Synthesis of Experience in Supporting Hydraulic Fracturing Treatments Using Cross-Dipole Acoustic Log (Russian)
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Evaluating Hydraulic Fracture Geometry from Sonic Anisotropy and Radioactive Tracer Logs
In developing a new field or reservoir, many parameters are important in understanding the success or possible areas for improvement in hydraulic fracturing. Estimating fracture geometry is essential to effectively calibrate a reservoir model to production results. Radioactive (RA) tracers have been used in hydraulic fracturing treatments to infer fracture dimensions. Three stable isotopes (i.e. Scandium, Iridium and Antimony) were used in various parts of the treatment to understand the progression of hydraulic fracture growth. Advanced sonic anisotropy logging tools, using a broader range of frequency acquisition, were used to enable shear measurement in cased hole environments over a wide range of interbedded coal, shale and sandstone sequences both before and after the hydraulic fracture treatment. Amplitude and anisotropy changes after a hydraulic fracture have been measured using sonic anisotropy logging and used to infer fracture height. Finally, the sonic anisotropy can be evaluated above and below the perforated interval and investigate hydraulic fracture height growth away from the wellbore, potentially visualising a greater distance than available with RA tracers. We will show how sonic anisotropy and radioactive tracer logging methods can be used to better understand the fracture geometry and aid further design work. The paper will present data from two (2) wells in the Walloon Coal Measures of the Surat Basin where both RA tracers and sonic anisotropy logs were used to infer fracture dimensions. Both wells used a combination of treated water stages, containing low concentrations of proppant, followed by borate-crosslinked gelled water stages with higher concentrations of proppant. This project contained a large amount of other hydraulic fracturing diagnostics including treatment pressure history- matching, microseismic monitoring and surface tiltmeters. In this paper we will note how those diagnostics compared with the results presented herein, but their results are discussed in greater detail elsewhere (Johnson et al. 2010a). Generally, the results indicate good agreement between these two fracture diagnostic methods and the authors will illustrate the complimentary nature of these diagnostics in gaining a fuller understanding of fracture height, especially in environments of complex fracture development.
Evaluating Hydraulic Fracture Geometry from Sonic Anisotropy and Radioactive Tracer Logs
In developing a new field or reservoir, many parameters are important in understanding the success or possible areas for improvement in hydraulic fracturing. Estimating fracture geometry is essential to effectively calibrate a reservoir model to production results. Radioactive (RA) tracers have been used in hydraulic fracturing treatments to infer fracture dimensions. Three stable isotopes (i.e. Scandium, Iridium and Antimony) were used in various parts of the treatment to understand the progression of hydraulic fracture growth. Advanced sonic anisotropy logging tools, using a broader range of frequency acquisition, were used to enable shear measurement in cased hole environments over a wide range of interbedded coal, shale and sandstone sequences both before and after the hydraulic fracture treatment. Amplitude and anisotropy changes after a hydraulic fracture have been measured using sonic anisotropy logging and used to infer fracture height. Finally, the sonic anisotropy can be evaluated above and below the perforated interval and investigate hydraulic fracture height growth away from the wellbore, potentially visualising a greater distance than available with RA tracers. We will show how sonic anisotropy and radioactive tracer logging methods can be used to better understand the fracture geometry and aid further design work. The paper will present data from two (2) wells in the Walloon Coal Measures of the Surat Basin where both RA tracers and sonic anisotropy logs were used to infer fracture dimensions. Both wells used a combination of treated water stages, containing low concentrations of proppant, followed by borate-crosslinked gelled water stages with higher concentrations of proppant. This project contained a large amount of other hydraulic fracturing diagnostics including treatment pressure history- matching, microseismic monitoring and surface tiltmeters. In this paper we will note how those diagnostics compared with the results presented herein, but their results are discussed in greater detail elsewhere (Johnson et al. 2010a). Generally, the results indicate good agreement between these two fracture diagnostic methods and the authors will illustrate the complimentary nature of these diagnostics in gaining a fuller understanding of fracture height, especially in environments of complex fracture development.
Rakushechnoe-8 is one of the exploration wells drilled in the Northern Caspian Sea. The understanding of the geometry and performance of the propped fracture completion in the Apt formation was considered critical for the economical development of this offshore oilfield. Because of this, and the potential risk of fracture breaking into the water zone below, no resources were spared and robust engineering methods were applied for the first time in Russian offshore operations to determine the formation productivity without and with a hydraulic fracture completion in place. This case history will detail how a planned joint engineered approach provided critical information for the reservoir and production teams to determine the formations potentials, ensuring at the same time reliable and safe offshore operations. After a detailed feasibility and engineering study, a local supply vessel was converted into a stimulation vessel to meet the maritime regulation requirements and projected needs of the Russian Federation. As part of the Project Readiness Assessment, the 4000-HHP strong frac equipment was mock-assembled on the dock, tested, and all the hazards evaluated before sailing. The joint engineering team prepared a rigorous plan for multi source data collection before, during, and after treatment operations. The plan included running dipole cased hole acoustic measurements before and after the frac treatment, bottomhole pressure gauges, a complete mini-frac test, multiple post mini-frac temperature logging runs, production logging runs, and well testing and sampling operations before and after the frac. Finally, a novel vertical seismic profile and micro-seismic measurement was employed to further understand the hydraulic fracture behavior in the Apt formation. The data analyzed before the main fracture treatment enabled safe placement of all 49 tons of 16/20 mesh Intermediate Strength Proppant (ISP) through the drillstem test string obtaining a Cfd = 2.7 deemed optimal for the formation. Post frac measurements and semi numerical modeling indicated that the mechanical model created before the mini frac required some additional modifications and that the propped fracture remained within the target zone. The acoustic and microseismic post frac measurements and well-test results correlated with the expected fracture effective half-lengths and conductivity, confirming that the preparation and execution involved with attaining accurate measurements provided significant value.
Novel Pressure-Temperature BH Gauge for Hydraulic Fracturing Characterization… The key to Enhance Well Production in Complex Tight Reservoirs. Case Studies in Mexico
Propped hydraulic fractures are key to producing tight reservoirs, and knowledge of fracture geometry is fundamental for a proper field development plan. To this end, hydraulic fracture propagation characterization in tight gas reservoirs, pioneered by Amoco during the 1980s, is obtained by combining a dynamic closure test, fracture height determination, and pumping net pressure behavior. The result provides an estimated propped fracture geometry that can then be compared with pressure or rate transient analysis to validate the effective propped geometry. Although surface pressure is generally sufficient to establish bottomhole (BH) pressure decline behavior by correcting for a constant hydrostatic pressure, the inherent uncertainty of friction pressure of crosslinked gel in the tubular does not establish the correct pumping net pressure trend. BH sensor pressure recordings are operationally simple and inexpensive when a fracturing string is required and recovered after the operation (frac-pack operation, well with mechanical pump), but that is not the case with casing fracturing. To remediate this, a high-speed, high-accuracy, and miniaturized BH pressure and temperature sensor, based on microelectromechanical systems (MEMS), was developed under a project funded by the Mexican Secretary of Energy and combined with an economical and practical way to deploy a BH sensor hung from a slickline or wireline cable thereby enabling pressure recording during the entire operation including, the main proppant fracturing (patent pending). This paper presents the results and analysis of two case studies in Mexico where BH pressure and temperature were recorded with this novel sensor. Both jobs were conducted in vertical wells in tight sandstones. In the first field-test job, a post-fracture wellbore propped height determination using dipole sonic logs and radioactive tracer were used. In addition, the entire operation was monitored with microseismic monitoring. The results of these three measurements enabled validating the fracturing model for an increased confidence for field development. In the second field-test job, the BH gauges enabled visualization of the different events that occurred when proppant of different mesh sizes was used during the treatment, containing the fracture eliminating premature screenouts. Only direct measurement of the fracture behavior net pressure and its associated dimension allow the proper calibration of fracturing models required to correctly predict and optimize propped fracture and thus reduce the cost of hydrocarbons produced. This information is property of PEMEX; partial or total use is strictly prohibited without authorization.
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