Proppant Pack Conductivity Research Articles

Enhancing Fracturing Proppant Performance: Methods and Assessment

AbstractThe use of fracturing proppants is a key element of hydraulic fracturing operations in the oil and gas industry. The selection of proppants with superior performance is critical to ensure efficient and effective hydraulic fracturing. Proppant technologies are developing rapidly. Therefore, standardization of proppant evaluation is necessary to ensure accurate proppant evaluation during proppant production. Although the API and ISO have released a number of recommended practices for this purpose, there are still significant gaps in them. This is because several hypotheses regarding proppant performance, including proppant embedment and diagenesis, and their influence on proppant conductivity, are still not fully clear. Numerous proppants have been produced within the petroleum industry, featuring diverse compositions, sizes, shapes, and intended uses. While many proppants consist of silica or ceramics, there is growing interest in advanced types such as ultra-lightweight proppants. These innovations aim to minimize settling and enable transport using low-viscosity fluids. Moreover, to reduce expenditures, it is common practice in hybrid completions to mix proppant of different sizes according to stimulation design objectives and assumptions. Proppant can be equally mixed, separated by tail-in, or mixed with dominating concentrations of a specific size, depending on the type of fluids, viscosity, and anticipated settlement velocity. Surface modification involves altering the surface properties of the proppant to improve its adhesion to the fracture face and to reduce embedment and fines generation. Surface modification techniques include silane treatment, plasma treatment, and chemical treatment. The method can maintain oil flow channels after the hydraulic fracturing operation for a very long time. Proppant flowback, fines generation, and gel degradation are the key factors that contribute to a proppant pack losing permeability. Proppant pack conductivity can be increased, and well cleanup can be hastened, with the aid of a surface modification. This review paper aims to provide a comprehensive overview of proppant and its types, proppant performance assessment, and methods to enhance proppant performance. We discuss various techniques to evaluate proppant performance, including crush resistance, conductivity, embedment, and closure stress. Additionally, we highlight the importance of selecting the most appropriate proppant type for a particular well based on the formation properties and proppant characteristics. Furthermore, we explore recent advancements in proppant enhancement methods, such as coating, sintering, altering proppant surface, and consolidation, and their effectiveness in improving proppant performance. The comprehensive review provides insight into current industry practices and highlights potential areas for future research to improve fracturing proppant performance.

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.

Investigation of the conductivity of a proppant mixture using an experiment/simulation-integrated approach

Proppant selection in hydraulic fracturing operations is a crucial decision that influences the productivity and performance of stimulated wells. In hybrid completion designs, proppants of various sizes and materials are often mixed and incorporated into the pumping schedule. Optimization of mixing proppants of various sizes and materials has the potential to maximize proppant pack conductivity and to enhance the reservoir production performance. In this work, an experiment/simulation-integrated workflow, which combines the discrete element method (DEM) and lattice Boltzmann (LB) modeling with laboratory penetrometer experiments, was adopted to investigate the effects of proppant mixtures of different sizes and materials on the fracture conductivity. The DEM was used to simulate proppant compaction and rearrangement. Proppant embedment was determined by a load-embedment correlation obtained from the penetrometer experiments. The pore structure of the proppant pack was extracted from the DEM model and then imported into the LB simulator as internal boundary conditions of flow modeling to determine the time-dependent conductivity of the proppant-supported fracture. The integrated workflow demonstrates that the conductivity of a mixed-sized proppant pack is not simply the arithmetic average of the conductivities of the pure proppant packs. The selection of proppants with close sizes has a minor impact on the fracture conductivity when proppants develop to multilayers; whereas mixing with a much finer proppant size will downgrade the fracture conductivity significantly. It is demonstrated that proppant size combination has a lesser effect on the fracture conductivity compared to proppant material combinations. This study also suggests that the application of combinations of sand and premium proppants and modification of proppant injection schedule in the fracturing treatment design can mitigate fracture closure and improve fracture conductivity. This study investigated fundamental mechanisms of proppant mixture at the pore scale, which have significant implications to the optimization of hydraulic fracturing and proppant placement designs.

Validation of flow capacity and state-of-stress models in unconventional reservoirs by implementation of numerical models of diagnostic fracture injection tests

Diagnostic fracture injection tests contain critical information for reservoir characterization and hydraulic fracturing design, defining every input and output of the simulation modeling process. They help to assess the expected fracture geometry, proppant pack conductivity, formation flow capacity, and optimum hydraulic fracture design. At the same time, these data provide the necessary means to place a frac job adequately. However, interpretation challenges and inherent modeling nonuniqueness demonstrate the need for more constraints to reduce the solution space. Proprietary workflows have been applied using a 3D planar shear decoupled hydraulic fracture simulator to several vertical wells in the Vaca Muerta play in Argentina. The generated information makes it possible to build models consistent with multiple independent measurements from bottom-hole gauges, near wellbore, and far-field assessments of fracture geometry, which permit us to better understand production performance of the wells. The proposed workflow can be utilized to collapse the learning curve in a significant and meaningful way, playing a vital role in the optimization of horizontal wells and the field development strategy.

Using an Experiment/Simulation-Integrated Approach To Investigate Fracture-Conductivity Evolution and Non-Darcy Flow in a Proppant-Supported Hydraulic Fracture

SummaryOptimizing proppant-pack conductivity in a hydraulic fracture is of critical importance to sustaining effective and economical production of petroleum hydrocarbons. In this study, a hybrid, experiment/simulation-integrated workflow, which combines the discrete element method (DEM) and the lattice Boltzmann (LB) method with laboratory-measured load-embedment correlations, was developed to advance the understanding of fracture-conductivity evolution from partial-monolayer to multilayer concentrations. The influence of compressive stress and proppant-diameter heterogeneity on non-Darcy flow behaviors was also investigated. The DEM method was used to simulate effective-stress increase and the resultant proppant-particle compaction and rearrangement. Proppant-embedment distance was then determined using an empirical correlation obtained by fitting experimental data. The final pore structure of the proppant pack was imported into the LB simulator as interior boundary conditions of fluid-flow modeling in the calculation of time-dependent permeability of the proppant pack. To validate the integrated workflow, proppant-pack conductivity as a function of increasing proppant concentration was simulated and then compared with laboratory data. Good agreement was observed between the workflow-derived and laboratory-measured fracture-conductivity vs. proppant-concentration curves. Furthermore, the role of proppant size, size heterogeneity, and closure pressure on the optimal partial-monolayer proppant concentration was investigated. The optimal partial-monolayer proppant concentration has important engineering implications, because one can achieve a considerable fracture conductivity using a partial-monolayer proppant structure, which has much lower material costs compared with the conventional multilayer proppant structures. To investigate the effect of non-Darcy flow on fracture conductivity, three proppant packs with the same average diameter but different diameter distributions were generated. Specifically, the coefficient of variation (COV) of diameter, defined as the ratio of standard deviation of diameter to mean diameter, was used to characterize the heterogeneity of particle size. The results of this research provide fundamental insights into the multiphysics processes regulating the conductivity evolution of a proppant-supported hydraulic fracture, as well as the role of compressive stress and proppant-size heterogeneity in non-Darcy flows.

Rheological and breaking characteristics of Zr-crosslinked gum karaya gels for high-temperature hydraulic fracturing application

The metal-crosslinked polymer gels play a vital role in stimulating oil and gas wells since many years, but the presence of large insoluble residues and incomplete breaking of the conventional guar-based fracturing fluids reduces the permeability of the proppant pack necessary for oil and gas flow. In the present study, a novel crosslinked gel has been synthesized using the low molecular weight acidic polymer gum karaya and zirconium crosslinker as an alternative to guar-based fracturing fluids to increase the proppant pack conductivity with competitive rheological performances. The polymer and crosslinker concentrations were optimized and the synthesized gel was studied for structure, morphology, time-independent and time-dependent rheological tests under simulated conditions of pressure and high temperature. The smaller amount of residues left by the fluid after breaking with oxidative breakers and higher regained permeability of the sand pack system compared to Guar confirm its ability to reduce the proppant pack damage.

Analysis of proppant particles porosity based on microCT image processing

The proppant is a granular material with a typical size of 0.2 to 1.2 mm. It is used to prevent the closure of fractures in the reservoir created by hydraulic fracturing procedure, which is actively used in the oil and gas industry. Some types of proppant are manufactured from porous technical ceramics. Presence of internal voids can dramatically decrease the proppant grain mechanical strength and consequently proppant pack conductivity under natural stress. For a detailed study of proppant particles’ internal porosity structure and its relation to the pack’s strength, we applied X-ray microtomography (microCT), which allows to observe this structure non-destructively.In the work, we presented our approaches for digital analysis of reconstructed 3D microCT images for studying the internal voids and the homogeneity of their distribution inside the proppant. We used an automatic thresholding for primary segmentation of pores and particles. We apply 3D marker-controlled watershed to separate individual proppant particles. We propose features for characterization of radial and layered porosity distribution for each particle and homogeneity evaluation. The correctness of our method was tested on synthetic models. Current results indicate probable dependence of proppant strength properties on its internal porosity, but not on the homogeneity of porosity distribution.

A new method for mechanical damage characterization in proppant packs using nuclear magnetic resonance measurements

Proppant performance can significantly affect the success of hydraulic fracturing treatments and production in unconventional plays. Performance of proppants can decrease rapidly by mechanical damage. Quantifying the impact of mechanical damage on proppant performance can be challenging either in the laboratory or in-situ condition. This paper introduces a new method based on Nuclear Magnetic Resonance (NMR) Transverse relaxation (T2) measurements to characterize pore-size distribution in proppant packs. Quantifying the pore-size distribution in proppant packs enables enhanced evaluation of porosity and conductivity of proppant packs and possible mechanical damage to the packs. The objectives of this paper are (a) to evaluate the performance of this new NMR-based method for characterizing pore structure of the proppant packs, and (b) to isolate and quantify the mechanical damage in proppant packs due to generating of fines in the laboratory using this new NMR-based method.First, we prepared proppant pack test samples in three categories including (a) different types of proppants with different surface relaxivity, (b) mixture of proppants with different sizes, and (c) proppants undergone different levels of mechanical damage. We measured NMR response in proppant packs and quantified the impacts of proppant type, size, and mechanical damage on NMR T2 distribution. Next, we used the fractional packing model to quantify the efficiency of packing of proppant mixture and to quantify the changes in porosity of proppant packs caused by variation in size and fraction of fines. Finally, we used Kozeny-Carman (KC) equation and modified Schlumberger Doll Research (SDR) equation to correlate the variation in T2 distribution to the decrease in proppant pack permeability.Results showed that NMR T2 distribution is sensitive to pore-size distribution in the proppant packs. The variable pore-size distribution was either a consequence of having a mixture of proppants with different sizes or different levels of mechanical damage. The impacts of fines on the pore-size distribution of the proppant packs was measureable, which is promising for the successful application of the introduced method for time-lapse quantification of generated fines. We also observed a measurable sensitivity of T2 distribution to mechanical damage in the proppant packs, which enables quantifying the level of damage in proppants through quantifying pore structure in the proppant packs. The NMR T2 measurements were, however, sensitive to the presence of paramagnetic materials such as iron in proppants. This sensitivity was more significant in cases where paramagnetic materials were distributed on the proppant surface. The proposed method is considered as an indirect measurement of pore structure and could potentially provide a quantitative assessment of the proppant pack conductivity both in the lab-scale and in-situ conditions. Improved assessment of proppant conductivity can help in enhancing the design and execution of fracture treatments for successful development of unconventional plays.

Generic Correlations for Proppant-Pack Conductivity

Summary With the large number of fracture stages and the size of jobs being pumped in horizontal wells, many companies have elected to use nonstandard or noncommercial natural sands as propping agents. The Stim-Laboratory Proppant Conductivity Consortium, supported by approximately 50 proppant suppliers, pumping service companies, and operators, has developed consistent laboratory-conductivity-test procedures during the past 30 years that have become de facto industry standards. One outcome of this long history of proppant testing is a set of correlations that can predict the baseline conductivity, as a function of closure stress and rock (substrate) properties, within the range of uncertainty of laboratory tests. Inputs to the correlations are basic material-property measurements such as specific gravity (SG) and median particle size of the sieve distribution. The correlations can be used to compare materials of unknown properties with standardized data sets, or to develop useful predictions of how a non-American Petroleum Institute (API) standard material is likely to perform. The correlations are general enough for application to brown sand, white sand, resin-coated materials, and ceramic proppants of various sizes and densities. These correlations have been found to be sufficient for comparing proppants and for estimating their performance in production computations, when adjustments for appropriate damage and cleanup are made to the calculated-baseline-conductivity values.

Next-Generation Boron-Crosslinked Fracturing Fluids: Breaking the Lower Limits on Polymer Loadings

Summary Hydraulic fracturing is a robust stimulation technique that has been used for more than 60 years to help increase the recovery rate of hydrocarbons from reservoirs. Hydraulic-fracturing fluids are key components of the process. Significant efforts have been made to refine the fluids and advance new technology to help improve the economics, efficiency, and safety of the systems. Specifically, the pursuit of fluids that provide reliable and consistent performance while using lower concentrations of polymer, usually guar or a guar derivative, has been a recurrent point of emphasis in fracturing-fluid advancement. There are many advantages of using lower polymer concentrations, including lower costs, improved logistics, and introducing less polymer with its associated residues into the fracture, among others. This paper presents a new fracturing fluid that combines a next-generation boron crosslinker with a new hydroxypropyl guar (HPG) to be crosslinked with 40 to 60% less polymer than used in conventional borate-crosslinked fluids. For this fluid, HPG loadings in the range of 8 to 12 lbm/1,000 gal were used to produce boron-crosslinked stimulation fluids stable up to 200°F. Fluid-viscosity testing showed stable fracturing fluids with controlled breaking profiles at temperatures up to 180°F. Dynamic proppant-suspension testing indicated that the new fracturing fluid exhibited proppant transport equal to or better than conventional borate fluids. Regained-permeability testing with Berea sandstone cores exceeded 75% at 160°F, 85% at 180°F, and 95% at 200°F. In addition, excellent fluid cleanup was measured by retained proppant-pack conductivity with 2 lbm/ft2 of 20/40-mesh lightweight ceramic proppant. This new boron-crosslinked fluid retains the “rehealable” property and flexibility of conventional borate-crosslinked fluids; however, the polymer is crosslinked at or near the minimum concentration at which the polymer chains can entangle (and are capable of crosslinking), which is an improvement compared with conventional borate fluids. This concentration is known as the critical overlap concentration, c*, of the polymer. The use of the new crosslinking technology coupled with the new HPG allows for a two-fold advantage in terms of residue reduction. The derivatized polymer requires additional processing, yielding a cleaner polymer with less residue, and the lower polymer dosage results in a further reduction of residue compared with conventional fluids.

New Insights of Formation Damage Caused by Borate Crosslinker Fracturing Fluids

Hydraulic fracturing has substantially increased the productivity of unconventional reservoirs. The most widely used one is the cross-linked fracturing fluids. Therefore this study analyzed the formation damage issues caused by borate cross-linked fracturing fluids. Results shows that permeability of formation and proppant pack conductivity are greatly affected by reside left behind. The unbroken polymer chains may be cross-linked again if favor conditions present. The residue will ultimately reduce the conductivity of sand pack and only a small amount of guar residue can be displaced with production. To minimize the formation damage problems caused by polymer residue, the concentration of breaker needs to be the optimum value. To help analyze the degradation extent of fracturing fluids, flow-back fluids can be analyzed through various chemical analysis methods, taking into account the dilution effect of produced water.

Assessment of Fracturing-Fluid Cleanup by Use of a Rapid-Gel-Damage Method

Summary The primary purpose of hydraulic fracturing is to provide highly conductive paths from the reservoir to the wellbore. This is accomplished by pumping fracturing fluids at extreme pressures to create fractures in the reservoir rock. In addition to creating the fractures, the fluid is used to carry proppant into the fractures to keep them open for flow after the pressure is relieved. The performance of fracturing fluids is generally determined by their ability to create fracture width and length with minimal loss of energy caused by friction, to transport proppant efficiently through the tubulars and deep into the fracture, to keep the proppant suspended to help distribute proppant vertically in the fracture, to break on a planned schedule to permit rapid and efficient flowback without producing back the proppant, and to perform all of these goals economically. There are several good methods available to determine fluid efficiencies, proppant-transport properties, and fluid-break times that are important to a stimulation engineer when designing fracture treatments. However, there are few methods available that adequately simulate post-fracturing fluid recovery and that provide the expected well-cleanup rate, efficiency, and impairment of proppant-pack conductivity. This paper presents the development of a laboratory method that permits a rapid assessment and screening of fluids for post-fracture cleanup parameters of a fluid system under realistic reservoir conditions. Fluid-rheology and fluid-recovery data are presented that compare commonly used fracturing-fluid systems with a variety of breakers and proppant types. The use of these data should aid in determining which fluid systems are appropriate for future detailed evaluation.

Development and Field Application of a Low-pH, Efficient Fracturing Fluid for Tight Gas Fields in the Greater Green River Basin, Wyoming

Summary Hydraulic fracturing has proved to be one of the best technologies to improve productivity from tight gas wells. In such low-permeability reservoirs, careful consideration must be given to fracturing fluid selection. Some reservoirs are underpressured and require the use of energized fluids, while others are sensitive to water-based fluids because of clay swelling and migration. Proppant pack damage because of gel residue is one of the primary causes of low production rates after hydraulic fracturing treatments. To minimize the damage and maximize production, a new premium, highly efficient fracturing fluid was developed. This premium system incorporates low-polymer-loading carboxymethyl guar polymer and a zirconium-based crosslinker. An adjustable crosslink delay makes the fluid ideal for deep-well fracturing and coiled-tubing treatment as frictional pressure losses can be minimized. The system can be energized or foamed with carbon dioxide (CO2) and nitrogen (N2) or may also be used in binary foam systems. This paper will provide details on the new fracturing fluid system, in terms of proppant pack cleanup, rheological properties, and fluid loss, as well as other parameters. Various rheological evaluations using high-pressure, high-temperature rheometers as well as a foam loop, fluid leakoff testing, proppant pack conductivity, and regain permeability evaluations are presented. Field case histories will evaluate fracturing treatments using new fracturing fluid and comparable treatments using conventional fluid. Normalized production data of the treated wells of both systems are also compared.

Successful Hybrid Slickwater-Fracture Design Evolution: An East Texas Cotton Valley Taylor Case History

Summary As the development of tight/unconventional and partially depleted gas reservoirs has increased, so has the demand for more-innovative hydraulic-fracture designs. Operators are increasingly placing proppant with slickwater, linear gel, or hybrid fracture designs. While the benefits of these designs typically are attributed to a reduction in gel damage of the proppant pack, many operators mistakenly believe that the resulting fractures are not conductivity-limited. Because few (if any) models on the market can adequately model the propagation of a slickwater fracture along with the associated proppant transport and deposition, it becomes difficult to optimize these fracture designs. This has led many operators to assume incorrectly that only small-diameter sand or resin-coated sand may be placed in these types of designs, and that these products supply ample flow capacity. However, one east Texas operator has combined insight into proppant transport with an appropriate understanding of realistic proppant-pack conductivity to develop a novel, hybrid slickwater-fracture design. This design has allowed the placement of larger-diameter, higher-conductivity proppant in fractures that many believed could not be placed in fractures either operationally or economically. Additionally, this operator has developed a unique pumping strategy to place the highest-conductivity proppant in portions of the fracture where it provides the most value. This paper will present a case history of these new hybrid slickwater-fracture designs in this operator's east Texas Cotton Valley Taylor (CV-T) completions. The design theory and sequential improvements will be documented, including larger-diameter, higher-strength proppants, and a novel placement design. Field results from the first six wells fractured will be presented, showing substantial increases in gas production compared with similar offset completions. Economics will also be shown to illustrate the tremendous value added to completions using this hybrid fracture design.

New International Standards for Proppant Testing

Over the past several years, the Intl. Standards Organization (ISO) and the American Petroleum Inst. (API) have been working to revise inter-national standards for proppant testing. The two ISO committees drafting standards for the petroleum industry are Technical Committee 28—Petroleum Products and Lubricants and Technical Committee 67—Materials, Equipment, and Offshore Structures for the Petroleum and Natural Gas Industry. Subcommittees are examining standards in drilling fluids, cementing, and completion fluids and materials. The first task of the fluids group was to rewrite API Recommended Practice 39, which was published in 2000 as ISO 13503-1 and API 13 M and titled Procedures for Measuring the Viscosity of Completion Fluids. The group, chaired by Mahmoud Asadi of Core Laboratories, is also writing standards for fluid-leakoff measurements, regained permeability tests, and friction tests. The second task has been to review API recommended practices for proppant materials. Three proppant subgroups have been set up to work on specific areas including quality-control testing procedures for proppants, proppant specifications, and proppant-conductivity testing. The work groups are well represented internationally, with participation from Brazil, China, France, Indonesia, Italy, Norway, The Netherlands, Poland, Russia, the United Kingdom, and the United States. Membership includes oil and gas producers, service companies, and proppant suppliers. Updating Recommended Practices API recommended practices for testing proppants were last published in 1995. A subgroup, chaired by Sara Joyce of Badger Mining, began reviewing the practices in 1998, and a committee draft was approved in 2000 that combined the API recommended practice documents into a single standard for testing proppant agents and gravel-pack materials. The work now has progressed to the draft international standard stage. The final draft will be circulated for voting in early 2006 with publication later in the year. Another subgroup, chaired by Mark Ziegler of Unimin Corp., is preparing a draft and conducting tests to set specifications for propping agents and gravel-pack materials. This draft will be circulated for voting as a draft international standard in 2006, with publication scheduled for 2007. In 2003, a third subgroup was formed to write procedures for measuring the long-term conductivity of proppant packs, chaired by Phil Kaufman of BJ Services. A committee draft was submitted in 2004 and is intended to replace RP 61, Recommended Practices for Evaluating Short-Term Proppant Pack Conductivity, published in 1989. A dozen facilities worldwide currently are running long-term conductivity tests without a standard procedure. The subgroup decided not to review and rewrite short-term conductivity procedures but instead to standardize procedures for measuring long-term conductivity. Recent advances in technology have been incorporated into these procedures to increase the accuracy of results and to standardize equipment. The conductivity document has progressed to draft international standard voting. After the comments are considered, the document will be submitted as a final draft for voting by early 2006, and it is scheduled for publication in 2007.

Fracture Conductivity in Hydraulic Fracture Stimulation

Introduction Hydraulic fracturing treatments are frequently required to ensure economic production rates from wells completed in low- to moderate-permeability formations. This type of stimulation treatment involves placing layers of proppant material in the created fracture (Fig. 1). Thus, the formation inflow area to the wellbore is greatly enhanced. The relationships between the productivity improvement factor, Fp, obtained by hydraulic fracture stimulation and the dimensionless fracture conductivity, CfD, of the propped fracture have been published by Prats. CfD is proportional to proppant-pack permeability, kf, and fracture width, bf: .......................... (1) The fracture conductivity may be increased by enlarging the propped fracture width, bf, by application of high proppant concentration. This has become popular during the last few years. Fig. 2 shows that a dimensionless fracture conductivity of 15 is a proper design value for (pseudo) steady-state flow conditions. This value is often not achieved in practice. Moreover, the fracture conductivity found from production-test interpretation on hydraulically fractured wells is often an order of magnitude smaller than expected. Tight reservoirs with high initial transient production rates require higher dimensionless fracture conductivities than indicated above because these transient rates can last for more than 1 year and significantly contribute to the economic success of the fracturing treatment. More sophisticated tools, such as type curves or reservoir simulators, are required to assess optimum fracture conductivity in these cases. Many factors influence the effective proppant-pack permeability, kf, e.g., proppant type, grain size, effective closure stress acting on the proppant pack and formation face, non-Darcy flow effects in the fracture (for gas wells), damage from fracturing-fluid residue remaining after fracture cleanup, and multiphase flow effects. These factors will be discussed individually. Proppant-Pack Permeability (Low Closure Stress) The permeability of a lightly stressed proppant pack is a function of the porosity of the pack, phi, and the mean diameter of the proppant grains, d50: .............(2) Notice the importance of the proppant-pack porosity. In addition, a wider grain-size distribution of a given d50 reduces the permeability -- hence the modern tendency to market narrow sieve fractions, with a bigger mean grain size within a given nominal mesh range. For gas wells, non-Darcy ("turbulence") flow effects in the propped fracture result in an extra pressure drop, : .............................. (3) where v is the fluid flow velocity and the non-Darcy flow factor, which is dependent on kf. Non-Darcy flow effects calculated from Guppy et al. for typical hydraulically fractured gas wells can reduce the effective fracture conductivity by more than a factor of 3. Effective Closure Stress The fracture conductivity dependence on effective closure stress (minimum in-situ stress minus pore pressure) cannot be assessed theoretically; empirical relations based on extensive proppant conductivity measurements over a wide range of conditions are required. The majority of these measurements have been carried out on the most popular proppant size (20/40 mesh) with low liquid flow rates (negligible non-Darcy flow effects) at low temperature and short measurement times. Limited data are available for measurements with gas. The most recent measurements were conducted at reservoir temperature with long measurement times. Significantly lower proppant conductivities are measured for realistic reservoir conditions than reported for the early short-term conductivity tests (Fig. 3). Lack of reproducibility of absolute-permeability measurements between the various laboratories plagues this area of research because standard procedures for preparation - in particular pack porosity - have not been agreed on. The high closure stresses encountered in deeper wells require the use of artificial (intermediate- or high-strength) proppants to improve fracture conductivity. The recent long-term measurements discussed show a technical need for these stronger (and therefore more conductive) proppants at lower closure stresses (shallower depth). This is also true if coarser proppant sand grades are used in an attempt to increase fracture conductivity because crushing occurs at lower closure stress. Multiphase Flow Effects Proppant-pack conductivity is normally measured with single-phase flow. Adding a second or third phase reduces the effective proppant-pack permeability to the original phase significantly. Fig. 4 shows a proppant-pack permeability decrease by more than a factor of 5 if water-saturated gas (two phases) flows through the pack. (Note that in Fig. 4 is called the normalized flow -- see Eq. 3.) Fracturing-Fluid Damage The fracturing fluid is an essential part of a hydraulic fracturing treatment. JPT P. 550^