Surfactant-Based Treatment Fluids Mitigate Fracture Hits in Parent Wells
The complete paper presents a strategy for selecting a surfactant/solvent package for parent wells. Oil recovery and associated water saturation in the microfluidic-based device, with or without surfactant, are quantified and reveal that the oil recovery is enhanced with surfactant.
Preloading parent wells with surfactant-based treatment fluids for fracture-hit mitigation has been applied extensively in liquids-rich shale plays. However, why specific chemical packages help improve parent-well production remains unclear. The complete paper presents a strategy for selecting a surfactant/solvent package for parent wells. Oil recovery and associated water saturation in the microfluidic-based device, with or without surfactant, are quantified and reveal that the oil recovery is enhanced with surfactant. Water saturation in the parent well could be reduced, thereby mitigating water blocks from primary fracturing-fluid invasion from child wells.
During child-well completions in development of liquids-rich shale plays, fracturing fluids and proppants are likely to infiltrate the parent-well fracture network and wellbore through hydraulically connected flow paths. Parent wells, after producing for a period, serve as a pressure sink that attracts new fracture propagation and extension initiated from a child-well fracture. As a result, parent wells could lose production because of a potentially plugged fracture network filled with new sand from child wells. The production of child wells also could suffer because of unwanted fracture extension and loss of reservoir pressure.
The technique of reloading parent wells with surfactant-based treatment fluids for fracture-hit mitigation has been applied recently in environments where intense infill drilling and tighter well spacings are prerequisites for improved production and economic return. Preloads can provide a significant temporary increase in fracture network pressure if performed properly and are most effective with a surfactant and solvent package. However, why specific chemical packages help improve the parent-well production remains unclear, although the notion of capillary force resistance reduction for further treatment-fluid leakoff into fractures and rock-wettability alteration by surfactant has been proposed in the literature. Recent residual surfactant analysis in produced water from both parent and child wells indicates that hydraulic communication exists after fracture hits; additionally, field trials in the Wolfcamp suggest that the same surfactant package in primary fracture fluids in child wells can migrate gradually to parent wells, potentially activating various secondary oil-recovery mechanisms.
This study provides an evidence-based strategy for selecting a surfactant solvent package by a commercial microfluidic device (MD) and spontaneous imbibition (SpI), thus eliminating unnecessary testing that does not involve formation rocks. Surfactant optimization permits further leakoff into secondary fractures, potentially increasing fracture network pressure. Surfactant migration from child wells presents a unique enhanced-oil-recovery mechanism for parent wells. Field trials in different liquids-rich shale plays, including the Wolfcamp, appear to support this finding.
Results and Discussion
The following procedure was used to perform the invasion-flowback cycles on the MD:
- The crude oil was first injected to fill the MD. Because the MD’s surface was neutrally wet, caution was taken to ensure that no air was trapped inside the porous matrix.
- A 2% potassium chloride (KCl) brine or surfactant solution was then injected into the MD at a constant pressure of 2.8 psi from the inlet of the channel for 170 PV (pore volume) when the irreducible oil saturation was obtained. This step was used to simulate the first invasion of the fracturing fluid.
- The crude oil was reinjected from the outlet of the channel at the same water head as the invasion of the fracturing fluids. This step was used to simulate the first flowback.
- The 2% KCl brine or surfactant solution was reinjected into the MD fracture and matrix at a constant pressure of 1.4 psi from the inlet of the channel for 170 PV. This step was used to mimic the second invasion of the fracturing fluid (i.e., representing the invasion of fracturing fluids from a new infill well into the old well).
- The crude oil was reinjected from the outlet of the channel at the same water head as the second invasion of the fracturing fluids to mimic the production of the old well after the second invasion. The results of the water saturation was used to assess the damage by the fracturing fluid from the new infill well.
Test results revealed that, without surfactant in fracture fluids in child wells, water saturations in the MD after the second flowback were higher than those after the first invasion/flowback cycle, suggesting that the second invasionflowback cycle could indeed damage the matrix and reduce the relative permeability to oil. On the other hand, surfactant improved the displacement efficiencies in the matrix. Surfactant used in the second invasion/flowback cycle reduced the damage incurred by the first invasion/flowback cycle from 25 to 13%. The benefit of surfactant has been observed from field results from the Wolfcamp shale, where the estimated ultimate recoveries (EURs) of wells diminished by surfactant-stimulated offset wells were higher than those diminished by nonsurfactant-stimulated offset wells. After a fracture hit from a child well fractured with surfactant, the parent well’s production has been observed to increase rather than diminish, resulting in a higher EUR.
SpI testing considers a completion strategy of rock soaked with fracture fluids. During fracturing, a wait time of hours or days may occur before each single fracturing stage is completed. After fracturing, a typical well shut-in time of several days is not uncommon. This additional soak time allows fracture fluids to imbibe spontaneously into the rock and move deeper into the reservoir. Similarly, when a parent well is pressurized with surfactant containing fracture fluids, it is crucial to know how much farther fracture fluids have spread into the existing fracture network, increasing the likelihood of raising pressure at the farthest fracture tips, which are more likely to encounter incoming fracture pressure waves or direct fracture hits from nearby child wells. SpI is a means of probing these phenomena by comparing oil recoveries, particularly fluid-penetration magnitudes, with and without surfactant in fracture fluids.
SpI uses presaturated or preserved sidewall core plugs and typically is performed in Amott cells at reservoir temperature (Fig. 1). Oil-saturated core plugs are placed vertically or horizontally inside a vessel prefilled with fracturing fluids containing surfactant. The right surfactant lowers the capillary pressure (determined through interfacial surface tension) moderately, alters the rock wettability from oil-wet to water-wet as measured by contact angle, and drives fracturing fluids into core plugs gradually. Oil is produced from all sides of the core plug and is collected on the top of the vessel, where a graduated cylinder measures the oil volume. The produced oil volume is plotted over 5 days, and each surfactant’s performance is quantified. More importantly, computed tomography (CT) imaging techniques are used to scan core plugs during testing to gain insight into water penetration into core centers. The differences between average initial and final CT numbers are calculated to estimate penetration magnitude.
When both oil-recovery and water-penetration magnitudes without and with 1 gal/Mgal surfactant in 4% KCl at reservoir temperature were compared, water alone yielded 8.0% oil recovery vs. 10.3% with surfactant. Smaller differences in oil recovery were attributed to carbonate-rich rock and consequent surfactant adsorption, reducing the number of surfactant molecules available to mobilize the oil. However, surfactant appeared to penetrate the cores much farther than water, with a 6 vs. 2 penetration magnitude within a specified time period, demonstrating its high potential to contact additional surface area and possibly more secondary fractures.
Adding surfactant to treatment fluids to enhance fluid penetration into secondary fractures when pressurizing parent wells is crucial. To select a surfactant properly, both MD and SpI testing are run to gain insights into fluid interaction and penetration magnitude. Such laboratory methods allow additional understanding of field operational practices and production results.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197097, “Fracture-Hit Mitigation Through Surfactant-Based Treatment Fluids in Parent Wells,” by Liang Xu, James Ogle, and Todd Collier, SPE, Halliburton, prepared for the 2019 SPE Liquids-Rich Basins Conference—North America, Odessa, Texas, 11–12 September. The paper has not been peer reviewed.