Resin-Coated Proppant Research Articles

Feasibility of Proppant Flowback Control by Use of Resin-coated Proppant

Proppant flowback is a problem in Xinjiang oilfield. It decreases production rate of a fractured oil well, corrodes surface and downhole facilities and increases production costs. Curable resin-coated sand is a common technique to control proppant flowback. This article presents an experimental investigation whether it is feasible to control proppant flowback by use of resin-coated sand and whether resin-coated sand has a negative effect on proppant pack conductivity. It included two kinds of experiments, Proppant flowback experiment measured critical flow rate while the Proppant pack conductivity one measured proppant conductivity. The experimental results of proppant flowback show that the critical flow rate of resin-coated sand is far greater than that of common sand which means proppant flowback would not happen by resin-coated sand tail-in. Compared to Xinjiang sand conductivity, resin-coated sand conductivity is far smaller though it declines slightly which means use of resin-coated sand would lead to conductivity loss and sequentially results in production impairment. Experimental results show that it is feasible to control proppant flowback by use of resin-coated sand and resin-coated sand would affect fracture conductivity of a fractured oil well. Based on the experimental results, resin-coated proppant conductivity can be improved by use of resin-coated ceramic or liquid-resin-coated proppant. The achievements can give a direction towards how to select a resin-coated proppant and how to improve resin-coated proppant.

Experimental Investigation of Solids Production Mechanisms in a Hydraulic Screen-Through Fracturing Well in a Loose Reservoir and Its Control

Summary Successful cases of hydraulic screen-through fracturing (HSTF) in the Bohai oil field highlight the possibility that hydraulic fracturing can be an alternative method for enhancing the productivity of loose reservoirs. However, a portion of the HSTF wells in the Bohai oil field suffer from severe solids production, meaning that proppants and stratum sands are produced in the wellbore during production and cause wellbore plugging and ensuing debilitation of productivity. In this study, fluid flow amid the stratum, fracture, and HSTF well is simulated experimentally, and pressure drop, flow rate of the fracture, and stratum are monitored to investigate mechanisms and influencing factors of solids production from HSTF wells. Perspectives on solids control optimization are put forward for the Bohai oil field. Results indicate that the formation of an erosion cavity on lip-sealing in fracture and a dominant fluid channel near the wellbore in the stratum are two main mechanisms of solids production. The higher the flow rate and fluid viscosity are, the more severe solids production can be. For the Bohai oil field, with 725-psi-strength resin-coated proppant, the minimum proportion of resin-coated proppant in fractures to prevent solids production can be reduced from the previous 65% to 30%. With 1,073-psi-strength resin-coated proppant, it can be further reduced to 20%. Reducing the proportion of resin-coated proppant can help optimize the conductivity of fractures. This study aims to provide preliminary insight on solving the solids production problem of an HSTF well, thus enhancing the applicability of hydraulic stimulation in loose reservoirs.

Numerical simulation of coated proppant transport and placement in hydraulic fractures based on CFD-DEM

Channel fracturing technology is designed to form fractures supported by non-uniform pillar proppants. Non-cured adhesive resin-coated proppant gradually becomes viscous after immersion and agglomerates during transportation. The pillars are stable after the fracture is closed. They not only maintain a certain compressive strength but also maintain long-term conductivity. Currently, there are few evaluations of coated proppant migration. Based on CFD-DEM method, a two-phase flow coupling model considering the adhesive contact force of coated proppant particles is established to study the cementation characteristics of coated proppant during transportation. The transportation mechanism of coated proppant are revealed by numerical calculation analysis. The results show that different from the conventional proppant, the migration process of the coated proppant is divided into four stages (1) the softening of the proppant contact; (2) the paving of the proppant agglomeration; (3) proppant pillars growth along fracture height; and (4) proppant pillars growth along fracture length. We have completed a preliminary geometric characteristics evaluation of sand bank formed by coated proppant by evaluating the pore volume ratio (the ratio of void volume between pillars to the sand bank volume) under various parameters. This evaluation offers some theoretical guidance for the optimization of channel fracturing proppant injection parameters.

Graphene and Resin Coated Proppant with Electrically Conductive Properties for In-Situ Modification of Shale Oil

Proppant is an essential material in hydraulic fracturing, and it can support artificial fractures for a long time. However, few people have applied proppant and conductive materials in the in-situ modification of shale oil. Here, we developed a graphene and resin coated (GRC) proppant with electrically conductive properties. The electrical conductivity of the GRC proppant improved by four orders of magnitude. The GRC proppant has a 54.58% improvement in suspension and 22.75% increase in settlement time at 0.25 wt% concentration compared with uncoated proppant. The GRC proppant’s adhesion reached 68.34 nN under 1 μN load force, increasing by 63.13% compared to uncoated proppant. This new electrically conductive proppant can be used as a conductive carrier to improve the efficiency of electric heating in in-situ modification technology of shale oil.

Quantifying Erosion of Downhole Solids Control Equipment during Openhole, Multistage Fracturing

SummaryProppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons as proppant may accumulate downhole. Several strategies have been applied to avoid or minimize proppant flowback, such as treatment optimization to maximize pack stability, resin-coated proppant, limiting drawdown, or letting it flow to deal with the consequences later. Another strategy to avoid proppant flowback is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string. Although the presence of sand control equipment can mitigate the problem, it raises concern about erosion during fracturing. Although some installations have been successful, one is known to have experienced sand control failure. This study aimed to understand the effect of hydraulic fracturing on the erosion of completion equipment with an objective of improving the design to, as much as possible, prevent erosion failure. Computational fluid dynamics (CFD) was used to evaluate the root cause and identify more robust design solutions.The first step was to identify the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. The as-is completion was then modeled, along with the screen, SSD, fracturing port, and OH isolation packer. Because the fracture location between two packers is unknown, and the fracturing port was located between multiple screen/SSD assemblies, annular flow across the assembly in both directions was considered. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from the failed installation. A new quasidynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components of the 10-ksi-rated system, and CFD was rerun to confirm erosion resistance targets. Design modifications were implemented, and improved products were then manufactured and field tested. For a new 15-ksi design, particle–particle interaction was added to the CFD analysis. The results of the CFD analysis and field test are presented herein.

Shale-Oil-Fracturing Designs Move to Just-Good-Enough Proppant Economics with Regional Sand

SummarySelecting 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.

The Effect of Resin-Coated Proppant and Proppant Production on Convergent-Flow Skin in Horizontal Wells With Transverse Fractures

Summary In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 md have been developed with horizontal wells with transverse fractures. The potential negative effect of convergent flow in the fractures seems to have been forgotten. The widespread use of resin-coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared with uncoated proppant. Several North Sea horizontal and deviated multifracture gas wells that used RCP and had a significant mechanical skin are presented. Pressure-buildup data confirm the presence of a near-wellbore pressure drop in the fractures. Reservoir simulation with a fine grid reproduces the observed pressure drop because of convergent flow, using realistic proppant-pack permeabilities with gel damage. The effect of proppant production on the convergent-flow skin is shown using production data before and after discrete proppant-production events, demonstrating how proppant production has a beneficial effect on removing convergent-flow skin. We also compare the performance of a new horizontal multifracture well to the original discovery well in the same location, in which a vertical well was fracture stimulated with uncoated proppant and had comparable productivity. If there is a large convergent-flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create “infinite conductivity” channels at the perforations. This removes the convergent-flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily, and convergent flow acts as a downhole “choke” on production. This “choke” can produce a significant positive skin. In the worst case, a horizontal multifracture well with three or four transverse fractures can produce the same as a fully perforated vertical well with a single fracture. On the basis of a number of real-world incidents of proppant production during post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well productivity index (PI) and a decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. In this paper we highlight the potential reduction in well productivity from using RCP for fracturing in gas wells (0.1 to 10 md) with limited inflow area (transverse or oblique fractures), where convergent-flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite-conductivity channels and removing the convergent-flow skin.

Novel Proppant Surface Treatment for Enhanced Performance and Improved Cleanup

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175537, “Novel Proppant Surface Treatment Yields Enhanced Multiphase- Flow Performance and Improved Hydraulic-Fracture Cleanup,” by Terry Palisch, Mark Chapman, and Joshua Leasure, SPE, Carbo Ceramics, prepared for the 2015 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 2–3 September. The paper has not been peer reviewed. This paper describes the development and testing of a new proppant designed to exhibit a neutrally wet surface. The modified surface does not have a preferential affinity for oil, gas, or water and therefore will not promote the preferential entrapment of any phase within the proppant pack. This proppant technology and the results described in this paper should be useful for completions, production, and the work of reservoir engineers dealing with hydraulically fractured wells, particularly in oil- and condensate-rich reservoirs that are particularly challenged by multiphase flow. Introduction A new proppant technology has been developed whereby a thin chemical coating is permanently applied to the ceramic proppant surface. The coating is very thin, approximately 0.13 Μm, or less than 1% of the thickness of the resin on a standard resin-coated proppant grain. The coating is applied to every grain, after the manufacture of the base substrate. It can be applied to any size and type of ceramic proppant, including low-, intermediate-, and highdensity ceramic proppant. The key attribute of the coating is its ability to modify the surface wettability of the proppant grain to a neutral state. Because the coating is applied to every proppant grain, the entire proppant pack exhibits a neutral-wettability surface. When a surface is neutrally wet, the contact angle of the wetting fluid is 90°. For this contact angle, the capillary pressure in the proppant pack is eliminated. A visual test was performed to illustrate the impact of eliminating capillary forces in the presence of the new coating (Fig. 1). Tubes of the 40/80 low-density ceramic (LDC) proppant were assembled with screens at the bottom that would allow water to enter while keeping the proppant in place. When the tube containing uncoated standard proppant was placed in the water, the capillary forces in the proppant pack caused the water to be drawn up into the tube. However, when the same process was repeated with surface-modified proppant, the water level was not drawn up inside the tube.

Rigless Interventions in Failed Gravel-Pack Gas Wells Using New Resin Systems

SummaryWhen a gravel-pack completion fails, it usually results in loss of production for the interval until a workover rig is available to recomplete the well. This paper describes two recent successful rigless interventions completed in offshore multizone completed gas wells in the Adriatic Sea. A key factor in the success of these remedial treatments has been the application of two different chemical technologies applied to the proppant while it is being pumped into the well.In the first well, production loss was caused by fines migration (fine silt ≤44 microns) into the 40/60 gravel-pack sand, which completely plugged the screens and gravel. An intervention was performed which included sealing the existing completion and then reperforating the premium screen using wireline guns. The interval was then fractured with a tip screenout design and a through-tubing screen was placed across the perforated screen. Critical to this treatment was the use of a surface modifying agent to prevent fines migration and plugging of the gravel pack. Production results have confirmed the correctness of this technical choice.A different problem existed with the second well, which had a frac-pack completion; in this case, a screen failure resulted in formation sand and proppant being produced to the surface. The well was refractured through the hole in the screen and a newly developed resin was applied to the proppant to lock the proppant into place and thus repair the damaged screen without restricting the flow area with a secondary inner string. Unlike conventional resin-coated proppant at low temperatures, this new type of resin does not require confinement pressure and/or the use of chemical flushes to cause the resin to set. Since the intervention, the well has been producing sand-free at very close to the original productivity index (PI).In both cases, these treatments have put back into production wells that in the past could not have been restored to production except through recompletion using a workover rig. This paper will describe the treatment design, well operations performed, materials used, and production performance of each well, comparing each aspect with the case of a conventional recompleted well.

Fracturing for Sand Control: Screenless Completions in the Yegua Formation

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 96289, "Fracturing for Sand Control: Screenless Completions in the Yegua Formation," by V.R. Ellis, SPE, and G. Cormier, SPE, Halliburton; G. Adams, SPE, Noble Energy Inc.; and F. Santos, SPE, Sanchez Oil & Gas, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. Natural completions in the Yegua formation have resulted in failures caused by formation-sand production and wellbore collapse. In the past, a popular remedy was small fracturing treatments with gravel-pack screens to control the production of formation material. Designing the completions specifically for wellbore stabilization, sand control, and maximizing the conductivity endurance has resulted in techniques that eliminate the need for gravel-pack screens, helping to simplify completion operations and minimize cost. Introduction The Yegua formation is a sand/shale depositional system that extends from south Texas to south-central Louisiana. Historically, the Yegua has been completed naturally, requiring periodic cleanout when formation sand accumulates in the wellbore. The typical solution for preventing the production of formation sand has been some form of mechanical remediation involving gravel packs or vent screens. In some areas, the Yegua will produce naturally without making formation sand; however, casing failures occur when the bottomhole flowing pressure is drawn down until a critical failure stress is reached and the rock fails. The downdip Yegua, studied here, usually is an overpressured gas/condensate, pressure-depletion-type reservoir. Water production is relatively low in early stages of production and can vary greatly in later stages. The increased water production has been attributed to water coning from higher-permeability stringers. Well 1. Well 1 production was severely restricted when a failure occurred. As the reservoir pressure depleted, fines migration and formation compaction reduced the near-wellbore permeability. As a result, the drawdown pressure increased, causing eventual failure of the formation rock. Formation sand filled the wellbore, halting production, which required a workover to clean out the wellbore. In several cases, the near-wellbore stresses increased to the point at which the casing either collapsed or was sheared, thereby losing the wellbore. Well 1 is an example of lost production because of formation failure that, eventually, led to collapsed casing. Objective The purpose of the work reported here was to maximize hydrocarbon recovery while minimizing casing failures and formation-sand production. The objective was accomplished by reducing the drawdown pressure near the wellbore by placing highly conductive proppant packs. The packs included curable, resin-coated proppant or proppant coated with a conductivity-endurance modifier (CEM) to help ensure that all perforations were packed with coated proppant. Well 2 Well 2 was completed with a 5-in., 18 lbm/ft, P-110 long string set at 13,730 ft measured depth (MD) and 2 7/8-in., 6.5 lbm/ft tubing set with a packer at 13,535 ft MD. The Yegua EY3 sand was perforated in three intervals: 13,588 to 13,592, 13,599 to 13,603, and 13,610 to 13,613 ft MD. The perforated zones then were fracture stimulated. The net pay interval was approximately 35 ft long with a porosity of 22%.

Proppant Flowback Control in Deviated Shallow Gas Wells

Abstract This case-history paper presents results from various proppant flowback prevention methods. The wells studied are part of a shallow gas development project near Brooks, Alberta, Canada. The wells were drilled from multi-well pads resulting in deviated wellbores that reach the gas targets. Each well penetrates two or three gas bearing geologic formations, 400 m to 800 m in depth. Each formation has multiple sand and shale layers that were typically completed by perforating six or seven 2.0 m pay intervals. Then each interval was hydraulically fractured with energized, viscosified water frac fluid that placed 12 tonne of proppant in the formation. The fracture treatments were pumped through coiled tubing and a straddle packer was used to isolate each pay interval. The occurrence of undesirable proppant flowback into the wellbore lengthened clean-out time and increased disposal cost. Three solutions to the flowback problem were tried:curable resin-coated proppant;proppant surface- modification agent; and,fibre elements. Each product was tailed into the end of the frac treatment and the amount of each product used had to stay within the economic limits of the project. This paper describes the proppant flowback control achieved by each technique. Other considerations that were required to successfully pump the flowback control products are also discussed. Introduction History The occurrence of proppant flowback from propped hydraulic fractures has long been an operational problem. Many solutions to try and prevent proppant flowback have been attempted with inconsistent results(1, 2). In most cases, the unwanted proppant is produced during cleanup operations, immediately following the fracture treatment, when the well is being flowed or is swabbed to recover frac fluid. During this time, operators can easily handle the produced proppant with the equipment that is present for well stimulation and completion operations. However, proppant disposal can be time consuming and costly as well as reducing the effectiveness of the stimulation treatment. In other situations, proppant is produced during hydrocarbon production and can be a problem for the production life of the well. Proppant flowback can cause valve and choke erosion, plugging of surface vessels, and proppant can build up in the wellbore covering perforations. During production of the well, proppant flowback increases operating costs, compromises safety and reduces hydrocarbon production. Substantial work has been conducted in the industry to explain, predict, and reduce proppant flowback(3). Uneven closure of the formation on the proppant coupled with proppant settling allows upper portions of the proppant pack to be free moving. Proppant flowback is more prevalent in soft, low closure-stress formations and in deviated wells, but can occur in almost any situation. The chance of proppant flowback from properly packed fractures is reduced but proper packing does not insure proppant free production(2). The literature does not provide a clear understanding of proppant flowback causes or flowback prevention techniques. Problem In the subject case history, proppant flowback is a problem in the field's deviated wells but is not a problem in the nearby vertical wells.

Analysis and diagnostic of proppant flowback in the Orito field, Colombia

Hydraulic fracturing is a conventional practice for production enhancement in low production and damaged wells. Proppant flowback has been a concern in hydraulic fracturing since proppant began to be used as fracture supporting material. In order to prevent the usual proppant flowback problems, some wells in the Orito field were fractured using curable resin coated proppant (RCP). However, flowback production of proppant from some hydraulically fractured wells has caused some serious operational problems, demanding additional analysis of the problem and field handling procedures. This paper describes the laboratory tests and field considerations to design the tests, taken into account to analyze and diagnose the proppant flowback problem in the Orito field. Two types of tests were performed i.e., displacement and flowback.

A Novel Technology To Control Proppant Backproduction

Summary Backproduction of proppant from hydraulically fractured wells continues to create operational problems for oil and gas producers. As much as 20% of the proppant placed in the fracture can be returned to the surface, necessitating costly and labor-intensive surface-handling procedures. The development of unmanned platform operations remains impossible in some areas because of proppant backproduction. Flexibility in well turnaround and production strategies also can be very limited. Curable resin-coated proppant (RCP) has provided the most cost-effective and widely used method to control proppant backproduction. While this is a valuable technique that has served the industry well for many years, it is not universally successful. A new technology has been developed to control proppant back-production and to increase flexibility in well turnaround and production strategies. The technology has been used successfully on several hundred hydraulic fracturing treatments. In this technology, a mixture of fibers and proppant is pumped into the fracture to form a pack that is resistant to proppant backproduction under typical oil/gas production conditions. The proppant/fiber mixture depends on a physical mechanism rather than chemical bonding to increase pack resistance to flowback. There are no minimum closure stress, temperature, or shut-in time requirements associated with the use of this technology, which increases the flexibility available to the operator to optimize well turnaround and production strategy. This paper reviews the laboratory data relevant to the understanding and application of this technology. Studies include proppant pack resistance to flowback in one- and two-phase flow, the effect of cyclic loading, aging phenomena, permeability/conductivity studies, and fluid/breaker interactions. The benefits of the technology are illustrated with field studies.

Proppant Backproduction During Hydraulic Fracturing-A New Failure Mechanism for Resin-Coated Proppants

Summary Back production of proppant from hydraulically fractured wells, particularly those completed in the northern European Rotliegend formation, is a major operational problem, necessitating costly and manpower-intensive surface-handling procedures. Further, the development of unmanned platform operations offshore, required in today's economic climate, is impossible as long as this problem remains unsolved. The most cost-effective potential solution to this problem is provided by curable resin-coated proppant (RCP), which consolidates in the fracture. Early field trials with RCP's, however, were not completely effective in stopping the back production of proppant. Typically, some 10% of the total volume of RCP placed in the fracture was backproduced. Two types of RCP back production were identified: during well cleanup (Type A) and after a long period of proppant-free production (Type B). Type A is believed to be caused by an insufficient strength buildup of the RCP pack. The influence of factors affecting RCP pack strength buildup-resin type, reservoir (curing) temperature, resin/fracturing-fluid interaction (under shear and temperature), and erosion of the resin from the proppant grains, which can reduce the RCP pack strength-have been studied in the laboratory. Type B proppant back production was suspected to be caused by a previously unobserved phenomenon: damage resulting from stress cycling that the proppant pack undergoes each time the well is shut in and put back on production. Further, the applied stress increases as the drawdown is increased and the formation is depleted. We performed a laboratory study to help clarify the effect of curing temperature, water production rate, proppant size, and stress cycling on the integrity of RCP packs. The experiments confirmed the field experience that stress cycling has a dramatic effect on proppant back production of commercial RCP packs. The number of applied stress cycles (i.e., the number of times the well is shut in) and the initial RCP pack strength appear to be the dominant factors that govern proppant back production. Dedicated experiments are therefore required to evaluate the use of RCP's to eliminate proppant back production for a particular field application. Introduction Sand production is an operational problem that has plagued oil and gas wells producing from clastic formations since the early days of the oil industry. By contrast, proppant back production is found only in wells where hydraulically created fractures have been packed with (large) volumes of proppant. The proppant pack is unrestrained at the fracture mouth; once proppant grains enter the wellbore, they can be brought to surface with the well fluids. Such back production of proppant from hydraulically fractured wells, particularly those completed in the northern European Rotliegend formation, is a major operational problem. It necessitates costly and manpower-intensive surface-handling procedures (viz., the daily dumping of proppant) and on-site control of the chokes when beaning up the wells. Further, erosion of well and surface facilities presents a safety hazard, and proppant remaining in the wellbore can shut off production by covering the productive interval. Consequently, the development of unmanned platform operations offshore, required in today's economic climate, is impossible as long as significant proppant back production occurs. Incidentally, a similar tendency for hydraulically fractured wells to backproduce proppant is observed in Alaskan operations; however, owing to the different conditions (onshore oil production), the approach adopted there is "to live with it."

Frac-and-Pack Stimulation: Application, Design, and Field Experience

Paper first presented at the 1993 SPE Annual Technical Conference and Exhibition held in Houston, Oct. 3-6. Combined with SPE 26563 and published in the Journal of Petroleum Technology, March 1994. Summary A relatively short, highly conductive fracture created in a reservoir of moderate to high permeability will breach near-wellbore damage, reduce the drawdown and near-wellbore flow velocity and stresses, and increase the effective wellbore radius. Fracturing treatments of this type have two stages:fracture created, terminated by tip screen out, and fracture inflation and packing. Such a two-stage treatment is the basis of a number of newwell-completion methods, collectively known as "frac-and-pack." This technique has been successfully applied, with a range of fracture sizes, to stimulate wells in various reservoirs worldwide. This paper discusses the criteria for selecting wells to be frac-and-packed. We show how a systematic study of the inflow performance can be used to assess the potential of frac-and-packed wells, to identify the controlling factors, and to optimize design parameters. We also show that fracture conductivity is often the key to successful treatment. This conductivity depends largely on proppant size; formation permeability damage around the created fracture has less effect. Appropriate allowance needs to be made for flow restrictions caused by the presence of the perforations, partial penetration, and non-Darcy effects. We describe the application of the overpressure-calibrated hydraulic fracture model in frac-and-pack treatment design, and discuss some operational considerations with reference to field examples. The full potential of this promising new completion method can be achieved only if the design is tailored to the individual well. This demands high-quality input data, which can be obtained only from a calibration test. This paper presents our strategy for frac-and-pack design, drawing on examples from field experience. We also point out several areas that the industry needs to address, such as the sizing of proppant in soft formations and the interaction between fracturing fluids and resin in resin-coated proppant. Introduction The idea of combining sand control and well stimulation in a single treatment was first practiced in Venezuela some 30 years ago. The treatment consisted of perforating the pay zone, then applying a small-scale fracturing treatment with a viscous crude (10 to 20 cp) and sand sizing to control formation sand. Ball sealers were used in long intervals to promote distribution across the entire section. A screen was washed down through the gravel remaining inside the casing after the fracture treatment, and additionals and was placed around the screen where necessary. This technique yielded relatively high production rates because of low skin and adequate sand control. This treatment was later extended to consist of a small, propped fracture designed to bypass the skin around wells completed in well-consolidated sands that were severely impaired. In this case, the screen was not run and the gravel was not topped up. A typical job for a 100-ft interval would consist of 500 to 800 bbl of crude oil (18 API) with some 40,000 lbm of 10- to 20-meshsand. This propped minifracture typically yielded a two- to three-fold increase in production rate. Though it received considerable publicity, to the best of our knowledge, the technique was never applied widely outside Venezuela. Nevertheless, the technology in this area has now developed to the point where the theoretical understanding of the processes involved has greatly improved, proven treatment design tools are available, and vastly improved mixing and pumping equipment has been developed for both gravel packing and propped hydraulic fracturing.

Improving Quality Control in Alliances and Partnering

Improving Quality Control in Alliances and Partnering