The key challenge in unconventional gas plays covering vast geographical areas is locating the regions in the reservoir with the highest combination of reservoir and completions quality. This allows operators to evaluate not only the richness of their resource but also the ability of the reservoir to produce hydrocarbons in commercial quantities. This paper discusses hydraulic fracturing designs targeting tight gas in horizontal wells drilled in the Apollonia tight chalk formation in the Abu-Gharadig basin, Western Desert, Egypt through the integration of laboratory, geological, petrophysical, geomechanical, fracture simulation, and diagnostic fracture injection test (DFIT) analysis. Laboratory testing, which included scanning electron microscopy (SEM) and X-ray diffraction (XRD), was conducted to determine mineralogy and potential damage mechanisms. Fracturing fluid chemistry was tested and optimized using core plugs from representative reservoir rock (fracture conductivity, fracturing fluid compatibility, surfactant type, fracture regain permeability, and scale tendency). Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple-combo full-wave sonic logs and core samples were combined with geological parameters and potential treating schedules to develop sophisticated fracture simulation models. These models were then refined with in-situ reservoir data obtained from DFIT analyses to derive the final fracturing treatment design. The stimulation model was built using a three-dimensional (3D) geological model with multidisciplinary inputs, including formation properties, in-situ stresses, natural fractures, and completion parameters (i.e., well orientation, stage and perforation cluster spacing, fluid volume, viscosity, and proppant volume, size, and ramping schedule). The integration of all available data resulted in an optimized fracture design that helped reduce both cost and formation damage, thus improving flowback, long-term productivity, and profitability from this tight formation.
Large amounts of aqueous‐based fluids used in hydraulic fracturing of tight formations are not fully recovered immediately after treatment, resulting in increased water saturation, water blockage, clay swelling, reduced relative permeability, and long‐lasting formation damage that impedes production. To enhance flowback fluid recovery, nano‐emulsion based flowback aids were developed for oil‐bearing sandstone and carbonate formations. The flowback aids were formulated using a blend of high‐temperature stable ester‐based solvents, alcohols, and surfactants to form optically clear nano‐emulsions. All the developed flowback aids demonstrated low surface tension (22–30 mN/m) and interfacial tension (<6 mN/m), which is necessary for reducing capillary pressure. The particle size of the nano‐emulsions was found to be 5–15 nm. The flowback aids were able to prevent the formation of the emulsion with crude oil. It has been found that nano‐emulsions formulated using non‐ionic and anionic surfactants worked better for sandstone, whereas non‐ionic and cationic surfactant‐based formulations worked better for carbonate. These formulations not only provide quick aqueous fluid displacement in column tests but also greatly enhance the rate of oil flow in core flow experiments conducted with broken slickwater fracturing fluids. It was determined that in the absence of a flowback aid, the regained permeability was around 40%, whereas with flowback aids it was increased to 65%–75%. The paper demonstrates the effectiveness of flowback enhancers to quickly recover the injected aqueous fracturing fluid, thereby reducing water saturation, which in turn enhances productivity, and shows the benefit of applying chemistry for low permeability oil reservoirs.
Concerns by regulatory authorities regarding cumulative effects or reservoir adsorption of hydraulic fracturing fluid have increased, with an overall focus on fracturing fluid additives. Operators do not always obtain adequate core materials to fully evaluate additive effectiveness or to belay regulatory concerns regarding the cumulative interaction effects of fracturing fluids with the formation. Without these materials, operators are often required to representatively sample post-fracturing fluids and hypothesize the volumes of additives remaining in the formation, material balancing on a qualitative post-frac testing basis, which can be highly unrepresentative.This paper presents the results from a study from a prospective shale gas interval where formation materials or cuttings were sampled across a representative producing interval, offsetting the proposed multistage fracturing treatment. The processes of how the fluid formulation was optimized using established qualitative procedures for clay sensitivity (i.e., capillary suction testing) and then further evaluated for surfactant requirements (e.g., tensiometry) are demonstrated. Following final fluid formulation, interactive testing with reservoir materials was performed, providing insight into the level of fluid and additive interaction that might result between the formation and the proposed fluid. This study provides practical approaches to testing and defines benefits and limitations of employing these approaches to belay potential concerns evolving related to fracturing fluid interaction within reservoirs and their cumulative effects.
Water used in fracturing fluids must typically be treated to reduce the concentration of aerobic acid producing bacteria and, more importantly, anaerobic sulfate-reducing bacteria that can cause a well to go sour. Typically chemical biocides are used to provide the disinfection. However, biocides can interfere with chemical additives in the fracturing fluid and cause equipment damage. Additionally, biocides are toxic chemicals that must be handled carefully and registered with federal and local environmental protection agencies. Some areas strictly regulate which chemicals can be persistent in treatment liquids flowed back from wells. To address the issues associated with the chemical biocides, disinfection via ultraviolet (UV) light has been introduced into hydraulic fracturing operations. The use of UV light can greatly reduce the volume of chemical biocides used and also decreases the biocide concentration in liquids flowed back from a treated well. Early UV equipment treated water as it was placed into storage tanks on the fracturing location. This allowed for possible recontamination from biofilms present in the storage tanks. A new trailer has been placed into operation that treats the water on the fly as it flows from the storage tanks to the fracturing blender. The performance of the UV light equipment has also been improved. The disinfection effectiveness of the UV light system has been verified on site during fracturing treatments using the serial dilution method to measure aerobic and sulfate-reducing bacteria levels, both before and after the UV treatment. The test results prove that bacteria concentration in the fracturing water can be significantly reduced, sometimes to undetectable levels, by UV treatment.
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