modelled permeability used as secondary conditioning data. The fine-scale model was then used as input in an upscaled dynamic simulator built to test reservoir mechanisms. The model was also useful for prognosing porosity and permeability at proposed well locations. Early drilling results indicate that substantial quantities of producible oil remain in the former gas injection area.

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Kuparuk Large-Scale Enhanced Oil Recovery Project

Cited by 8 publications

References 13 publications

Review of Gas Injection Projects in BP

Review of Gas Injection Projects in BP

Water-Alternating-Gas (WAG) Pilot Implementation, A First EOR Development Project in Dulang Field, Offshore Peninsular Malaysia

Application of Lévy Random Fractal Simulation Techniques in Modelling Reservoir Mechanisms in the Kuparuk River Field, North Slope, Alaska

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