Technology Focus As gas development focuses more on tight and ultratight formations, the challenges to produce economically become diverse and more intense. One main challenge faced while fracturing a well is a high fracture gradient. This can be caused by near-wellbore tortuosity, drill-in-fluid-induced damage, high build-up of filter cake, or far-field tectonics and stresses. Formations with high fracture gradients result in high breakdown pressure and frequently need very high treating pressure to fracture the interval effectively. This may cause problems with completions integrity, and, depending on the intensity of treatments and pressures reached to propagate fractures, wells may no longer be accessible because of tubular deformation. Also, if fracturing stages are skipped while treating hard rocks because of completion limitations or some stages not being treated effectively and uniformly, production will fall far below expectations. If high breakdown pressure is caused by near-wellbore damage and tortuosity, attempts can be made to lower it with chemical treatments such as mutual solvents or acids or with the help of mechanical means such as hydra-jetting, reperforation, or slotting. When it comes to far-field high-stress regimes, the in-situ stress magnitude and fault stress regime should be well-known, evaluated, and calculated to prepare for high surface pumping horsepower. Advanced completion technology that can accommodate high-pressure/ high-temperature conditions is frequently required to perform the desired stimulation treatments. Before embarking on the remedial tasks, important steps include reviewing well location and placement, selecting a well trajectory in the more-prolific interval, completing with multistage fracturing assembly in better rocks, using nondamaging fluids for fracturing, and using optimal treatments with appropriate additives that will ensure high fracture conductivity. Parts of the fracture stages that do not contribute to production because of reservoir and geomechanical heterogeneity can be reduced by the use of an engineered approach in selecting the well location, the drilling direction and azimuth, completions placement, stage and cluster design, and fracturing techniques combining real-time monitoring and optimization. Otherwise, identifying the reason for low producers becomes difficult, whether they are the result of bad completions and poor fracturing design or reservoir development and quality. The use of appropriate fracturing fluid is also important to lessen high breakdown pressures, induce sufficient length and width to carry proppant in proppant fracture treatments, and reduce or eliminate formation damage and forming of scales. Scales formed because of fluid incompatibility can deteriorate fracture and formation conductivity dramatically and obstruct gas flow. The use of seawater as a base fracturing fluid is gaining momentum in the Middle East because it is a viable alternative to fresh water, thereby reducing stimulation cost. Seawater needs treatment such that precipitation while interacting with formation water does not become severe and impair production. Treatments such as phosphonate-based inhibitors are tested and considered to address the effect of hypersalinity and precipitation of barium, calcium, and strontium sulfate that reduce gas flow. Phosphonate-based scale inhibitors are introduced for high-temperature treatments. SPE 189896 Fracturing in a Tectonically Stressed Area Under Anomalously High Gradients by Dmitriy Abdrazakov, Schlumberger, et al. SPE 186313 First Application of Residue-Free Fluid System for High-Temperature Fracturing Treatment in Saudi Arabian Carbonate Formations by Zillur Rahim, Saudi Aramco, et al. SPE 186212 A Comparative Work Flow for Different Hydraulic-Fracturing Techniques in the Western Desert Oil Fields of Egypt by Ahmed Abd ElHamid, Qarun Petroleum Company, et al.
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Jan 1, 2022
Selina Reigl + 5
Open Access