Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Several completion methods are the current options typically considered when completing oil and gas wells in unconsolidated sand reservoirs. These include(1) rate control, where the flow rate is held below the sand-production threshold or below erosional limits handling produced sand at surface; (2)screen-only completions, which are common to horizontal and extended-reachwells; (3) underreamed openhole gravel packs; (4) cased-hole gravel packs; (5)in-situ resin treatments; (6) high-rate water packs; (7) water fractures; (8)" frac packs" ; and (9) screenless frac packs. Frac packing is a developings and-control alternative, and use of this method continues to increase in both absolute numbers and percentage of all sand-control completions implemented. Frac-pack pumping strategies represent a definitive break in the long history of sand-control developments. Most early procedures categorically avoided pumping strategies that "break down" unconsolidated formations. Discarding the" don't-break-down" paradigm has resulted in a new generation of sand-control concepts. This paper provides a brief overview of frac-pack evolution and discusses how growing acceptance of the method is creating a revolution in well-completion practices where sand control is required. Frac-Pack Beginning Focus on frac-pack developments started about 1987 after convincing technical and economic achievements resulted from application of tip-screenout(TSO) hydraulic-fracture stimulations in North Sea chalk formations and in high-permeability Prudhoe Bay and Kuparuk field formations on the North Slope in Alaska. The TSO-fracture method significantly increases proppant loading in a fracture, providing substantial conductivity improvement. High fracture conductivity resulted in dramatic and sustained productivity improvements and prompted application of TSO-fracture stimulation in high-permeability, unconsolidated formations. Amoco experimented with completions in 1964 in the Hackberry field, Louisiana, that included fractures in conjunction with sand-control completions(call "hack fracs"). The term frac pack was actually used as early as the late1950's by Shell in Germany for sand-control completions that were fractured before gravel packing. Current use of frac pack refers to completions that combine TSO hydraulic-fracture stimulation pumped with a gravel-packscreen packer assembly in place. The TSO fracture creates a short, highly conductive fracture that is designed to bypass near-wellbore damage. The gravel-pack screen assembly prevents proppant flowback. The proppant/formation interface establishes a stable barrier, preventing sand production. This increase in effective wellbore radius reduces (and often eliminates) positive skin and mitigates factors related to fines-migration problems (see Figs. 1through 3). Frac-pack case histories from the Gulf of Mexico, Europe, Africa, South America, and the Asia-Pacific report increased productivity and effective sand control. In the past 10 years, the use of frac-pack completions has steadily increased in both absolute numbers and as a percentage of sand-control completion methods deployed throughout the world. Significant investment by the service sector has increased the number of purpose-built fracture boats for offshore operations in the past 4 years. Further expansion of these resources is under way. Frac packs are often considered whenever and wherever sandcontrol is required. During the early frac-pack development period, operator and service company innovators often discussed minifracture interpretation methods, design strategies, implementation techniques, and job procedures. Sharing of experiences, observations, concerns, and nonproprietary results was fairly widespread. This open dialogue significantly accelerated frac-pack evolution. In 1992 and 1993, SPE chapters in Houston and Lafayette, Louisiana, sponsored meetings and study-group sessions to present frac-pack developments and address opportunities to improve frac-pack techniques and procedures. The SPE Gulf Coast Section organized a 1-day frac-pack workshop in 1994 and has held three more since. In 1996, "Frac Packs and Other Sand Control Methods" was an SPE Forum Series in North America topic. All these technology exchange sessions had excellent industry participation. Early Concerns At the beginning of the frac-pack revolution, application of TSO-fracture stimulation to highly deviated, typical Gulf of Mexico wells was a controversial concept and many concerns were voiced. The most frequently stated issues were increased cost, inadequate gravel-pack tool capabilities, fear of fracture-height growth into nearby water sands, and lack of coincidence between a vertical fracture and a deviated wellbore.
This paper discusses case histories of more than seventy completions requiring sand control. Approximately half of these wells were gravel packed (both slurry and water packs) between 1990 and 1995 while the remaining completions were fracture stimulated (frac-packs) from 1992 through 1995. The case histories include: geopressured oil reservoirs of moderate permeability, normal pressured high perm oil and gas formations, partially depleted high perm gas sands, and shallow dry gas formations. Results of bottom hole pressure transient analyses are included that compare skin values and completion efficiencies of both gravel packed and frac-packed completions. Production plots and decline curves are presented depicting accelerated as well as improved reserve recovery with the frac-packed completions. The associated costs of frac-packing is discussed along with a net present value analysis justifying these costs. Introduction The popularity of fracture stimulation combined with sand control as a completion technique has intensified in recent years. Due to the pronounced success of frac packing, this technique has become the preferred completion method in sand control environments with several operating companies. However, there has been some debate within the industry concerning the feasibility of this technique in moderate to high permeability formations. This paper reviews the results of one operator's experiences in a variety of applications, including both oil and gas reservoirs with permeability ranges of 3 to 4000 md and bottom hole pressure gradients of 0.17 to 0.84 psi/ft. The skin values of 35 frac-pack completions are compared to those observed in 29 gravel packs employing similar completion techniques with the exception of the sand control method. The relationship of skin damage to flow efficiency is also discussed. Several case histories confirm the theoretical calculations, comparing original gravel pack completions that sanded up to their subsequent frac-pack workovers in the same perforated interval. The rate acceleration and improved recovery of these direct comparisons is presented as well as the rig time and costs of the two different techniques. A comparison of productivity index (PI) and the improvement of PI observed over time in frac-packs is summarized. Finally, the economic impact of these improvements is evaluated relative to the increased cost of the frac-pack technique. Skin Damage The most obvious economic justification for frac-pack completions is improved completion efficiency (lower skin) and the resultant higher flow rates. P. 201
Summary Selecting appropriate proppants is an important part of hydraulic-fracture completion design. Proppant selection choices have increased in recent years as regional sands have become the proppant of choice in many liquid-rich shale plays. But are these new proppants the best long-term choices to maximize production? Do they provide the best well economics? The paper presents a brief historical perspective on proppant selection followed by various detailed studies of how different proppant types have performed in various unconventional onshore US basins (Williston, Permian, Eagle Ford, and Powder River), along with economic analyses. As the shale revolution pushed into lower-quality reservoirs, the concept of dimensionless conductivity has pushed our industry to use ever lower-quality materials—away from ceramics and resin-coated proppant to white sand in some Rocky Mountain plays, and more recently from white sand to regional sand in the Permian and Eagle Ford plays. Further, we compare early-to-late-time production response and economics in liquid-rich wells where proppant type changed. The performance of various proppant types and mesh sizes is evaluated using a combination of different techniques, including big-data multivariate statistics, laboratory-conductivity testing, detailed fracture and reservoir modeling, as well as direct well-group comparisons. The results of these techniques are then combined with economic analyses to provide a perspective on proppant-selection criteria. The comparisons are anchored to permeability estimates from production history matching and diagnostic fracture injection tests (DFITs) and thousands of wellsite-proppant-conductivity tests to determine dimensionless conductivity estimates that best approach what is obtained in the field. Dimensionless fracture conductivity is the main driver of well performance because it relates to proppant selection thanks to the inclusion of the relationship of fracture conductivity provided by the proppant relative to the actual flow capacity of the rock (the product of permeability and effective fracture length), which is supported by the production analyses in the paper. The paper shows how much fracture conductivity is adequate for a given effective fracture length and reservoir permeability and then looks at the economics of achieving this “just-good-enough” target conductivity, either through less proppant mass with higher-cost proppants or more proppant mass with lower-cost proppants, as well as mesh-size considerations. This paper does not rely on a single technique for proppant selection but uses a combination of various data sources, analysis techniques, and economic criteria to provide a more holistic approach to proppant selection.
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.
Selecting appropriate proppants is an important part of hydraulic fracture completion design. Proppant selection choices have dramatically increased in recent years as regional sands have become the proppant of choice in many liquid-rich shale plays. But are these new proppants the best long-term choices to maximize production? Do they provide the best well economics? The paper presents a brief historical perspective on proppant selection followed by various detailed studies of how different proppant types have been performing in various unconventional basins (Williston, Permian, Eagle Ford, Powder River and DJ) along with economic analyses. As the shale revolution pushed into lower-quality reservoirs, the concept of dimensionless conductivity has pushed our industry to use ever lower-quality materials – away from ceramics and resin-coated proppant to white sand in some Rocky Mountain plays and more recently from white sand to regional sand in the Permian and Eagle Ford plays. Further, we compare early-to late-time production response and economics in liquid-rich wells where proppant type changed. The performance of various proppant types and mesh sizes is evaluated using a combination of different techniques, including big data multi-variate statistics, lab conductivity testing, detailed fracture and reservoir modeling, as well as direct well group comparisons. The results of these techniques are then combined with economic analyses to provide a perspective on proppant selection criteria. The comparisons are anchored to permeability estimates from production history matching and DFITs and thousands of wellsite proppant conductivity tests to determine dimensionless conductivity estimates that best approach what is obtained in the field. Proppant selection is typically based on crush resistance to stress loading and fracture conductivity under various flow conditions while having the lowest possible cost. However, dimensionless fracture conductivity is the main driver of well performance as it relates to proppant selection since it includes the relationship of fracture conductivity provided by the proppant relative to the actual flow capacity of the rock (the product of permeability and effective fracture length), which is supported by the production analyses in the paper. The paper shows how much fracture conductivity is adequate for a given effective fracture length and reservoir permeability and then looks at the economics of achieving this "just-good -enough" target conductivity, either through less proppant mass with higher-cost proppants or more proppant mass with-lower cost proppants, as well as mesh size considerations. This paper does not rely on a single technique for proppant selection but uses a combination of various data sources, analysis techniques and economic criteria to provide a more holistic approach to proppant selection.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.