Crosswell acoustic surveys enable the
Porosity was determined from crosswell data using the empirical relationshipbetween acoustic velocity, porosity, and effective pressure developed byDomenico.6
Values for Young's modulus and Poisson's ratio derived from crosswellmeasurements are comparable to values obtained from core. Apparent seismic Qmeasured
There are few ways to investigate rock properties beyond several wellboreradii of gas wells. The principal seismic methods include vertical seismicprofiling (VSP), 3-D seismic surveying, and crosswell acoustic measuring. Thefirst two methods are primarily exploration tools useful in characterizing thegross structure of an area; however, crosswell acoustic surveys can measurerock properties between closely spaced wells. The crosswell techniques alsoallow the determination of
In this study, crosswell measurements of Young's moduli, Poisson's ratio andporosity are compared with laboratory measurements made on core; whereasseismic Q measurements are compared with average values for sandstone. Thelaboratory core measurements of moduli, Poisson's ratio, and porosity were madeby oil and gas industry support companies under contract to Sandia NationalLaboratories.
Measurements were conducted at the Department of Energy Multi-WellExperiment (MWX) site in the Piceance Basin near Rifle, Colorado. The crosswelldata were acquired in sands deposited within a delta plain coastal environment,part of the Cretaceous Mesa Verde formation. This region of the Mesa Verde is atarget area for hydrofracture stimulation due to the suspected high gascontent, but low permeability, of this sandstone.
The Upper Cretaceous Corcoran and Cozzette Sandstones are fine to very fine grained blanket-geometry, low-permeability barrier and strandplain sandstones that trend northeast across the southern Piceance Creek Basin of Colorado. Development of these tight gas Piceance Creek Basin of Colorado. Development of these tight gas reservoirs has been concentrated in the Shire Gulch-Plateau field area where core and log data show contrasting trends in reservoir properties for sandstones with blocky or with upward-coarsening properties for sandstones with blocky or with upward-coarsening gamma ray log patterns. Lesser reservoir quality is associated with increased amounts of carbonate cement, and with more highly burrowed sandstones containing additional silt. Individual Corcoran or Cozzette gas productivity is difficult to determine because production is commingled and is from more than one depositional unit even within a single sandstone member. Net pay by generic depositional unit offers a means of understanding resource distribution.
The Corcoran and Cozzette Sandstones are part of the Upper Cretaceous Mesaverde Group of the southern Piceance Creek Basin of northwestern Colorado. The sandstones are members of the Price River Formation of the Mesaverde, and consist of progradational marginal marine facies that overlie the marine Mancos Shale and underlie the continental facies that make up the bulk of the Mesaverde Group. Together with the overlying Rollins Sandstone, the Corcoran and Cozzette have recently been developed as low-permeability gas reservoirs.
The Corcoran and Cozzette have long been recognized as shoreline sandstones, but only recently have data become available on the distribution of specific genetic facies. Palmer and Walton defined shelf, shoreface, tidal inlet, and coastal plain facies from outcrop studies, and Finley and Ladwig defined barrier and strandplain facies in the subsurface. Zapp and Cobban recognized that Campanian-age regressive shorelines, represented by the Corcoran and Cozzette Sandstones in this study, had a northeast trend across the southern Piceance Creek Basin. This shoreline orientation is related to progradation into the Cretaceous interior seaway from the west, including major deltaic progradation at a point along the Colorado-Wyoming border in northwestern Colorado. point along the Colorado-Wyoming border in northwestern Colorado. Within this depositional setting, therefore, the Corcoran, Cozzette, and Rollins Sandstones are intermediate facies located between the marine shelf muds of the Mancos and the fluvial and coal-forming environments within which Mesaverde sediments were primarily deposited. As the latter deposits prograded successively primarily deposited. As the latter deposits prograded successively farther into the seaway with time, marginal marine sandstones, such as the Corcoran and Cozzette, formed a blanket sandstone with good lateral continuity as the leading edge of the Mesaverde sediment package. The sandstones are time transgressive and become younger toward their basinward (southeastern) margins. In the depositionally updip direction (northwestward), the Corcoran and Cozzette grade into continental facies and lose the readily correlatable log signature characteristic of marginal marine blanket sandstones.
The Piceance Creek Basin is a Late Cretaceous to Early Tertiary structural basin defined by a series of Laramide-age uplifts. The Douglas Creek Arch is a mildly positive feature on the western basin margin that separates the Piceance Creek Basin from the Uinta Basin in Utah. There is little evidence of uplift on the Douglas Creek Arch at the time of Mesaverde deposition, and Laramide structural elements in general had little influence on Cretaceous depositional patterns. The strongly asymmetrical Piceance Creek Basin has a gentle western flank and a steeply dipping eastern flank that lies close to the deep axis of the basin. The Corcoran and Cozzette Sandstones crop out along parts of the western basin margin in the Book Cliffs and along the eastern basin margin as part of the Grand Hogback (Fig. 1). Structure contours on the Cozzette Sandstone show relatively uniform northeast-to-north dip throughout most of the southern part of the basin.
The flow of nitrogen and brine in tight Vicksburg "P" Sand cores was studied under field stress conditions. The experiments simulated various stages of a hydraulic fracturing treatment. Measurements were made of critical gas saturation, gas flow vs pressure gradient, and gas permeability vs brine pressure gradient, and gas permeability vs brine saturation. Brine saturations were imaged with a medical Computerized Tomography (CT) scanner.
The laboratory results suggest that water block is not important when drawdown pressures at the fracture face exceed the capillary entry pressure by several hundred psi. The addition of alcohol or an alcohol/surfactant package to the brine does not significantly increase final gas flow.
Production problems with tight gas sands have been Production problems with tight gas sands have been discussed in many papers. Poor gas production from tight rock following a water-base fracture treatment is often attributed to water block. In water-wet rock, capillary forces resist brine displacement from the matrix into the fracture. Water block occurs if the drawdown pressure gradient in the formation near the fracture face does not exceed the rock capillary pressure sufficiently for gas to flow.
In 1979, Holditch reported results of a numerical simulation of water block in tight formations. He concluded that water block is not a serious problem in most tight formations because drawdown pressure and water mobility are usually high enough for efficient displacement of fracture fluid from the formation. However, water block may develop if reservoir pressure gradients in the near fracture face region are low or if fluid mobilities are seriously reduced by formation damage.
Several aspects of gas flow in tight rock were also studied in the laboratory. They also indicated that water mobility is probably high enough so that final gas production is not affected by water block.
Nevertheless, there is continued effort in the industry to develop fracture fluid additives designed to overcome water block and increase gas production. Many additive packages such as alcohol production. Many additive packages such as alcohol and alcohol/surfactant are commercially available. A detailed review of one such package, including field test data, has been published by Penny, Soliman, Conway, and Briscoe. They claim Penny, Soliman, Conway, and Briscoe. They claim that "oil wetting" (reducing water wetting in a gas-water system) the rock surface would lower the capillary pressure sufficiently to reduce both water blocks and brine imbibition. As a result, the volume of invaded brine would be reduced. A further benefit would accrue from increased water mobility during gas displacement due to surface tension reduction. Field examples are cited which show improvements in both load water production and gas production.
In order to resolve the controversy over the significance of water block in hydraulic fracturing of tight gas sands, a laboratory study was initiated using a CT scanner to measure brine saturations and fluid flow under stress conditions that simulate a hydraulic fracture.
In this study, reference gas and brine permeabilities were first measured at downhole permeabilities were first measured at downhole pressure conditions. A gas drawdown test was pressure conditions. A gas drawdown test was developed to measure gas flow following the fracture treatment. Gas flow following and gas permeability were measured as the pressure gradient was increased. Drawdown tests with alcohol and the alcohol/surfactant packages were included for comparison with brine fracture fluids.
Tests were conducted at ambient temperature and reservoir effective overburden pressure (core overburden pressure - pore pressure).
This paper explores the feasibility of making in situ stress measurements at depth from caliper measurements of deformed wellbores. The work has been carried out in three steps: (1) theoretical development of viscoelastic constitutive equations necessary for calculation of stress directions and magnitudes, (2) application of the equations to field data, and (3) comparison of results to stress measurements made by hydraulic fracturing and overcoring methods. The results of the theoretical analysis are equations that relate the minimum and maximum radii of a deformed wellbore to the maximum and minimum stresses perpendicular to the axis of the wellbore. Calculation of perpendicular to the axis of the wellbore. Calculation of absolute magnitudes of stresses requires the viscoelastic compliance and Poisson's ratio of the rock, but even when this information is not available relative magnitudes of stresses can be determined. The constitutive equations were applied to caliper measurements of a horizontal borehole in unwelded ash-fall tuff near an underground tunnel complex in Rainer Mesa on the Nevada Test Site. The horizontal borehole was aligned in the direction of the maximum horizontal stress. Over a 37 day period the wellbore showed time-dependent deformation, with maximum closure in the maximum stress direction (overburden). The ratio of principal stress calculated from caliper measurements of the deformed wellbore varied from 1.73 to 2.06, depending on the time interval used. The ratios obtained from overcoring and hydraulic fracturing were 1.79 +/- .22 and 2.12 +/- .12. Limitations of this approach to stress measurement are discussed, but results of the present study suggest that with further development of the viscoelastic consitutive model, stress variations along the length of the wellbore might be readily examined as part of the well logging process. process
The overriding influence of stress an the orientation and geometry of hydraulic fractures has established the importance of knowing in situ stress to optimize stimulation treatments. The economic importance of in situ stress measurements and their relation to fracture geometry is reflected in the results of an industry survey sponsored by the U.S. Department of Energy. This survey reported that out of ten tight-gas R and D objectives, the ones given first and second rank in importance were (1) prediction and/or control of fracture geometry and (2) measurement of in situ stress to better predict fracture geometry. In addition, the production characteristics of many reservoirs are being recognized as stress sensitive, and thus even more emphasis is being placed on stress determination.
The conventional method of determining in situ stresses at depth is with a small volume hydraulic fracture. The relation between the in situ stresses and the pressure record have been the subject of intense study since the benchmark work of Hubbert and Willis. Even so this approach has several limitations. For example, reliable results may be difficult or impossible to obtain when the wellbore is not closely aligned with one of the principal stresses, when the rock is strongly anisotropic, or when the packers induce fractures. packers induce fractures. One situation in particular which causes conventional hydraulic fracturing data to be of limited value occurs when the rock is not strong enough to support the stress concentrations near the wellbore. Under these conditions wellbore deformation occurs, making it difficult to accurately determine either the horizontal stress magnitudes or orientations at the wellbore. In brittle rock, wellbore deformation results in spalling of the wellbore (breakouts). Whereas in ductile rock, creep deformation results in wellbore closure. There is work to suggest that the geometry of deformed wellbores may provide information on the in situ stresses.
The objective of this study has been to develop equations that relate creep deformation of a wellbore to the in situ stress acting perpendicular to the wellbore and to test the equations in the field. The equations are formulated so that stresses can be determined from measurements made by an oriented caliper or televiewer log.
In recent years, there have been significant developments in the optimization of hydraulic fracture treatment of wells with one pay zone, but studies concerning treatment in wells with multiple zones are virtually nonexistent. Because a significant portion, it not a majority, of hydraulic fracture treatments are done in wells with multiple pay zones, discussions are presented to show (1) the use of limited technology leads to uneconomical depletion of the formation and (2) a model for effectively designing fracture treatment for multiple pay zones.
Three field examples are presented to illustrate the various uses of the model in optimizing hydraulic fracturing treatment of wells with multiple zones.
INTRODUCTION AND BACKGROUND
Approximately 35 to 40 percent of all new wells drilled in the United States require hydraulic fracturing for commercial production. Consequently, a demand exists for reliable techniques of hydraulic fracturing, in recent years, significant developments have taken place in the optimization of hydraulic fracture treatment of wells with one pay zone. Topics pertaining to fracture migration, adequate proppant transport, and three-dimensional hydraulic fracture geometry simulation of single zones have been extensively discussed and published. Similar studies concerning treatment in wells with multiple zones, however, are virtually nonexistent. The difficulty of using conventional single-zone treatment design on wells with multiple zones is also well documented.
Current methods of designing hydraulic fracture treatment for wells with multiple pay zones include limited entry, staging (with the use of diverting agents and ball sealers), and packing off zones (including techniques employing bridge plugs and sand plugback). A common assumption used in these methods considers all zones to open up and the fracture to propagate in a similar fashion. This assumption typically stems from not propagate in a similar fashion. This assumption typically stems from not knowing the variations in fracture gradient pressure (in-situ stress) of the various zones.
Limited entry permits fracture to be placed in all desirable parts of a reservoir and gives maximum control of stimulation fluids at each fracture point. In essence, it provides for the equal distribution of treating fluids through all perforations by (1) limiting the number and size of perforations, and (2) by controlling the differential pressure across the perforations. Correctly applied under the proper well conditions, limited entry can be extremely effective. Although this "basic definition" illustrates what limited entry is, the proper design and application of the technique needs to be specifically outlined.
All the multiple zone treatment techniques mentioned lack a very important aspect - the capability of quantitatively predicting the created fracture characteristics in each zone. Recent publications state that this limitation primarily is due to the lack of technology in fracture migration prediction of wells with multiple zones. Also, the unavailability of prediction of wells with multiple zones. Also, the unavailability of reliable and continuous fracture gradient pressure and mechanical properties data has hindered the commercial development of a fracture properties data has hindered the commercial development of a fracture migration predictive tool.
The multiple-zone fracture migration model reads in fracture gradient pressure, Poisson's ratio, and moduli data every 6 in. (15.2 cm) over the pressure, Poisson's ratio, and moduli data every 6 in. (15.2 cm) over the intervals of interest.
This paper describes a laboratory and numerical study of contained hydraulic fracture propagation via a preexisting stress gradient. This study was conducted in order to improve current knowledge of three-dimensional geometry. Laboratory tests were performed using prefractured polymethylmethacrylate (PMMA) beams prefractured polymethylmethacrylate (PMMA) beams which were subjected to a stress gradient in the minimum principal stress direction. The fracture propagation was studied as a function of fluid propagation was studied as a function of fluid rheology, flow rate and state of stress. The numerical approach consisted of a pseudo-three-dimensional model, developed to handle any type of boundary condition.
Results show that fracture-shape evolution is close to radial propagation at initiation, but becomes more and more contained as the length increases. A good prediction is achieved once the assumptions of the model are validated, i.e., once the fracture is sufficiently elongated.
The last four years have seen the development of numerous models for predicting the complete geometry of hydraulic fractures. They differ from previous classical models (e.g., Perkins and Kern, Khristianovich and Zheltov) in that they no longer require a constant fracture height to be imposed. This complete determination of the fracture shape allows prediction of containment on the basis of the fluid behavior, the pumping schedule, the fluid-loss to the formation, the in-situ state of stress and, in some of the models, the variation in mechanical properties in the boundary layers. properties in the boundary layers. These models are either pseudo-three-dimensional, or fully three-dimensional.
In general, assumptions are introduced to simplify the physics, making the problem tractable within a reasonable amount of computer time. Such assumptions have to be validated and their limits of application determined.
Field validations are certainly one important procedure; however, they suffer from several major procedure; however, they suffer from several major limitations, including the following.
Uncertainty in the knowledge and variability of the mechanical properties of the layers and the state of stress in the formation.
Behavioral complexity of some rock types which cannot be handled by current fracture propagation models (i.e., plasticity, major preexisting discontinuities).
Inadequate knowledge of the behavior of the fracturing fluid in the fracture.
Difficulty in measuring the evolution of the fracture geometry as a function of time (the only parameters recorded during a usual fracturing job being the rate, the density of the fluid and the pressure, often recorded at the wellhead).
In order to validate the principal assumptions of some of these models, laboratory experiments can be an important tool. Quantitative experiments on fracture propagation have been performed, but they only deal propagation have been performed, but they only deal with radial fracture propagation or constant height fractures. Until now, the only experiments on containment have been relatively qualitative.
A new experimental procedure has been developed, in order to quantitatively study the fully three-dimensional propagation. The experiment presented in this paper deals only with containment related to a gradient acting in the minimum principal stress direction, using a homogeneous impermeable sample. The model used for validation is quasi-three-dimensional and has the advantage over other existing models, of accommodating any type of stress distribution, as opposed to step functions.
In an effort to better understand the geologic and engineering factors that explain the production performance of the tight Clinton sandstone of Eastern Ohio, logs, completion data, and production performance records were evaluated for a number of production performance records were evaluated for a number of Clinton sandstone wells in east central Ohio.
The wells were divided into low slope (linear) and high slope (radial) groups based on plots of log cumulative production versus log time. The distributions of expected recoveries from these two groups of wells were compared using the chi square and Pearson's P-M correlations, and were found to be significantly different. The linear wells had a median expected ultimate production of less than 20 MMcf (5.7 x 10(5) m3) while the radial group had a median of more than 50 MMcf (1.4 x 10(6) m3). Some of the wells tended to be located in contiguous trend areas. The distance to the drainage boundary was also calculated for the linear and radial wells. The median length for the linear wells is about 500 feet (150 m) while the median radius for the radial wells is about 2,000 feet (600 m).
The intent of this paper is to provide industry with a methodology that can be used to calculate reservoir parameters, such as size and geometry, which are important in designing stimulations and in estimating reserves.
Results from an on-going DOE sponsored program related to hydraulic fracture response modeling are presented. Finite element model formulations and presented. Finite element model formulations and the solution methodology associated with a pseudo-three-dimensional hydraulic fracture model pseudo-three-dimensional hydraulic fracture model coupling fracture fluid flow and leak-off on both horizontal and vertical cross-sections with the elastic response in vertical cross-sections are described. In addition, fracture geometry evaluations and selected comparisons with available results are revealed.
The development of rigorous hydraulic fracture models is being vigorously pursued by several researchers in industry, universities, and government laboratories. The mathematical, computational, and experimental sophistication of these investigations can often be incompatible with the limited data on reservoir properties. The models, however, can furnish interpretive information on the governing mechanisms such as the role of in situ stresses, layered media including inclusions, bi-material interfaces, natural joints, fracture and reservoir fluid properties, and proppant transport. The design of stimulation treatments, based on these predictive capabilities, for optimum recovery of the predictive capabilities, for optimum recovery of the hydrocarbon resources is a formidable challenge.
Summary reviews of selected hydraulic fracture model investigations and design considerations have been previously presented. In addition, detailed critiques of various 2D and 3D models along with work on vertical fracture growth have been recently presented by Mendelsohn. Subsequent research on the analysis of growth and interaction of multiple hydraulic fractures has been presented by Narendran and Cleary. Advanced simulations of hydraulic fracture models have been recently conducted by Barree, Roegiers and Ishijima Nghiem et al., Settari and Cleary, Bouteca, and Dougherty and Abou-Sayed. Several related papers on hydraulic fracture geometry prediction were also presented by Ahmed, Abou-Sayed et al., and presented by Ahmed, Abou-Sayed et al., and Palmer and Craig at the 1984 Unconventional Gas Palmer and Craig at the 1984 Unconventional Gas Recovery Symposium. A recent paper by Warpinski and Teufel has examined the role of geological discontinuities (joints, faults, and bedding planes) and in situ stresses on hydraulic fracture propagation.
In this paper, formulations and results for a sophisticated pseudo-three-dimensional finite element model for hydraulic fracture geometry are presented. This model employs a numerical approach to solve the coupled non-linear partial differential equations for the fracture fluid pressure and induced fracture dimensions. The fracture is discretized into a number of vertical sections. Fracture width and pressure evaluations are conducted by applying to pressure evaluations are conducted by applying to each vertical crack, the two-dimensional flow in the vertical direction with leak off. The model then utilizes the fluid flow along the horizontal direction to predict the fracture height profile and length. An iteration process is designed until satisfactory convergence is attained. Comparisons with hydraulic fracture configuration simulations reported in recent literature are also presented.
A schematic of the fracture geometry is illustrated in Figure 1.
Standard decline curve equations can by used outside their normal range of application to give accurate and theoretically valid projections of tight gas well performance. This approach is preferable to the use of the reciprocal square-root of time as a preferable to the use of the reciprocal square-root of time as a tight gas well "type curve".
Low permeability fractured gas wells, when produced without constraint, typically exhibit a characteristic decline curve shape: a steep initial decline followed by a long well life at low producing rates relative to the initial potential. The common producing rates relative to the initial potential. The common methods of forecasting production from these wells vary in complexity and in the amount of detail required. Decline curves and mathematical curve fitting require only monthly production data; no knowledge of reservoir properties is necessary. The problem with these techniques it that, especially at early times, problem with these techniques it that, especially at early times, virtually any curve can give a reasonable fit to monthly data. On the other hand, log-log type curves and mathematical simulation require knowledge of the fracture and reservoir geometries as well as a detailed history of flowing rates and pressures. As a practical matter, this kind of detail is often unavailable practical matter, this kind of detail is often unavailable The utility of decline curves can be enhanced by recognizing the influence of the physics of reservoir fluid flow on the resulting semi-log plot. The characteristic tight gas well decline shape is a predictable result of the flow from a low permeability reservoir into a more conductive fracture.
The Arps Equation
The Arps equation is the most commonly used ratetime decline relationship:
Arps treated the equation as empirical, but noted that the exponent can be influenced by the reservoir flow conditions. The value of b determines the degree of curvature of the semi-log decline, from a straight line (exponential decline) at be = 0.0 to increasing curvature at higher values of b. He stated that the value of b varies between zero and 1.0, with no discussion of the possibility of b greater than 1.
There is no theoretical basis for limiting the exponent to values less than 1. Using numerical simulations, Gentry and McCray showed that reservoir heterogeneity (e.g., layered reservoirs) can result in a hyperbolic exponent exceeding 1.
A single decline equation with b less than 1 cannot approximate a typical tight gas decline shape as shown in Figure 1. Bailey used mathematical curve fitting to determine the "best fit" hyperbolic equation for wells in three tight has basins. For his representative group of fractured Wattenberg Field wells, the optimized exponent exceeds 1 in all but a few cases, and ranges as high as 3.5 in one case.
In practice, many engineers avoid the use of hyperbolic decline curves. Some use a favorite French curve to approximate tight gas well declines. Another common approach is to assume a decline shape composed of a series of straight line segments: for example, 50% exponential decline for two years, then 20% decline for three years, followed by 8% decline to an economic limit. While these methods may give satisfactory results for a group of similar wells, one must ask: Why do these wells follow a decline shape which is apparently arbitrary?
The Inverse Square-Root of Time Equation
In search of an equation which explains the influence of low permeability and flow geometry on the shape of the decline curve, permeability and flow geometry on the shape of the decline curve, some recent papers and articles have proposed the following equations for use with tight gas well declines:
The argument for this equation is based on the physics of linear flow and on observations from log-log type curves for fractured wells.
Two stimulation operations have been conducted to date in the paludal zone of the Mesaverde formation in one well, MWX-1, at the DOE's Multiwell Experiment test site in the Piceance Basin near Rifle, Colorado. Problems were encountered in the second stimulation: MWX-1 would not sustain production for several months and post-frac production production for several months and post-frac production was less than pre-frac rates. The laboratory program was expanded to examine these problems and program was expanded to examine these problems and these laboratory studies were integrated with well testing and other data to help explain MWK-1 production behavior. A unique explanation cannot be found production behavior. A unique explanation cannot be found for the failure of MWX-1 to produce; a combination of factors was responsible. Water probably inhibited matrix rock production. A system of naturally occurring microfractures is important in production from the paludal zone and it probably sustained damage by water and fracture fluids. The basic gel degraded slowly because only a small amount of breaker was used. The fracture closure (viscosity break) observed from the volte analysis of the stimulation was not the same as the breakdown of the basic gel. The remedial treatment conducted after the second stimulation was probably too reactive. A list of items has been developed from experience gained both inside and outside the laboratory that shows what work and which procedures should be emphasized or avoided in tight sand stimulations.
Two stimulation operations have been conducted in Well MWX-1 of the Department of Energy's Multiwell Experiment (MWK) in the Piceance Basin near Rifle, Colorado. Zones 3 and 4 of the paludal section of the Mesaverde Formation, shown in Figure 1, were the zones of interest. The first stimulation operation (Phase I, December 1983) consisted of a series of small, unpropped step-rate/flow-back tests and minifracs whose primary goals were fracture diagnostics and containment prediction. The second (Phase II, May 1984) was a larger sandpropped hydraulic fracture treatment with the additional goal of production enhancement.
Production rates of 250 MCFD (3080 m /d) were measured from the two zones together during prePhase I testing. No difficulty was encountered in prePhase I testing. No difficulty was encountered in getting the well to flow after periodic cleanup during the winter after the Phase I operations. However maximum flows of only 200 MCFD (5660 m /d) could be sustained just prior to Phase II operations. Clean-up after the Phase II Phase II operations. Clean-up after the Phase II stimulation was difficult and the well was not capable of sustained flow. A remedial breaker treatment was performed a month later (June 1984) without notable improvement. Sustained gas flow was not realized until mid-July when a revised packer assembly was installed. Nevertheless, rates in excess of 170 MCFD (4810 m /d) could not be sustained during the ensuing post-frac testing period. period. Extensive laboratory investigations were initiated to examine the production problems. These studies involved many aspects of the core program and the analyses which had been performed prior to both stimulation operations.
The purpose of this report is to examine (a) early core analysis data, (b) laboratory core studies supporting stimulation design, and (c) post-frac laboratory investigations and analyses, post-frac laboratory investigations and analyses, and then to integrate these results with field data to clarify and interpret the results of both the Phase I and II stimulation operations. Phase I and II stimulation operations. BACKGROUND CORE DATA
The objectives of the MWX core program are to provide a physical description of the reservoir and provide a physical description of the reservoir and to support well testing and-stimulation. Prior to MWX, there was very little specialized core data (e.g., restored state permeabilities as a function of water saturation, capillary pressures, etc.) available from tight sandstone formations such as the Mesaverde. In fact, many of the first such measurements were made on WWX core.