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Summary In this paper, we investigate the change in oil effective permeability () caused by fracturing‐fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF‐leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut‐in duration, and plug properties on regained permeability values. We found that adding appropriate surfactants in FF not only significantly reduces impairment caused by leakoff, but also improves compared with the original baseline for a low‐permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced by only 10%. The observed improvement in regained is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact‐angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces by 5 to 10%, and this range only increases slightly by increasing the shut‐in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original before the leakoff process. We observed 28.52 and 64.61% increase in after 3‐ and 14‐day shut‐in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases . Under such conditions, extending the shut‐in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.
In tight reservoirs, the invasion of water-based fracturing fluids into the rock matrix may reduce hydrocarbon relative permeability and consequently oil production rate. This paper aims at investigating the change in oil effective-permeability () during the flowback processes after hydraulic fracturing operations. We perform a series of core flooding tests on core plugs collected from Midale tight carbonate reservoir to simulate fracturing fluid leak-off and flowback processes. First, we clean, saturate the plugs with reservoir brine and filtered oil, then age them in oil for 14 days under reservoir conditions (P 2500 psig and T 60 C) to restore reservoir conditions and define baseline.
Low recovery of fracturing water is mainly due to fracturing fluid leak-off into formation and trapping of water in matrix. In our previous studies (
To answer this question, we developed and applied a comprehensive laboratory protocol on a core plug from the Montney Formation to simulate leak-off and flowback processes consistently under reservoir pressure and different values of initial water saturation (Swi). A cationic surfactant additive with hydrophilic-hydrophobic balance (HLB) of between 13 and 15 and solvent concentrations of 20 vol% was mixed with water to generate a microemulsion (ME) solution. To complement the core flooding tests, we (1) conducted bulk phase experiments using the ME solution and oil to study fluid-fluid interactions; (2) evaluated the possibility of pore plugging by comparing pore-throat size distribution of the core plug and size distribution of the particles formed in the ME solution; and (3) investigated the effects of Swi on effective oil permeability (Keff,o) after the flowback process.
The results of leak-off and flowback tests using tap water as the base case showe that Keff,o after flowback is lower than that before the leak-off, mainly due to water blockage. However, results of the tests using the ME solution show that Keff,o after flowback is greater than Keff,o before leak-off. This observation suggests that the leaked-off ME solution enhances regained oil relative permeability during flowback by 1) reducing phase trapping and water blockage, and 2) reducing residual water saturation. Investigation the effect of Swi shows that if the core plug is in a state of sub-irreducible water saturation, additional water blockage happens fluid leak-off that reduces efficiency of the ME solution in decreasing water blockage. The mean size of micelles formed by mixing the ME solution with water is around 10-20 nm. The MICP profile of the core sample shows that around 95% of pore throats are bigger than micelle size, suggesting low chance of blocking the pore throats by the ME.
Abstract Low recovery of fracturing water is partly due to fracturing fluid leak-off into formation and water trapping in matrix. In our previous studies (Soleiman Asl et al. 2019 and Yuan et al. 2019), we showed that using surfactant solutions in fracturing fluid can significantly enhance imbibition oil recovery. However, there is one critical question remained unanswered: What are the consequences of these additives on well performance during flowback and post-flowback processes? Can they block the pore-throats of rock matrix and induce formation damage? To answer this question, we develop and apply a comprehensive laboratory protocol on a tight core plug to simulate leak-off and flowback processes under reservoir pressure, with and without initial water saturation (Swi). We evaluate the possibility of pore-throat blockage by comparing pore-throat size distribution of the core plug and size distribution of the particles formed in a microemulsion (ME) solution. We also investigate the effects of Swi on effective oil permeability (ko) after the flowback process. The results of leak-off and flowback tests using tap water as the base case shows that ko after flowback is lower than that before the leak-off, mainly due to phase trapping. However, results of the tests using the ME solution show that ko after flowback is greater than ko before leak-off. This observation suggests that the leak-off of ME solution enhances regained oil relative permeability during flowback by reducing phase trapping and water blockage. When Swi = 0, the blockage of leaked-off fluid reduces ko during the flowback process. The mean size of self-assembled structures (referred to as "particles" here) formed by mixing the ME solution with water is around 10-20 nm. The MICP profile of the core sample shows that around 95% of pore throats are bigger than the size of formed particles, suggesting low chance of pore-throat blockage by the suspended particles.
Various chemical additives have been recently proposed to enhance imbibition oil recovery from tight formations during the shut-in periods after hydraulic fracturing operations. Although, soaking experiments under laboratory conditions usually confirm the performance of such additives, their effects on oil regained permeability during the flowback process are poorly understood. This is mainly because measuring effective permeability of such low-permeability rocks is extremely challenging. We develop and apply a laboratory protocol mimicking leak-off, shut-in, and flowback processes to evaluate the effects of fracturing fluid additives on oil regained permeability. We modify the conventional coreflooding apparatus to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Adjusting the system total compressibility allows quickly achieving steady-state conditions at multiple ultra-low flowrates. We apply the proposed technique on two tight plugs with and without initial water saturation (Swi), and observe pressure humps during the flowback process that can be explained mathematically using the fractional-flow theory.
Spontaneous imbibition of the surfactant solution into the two oil-saturated plugs results in recovery of around 20% of the initial oil. For the plug with Swi = 0, koeff is reduced from around 3 µD to 1 µD, indicating the adverse effect of water trapping over the favorable effects of interfacial tension reduction and wettability alteration by the surfactant. For the plug with Swi = 0.21, koeff increases from 0.85 µD to 1.08 µD that can be explained by the combined effects of Swi reduction and wettability alteration, favorably shifting the oil relative permeability curve.