Modelling Injection Strategies for a Reservoir with an Extreme Permeability Contrast: IOR Qualification

Surguchev, L.M.; Hanssen, Jan Erik; Johannessen, Hege M.; Sisk, Carl

doi:10.2118/35504-ms

Cited by 8 publications

(1 citation statement)

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“…In vertical fractures, care should be taken to limit gravity-segregated fluid flow during coinjection of aqueous and gaseous phases. During gas-injection projects, foam should be injected as early as possible after gas breakthrough (Surguchev et al 1996). Foam injection in combination with other EOR efforts may also improve economics-for instance, foam in combination with alkaline/surfactant/polymer flooding or polymer gels (Wang et al 2008).…”

Section: Pv Injected Oil Recovery Fraction Of Ooip Differential Presmentioning

confidence: 99%

Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery

Haugen

Fernø

Graue

et al. 2012

SPE Reservoir Evaluation &Amp; Engineering

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Our objective was to study foam flow in fractured, oil-wet carbonate rocks and determine if foam may be a viable enhanced-oilrecovery (EOR) agent in such reservoirs. We present experimental results in fractured carbonate rock and show effects of wettability on oil recovery when using foam. Oil recovery by water, surfactant, or gas injection exhibited low recovery, less than 10% of original oil in place (OOIP). Oil recovery during injection of pregenerated foam was improved significantly, with up to 78% of OOIP produced. Foam reduced the gas mobility in the fractured rock, increased differential pressure, and diverted flow into the oil-saturated matrix. However, a significant amount of foam injection was required for the additional oil recovery. Generation of foam in-situ was weak in the smooth-walled fractures, and no fluid diversion from the fractures with additional oil recovery was observed. On the basis of the experimental results, mechanisms for foam collapse in the fracture are discussed and possible steps to improve recovery are outlined.

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Section: Pv Injected Oil Recovery Fraction Of Ooip Differential Presmentioning

confidence: 99%

Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery

Haugen

Fernø

Graue

et al. 2012

SPE Reservoir Evaluation &Amp; Engineering

View full text Add to dashboard Cite

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Impact of Relative Permeability Hysteresis, IFT dependent and Three Phase Models on the Performance of Gas Based EOR Processes

Masalmeh¹,

Wei

2010

All Days

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In this paper we report on a gas-injection based EOR study in heterogeneous carbonate reservoirs. The focus of the study is on modelling three phase flow, hysteresis and compositional effects on relative permeability for a reservoir with different scales of heterogeneity.For all gas-injection based EOR processes, numerical modelling requires proper understanding and presentation of phase behaviour, saturation functions and geological heterogeneity. In this study we performed a systematic analyses of the interplay between compositional effects, relative permeability hysteresis, interfacial tension dependent relative permeability and three phase relative permeability models for different gas based EOR schemes (e.g., WAG, SWAG, SIMGAP). The simulation runs were performed using 2D and 3D fine scale sector models. In order to extend the applicability of the results to a wide range of carbonate reservoirs, the study was performed using three different reservoir models with different permeability profiles and different initial water saturation distributions. To quantify the impact of phase behavior, the performance of different injection gases (methane, CO2 and acid gas) was compared. Finally, we also compared the impact different three phase relative permeability models on oil recovery.To the best of our knowledge, there is no commercial simulator which has implemented the combination of relative permeability hysteresis, IFT dependent and three phase models in compositional mode. Therefore, the study presented in this paper is the first in the literature which investigates the combination of all these effects on the performance of gas injection EOR schemes. The study shows that proper representation of relative permeability hysteresis, compositional effects and three phase models is essential in order to assess the performances of all gas based EOR processes. The study also shows that before embarking on very expensive laboratory work for EOR studies under three-phase flow, simulations should be used to help design the laboratory work in order to focus on the most important parameters that affect fluid flow and hydrocarbon recovery. The simulation work should be carried out using fine grid sector models.

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Miscible CO2 Injection in Highly Heterogeneous Carbonate Cores: Experimental and Numerical Simulation Studies

Eidan

Mamora

2011

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We have conducted a miscible CO 2 flood using carbonate cores and 31° API west Texas oil under four injection modes: simultaneous water and CO 2 (SWACO 2 ), water alternating CO 2 (WACO 2 ), continuous gas injection (CGI), and waterflood (WF). Then, a pseudo-miscible black oil simulator was used to match the experimental results. The matched simulation model was extended to conduct a sensitivity study on permeability variation in the core, WACO 2 ratio and slug size, and SWACO 2 ratio. Three permeability values were chosen to represent a flow barrier, average matrix permeability, and high permeability streak. These values were arranged to represent a layered reservoir and then aligned in series to represent a sequenced reservoir. The four injection modes were conducted in all six permutations of these three values in both the layered and sequenced arrangements. The oil recovery from the coreflood experiments was measured to be 90, 86, 75, and 54 % of OIIP for SWACO 2 , WACO 2 , CGI, and WF, respectively. The simulation results may be summarized as follows: for all injection modes during the layered permeability arrangements, the best oil recovery was obtained when the flow barrier is in the middle of the core. Conversely, lower recoveries were obtained when the barrier was not in the middle and the high permeability was located at the top with significant decrease in oil recovery (up to 40%). In sequenced reservoirs, each injection mode showed different preference to the permeability arrangements. For example, CGI showed higher recovery (5% increase) when the low permeability is near the outlet which allowed for more controlled displacement but with high differential pressure across the core. The WACO 2 ratio study in the homogenous (base) case showed that a 1:2 ratio had the highest oil recovery but the optimum ratio was 1:1 based on the amount of injected CO 2 . In layered reservoirs, each permeability arrangement had higher recovery at different WACO 2 ratios depending on the location of the flow barrier. However, in most cases 1:1 ratio was the optimum except for two cases, where the high permeability was at top, the 3:1 (increasing water ratio) was the optimum WACO 2 ratio.

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Modelling Injection Strategies for a Reservoir with an Extreme Permeability Contrast: IOR Qualification

Cited by 8 publications

References 0 publications

Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery

Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery

Impact of Relative Permeability Hysteresis, IFT dependent and Three Phase Models on the Performance of Gas Based EOR Processes

Miscible CO2 Injection in Highly Heterogeneous Carbonate Cores: Experimental and Numerical Simulation Studies

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