Quantifying the Impact of Permeability Heterogeneity on Secondary-Recovery Performance

Rashid, Bilal; Muggeridge, Ann; Bal, Astor-Lonice; Williams, Glyn

doi:10.2118/135125-pa

Cited by 56 publications

(18 citation statements)

References 17 publications

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“…Heterogeneity and geological factors have different impacts on the various EOR processes, including polymer and alkaline-surfactant-polymer, thermal and gasinjection (miscible and immiscible) EOR. Studies of the effects of geological heterogeneity and uncertainty on EOR performance include Kumar et al (2006), Chen et al (2008), Popov et al (2010), Rashid et al (2010), Soleimani et al (2011), Chiotoroiu et al (2017), and Kumar et al (2017).…”

Section: Introductionmentioning

confidence: 99%

Discerning in-situ performance of an EOR agent in the midst of geological uncertainty I: Layer cake reservoir model

Fatemi

Rossen

2017

Journal of Petroleum Science and Engineering

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An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to demonstrate oil recovery, verify the properties of the EOR agent in-situ, and provide the information needed for scale-up to an economic process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in-situ in the midst of geological uncertainty. We propose a general workflow and present a case study to illustrate this challenge: a polymer EOR process in a 2D layer-cake reservoir. The polymer is designed to have a viscosity of 60 cp in-situ. There is uncertainty in the reservoir description, represented here by a range of values of Dykstra Parsons coefficient and different spatial arrangements of layers. We allow that the polymer process might fail in-situ and viscosity could be 20% of that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of the geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity to the scatter caused by the geological uncertainty using the statistical 95% confidence interval. Among the signals considered, the 'rate of rise in injection pressure with polymer injection' and 'maximum injection pressure in the injector' give the most reliable indications of whether a polymer viscosity was maintained in-situ. If unintended and uncontrolled fracturing of the injection well is considered likely during polymer injection, however, injection pressure may be an unreliable indicator of in-situ polymer viscosity. In that case a diagnostic fracture-injection/falloff test could produce the needed indication of polymer viscosity in-situ. 'Polymer breakthrough time' and 'cumulative oil production at the end of process' give indications of polymer in-situ loss in some of the cases. With a more severe viscosity loss, e.g. 90% or worse, these signals give a statistically significant indication of loss of polymer viscosity in all of the cases.

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Section: Introductionmentioning

confidence: 99%

Discerning in-situ performance of an EOR agent in the midst of geological uncertainty I: Layer cake reservoir model

Fatemi

Rossen

2017

Journal of Petroleum Science and Engineering

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“…In most cases, stratified reservoirs possess vertical continuity; however, there are many with barriers to vertical flow. To the best of our knowledge, most waterflood performance is studied in stratified communicating reservoirs [2,10] with very few reported studies on stratified reservoirs with vertical discontinuity. It is worth mentioning that the enormous works done on waterflood performance on heterogeneous reservoir with vertical discontinuity based on Dykstra-Parson and Styles method are based on the assumption of piston like displacement, ignoring the aspect of microscopic displacement efficiency, which is the focus of this study.…”

Section: Introductionmentioning

confidence: 99%

Effect of Pore-Scale Heterogeneity and Capillary-Viscous Fingering on Commingled Waterflood Oil Recovery in Stratified Porous Media

Al-Shalabi

Ghosh

2016

Journal of Petroleum Engineering

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Oil recovery prediction and field pilot implements require basic understanding and estimation of displacement efficiency. Corefloods and glass micromodels are two of the commonly used experimental methods to achieve this. In this paper, waterflood recovery is investigated using layered etched glass micromodel and Berea sandstone core plugs with large permeability contrasts. This study focuses mainly on the effect of permeability (heterogeneity) in stratified porous media with no cross-flow. Three experimental setups were designed to represent uniformly stratified oil reservoir with vertical discontinuity in permeability. Waterflood recovery to residual oil saturation (Sor) is measured through glass micromodel (to aid visual observation), linear coreflood, and forced drainage-imbibition processes by ultracentrifuge. Six oil samples of low-to-medium viscosity and porous media of widely different permeability (darcy and millidarcy ranges) were chosen for the study. The results showed that waterflood displacement efficiencies are consistent in both permeability ranges, namely, glass micromodel and Berea sandstone core plugs. Interestingly, the experimental results show that the low permeability zones resulted in higher ultimate oil recovery compared to high permeability zones. At Sor microheterogeneity and fingering are attributed for this phenomenon. In light of the findings, conformance control is discussed for better sweep efficiency. This paper may be of help to field operators to gain more insight into microheterogeneity and fingering phenomena and their impact on waterflood recovery estimation.

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“…The drawback is that the gas viscosity and density are much lower than those of the oil. This typically results in a poor macroscopic sweep efficiency due to gravity override or viscous fingering (Fayers and Muggeridge, 1990) in a homogeneous reservoir or channelling in heterogeneous reservoirs (Rashid et al, 2012).…”

Section: Introductionmentioning

confidence: 99%

Experimental and Numerical Studies of First Contact Miscible Injection in a Quarter Five Spot Pattern

Djabbarov

Jones

Krevor

et al. 2016

SPE Europec Featured at 78th EAGE Conference and Exhibition

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We quantify the impact of mobility, simple heterogeneities and grid orientation error on the performance of first contact miscible gas flooding in a quarter five spot configuration by comparing the outputs from experimental and numerical models. The aim is to quantify the errors that may arise during simulation and to identify a workflow for minimizing these when conducting field scale fingering studies.A commercial reservoir simulator was validated by comparing its predictions with the results obtained from physical experiments. An uncorrelated, random permeability distribution was used to trigger fingering in the simulations. The physical experiments were carried out using a Hele-Shaw cell (40ϫ40cm) designed and constructed for this study. The impact of a square low permeability inclusion (20ϫ20cm) on flow was investigated by varying its permeability, location and orientation.For lower mobility ratios (Mϭ2 to Mϭ10) the commercial numerical simulator was able to reproduce the experimental observations within the uncertainty range of the permeability distribution used to trigger the fingers, provided a nine-point scheme was used for the pressure solution. At higher mobility ratios (Mϭ20 to Mϭ100) the grid orientation effect meant that the simulator overestimated the areal sweep even when a nine-point scheme was used. The introduction of a square, low permeability inclusion near the injection well reduced the discrepancy between experimental and numerical results, bringing it back within uncertainty limits in some of the cases. This was mainly because the real flow was then forced to move parallel to the edges of the Hele-Shaw cell and thus parallel to the simulation grid. Breakthrough times were well predicted by the numerical simulator at all mobility ratios.

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Quantifying the Impact of Permeability Heterogeneity on Secondary-Recovery Performance

Cited by 56 publications

References 17 publications

Discerning in-situ performance of an EOR agent in the midst of geological uncertainty I: Layer cake reservoir model

Discerning in-situ performance of an EOR agent in the midst of geological uncertainty I: Layer cake reservoir model

Effect of Pore-Scale Heterogeneity and Capillary-Viscous Fingering on Commingled Waterflood Oil Recovery in Stratified Porous Media

Experimental and Numerical Studies of First Contact Miscible Injection in a Quarter Five Spot Pattern

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