Reservoir Management Challenges of the Terra Nova Offshore Field: Lessons Learned After Five Years of Production

Haugen, Einar Dagfinn; Costello, James; Wilcox, L.; Albrechtsons, Eric; Kelly, Irene

doi:10.2118/109587-ms

Cited by 3 publications

(9 citation statements)

References 11 publications

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“…The Terra Nova offshore oil field, located in the Jeanne d'Arc Basin, came online roughly twenty years ago. Haugen et al published a paper in 2007 covering the lessons learned after the first five years of production with a section focusing on the injection of a rich gas for gas flood, near or above miscible conditions [11].…”

Section: Regionalmentioning

confidence: 99%

“…The Graben region of the Terra Nova field was designated for gas injection, with a total of three gas injector wells planned; however, due to delays in commissioning, the two associated production wells produced on primary for some time until the gas injectors were brought online [11]. The startup of gas injection quickly supported the producers and brought the reservoir pressure back up [11].…”

Section: Regionalmentioning

confidence: 99%

“…Throughout the literature review sourcing process it became clear that many papers related to WAG serve as case studies of particular offshore fields [11] or very specific simulation studies aimed at evaluating WAG recovery as an EOR technique [12]. The novelty of this study comes from its evaluation of WAG as a secondary recovery method, compared against water flooding and gas flooding in a sensitivity analysis format.…”

Section: Introductionmentioning

confidence: 99%

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Assessment of Oil Recovery Methods for Reservoirs in the Flemish Pass Basin

LaFitte¹

2022

Day 2 Thu, March 17, 2022

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Summary In recent years, the Flemish Pass Basin has been gaining momentum as an area of potential high-volume resources on the frontier of remote, deep-water offshore oil development. This simulation study utilizes three sector models representing regional, discovered reservoirs, and two tuned fluid models representing oil sampled from wells in the Flemish Pass Basin. Generally speaking, WAG is considered a late-life enhanced oil recovery (EOR) technique, while implementing WAG immediately upon first oil for secondary recovery is less common; however, may be equally or more valuable. This study aims to evaluate three secondary oil recovery methods, water flooding, gas flooding, and water-alternating-gas (WAG) flooding. Each recovery method is simulated with Schlumberger’s ECLIPSE reservoir simulator and uses a combination of three distinct reservoir geo-models and two fluid models. This study is a sensitivity analysis using geo-models that represent three discovered regions and two sampled fluids from the Flemish Pass Basin. The study is aimed at evaluating the effects of the various recovery methods over a duration of either five- or twenty-year forecast periods. Results from this study capture an inherent uncertainty by drawing from eighteen simulation cases to quantify the relative benefit of each recovery method. These results indicate that using WAG as a secondary recovery method can yield a 4% to 10% increase in recovery over water or gas flood, and that secondary WAG can extend a well pair’s production plateau by up to 80% in specific circumstances. Further observations indicate that secondary WAG in light oil reservoirs yield a ∼10% increase in recovery over secondary water or gas flooding. Using WAG in a medium oil reservoir yields a 4% to 9% increase in recovery over water flood, and a 2% to 16% increase in recovery over gas flood. In terms of geology, WAG is observed to be most valuable in ultra-high-quality reservoirs. The better the reservoir quality, the more recovery improvement. In terms of fluids, the medium oil responds best to the gas injection phase of WAG while the light oil appears to respond well to both phases. During development optimization, these trends can be accounted for in the injection cycle timing and duration for each phase. In terms of using WAG as a tertiary recovery method after a period of water or gas flooding, tertiary WAG is observed to be most beneficial in the low to medium quality reservoirs. Tertiary WAG extends the production duration and results in a ∼4% increase in recovery beyond water flooding. Study results go on to quantify the differences in water and gas breakthrough as a factor of pore volume injected (PVI) and conclusions further indicate which reservoirs are best suited for each recovery method.

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Section: Regionalmentioning

confidence: 99%

Section: Regionalmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Assessment of Oil Recovery Methods for Reservoirs in the Flemish Pass Basin

LaFitte¹

2022

Day 2 Thu, March 17, 2022

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“…Fifteen oil producers, eight water injectors and three (solution) gas injectors have been drilled from four drill centers. In reviewing the field after five years of production, Haugen et al (2007) comment that, 'initial concerns of barriers at sub-seismic faults have not materialized,' and, 'material balance and history matching indicate extensive cross-fault connectivity.' Two examples of this high level of connectivity that affect reservoir management are illustrated here.…”

Section: Production Fault Block Scale Rcamentioning

confidence: 99%

“…In addition to its utility at Terra Nova, RCA has been an excellent reservoir management tool at Hibernia Field and led directly to identification of over 200 million barrels of additional reserves, 25 years after discovery and 7 years into production. Overviews are provided by Magoon et al (2005), who synthesize the Egret-Hibernia petroleum system in the Jeanne d'Arc Basin; and by Haugen et al (2007), who provide a summary of the geoscience and petroleum engineering of the Terra Nova field.…”

mentioning

confidence: 99%

Reservoir connectivity analysis of a complex combination trap: Terra Nova Field, Jeanne d'Arc Basin, Newfoundland, Canada

Richards

Vrolijk

Gordon

et al. 2010

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Terra Nova Oil Field is formed by a complex, structural, stratigraphic and diagenetic combination trap. About 1 billion barrels Stock-Tank Oil-In-Place (STOOIP) are trapped in a faulted plunging anticline, reservoired in stacked, braided fluvial sandstones which are of varying quality and extent due to onlap, cementation and facies transitions. Terra Nova Field is unusual when compared to the other three major hydrocarbon fields in the Jeanne d'Arc Basin in that it lacks a gas leg, and hydrocarbons are confined to the deepest of four major reservoir intervals, the Jeanne d'Arc sandstones. In this reservoir interval, the highest part of the plunging anticline is wet while the lowest part has the deepest fluid contact and longest oil column. Aquifer pressures vary between hydrostatic and significantly overpressured, but are far below leak-off. This apparently unusual distribution of fluids, pressures and contacts can be understood by systematically describing the many compartments within the overall structure, defining the connections between compartments, and building a 'connectivity diagram' which ensures a disciplined analysis of the fluid system. This type of approach, used historically by the Operator, Petro-Canada, and formalized as 'Reservoir Connectivity Analysis' (RCA) at ExxonMobil, is effective and necessary at multiple scales: basin, field, producing fault block and individual sandstone, and continues to be important at Terra Nova eight years into development and production.

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