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Modeling Two-Phase Flowback of Multifractured Horizontal Wells Completed in Shale
- Christopher R. Clarkson (University of Calgary) | Jesse Williams-Kovacs (University of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- July 2013
- Document Type
- Journal Paper
- 795 - 812
- 2013. Society of Petroleum Engineers
- 2.2.2 Perforating, 5.6.9 Production Forecasting, 4.1.2 Separation and Treating, 5.2.2 Fluid Modeling, Equations of State, 5.8.2 Shale Gas, 5.3.2 Multiphase Flow, 5.6.5 Tracers, 5.8.3 Coal Seam Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation
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Early fluid production and flowing pressure data gathered immediately after fracture stimulation of multifractured horizontal wells may provide an early opportunity to generate long-term forecasts in shale-gas (and other hydraulically fractured) reservoirs. These early data, which often consist of hourly (if not more frequent) monitoring of fracture/formation fluid rates, volumes, and flowing pressures, are gathered on nearly every well that is completed. Additionally, fluid compositions may be monitored to determine the extent of load fluid recovery, and chemical tracers added during stage treatments to evaluate inflow from each of the stages. There is currently debate within the industry of the usefulness of these data for determining the long-term production performance of the wells. "Rules of thumb" derived from the percentage of load-fluid recovery are often used by the industry to provide a directional indication of well performance. More-quantitative analysis of the data is rarely performed; it is likely that the multiphase-flow nature of flowback and the possibility of early data being dominated by wellbore-storage effects have deterred many analysts.
In this work, the use of short-term flowback data for quantitative analysis of induced-hydraulic-fracture properties is critically evaluated. For the first time, a method for analyzing water and gas production and flowing pressures associated with the flowback of shale-gas wells, to obtain hydraulic-fracture properties, is presented. Previous attempts have focused on single-phase analysis. Examples from the Marcellus shale are analyzed. The short (less than 48 hours) flowback periods were followed by long-term pressure buildups (approximately 1 month). Gas+water production data were analyzed with analytical simulation and rate-transient analysis methods designed for analyzing multiphase coalbed-methane (CBM) data. This analogy is used because two-phase flowback is assumed to be similar to simultaneous flow of gas and water during long-term production through the fracture system of coal. One interpretation is that the early flowback data correspond to wellbore+fracture volume depletion (storage). It is assumed that fracture-storage volume is much greater than wellbore storage. This flow regime appears consistent with what is interpreted from the long-term pressure-buildup data, and from the rate-transient analysis of flowback data. Assuming further that the complex fracture network created during stimulation is confined to a region around perforation clusters in each stage, one can see that fluid-production data can be analyzed with a two-phase tank-model simulator to determine fracture permeability and drainage area, the latter being interpreted to obtain an effective (producing) fracture half-length given geometrical considerations. Total fracture half-length, derived from rate-transient analysis of online (post-cleanup) data, verifies the flowback estimates. An analytical forecasting tool that accounts for multiple sequences of post-storage linear flow, followed by late-stage boundary flow, was developed to forecast production with flowback-derived parameters, volumetric inputs, matrix permeability, completion data, and operating constraints. The preliminary forecasts are in very good agreement with online production data after several months of production. The use of flowback data to generate early production forecasts is therefore encouraging, but needs to be tested for a greater data set for this shale play and for other plays, and should not be used for reserves forecasting.
Al-Ahmadi, H.A., Almarzooq, A.M., and Wattenbarger, R.A. 2010. Applicationof Linear Flow Analysis to Shale Gas Wells-Field Cases. Paper SPE 130370presented at the SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania,23-25 February. http://dx.doi.org/10.2118/130370-MS.
Barree, R.D., Barree, V.L., and Craig, D.P. 2009. Holistic FractureDiagnostics: Consistent Interpretation of Prefrac Injection Tests UsingMultiple Analysis Methods. SPE Prod & Oper 24 (3): 396-406.http://dx.doi.org/10.2118/107877-PA.
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Clarkson, C.R. 2012b. Modeling 2-Phase Flowback of Multi-FracturedHorizontal Wells Completed in Shale. Paper SPE 162593 presented at the SPECanadian Unconventional Resources Conference, Calgary, Alberta, 30 October-1November. http://dx.doi.org/10.2118/162593-MS.
Clarkson, C.R. and Beierle, J.J. 2011. Integration of Microseismic and OtherPost-Fracture Surveillance with Production Analysis: A Tight Gas Study. J.Natural Gas Sci. and Eng. 3 (2): 382-401. http://dx.doi.org/10.1016/j.jngse.2011.03.003.
Clarkson, C.R., Jensen, J.L., and Blasingame, T.A. 2011. ReservoirEngineering for Unconventional Gas Reservoirs: What Do We Have to Consider?Paper SPE 145080 presented at the SPE North American Unconventional GasConference and Exhibition, The Woodlands, Texas, 14-16 June. http://dx.doi.org/10.2118/145080-MS.
Clarkson, C.R., Jordan, C.L., Ilk, D. et al. 2012. Rate-transient Analysisof 2-Phase (Gas + Water) CBM Wells. J. Natural Gas Sci. and Eng. 8:106-120. http://dx.doi.org/10.1016/j.jngse.2012.01.006.
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Clarkson, C.R. and Pedersen, P.K. 2010. Tight Oil Production Analysis:Adaptation of Existing Rate-Transient Analysis Techniques. Paper SPE 137352presented at the Canadian Unconventional Resources and International PetroleumConference, Calgary, Alberta 19-21 October. http://dx.doi.org/10.2118/137352-MS.
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Crafton, J.W. 2008. Modeling Flowback Behavior or Flowback Equals"Slowback". Paper SPE 119894 presented at the SPE Shale Gas ProductionConference, Fort Worth, Texas, 16-18 November. http://dx.doi.org/10.2118/119894-MS.
Crafton, J.W. 2010. Flowback Performance in Intensely Naturally FracturedShale Gas Reservoirs. Paper SPE 131785 presented at the SPE Unconventional GasConference, Pittsburgh, Pennsylvania, 23-25 February. http://dx.doi.org/10.2118/131785-MS.
Crafton, J.W. and Gunderson, D. 2006. Use of Extremely High Time-ResolutionProduction Data To Characterize Hydraulic Fracture Properties. Paper SPE 103591presented at the SPE Annual Technical Conference and Exhibition, San Antonio,Texas, 24-27 September. http://dx.doi.org/10.2118/103591-MS.
Crafton, J.W. and Gunderson, D. 2007. Stimulation FlowbackManagement—Keeping a Good Completion Good. Paper SPE 110851 presented at theSPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14November. http://dx.doi.org/10.2118/110851-MS.
Fan, L., Thompson, J.W., and Robinson, J.R. 2010. Understanding GasProduction Mechanism and Effectiveness of Well Stimulation in the HaynesvilleShale Through Reservoir Simulation. Paper CSUG/SPE 136696 presented at theCanadian Unconventional Resources and International Petroleum Conference heldin Calgary, Alberta, Canada, 19-21 October. http://dx.doi.org/10.2118/136696-MS.
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Larsen, L. and Hegre, T.M. 1991. Pressure-Transient Behavior of HorizontalWells With Finite-Conductivity Vertical Fractures. Paper SPE 22076 presented atthe International Arctic Technology Conference, Anchorage Alaska, 29-31 May. http://dx.doi.org/10.2118/22076-MS.
Mayerhofer, M.J., Lolon, E.P., Warpinski, N.R. et al. 2010. What IsStimulated Reservoir Volume? SPE Prod & Oper 25 (1): 89-98.http://dx.doi.org/10.2118/119890-PA.
Nobakht, M. and Clarkson, C.R. 2012. A New Analytical Method for AnalyzingLinear Flow in Tight/Shale Gas Reservoirs: Constant-Flowing-Pressure BoundaryCondition. SPE Res Eval & Eng 15 (3): 370-384. http://dx.doi.org/10.2118/143989-PA.
Nobakht, M. and Mattar, L. 2012. Analyzing Production Data FromUnconventional Gas Reservoirs With Linear Flow and Apparent Skin. J. Cdn.Pet. Tech. 51 (1): 52-59. http://dx.doi.org/10.2118/137454-PA.
Ramurthy, M., Barree, R.D., Kundert, D.P. et al. 2011. Surface Area vs.Conductivity-Type Fracture Treatments in Shale Reservoirs. SPE Prod &Oper 26 (4): 357-367. http://dx.doi.org/10.2118/140169-PA.
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