Hydraulic fracturing has remained a fundamental technique for stimulation of oil and gas reservoirs for enhanced or economic recovery of hydrocarbons from tight formations for more than 60 years. Transporting proppant downhole without any interruption and then to obtain maximum recovery of fracturing fluids are two important criteria for successful hydraulic fracturing. To achieve such objectives, the fracturing fluid should demonstrate good viscosity and complete cleanup of gelling agents. Because wells are exploited at both shallow and great depths in environments of moderate to very high temperatures and pressures, fracturing fluid selection is fundamental. Fracturing fluids prepared by crosslinking guar, guar derivatives, and other naturally occurring polymers with borate or metal crosslinkers often exhibit instability at very high temperatures. The primary reason for instability of the fracturing fluid is because strength of the bonds between the polymer chain and crosslinker decreases sharply in addition to breakdown of the glycosidic bonds between monomer units of the polymer chain beyond 375°F. Additionally, metal crosslinked bonds are prone to shear degradation, creating doubt for a successful stimulation treatment in high-temperature extended-reach wells. To address these issues, a synthetic gelling-agent-based fracturing fluid that can work at temperatures greater than 400°F was developed. The gelling agent is a terpolymer, which can be crosslinked with a zirconium-based crosslinker. This paper discusses evaluation and performance of an extreme temperature fracturing fluid. This fracturing fluid system has sufficient proppant carrying viscosity and provides efficient post-treatment cleanup using delayed oxidized breaker. Analysis of fluid viscosity stability and delayed oxidizing breaker usage is presented in addition to performance parameters such as regained permeability and fluid loss. The study illustrates performance of the synthetic gelling-agent-based fracturing fluid at temperatures ranging from 380 to 440°F.

The phenomenon of fines migrating through porous and permeable paths is well-known, as are the issues related to fines migration. During the life of a producing well, fines can migrate and reduce formation permeability by clogging pore throats of the mineral grains and reduce conductivity of proppant packs placed by hydraulic fracturing treatments, Frac Packs, or by gravel pack operations. Such fines migration can eventually lead to reductions in well production. The primary contributing factors that release fines are high fluid velocity, changes in salinity, wettability, pH, and rock failure. Use of a surface modifying agent (SMA), which can immobilize fines in place, helps minimize or mitigate fines migration. However, solvent-based SMAs are difficult to apply as a remedial treatment, and this limits their applicability. This paper discusses the use of an aqueous-based surface modifying agent (ASMA) that can be used to help mitigate fines migration. The ASMA is a conductivity enhancer that immobilizes fines by locking them in place as a result of its tacky surface. Because it is hydrophobic in nature, it resists water flow without hampering hydrocarbon flow.The ASMA can be pumped into formations having permeabilities greater than 100 md as a remedial treatment. It also can be coated onto proppants immediately before pumping them downhole.To demonstrate the efficiency of the ASMA, a number of laboratory experiments were conducted on sand packs consisting of a sand-fines mixture and proppant, which closely simulated actual downhole conditions. Control tests (without the ASMA treatment), pre-coating of proppant pack tests, and remedial treatment tests were performed at different flow rates to study the effect of fines migration along with the efficiency of the ASMA as a technique to mitigate the issue.

Hydraulic fracturing has remained a fundamental technique for stimulation of oil and gas reservoirs for enhanced or economic recovery of hydrocarbons from tight formations. Transporting proppant downhole without any interruption and maximum recovery of fracturing fluids are two important criteria for successful hydraulic fracturing. To achieve such objectives, the fracturing fluid should demonstrate good viscosity and complete cleanup of gelling agents. As wells are exploited at greater depths in environments of higher temperature and pressure, fracturing fluid selection is key. Fracturing fluids prepared by crosslinking guar, guar derivatives, and other naturally occurring polymers with borate or metal crosslinkers often exhibit instability at very high temperatures. The key reason for instability of the fracturing fluid is because strength of the bonds between the polymer chain and crosslinker decreases sharply in addition to breakdown of the glycosidic bonds between monomer units of the polymer chain beyond 375°F. Additionally, metal crosslinked bonds are prone to shear degradation, creating doubt for a successful job in high temperature long reach wells.To address these issues, a synthetic gelling-agent-based fracturing fluid that can work at temperatures greater than 400°F was developed. The gelling agent is a terpolymer, which can be crosslinked with a zirconium-based crosslinker. This paper discusses evaluation and performance of an extreme temperature fracturing fluid. This fracturing fluid system has sufficient proppant carrying viscosity and provides efficient cleanup using delayed oxidized breaker. Analysis of fluid stability and delayed oxidizing breaker usage is presented in addition to performance parameters, such as regained permeability and fluid loss. The study illustrates performance of the synthetic gelling-agent-based fracturing fluid at temperatures ranging from 380 to 420°F.

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Operators can face multiple challenges during various completion and workover operations, one of which is fluid loss into the formation. Ensuring minimal fluid loss is of the utmost importance, particularly in highly permeable zones as expensive completion fluids are pushed into the porosity of the formations, usually resulting in perm damage.Available techniques for controlling fluid loss primarily include mechanical or chemical options. Mechanical techniques, although widely used successfully, have drawbacks, such as plug failure at high-pressure/high-temperature HP/HT conditions, requiring an additional trip. With industry needs for lower costs and better fluid-loss control (FLC) systems, many chemical systems have been developed to help overcome such problems associated with mechanical systems. These chemical systems include linear polymers, CaCO 3 ϩ polymer gel, sized salt ϩ polymer gel, and oil soluble resins. Although effective, these are either expensive or can leave residue behind as a result of incomplete break, causing formation damage. Crosslinked hydroxyethyl cellulose (CLHEC) based gel plugs can provide effective FLC and are used post-perforating in addition to before and after gravel pack operations. They consist of highly viscous, solids-free crosslinked gel, prepared in medium and low density brines. CLHEC based gel plugs form a filter cake, which can be removed by internal and/or external breakers as a means for cleanup.To obtain a desired break time, understanding the behavior of the breaker under bottomhole temperature (BHT) conditions is vital. This study focuses on investigating various internal and external breaker actions at temperatures ranging between 120 and 270°F. The laboratory data provided in this paper demonstrates the performance of various breakers, such as oxidizers, delayed-release acids, and selfdegrading particulate systems in low and medium density brines. The information provided in this study offers a guideline for an appropriate breaker selection in hydroxyethyl cellulose (HEC) based gel plugs.