The paper reports on a U.S. Department of Energy sponsored project to evaluate deep gas well stimulation (Deep Trek Program). Under the Deep Trek Program, this study was conducted to evaluate the stimulation of deep wells onshore U.S. and Gulf of Mexico Shelf. The objective of the project was to assess U.S. deep well drilling & stimulation activity, review rock mechanics & fracture growth in deep, high pressure/temperature wells and evaluate stimulation technology in several key deep plays. This paper documents the location and level of deep gas development in the near future, discusses important issues and technology needs, and presents case histories of current stimulation practices for selected fields.

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.

The technology of hydraulic fracturing is faced with a conceptual transition from a classical single-planar fracture to a tortuous fracture network and simultaneously propagated multiple hydraulic fractures. This new concept is applied to analyses of two propped fracture treatments conducted in a volcanic formation. In both cases, the productivity was doubled, but the treatments themselves were unsuccessful, experiencing extremely high net fracturing pressures and very premature screen-outs.

The classical concept of a single-planar fracture could not explain either the fracturing-pressure behavior or the post-frac production rate/pressure. Adopting a multiple-fracture geometry resolves this problem. The fracturing pressures are successfully simulated, and the resultant fracture geometries are consistent with both the premature screen-outs and the post-frac production performances. Combined analyses of fracturing pressure and subsequent production performances firmly confirm the creation of multiple fractures in a volcanic formation.

Fracturing treatments using treated water and very low proppant concentrations ("waterfracs") have proven to be surprisingly successful in the East Texas Cotton Valley sand. This paper presents field and production data from such treatments and compares them to conventional frac jobs. We also propose possible explanations for why this process works.

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.

In 1994 and 1995, a series of hydraulic fracture stimulation treatments were performed in the McKittrick field Point of Rocks formation, a thick (>2000') marine sequence of low permeability (0.1 ml)) sandstone intervals separated by shales. The thick interval, 10,000' depth, and a formation temperature of nearly 300 F posed challenges to effectively completing the desired intervals.

In general, the initial series of treatments targeted large gross perforation intervals and incorporated a large pad fraction. The treatments included few procedures to enable engineering evaluation of actual in-situ fracture behavior, which was later found to be very different from theoretical or pre-job estimates. Due to some combination of fracture treatment design and reservoir limitations, the production response results from the 1994-995 treatments were mixed, resulting in marginal overall project economics.

In 1996, six additional fracture treatments were performed in a new Point of Rocks well, No. 733-17Z. However, a very different fracture design methodology was utilized, focusing on real-data (net pressure) analysis. Objectives for these treatments included a) to place a more effective stimulation than resulting from past efforts, b) to characterize fracture behavior so that reasons for success or failure were clear, and c) to begin the process of optimizing treatment design. A more surgical fracturing strategy was employed, targeting selected Point of Rocks intervals using small perforation intervals and multiple independent fracture stages. Changes were also made to more effectively place fracture conductivity in the intended intervals, including a dramatic reduction in pad fraction and an increase in maximum proppant loading. These changes were implemented with the support of real-time fracture pressure analysis, enabling on-site diagnosis of proppant placement problems, and final treatment design refinement based on observed fracture behavior.

Compared with past treatment results, the new hydraulic fracture strategy resulted in a dramatically improved production response. With initial commingled production of over 6 mmscfd and 200 bopd (over 1200 boegd), well 733-17Z had a larger IP and has not experienced the rapid production decline of the previous Point of Rocks wells. With this success, the use of real-data fracture engineering will continue; there remains significant potential for treatment optimization in further planned field development.

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.

Since 1988, over 1.3 billion pounds of proppant have been placed in the Lost Hills Field of Kern County, California in over 2700 hydraulic fracture treatments involving investments of about $150 million. In 1995, systematic reevaluation of the standard, field trial-based fracture design began. Reservoir, geomechanical, and hydraulic fracture characterization; production and fracture modeling; sensitivity analysis; and field test results were integrated to optimize designs with regard to proppant volume, proppant ramps, and perforating strategy.

The results support a reduction in proppant volume from 2500 to 1700 lb/ft which will save about $50,000 per well, totalling over $3 million per year. Vertical coverage was found to be a key component of fracture quality which could be optimized by eliminating perforations from lower stress intervals, reducing the total number of perforations, and reducing peak slurry loading from 16 to 12 ppa. A relationship between variations in lithology, pore pressure, and stress was observed. Point-source perforating strategies were investigated and variable multiple fracture behavior was observed.

The discussed approach has application in areas where stresses are variable; pay zones are thick; hydraulic fracture design is based primarily on empirical, trial-and-error field test results; and effective, robust predictive models involving real-data feedback have not been incorporated into the design improvement process.

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.

Hydraulic fracture orientation is critical to both primary and secondary oil recovery in low-permeability reservoirs. Incomplete and often overlapping drainage patterns under primary recovery, as well as inefficient sweep and premature water (or steam) breakthrough under secondary recovery are some of the common production problems that often result from hydraulic fracture reorientation. Often, hydraulic fracture orientation is measured on a few wells, and then generalized across the entire field under development. This characterization of regional fracture (stress) orientation is then assumed constant over the development life of the field. A wealth of recent observations have definitively shown that fracture (stress) orientation in low-permeability reservoirs can be profoundly affected by production activities.

Hydraulic fracture reorientation has been observed on dozens of staged fracture treatments (in several fields) under both primary and secondary recovery. A summary of collected field data from three extensive field studies is presented. The production impact of fracture reorientation on both primary and secondary recovery schemes is addressed; and strategies are presented which utilize the recent findings for both enhancing primary recovery and mitigating some common problems with secondary recovery.

The discussion of reorientation mechanisms is greatly enlightened by recent data which reveals a startling correlation between observed fracture reorientation and indirect measurements of reservoir compaction.

Waterflooding of California's diatomite reservoirs has heen extensively employed for two reasons: (1) to increase total recovery, and (2) to mitigate the potentially catastrophic effects of reservoir compaction and the resulting surface subsidence. Waterflooding has typically striven to replace each barrel of produced fluid with a barrel of injected water in order to achieve "zero net voidage." The extremely low permeability of the diatomite reservoirs, however, results in the generation of very significant reservoir pressure gradients during waterflooding, even under zero net voidage conditions. These extreme gradients in reservoir pressure, together with the reservoir compaction, result in significant changes in the local reservoir stress field. These local stress perturbations can, in turn, result in reorientation of hydraulic fractures on infill wells and possibly contribute significantly to the potential for wellbore casing failure.

This paper summarizes the (preliminary) findings from extensive field studies of hydraulic fracture orientation in diatomite waterfloods and related efforts to monitor the induced surface subsidence. Included are case studies from the Belridge and Lost Hills diatomite reservoirs. The primary purpose of the paper is to document a large volume of tiltmeter hydraulic fracture orientation data that demonstrates waterflood-induced fracture reorientation-a phenomenon not previously considered in waterflood development planning. Also included is a brief overview of three possible mechanisms for the observed waterflood fracture reorientation. A discussion section details efforts to isolate the operative mechanism(s) from the most extensive case study, as well as suggesting a possible strategy for detecting and possibly mitigating some of the adverse effects of production/injection induced reservoir stress changes - reservoir compaction and surface subsidence as well as fracture reorientation.

This paper illustrates a comprehensive and economical approach to the application of reservoir data to optimize stimulation designs. The paper documents the selective application of in situ stress tests and dipole sonic logs to provide accurate stress profiles that can be used in concert with standard log and mini-fracture data to improve stimulation designs.

Measured stress data on 3 wells were used to calibrate open-hole logs to provide an estimate of stress profiles throughout a 300 square mile area of the Moxa Arch. Dipole sonic log-derived stress profiles were correlated to measured stress data. Calibrated stress profiles from dipole sonic logs and the measured stress data were then used to develop a correlation between gamma-ray logs and in situ stress. The log-based stress data was improved with the addition of over 50 mini-fracture tests. The combination of selected stress measurements, dipole sonic logs, and mini-fracture treatments resulted in optimized stimulation designs and cost savings of over $100,000 per well.

This paper details the application of static tubing pressure measurements and on-site fracture modeling on over 70 wells in the Moxa Arch and Wamsutter areas in the Green River Basin, Wyoming. Specific examples illustrating the field procedures that evolved during a 2-year development program are presented, including on-site analysis of mini-fracture treatments, pad optimization, and treatment evaluation. Field applications include foamed and water based fluids in low and moderate permeability Frontier and Mesaverde gas sands. Bottom-hole pressure (BHP) measurements in all 70-plus treatments were obtained using a static tubing string, eliminating the inaccuracy of surface estimated BHP. Field data illustrate large variations in friction pressures that occur during many treatments which may lead to erroneous interpretations and premature job termination.

The quality of the data coupled with on-site three dimensional (3D) fracture modeling allowed field engineers to evaluate minifrac data and optimize pad volumes within 30 minutes. On-site modeling of the mini-frac data eliminated the need to measure fracture closure time which requires long shut-ins for many tight gas formations. This procedure includes the mini-frac volume in the pad volume, decreasing mini-frac costs and job delays.

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.

A case history of the Moxa Arch in southwestern Wyoming details the initial development on 640 acre spacing in 1977 through 1982 and the results of subsequent infill wells drilled from 1989 to 1992. The engineering evaluation includes an integration of 3D hydraulic fracture modeling and reservoir simulation with petrophysical and geological studies.

The study indicates that the Moxa Arch Frontier Formation is very heterogeneous with permeabilities ranging from 0.001 mD to more that 0.1 mD. The productive sand thicknesses vary from less than 10 ft to over 70 ft. Effective drainage areas range from over 640 acres to less than 100 acres, with ultimate gas recoveries estimated from less than 1 BCFG to over 5 BCFG. Reservoir and hydraulic fracture modeling indicate that infill drilling on 160 acre spacing (within a portion of the Moxa Arch) would increase reserves by 68% when compared to reserves for 320 acre spacing. Results from new CO2 foam/ISP stimulations did not show significant improvement compared to early water-based fluid and sand treatments.