Geothermal power plants use heat from the Earth's interior to produce one of the cleanest sources of electric power currently available, but the production of geothermal fluids can be costly if large quantities of silica scale are deposited on production tubulars. This widespread problem significantly reduces the ID of the tubulars, thereby reducing the production rate of the well. Previously, scale removal techniques involved the use of a drilling rig and a combination of such mechanical tools as drill bits and mills. Rig-based methods, however, are expensive and time-consuming. This paper discusses the design, use, and evaluation of an alternative technique that includes a coiled tubing unit (CTU). When compared to traditional rig-based scale removal techniques, coiled tubing methods offer several economic, environmental, and safety benefits. Specifically, the use of coiled tubing reduces job time because coiled tubing is faster to rig up/down and pull out of the well. From an environmental standpoint, well effluent and debris can be flowed through the flowline to the existing processing facilities; pits are unnecessary. Coiled tubing also provides a greater degree of safety and well control when operations are being performed on a live well. In the case histories provided in this paper, three methods were used to remove scale. For the first method, the cleaning energy was applied by highly focused polymerized fluid jets, which were specially designed for the job by a computer program. This hydraulic technique can be performed on a live well, which results in additional savings over traditional methods. The steam production during cleaning creates the required annular velocities to remove debris from the well without the need for energized treatment fluids. The second method consisted of a high-speed coiled tubing motor in combination with a flat-bottom junk mill. Although both mechanical techniques have been performed with varying degrees of success, both increased the geothermal production rates of the wells treated. The third method involved the use of a silicate scale remover that was used between the slotted liner and openhole section. It was also used to treat the well when either of the first two techniques were slowed or stopped by particularly hard scale deposits.
Wells in the Montney Formation area, British Columbia, Canada, were designed as monobores and include surface and long lateral production casings. The decision to modify the openhole (OH) completion to a cemented sleeve system presented some concerns. A comprehensive data set from all prior cement operations was compiled and analyzed. This data showed severe gas migration to surface for both an OH completion and cemented lateral well. Computational fluid dynamics (CFD) and a finite-element simulator were used to evaluate both conventional and foam cement options using actual centralization and caliper log data. The results from this analysis identified a gas-flow potential factor (GFP) was of an order of magnitude where only compressible, foam cement would provide the required properties to achieve competent, long term zonal isolation. The characteristics of foam cement include a high kinetic energy that assists removing immobile mud trapped on the low side of the casing. Additionally, in this case, using a foamed spacer further improved mud removal from the annulus, resulting in improved displacement efficiency, as observed in the final cement evaluation logs. Filtrate loss and reduced hydrate volume can allow gas migration, giving rise to surface casing vent flow (SCVF) while the cement is curing. Foamed cement helps create a highly compressible cement system that can compensate for these volume decreases and reduce the potential for SCVF. The ductile properties of the set foam cement help mitigate the likelihood of cement debonding and cracks forming during hydraulic fracturing operations, which also helps to reduce the potential for SCVF.
An off-shore field in Abu-Dhabi has water injectors with dual completions injecting into 3 carbonate subzones A, B and C, separated by dense carbonate layers which act as impermeable barriers. Each completion has one of the two strings completed into two consecutive subzones. The irony is that subzone B is the most permeable and robs the other two of their injection quotas. This was occurring as the low permeability zones could not be acidized properly due to inefficient diversion. Repeated acidization of the commingled zones with benzoic acid diversion had not yielded desired results. In the on going inquest to select a positive diverter, a polymer based system was investigated as a diverting agent. This paper discusses the use of this polymer based acid activated diverting agent in staged stimulation's performed in injector wells in an off-shore field, Abu-Dhabi. The diversion mechanism is explained including how it compares with the other techniques. Polymer properties and characteristics are also explained. Introduction To ensure maximum damage removal and homogenous distribution of stimulation fluid occurs during treatments on multiple intervals of varying reservoir characteristics, it is necessary to divide the treatment into stages. A technique that forces each stage to go into a different zone is used during the procedure to assure treatment of the total productive interval. One of the most important factors affecting the success or failure of matrix stimulation treatments is the correct downhole placement of fluids for optimal zone coverage. When injected, these fluids naturally tend to follow the path of least resistance, that is to the higher permeability and/or least damaged zones. Since damage must be removed from the entire producing interval, effective diversion techniques must be employed. Previous techniques include; mechanical methods (zone isolation packers, packers and bridge plugs) for selective injection, are considered to be the most effective form of diversion, However, these tools generally require a rig on site. Ball sealers offer a cheaper and more practical approach but their effectiveness depends on many parameters including, the length of the perforated interval(s), roundness and smoothness of the perforation holes, injection rate and the differential pressures across the perforations. Particulate diverters like graded rock salt (GRS) and benzoic acid flakes (BAF) enable the flow to be diverted by depositing a cake on the reservoir rock face, thereby generating a temporary skin factor. P. 503
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.