Trends In Unconventional Gas - Halliburton

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D r i l l i n g & Pr o d u c t i o n in the rock matrix. Gas-content determination is largely independent of the core porosity and permeability, but is a function of methane adsorption within the coal macerals. Prospectors may tend to rely on nonspecific seam lithotypes and assumed values for adsorption isotherms. Gas contents are calculated with assumed isotherms, reservoir pressures, and gross seam thickness. Although these estimates are appropriate during early prospect evaluation, they must be validated through direct-core measurement in Phase 2. A complete coal-seam anatomy can be obtained and applied to the macroscale reservoir. 3. Well logging. Significant technical breakthroughs in well logging have been developed specific to CBM. Perhaps the greatest advances involve log-processing methods and core-log integration techniques. Table 2 provides recommended log suites for projects in Phases 2 through 5. Electric microimaging (EMI) logging may provide the closest thing to a continuous core as currently possible. It can be integrated with the whole core so that grayscale levels can be correlated to discrete core lithology. Such integration can be performed in one well and applied across the field or basin that lacks core information. 4. Cleat permeability determination. Three technologies are potentially available for cleat permeability determination and are applied predominantly through Phases 2 and 3: • Openhole discrete-seam drillstem testing (DST). • Interference testing and injection fall-off. • G-function derivative analysis. DST technology can enable the highgrading of discrete seams for subsequent production during the corehole process. Multiwell interference testing can enable the acquisition of far-field regional cleat permeability and permeability anisotropy. G-function analysis, primarily used for comparing regional variations, can enable near-field qualitative cleat permeability information to PROJECT LIFE-CYCLE PHASES Fig. 2 Phase 1— Core / single well Phase 4— 60 wells mature Phase 1— 5-spot Phase 1—5-spot Phase 1—Core / single well be obtained in conjunction with the hydraulic fracturing parameters. 5. Primary hydraulic fracture stimulation. Very few coal-seam gas reservoirs can produce commercial rates of methane without some type of primary production enhancement. Three primary proven stimulation technologies have been developed for enhancing CBM production: cavitation, underreaming, and hydraulic fracture stimulation. Historically, the most effective technology Phase 1—Core / single well Phase 3—22 wells early Phase 5—180 wells mature / declining Phase 1—5-spot Phase 2— Phase 1—Core / single well 12 wells early Phase 2—16 wells early Phase 3—40 Phase 1—5-spot wells early 2 x 2 Phase 1— 5–spot Phase 1— Core / single well INTEGRATING RESOURCE-ASSESSMENT, SIMULATION DATA Fig. 3 1 Core desorption 2 Openhole log OH test information 3 Coal-seam diffusivity data 8 Multiseam production results 10 Reservoir production model and extractable reserves evaluation 7 Geologic and stratigraphic information 2 x 2.5 9 Single-seam production results 6 Coal core study information 4 Regional permeability/ interference test data 5 Regional and core-based fracture analysis appears to be hydraulic fracturing although novel stimulated horizontal and complex wells are rapidly becoming viable alternatives to traditional vertical hydraulically fractured wells. In the early phases, a technically, rather than economically, optimal fracturing system is critical to acquire valid gas and water producibility data for subsequent reservoir simulation and sensitivity analysis. Early development of fracture-design simulation No. z080121OGJdwy02.eps No. z080121OGJdwy03.eps
model(s) can match the outcome of the development-phase treatments and provide dependable predictions for future economic fracture treatments. Recent technological developments have enhanced hydraulic fracturing for CBM resource evaluation. Because the indiscriminate application of fracturing fluids to coal reservoirs contributes to production performance, identifying an optimal fracturing system during resource evaluation phase is critical. Economic constraints regarding mobilization and logistics, especially in frontier regions where little or no service infrastructure exists, largely drive fracture design decisions. If the goal of a single test well in a frontier region is to demonstrate that free gas can be produced to verify gas saturation, then a relatively small, low-cost hydraulic fracture design may be more appropriate than one designed for fullscale production. 6. Secondary production enhancement. During the final two life-cycle phases, technologies focusing on secondary production enhancement are increasingly important for extending the life of the CBM field. Technologies enabling the extension of Phases 4 and 5 include the following: • Hydraulic refracturing of previously fractured wells. • Hydraulic fracturing of previously cavity-completed wells. • Chemical-enhancement additives designed to mitigate specific impairment mechanisms included as part of the hydraulic fracturing system. Such remedial “backflush” technologies can be economic, repeated on the same well, and extend Phase 4 for years. 7. Infill drilling. Tapping into new reservoirs in a development field is an enabling technology because it has significantly helped extend Phases 4 and 5 of a mature CBM prospect. Because infrastructure investments have been capitalized, combining this approach with secondary production-enhancement methods offers a solution to stopping or stabilizing field or basin-wide production declines. Reservoir modeling and historymatching the field’s cumulative production can help identify infill-drilling candidates. Combined with geospatial Recommended log suites for specific phases Table 2 –––––––– Phase ––––––– Log suite 2 3 4 5 High-resolution spectral density log X X X High-resolution gamma ray X X X High-resolution dual-spaced neutron X X High-resolution induction X X Microlog X X X Magnetic resonance imaging log (if applicable) X X Electric microresistivity imaging log Wave sonic tool (dipole sonic) Thermal multigate decay pulsed neutron (if also evaluating sands) run through casing Dual-spaced neutron (if not evaluating sands) run through casing X X well-pattern optimization, infill drilling can be optimized for a given asset within a basin or field. Emerging technology involving multilateral and directional drilling may eventually replace verticalwell infill drilling for CBM. Currently, economics are looking more favorable for widespread application of innovative multilateral and directionally drilled well completions in coal. 8. Treatment selection. Determining an optimum stimulation treatment involves experimentation, but the following guidelines can help operators avoid misapplications and decrease the learning curve. The following steps can be used for planning treatments in areas where few or no CBM completions have been performed. Typically, coalbeds are categorized by: • Type of coal, coal thickness, and stratigraphy. • Proppant needs and desired proppant concentrations. • Field economics, including service costs, accessibility and availability, and potential gas rates. • Cleanup concerns or needs for long-term dewatering of well. • Job design process, including frac-modeling simulation (pressuredependent leakoff (PDL) concerns, rate effects, etc.). When a well contains several coal seams that will act as producing zones, differences between zones may prevent the success of a single fracture design. Economics seldom allow operators to pump optimum jobs for each zone, even when the zones are X X fractured separately. 9. Optimizing hydraulic technology. Helping to define hydraulic technology should be considered early and evolve throughout the entire lifecycle, particularly in the local asset evaluation, single test well, and five-spot subphases. Fracturing fluids selection and optimization for hydraulic-fracturing technology is key in the local asset evaluation, single test well, and fivespot subphases. In these early phases, a technically optimal fracturing system is critical in acquiring valid gas and water producibility data for subsequent reservoir simulation and sensitivity analysis. Later in the well’s life, emphasis can be shifted from technology to efficiency optimization. Realistically, the time in which an optimum fracturing design can be achieved depends on several factors, including the following: • The volume of available information about the seam(s) that will be fracture stimulated. • How this CBM reservoir responds to fracturing compared to existing CBM reservoirs. Fracturing treatments that incorporate the use of fines control and surface modification agent (SMA) provide both fines and proppant flowback control. This allows the operator to produce the wells with the pump at or below the lowest perforations for optimum efficiency. Increased run times with fewer workovers improve the dewatering efficiency, shortening the time to maximum gas desorption. • The technical background and CBM stimulation experience of the team member(s) responsible for developing
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Trends In Unconventional Gas - Halliburton

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