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A field study was initiated to determine fracture cleanup by examining the carbohydrate content of flowback water production from a series of hydraulic fracture stages in the McKittrick field Point of Rocks formation. The study was an effort to understand hydraulic fracture cleanup of the Point of Rocks formation and obtain an idea on the amount of fracture volume contributing to production to optimize hydraulic fracturing design. The carbohydrate content and concentration measured from the water flowback samples are used as direct estimation to the amount of guar polymer recovered postfracturing treatments. Carbohydrate estimation via anthrone testing method to quantify load recovery is by far the most accurate water analysis method available to the industry outside of injecting (and recovering) any special chemical markers. By contrast, studying the ionic content of produced waters by itself can be a misleading quantifier to load recovery due to the mixing and dilution of the pumped frac water with produced formation water. However, the accuracy of polymer quantification using the anthrone method is as accurate as the process of sampling, the frequency of sampling, the time from sampling to testing, the sample container, the testing method, and the calculations involved due to sampling frequency. This paper will discuss the anthrone testing method and will share guidelines that will enhance the accuracy of the testing process. The paper will also compare the guar polymer recovered from a number of hydraulic fracture stages in different Point of Rocks sands and compare to the amount of polymer pumped to present "hypothesis" as to the percent of the propped fracture actually contributing to production. Introduction A study of load water analysis recovered after a series of hydraulic fracturing treatments was initiated in a concerted effort to understand the productivity potential and fracture cleanup of the Point of Rocks formations. Flowback water samples were taken at the wellhead in pre-determined cumulative water production intervals and tested for guar polymer content. The amount of guar polymer mass recovered during the flow back period is compared to the amount of polymer pumped to quantify degree of cleanup. Guar polymer quantification during flowback is a much more accurate method to quantifying load recovery, and therefore cleanup, than load water ionic analysis. Load water ionic analysis can be a misleading quantifier to load recovery due to mixing and dilution with formation waters. Variability in the formation water's ionic make up can also lead to error in estimating cleanup. The degree of propped fracture cleanup post fracturing is related to a number of factors. Some of these factors would include fluid viscosity, polymer type, polymer amount, cross linker type, relative permeability, reservoir pressure (more so reservoir pressure draw down values), reservoir temperature, breaker type and concentration, and fluid surface tension and capillary issues. In addition to frac fluid, the degree of fracture cleanup is also reservoir and pay zone specific. It has always been the industry's desire to take all steps necessary to maximize fracture conductivity. Fracture conductivity is the product of propped fracture permeability and fracture width. In accordance with this desire, a large amount of effort and funding has been spent (and continues to be spent) on breaker technologies to reduce polymer viscosity.
Controlling steam conformance in the horizontal injectors of SAGD projects is widely accepted as being critical for commercial success. This work is focused on steam distribution in horizontal injectors in mobile, heavy oil (non-bitumen), thermal development projects. Steam Conformance can be achieved by tubing or liner deployed FCD's (flow control devices). Liner deployed FCD's have several advantages over tubing-deployed FCD's which includes: smaller tubulars, lower capital costs, reduced well interventions, and potentially reduced surveillance requirements. This paper provides an overview of a collaborative development methodology for liner-deployed FCD's in horizontal steam service between a service company and operator. This methodology included: Establishing functional, operational and dimensional basis of designComputational fluid dynamics (CFD) analysis of the FCD design and phase-split testing in the Horizontal Steam Injection Test Facility (HSITF)Design revisions based on CFD, HSITF and shift testing resultsField installations results based upon fiber optic, thermo-hydraulic, and mechanical analysis These FCD's were designed with sliding-sleeve technology to enable opening or closing of each device. Different specifications of electroless nickel (EN) coatings were also tested to determine the performance for scaling and corrosion resistance. Within 6 months, three versions of the FCD's were tested in the HSITF with accompanying CFD. For each version the shifting forces before and after ~6 weeks of steam injection were measured. Each generation was improved based on the data from the prior version. In December 2018, three FCD's were installed in a large bore horizontal steam injector in a tubing deployed completion for field qualification of the devices. This installation was the first step of a one-year field qualification test. The full test will involve multiple interventions to opening and closing the FCD's. A capillary tubing with fiber optic wrapped around the tubing and devices can confirm FCD openings or closings. The field qualification will also test the local operational capability to shift the FCD's. At the end of the field qualification, the flow devices will be retrieved for inspection and identification of further design improvements.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Monterey formation, Belridge Diatomite is a high porosity (45%) low permeability (0.5 -7 md), low Young's modulus (~100,000 psi) oil reservoir with few stress barriers for fracture containment. Due to the low permeability it is desirable to optimize the fracture length per pound of proppant placed. Conventional cross-linked fluids are not well suited for this purpose as they create excessive width -reducing the effective fracture length generated for a given amount of proppant. Post-treatment production tests often show only 30 -100 ft of effective fracture length even for relatively large treatments designed for longer length. Not only is production limited by these shorter-than-designed half-lengths; excessive fracture width combined with low closure stress often leads to serious sand production problems. Pseudo-3D simulations indicated that longer fractures could be realized by significantly reducing fluid viscosity.A novel low viscosity fracturing fluid, designed to address the serious problems unique to low-modulus formations, was field-tested in the Lost Hills field, California. The lowviscosity fluid developed for this application was composed of a linear gel and a fibrous material. Laboratory studies established that the fiber greatly hinders proppant settling, while maintaining a low slurry viscosity required for fracture length creation. Proppant concentrations up to 12 PPA were pumped with this fluid.Seven new wells were treated with the novel fluid. All wells were fractured in multiple stages; 1,250,000 to 1,500,000 lbm of proppant was used in each well. Real-time pressure data was collected on all stages, and treatments on the first two wells were observed with downhole tiltmeters. Both pressure and tiltmeter data indicated that for similar sized treatments, longer fracture half-lengths were achieved with the new fluid -200-400 ft -versus 30-100 ft for conventional crosslinked gels. Production from the test wells compares favorably to offsets, while using 30% less proppant than conventional treatments.Furthermore, it appears that proppant flowback and sanding problems are significantly reduced.
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