Adsorption Role in Shale Gas Recovery and the Feasibility of CO2 in Shale Enhanced Gas Recovery: A Study on Shale Gas from Saudi Arabia

Eliebid, Mohammed; Mahmoud, Mohamed; Elkatatny, Salaheldin; Abouelresh, Mohamed O.; Shawabkeh, Reyad

doi:10.2118/187667-ms

Cited by 18 publications

(8 citation statements)

References 28 publications

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“…This review will not delve into efforts toward enhanced gas recovery from unconventional gas reservoirs that produce little, if any, oil, − such as the fields in the Barnett, the Qusaiba in Saudi Arabia, and the Longmaxi in China. ,− Mechanical approaches to improving oil recovery such as improving the fracturing process, − optimizing wellbore geometry or spacing and stability, , improving perforation strategies, controlling proppant placement, modeling fracture patterns, developing choke management strategies, improving postfracturing operations and fluid cleanup, , refracturing, , production data analysis, and improving well monitoring technology, are also beyond the scope of this review.…”

Section: Introduction To Enhanced Oil Recovery In Unconventional Liqu...mentioning

confidence: 99%

A Literature Review of CO₂, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

et al. 2020

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Primary oil recovery from fractured unconventional formations, such as shale or tight sands, is typically less than 10%. The development of an economically viable enhanced oil recovery (EOR) technique applicable to unconventional liquid reservoirs (ULRs) would lead to tremendous increases in domestic oil production. Although injection techniques such as waterflooding and CO2 EOR have proven profitable in conventional formations for decades, EOR in ULRs presents a far more difficult challenge. The extremely low permeability and mixed wettability of unconventional formations are the foremost obstacles to success. Because of the challenges associated with water-based EOR techniques (a.k.a., chemical EOR) in shale, several nonaqueous injection fluids have been considered, including CO2, natural gas, and (to a lesser degree) nitrogen. All these fluids have significantly lower viscosities than water, allowing them to more easily penetrate shale nanopores. Unlike water, they also each possess some degree of miscibility with oil, which enables the gas to extract oil through a combination of mechanisms. Based on laboratory-scale experimentation, CO2 and rich natural gas (methane-rich natural gas containing high concentrations of ethane, propane, and butane) are the most promising EOR fluids. The interpretation of results from field tests in the Bakken and Eagle Ford formations have been complicated by interference of frac-hits or well-bashing caused by hydraulic fracturing at nearby wells. In this review we cover mechanisms, laboratory experiments, numerical simulations, and field tests involving high-pressure CO2, natural gas, ethane, nitrogen, and water.

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Section: Introduction To Enhanced Oil Recovery In Unconventional Liqu...mentioning

confidence: 99%

A Literature Review of CO₂, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

et al. 2020

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“…[4] Both of these cases are far removed from the wide pore size distributions, complex wettabilities, unpredictable pore geometries, and complex fluid compositions in shale. Even so, the ease with which longstanding, simplistic adsorption theories, such as Langmuir and BET, can be fit to shale adsorption isotherms has led to their widespread incorporation into shale characterization [9], [3], [10], [11] and reservoir modeling. [12]- [14] However, we prove here that despite the fact that the shapes of shale isotherms are often similar to IUPAC isotherms, the underlying physics are generally not the same.…”

Section: Introductionmentioning

confidence: 99%

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

et al. 2020

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The abundance of nanopores (pores with diameters between 2 and 100 nm) in shale and ultra-tight reservoirs precludes the use of common pressure-volume-temperature (PVT) analyses on reservoir fluids. The small sizes of the pores cause capillary condensation, which is a nanoconfinement-induced gas-to-liquid phase change, that can occur at pressures more than 50% below the corresponding bulk phase change of the fluid due to strong fluid-pore wall interactions. We quantify this phenomenon by measuring propane isotherms both in a synthetic nanoporous medium and a core from a shale gas reservoir. Comparison of our results in the two porous media indicates the occurrence of capillary condensation in shale rock. At the same time, we observe capillary condensation hysteresis for shale, in which the density of the fluid is significantly lighter during desorption than adsorption. This indicates structural changes to the rock matrix caused by the phase behavior of the confined fluid. We use scanning electron microscopy to corroborate our findings. These results have significant implications for determining the PVT properties, porosity, and permeability of shale and ultra-tight formations for use in reservoir modeling and production estimations.

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“…19 The gas−rock system's temperature is a major adsorption phenomenon controlling factor along with the free gas pressure; increasing pressure increased the adsorption capacity. 20,21 In addition, the adsorbed gas maximum volume is determined by the adsorption isotherm that represents the volume of gas adsorbed at equilibrium on the surface at constant temperature. 22 Adsorption isotherms are essential to model the gas flow and transport in porous media.…”

Section: Introductionmentioning

confidence: 99%

Impact of Surfactant on the Retention of CO₂ and Methane in Carbonate Reservoirs

et al. 2018

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Enhanced gas recovery methods such as foamed CO 2 are recommended for depleted gas reservoirs. Viscoelastic surfactant (VES) is a form of a surfactant used for forming CO 2 foam. In this study, the impact of VES on CH 4 and CO 2 retention and adsorption in calcite rock samples was studied. Crushed samples of Indiana limestone rocks of average particle size (125−250 μm) were used in the static adsorption experiments. To study the effect of VES on CH 4 and CO 2 adsorption, 50% of the crushed samples were conditioned in a solution of NaCl of 0.1 vol % surfactant. X-ray diffraction shows that the rock samples are 99.99% calcite and traces of quartz. The gas adsorption experiments were performed at different temperatures; namely; 50, 100, and 150 °C and at a pressure of 45 bar. At 50 °C, the plain calcite samples adsorbed more CH 4 and CO 2 compared to that treated with VES. However, at 100 and 150 °C, the plain sample adsorbed much less CH 4 and CO 2 than the treated sample. This means that at higher temperatures (100 and 150 °C) VES enhanced the adsorption of both CO 2 and CH 4 on the rock surface. Thermodynamic investigations showed that the process of gas adsorption in the plain samples was exothermic with ΔH ads of −13.5 and −16.7 kJ/mol for CO 2 and CH 4 , respectively, and at 50 °C the adsorption was spontaneous with ΔG ads of −0.425 for CH 4 and −2.599 for CO 2 . In contrast, at higher temperatures (100 and 150 °C), the adsorption of CO 2 and CH 4 on surfactant treated sample was spontaneous and endothermic with corresponding ΔH ads of 36.2 and 60.1 kJ/mol and ΔG ads of −4.701 and −0.581 for CO 2 and CH 4 , respectively. The adsorption of CO 2 was three times that of CH 4 because of the high affinity of calcite to CO 2 . Because of the multilayer adsorption on both samples, Freundlich isotherm was found to be the best model that fits the experimental data of calcite with both CO 2 and CH 4 at different temperatures. Dynamic adsorption experiments were carried out using gas coreflooding system with the same calcite cores used in the static adsorption experiments. The results of this study showed that carbonate rock samples conditioned in the surfactant solution have great adsorption potential for CO 2 and are excellent candidates for CO 2 sequestration. However, surfactant promoted high CH 4 adsorption at 100 and 150 °C, and this will reduce the natural gas recovery. In contrast, using viscoelastic surfactant at low-temperature reservoirs (50 °C) reduced CH 4 adsorption by blocking the active adsorption sites in the carbonate rock samples, and this will increase the gas recovery.

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Adsorption Role in Shale Gas Recovery and the Feasibility of CO2 in Shale Enhanced Gas Recovery: A Study on Shale Gas from Saudi Arabia

Cited by 18 publications

References 28 publications

A Literature Review of CO₂, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

A Literature Review of CO₂, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

Impact of Surfactant on the Retention of CO₂ and Methane in Carbonate Reservoirs

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Adsorption Role in Shale Gas Recovery and the Feasibility of CO2 in Shale Enhanced Gas Recovery: A Study on Shale Gas from Saudi Arabia

Cited by 18 publications

References 28 publications

A Literature Review of CO2, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

A Literature Review of CO2, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

Impact of Surfactant on the Retention of CO2 and Methane in Carbonate Reservoirs

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A Literature Review of CO₂, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

A Literature Review of CO₂, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

Impact of Surfactant on the Retention of CO₂ and Methane in Carbonate Reservoirs