Abstract The Bakken boom in North Dakota is currently focused on the Central Basin area where around half of the drilling rigs in North Dakota are now operating. What makes this area different compared to previous areas of Bakken development is that there is only minor structural variation and significantly less naturally induced fracturing as compared to the higher permeability rock facies that exist in the sub-reservoirs of earlier Bakken development such as at the Elm Coulee field in Montana or the Sanish and Parshall fields in North Dakota. As a consequence, the role of the well's completion and stimulation design has a greater significance and impact on well productivity and ultimate recovery. Different companies have taken very different approaches to well design using either plug and perf or ball and sleeve completions, and a variety of fracture designs with slickwater, hybrid or cross-linked gel fluids and a variety of proppants from 100% natural sand to 100% ceramics. As a consequence, it is not uncommon for different operators to have over a 2 million dollar difference in their AFE's solely because of the differences in approach to the well's completion and stimulation design. The authors have chosen to apply "advanced completion and stimulation designs" which are designed to maximize the reservoir contact area (slickwater and plug and perf) and optimize the conductivity (ceramic proppant at relatively high volumes).1,2 In order to benchmark performance of its completion and stimulation program the authors in 2010 developed a production and completion database of all wells completed in the Central Basin using publicly available information from the North Dakota Industrial Commission's records augmented by additional completions information obtained directly from the operators. From an initial dataset of ∼30 wells the database has been updated monthly and has now grown to over 1100 wells in the Central Basin from 28 operators. Benchmarking of completion performance has been performed using the above database together with a Petra geological database developed from all publicly available logs in the Central Basin (∼500 vertical wells which had been drilled and logged prior to the first Bakken horizontal well). Benchmarking of performance is somewhat subjective in the Bakken (as well as most reservoirs) due to variations in reservoir quality. Without geological input (reservoir quality), the acquired data were too scattered to achieve meaningful correlations to completion methods unless the area was limited to ensure similar reservoir quality for the wells being evaluated. By narrowing the analysis to very limited areas; this also reduced the input as to the number and type of completion methods being compared. Multivariate analysis methods, that included geological input, were used to benchmark performance over most of the Williston Central Basin, allowing comparison of the varied completion methods for 28 operators and over a thousand wells. Using multiple parameters an excellent correlation for completion methodology versus reservoir quality was obtained. While early analysis focused on 30, 60 and 90-day cumulative production; in the past year there have been enough wells to generate performance metrics based on 180 and 365-day cumulative production since over 600 wells have now been on production for at least a year. The analysis shows that companies with a greater completion spend are typically paying out the increased spend in 1 to 8 months depending on the area and these wells are still producing at significantly higher rates after one year of production. The declines of these wells also project a significantly greater EUR and hence have lower F&D costs per barrel of oil. This higher performance continues to hold after 365-days of production.

Abstract Surface deformation measurements have been used for years in oilfields to monitor production, waterflooding, waste injection, steam flooding, and Cyclic Steam Stimulation (CSS). They have been proven to be a very effective way to monitor the field operations and save money for operators wishing to avoid unwanted surface breeches, casing failures and excessive subsidence due to production. This paper demonstrates that more information can be extracted from surface deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level, so the areal distribution of volumetric deformation can be identified. First, a poroelastic model is presented to calculate the deformation due to the volumetric change in the reservoir. Then, a linear geophysical model is formulated to invert for the reservoir volumetric deformation from the measured surface deformation (or tilt). Constraints are added into the procedure as necessary to better resolve the inversion problem. After each inversion, the theoretical surface deformation (displacement, tilt, reservoir compaction and volumetric strain) can be calculated from the inverted volumetric deformation distribution which best fits the measured deformation data (or tilt) at the surface. The technique of mapping fluid flow using surface deformation was applied to real data from a cyclic steam injection project.

Abstract Utilization of direct fracture mapping technologies has greatly increased over the last few years, from the first real-time measurement of fracture dimensions in 1997 to the routine mapping of fracture dimensions on more than 500 fracture treatments per year in 2004.The development of commercial technologies1-5 to routinely measure fracture growth has greatly improved our fracture modeling capabilities, enabling us to distill the essential fracture growth behavior in many environments into calibrated fracture models. Calibrated fracture models combine complimentary strengths and weaknesses of fracture mapping and modeling.Fracture models provide the ability to predict how changes to a fracture treatment should alter fracture geometry6, but suffer from a tenuous and generally unknown relationship with reality.Fracture mapping provides a direct measurement of fracture geometry from a given treatment, but cannot be used to predict what might happen under a different set of conditions.By combining direct measurements with models, we can create calibrated frac models with superior predictive capabilities. Calibrated models have been developed for various regions and formations, and the improvements in predictive modeling capabilities have lead to a proliferation of calibrated fracture models throughout the industry.This has provided improved insight into fracture growth behavior in a diverse set of environments including the North Texas Bossier and Barnett shale, the East Texas Cotton Valley sands, and various formations in the Rockies, the San Juan basin and California. This paper discusses how fracture growth models can be improved using direct fracture geometry measurements and what changes in models have been necessary to accomplish this.We will also discuss minimum data requirements for calibrated models, discuss their main limitations and capabilities, and the strategies that are used to define calibrated models.Finally, we will present several case histories – comprising the results of over a hundred mapped treatments – to illustrate how these findings have been used to improve fracture treatment design, execution and economics in various formations and regions across the United States.

Summary A large hydraulic-fracture diagnostic project was undertaken in the summer of 2001 that integrated fracture-diagnostic technologies, including tiltmeter (i.e., surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett shale of north Texas. The detailed fracture-mapping results allowed construction of a calibrated 3D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed. The Barnett shale has seen a rebirth of drilling and refracturing activity in recent years because of the success of waterfracture, or "light-sand," fracturing treatments. This extremely low-permeability reservoir benefits from fracture treatments that establish long and wide fracture "fairways," which result in connecting very large surface areas of the formation with an extremely complex fracture network. Understanding the created-fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area, with its nonclassical fracture networks. Integrated-fracture diagnostics have led to the identification of new fracturing techniques, as well as additional refracturing and infill-drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface- and downhole-tilt fracture mapping allowed characterization of the created-fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior.

Abstract The Barnett Shale of North Texas is an ultra low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. As a result, techniques to optimize hydraulic fracturing effectiveness have evolved over the past decade. The first Barnett Shale "discovery" well, the C.W. Slay #1, was drilled in 1981 and it was almost 17 years before any significant commercial success was found in the Barnett, so the Barnett is a relatively new play. In fact, 75% of the producing wells in the Barnett have been drilled since 2000. In 1995, when the USGS was performing a gas in place assessment of the significant gas fields in the United States, the Barnett was not even evaluated. In 2002, according to the Energy Information Administration, the Newark East Field produced 202 Bcf, more than any other field in Texas, and was the 7th largest gas producer in the United States! In some areas of the Barnett, horizontal drilling has recently been applied in an attempt to optimize gas production. Issues such as nearby water bearing intervals, inadequate surface locations, improved gas production rates and cost per scf can, in some cases, be addressed by the use of horizontal wellbores. The goal is to maximize fracture network surface area in the targeted pay intervals, and in some areas, reduce the probability of excessive fracture height growth. Several horizontal completion techniques have recently been utilized, including single and multiple stage treatments with multiple perforation clusters in uncemented casing and multiple stage treatments performed in cemented perforated casing. In order to understand created fracture geometry for various completion designs, fracture treatments are often mapped with microseismic and tilt sensors. Production results from this pilot study of the first twenty-three horizontal wells in the same general "Core" area of the Fort Worth Basin are compared in addition to mapped fracture geometry from eleven of these with vertical wellbores. This paper will discuss drilling and completion strategies, look at fracture network areas obtained from each, and then compare and contrast the fracture effectiveness with the standard procedures used in vertical Barnett wells.

SummaryThis paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Along with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid-saturated reservoirs experience much more widespread activity than do gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture, because considerable microseismic activity occurs around the tip as it propagates.

Anadarko Petroleum Corporation has conducted a study to improve hydraulic fracturing and field development in the Bossier sands in the East Texas Basin. As part of this study, hydraulic fracture mapping was performed with microseismic imaging on three wells completed in the Bossier sands.Microseismic fracture mapping is an emerging technology to optimize development of hydraulically fractured reservoirs. This paper demonstrates the use of microseismic mapping under high temperature (300°F) conditions. It also demonstrates how the directly measured results can be implemented to calibrate a 3D fracture growth model.The study shows mapping results for waterfracs and hybrid fracture treatments (which utilize slickwater to generate the fracture geometry and crosslinked gel to transport the proppant) in the Bossier. Fracture azimuth was fairly consistent for the three wells and fit with earlier surface tiltmeter mapping result in this area. Fracture growth asymmetry was observed and is discussed in the paper. Payzone coverage was generally good but could be improved and created fracture lengths varied significantly between wells.

Abstract The Rose field in central California produces oil from the McLure shale, a low permeability overpressured quartz-phase siliceous shale interval at 8000’ depth. The field has been developed with horizontal wells, completed with an uncemented liner and a single hydraulic fracture treatment to cover the average 2500’ lateral length. Based on initial vertical well experience in the adjoining North Shafter field, this horizontal well strategy greatly improves the ability to place hydraulic fracture treatments, and improves well economics by accessing a greater volume of reservoir rock per well. However, the half-mile long completion interval and the uncemented liner unavoidably add uncertainty to fracture treatment distribution along the lateral. Using limited entry perforation strategy, does the completion technique effectively stimulate the entire target lateral interval? To assist with answering this question, the fracture diagnostic of surface tiltmeter fracture mapping was used to evaluate fracture growth during the nine fracture treatments. Tilt results include fracture orientation and the approximate location and volume distribution of fracture components along the lateral. The original intention of the uncemented liner strategy in the McLure shale was to align the wellbore with the preferred fracture orientation, thus resulting in the initiation and propagation of a simple longitudinal fracture along the entire lateral. However, the actual fracture growth pattern was found to be much more complex, with vertical fracture components in two orthogonal directions, and a significant horizontal fracture component. Considering overall averages, about 45% of fracture volume was contained in transverse fracture components (~N60°W), while 35% of fracture volume was in longitudinal components (~N30°E), and the remainder in horizontal fractures. This complex multiple-component fracture growth is believed to be due to a small in-situ stress bias, combined with the impact of the completion technique and the naturally fractured character of the McLure shale. Fracture orientation and approximate component distribution along the lateral are compared and discussed for the nine treatments evaluated. Although the uncemented liner technique did not achieve the original intent of longitudinal fracture dominance, reasonable lateral coverage was achieved. Based on 1-year cumulative production, the limited dataset is suggestive, but not conclusive, that horizontal and transverse fracture growth is preferable to longitudinal fracture growth.

SummaryIn recent years, there have been numerous advances in fracture mapping/diagnostic technologies. This paper details the state of the art technologies in applying both conventional and advanced methods to better understand hydraulic fracturing and improve treatment designs. The initial portion of the paper describes the application and limitations of various diagnostic tools and methods, including well testing, net pressure analysis (fracture modeling), techniques that employ open-and cased-hole logs, surface-and downhole-tilt fracture mapping, microseismic fracture mapping, and production-data analysis. The bulk of the paper is dedicated to case histories that illustrate the application of these fracture-diagnostic technologies. The case histories include examples of how several fracture diagnostics can be used in concert to provide more reliable estimates of fracture dimensions and allow better economic decisions.

Abstract In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages. Successful proppant placement in the northern part of the Minami-Nagaoka Field in Japan has proved to be extremely difficult in the past1-2. During two propped fracture treatments pumped more than a decade ago, treatments failed miserably with only about 20% of the designed proppant placed before job termination due to premature screen-outs. Post-frac evaluation showed extremely high levels of net pressure of order 4000 psi prior to pumping any proppant – indicating that proppant placement problems were mainly occurred due to simultaneous propagation of very narrow multiple hydraulic fractures. Detailed pressure build-up tests and production data analysis confirmed the diagnosis of narrow multiple hydraulic fractures, which resulted in extremely poor propped fracture conductivity and non-economic gas production. As successful development of the northern part of the Minami-Nagaoka reservoir could significantly impact Japan's domestic natural gas production, another attempt at propped fracture stimulation was justified. In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field was successfully completed using six propped fracture treatment stages. The new treatments in Minami-Nagaoka focused on the ability to mitigate the adverse effects of multiple hydraulic fracture propagation and the accompanying severe near-wellbore fracture tortuosity. A major equipment mobilization was required for this treatment to be possible as part of this concerted effort. Many unconventional changes, including completion changes to obtain highest possible injection rates to enhance proppant placement, aggressive proppant slug strategy, extensive fluid testing, real-time fracture treatment analysis, careful perforation placement, quality control, extreme overbalance perforating, and use of small-grained proppant, resulted in successful stimulation and favorable production response. This paper discusses all these design changes in detail, and provides final results regarding the fracture geometries obtained and post-fracture production response.

Abstract Water injection and reservoir fluid production result in poroelastic stress changes that can dramatically alter the created fracture geometry on infill wells. This basic conclusion is not new. It has been documented in many different environments, and is supported by theoretical modeling. However, this paper presents for the first time a large data-set of 76 fracture treatments in a concentrated area that not only shows stress reorientation, but also shows how fracture reorientation depends critically on the pattern of injectors and producers and their interaction. This knowledge can be used to improve recovery in water injection projects that depend on closely spaced fractured wells. Data is presented from 76 fracture stages in 16 infill wells completed within a one-year period in Chevron's Lost Hills diatomite waterflood. Surface tiltmeter fracture mapping determined the fracture orientation (azimuth and dip) of the induced fractures, consisting of a vertical fracture component and a secondary sub-horizontal fracture component. This dataset clearly shows that the interaction between injectors (located in a line along preferred fracture azimuth) and producers results in a large-scale stress perturbation, producing a "room-and-pillar" stress structure. Both the fracture azimuth and the degree of secondary sub-horizontal fracturing are controlled by the location of infill wells with respect to nearby injector wells. Infill wells "inline" with injector wells yield fractures that grow close to the initial preferred fracture orientation. In contrast, infill wells that are "offset" from the line of injector wells yield highly variable fracture azimuths (often rotating towards injector wells) and greatly increased secondary sub-horizontal fracturing – both of which raise the risk of "short-circuiting" waterflood sweep. The data is presented and phenomenologically explained. A geomechanical model explains the observed stress changes, allowing predictive modeling of various infill-drilling scenarios in waterfloods to optimize recovery. For a number of project treatments, downhole tiltmeter fracture mapping was also used to evaluate fracture dimensions, and fracture pressure analysis was performed to link tilt observations with treatment pressure behavior. Poroelastic effects have resulted in increased stress magnitudes in some layers and decreased stress in others, impacting the created fracture dimensions (height, length, and width). A summary of the mapped fracture dimensions and pressure analysis findings is presented together with a brief discussion of the poroelastic impacts on fracture geometry.

Abstract In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages. While successful development of the northern part of the Minami-Nagaoka reservoir could significantly impact Japan's domestic natural gas production, successful proppant placement in this field has proved extremely difficult in the past1–2. During two propped fracture treatments pumped more than a decade ago, treatments failed miserably with only about 20% of the designed proppant placed before job termination due to premature screen-outs. These treatments exhibited net pressures up to 4,000 psi before pumping any proppant - the highest net pressure level that we have ever observed, indicating extremely complex fracture growth. Post-frac evaluation confirmed that proppant placement problems mainly occurred due to simultaneous propagation of very narrow multiple hydraulic fractures. Detailed pressure build- up and production test analysis confirmed the diagnosis of narrow multiple hydraulic fractures, which resulted in extremely poor (and vanishing) propped fracture conductivity and non-economic gas production. The new treatments in Minami-Nagaoka focused on the ability to mitigate the adverse effects of multiple hydraulic fracture propagation and the accompanying severe near- wellbore fracture tortuosity. Major equipment mobilization was required for this treatment to be possible as part of this concerted effort. Many unconventional changes, including completion changes to obtain highest possible injection rates to enhance proppant placement, aggressive proppant slug strategy, real-time fracture treatment analysis, gel testing for minimization of proppant damage, careful perforation placement, quality control, extreme overbalance perforating, and use of small-grained proppant, resulted in successful stimulation and favorable production response. This paper discusses all these design changes in detail, and provides final results regarding the fracture geometries obtained.

Abstract The recent and dramatic increase in direct fracture mapping has profoundly altered our understanding of how fractures really do grow. New fracture-mapping technologies have allowed us to often directly measure what we could previously only model or assume. However, perhaps the greatest limitation of these new direct fracture-mapping technologies (tilt and microseismic) is the need for a nearby offset well in which to deploy instruments. In many environments, most notably offshore, there is often no feasible way to employ an offset observation well. Treatment well tilt mapping uses the fracture (injection) well itself as the "observation" well. The goal, quite simply, is to expand the range of environments where direct fracture mapping can be performed. The concept is simple: if fracture-induced deformation can be measured thousands of feet away at the surface or in offset wells, then it most certainly can be measured in the fracture well itself. The measurement of fracture-induced tilt versus time and depth (via an array of 4 to 20 tiltmeters) can allow robust real-time mapping of fracture height and width. Fracture length is then "modeled" based on observed height and width, and inferred fracture fluid efficiency. Treatment well tilt measurements can also provide direct measurement of mechanical fracture closure aiding, among other things, the estimation of formation closure stress. Mapping from the treatment well brings its own set of limitations and challenges. One is conducting minute wellbore movement measurements in the midst of a highvelocity flow stream. We have solved this challenge. Field data shows that the fracture-induced tilt signals in the treatment well are several orders of magnitude higher than those measured in offset wells, and they are much greater than the fluid-motion noise. The trickier challenge is deploying tools in a well during the pumping of proppant. So far we have performed real-time treatment well mapping only on fractures with clean fluid (i.e., no proppant), however, efforts are underway to overcome the difficulties with proppant. This paper provides an overview of the basic concepts, shows some real-data from treatment well applications, and presents one brief case study.

Abstract In secondary and enhanced oil recovery projects, it is critical to determine if hydraulic fracturing occurs during water injection and, if fracturing occurs, to understand its associated impacts on oil recovery. If hydraulic fracturing occurs under normal injection operating conditions or, if the production and/or injection wells are fracture stimulated, knowing the orientation and dimensions of the created fractures are critical for determining the proper pattern alignment to optimize sweep efficiency. This paper presents the application and results of tiltmeter mapping techniques used at the Howard Glasscock East Unit (HGEU). Tiltmeter mapping was used to determine the existence, orientation, and geometry of created hydraulic fractures, as well as, the dependence of fracture length on the water injection rate. Tiltmeter fracture mapping identified that hydraulic fracturing occurs even at very low water injection rates (less than 250 BWPD) at the HGEU creating significant fractures (exceeding 400 feet of half-length). The mapping also showed that the length of the fractures was relatively rate independent over the range of rates tested. The HGEU waterflood pattern orientation, pattern spacing and injection rate guidelines were established based on these results.

Refracturing can be used to increase production in poorly fractured wells. A different application of this technology is to refracture wells with strong initial fractures. In this paper, we provide evidence of increased production due to refracturing two tight gas wells having deeply penetrating initial fractures. Surface tiltmeter measurements show refracture orientations at oblique angles to the azimuth of the initial fractures.