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Summary In general, successful applications of horizontal wells have been limited to high-permeability reservoirs and unconventional formations such as coal, chalk, and shale. Conversely, few tight-gas-sandstone reservoirs that require stimulation have realized sustained success with horizontal completions. One example of such success is the Cleveland Sand of north Texas and the Oklahoma Panhandle. Very recently, some success with horizontals has been observed in the Bossier and Cotton Valley Sands of East Texas and north Louisiana. Horizontal wells are commonly two to four times more expensive to drill and complete than offset vertical wells, yet they are theoretically capable of up to three to five times the production. Higher gas prices have lead to potentially better economics for horizontal wells (Mulder et al. 1992). However, research shows that in practice, many of these wells typically produce only 10 to 30% more than offset vertical wells. With costs more than double those of vertical wells, the economics is obviously unfavorable. This paper discusses ways to identify and manage risks when planning, drilling, and completing horizontal wells in tight-sandstone formations to improve success. Evidence has shown that shortcuts and blanket approaches do not work usually in these completion environments. A multitude of lithological and depletion possibilities exist as risks that need to be identified and managed through appropriate application of integrated drilling and completion technologies. Each risk may require different drilling and completion considerations in order to succeed. There is simply no recipe for repeat success. A detailed method is presented to identify, understand, and manage risk associated with horizontal wells drilled in tight-gas-sandstone reservoirs. The method will address all of the complex subjects that need to be considered for the successful placement and completion of a horizontal well, including reservoir description (both static and dynamic), well design, drilling, stimulation, and production. It will also illustrate consequences of what may happen if these issues are not considered properly. Through this method, horizontal-well feasibility and economic results can be determined. If a horizontal well has been determined to be viable economically, this method can consistently provide a solution as to what the best completion type (vertical or horizontal) is to recover reserves and enhance recovery efficiency in tight-gas-sandstone reservoirs.
Summary In general, successful applications of horizontal wells have been limited to high-permeability reservoirs and unconventional formations such as coal, chalk, and shale. Conversely, few tight-gas-sandstone reservoirs that require stimulation have realized sustained success with horizontal completions. One example of such success is the Cleveland Sand of north Texas and the Oklahoma Panhandle. Very recently, some success with horizontals has been observed in the Bossier and Cotton Valley Sands of East Texas and north Louisiana. Horizontal wells are commonly two to four times more expensive to drill and complete than offset vertical wells, yet they are theoretically capable of up to three to five times the production. Higher gas prices have lead to potentially better economics for horizontal wells (Mulder et al. 1992). However, research shows that in practice, many of these wells typically produce only 10 to 30% more than offset vertical wells. With costs more than double those of vertical wells, the economics is obviously unfavorable. This paper discusses ways to identify and manage risks when planning, drilling, and completing horizontal wells in tight-sandstone formations to improve success. Evidence has shown that shortcuts and blanket approaches do not work usually in these completion environments. A multitude of lithological and depletion possibilities exist as risks that need to be identified and managed through appropriate application of integrated drilling and completion technologies. Each risk may require different drilling and completion considerations in order to succeed. There is simply no recipe for repeat success. A detailed method is presented to identify, understand, and manage risk associated with horizontal wells drilled in tight-gas-sandstone reservoirs. The method will address all of the complex subjects that need to be considered for the successful placement and completion of a horizontal well, including reservoir description (both static and dynamic), well design, drilling, stimulation, and production. It will also illustrate consequences of what may happen if these issues are not considered properly. Through this method, horizontal-well feasibility and economic results can be determined. If a horizontal well has been determined to be viable economically, this method can consistently provide a solution as to what the best completion type (vertical or horizontal) is to recover reserves and enhance recovery efficiency in tight-gas-sandstone reservoirs.
Before the mid-1990s, the main goal of hydraulic-fracturing operations in Russia was preventing near wellbore damage. Typical fracturing treatments used a crosslinked polymer-based gel as carrier fluid to place 5 to 20 MT of proppant into the formation. Because of the results, a new phase started, whereby "real" production enhancement treatments achieving skins of well beyond -4 were pumped with proppant volumes from 50 to over 100 MT. Because of Russian oil production practices at the time, it became apparent that the hydraulic fracturing technology combined with drilling horizontal wells increased production and was therefore beneficial to the Russian economy. When the optimization process started, quality control in the field became mandatory in addition to an enhanced focus on health, safety and environment. Service companies focused on cleaner fluids with less polymer loadings and better breaker systems. Prejob, on-the-job, and postjob quality control procedures were developed specifically for the Russian environment and reached a standard unlike anywhere else in the world. The number of unwanted screenouts was reduced significantly by following proper perforating practices and optimizing the treatments designs in real time. The new goal was a skin of -5, and the design process was optimized to achieve this number by designing each job to achieve optimum production for the given reservoir parameters, especially permeability. Treatments of 300–400 MT are not uncommon these days for low permeability reservoirs with a large reservoir height sometimes covering several zones. This lead to the optimization process that is currently practiced. Because many sandstone reservoirs, particularly in Siberia, are laminated, the vertical permeability is often an order of magnitude or more lower than compared to the horizontal permeability. Several times, horizontal wells did not yield the expected results. Hydraulic fracturing treatments placed in the horizontal wellbore can be the solution for further production optimization. This paper describes how this can be established through several techniques. Hydraulic fracturing includes propped hydraulic fracturing in both oil and gas reservoirs, as well as carbonate fracture acidizing. This paper discusses propped hydraulic fracturing in oil reservoirs. Covering propped hydraulic fracturing in gas reservoirs, although still at the beginning stages, could reveal enough material for a paper on its own. However, carbonate fracture acidizing is not frequently used. Introduction In 2009, the oil and gas industry will celebrate 60 years of hydraulic fracturing. In March, 1949, a team of Halliburton Oil Well Cementing Company and Stanolind Oil Company personnel gathered at a wellsite near Duncan, Oklahoma, U.S.A., to make oilfield history by performing the first commercial hydraulic-fracturing treatment (Fig. 1). Tens of thousands of wells have been treated using this technology and several improvements have been made since in the Western world. Exploration for oil was active in the former Soviet Union in the 1840s in the vicinity of Baku (the first modern oil well was drilled in 1846 by Russian engineer F.N. Semyenov) in the Caspian and was revived significantly after World War II. Soviet explorers were able to apply scientific methods free of commercial constraints. Boreholes were drilled for geological information and Russian explorers pioneered the geochemical breakthrough that identified the source rocks and generating belts.
This particular field is a mature gas field. It produces gas and condensates. The reservoir consists of low permeability sandstones deposited in a fluvio-tidal to littoral environment. The last one can be classified as "Tight Gas" reservoir, which requires fracture stimulation treatments. The reservoir characteristics led to think about non-conventional designs of the wells and their completions. The approach of completing a ca 1700 m TVD / 3000 m MD cemented horizontal well was the challenge. As a result of this process, new technologies were applied for the first time in the region. Among others, abrasive perforating using state of the art coiled tubing tools; multiple zones stimulation, creating orthogonal fractures in the horizontal section; the use of composite frac plugs and special sand bridge plugs for zonal isolation. On the other hand, the analysis and the inherent operational learning curve led to important logistic and economic benefits, ie a rig-less completion operation. One of the final steps of this process, the completion of the first well, was carried out on December 2009. Six frac stages were successfully performed using sand jetting perforating technology, composite bridge plugs, enhanced proppant bridge plugs and ultra light weight proppant, among others. This paper summarizes the process of selecting the best options for completion sizes for an optimized production, CT tools and strings, the design, operational planning and results of the application of the above described completion techniques.
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