SPE106269 “Development of a Methodology for Hydraulic Fracturing Models in Tight, Massively Stacked, Lenticular Reservoirs”, C.A. Green, Perenco UK Ltd.; R.D. Barree, Barree & Associates; J.L. Miskimins, Colorado School of Mines. This paper was prepared for presentation at the 2007 SPE Hydraulic Fracturing Technology Conference held in College Station, Texas, U.S.A., 29–31 January 2007.
This paper describes and critically assesses a common methodology currently used to model hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3-D fracture simulator is used with a fully coupled fluid/solid transport simulator. The model incorporates a unique data set from the Piceance basin, Colorado, which produces hydrocarbons from the Cretaceous-age Mesaverde formation. Initially, vertical variations in geo-mechanical rock properties (Young’s modulus, Poisson’s ratio and Biot’s constant) were calculated from well logs. The results were then compared with previous work undertaken on the Mesaverde formation and carried out at the DOE/GRI MWX site. From this analysis, specific correlations were developed for rock properties derived from well logs on a foot-by-foot basis to be used in the hydraulic fracture model. Diagnostic mini-frac injection tests of individual sandstone reservoirs were used to confirm model inputs and develop a valid stress model.
Previous attempts to model hydraulic fracture growth in the Mesaverde have been hampered by a lack of detailed input data sets and the inability to accurately determine horizontal rock property variations. This paper outlines a method which uses micro-seismic/tiltmeter data to constrain and verify the model inputs. The resulting frac model is shown to have not only matched the fracture containment but also pressure matched the actual net surface pressure data in this extremely geologically complex area. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data required to develop such a model has been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
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SPE106270-PA “Hydraulic Fracture Model Sensitivity Analyses of a Massively Stacked, Lenticular, Tight Gas Reservoir”, C.A. Green, Perenco; R.D. Barree, Barree & Associates; J.L. Miskimins, Colorado School of Mines. This paper was prepared for presentation at the 2007 SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, U.S.A., 31 Mar – 3 Apr 2007.
This paper assesses critically the importance of various inputs that are used for a common method to develop a simulator model of hydraulic fractures (HFs) in geologically complex, fluvial, tight gas reservoirs. A planar 3D fracture simulator is used with a fully coupled fluid-/solids-transport simulator. The geomechanical rock properties from logs (Young’s modulus, Poisson’s ratio, and Biot’s constant) and diagnostic minifracture injection tests of individual sandstone reservoirs were investigated to assess their importance in developing a valid stress model.
This paper describes the investigations by use of a model matched previously with both net surface pressure and microseismic/tiltmeter data. From these results, it is possible to obtain a better understanding of how fractures grow and interact with complex fluvial reservoirs, allowing operators to optimize field-well performance and completion methods better in these geologic settings. Additionally, the minimum critical data recommendations necessary to develop such a model have been identified and will aid operators in developing their data-acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extended to other similar geologically complex reservoirs worldwide.
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SPE166550-MS “Offshore Horizontal Well Fracturing: Operational Optimisation in the Southern North Sea”, B Bocaneala, SLB; B Holland, M. E. Langford, Centrica; C. A. Green, G Frac; M.R. Norris, SLB. This paper was prepared for presentation at the SPE Offshore Europe Oil and Gas Conference and Exhibition, 3-6 Sept 2013.
Recently, there has been an increased interest in optimising horizontal multifrac completion technologies used to complete unconventional US onshore wells. The developing technologies and techniques are increasingly being used for offshore applications and have found widespread use in horizontal wells in areas such as the southern North Sea. This case history describes the application of two complementary technologies which have enabled the placement of 1.4 million pounds of proppant in four treatments within 4 consecutive days. Prior to this similar offshore completion operations have typically taken 12 to 25 days.
Historically, cemented liners and “plug-and-perf?? completions have been used for horizontal fracturing in the southern North Sea. Such operations often involve extensive coiled tubing interventions between fracturing stages. This introduces unnecessary technical and associated operational risks due to the extended, long horizontal well architectures that are often used. An openhole, ball-activated multi-stage system, recently introduced into the North Sea, was applied in tandem with the application of a new environmentally-compliant seawater fracturing fluid. The use of the seawater-based system allowed sufficient fluid volume to be loaded and pumped for the placement of four hydraulic fracturing treatments on consecutive days, without the need for the vessel to disconnect and sail back to port to reload fresh water.
As a result of this dual development and correct application of the completion technologies, the requirement for coiled-tubing interventions between stages was eliminated, saving both vessel and rig time. Ultimately, such savings result in faster turnaround times for wells to be placed on production, thereby improving overall well economics. Following the success of the application of this technology the operator is actively pursuing similar new complimentary technologies. Such operational improvements will not only enhance well economics, but possibly define future North Sea fracturing operations.
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SPE18144-MS Permanent Downhole Gauges Selection for HPHT and Fractured Basement Reservoirs, Vietnam H.V. Pham, Cuulong JOC; C.A. Green, G Frac; C Yapp, Weatherford; T.M. Le and A. Butt, Cuulong JOC. This paper was prepared for presentation at the IPTC in Kuala Lumpur, Malaysia 10-12 December 2014.
CuuLong Joint Operating Company, Vietnam operates a number of HPHT and basement fractured reservoirs and has installed over 60 quartz or fiber optic permanent downhole gauges in development wells, since 2003. This paper reviews the selection process for the different type of gauges, gauge reliability and also details some of the considerations when assessing the relative cost advantage of each gauge type.
Equipment and material reliability has always been critical to success in the HPHT and fractured basement environment. As development wells target ever more challenging reservoirs, extreme testing and qualification processes are required to give reliable downhole sensors. This paper describes a methodology used by an Operator to address the significant challenges of selecting gauges for high temperature reservoir monitoring. The work details how the extensive qualification/testing process was successfully applied to select suitable gauges. Initially, after selecting quartz gauges the first deployment of an optical gauge system took place offshore Vietnam in February 2009. To date a total of 20 fiber optic gauges have been installed on different platforms in various reservoirs and when successfully installed have achieved a 100% success rate.
Four major areas were addressed using this methodology, which are necessary in order to ensure success:
Establish applicable standards appropriate optical sensing technology to which components should comply, in order to qualify for selection.
Determining the reliability of electronic gauge systems in the specified high temperature reservoirs environment.
Develop an effective monitoring and optimization process that considers all possible scenarios, in order to properly assess the cost-benefit of the proposed system.
Continually review and improve the system based on available data and analyses.
Application of this methodology has led to a 100% success rate for recently installed gauges and application of this system, developed over the past 10 years, should help other operators world-wide achieve similar success rates in comparable, ‘extreme’ reservoir monitoring environments.
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Principal author of DECC report for advice on mitigation of earthquake risk during HF operations (findings later included into a Royal Society report): Click here.
DECC shale gas technical note: Click here.
Author of technical sections in reply to public consultation on Shale gas development (https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/49542/7268-sg-qa.pdf)
Atlantic Council invited speaker on sustainable shale gas development 2013-2014.