Experimental and Numerical Simulation Studies of Different Modes of CO2 Injection in Fractured Carbonate Cores

Eidan, Ahmed Abdulaziz Al; Mamora, Daulat Debataraja; Schechter, David S.

doi:10.2118/143512-ms

Cited by 11 publications

(10 citation statements)

References 13 publications

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“…The continuous miscible CO 2 flooding shows the highest oil recovery of 73.44% OOIP after injection of about 5 pore volumes of CO 2 , Figure 4. This observation agrees with published work on sandstone, chalk, and limestone ( K u l k a r n i and Rao, 2005; Karimaie et al, 2008;and Aleidan et al, 2011). Continuous brine flooding shows about 52% OOIP after injecting 12 pore volumes of water which is comparable to some published work on carbonate cores (Aleidan and Mamora, 2010).…”

Section: Effect Of Wag Ratio On Oil Recoverysupporting

confidence: 92%

Optimization of CO2 WAG Processes in a Selected Carbonate Reservoir-An Experimental Approach

et al. 2012

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Miscible gas flooding using carbon dioxide is currently being investigated as a possible EOR process for a number of United Arab Emirates (UAE) reservoirs. It has high potential to improve oil recovery in addition to possibly utilizing most of the carbon dioxide emissions from industrial sources. The major factors affecting implementation of CO2 floods are the availability of CO2 at economic prices (generally within 2-3 $/MSCF) and the net utilization ratio of CO2 per barrel of additional oil recovered. Typical net utilization of CO2 for well-designed floods vary from field to field but on average has been estimated at 5.5 MSCF CO2 per additional barrel of oil in a US EOR overview study by Broome et al.1 and between 4-6 MSCF/barrel by a more recent study by Jeschke et al.2. At other fields it might be as high as 15 MSCF/barrel or more. Minimizing net utilization requires controlling the high mobility ratio for miscible gas injection which causes lower sweep due to gas channeling and by-passing of the oil in the reservoir. To control the mobility ratio, the Water-Alternating CO2-Gas (WAG) technique is proposed by injecting alternately small solvent [CO2] and water slugs. The slug of water reduces the speed of the solvent and solvent fingering thus improving the mobility ratio of the injected fluids to fluids in place. The objective of this work is to experimentally assess the recovery of oil with CO2 injection in a selected UAE carbonate reservoir. Two types of CO2-flooding experiments were conducted, continuous miscible CO2 injection and CO2-WAG injection using a specialized experimental rig. The effects of changing the CO2-Water ratio and WAG timing on the overall performance of the flood were investigated. All laboratory tests were conducted under controlled conditions of pressure and temperature corresponding to field conditions. Results of this laboratory investigation reveal a general trend of improved oil recovery with increased volume of CO2 inside core samples during the flood process. The observed ultimate oil recoveries range from 52 percent with continuous water injection to 72 percent of the original oil in place with continuous CO2 injection over the full period of the experiment with recoveries of the CO2-WAG floods falling in between. The optimum CO2-WAG ratio was found to occur at 1:2. The outcomes of this work should contribute to our understanding of WAG CO2 floods for the UAE reservoirs and supports the ongoing R&D efforts made by the operating oil companies in the UAE towards application of CO2-WAG floods

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Section: Effect Of Wag Ratio On Oil Recoverysupporting

confidence: 92%

Optimization of CO2 WAG Processes in a Selected Carbonate Reservoir-An Experimental Approach

et al. 2012

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“…Several field case studies have shown the successful management of the CO 2 ‐EOR process both above and below the minimum miscibility pressure 11,14,34 . Water alternating gas (WAG) injection has also been considered as another means of enhancing oil recovery after primary production 35–38 . Furthermore, CO 2 can be potentially stored in the depleted reservoir after the EOR phase as a strategy to reduce the amount of greenhouse gases in the atmosphere 34,39 .…”

Section: Introductionmentioning

confidence: 99%

“…Screening methods (such as analytical and numerical analysis) 34,39,56,57 have been used to evaluate the efficiency of each step. In this case, numerical and analytical methods provide tools to evaluate the effect of specific parameters on EOR and CO 2 ‐storage performance including the effect of miscibility on CO 2 ‐EOR performance, 41,50,58–61 different injection strategies, 35 wettability and hysteresis, 49,52,62 fracture–matrix interaction, 25 and CO 2 ‐EOR and storage efficiency 34,36,63–71 …”

Section: Introductionmentioning

confidence: 99%

The effect of natural fractures on CO₂storage performance and oil recovery from CO₂and WAG injection in an Appalachian basin reservoir

2020

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Natural fractures affect both the oil recovery from the enhanced oil recovery (EOR) process and the associated CO 2 storage during and after EOR. The main objective of this study is to evaluate two performance parameters: (1) oil recovery during CO 2 and water alternating gas (WAG) injection, and (2) CO 2 storage, during and after EOR, in a fractured oil reservoir of the Appalachian basin. While previous studies have shown the potential of CO 2-EOR to enhance oil recovery in the Appalachian basin, this work investigates WAG performance in comparison to continuous CO 2-EOR. A compositional numerical modeling approach was used to quantify the incremental oil recovery stemming from incorporating natural fractures. History matching of primary production and CO 2 huff-and-puff pilot test for a well producing from a depleted oil field in Ohio was used to assign the fracture network parameters in the dual continuum model. The scenarios modeled include continuous CO 2 and WAG injection under two injection pore volumes. Each scenario is followed by a CO 2 storage phase. These simulations help evaluate the performance of different scenarios in terms of oil recovery and CO 2 storage. Simulation results show how oil recovery and CO 2 storage vary significantly as a function of operational parameters. The results also show the amount of CO 2 stored during WAG injection is significantly lower than that stored during the storage phase at the end of oil recovery. In addition, the operational parameters during WAG affect the amount of CO 2 stored at the end of following storage phase.

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“…Because the gas is in bubbles,t he gas flow can be easily controlled and the poor volumetric sweep efficiency problem can be remedied. [8][9][10][11] As foam is injected into place, it can block the high-permeability layer first and divert subsequent fluid into al ow-permeability layer. However, bubbles are unstable both thermodynamically and kinetically.F oams can be stabilized either by surfactantd issolved in the liquidp hase or by as mall solid phase dispersed in the liquid phase.…”

Section: Introductionmentioning

confidence: 99%

Nanoparticle‐Stabilized Foam for Mobility Control in Enhanced Oil Recovery

Sun

Zhang

et al. 2016

Energy Tech

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Foam stabilized by a surfactant has been used successfully for mobility control during enhanced oil recovery processes, but the stability of the foam limits its application. Aqueous foams prepared from dispersions of partially hydrophobic silicon dioxide (SiO2) nanoparticles and sodium dodecyl sulfate (SDS) anionic surfactant were studied and the injection behavior of foams stabilized by a solution of SDS or dispersion of SiO2/SDS were analyzed for comparison. Foam stability increased with increasing nanoparticle concentration although the feasibility of producing a foam (foamability) followed the opposite trend. The surface tension and interfacial dilatational rheological properties were affected by the addition of SiO2 nanoparticles. When 0.05 wt % SiO2 was added to the solution of SDS, the system's dilatational elasticity increased significantly, but not the dilatational viscosity. The sweep efficiency to dead end was very small, and the SiO2/SDS foam could displace more residual oil in the dead end than that in the SDS foam. The differential pressure could increase to 0.58 MPa when SDS foam was injected, but for the SiO2/SDS foam it could increase to 1.7 MPa. The SiO2/SDS foam exhibited better profile control performance than that of the SDS foam. When subsequent water was injected for 3.5 pore volumes, the flow rate of the high‐permeability sand pack could still be maintained at 1.0 mL min−1, which suggested that the SiO2/SDS foam had a better resistance to water flushing. Additionally, the foam volume should also be considered, especially for a SiO2 concentration of >1.5 wt %. SiO2/SDS foam can reduce the residual oil saturation clearly, and the enhanced oil recovery and final oil recovery can reach 36.90 and 69.57 %, respectively.

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Experimental and Numerical Simulation Studies of Different Modes of CO2 Injection in Fractured Carbonate Cores

Cited by 11 publications

References 13 publications

Optimization of CO2 WAG Processes in a Selected Carbonate Reservoir-An Experimental Approach

Optimization of CO2 WAG Processes in a Selected Carbonate Reservoir-An Experimental Approach

The effect of natural fractures on CO₂storage performance and oil recovery from CO₂and WAG injection in an Appalachian basin reservoir

Nanoparticle‐Stabilized Foam for Mobility Control in Enhanced Oil Recovery

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Experimental and Numerical Simulation Studies of Different Modes of CO2 Injection in Fractured Carbonate Cores

Cited by 11 publications

References 13 publications

Optimization of CO2 WAG Processes in a Selected Carbonate Reservoir-An Experimental Approach

Optimization of CO2 WAG Processes in a Selected Carbonate Reservoir-An Experimental Approach

The effect of natural fractures on CO2storage performance and oil recovery from CO2and WAG injection in an Appalachian basin reservoir

Nanoparticle‐Stabilized Foam for Mobility Control in Enhanced Oil Recovery

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The effect of natural fractures on CO₂storage performance and oil recovery from CO₂and WAG injection in an Appalachian basin reservoir