Evaluation of Key Reservoir Drive Mechanisms in the Early Cycles of Steam Stimulation at Cold Lake

Denbina, E.S.; Boberg, T.C.; Rotter, M. B.

doi:10.2118/16737-pa

Cited by 40 publications

(18 citation statements)

References 9 publications

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“…Operation during the first 30 months (Phase A) can be classified as SAGD process: simultaneous and continuous steam injection and oil production. However, the oil-steam ratio during this period was 0.15, which is about half of that obtained using the Cyclic Steam Stimulation (CSS) process in the same area (7) . A depletion index of 0.96 seen during this period is also unexpectedly low.…”

Section: Objectives Of the Studymentioning

confidence: 67%

Reinterpretation of Performance of Horizontal Well Pilot No. 1 (HWPI) 1980 - 1989

Ito¹,

Singhal

1999

Journal of Canadian Petroleum Technology

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The performance of Imperial Oil Resources Ltd.'s Horizontal Well Pilot No.1 (HWPI) was reinterpreted using numerical simulation. It appears plausible that the performance was significantly influenced by geomechanical deformation of the reservoir. The project is a successful thermal horizontal well pilot that has recovered more than 50,000 m3 of 10 ° API Cold Lake Clearwater bitumen over the last decade at an oil-steam ratio of over 0.35. Steam is injected via a vertical injector, and oil produced via a horizontal producer. It was observed that oil rates, as well as oil cuts improved when steaming was discontinued. Consequently, the bulk of the oil was recovered when steam was not being injected. This behaviour could not be explained by any of the conventional theories regarding thermal operations. It is speculated that geomechanical effects (namely, increases and decreases in porosity with pressurization and depressurization, creation of flow channels due to formation-dilation upon steam injection, transport of heat and fluids deep into the reservoir via these channels, etc.), as first proposed by Ito, and termed "Sand Deformation," may be responsible for this production behaviour. To test this hypothesis, the performance of the pilot for the first eight years was simulated. Excellent history matches were obtained. Many interesting field observations were made, such as (1) oil production improved when steaming was stopped, (2) low fluid production was seen for the first two and a half years of operation, and (3) lower than expected amount of energy was produced. Changes in porosity, permeability and relative permeability to water with pressure, as required for obtaining a satisfactory history match, are larger than those determined in the laboratory. This discrepancy needs to be investigated by further research. Introduction The first horizontal well in the oil sands was drilled in 1978 at Cold lake by Imperial Oil. It was drilled from the surface and has a horizontal slotted section of 245 m total length. It served as a production well. A vertical injection well was located over the horizontal well at a distance of 45 m from the toe end of the slotted section. Over 50,000 m3 of bitumen has been recovered at a cumulative oil-steam ratio (OSR) of over 0.35 during the first eight years of operation. Performance during the first eight years of operation, as well as data for comprehensive field monitoring program, including bottom hole pressures and reservoir temperatures, were presented by Adegbesan et al.(1) Analytical models were developed and recovery mechanisms were also investigated. It was concluded that recovery mechanisms changed with elapsed time of the project. The results of a numerical history match of the subject well pair were presented by Adegbesan(2). Many interesting concepts, including geomechanical deformation, were used for obtaining the history match. A good match of the cumulative oil production was obtained. According to Butler(3), during the Steam Assisted Gravity Drainage (SAGD) process, production rates will increase as a steam chamber spreads along a horizontal production well with a vertical injector. He developed equations to calculate oil production rate during the spreading period.

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Section: Objectives Of the Studymentioning

confidence: 67%

Reinterpretation of Performance of Horizontal Well Pilot No. 1 (HWPI) 1980 - 1989

Ito¹,

Singhal

1999

Journal of Canadian Petroleum Technology

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“…CSS is particularly attractive because it has quick payout, however, recovery factors are low (10-40% OIP). In a variation, CSS is applied under fracture pressure [2]. The process becomes more complex as communication develops among wells.…”

Section: Hotmentioning

confidence: 99%

“…CO 2 Miscible CO 2 Miscible [16] method has been gaining prominence in recent years, partly due to the possibility of CO 2 sequestration. Apart from environmental objectives, CO 2 is a unique displacing agent, because it has relatively low minimum miscibility pressures (MMP) with a wide range of crude oils.…”

Section: Vaporizing Gas Drivementioning

confidence: 99%

Enhanced Oil Recovery - An Overview

Thomas¹

2007

Oil & Gas Science and Technology - Rev. IFP

714

318

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Résumé -Récupération assistée du pétrole : panorama -Près de 2,0 × 10 12 barils (0,3 × 10 12 m 3 ) de pétrole conventionnel et 5,0 × 10 12 barils (0,8 × 10 12 m 3 ) de pétrole lourd resteront dans les réservoirs du monde entier lorsque les méthodes de récupération traditionnelles auront été épuisées. Une grande partie de ce pétrole serait récupéré grâce à des méthodes de Récupération Assistée du Pétrole (EOR), qui fait partie du projet général de Récupération Améliorée du Pétrole (IOR). Le choix de la méthode et la récupération escomptée dépendent de nombreuses considérations économiques et technologiques. Cet article étudie les méthodes EOR qui ont été testées sur le terrain. Certaines ont été une réussite commerciale, tandis que d'autres sont d'un intérêt essentiellement académique. Les raisons en sont discutées. L'article examine les méthodes de récupération du pétrole thermique et non thermique. Elles sont présen-tées de façon équilibrée, en prenant en compte le succès commercial sur le terrain. Seules quelques méthodes de récupération ont connu une réussite commerciale, tels que les processus d'injection de vapeur dans les pétroles lourds et les sables bitumineux (si le réservoir offre des conditions favorables pour de telles applications) et de dioxyde de carbone miscible pour les réservoirs de pétrole léger. D'autres méthodes de récupération ont été testées, et ont même permis d'augmenter la récupération d'huile mais comportent des limites inhérentes. Les technologies EOR actuelles sont présentées dans une perspective appropriée, soulignant les raisons techniques au manque de réussite. Les méthodes d'amélio-ration de la récupération de pétrole, en particulier celles visant à diminuer la saturation interstitielle du pétrole, ont fait l'objet d'une attention particulière dans les laboratoires et sur le terrain. Les nombreux documents qui traitent du sujet donnent l'impression qu'il est relativement simple d'augmenter la récupé-ration de pétrole au-delà de la récupération secondaire (en assumant que le réservoir se prête à une récu-pération primaire et secondaire). Il s'avère que ce n'est pas le cas. De nombreux réservoirs adaptés à l'injection de vapeur et au dioxyde de carbone ont déjà été exploités et arrivent à maturité. D'autres méthodes EOR rencontrent des limites qui ne sont pas liées à des facteurs économiques. La récupération du pétrole supplémentaire est complexe et coûteuse, et s'est révélé probante seulement pour quelques processus et ce, dans des conditions astreignantes. Néanmoins, l'EOR continuera d'avoir une place importante dans la production pétrolière, en raison de l'intensification de la demande en énergie et de l'offre limitée. Un important travail de recherche doit être mené à bien pour développer des technologies de récupération sur les deux tiers du pétrole qui ne sera pas récupéré dans les réservoirs. Des références clés sont indiquées. Abstract

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“…Before steam injection, the reservoir model was run for a period of 61 days with no injection or production to ensure that the variables (e.g., flow, saturations, pressure, temperature, stresses) in the model were fully equilibrated. Typical of Cold Lake CSS operations, the steam-injection period lasted for 38 days (Denbina et al 1991). After the steam-injection period, no soak period was conducted and the well was converted directly to production, which lasted 76 days.…”

Section: Resultsmentioning

confidence: 99%

Reservoir Simulation of Steam Fracturing in Early-Cycle Cyclic Steam Stimulation

Cokar

Gates

Kallos

2012

SPE Reservoir Evaluation &Amp; Engineering

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In cyclic steam stimulation (CSS), steam is injected above the fracture pressure into the oil-sands reservoir. In early cycles, the injected steam fractures the reservoir, creating a relatively thin dilated zone that allows rapid distribution of heat within the reservoir without excessive displacement of oil from the neighborhood of the wellbore. Numerical reservoir-simulation models of CSS that deal with the fracturing process have difficulty simultaneously capturing flowing bottomhole-pressure (BHP) behavior and steam injection rate. In this research, coupled reservoir-simulation (flow and heat transfer) and geomechanics models are investigated to model dynamic fracturing during the first cycle of CSS in an oil-sands reservoir. In Alberta, Canada, in terms of volumetric production rate, CSS is the largest thermal recovery technology for bitumen production, with production rates equal to approximately 1.3 million B/D in 2008. The average recovery factor from CSS is between 25 and 28% at the economic end of the process. This implies that the majority of bitumen remains in the ground. Because the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir, which is largely established during steam fracturing of the reservoir in the early cycles of the process. Thus, a fundamental understanding of the flow and geomechanical aspects of early-cycle CSS is critical. A detailed thermal reservoir-simulation model, including dilation and dynamic fracturing, was developed, with the use of a commercially available thermal reservoir simulator, to understand their effects on BHP and injection rate. The results demonstrate that geomechanics must be included to accurately model CSS. The results also suggest that the reservoir dilates during steam injection as the result of increases in reservoir temperature, which lead to thermal dilation and higher pore pressure.

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Evaluation of Key Reservoir Drive Mechanisms in the Early Cycles of Steam Stimulation at Cold Lake

Cited by 40 publications

References 9 publications

Reinterpretation of Performance of Horizontal Well Pilot No. 1 (HWPI) 1980 - 1989

Reinterpretation of Performance of Horizontal Well Pilot No. 1 (HWPI) 1980 - 1989

Enhanced Oil Recovery - An Overview

Reservoir Simulation of Steam Fracturing in Early-Cycle Cyclic Steam Stimulation

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