This paper discusses the integration of microseismic fracture mapping with fracture engineering, well production results and offset well interference data in the Overton Field, East Texas. Target formation is the Taylor Cotton Valley at depths of about 11,500 ft. The fracturing program in this field included different types of waterfrac and linear gel hybrid frac treatments, which were compared to evaluate the optimal type of fracture design in this area. Detailed production analyses of were performed to evaluate well performance in conjunction with fracture geometry measurements provided by microseismic fracture mapping results, calibrated fracture modeling and direct production interference data, which provided interesting insights into effective fracture lengths, reservoir quality, and drainage areas.

This paper shows a comparison of dual-array microseismic maps with single-well maps for horizontal wells in the Barnett shale. Results from two test cases showing gel and water fracturing maps are given and compared with initial production. Dual-array mapping provides for a much larger areal coverage and increased accuracy when accurate bottomhole locations and velocity structure are available, but do have trade-offs that need to be considered.

Hydraulic fracturing is often necessary for commercial production of natural gas from coal beds. In recent years, much effort has been spent in the area of completion design, fluid chemistry, proppant selection and job procedures in an effort to optimize our understanding of stimulation behavior in coal bed environments. Coal bed gas is an emerging and important resource: over the ten-year period from 1990 to 2000, the number of wells producing coalbed gas in the U.S. Lower 48 has increased from 2,982 to 13,985 and annual production from these wells increased from 195 Bcf to 1352 Bcf (more than 7% of U.S. dry gas production).

The standard industry practice for the past 5 years in the Helper Utah Field has been to stimulate coals in multiple stages in order to ensure that all zones were adequately stimulated. Even though many indicators and models implied "uncontrolled" fracture height growth, there is still much discussion on whether or not height coverage is lost to a horizontal "slippage" component. The usefulness of three-dimensional hydraulic fracture simulators to model and predict fracture geometry in coal-beds has been restricted by a general lack of knowledge about fracture growth and dimensions in these unconventional reservoirs.

A large hydraulic fracture diagnostic project was undertaken in the summer of 2001, which integrated fracture diagnostic technologies including tiltmeter (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 3-D 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 due to the success of waterfrac 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

Real-Data/Real-Time analysis of fracture stimulation data is a valuable tool for fracture engineering in the field, especially in fields where there is a large variation in well to well behaviour. The differences in behaviour can be due to reservoir heterogeneity, differences in depletion, lateral heterogeneity, different fracture growth mechanisms and varying completion types. In such cases, a standard "cookbook" fracture design is not possible.

In this paper, the authors present a case study based on 12 fracture treatments in 10 wells in the Arman field, a moderate permeability oil reservoir with significant water and gas production. The field is also under water flood in some zones, leading to large variations in reservoir pressure from zone to zone. We first look at using real-data analysis to calibrate a fracture growth model by comparing predicted results for a fracture treatment design with the actual pressure data recorded during the treatment. We also give examples of dealing with such real-world issues as operational problems, reservoir heterogeneity, tortuosity, multiple fractures, high spurt loss and calibration of tip-screenout behaviour, and show the successful application of a fracture modelling tool to deal with these issues.

This paper presents a case study of a successful hydraulic fracturing campaign in the Arman field in western Kazakhstan: the first large scale campaign ever performed by a western service company in Kazakhstan. The Arman field is a mature field, originally delineated in Soviet times, and currently producing from four of the original vertical wells, and from newly drilled deviated (30 to 60 degree) wells. The field is currently under waterflood in three of the producing zones, but formation water is also being produced from wet zones. There is significant gas production, since the wells are all producing below the bubble point, either with ESP's or rod pumps.

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.

This paper is a case history describing fracture optimization of low-permeability highly-stratified stacked turbidite sandstone reservoirs of the B interval of the Elk Hills Field. The occurrence of high-permeability, high-pressured water saturated sands immediately above and/or below the objective oil sands poses a major challenge.

Integration of improved petrophysical understanding, geoscience techniques, hydraulic fracture model calibration and on-site, real-time execution has achieved a two-fold oil production increase in the south east nose area of the field while limiting water production to a 40% increase. Downhole tiltmeter measurements are incorporated to calibrate the fracture model and limit fracture height growth, thus regulating fracture conductivity to the oil saturated reservoirs, and minimizing contact with the adjacent wet zones.

To date, results from surface tiltmeter1 measurements completed during twenty six fracture stages have been used with the downhole tiltmeter2 data and reservoir characterization to optimize the ongoing redevelopment from a peripheral waterflood to a pattern flood.

This paper presents detailed analyses of hydraulic fracture microseismicity and engineering data created during the joint operator Cotton Valley Hydraulic Fracture Imaging Project in East Texas. The project was a joint operator consortium with the goal of evaluating hydraulic fracture growth of conventional "sandfracs" and waterfracs with very low sand concentrations. A variety of fracture diagnostic tools were used on ten fracture stages in three wells including microseismic and downhole tiltmeter fracture mapping, fracture modeling, stress tests, radioactive tracers, pressure transient well tests, and production logging. We also introduce a methodology that uses full triaxial waveform analysis of the microseismic signals to obtain seismic source parameters, which characterize failure modes during hydraulic fracturing. This information could potentially be used for a detailed description of fracture geometry, growth and complexities and may give some indications about created versus propped fracture lengths. The paper compares the microseismic created lengths and propped lengths with those from frac models.

This paper documents the application and final results of using surface and downhole tilt mapping to monitor and evaluate downhole drill cuttings disposal at the Joint Industry Mounds Drill Cuttings Injection Field Experiment Project. Knowledge of the created hydraulic fractures was critical for determining the placement of "core-through" wells to evaluate the fracturing disposal mechanisms for both sandstone and shale intervals. Through "real-time" monitoring of the fracture it was possible to detect fracture height growth while the test was being performed and measure that the injected fluids stayed in the intended zone. Surface and downhole tiltmeter diagnostics have been widely used for mapping conventional propped and unpropped hydraulic fractures; however, this is the first application of the combination of surface and downhole tiltmeters to evaluate fracture geometry during drill cuttings disposal.

The application of tilt mapping will significantly aid in the advancement of both non-hazardous (drill cuttings and other oil field waste) and hazardous waste disposal by downhole injection. These applications will include: 1) "real-time" monitoring of the actual created fracture geometry allowing injection to be terminated before the fracture grows out of the intended disposal zone, 2) calibration of existing fracturing models by using the diagnostic results, and 3) aiding in the development of new models, if required, for disposal situations.

The combination of surface and downhole tilt fracture mapping determined the location (azimuth and depth) and geometry (height, length and width) of the hydraulic fractures created by injecting drill cuttings. On-site real-time monitoring (with tiltmeters installed in an observation well close to the injection well) indicated that the fractures did not grow out of the target intervals. These results were confirmed by subsequent "core-through" evaluation wells.

The disposal of waste by downhole injection has proven to be an economically and environmentally attractive solution. The key to moving this method forward is to develop and implement technology that will convince the regulatory community that this is safe, reliable, and permanent. Tiltmeter fracture mapping has played a key role to date, and will continue to, in achieving this goal.

In recent years there have been numerous advances in fracture mapping/diagnostic technologies. This paper details the state-of-the-art in applying both conventional and advanced technologies 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-hole & cased-hole logs, surface & 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 various 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.

This paper presents both downhole and surface tiltmeter hydraulic fracture mapping results of five fracture treatments (in two wells) in the Clearfork formation located in the North Robertson Field, West Texas. This field is under waterflood and both injectors and producers are generally fracture treated in three stages at depths of roughly 6,000 to 7,100 feet. Surface tiltmeter mapping was performed on all five treatments to determine hydraulic fracture azimuth and dip. Downhole tiltmeter mapping was performed on 2 treatments in one well to determine the fracture geometry (height and length). In addition, other diagnostic technologies such as fracture modeling and radioactive tracers were used and their results and conclusions are discussed in conjunction with tiltmeter mapping. Understanding hydraulic fracture growth is of critical importance for evaluating well placement and the risk of communication between producers and injectors and to assess fracture staging, perforating and well performance issues.

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.

This paper presents the results of a study conducted to improve hydraulic fracturing and field development in the Arcabuz-Culebra Gas Field in Mexico. Hydraulic fracture mapping was performed on four stimulation treatments using a combination of tiltmeters (surface and downhole) and microseismic imaging. Fracture mapping was complimented by 3-D fracture modeling and geomechanical modeling. Data analyses resulted in recommendations regarding well positioning and hydraulic fracture design.

Conventional wisdom regarding fracture orientation 1 of steam fractures is that they grow along the same orientation as “typical” propped fracture treatments – i.e., perpendicular to the least principle stress direction. However, direct measurements (utilizing surface tiltmeter fracture mapping) show that the orientation of steam-induced fractures is very different from propped fractures. Steam fractures have been observed to grow predominantly along two distinct planes that are oriented 45° with respect to the preferred fracture plane. These two planes coincide with the planes of maximum shear stress. Steam fracture reorientation toward these two planes has thus far been directly observed in the South Belridge, Lost Hills, and Cymric Fields in the San Joaquin Valley in California.

The measured data also shows that the fracture orientation is sensitive to the injection rate. Above a “critical” rate (which most likely depends on horizontal stress bias, shear frac conductivity and fluid viscosity) fractures grow perpendicular to the minimum principle stress. Below this critical rate, however, fracture growth is along the two distinct maximum-shear orientations. Steam injection wells are especially vulnerable, as steam injection rates are generally low in comparison to propped fracture treatments. The proposed mechanism for steam fracture reorientation that we present in this paper is pore pressure elevation along a direction of enhanced permeability along shear fractures ahead of the fracture tip, which causes the preferential fracture growth direction to change along the direction of maximum shear stress.

Although fracture reorientation can provide an increase in reservoir access and production rates in areas where the “huff and puff”-technique is used, reorientation is detrimental for steamfloods, as “short-circuiting” may result and reserves may be bypassed.

The Lost Hills Field Diatomite has traditionally been developed using vertical wells completed with multiple propped hydraulic fracture treatment stages. As the main portion of the field is nearing fall development at 2 1/2 acres per producer, the search for additional reserves has moved out to the flanks of the field's anticlinal structure. Due to limited pay thickness, these flank portions of the field will not support economic vertical well development. The use of horizontal wells was determined to have the best chance to economically develop these areas of the field. To evaluate this development concept, three horizontal wells were drilled and completed over the time period from November 1996 to December 1997.

To assist with the horizontal well design and evaluation, several vertical data wells were drilled offset and parallel to the intended well path of each horizontal well. Additionally, two vertical core wells were drilled in line with the toe and heel of the horizontal well paths. These data wells were utilized to estimate properties such as in-situ stress profiles, pore pressure gradients, rock properties and fluid saturations, and to determine horizontal well vertical depth placement. The horizontal wells were then drilled in the direction of minimum horizontal stress (transverse to the preferred hydraulic fracture orientation) and completed with multiple- staged propped hydraulic fracture treatments.

During the completion of the three horizontal wells, hydraulic fracture growth behavior was characterized using surface tiltmeter fracture mapping and real-time fracture pressure analysis. In the third horizontal well, downhole tiltmeter fracture mapping was also used. This combination of fracture diagnostics provided significant insights into hydraulic fracture behavior, allowing diagnosis of anomalous fracture growth behavior and evaluation of remediation measures. Fracture diagnostics during the first horizontal well revealed an unexpectedly complex near-wellbore fracture geometry, a result of fracture initiation problems. These problems slowed the completion process and severely harmed the effectiveness of the fracture-to-wellbore connection. In the subsequent horizontal wells, a number of design and execution changes were made which resulted in simpler near-wellbore fracture geometry and a greatly improved production response.

The paper provides an overview of the completion and stimulation of all three horizontal wells, describes the lessons learned along the way, and discusses the implications for future Lost Hills horizontal well development.

The Lost Hills Field Diatomite has traditionally been developed using vertical wells completed with multiple propped hydraulic fracture treatment stages. As the main portion of the field is nearing full development at 2 1/2-acres per producer, the search for additional reserves has moved out to the flanks of the field's anticlinal structure. Due to limited pay thickness, these flank portions of the field will not support economic vertical well development. The use of horizontal wells was determined to have the best chance to economically develop these areas of the field. To evaluate this development concept, three horizontal wells were drilled and completed over the time period from November 1996 to December 1997

To assist with the horizontal well design and evaluation, several vertical data wells were drilled offset and parallel to the intended well path of each horizontal well. Additionally, two vertical core wells were drilled in line with the toe and heel of the horizontal well paths. These data wells were utilized to estimate properties such as in-situ stress profiles, pore pressure gradients, rock properties and fluid saturations, and to determine horizontal well vertical depth placement. The horizontal wells were then drilled in the direction of minimum horizontal stress (transverse to the preferred hydraulic fracture orientation) and completed with multiple-staged propped hydraulic fracture treatments.

During the completion of the three horizontal wells, hydraulic fracture growth behavior was characterized using surface tiltmeter fracture mapping and real-time fracture pressure analysis. In the third horizontal well, downhole tiltmeter fracture mapping was also used. This combination of fracture diagnostics provided significant insights into hydraulic fracture behavior, allowing diagnosis of anomalous fracture growth behavior and evaluation of remediation measures. Fracture diagnostics during the first horizontal well revealed an unexpectedly complex near-wellbore fracture geometry, a result of fracture initiation problems. These problems slowed the completion process and severely harmed the effectiveness of the fracture-to-wellbore connection. In the subsequent horizontal wells, a number of design and execution changes were made which resulted in simpler near-wellbore fracture geometry and a greatly improved production response.

The paper provides an overview of the completion and stimulation of all three horizontal wells, describes the lessons learned along the way, and discusses the implications for future Lost Hills horizontal well development.

This paper introduces a new fracture diagnostic technology that allows economic mapping of hydraulic fracture dimensions. The downhole tiltmeter fracture mapping technology requires the use of an offset wellbore(s) for running wireline-conveyed downhole tiltmeter arrays. For the first time, hydraulic fracture dimensions including growth during pumping can be measured at a relatively modest cost. In addition to providing fracture diagnostic data (fracture height, width and length), this new capability allows enhanced utilization of hydraulic fracture models because model predictions can be "calibrated" with in-situ observations of fracture growth.

The concept is quite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping involves measuring the fracture-induced deformation in a nearby offset well(s) and solving the geophysical inverse problem to obtain the created fracture dimensions. The technology follows the same principles as surface tiltmeter mapping, but the different array geometry and placement make it very sensitive to fracture dimensions and less sensitive to fracture orientation - just the reverse of surface tiltmeter mapping. This paper will explain the fundamental concepts, the implementation strategy (wireline conveyed tiltmeter arrays, data acquisition, processing, and modeling), and three field case studies of measured hydraulic fracture growth.

Recent improvements in tilt measurement techniques have greatly enhanced the resolution of hydraulic fracture-induced tilts, resulting in both greater mapping precision and an increase in the maximum mapping depth achievable with a surface tiltmeter array. With a previous depth limitation of around 6,000 ft., surface tiltmeter mapping was limited to areas with relatively shallow production. Application is greatly broadened now with a depth range down to 10,000 ft. In addition to the expanded depth range, there has been a marked improvement in the fracture mapping resolution.

This paper begins with an overview of the tiltmeter fracture mapping concept, highlighting both the strengths of this technique and its limitations. Following that is a description of the technical advancements made over the last three years to allow fracture mapping at far greater depths. Finally, two brief case studies are presented to demonstrate fracture mapping at great depth, and also to provide insight on hydraulic fracture growth behavior in two different environments. As the case studies make clear, fracture growth is far more complex than is generally assumed. Better understanding of these complexities can lead to significantly enhanced fracture stimulation practices.

In an increasing number of hydraulic fracturing environments, the petroleum industry has aimed for greater cost-effectiveness through the use of horizontal wells instead of conventional vertical wells. Several recent examples where this strategy has been evaluated include the giant Belridge oilfield where three horizontal wells have been drilled with an oblique orientation of roughly 700 to the preferred fracture orientation (determined by the existing well pattern), and completed with multiple propped fracture stages. In the past, industry has focused much attention on the connection between transverse hydraulic fractures and horizontal wellbores, primarily to avoid bridging screen-outs in the near-wellbore tortuous region. It was assumed that if the proppant could be placed successfully, then the fracture stimulation would be successful.

However, in the soft diatomite rocks in the San Joaquin Valley, a different problem has emerged. While premature screen-outs have not been a problem, the complex character of hydraulic fracture initiation in this rock has impeded the creation of a sufficiently conductive connection between the wellbore and the primary propped fracture(s). Integration of several diagnostic techniques (such as net fracture pressure analysis, tiltmeter fracture mapping, Hydraulic Impedance Testing (HIT), post-fracture production logging and video logging) reveals that the poor wellbore-to-fracture connection is due to the complex initiation of multiple hydraulic fractures along the horizontal wellbore, many of which are not effectively connected to the perforations. Despite appropriate far-field propped fracture penetration in the reservoir zones of interest, connection between the reservoir and wellbore is compromised because the main propped transverse fracture can be displaced 10 - 100 ft along the wellbore away from the perforated interval, This breakdown in wellbore-to-reservoir connection can severely damage well productivity, in extreme cases reducing individual stage contributions to zero. Figure 1 shows a conceptual sketch of what the actual fracture geometry induced from a single stage may look like. Note the small longitudinal fracture that runs along the wellbore and the many transverse fractures that leave the wellbore away from the perforated interval.

As petroleum production from transversely fractured horizontal wells has been successful in other environments, it is believed that the severity of the problems encountered with these wells was due the specific environment conditions (3D-stress state, rock properties, poor cement quality, etc.). However, these same problems are likely to occur, perhaps to a lesser degree, in many environments.

Conventional wisdom regarding horizontal hydraulic fractures is that they are common in shallow environments but that they generally do not occur below a "critical" depth of about 2000 ft. However, direct measurement of hydraulic fracture orientation utilizing tiltmeter fracture mapping on well over 1000 fracture treatments has shown that hydraulic fracture growth behavior is much more complex than implied by this simple "rule of thumb".

Horizontal hydraulic fractures are far more common than generally believed. This paper documents the widespread occurrence of horizontal fractures in two classes of environments: (1) reservoirs with high horizontal stresses, including an example at 7,500 ft.; and (2) reservoirs undergoing Enhanced Oil Recovery (EOR) where the distribution of the overburden load (vertical stress) has been altered such that horizontal fractures are created even when fracture pressure gradients are well below the overburden gradient as estimated from an integrated density log.

Fracture mapping data is presented from three different fields. The Lost Hills Field in California exhibits a curious stress state where the shallowest zones at the top of the thick diatomite reservoir (1000 - 2000 ft.) yield near vertical hydraulic fractures, but stimulating the deeper zones often creates horizontal hydraulic fractures due to a stress state "reversal" with depth. Fracture orientation data is also presented from the 7,500 ft. deep North Shafter Field where one treatment resulted in a (near) horizontal hydraulic fracture(s) that resulted in a very early premature treatment screenout, in contrast to another nearby fracture treatment where a dominant (near) vertical fracture was created and there was no difficulty placing all 400,000 lb. of proppant. These two fields illustrate "unconventional" original insitu stress states that result in significant horizontal fracture growth at depth. The third example presented, in the massive Belridge oil field, illustrates a much different phenomenon where the original stress state generally resulted in near vertical hydraulic fractures throughout the entire interval. However, secondary recovery has sufficiently altered the stress state such that horizontal fracture growth is becoming very significant. Direct fracture intersection of nearby wells has confirmed the creation of horizontal hydraulic fractures in many wells in the Belridge Field, even when the observed fracture gradients are well below the integrated density log estimates of the overburden stress. We believe that this is due to a "room and pillar" vertical stress state that is created by the highly variable reservoir pressure profile induced by secondary recovery (waterflooding), with a lower local vertical stress around producer wells and higher vertical stress around injector wells. illustrates the tremendous impact that horizontal hydraulic fracture growth can have on hydrocarbon recovery for both primary and secondary production. Horizontal fractures can severely reduce fracture treatment coverage in thick gross pay intervals, particularly when vertical permeability is impaired. In secondary recovery, horizontal fractures can greatly reduce water/steam flood sweep efficiency and leave large parts of the reservoir unswept. Horizontal fractures can also be far trickier to place proppant in and, therefore, lead to many premature treatment screenouts. Although these issues are rarely consideredError! Bookmark not defined., fracture and completion design should be significantly altered if horizontal fracturing is occurring.

This paper describes the results from the Pakenham Field effort at fracture stimulation engineering which incorporated, to the greatest extent possible, the results of actual measured field data. Measured data included: formation closure stress in payzones and bounding shales; numerous pre-frac diagnostic injections; measurement of actual perf friction and near-wellbore fracture tortuosity reflected bottomhole pressure and real-time net pressure data on many treatments; post-frac pressure build-up tests; and (early) post-frac production data. We feel that the large amount of measured data allowed us to increase our confidence in the veracity of the results by greatly reducing, the requirements for unsubstantiated physical assumptions.

Measurement of the sand-shale closure stress contrast and the relatively high net fracturing pressures (compared to the closure stress contrast) revealed that fractures obtained in most of the treatments were much shorter and less confined than we originally expected: the fracture half-length was about 200 to 300 ft (instead of about 600 ft), which is consistent with estimates from post-fracture pressure build-up tests.

Based on these measurements, Chevron's fracturing practices in the Pakenham Field could be carefully reviewed to enhance fracture economics. Supported by the real-data fracture treatment analysis, several changes in completion, fracture treatment design and data-collection procedures were made, such as: (1) changing from CO2-foam to Borate crosslinked gel; (2) reducing the perforated interval to help minimize the simultaneous propagation of multiple hydraulic fractures; and, (3) reducing the pad fluid size, as fluid leakoff from the fracture into the formation was relatively low.

This paper should be regarded as only a first step towards fracture treatment optimization in the Pakenham Field. Further fracture treatment optimization will continue throughout the development of the Pakenham Field. Although it is still too early to quantify production benefits of implementing these real-data-based treatment changes, modest cost savings have been realized on the newly completed wells. Introduction

Too often in this industry, the engineering of hydraulic fracture stimulation begins with making a number of broad, but unsubstantiated, assumptions about hydraulic fracture growth in the reservoir in question -- such as confined fracture height, or radial fracture growth, or assuming an in-situ stress profile and running a favorite 3-D fracture model. After these broad assumptions regarding hydraulic fracture growth are made, and a particular simulation model is chosen, the engineer then embarks on detailed "studies" of the (economic) optimum designed fracture length; the appropriate completion strategy; fluid and proppant selection; detailed treatment schedules; and procedures (if any) for post-treatment evaluation. While motivated by admirable principles, these "studies" often fall short of their goals due to grave errors in the unsubstantiated assumptions that were initially made.

Chevron intended to verify these basic physical assumptions as early as possible during the development of the Pakenham Field (West Texas), especially in the Wolfcamp A2 sand, and to a limited extent in the Wolfcamp D sand. Pakenham engineers in Midland (from Chevron and their local service company alliance partner) desired to utilize the Gas Research Institute's (GRI's) Advanced Stimulation Technology (AST) as the main "tool" to evaluate and enhance their fracturing practices. The main concept behind AST is collecting and utilizing measured (real) hydraulic fracturing data. AST provides a methodology and an engineering tool to approximate fracture dimensions and to identify critical fracture design issues during and after a fracture treatment. A vast number of authors have reported positive results from real-data fracture treatment analysis.

A wide variety of hydraulic fracture strategies are utilized by producers of Southern San Joaquin Valley diatomite formations. In most cases, producers have developed a standardized fracture design over the last five to ten years, which is applied on a mass scale in several large field developments. The rock is very forgiving from a fracture design and proppant placement standpoint; this forgiving nature belies the extreme complexity of diatomite fracture behavior. Most producers have an idea or estimate of the created fracture geometry. However, for the most part, these geometry estimates are not well-founded from the standpoints of fracture pressure analysis or reservoir production response.

This paper presents a case study of fourteen fracture stages in four wells, located in a closely spaced (5/8 acre) Belridge Diatomite waterflood. In this project, Crutcher-Tufts chose to evaluate a new completion strategy with shorter wells, fewer fracture stages, and a limited interval (point source) perforation technique. Twelve minifrac injections and fourteen propped fracture stages were evaluated using a combination of real-data (net pressure) fracture analysis and surface tiltmeter mapping. The minifrac injections were independently performed and evaluated before the propped fracture treatments, to identify stages with unacceptable fracture reorientation, and to compare these orientations with the larger volume propped frac injections.

Based on unacceptable minifrac orientation and marginal petrophysical log properties, one propped fracture stage was not performed. Even with the point source (limited interval) perforation strategy, the simultaneous growth of competing multiple fractures was required to explain observed fracture net pressure levels. Tiltmeter fracture mapping to showed multiple fracture growth in the form of vertical and horizontal fracture components. Several treatment behaviors were observed that are believed related to whether fracture growth was centered in the perforation interval or whether the induced fractures grew predominantly upward or (downward) away from the perforated interval. Average propped fracture half-length for the moderate-sized treatments pumped was estimated to be about 100 feet. With variations in fracture height growth behavior, the "point source"' perforation strategy is believed to have resulted in somewhat uneven, but reasonable height coverage of the target diatomite interval. Well production response supports this interpretation. In future wells, a multiple point source, limited-entry completion strategy may prove to obtain better, interval coverage.

Chevron has performed over 200 refracture treatments m the diatomite reservoir within the Lost Hills field. Most treatments have consisted of refracturing intervals originally stimulated with less than adequate fluid and proppant volumes to efficiently deplete the reservoir. Many of these refracture treatments show production and pressure responses similar to new development wells completed in virgin" reservoir. Recently, from 1990 to 1993, four new wells (post 1986) with modern initial fracture treatments were refractured in the same intervals with treatments similar (fluid and proppant volumes) to the original fracture treatments. All wells responded with post refracture production response equal to or slightly less than that of the original treatments. On the average these wells showed production increases of 50 BOPD over the previous daily rates of approximately 10 BOPD.

An effort began in 1993 to investigate possible reasons for the apparent "virgin" production response that resulted from the refracture treatments. A number of potential mechanisms were considered, including dramatic fracture conductivity degradation of the original propped fracture treatments; greatly enhanced fracture length growth upon refracturing; and stress change induced reorientation of the refracture treatments along a different fracture plane than the original fractures. This latter mechanism was considered the most likely mechanism and a program was designed to gather the necessary data for positive determination. Because Chevron had previously utilized tiltmeter fracture mapping on over 100 propped fracture treatments in the Lost Hills Diatomite, there existed ample original fracture treatment orientation data for comparison with fracture mapping data from refracture treatments.

In the Spring of 1993 tiltmeter fracture mapping was performed on five refracture treatments. All five of the refracture treatments propagated along a significantly different orientation than the original fracture treatments in these wells. Refracturing along a different fracture plane from the original fracture plane has dramatic implications for production strategies of both primary and secondary recovery. The tiltmeter fracture mapping results, production data, calculated reservoir stress changes, and proposed mechanism for refracture reorientation are all presented in the paper.

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.

This 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. Coupled 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 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 since considerable microseismic activity occurs around the tip as it propagates.