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When hydraulic fracturing techniques are used to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. These problems may be related to the perforation entry or to the fracture width in the immediate vicinity of the wellbore. It has often been concluded that insufficient width generation in the NWB area is the result of the fracture having a very tortuous (rapidly turning or twisted) path for the first few inches or feet before adopting its generally planar shape after it grows beyond the wellbore area. In other cases, the inadequate width problem may result from the generation of several independent fracture planes instead of only one (or a few). During the early 1990's, the oil industry began to consider these problems more seriously, and many operators now use techniques to mitigate such problems before or during a fracture stimulation. The completion plan must sometimes be altered to reduce the occurrence of similar problems in future wells completed in a particular reservoir. Proppant slugs and viscous gel slugs have helped remediate this problem during several applications throughout the world. Contrary to what we would like to believe, proppant and/or viscous gel slugs do not cure every premature screenout. Of course, some people still believe that these slugs would prevent every premature screenout if they were applied properly for the particular problem. If economics were not a real-life consideration, and every completion could be treated as an experiment, that position might be valid. In today's oil and gas exploration environment, the more practical constraints of "economic benefit" present several limitations. This paper discusses these "slug" techniques and their evolution in recent years. It also presents some of the current state-of-the-art methodologies being used. We also offer practical limits to be considered for use with these techniques. Several case histories are presented as illustrations, and suggestions for alternate completion techniques are discussed. History and Background There is much debate about the first use of proppant slugs in hydraulic fracturing operations and many claims to "inventor" status. Considering the typical size of fracturing treatments over the past 20 years, the original frac jobs of the late 40's and early 50's were no more than "proppant slugs" by modern standards. From the 60's through the 80's, proppant slugs were used only sporadically and seldom through a premeditated or scientific method. McMechan et al. 1 reported dramatic effects from small slugs improving perforation entry problems in very deep Okla-homa reservoirs. To some extent, this phenomenon has probably existed for 50 years. History also shows that the use of very small, 100-mesh sand added to the pad volume or just before the primary (larger size) propping agent was started in an attempt to improve fluid-loss control into natural fractures. This application was rare before the late 70's; however, as Cipolla et al.2 have reported, it continues to find significant applications today.
When hydraulic fracturing techniques are used to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. These problems may be related to the perforation entry or to the fracture width in the immediate vicinity of the wellbore. It has often been concluded that insufficient width generation in the NWB area is the result of the fracture having a very tortuous (rapidly turning or twisted) path for the first few inches or feet before adopting its generally planar shape after it grows beyond the wellbore area. In other cases, the inadequate width problem may result from the generation of several independent fracture planes instead of only one (or a few). During the early 1990's, the oil industry began to consider these problems more seriously, and many operators now use techniques to mitigate such problems before or during a fracture stimulation. The completion plan must sometimes be altered to reduce the occurrence of similar problems in future wells completed in a particular reservoir. Proppant slugs and viscous gel slugs have helped remediate this problem during several applications throughout the world. Contrary to what we would like to believe, proppant and/or viscous gel slugs do not cure every premature screenout. Of course, some people still believe that these slugs would prevent every premature screenout if they were applied properly for the particular problem. If economics were not a real-life consideration, and every completion could be treated as an experiment, that position might be valid. In today's oil and gas exploration environment, the more practical constraints of "economic benefit" present several limitations. This paper discusses these "slug" techniques and their evolution in recent years. It also presents some of the current state-of-the-art methodologies being used. We also offer practical limits to be considered for use with these techniques. Several case histories are presented as illustrations, and suggestions for alternate completion techniques are discussed. History and Background There is much debate about the first use of proppant slugs in hydraulic fracturing operations and many claims to "inventor" status. Considering the typical size of fracturing treatments over the past 20 years, the original frac jobs of the late 40's and early 50's were no more than "proppant slugs" by modern standards. From the 60's through the 80's, proppant slugs were used only sporadically and seldom through a premeditated or scientific method. McMechan et al. 1 reported dramatic effects from small slugs improving perforation entry problems in very deep Okla-homa reservoirs. To some extent, this phenomenon has probably existed for 50 years. History also shows that the use of very small, 100-mesh sand added to the pad volume or just before the primary (larger size) propping agent was started in an attempt to improve fluid-loss control into natural fractures. This application was rare before the late 70's; however, as Cipolla et al.2 have reported, it continues to find significant applications today.
When using hydraulic fracturing techniques to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. Many times, these problems are specifically related to the perforation entry or to the width of the fracture near the wellbore. A likely conclusion is that insufficient width generation in the NWB region is the result of a tortuous (rapidly turning or twisted) path for the first few inches or feet of the fracture. Within this near-wellbore region, such fractures must overcome rock stresses greater than the least principle stress. In other instances, the inadequate width problem may result from the generation of a large number of independent near-wellbore fracture planes (starter fractures) instead of only one fracture (or at least only a few). Additionally, the hydraulic fracture may initiate from a fluid-filled microannulus rather than the perforations, which can lead to significant proppant-pumping limitations. During the early 1990's, the oil industry began to consider these NWB problems more seriously. Procedures to help identify the problems were developed, and techniques involving proppant slugs and viscous gel slugs were used to mitigate such problems before or during a fracture-stimulation treatment. Alterations of the well completion plan proved to be a major part of successfully reducing the occurrence of similar problems in future wells in that reservoir. This paper discusses this technology and its evolution through recent years, as well as current applications of these techniques. History and Background The first use of proppant slugs in hydraulic fracturing operations and the inventor are debatable. Between the 60's and the 80's, proppant slugs were used sporadically, and seldom through a premeditated or scientific method. In the early 1980's, McMechan and Conway1 reported small slugs dramatically improving perforation entry problems in very deep Oklahoma reservoirs. To some extent, this phenomenon has probably existed for 50 years. Considering the typical size of fracturing treatments over the past 20 years, the original frac jobs of the late 40's and early 50's were no more than "proppant slugs" by modern standards. History also shows that adding very small, 100-mesh sand to the pad volume or just before the primary (larger size) propping agent was begun in an attempt to improve fluid-loss control into natural fractures. This application was rare before the late 70's; however, as Cipolla et al.2 have reported, it continues to find significant applications today. In the early 70's, Daneshy3 was the first to extensively study the effect of perforated (rather than openhole) wellbores in laboratory testing with realistic insitu stress conditions on synthetic (hydrostone) blocks. When he investigated perforations perfectly aligned with the preferred fracture plane (PFP), he reported that most of these test specimens had a single planar bi-wing fracture emanating from the perforations, but he also found that a less desirable fracture path sometimes resulted. Fig. 1 (Page 13) represents his photograph of this anomaly. Daneshy investigated many other perforation alignments and various degrees of perforation misalignment with the PFP. He also presented a photograph of his observations with a zerodegree phasing of five perforations that were 60° out of alignment with the PFP. Fig. 2 (Page 13) depicts the fracture path he reported as typical for this condition. Many later investigators4–9 also found that fracture initiations do not always begin at the perforations but sometimes initiate from a microannulus outside the casing. Abass et al.7 extensively retested the perforation effect in the NWB region. They observed perforation dominated fracture behavior with perforations aligned within 30° or less to the PFP. Part of their results of tests with higher angles are shown in Fig. 3 (Page 13).
The early stages of a coalbed methane (CBM) project development often require more extensive use of currently available technologies than can be economically justified when approached from a conventional oil and gas drilling focus. As a result, key evaluation tools and technologies are either omitted or not considered before significant decisions are made regarding viability of a CBM play. Understanding that the various lifecycle phases will each affect different objectives and decision points is important. Following site acquisition and estimating basic drilling costs, at least five lifecycle phases can be identified: (1) Regional Resource Reconnaissance, (2) Local Asset Evaluation, (3) Early Development, (4) Mature Development; and (5) Declining Production.A systematic review of current and recently developed enabling technologies is presented in the context of their potential use and applicability. Environmental risk and other constraints that can impact development vary globally, as do economics and production forecasting. New and emerging chemical technologies, as well as hydraulic fracturing refinements, play key roles in various lifecycle phases and decision making to identify successful CBM development projects as early as possible. The paper presents strategies that can reduce development phase failure risk and help predict or rank production potential. Economic constraints usually become more restrictive as the lifecycle moves to Phase 4 and beyond, but key information needed to enter Phase 4 is often overlooked. Examples of this scenario are presented from a global perspective.Globally, new and existing technologies combined with dynamic gas and electricity markets are changing the nature of CBM development opportunities. More accurate and timely go/no-go information needs to be used in the decision making process. Converting development opportunities to development successes involves integrating planning and evaluation methods, using targeted development technologies in the proper phase, and managing risk. TX 75083-3836, U.S.A., fax 01-972-952-9435.
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