To date, the art of effective openhole horizontal well fracturing is not well defined. Difficulties in regional sealing hamper the fracturing task, and results are generally suspect. Without proper isolation methods, the use of openhole horizontal well fracturing is limited. During many fracturing processes, including fracture acidizing, fracture or acid placement often occurs where fluid first contacts the borehole, often at the heel of the well. A new method is now available that combines hydrajetting and fracturing techniques. By using this new method, operators can position a jetting tool at the exact point where the fracture is required without using sealing elements. Unlike other techniques, this new method allows operators to place multiple fractures in the same well; these fractures can be spaced evenly or unevenly as prescribed by the fracture design program. Large-sized fractures can be placed with this method. Because the method is simple, operators can economically bypass damage by placing hundreds of small fractures in a long horizontal section. To enhance the process even more, operators can use acid and/or propped sand techniques to place a combination of the two fracture types in the well. This paper discusses the basic principles of horizontal hydrajet fracturing and how Bernoulli's theorem was used to design a hydrajet fracturing technique. Laboratory test results for the new technique are provided on Page 4. P. 263
Summary A comprehensive set of experiments including remote- and treatment-well microseismic monitoring, interwell shear-wave shadowing, and surface tiltmeter arrays, was used to monitor the growth of a hydraulic fracture in the Belridge diatomite. To obtain accurate measurements, an extensive subsurface network of geophones was cemented spanning the diatomite formation in three closely spaced observation wells around the well to be fracture treated. Data analysis indicates that the minifracture and main hydraulic fracture stimulations resulted in a nearly vertical fracture zone (striking N26E) vertically segregated into two separate elements, the uppermost of which grew 60 ft above the perforated interval. The interwell seismic effects are consistent with a wide process zone of reduced shear velocity, process zone of reduced shear velocity, which remote-well microseismic data independently suggest may be as wide as 40 ft. The experiments indicate complicated processes occurring during hydraulic fracturing that have significant implications for stimulation, waterflooding, infill drilling, and EOR. These processes are neither well understood nor included in current hydraulic fracture models. Introduction At the very close well spacings in the Belridge diatomite, reservoir performance is dominated by the fracture system, both natural and hydraulically induced. Fracture azimuth, height, extent, and possible existence of a wide process zone surrounding the main crack are all critical because, if neighboring fractures link up either laterally or vertically, undesirable bypassing will occur during waterflooding and other enhanced recovery operations. Thus, understanding the hydraulic fracture process in Belridge is essential for optimizing diatomite reservoir performance. Existing hydraulic fracture models depict a single, narrow (less than 1-in. thick), vertical, planar fracture with two symmetric wings radiating from the wellbore with an orientation orthogonal to the direction of least principal stress. With these models, leakoff of fracture fluids into the formation would suggest a leakoff-affected zone of several feet for the diatomite formation. This perception of the fracturing process may be too simplistic in light of many laboratory and field observations. laboratory experiments on manmade materials indicate that a process zone is created around the main crack. The details of the process zone vary from material to material. Depending on the conditions under which the fracture is created, the process zone would contain tensile and/or shear cracks, as well as other transformations of the original material. The growth of the main crack is accompanied by the evolution of the process zone that often controls the fracturing process. The process zone induced during process. The process zone induced during hydraulic fracturing manifests itself indirectly by "abnormal" net fracture treatment pressures much larger than can be simulated wiih classic single hydraulic fracture models. Field studies have provided evidence of multiply fractured, hydraulically communicating process zones in almost every case, especially when the material is heterogeneous. Examples include the Gas Research Inst. Second Staged Field Experiment, mineback and coring experiments after a hydraulic fracture, and geological analogs such as microfracturing around dikes. Green et al. using treatment-well vertical seismic profiles (VSP's) and interwell seismic surveys, reported an overlay between a low-velocity anomaly and the microseismic cloud in a hot, dry rock geothermal system.
The objective of this study was to evaluate treatment distribution and fracture geometry in a multi-stage, multi-cluster fracture completion performed in a horizontal Eagle Ford well. Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data were acquired on the subject well. The DAS/DTS-observed fracture treatment distributions were then modeled in a three-dimensional fracture model in an effort to visually represent resultant fracture geometries. This process was used to evaluate the impacts on the resulting treatment distributions that occurred as a result of stress-shadowing between fractures. The ultimate goal was to understand the influence that adjacent fractures within a stage and adjacent stages have on fracture distribution, fracture geometry, and completion effectiveness. DAS/DTS data suggest a high level of interference between adjacent fractures. Interference between adjacent fractures within a given stage, and from adjacent fracture stages, results in a consistent geometric predominance for fracture growth in the most heel-ward perforation cluster. DAS/DTS results also indicate that an excessive number of perforation clusters, spaced closely together, magnify the negative effects of stress shadowing, and potentially diminish completion effectiveness. Operationally, the DAS/DTS data showed that the surface pressure response originally attributed to downhole diversion from particulate diverters was in fact not due to diversion. Once a dominate fracture was established in a given stage, it remained dominate throughout the entire stage even though two diverter drops per stage were incorporated into the treatment. Finally, the DAS/DTS data indicated that a significant portion (71%) of the stages experienced intra-stage communication. The large majority of this communication was due to plug leakage.
Summary Lost circulation has been one of the major challenges that cause much nonproductive rig time each year. With recent advances, curing lost circulation has migrated from "plugging a hole" to "borehole strengthening" that involves more rock mechanics and engineering. These advances have improved the industry's understanding of mechanisms that can eventually be translated into better solutions and higher success rates. This paper provides a review of the current status of the approaches and a further understanding on some controversial points. There are two general approaches to lost circulation solutions: proactive and corrective, based on whether lost circulation has occurred or not at the time of the application. This paper provides a review of both approaches and discusses the pros and cons related to different methods—from an understanding of rock mechanics and operational challenges. Introduction Lost circulation (LC) is defined as the loss of whole mud (e.g., solids and liquids) into the formation (Messenger 1981). There are two distinguishable categories of losses derived from its leakoff flowpath: Natural and Artificial. Natural lost circulation occurs when drilling operations penetrate formations with large pores, vugs, leaky faults, natural fractures, etc. Artificial lost circulation occurs when pressure exerted at the wellbore exceeds the maximum the wellbore can contain. In this case, hydraulic fractures are generally created. During the last century, lost circulation presented great challenges to the petroleum industry, causing significant expenditure of cash and time in fighting the problem. Trouble costs have continued into this century for mud losses, wasted rig time, and ineffective remediation materials and techniques. In worst cases, these losses can also include costs for lost holes, sidetracks, bypassed reserves, abandoned wells, relief wells, and lost petroleum reserves. The risk of drilling wells in areas known to contain these problematic formations is a key factor in decisions to approve or cancel exploration and development projects. Background literature (Messenger 1981) on the subject describes many methods and materials used to remedy lost circulation. Many of these methods worked in some wells but not in others. Trial and error applications almost always resulted in a costly learning curve. A field practices study (API 1991) of cementing wells, published by the American Petroleum Institute (API) in 1991, compiled drilling and production surveys and trade journal data for 339 fields worldwide between 1980 and 1989. The number of fields in each area is presented for general information and may not represent all wells or fields in that specific area. The North American fields include fields in Canada, Mexico, and the USA. Listed among the many types of data sourced in this study is LC information in relevant fields. This LC data was analyzed for this paper to obtain the LC event frequencies of occurrence presented in Table 1. The LC data analysis indicates that up to 45% of all wells in the 339 fields require intermediate casing or drilling liner strings to isolate LC zones and prevent LC while drilling deeper to total depth (TD). Even after using these extra pipe strings, LC events still occurred in 18 to 26% of all the hole sections drilled in relevant fields. Some fields had higher occurrences of LC events ranging from 40 to 80% of wells. In recent years, these percentages likely increased as the number of shallow, easy-to-find reservoirs steadily declined and industry operators intensified their search for deeper reservoirs and drilled through depleted or partially depleted formations. Conventional lost-circulation materials (LCM), including pills, squeezes, pretreatments, and drilling procedures often reach their limit in effectiveness and become unsuccessful in the deeper hole conditions where some formations are depleted, structurally weak, or naturally fractured and faulted. To address these issues, new LC solutions and concepts, such as borehole strengthening or wellbore pressure containment (WPC), evolved (Alberty and Mclean 2004; Aziz et al. 1994; Fuh et al. 1992). The mechanisms behind various means proposed and used to enhance WPC are still debated and are not fully understood. Proposed mechanisms include sealing incipient fractures at the wellbore wall; propping open multiple short fractures at the wellbore wall, thus increasing compressive stresses around the wellbore; and sealing fractures with various materials using a hesitation-squeeze technique. Based on the ongoing debate of these emerging new technologies for controlling lost circulation, this paper intends to provide a comprehensive review and analysis for a better understanding of both proactive and corrective borehole strengthening technologies.
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