Guar gum and its derivatives based fracturing fluids are most commonly used in hydraulic fracturing. For high temperature wells, guar-based fracturing fluids need to be formulated with higher polymer loading and at a high pH that leaves insoluble residue and tendency to form scales with divalent ions. In this paper, a systematic approach to field deploy a novel low-polymer loading, nondamaging acrylamide basedfracturing fluid system is presented. Thermally stable acrylamide-based polymer with reduced polymer loading of 30-40% less than guar-based fracturing fluid was considered to minimize formation damage concerns. For successful field deployment, a novel nondamaging fracturing fluid was evaluated in following sequence: chemical management and quality control, optimization of fracturing fluid formulations with field water, field mixing procedure, onsite QA/QC, friction analysis, leakoff analysis, data frac analysis and execution of main fracturing treatment. In both scenarios, batch mixing and on-the-fly mixing of linear gel were evaluated. The friction of crosslinked fluid was analyzed by using bottomhole gauge and fluid efficiency was evaluated during data frac analysis. This paper presents rheological studies at bottomhole static temperature (BHST) and cool down temperatures of selected well candidates that demonstrate superior thermal stability of this novel fracturing fluid. With polymer loading of 25 lb/1000 gal, the fluid viscosity stayed above 300 cP at 100 1/s shear rate for 2 hours at 290°F. The fracturing fluid formulations were optimized using both live and encapsulated breakers with high pressure and high temperature (HPHT) rheometer. Due to the fast hydration of the base polymer, the linear gel was mixed both in batches and on-the-flying during the main fracturing treatment. Slightly higher friction at higher pumping rate was observed by the down hole gauge during data frac for this novel fracturing fluid as compared to guar-based fracturing fluid. The main fracturing treatment was successfully executed with 45-50 barrels per minute (bbl/min) pumping rate with increased proppant concentration up to 5 pounds per gallon (ppa) using 30/50 high strength proppant (HSP) proppant. The fracturing fluid system based on the novel acrylamide copolymer offers advantages over guar-based fracturing fluid such as low polymer loading, excellent high temperature stability and less formation damage. This paper presents a systematic approach and lesson learnt during novel fracturing fluid deployment.
Production decline in acid-fractured reservoirs result from the elastic, plastic, and creeping response of highly confined vertical stresses that can destroy the conductive channels created by the acid. This paper introduces a novel, highly viscous acid system having the potential to suspend proppant and perform simultaneous acid and proppant fracturing treatments. During production, impure carbonates tend to decrease productivity as quartz and other minerals migrate, leading to channel closing and/or collapse. Conventionally, acid fracturing treatments are performed by fracturing without proppant followed by different acid stages, including gelled acid. The idea of proppant-fracturing-acidizing (PFA) system entails fracturing in a single stage operation, although to avoid post-treatment plugging of the propped fractures the application of the process would be limited to very clean carbonates. This paper describes PFA fluid prepared by emulsifying hydrochloric acid (HCl) in the internal phase using diesel as the external phase. PFA offers distinct advantages compared to conventional acid systems, namely high viscosity to carry proppant, simultaneously acid-etching the rock, while attaining deeper live acid penetration. Another potential advantage is lowering operational time because mixing can be performed on-the-fly. Preliminary experimental studies have been carried out to investigate the performance of PFA fluid and validate its applicability to perform simultaneous acid and proppant fracturing. PFA was prepared at various HCl concentrations and tested up to 28%. PFA fluid viscosity under different shear rates was measured at high-pressure/high-temperature (HP/PT). It exhibited viscosity as high as 2424 cp at 100°F and 300 cp at 300°F at 50 1/s shear rate. The oil external nature and the stability of the PFA fluid were examined using HP/HT autoclaves at 300°F. The effectiveness of corrosion inhibitors in PFA fluid was determined at 300°F. Static proppant settling tests showed that PFA fluid has good proppant carrying capacity at different particle loadings. After spending PFA fluid in carbonate, the viscosity was reduced significantly, exhibiting breaker-free cleanup. Carbonate reservoirs having closure stress of more than 5,000 psi could be propped to enhance conductivity using PFA system. Enhancing the stimulated reservoir volume could be plausible using PFA system as a single-fluid treatment option, particularly if acid leakoff control and diversion, deeper penetration, and acid and proppant fracturing can be simultaneously implemented.
During the past two decades, fracturing stimulation has become a production driver for a much greater part of the oil industry worldwide. Because of the extensive reservoir formation types, fracturing scenarios widely vary from conventional to unconventional cases. Fracturing is one of the few options for commercial hydrocarbon production in some extremely tight reservoirs. Unfortunately, many of the tight formation scenarios achieve fracture inititation and/or extension only under extremely high pressure, thus frequently reaching mechanical forces close to the well completion limitations. Among the different techniques used, the controlled breakdown technique (CBT) helped significantly improve pump rates in some fracture initiation and injection conditions. This technique controls pressure, while considering the completion's mechanical limits. This paper discusses the process and appropriate conditions for CBT application and evaluates when it is convenient or even crucial to help enhance fracture initiation and development.
The infinite conductivity theory to enhance production was introduced to the industry around 1971. Exploration from the 1970s to the 1990s focused on high permeability formations. The unconventional reservoirs and tight formations were left behind until new technology could enable hydrocarbons to be produced in economical manner. Operators seek methods to both increase initial production and slow the decline rates. This paper describes the infinite conductivity technique to help to enhance production in unconventional reservoirs and tight formations. The advanced pillar fracturing technology was evaluated as an infinite conductivity technique using binding agents to help generate stabilized proppant pillars to create voids and conduits inside the induced fractures during fracture stimulation treatments. The pillars remain stable at reservoir pressure and temperature to help to prevent excessive fracture closure during drawdown. The methodology uses specific surface equipment designed to establish pulsing of slurry and clean fluid segments during proppant placement. This methodology is combined with liquid resin technology to help to prevent proppant and fines migration, as well as reduce proppant embedment that would allow blockage of the conduit spaces. Consequently, the new technology reduces the necessary proppant volume pumped into the formation, thereby reducing the potential of proppant screenout. Mechanical stress on the packed fractures is significantly greater during production when drawdown pressures are maximized and reservoir pressures begin to decline. These two pressures can lead to greater stresses on the proppant after closure. High closure stress also applies pressure to the proppant during production; consequently, the proppant has an increased tendency to crush. Proppant diagenesis is possible and can consequently contribute to reductions in conductivity. However, the application of liquid modified resin creates a film on the proppant surface, resulting in significant reductions in proppant reaction with the formation rock and fluid. This technique reduces diagenesis and helps to control fines generated from crushing that could plug the proppant pack and reduce conductivity. Modified liquid resin also increases pillar strength by creating a film on proppant grains. The application of different shear stresses enhances and stabilizes the strength of the pillar and keeps the newly created conduits open to flow. This paper presents a case history that shows that the production from a well stimulated without modified liquid resin declines significantly more than another well treated with resin-coated proppant. This paper presents a novel infinite conductivity technique that uses a pulsed proppant fracturing process to provide enhanced and sustained production over conventional treatments. The proppant pulsing process helps to create proppant pillars with open flow paths that are highly conductive and can enable almost infinite conductivity.
Increased exploration and development of unconventional reservoirs is one of the main contributing factors to increased hydraulic fracturing activity. The primary aim of hydraulic fracturing is to provide a means for hydrocarbon productivity in tight formations at economic levels. The use of natural sand in high stress zones (greater than 5,000-psi closure stress) is known to lead to increased fines generation and subsequent migration. Thisresults in a detrimental decrease in hydrocarbon productivity, which reduces the value of and could even negate the purpose of conducting hydraulic fracturing. Manmade proppants are able to withstand elevated closure stress environments and have been a widely accepted means of overcoming the limits of natural sand as a propping agent for fracturing operations in medium to high stress environments. A novel engineering procedure using natural sand to withstand higher stresses in proppant fracturing operations was evaluated both in the laboratory and at field scale. This methodology successfully demonstrated the ability of natural sand tokeep fractures open and support formation stresses while simultaneously allowing access to a highly conductive path typically achieved using intermediate- to high-strength manmade proppants in the associated stress regime. This technique also has shown to drastically reduce fines generation and migration along propped fracture geometry, maintain acceptable conductivity of the fracture throughout the stress process, and minimize diagenesis effects typically observed on existing proppant materials. This novel technique can be used to increase the conductivityof hydraulic fractures in unconventional reservoirs. The paper describes a methodology to increase the strength range of natural sand to enable its use in high stress zones without risk of losing fracture conductivity resulting from fines migration. A laboratory scale model was designed to simulate the high temperatures and stresses present at reservoir conditions. The associated model showed natural sand can be used in elevated reservoir conditions up to 12,000 psi stress, resulting in increased hydrocarbon production and reduced costs as well as providing new opportunitiesfor economic fracturing applications in conventional and unconventional reservoirs.
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