Injection Fall-off Test Research Articles

Transient Pressure Behavior of CBM Wells during the Injection Fall-Off Test Considering the Quadratic Pressure Gradient.

Conventional coalbed methane (CBM) reservoir models for injection fall-off testing often disregard the quadratic pressure gradient's impact. This omission leads to discrepancies in simulating the transient behavior of formation fluids and extracting critical reservoir properties. Accurate determination of permeability, storability, and other properties is crucial for effective reservoir characterization and production forecasting. Inaccurate estimations can lead to suboptimal well placement, ineffective production strategies, and ultimately, missed economic opportunities. To address this shortcoming, we present a novel analytical model that explicitly incorporates the complexities of the quadratic pressure gradient and dual-permeability flow mechanisms, prevalent in many CBM formations where nanopores are rich, presenting a kind of natural nanomaterial. This model offers significant advantages over traditional approaches. By leveraging variable substitution, it facilitates the derivation of analytical solutions in the Laplace domain, subsequently converted to real-space solutions for practical application. These solutions empower reservoir engineers to generate novel type curves, a valuable tool for analyzing wellbore pressure responses during injection fall-off tests. By identifying distinct flow regimes within the reservoir based on these type curves, engineers gain valuable insights into the dynamic behavior of formation fluids. This model goes beyond traditional approaches by investigating the influence of the quadratic pressure gradient coefficient, inter-porosity flow coefficient, and storability ratio on the pressure response. A quantitative comparison with traditional models further elucidates the key discrepancies caused by neglecting the quadratic pressure gradient. The results demonstrate the proposed model's ability to accurately depict the non-linear flow behavior observed in CBM wells. This translates to more reliable pressure and pressure derivative curves that account for the impact of the quadratic pressure gradient.

In situ coal permeability and favorable development methods for coalbed methane (CBM) extraction in China: From real data

Permeability plays a significant role in the economic viability of coalbed methane (CBM) development. In China, in situ permeability obtained from injection fall-off tests range from 0.0001 to 41 mD at depths of 130–1728 m, with the majority (78%) falling between 0.01 and 1 mD. Coal reservoirs with high rank, common cleat mineralization, and depth-dependent high stress may result in extremely low permeability. Low-rank coal and cataclastic coal exhibit more favorable permeability conditions at shallow depths. Heterogeneity in coal rank, coal texture, and stress magnitude results in a discrete distribution of permeability both regionally and vertically. Most deep seams are highly compressed with extremely low permeability (<0.1 mD) as high stress levels. Multilateral horizontal wells work best with high permeability seams, while vertical wells with conventional hydraulic fracturing demonstrate limited adaptability to deep and low-permeability seams due to insufficient proppant-supported fractures. With increasing depth, both vertical and horizontal wells should employ larger fracturing scales to create effectively supported zones with higher fracture conductivity and reduced stress sensitivity to enhance CBM productivity. Horizontal wells with large-scale volume fracturing demonstrate superior performance compared to vertical wells in extracting CBM from deep, low-permeability, and high gas saturation reservoirs.

In Situ Stress Distribution of Deep Coals and Its Influence on Coalbed Methane Development in the Shizhuang Block, Qinshui Basin, China.

The in situ stress plays a crucial role in variations in coal permeability, hydraulic fracturing behavior, and accordingly coalbed methane (CBM) productivity. As the depth increases, the effects of in situ stress will become more prominent. In the Shizhuang block, present-day stress magnitude and permeability of coals at depths >800 m were measured with multiple-cycle hydraulic fracturing and injection falloff test, respectively. The results show that most seams are under pressure reservoirs with pressure gradient <0.9 MPa/100 m. Horizontal stress magnitudes and gradients tend to increase (800-1200 m) and then decrease (>1200 m) with increasing depth. Strike-slip fault stress regimes are predominant, while seams with depth >1400 m are subjected to a normal fault stress regime. Coal permeability tends to decrease gradually with depth and tends to be convergence to 0.01 mD. Considering extremely low permeability of these deep seams, hydraulic fracturing must be applied to create seepage channels for gas and water drainage. Although the high horizontal stress difference in deep seams is favorable for the generation of longer and simple hydraulic fractures, there is no obvious relations between fracture length and gas productivity as poor-support fractures and limited sand migration distance. The current hydraulic fracturing missed the variable stress regimes and permeability at various depth, but used the similar fracturing schemes, leading to significant reduction in gas productivity with depth. Using the high viscosity fracturing fluid, great sand volume, big injection rate, and low sand concentration are recommended for hydraulic fracturing. Single-branch horizontal well with staged fracturing show better applicability for deep CBM extraction.

Assessment of Coal Permeability using Injection Falloff Test and Effect of Temperature and Skin Factor on It: A Case Study for Coal Seams of Jamalganj Coalfield, Bangladesh

The Jamalganj coalfield with the coal deposits of the Permian Gondwana Group in the halfgraben basin was discovered in Joypurhat District, Northwestern Bangladesh, sometime in 1962. Individual coalbed thickness ranges from 0.60 m to 42 m and seams were encountered between the depth ranges of 640 m and 1158 m. Since mining has not yet begun due to the greater depth of the coal seams, several researchers have proposed a Coalbed Methane (CBM) exploration in this region. This research focuses on the permeability of the Jamalganj coal derived from the in-situ Injection Falloff Test (IFT), which is an important reservoir parameter and one of the key factors in CBM exploration and Underground Coal Gasification (UCG). In addition to that, the relationship of temperature and skin factor with permeability is one of the key findings of this research, permeability obtained from the IFT ranges from 2.57 to 121.16 mD while the skin factor ranges from - 6.11 to 50.85 and a higher temperature gradient as of about 4°C per 100 m depths was observed. The study shows that temperature has an inverse relationship with the permeability that decreases with depth and temperature increases, which is analogous with the other CBM producing reservoirs around the world. The negative skin factor denotes flow enhancement near the wellbore and a well-stimulated reservoir, and the positive skin factor indicates increased flow resistance near the wellbore, which reduces permeability. The permeability data suggest that the analyzed coal seams of the Jamalganj Coalfield are suitable for unconventional gas production by either CBM or UCG development. The Dhaka University Journal of Earth and Environmental Sciences, Centennial Special Volume June 2022: 103-112

Geothermal wells with water hammer during injection fall-off test: Numerical pressure transient analysis

Extended pressure fall-off test data of low permeability wells can display oscillations that cannot be easily interpreted by using the existing analytical pressure transient analysis (PTA) methods. Additionally, water hammer effects resulting from wellhead valve shutting off are observed immediately after valve closure.Numerical PTA applied to well MOL-GT-03, Belgium, using 1-D radial model with fractional dimension grid gave a good match with field data clearly indicating low reservoir permeability and the fractured nature of the reservoir. In addition, the water hammer effect was investigated by solving the wave equation to help identifying the extent of the well reach providing an estimate to the reservoir boundary.

Well-Testing Challenges in Unconventional and Tight-Gas-Formation Reservoirs

Summary Well–testing techniques provide valuable reservoir information, which is used to evaluate production potential and helps make development and completion decisions. Traditionally, newly drilled wells are tested using a drillstem test (DST) or wireline formation test (WFT). These methods are typically designed to flow the well under controlled conditions and then shut in the flow to achieve a pressure buildup (PBU). In this paper, we present eight case studies to highlight well–testing challenges in tight–gas–formation wells in unconventional reservoirs. These challenges are accompanied by methods and solutions to adequately address them. During the first two cases, the duration of the PBU was not long enough to overcome high wellbore storage and reach radial flow. This was because of surface shut–in. A simulation is provided for Case 2 to highlight the importance of downhole shut–in. A hydraulically fractured, horizontal, tight–gas–formation well is presented in Case 3, where a 46–day–long PBU was conducted. However, owing to low permeability and high wellbore storage (WBS), this still resulted in a nonunique solution. The use of a wireline–conveyed formation tester to mitigate WBS effects is presented in Cases 4, 6, and 7. Case 5 is an example of a surface diagnostic fracture injection test (DFIT), with surface shut–in. In addition to the conventional PBU analysis, microfracturing and subsequent fluid sampling from tight formations have also been discussed. Finally, an injection/falloff (IFO) case is presented in a hydraulically fractured formation to discuss the challenges and solutions. Because of controlled rates with an IFO test in low–permeability wells, faster flow stabilization can be achieved, resulting in shorter WBS durations. This technique can obtain well and reservoir information faster than a conventional PBU test. One issue with unconventional wells, particularly tight–gas–formation wells, is that the WBS lasts significantly longer than in standard wells. A downhole shut–in tool or any test that minimizes the WBS effects can greatly reduce the duration of such tests and help improve the quality of the analysis results. A discussion on formation compressibility has been provided to highlight the shortcomings of the traditional Hall's correlation for application in unconventional formations. This paper discusses several well–testing applications with corresponding analyses pertaining to unconventional wells. The results provided valuable information to help optimize production and evaluate reservoir potential.

Determine In-Situ Stress and Characterize Complex Fractures in Naturally Fractured Reservoirs from Diagnostic Fracture Injection Tests

Estimation of in-situ stresses has significant applications in earth sciences and subsurface engineering, such as fault zone studies, underground CO2 sequestration, nuclear waste repositories, oil and gas reservoir development, and geothermal energy exploitation. Over the past few decades, Diagnostic Fracture Injection Tests (DFIT), which have also been referred to as Injection-Falloff Tests, Fracture Calibration Tests, and Mini-Frac Tests, have evolved into a commonly used and reliable technique to obtain in-situ stress. Simplifying assumptions used in traditional methods often lead to inaccurate estimation of the in-situ stress, even for a planar fracture geometry. When a DFIT is conducted in naturally fractured reservoirs, the stimulated natural fractures can either alter the effective reservoir permeability within the distance of investigation or interact with the hydraulic fracture to form a complex fracture geometry, this further complicates stress estimation. In this study, we present a new pressure transient model for DFIT analysis in naturally fractured reservoirs. By analyzing synthetic, laboratory and field cases, we found that fracture complexity and permeability evolution can be detected from DFIT data. Most importantly, it is shown that using established methods to pick minimum in-situ stress often lead to over or underestimates, regardless of whether the reservoir is heavily fractured or sparsely fractured. Our proposed “variable compliance method” gives a much more accurate and reliable estimation of in-situ stress in both homogenous and naturally fractured reservoirs. By combining the unique pressure signatures associated with the closure of natural fractures, a lower bound on the horizontal stress anisotropy can be estimated.

A Two-Phase Flow Model for Pressure Transient Analysis of Water Injection Well considering Water Imbibition in Natural Fractured Reservoirs

The pressure injection falloff test for water injection well has the advantages of briefness and convenience, with no effect on the oil production. It has been widely used in the oil field. Tremendous attention has been focused on oil-water two-phase flow model based on the Perrine-Martin theory. However, the saturation gradient is not considered in the Perrine-Martin method, which may result in errors in computation. Moreover, water imbibition is important for water flooding in natural fractured reservoirs, while the pressure transient analysis model has rarely considered water imbibition. In this paper, we proposed a semianalytical oil-water two-phase flow imbibition model for pressure transient analysis of a water injection well in natural fractured reservoirs. The parameters in this model, including total compressibility coefficient, interporosity flow coefficient, and total mobility, change with water saturation. The model was solved by Laplace transform finite-difference (LTFD) method coupled with the quasi-stationary method. Based on the solution, the model was verified by the analytical method and a field water injection test. The features of typical curves and the influences of the parameters on the typical curves were analyzed. Results show that the shape of pressure curves for single phase flow resembles two-phase flow, but the position of the two-phase flow curves is on the upper right of the single phase flow curves. The skin factor and wellbore storage coefficient mainly influence the peak value of the pressure derivatives and the straight line of the early period. The shape factor has a major effect on the position of the “dip” of pressure derivatives. The imbibition rate coefficient mainly influences the whole system radial flow period of the curves. This work provides valuable information in the design and evaluation of stimulation treatments in natural fractured reservoirs.

Comprehensive before-closure model and analysis for fracture calibration injection falloff test

The fracture calibration injection falloff test, also known as mini-frac and diagnostic fracture injection test (DFIT), is widely used to quantify essential input parameters for the following main fracture treatment design. Over time, data presentations used to facilitate the analysis have revealed trends in the before-closure falloff transient data that have been labeled as abnormal closure. This paper provides new models for all known before-closure leakoff behaviors and a comprehensive model that enables a match with the entire before-closure transient response.The before-closure leakoff behaviors in the comprehensive model include wellbore storage (WBS), friction dissipation, tip extension, pressure dependent leakoff area (PDLA), multiple apparent closures, transferred storage (also known as transverse storage), height recession and variable fracture compliance. Besides the parameters such as closure pressure, leakoff coefficient, and the hydraulic fracture geometry that can be quantified by commonly known analysis techniques, the new model enables quantification of several new parameters.Two diagnostic plots are used to facilitate identification and quantification of the standard and newly modeled parameters: the Bourdet log-log plot of pressure change and derivative and the composite G-function plot. Tip extension is more easily identified on the G-function plot, and the model match with this behavior quantifies the tip extension distance after shut-in and the fracture minimum propagation pressure. So-called pressure dependent leakoff and transferred storage may be related to opening of secondary fractures, and may be seen as multiple closure events easily identified on either diagnostic plot. Such effects enable quantification of closure stress and surface areas for the secondary fracture sets. Alternatively, when the behavior that looks like transferred storage is explained as fracture height recession, the closure stress of overlying or underlying layers can be estimated along with the recessed fracture area. Variable fracture compliance has similar appearance with transferred storage as well in the diagnostic plots. When it occurs, the way to determine fracture closure stress and other parameters are provided.Matches with field data reflect highly enhanced understanding of the nature of hydraulic fracturing and natural fracture flow mechanisms that have not been possible with other models and that greatly refine well design strategies.

Sensitivity analysis in permeability estimation using logging and injection-falloff test data for an anthracite coalbed methane reservoir in Southeast Qinshui Basin, China

This paper presents a sensitivity analysis in permeability estimation by interpreting injection-falloff test and logging data for a producing coalbed methane field in Southeast Qinshui Basin. Injection-falloff test data are interpreted by an infinitely acting, constant compressibility and radial homogeneous model. Log interpretation is based on the Archie equation using data of shallow laterolog resistivity. The cementation factor of coal is calculated using laboratory measurements. Based on the interpreted cementation factors and the assumed fracture geometries, the sensitivity in permeability estimation using logging data is analyzed. Results show that the permeabilities are 0.041, 0.012 and 0.035mD for coal seam #3 in wells #W-1, W-5 and W-6, respectively, from the interpretation of injection-falloff test data; the calculated coal cementation factors range widely from 0.9 to 1.8 with average of 1.3. In order to match the log interpretation results with those from injection-falloff tests, different fracture spacing is used in log interpretation for the three wells. The fracture spacing varies from 0.39 to 0.67mm, and the average fracture aperture varies from 0.229 to 0.398μm for the three wells. The cementation factor has the highest impact on estimation of permeability if the cementation factor, mud filtrate resistivity and fracture spacing are varied with 10% from the base case. Effect of fracture aperture’s heterogeneity on permeability is depending on the standard deviation and average of fracture aperture. Effective permeability has a stronger relationship with geometric mean of face and butt cleats aperture than with total porosity for different face and butt spacing models.

Reservoir Characterization from Pressure Monitoring during CO2 Injection into a Depleted Pinnacle Reef – MRCSP Commercial-scale CCS Demonstration Project

Abstract The Midwest Regional Carbon Sequestration Partnership (MRCSP) is implementing a commercial-scale carbon capture and storage (CCS) project in multiple Silurian carbonate pinnacle reefs in northern Michigan that are in various phases of enhanced oil recovery. This paper presents analyses of five pressure fall-off tests performed sequentially during the injection of 166,000 tonnes of CO2 into a Type-1 (depleted) reef which has undergone primary and secondary production. Bottom-hole pressures were monitored in the injection well and in two observation wells to record progressively increasing reservoir pressure during the injection period, which also included five fall-off tests. Pressure data were analyzed using combined history-matching and pressure derivative matching techniques implemented with a commercial well-test interpretation program, FAST WellTest™. The paper illustrates the challenges of consistently interpreting CO2 injection fall-off tests under multi-phase flow with varying pressure conditions using a single-phase analytical model. This work is relevant to CO2 sequestration in depleted oil reservoirs because regular fall-off testing is required under the U.S. Environmental Protection Agency's Underground Injection Control (UIC) Program for CO2 geologic sequestration (75 FR 77230).

Application of After-Closure Analysis to a Dual-Porosity Formation, to CBM, and to a Fractured Horizontal Well

SummaryPublished techniques for after-closure analysis of fracturing data usually assume the presence of a vertical fracture intersecting a vertical well. In addition, these published techniques usually assume that the formation is homogeneous. When the formation is naturally fractured or the well is horizontally intersecting a transverse vertical fracture, those assumptions are obviously violated and the published analysis techniques might not be applicable. Through the use of analytical and numerical solutions and application to actual field data, this paper investigates the analysis of after-closure data for heterogeneous formations, a naturally fractured formation, a CBM, and a fractured horizontal well.This paper briefly reviews the various available techniques for after-closure analysis, pointing out the strengths and weaknesses of each. An analytical solution for an injection-falloff test for a naturally fractured formation has been developed and is presented. This solution might be used to analyze data for a minifrac test in a naturally fractured formation where the fracture has healed. Numerical simulation validated the developed solution for a fracture that has healed. The same numerical simulator was used to expand the solution to a situation where the fracture maintains residual conductivity.The solution for a minifrac test in the case of a transverse fracture is also presented and discussed. Using a numerical simulator, minifrac tests are simulated and analyzed for both heterogeneous formations and fractured horizontal wells. Guidelines for the analysis of such data have been developed and presented.Field data are also presented. One case presents a minifrac test for a heterogeneous formation. A case for a transverse fracture intersecting a horizontal well is also presented and analyzed. A third case for CBM is discussed.

CO2-ECBM field tests in the Ishikari Coal Basin of Japan

Abstract The feasibility of extracting gas from coal seam while storing carbon dioxide underground was evaluated in Japan. A CO2-ECBM project had begun near the town of Yubari on the island of Hokkaido in northern Japan. The primary coal seam of interest was a 5–6 m thick Yubari coal seam located at the depth of 900 m. A micro-pilot test with a single well and multi-well CO2 injection tests, involving an injection and production wells, were carried out in the period between May 2004 and October 2007. There were a variety of tests conducted in the injection well, including an initial water injection fall-off test and a series of CO2 injection and fall-off tests. Although gas production rate was obviously enhanced by CO2 injection, water production rate was not clearly affected by CO2 injection. Several injection tests suggested that injectivity of CO2 into the virgin coal seam saturated with water was eventually increased as the water saturation near the injector was decreased by the injected CO2. It was estimated that low injectivity of CO2 was caused by the reduction in permeability induced by coal swelling. N2 flooding test was performed in 2006 to evaluate the effectiveness of N2 injection on improving well injectivity. The N2 flooding test showed that daily CO2 injection rate was boosted, but only temporarily. Moreover, the permeability did not return to the initial value after CO2 and N2 were repeatedly injected. It was also indicated that the coal matrix swelling might create a high stress zone near to the injection well.

Technology Helps Revitalize Maturing Giant Gas Field: Horizontal-Well Redevelopment

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109948, "Applied Technology Helps Revitalize a Maturing Giant Gas Field: Learnings From the Cleveland Formation's Horizontal-Well Redevelopment Program," by Neil C. Decker, SPE, David B. Bumbaugh, SPE, Ron L. Brogdon, and David C. Gardner, SPE, BP plc; Stephen P. Roberts, SPE, Jones Energy; and Sean D. Petersen, BP plc, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed. The Cleveland formation is a giant tight gas reservoir under a large area of the northeastern Texas Panhandle and western Oklahoma. Operator strategies have shifted in recent years to infill drilling with horizontal wells. Challenges include optimizing horizontal-well orientation, lateral length, completion type, and the number and length of hydraulic fractures, all within the context of a partially depleted reservoir. Operators have become active in acquiring data to improve their understanding of the reservoir and to quantify the variables driving well performance. Introduction The Cleveland reservoir exists throughout much of the northeastern Texas Panhandle and western Oklahoma, with the majority of production in Lipscomb and Ochiltree Counties of Texas and Ellis County, Oklahoma. The formation was dis-covered during exploration for deeper Morrow objectives in the late 1950s. Initially, it was developed with traditional hydraulically fractured vertical wells on 640-acre (1-section) spacing, but much of the reservoir has been downspaced to optional 160-acre spacing. The Cleveland produces from depths of 6,500 to 8,200 ft true vertical depth. Pay thickness varies from approximately 20 to 80 ft, with porosity values ranging from 4 to 14%. Calculated water saturations are high because of the influence of interbedded sequences of sand with thin shale laminations and the fine-grained sandstone, as observed in core samples. However, the Cleveland does not produce significant volumes of formation water. Cleveland wells with significant water production historically have downhole mechanical problems. Permeabilities are estimated to range between 0.003 and 0.015 md on the basis of injection-falloff tests performed in horizontal Cleveland wells and Agarwal-Gardner type-curve analysis of vertical Cleveland producers incorporating rate/time superposition. The first horizontal Cleveland well in this area was drilled in late 1997. Performance results and reservoir pressures that indicated the reservoir was not being depleted effectively supported the shift to development with horizontal infill drilling. This inefficient drainage results from the overall low permeability of the reservoir, compounded by the effects of reservoir heterogeneity creating permeability barriers. Cost inflation has continued to place economic pressures on Cleveland development. Operators continue to explore ways to achieve improved and consistent well performance while lowering development costs. Major efforts have been made to acquire data to improve operators’ understanding of the reservoir and identify key variables to optimize horizontal-well development.

Techbits: Coalbed-Methane Recovery and CO2 Sequestration Raise Economic, Injectivity Concerns

Representing Australia, the U.S., Canada, and Europe, 40 engineers and geologists attended an SPE Applied Technology Workshop (ATW) focused on the viability of enhanced coalbed-methane (ECBM) recovery and CO2 sequestration in coalbeds. The workshop “Enhanced Coalbed-Methane Recovery and CO2 Sequestration,” held in Denver from 27–29 October 2004, was led by Scott Reeves, Executive Vice President of Advanced Resources Intl., and the program committee included Bill Gunter, Research Officer of the Alberta Research Council; Mike McGovern, Senior Staff Engineer of Burlington Resources; Henk Pagnier, Program Manager-SUS Energy, TNO-Netherlands Inst. of Applied Geosciences; and Pablo Tejera Cuesta, Reservoir Engineer for Shell Intl. E&amp;P. The ATW featured six sessions focusing on different aspects of ECBM recovery and CO2 sequestration, providing an excellent snap-shot of research and pilot programs in this topic area. Session 1, moderated by Reeves, introduced the workshop and reviewed the state of ECBM-recovery technology. During his introduction, Reeves noted that ongoing work in ECBM recovery is very research oriented and is driven by CO2 sequestration. Cuesta continued the session with an introduction to ECBM-recovery technology, stating that coalbed methane is a significant part of the global hydrocarbon resource base. He reviewed the reservoir characteristics of coal (classified as a continuous-type reservoir) in which gas storage is dominated by adsorption. Major points of discussion highlighted economic considerations, including the cost of injectant required for ECBM-recovery operations as well as the separation, capture, and storage of CO2. Lessons Learned Gunter moderated Session 2, focusing on pilot projects and emphasizing results and lessons learned and noting that experience with ECBM recovery and CO2 sequestration in coal includes one large-scale project in the Allison Unit of the San Juan basin and a series of single-well micropilots in Canada, Poland, and China. These pilot programs have focused on coal of bituminous-through-anthracite rank, and major issues being addressed include geomechanics, permeability, matrix swelling, and fracture porosity. McGovern presented the results of CO2 flooding in the Allison Unit, motivated by the desire to recycle CO2 produced from Fruitland coal while enhancing CBM production. Within the Allison Unit, CO2 was injected continuously for more than 5 years. During the project, approximately 4.7 Bcf of CO2 was injected, and approximately 4.2 Bcf of CO2 was sequestered. Incremental methane recovery during the project was approximately 1.5 Bcf, and the ratio of CO2 injected to methane produced was approximately 3.1:1.0. David Law of the Alberta Research Council presented results of micropilot programs in Mannville coal of the Western Canada sedimentary basin and the No. 3 coal of China’s Qinshui basin. In the pilot areas, Mannville coal is of highly volatile B bituminous rank, and the No. 3 coal is of anthracite rank. Well testing in these micropilots included multiple production and injection-falloff tests. The Mannville micropilot is notable because a variety of gases were injected, including pure CO2, flue gas, pure N2, and CO2-enriched flue gas. The Qinshui basin contains the first pattern of commercial CBM wells drilled in China and contains the highest-rank coal developed for CBM to date. Well testing in the Qinshui basin confirms that sequestration potential exists in anthracite and that permeability can exceed 12 md.

High Grading Fracture Candidate Selection

Abstract The ability to choose the best possible fracture stimulation candidate is very important in order to maximize production and revenue, To compare wells consistently in a given area, pressure build-up techniques are utilized. An up-lo-dale isobaric map is required. An estimate of the slope m of all the wells in the area is then determined using known m's from build-up and Jail-off tests. Since Pr and m are given/or all the wells, build-up calculations can be done to determine skin factors and maximum anticipated low rates with a −4 skin factor. Once maximum rates for oil have been estimated the wells with the greatest variance between actual oil production and estimated −4 skin oil production are investigated further to determine the best fracture candidates. Introduction The following paper outlines a method for high-grading fracture candidate selection in mature waterfloods, with medium to low permeability and pressures above the bubble point, by the use of pressure build-up surveys and injection well fall-off tests. The area investigated is the Pembina Easyford Cardium Unit No.1 located 15 km northwest of Drayton Valley. The unit is operated by Canadian Occidental and consists of 15 water injection wells, 78 producing wells and 15 shut-in wells. To fulfill Energy Resources Conservation Board's (ERCB) requirements, an extensive pressure build-up program was conducted from September to December 1986. In all, 17 wells were placed on build-up. To complement the pressure build-upsurvey all 15 water injection wells had fall-off tests conducted on them. In addition, three shut-in wells had injection fall-off tests performed on them (Fig. 1). The high-grading method calculates the present skin factor and then calculates the stabilized production rate at a skin = −4 for all the producing and shut-in wells within the unit. The method depends on assigned values of Pr, derived from the build-up surveys, fall-off tests and static gradients, and the Horner slope m for each well. The criteria and limitations will be discussed in a following section. The final step in the high-grading method compares the actual present oil production rate for each well with the estimated stabilized production rate at a S = −4. The wells with the greatest increase in oil production rates are the wells which should be investigated as potential fracture stimulation candidates. It should be emphasized that the method is only a screening method for determining the best possible fracture stimulation candidates. Once a short list has been generated, other criteria such as WOR, decline rate, peak fluid production rate, remaining recoverable reserves, well recovery and fracture stimulation history can be used to determine the best candidates for fracture stimulation. Equations The following equations were used in the skin and stabilized rate calculations on all of the producing and shut-in wells in Easyford. Equation (Available In Full Paper) The actual reservoir conditions behave in between both cases. The constant was calculated by using the stabilized rate equation and setting q5=q0 and S equal to the calculated present skin factor equation.