Polymer Flooding of Heavy Oil - From Screening to Full-Field Extension

Delamaide, Eric

doi:10.2118/171105-ms

Cited by 58 publications

(36 citation statements)

References 86 publications

(81 reference statements)

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“…Obviously, the reservoir conditions are completely adequate for utilizing chemical flooding according to the published screening criteria of the hydrocarbon formation types and initial fluid properties as well as well pattern design of the heavy-oil reservoir. In detail, the reservoir temperature is much less than 93.3˝C which is the limit point for surfactant and alkaline flooding, while polymer solution can maintain its viscosity at 99˝C [29]. Furthermore, as other requirements such as the nonexistence of gas cap or aquifer, absolute permeability higher than 10 mD, formation water salinity not over 50,000 ppm and the smallest moveable oil saturation of 30%, the considered reservoir is a great candidate for deploying chemical injection in term of technical aspects.…”

Section: Reservoir Modelmentioning

confidence: 99%

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Van

Chon

2016

Energies

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Heavy-oil resources represent a large percentage of global oil and gas reserves, however, owing to the high viscosity, enhanced oil recovery (EOR) techniques are critical issues for extracting this type of crude oil from the reservoir. According to the survey data in Oil & Gas Journal, thermal methods are the most widely utilized in EOR projects in heavy oil fields in the US and Canada, and there are not many successful chemical flooding projects for heavy oil reported elsewhere in the world. However, thermal methods such as steam injection might be restricted in cases of thin formations, overlying permafrost, or reservoir depths over 4500 ft, for which chemical flooding becomes a better option for recovering crude oil. Moreover, owing to the considerable fluctuations in the oil price, chemical injection plans should be employed consistently in terms of either technical or economic viewpoints. The numerical studies in this work aim to clarify the predominant chemical injection schemes among the various combinations of chemical agents involving alkali (A), surfactant (S) and polymer (P) for specific heavy-oil reservoir conditions. The feasibilities of all potential injection sequences are evaluated in the pre-evaluation stage in order to select the most efficient injection scheme according to the variation in the oil price which is based on practical market values. Finally, optimization procedures in the post-evaluation stage are carried out for the most economic injection plan by an effective mathematic tool with the purpose of gaining highest Net Present Value (NPV) of the project. In technical terms, the numerical studies confirm the predominant performances of sequences in which alkali-surfactant-polymer (ASP) solution is injected after the first preflushing water whereby the recovery factor can be higher than 47%. In particular, the oil production performances are improved by injecting a buffering viscous fluid right after the first chemical slug rather than using a water slug in between. The results of the pre-evaluation show that two sequences of the ASP group have the highest NPV corresponding to the dissimilar applied oil prices. In the post-evaluation, the successful use of response surface methodology (RSM) in the estimation and optimization procedures with coefficients of determination R 2 greater than 0.97 shows that the project can possibly gain 4.47 $MM at a mean oil price of 46.5 $/bbl with the field scale of a quarter five-spot pattern. Further, with the novel assumption of normal distribution for the oil price variation, the chemical flooding sequence of concurrent alkali-surfactant-polymer injection with a buffering polymer solution is evaluated as the most feasible scheme owing to the achievement of the highest NPV at the highly possible oil price of 40-55 $/bbl compared to the other scheme.

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Section: Reservoir Modelmentioning

confidence: 99%

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Van

Chon

2016

Energies

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“…Trade-off between mobility and injectivity improvement can be managed. Canadian polymer floods are a good example of this reporting the injection of polymer solutions between 20 and 50 cP in viscous oil (up to 7,500 cP) reservoirs and recovery factors up to 14% of the OOIP (Delamaide, 2014;Renouf, 2014). These observations have been also reported in recent coreflood studies using viscous crude oils (Fabbri et al, 2015;Romero et al, 2013;Skauge et al, 2014).…”

Section: Summary Discussionmentioning

confidence: 66%

“…The formation of oil-polymer emulsions in Delamaide (2014) review was focused on oil-water separation in surface facilities and the impact of the presence of polymer on emulsion stability. The author summarizes cases reporting injectivity reduction (20-40% for 5 of the projects reviewed) with respect to water injection.…”

Section: Summary Of Historical Reviews On Polymer Floodssmentioning

confidence: 99%

“…The author summarizes cases reporting injectivity reduction (20-40% for 5 of the projects reviewed) with respect to water injection. Delamaide (2014) selected the polymer flood in Tambaredjo Field, Suriname, as a case of polymer injection above fracture gradient. Potential risks suggested due to the injection of polymer above fracture gradient, by increasing polymer viscosity, to improve injectivity includes mechanical degradation of polymer, formation of a filter cake (i.e.…”

Section: Summary Of Historical Reviews On Polymer Floodssmentioning

confidence: 99%

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Historical and recent observations in polymer floods: An update review

Manrique¹,

Ahmadi²,

Samani³

2017

CT&F Cienc. Tecnol. Futuro

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Polymer flooding has been the most widely used chemical enhanced oil recovery (EOR) method. The experience gained over the past decades from laboratory studies to project design and field implementation has been well documented in the literature. The main objectives of this paper are to evaluate recent observations of polymer floods that report injection rates leading to pressure values above the formation fracture pressure (FFP), high polymer production, formation of tight emulsions and/or productivity losses.Based on this review, it can be concluded that no direct evidence exists to support that injecting polymer above the FFP will lead to more polymer production. However, uncertainties associated with the estimation of fracture propagation/dimensions using pressure Fall-Off Tests (FOT) still remain. High polymer production, other than severe channeling, is generally reported in large scale/commercial projects. The impact of oil geochemistry/ composition and water salinity on oil-water-polymer emulsions is commonly overlooked in polymer flood studies. The formation of in-situ emulsions can also explain the injectivity and/or productivity reduction and well test interpretation (i.e. FOT) reported in polymer floods. It was also identified that the OPEX (Operational Expenditures) associated with oil-water separation in the presence of polymer and productivity losses (i.e. workovers, stimulation costs) are generally underestimated. Finally, this review is expected to contribute with the planning, design and implementation of future polymer flood pilots and field expansions. OBSERVACIONES HISTÓRICAS Y RECIENTES EN INYECCIÓN DEPOLÍMEROS: REVISIÓN ACTUALIZADA. OBSERVAÇÕES HISTÓRICAS E RECENTES DE INJEÇÃO DE POLÍMEROS:REVISÃO ACTUALIZADA. EDUARDO MANRIQUE et. al. 18 L a inyección de polímeros es el método químico de recobro mejorado con mayor número de implementaciones a escala de campo. La experiencia adquirida en las últimas décadas desde estudios de laboratorio hasta el diseño e implementación de campo ha sido bien documentada en la literatura. El objetivo principal de este trabajo es evaluar observaciones recientes de proyectos de inyección de polímero reportando tasas de inyección por encima de la presión de fractura de la formación, alta producción de polímero, formación de emulsiones viscosas y/o pérdidas de productividad.Basados en esta revisión, se puede concluir de que no existen evidencias directas de que la inyección de polímero a tasas que impliquen superar la presión de fractura induzcan a una mayor producción de polímeros. Sin embargo, existen incertidumbres relacionadas con la estimación de las dimensiones y propagación de fracturas utilizando pruebas de caídas de presión (FOT). La alta producción de polímero, por razones diferentes a canalizaciones severas, generalmente se reportan en proyectos a escala comercial. Por otra parte, el impacto de la composición y geoquímica del crudo y de la salinidad del agua en la formación de emulsiones agua:petróleo:polímero ha sido subestimado en estudios de in...

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“…Evaluation of polymer injection started there in the early 1970s through laboratory research, followed by a pilot in 1990 which showed an increase of 14% in recovery in a single-layer test and 11.6 % oil recovery in a double-layer test Oman has followed in China's footsteps in implementing polymer floods. The Marmul field contains the highest viscosity oil in the Arabian Gulf area at around 90 cp (Delamaide, 2014). The first polymer pilot started in 1986, but due to low oil prices, full field injection implementation only started in early 2010, with 6.3 million barrels incremental oil recovered by December 2013 (Oil and Gas News, 2015).…”

Section: Current Projectsmentioning

confidence: 99%