New Stimulation Techniques Improve Canyon Sand Gas Production: A Case Study

Satisfactory stimulation of oil and gas bearing formations by "fracture acidizing" is dependent upon development of adequate fracture conductivity in naturally occurring or hydraulically induced fractures. The created fracture conductivity is a result of the action of acid on the exposed fracture face. Some of the kinetic parameters which will influence the resultant conductivity are acid type and strength, reaction temperature, reaction time, and flow regime. These parameters are treatment design variables which can be used to optimize fracture acidizing treatments. Formation characteristics will be equally important, and in many cases, more critical than the kinetic parameters. Some of the formation parameters which will affect the development of fracture conductivity are the mineralogical composition, degree of homogeneity, hardness, and closure stress. Equipment has been developed to allow realistic laboratory simulation of dynamic etching during the fracture acidizing process. Dynamic etching tests can be used to determine the feasibility of an acid treatment, as well as allowing optimization of the treatment parameters discussed above. Equipment construction allows evaluation of all strengths and forms of acids —e.g. non-gelled, gelled, foamed, emulsified, or chemically retarded — to be evaluated at temperatures up to 375°F, and at closure stress levels up to 12,000 psi. Any type of formation core may be evaluated. Recent improvements in dynamic etching tests have allowed successful stimulation of difficult to treat formations such as cold dolomites, chalks, formations with low acid solubilities, and uniform carbonates.

Effective fracture length is the portion of the propped fracture that cleans up after hydraulic fracturing procedure and contributes to well productivity. Studies indicate that this effective length is often less than 10% of the total propped fracture length. A large portion of our fracture stimulation dollars are wasted!This paper presents a comparative well study performed in the Cement field in south central Oklahoma. Stimulation of the Springer Sands using hydraulic fracturing with conventional low polymer fluids was compared with the use of low molecular weight polymer fracturing fluid. The depth of the three Springer Sands (Cunningham, Britt, and Boatwright) ranges from 12,500 feet to 15,500 feet and have an average permeability range of 0.1 to 5.0 md.This evaluation includes several components. Well production history matching and pressure analyses are used to determine effective fracture length. Results of these analyses are compared with calculated values based on laboratory generated cleanup data for the two fluid systems. Flowback rate, pressure, accumulated volume, viscosity, and polymer content were collected following the fracture stimulation treatments.The fluid systems compared in this study are a conventional low polymer system with gel breakers and a new, low molecular weight polymer system that requires no breakers. Both fluids use borate cross-linking chemistry. The low molecular weight fluid system creates transient, high molecular weight polymer chains at higher pH conditions. After exposure to the formation minerals, the pH drops and it reverts to a clean, nearly Newtonian, low viscosity fluid that causes little conductivity damage.The results of this study show that the use of low molecular weight fracturing fluid provides significant improvements in the effective fracture length over conventional low polymer fracturing fluids. Simple engineering tools have also been developed to evaluate both fluid and proppant selection and job design to achieve improved well performance. It also demonstrated that improved recovery of the fracturing fluid can be achieved at excellent rates without the use of conventional gel breakers.

Multi-stage/multi-cluster hydraulic fracturing in horizontal wellbores is a key technology driving the development of unconventional resources in North America. Several engineering technologies developed over the past decade are readily available for operators to help enhance production. The advantages of technology integration for creating multiple transverse fractures in horizontal wellbores have been well documented. Given the rapid pace of development, many operators strive to standardize completion programs to drive consistency and efficiency in operations and well performance. The key parameters that maximize production in unconventional reservoirs are not dissimilar to the key parameters proven successful time and again in conventional completion designs and fracturing treatments. Generating fracture complexity may be important in unconventional reservoirs, but maximum reservoir contact does not necessarily translate to an effectively stimulated reservoir. Fracture length, fracture conductivity and fracture spacing in multi-cluster/multi-stage completions are first-order parameters that can be engineered. However, additional completion and design considerations for unconventional wells such as natural fracture saturation, mid-field fracture complexity, mechanical fracture interaction and transverse fracture production interference must be considered to enhance production and maximize economics. This paper will focus on technology integration for the Wolfcamp A reservoir using a discrete fracture network (DFN) model for predicting fracture geometry, formation evaluation, oil and fluid tracers, microseismic monitoring and production history matching. The methodology includes: 1) utilization of current fundamental engineering principles and procedures for completion design, 2) simulator calibration to improve predictive models and 3) production history matching and forecasting. Application of this integrated technology approach will help provide the operator with a systematic approach for designing, analyzing, and optimizing multi-stage/multi-cluster transverse hydraulic fractures in horizontal wellbores. Readers of this paper will gain insight on how sound engineering, fracture modeling and data integration can increase recovery and optimize completions in the Wolfcamp formations. Those working in the Delaware and Midland basins can directly apply the principles presented in this paper to enhance the productivity and economics of their completions.

Today there are still many challenges in the quantitative interpretation of downhole distributed temperature measurements to diagnose multistage fracture treatments in horizontal wells. These challenges include handling enormous amount of data measured by the sensors continuously in time and space domain, a readily-to-be-used fast but robust forward model to simulate temperature behavior, and an efficient algorithm to inverse the parameters that are of interest. Because multistage fracturing involves many uncertain parameters; ranging from reservoir properties to treatment design, to fracture geometries and conductivity; the problem is extremely complex when inverse the measured temperature to a downhole flow profile. This study presents an approach to combine forward and inversion models to interpret downhole temperature data. The goal is to improve computational efficiency. Examples use the field data from a gas well in Marcellus shale formation to illustrate the feasibility of quantitative interpretation of temperature measurement for fracture diagnosis. The forward model uses the fast marching method. The forward simulation is order-of-magnitude faster than even the semi-analytical model, which is the essential contribution to apply the method in the field case successfully. The inversion procedure starts with a sensitivity study to select the inversion parameters among various parameters such as fracture half-length, fracture conductivity, and determine the impact of their uncertainty on inversion. The inversion model uses the initial analysis on temperature gradient to identify the zones with significant temperature changes for interpretation and eliminates the rest of the data from interpretation. Thus, we obtain a prior estimation of the selected inversion parameters, which will be used as an initial guess of the inversion process. This prior estimation saves significant computation. The inversion is performed fracture by fracture either using parallel computing or sequential computing based on the sensor locations. We first show a synthetic example with multiple fractures to illustrate the approach, test the procedure accuracy and computation speed. The primary inversion parameter is flow rate, and either fracture length or fracture conductivity, with all other parameters as an additional constraint. With an adequate initial guess, the inverted parameters match the reference "true value" properly. The inversion process converges with limited iterations for each fracture. The operation time highlights the advantages of the inversion model. The guided initial guess ensures the gradient inversion method converge and avoid local minimization. Finally, a field application is performed using this inversion model and shows encouraging results. The results of the paper illustrate the feasibility and procedure of using temperature date to diagnose multistage fracture treatment. The proposed inversion model is fast and reliable which provides a promising tool that can be used to interpret downhole temperature data quantitatively.

This paper describes the application of pseudo-stable fracturing fluids as a key technology to improve fracture conductivity and production performance in the first successful hydraulic fracture treatment pumped offshore Abu Dhabi. The primary target reservoir is the Pre-Khuff clastics Fm., a deep tight gas sandstone that can be found at depths exciding 16,000 ft with temperatures above 350° F. Even though our industry has a long-standing history in fracture stimulating high temperature reservoirs, the rheological behavior of fracturing fluids for optimum performance still remains to be highly controversial. It is well-known that at elevated temperatures fracturing fluids tend to prematurely break, losing its viscosity alongside the capability to transport proppant and develop fracture width that may lead to early treatment termination. What is rarely mentioned is that fracturing fluids break spontaneously at high temperature in oxygen rich environments (such as in a laboratory) nevertheless, when there is a lack of oxygen, fluids do not break effectively. Reservoirs are strong oxygen reducing environments because of the presence of iron, organic matter and hydrocarbons, having a negative effect on fracturing fluid rheology degradation, fluid cleanup and fracture conductivity. At the same time, there is still little consensus regarding the rate and magnitude of thermal exchange between the fracturing fluid and the reservoir high temperature conditions that will affect its rheological properties. Contrary to popular belief, fracturing fluids do not heat up to reservoir conditions as fast as suggested by many software applications and there is no need for large viscosity stability windows to efficiently transport proppant without premature screenouts. In this case history, a physics-based fracturing fluid design was utilized to successfully place ~ 100 tons treatments implementing a 15 minutes viscosity stability window which, under traditional standards, will not survive harsh downhole conditions and temperatures over 350° F. Post-frac production increased by 500%, reaching stable commercial rates after the first fracture treatment, proving that the implemented fluid design philosophy is correct and extremely efficient in developing high performing fracture treatments.

The effect of residual fracture fluid gels on the conductivity of propped fractures has commonly been measured in the laboratory with a static fracture conductivity procedure in which a certain amount of proppant is placed in a fracture conductivity cell, and then fracture fluid is injected into the cell. This test does not capture all of the physics of the process of proppant placement and fracture closure as it occurs in an actual fracturing treatment. In particular, the interactions among the transport of fracture fluid down the fracture and leakoff into the formation can result in a completely different distribution of residual polymer in the proppant pack in the real fracturing process compared with the static conductivity test. To more closely simulate actual fracturing conditions, we have developed a dynamic fracture conductivity procedure. In these experiments, fracture fluid/proppant slurry is injected into a fracture conductivity cell at injection rates representative of conditions in an actual fracture. Leakoff conditions are also set to mimic actual field rates. To be able to control leakoff at realistic rates, we use 3-inch thick core samples in the conductivity cell, rather than the 1/4 to 1/2 inch thick samples used in a standard API conductivity cell. After flowing the fracturing fluid slurry for some length of time, the cell is shut in, the fracture is closed by applying stress with a load frame, and then gas is flowed through the cell to represent the flowback period. During the gas flowback period, we repeatedly measure fracture conductivity to determine the amount of gel cleanup occurring. We have conducted a series of dynamic fracture conductivity experiments using a crosslinked guar-based fracture fluid at 150 °F. One of the most significant findings is that the fracture conductivity measured with the same proppant loading using the static conductivity procedure is about twice as high as that obtained with a dynamic test. We also show how gel cleanup depends strongly on the gas flux through the fracture, on the presence of breaker, and on the polymer loading.

Clark, P.E., Dowell Division of Dow Chemical U.S.A. Abstract This paper describes a new approach to the rheological characteristics of fracturing fluids. The new approach uses an oscillating or dynamic shear rate rather than a steady shear rate which allows the determination of the rheology of highly viscous, cross-linked gels accurately with a variation between measurements of less than 5 percent. An accurate and reproducible method of determining fluid properties is necessary for both fracturing treatment design in the field and fluid development and optimization in the laboratory. The coaxial cylinder and capillary-type viscometers in general use throughout the industry are adequate for uncross-linked fluids but are less than adequate for cross-linked, high viscosity fluids. Fracturing fluids of all types can be measured using a dynamic viscometer. There is a wealth of information available from dynamic measurements that cannot be derived from steady shear measurements. As an example, both the elastic storage modulus and the viscous-loss modulus can be measured. These parameters are related to the amount of energy stored parameters are related to the amount of energy stored elastically and lost through viscous heating, respectively, both are related to the pumping pressure. The instrument that will be described is also capable of accurately determining yield stresses, normal forces and viscosities of prop laden fluids. In this paper, the relationship between steady shear and dynamic viscosity data for several common fracturing fluids will be established. Data for cross-linked fluids will be presented as well as data for sand laden fluids. Introduction The rheology of well stimulation fluids play a commanding role in the results of hydraulic fracturing treatments. Fracture width, height and length, as well as prop-pack height and penetration, are determined in part by the rheological properties of the treating fluid. The standard method for determining the rheology of fracturing fluids specifies the use of a rotational viscometer with a couette fixture, such as a Fann Model 35, Model 50 or an equivalent instrument. This type of viscometer is well suited for measuring the properties of Newtonian or non-Newtonian fluids that exhibit only weak viscoelastic properties. Non-Newtonian fluids that exhibit strong properties. Non-Newtonian fluids that exhibit strong viscoelastic properties are difficult or impossible to study using a rotational viscometer. The need for a different measurement technique has been brought about by the advent of cross-linked gels that exhibit strong viscoelastic properties. This paper will describe a technique that can be used to paper will describe a technique that can be used to successfully study the rheology of cross-linked fluids, as well as noncross-linked fluids. Dynamic mechanical testing, which has been used to characterize a wide variety of materials used in other industries, can be used to study fracturing fluids over a wide range of conditions. It will be shown that even fluids containing proppants can be tested. FUNDAMENTALS The concept of fluids exhibiting a resistance to flow or viscosity originated with Newton. For simple fluids, the laminar flow behavior can be completely described by viscosity. In this case, the viscosity is given by: ............(1) This relationship hold for a number of materials including most low molecular weight fluids. Fluids that obey Equation 1 are termed of interest in well stimulation do not exhibit a linear relationship between shear rate and shear stress. Fluids that exhibit a complex relationship between shear rate and shear stress are called non-Newtonian fluids. The plot in Figure 1 illustrates the various types of non-Newtonian fluids. For the most part pseudoplastic, viscoelastic, Bingham plastic and yield pseudoplastic-type fluids are the most important in well stimulation. Measurements of the fluid properties for most of these fluids are relatively straight forward, although accurately determining the yield point for Bingham or yield type materials is difficult.

The Mancos-Niobrara formation in western Colorado is estimated by the USGS to contain 66 trillion cubic feet of natural gas. Successfully developing this asset depends on understanding the geology, geomechanics, the impact of fracture length and height, conductivity, fracture spacing, and well spacing on estimated ultimate recovery. The Mancos-Niobrara has tremendous resource potential and is in the early stages of development in the study area. This paper discusses the development and application of a detailed numerical reservoir model to guide best practice development. Six wells drilled from two multi-well pads and hydraulically fractured to produce natural gas are the subject of this paper. This study provides a comprehensive evaluation and integrated approach to help optimize field development in this new emerging play. The reservoir model includes six wells on two pads. The reservoir was characterized using geochemistry, triple-combo logs, dipole-sonic logs, and formation images. Completion geometry and efficiency were evaluated by collecting data including micro-seismic fracture mapping, micro-deformation, mini-fracturing tests, and production logs. Different designs or treatment schedules were utilized during completion operations to provide additional information on the formation sensitivity to differing completion parameters. The numerical reservoir modeling performed in this study gives deference to the rich data collected. The model was used to estimate effective fracture lengths and heights, evaluate well communications, predict individual well performance, and identify areas for economic optimization. Created fracture half-lengths were estimated to be 900-1,000 ft. This result shows excellent agreement between history matching the hydraulic fracture treatment, micro-seismic monitoring, and production results. The reservoir model confirms direct hydraulic connections, modeled as a few high-conductivity pathways (‘pipelines’), crossing multiple wells that could result from the repeated enhancement of the same natural fracture network during different treatment stages. Production results show large performance differences among the wells despite the similarity in completion designs which is attributed to well interference and shared production. Therefore, it would be advantageous in future development―utilizing essentially the same completion technique, double well spacing to 2,700 ft., while still maintaining 75%-80% gas recovery factors over 40 years, and drilling half the number of wells. Production logging indicated that only 30% of perforated clusters were producing a significant amount of gas. The simulation sensitivity shows that significant gas production boost was possible, especially in the first five years, if cluster efficiency was increased. Fracture conductivity was found to be of secondary importance for short and long-term gas recoveries due to the low system permeabilities. Accordingly, the flexibility in diversion techniques and varying proppant size to increase cluster efficiency should be tested. The reservoir modeling also shows that only a portion of the gross formation thickness may be effectively produced implying that the effective fracture height may be less than 750 ft. measured by micro-deformation. This leads to a future opportunity of targeting the more liquids-rich upper Niobrara zones in addition to the lower gas-producing interval.

Successful application of hydraulic fracturing is dependent on obtaining the desired propped fracture length and conductivity. Post-frac pressure analysis methods are often used to calculate the apparent length and conductivity that were achieved by a fracturing treatment. Many times, the calculated conductivity values are a factor of two to five lower than had been predicted by the pre-frac design calculation. Occasionally values an order of magnitude lower than those predicted are found. Recent laboratory tests on proppants held at stress for long time periods at various reservoir temperatures resulted in much lower conductivity values than when generated with very short test times. The result of this testing program has been the development of a large base of conductivity data that are much more realistic than the data which have been in use for many years. This may help explain discrepancies in pre-frac predictions and post-frac calculations. In many cases, the treatment design will be altered appreciably by the use of more realistic conductivity data. In this paper, we will present comparisons of the old data and the more realistic values. We will also illustrate the significant effect that use of the new data can have on fracturing treatment design. In many applications the recommended proppant addition schedule will be much more ambitious. Some well conditions may result in the need for a stronger propping agent than had been predicted using less realistic conductivity data. Introduction In recent years, advances in the field of transient pressure analysis on hydraulically fractured wells will often allow an operator to make post-frac estimates of effective fracture length and fracture conductivity(1,2). No longer are the analyses based on "infinite conductivity" fractures where the calculated fracture length was typically less than 30 m. When these new "finite conductivity" analysis methods were first introduced, the fracture length and fracture conductivity values were often in significant disagreement with pre-frac predictions of computer design simulator models. More recently, refinements in analysis techniques, coupled with further experience in applying these methods, have resulted in improved calculations which yield a calculated fracture length that is usually in reasonable agreement with design simulators(3.4). This has not been the case with post-frac calculations of fracture conductivity, however, where pre-frac predictions continue to be much higher in many cases(3–6). In 1973, Cooke(7) published data indicating that brine and temperature will have a significant effect on fracture conductivity with time. Corrosion of test equipment and other problems interfered with later attempts to extend this work. The net result was that essentially all the conductivity data published by the industry has been at ambient test temperatures with short test times at each stress level(8,11). A few authors have tested at higher temperatures, but again using only short time durations at each closure stress(12,13). In 1986, McDaniel(14) published work that described how these experimental problems can be overcome. The paper also presented data that indicated "time at stress" may be a very important factor at any temperature, although the primary emphasis was at relatively high reservoir temperature (135 °C).

Hydraulic fracturing has been an important aspect on the successful exploitation of gas sandstone formations in Saudi Arabia. During the past decade, conventional formations were stimulated successfully with traditional low to moderate temperature borate crosslinked based fracturing fluids. As the development of the existing fields continue into deeper formations and the exploration activities are inclined toward unconventional reservoirs, new challenges are experienced from lower permeabilities and higher temperatures. The conventional borate crosslinked gels are no longer the choice of fracturing fluids for extreme bottom-hole conditions. To overcome these challenges, an improved, salt-compatible, low-polymer, organometallic crosslinked-gel (CMHPG) as fracturing fluid has been introduced for high-temperature (HT) wells. The novel HT fluid provides excellent proppant transport capabilities at temperatures ranging from 60 to 375 °F, while using fracture fluid requires less base polymer that results in less formation damage and higher retained conductivity of the propped fracture. This property is especially valuable in low-permeability reservoirs, where extended fracture lengths are typically required to maximize reservoir contact and enhance production. Additionally this fluid has been enhanced with a microemulsion surfactant to obtain a higher load recovery and also a novel clay stabilizer specially designed for tight gas and shale formations. This paper addresses the successful application of this enhanced fracturing fluid in HT and tight gas wells of Saudi Arabia along with its post-treatment evaluation comparing dimensionless productivity index between fracture treatments with new and conventional fracturing fluids.

SummaryThis study develops deterministic, exact equations relating fracture frequency (P10), density (P32), and length and width dimensions of rectangular and elliptical fractures from borehole observations. These general equations are applicable to both image logs and cores. A Monte Carlo type of simulation model generated the stochastic data used to derive the equations. The equations use five basic parameters relating frequency to density: borehole diameter, fracture length, fracture width, fracture angle with borehole axis (β), and the rotation angle of the long fracture axis within the fracture plane (γ). For both general equations, density corrections can be applied to individual fractures to find density. Fracture porosity is calculated on a per–fracture basis by applying aperture to density corrections. Both equations match the model to within the small standard deviation between simulations. In addition, the elliptical equation generally agrees with the existing exact theory.The study also develops methods for calculating fracture height (width) and length for rectangular fractures. Fracture height and length are calculated by observing the borehole–enclosed height and length and comparing them with the borehole–enclosed area. The calculation of fracture size is extended to estimate block height and length (block–face size.)These relationships cover a wide range of fracture size and orientation vs. borehole diameter. The theory is valid from small boreholes to tunnels. The general equations consider fractures as planar objects with length and width dimensions and negligible aperture compared with the other dimensions. Fracture aperture is applied, on a per–fracture basis, after the density correction to calculate fracture porosity. In addition to density and porosity calculations, an existing method for fracture–frequency prediction is improved by applying the general relationships.The methods described here are demonstrated using an image log from a vertical well from British Columbia, Canada. In this well, an image log was run over the Triassic section, including the zone of interest, the Montney Formation. Although the average fracture size in the Montney was very large, possibly on the order of tens of meters, they had a much smaller block–face size, on the order of a few meters, which could explain some of the production aspects from this formation.

A previous work(1) described refinery plugging caused by volatile phosphorus components originating from phosphate ester oil gellants. Also documented were two successful field trials of new phosphonate ester oil gellants shown to address this problem. Another paper(2) presented the results of additional field testing of phosphonate ester gellants directed at the optimization of cost and performance. A maximum of 0.5 ppm volatile phosphorus in crude specification has been proposed to address costly unplanned refinery shutdowns. This specification is based on what is considered achievable through a combination of new chemistry and typical field dilution. However, this specification is based on average concentrations of phosphorus added to the oil to gel it and assumes the oil is phosphorus free to begin with. In some flowback studies, total and resulting volatile phosphorus concentrations greatly in excess of that added have been observed. In addition, refinery plugging is more the result of total phosphorus throughput than peak concentrations at any one point. Therefore, an understanding of total phosphorus recovery in addition to peak concentrations is needed. The objectives of this paper are to study:Total percent recovery of phosphorus originally added as phosphorus based gellant;Total percent recovery of volatile phosphorus as a function of total phosphorus;Peak concentrations of total and volatile phosphorus;Phosphorus concentrations in new and reused fracturing fluids before the addition of gellants; and,Potential explanations for phosphorus concentrations significantly higher than those originally added, which include phosphorus removal resulting in a positive/negative initial mass balance and long-term phosphorus removal with respect to overall mass balance. Introduction Unconventional gas reservoirs, including tight gas, shale gas and coalbed methane, are becoming critically important components of current and future gas supply. These reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low-permeability reservoirs may result in the loss of effective fracture half-length caused by phase trapping associated with the re-tention of the introduced water-based fluid into the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is, or ever has been, present) because of the strong spreading coefficient of water in such a situation. The retention of this increased water saturation in the pore system can restrict the flow of produced gaseous hydrocarbons such as methane. Capillary pressures of 10 ? 20 MPa or higher per thousand can be present in low-permeability formations at low water-saturation levels. The inability to generate a sufficient capillary drawdown force using the natural reservoir drawdown pressure can result in extended fluid-recovery times or the permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs may also reduce permeability and associated gas flow through a permanent increase in water saturation of the reservoir. Secondary costs such as rig time for swabbing can add to the negative economic impact. The effects of fracturing fluid retention on gas flow in the fracture face can be as important a consideration as fracture conductivity when designing a treatment.

Complex fracture technology is key to the successful development of unconventional oil and gas reservoirs, such as shale. Most current studies focus on how to improve the complexity of the fracture network. It is still unclear whether proppant can enter the branch fractures at all levels after the formation of complex fractures. The effects of construction displacement, proppant particle size, proppant density, fracturing fluid viscosity, sand ratio, and other factors on proppant migration in single fractures and complex fractures were studied using an experimental device independently developed by the laboratory. The results show that the lowest point height of the sandbank and the equilibrium height of the sandbank are directly proportional to the particle concentration and density, respectively, and inversely proportional to the displacement and fracturing fluid viscosity. The equilibrium time of the sandbank is inversely proportional to the displacement, particle concentration, and density, respectively, and proportional to the viscosity of the fracturing fluid. Under the same experimental conditions, the larger the branch angle, the smaller the height of the main/secondary fracture sandbank. In the design of the fracturing process, fracturing fluid with varying viscosities and proppant with different densities should be selected according to the formation conditions and fracturing targets. In the face of long fracture lengths, the combination of low-viscosity fracturing fluid with an appropriate viscosity and low-density proppant can meet the goal of placing proppant over long distances and effectively supporting fractures over extended lengths. Subsequently, high-density proppant or reduced construction displacement are adopted to usefully support fractures in the near-wellbore area. The results of this paper can provide theoretical support for proppant selection and fracturing program design.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117538, "Applying Science and Best Practices To increase Production and Optimize Economics in a West Texas Gas Field - A Canyon-Sand Case Study," by Kelly Blackwood, SPE, (now with Encana Oil and Gas), and Kaylene Williamson, SPE, Highmount Energy; Terry Palisch, SPE, and Mark Chapman, SPE, Carbo Ceramics; and Mike Vincent, SPE, Insight Consulting, originally prepared for the 2008 SPE Eastern Regional/AAPG Eastern Section Joint Meeting, Pittsburgh, Pennsylvania, 11-15 Octo ber. The paper has not been peer reviewed. Hydraulic fracturing is the most popular and successful stimulation treatment in the petroleum industry. Fracturing technology has opened numerous unconventional hydrocarbon frontiers that, were it not for this process, would be uneconomic to develop. However, designing the optimal hydraulic fracture is anything but an exact science. The industry relies on many simplifying assumptions that assist in making expedient decisions but can prevent reaching a truly optimized treatment. The full-length paper outlines the approach taken by one Canyon sand operator to apply sound science and best practices to meet their financial. Introduction A field trial comparing the performance of 20/40 economy-lightweight-ceramic (ELWC) proppant to 20/40 Brady sand was completed in 2006 and 2007 in the Canyon sand, Sutton County, Texas. The trial was initiated after modeling suggested that the current hydraulic fractures were conductivity limited. Twenty-one wells in close proximity to each other were included in the study. Production analyses were performed after all wells had at least 1 year of post-fracture production. Both raw production and production normalized to reservoir quality were analyzed, and both indicate that the wells stimulated with ELWC proppant significantly outperformed the offset wells that used Brady sand. Several economic yardsticks then were evaluated in the full-length paper. Canyon Sand The Canyon sandstone is productive in several fields, including the Sonora, Sawyers, Shurley, and Aldwell fields, with first production occurring in 1952. The Canyon-sandstone trend occurs basinward of the western margin of the Eastern shelf in west Texas. The sandstones were deposited from the Eastern shelf into the Val Verde basin. The reservoir is oil prone adjacent to the Midland basin and gas prone adjacent to the Val Verde basin. The vast majority of the sandstone members are fine- to medium-grained quartz lithic arenites.

Response characteristics and novel understandings of dual induction logging of horizontal wells in fractured reservoirs