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Abstract Several onshore concessions, currently under exploration by ADNOC, consist of tight laterally variable reservoirs that pose a significant challenge during the evaluation phase of exploration. Most tight hydrocarbon-bearing formations require fracture stimulation. As such, the evaluation phase of these resources comprises not only the characterisation of reservoir rock properties using petrophysical analysis but, crucially, the construction of 1-D Mechanical Earth Models which underpin the identification of stimulation intervals for both vertical and horizontal well completions. The 1-D MEMs discussed here were provided by different vendors and have been calibrated against interval pressure tests, that included standard "wet" straddle packer microfractures and novel "dry" Sleeve-Fracture tests. The microfracture test data used to calibrate the MEMs were obtained from different depth intervals in onshore Abu Dhabi E&A wells and exhibit non-ideal pressure decline "shut-in" behavior. This required re-analysis using different interpretation methods to identify the lower bound fracture closure pressures and minimum stress magnitudes. The identification of stimulation intervals from the 1-D MEMs highlighted the uncertainty in the minimum stress magnitude estimations from both the log-based models, and the microfrac interpretations. The uncertainty in the log-based minimum horizontal stresses can exceed 0.15 psi/ft (>17%), even after calibration with the microfracture tests. The uncertainty in the fracture closure pressure obtained from the microfracture test can also be as large as 1,600 psi (0.22 psi/ft and 30%). The identification of the sources of the uncertainty, their quantification and the re-evaluation of microfracture tests fed directly into updated 1-D MEMs, which led to improved recommendations for optimised injectivity tests and acid fracturing treatments. This, in turn, has translated into a successful fluid sampling and production appraisal programme.
Abstract The Antrim Shale of the Michigan Basin has been an active gas play with over 3,500 wells drilled over the last 5 years. There is substantial evidence that the Antrim must be fracture stimulated to be economical and that two-stage treatments provide the best results. However, due to the shallow depths (500-2300 ft) and naturally fractured nature of the Antrim fracture geometry is complex, and determination of optimal fracture treatments is not straight forward. Because historical field comparisons did not provide insight on the optimal fracture treatments, the Gas Research Institute (GRI) instituted a field-based project for the specific purpose of evaluating the geometry of hydraulic fractures in the Antrim. Open- and cased-hole tests were performed on two separate Antrim wells - a shallow producer (600+/- ft) and a deep producer (1550 +/- ft). Open-hole testing and data collection consisted of in-situ stress and mechanical property testing with Halliburton's THETM Tool (9 tests) and a detailed suite of geophysical logs including dipole sonic logs and natural fracture detection logs. Cased-hole testing consisted of pre- and post-fracture injection/falloff tests, minifracture treatments, multiple isotope tracer and tracer logs. and treating pressure and production data analysis. Analysis of open- and cased-hole data from the shallow and deep wells suggests that subvertical fractures are being created and are probably following existing natural fracture planes. The shallow depths, low in-situ stresses, and extremely fractured nature of the Antrim probably results in the preferential opening of existing fractures instead of the creation of new fracture planes. As a result, the creation of multiple fractures and severe near wellbore tortuosity is likely. Therefore, the natural fractures are responsible for increased leakoff and will greatly impact created fracture geometry. The results also suggest that creating long propped hydraulic fractures in the Antrim is not likely due to the creation of multiple fractures. Introduction The Antrim Shale play in the Michigan Basin has been one oil, the most active plays in recent years with over 500 well completions in 1993 alone. Antrim gas production has increased dramatically, rising from about 10 Bscf/year in 1988 to over 90 Bscf/year in 1993. In 1992. GRI initiated a field-based program to advance competition technology in the Antrim. The research has four primary objectives: increasing the effectiveness of fracture stimulations, developing methods for screening restimulation candidates, identifying optimal recompletion candidates and procedures, and improving the understanding of the Antrim reservoir. This paper focuses on the testing performed to better understand how hydraulic fractures grow in the Antrim for the purpose of optimizing stimulation results. For this project, a cooperative well program was implemented with two active Antrim producers (See Fig 1). The Trader D2-25, a deep Antrim test well, was drilled in cooperation with HRF E&P and Chevron USA in Alcona Co, Michigan. The Hyder 2–26, a shallow Antrim well, was drilled in cooperation with Terra Energy in Montmorency Co, Michigan. The deeper COOP well was completed in the Antrim at a depth of about 1550 ft whereas the shallow COOP well was completed in the Antrim at a depth of about 600 ft. Two wells with different completion depths were selected to investigate if fracture geometry changes with depth. In the remainder of this paper, we provide a brief background on the Antrim, discuss current stimulation practices in the Antrim, and summarize the testing and results of the research program. P. 343
Abstract In many cases, the production prediction at the fracture design stage and later from the post-fracture pressure-matching exercise is never realized. The underperformance of fracture treatments is often attributed either to formation damage, proppant crushing and embedment, or to the poor reservoir quality despite a reasonably good reservoir property indicator from all sources including the pressure decline in a mini-fracture test. Based on several case studies, this paper highlights a number of issues that were found responsible for underperformance of fracture treatments. The understanding and mitigation of these issues require the application of comprehensive geomechanics. For each case, a comprehensive geomechanical model was built for the field, characterizing the depth profiles of all three stresses, rock mechanical properties and the direction of the horizontal stresses by integrating available data from various sources including drilling and logging data, laboratory rock test data and mini-fracture test data. The contrasts in stress and rock mechanical properties among various lithologies along the well path were created based on fundamental geomechanical principles. The hydraulic fracture growth was simulated as per the pressure-matching practice for each treatment carried out. The production condition was applied to the simulated propped fracture to predict the production and compare it with the actual production data where available. Issues that were found responsible for lower-than-expected production include (1) out-of-zone fracture growth that could not be predicted using the oversimplified geomechanics; (2) poor connection between wellbores and fractures for unfavorably oriented wells; (3) non-optimum perforation intervals that caused non-optimum fracture growth and near-perforation low conductivity; (4) malpractices in treatment execution that resulted in disconnected fractures with the perforations; and (5) suboptimal treatments for reservoir conditions. Appropriate mitigation strategies were recommended for wells in production, and increased productions were reported where the recommendations were implemented. One significant observation is that several oversimplified techniques currently used in the industry create significantly different stress contrast profiles than that was found based on fundamental physics of geomechanics, though all these profiles could be calibrated with the same closure pressure from a mini-fracture test. The use of such inaccurate stress contrast profiles is primarily responsible for unrealistic fracture and production predictions.
Zeinabady, Danial (University of Calgary) | Zanganeh, Behnam (University of Calgary, Chevron Canada Resources) | Shahamat, Sadeq (Birchcliff Energy Ltd.) | Clarkson, Christopher R. (University of Calgary)
Abstract The DFIT flowback analysis (DFIT-FBA) method, recently developed by the authors, is a new approach for obtaining minimum in-situ stress, reservoir pressure, and well productivity index estimates in a fraction of the time required by conventional DFITs. The goal of this study is to demonstrate the application of DFIT-FBA to hydraulic fracturing design and reservoir characterization by performing tests at multiple points along a horizontal well completed in an unconventional reservoir. Furthermore, new corrections are introduced to the DFIT-FBA method to account for perforation friction, tortuosity, and wellbore unloading during the flowback stage of the test. The time and cost efficiency associated with the DFIT-FBA method provides an opportunity to conduct multiple field tests without delaying the completion program. Several trials of the new method were performed for this study. These trials demonstrate application of the DFIT-FBA for testing multiple points along the lateral of a horizontal well (toe stage and additional clusters). The operational procedure for each DFIT-FBA test consists of two steps: 1) injection to initiate and propagate a mini hydraulic fracture and 2) flowback of the injected fluid on surface using a variable choke setting on the wellhead. Rate transient analysis methods are then applied to the flowback data to identify flow regimes and estimate closure and reservoir pressure. Flowing material balance analysis is used to estimate the well productivity index for studied reservoir intervals. Minimum in-situ stress, pore pressure and well productivity index estimates were successfully obtained for all the field trials and validated by comparison against a conventional DFIT. The new corrections for friction and wellbore unloading improved the accuracy of the closure and reservoir pressures by 4%. Furthermore, the results of flowing material balance analysis show that wellbore unloading might cause significant over-estimation of the well productivity index. Considerable variation in well productivity index was observed from the toe stage to the heel stage (along the lateral) for the studied well. This variation has significant implications for hydraulic fracture design optimization, particularly treatment pressures and volumes.
Summary Over the last 20 years, diagnostic fracture injection tests (DFITs) have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic-fracture-treatment parameters. Thousands of tests are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results because of either problematic data acquisition or incorrect analysis of the acquired data. This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided, including data resolution, pump rates, test duration, and fluid selection. Strategies are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis. The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight-gas and shale reservoirs because of the long data-acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor instantaneous-shut-in-pressure data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after-closure analysis.