Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives

Liang, Tianbo; Longoria, Rafael A.; Lu, Jun; Nguyen, Quoc P.; DiCarlo, David A.

doi:10.2118/175101-ms

Cited by 8 publications

(5 citation statements)

References 30 publications

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“…However, gel residuals can block fractures and pores at fracture faces, thus impeding the flow of hydrocarbon [23][24][25]. Besides gel residuals, water can imbibe rock matrix and cause phase trapping, which reduces hydrocarbon permeability due to multiphase flow [26][27][28][29]. Formation damage due to drilling and fracturing fluids is likely different in the low-permeability sandstone with well-developed natural fractures.…”

Section: Introductionmentioning

confidence: 99%

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Liang

Yao

et al. 2017

Geofluids

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Drilling and fracturing fluids can interact with reservoir rock and cause formation damage that impedes hydrocarbon production. Tight sandstone reservoir with well-developed natural fractures has a complex pore structure where pores and pore throats have a wide range of diameters; formation damage in such type of reservoir can be complicated and severe. Reservoir rock samples with a wide range of fracture widths are tested through a multistep coreflood platform, where formation damage caused by the drilling and/or fracturing fluid is quantitatively evaluated and systematically studied. To further mitigate this damage, an acidic treating fluid is screened and evaluated using the same coreflood platform. Experimental results indicate that the drilling fluid causes the major damage, and the chosen treating fluid can enhance rock permeability both effectively and efficiently at least at the room temperature with the overburden pressure.

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Section: Introductionmentioning

confidence: 99%

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Liang

Yao

et al. 2017

Geofluids

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“…Ibrahim and Nasr-El-Din have recently even conducted similar experiments in tight sandstones (0.23 mD) and in Marcellus shales (3.16 nD) to show similar behavior of regained permeability to gas, as discussed above. Similarly, for an oil/water system in a low-permeable water-wet rock (3–10 mD), the studies performed by Liang and co-workers − have also demonstrated the migration of water-block phenomenon using high-resolution CT-scans. Liang et al even concluded that for the case of an oil-wet rock, the water-block at the fracture–matrix interface does not exist but rather the end-point relative permeability for oil is subdued at the residual saturation of water due to the capillary entrapment of water in the bulk of the pore space and not along the walls of the pore space.…”

Section: Introductionmentioning

confidence: 92%

Roles of Surfactants during Soaking and Post Leak-Off Production Stages of Hydraulic Fracturing Operation in Tight Oil-Wet Rocks

Tangirala

Sheng

2019

Energy Fuels

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Many experimental studies have been conducted in the recent past to assess the inclusion of different types of surfactant in a frac fluid in hydraulic fracturing of low-permeable formations. These lab studies either corresponded to spontaneous imbibition testing using Amott cells or dynamic core-flooding tests to assess the hydrocarbon permeability after the invasion of the frac fluid. Both these tests have been considered independently by different authors but have not been analyzed as one holistic approach to assess the oil recovery potential of a surfactant. It is prudent to understand the superiority of the specific interfacial mechanism of the surfactant that correlates to the best-case scenario of oil recovery by considering both the tests that lead to leak-off and follow the leak-off of frac fluid into the matrix. In this experimental study, two tests related to soaking and production processes are conducted simultaneously using surfactants with different interfacial properties of interfacial tension (IFT) reduction and wettability alteration for both low-permeable and high permeable core samples. The oil recovery from soaking tests are compared to the oil productivity of dynamic production tests assessed from the calculated parameters of effective permeability of oil recovered and flowback efficiencies. The results obtained in this study indicate that the surfactant which simultaneously reduces the IFT and alters the wettability of the low-permeable rock from oil-wet to water-wet is not conducive for oil productivity during dynamic production process despite it being very effective in oil recovery during the soaking process. Rather, a neutral-wetting surfactant seems to produce optimal results when the whole process of oil recovery from hydraulic fracturing is considered. The trend in the results for flowback efficiency and effective permeability of oil post leak-off observed in this study across the high and low-permeable rocks could be extended to unconventional shale rocks to safely infer that with regards to oil productivity, it would be beneficial to avoid any leak-off of the surfactant fluid, which showcases both IFT reduction and wettability alteration. The insights provided in this study motivate the reader to analyze beyond the common experimental methods of static imbibition testing in labs to embrace the methods that consider a complete hydraulic fracturing process for assessing enhanced oil recovery of low-permeable formations.

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“…The large hydraulic pressure difference between the shale matrix and the fracture primarily results in fluid seepage inside the matrix and the recovered fluid is mostly formation water . Furthermore, spontaneous imbibition due to capillary pressure − and the large osmotic potential due to the high-salinity contrast between the fracturing fluid and connate water also contributes to substantial loss of injected fluid in the reservoir.…”

Section: Evolution Of Shale Flow Channels Due To Reactive Transportmentioning

confidence: 99%

“…The component of the shale porosity present in the organic matter is assumed to be oil-wet, while interdetrital porosity tends to be more water-wet. The lost fluid has the tendency to change the surface wettability of the shale pores from oil-wet to water-wet. ,, The water phase in the micropores can become trapped due to the change in capillary pressures , or as a result of forming a connected hydrocarbon-phase ganglia that leaves the water-phase trapped near the water-wet pore surface (Figure ); this ultimately reduces the hydrocarbon recovery. , Multiple processes including heat and surfactant treatment have been proposed to mitigate this damage and enhance hydrocarbon recovery.…”

Section: Evolution Of Shale Flow Channels Due To Reactive Transportmentioning

confidence: 99%

A Critical Review of the Physicochemical Impacts of Water Chemistry on Shale in Hydraulic Fracturing Systems

Khan

Spielman-Sun

Jew

et al. 2021

Environ. Sci. Technol.

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Hydraulic fracturing of unconventional hydrocarbon resources involves the sequential injection of a high-pressure, particle-laden fluid with varying pH’s to make commercial production viable in low permeability rocks. This process both requires and produces extraordinary volumes of water. The water used for hydraulic fracturing is typically fresh, whereas “flowback” water is typically saline with a variety of additives which complicate safe disposal. As production operations continue to expand, there is an increasing interest in treating and reusing this high-salinity produced water for further fracturing. Here we review the relevant transport and geochemical properties of shales, and critically analyze the impact of water chemistry (including produced water) on these properties. We discuss five major geochemical mechanisms that are prominently involved in the temporal and spatial evolution of fractures during the stimulation and production phase: shale softening, mineral dissolution, mineral precipitation, fines migration, and wettability alteration. A higher salinity fluid creates both benefits and complications in controlling these mechanisms. For example, higher salinity fluid inhibits clay dispersion, but simultaneously requires more additives to achieve appropriate viscosity for proppant emplacement. In total this review highlights the nuances of enhanced hydrogeochemical shale stimulation in relation to the choice of fracturing fluid chemistry.

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Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives

Cited by 8 publications

References 30 publications

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Roles of Surfactants during Soaking and Post Leak-Off Production Stages of Hydraulic Fracturing Operation in Tight Oil-Wet Rocks

A Critical Review of the Physicochemical Impacts of Water Chemistry on Shale in Hydraulic Fracturing Systems

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