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Collaborating Authors
Results
Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
- North America > Canada > Alberta (0.73)
- North America > Canada > British Columbia (0.63)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic-Fracture/Dynamic-Drainage-Area Leakoff Model Constrained by Laboratory Geomechanical Data
Zhang, Zhenzihao (University of Calgary) | Clarkson, Christopher (University of Calgary) | Williams-Kovacs, Jesse D. (University of Calgary and Sproule Associates) | Yuan, Bin (University of Calgary) | Ghanizadeh, Amin (University of Calgary)
Summary The application of rateโtransientโanalysis (RTA) concepts to flowback data gathered from multifractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulicโfracture volume/conductivity. However, the initial fluid pressures and saturation in the fracture network and adjacent reservoir matrix are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. In this study, we present a semianalytical flow model, coupled with a hydraulicโfracture (fracture) model and constrained with laboratoryโbased geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semianalytical model based on the dynamicโdrainageโarea (DDA) concept was used to simulate waterโbased fluid leakoff from an MFHW into a tight oil reservoir (Montney Formation, western Canada), with minimal mobile water, during and after fracturing operations. The model assumed that each fracturing stage can be represented by a primary hydraulic fracture (PHF) containing the majority of the proppant, and an adjacent nonstimulated reservoir (NSR) or enhanced fracture region (EFR), which is an area of elevated permeability in the reservoir caused by the stimulation treatment. Each region was represented by a singleโporosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through using a simple analytical fracture model. Although this approach was considered novel, several improvements and additional laboratory constraints were considered necessary to yield more accurate predictions of initial flowback conditions. In the current work, the modeling approach described previously was improved by representing the EFR with a dualโporosity system; fully coupling the fracture model (used for PHF creation and propagation) with the DDA model for fluidโleakoff simulation into the EFR and adding a proppantโtransport model; and modeling the shutโin period. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously gathered laboratory data was used. Laboratoryโderived propped (PHF) and unpropped (EFR) fractureโpermeability/conductivity data as a function of pore pressure, as well as fractureโcompressibility data, were used as constraints for the model. It should be noted that our model assumes that fracture closure has no effect on the pressure/saturation of the PHF/EFR/matrix. The improved model was reapplied to the tight oil field case and yielded more realistic estimates of initial flowback conditions, enabling more confident history matching of flowback data. The results of this study will be important to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring proper model creation.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Upper Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (6 more...)
Rigorous Modeling of Salt Transport During Frac, Shut-in, and Flowback to Constrain Hydraulic Fracture/Reservoir Property Estimates
Zhang, Zhenzihao (University of Calgary) | Clarkson, Christopher (University of Calgary) | Williams-Kovacs, Jesse (University of Calgary) | Yuan, Bin (University of Calgary) | Ghanizadeh, Amin (University of Calgary)
Abstract Quantitative flowback analysis can be used to obtain early hydraulic fracture property estimates which, in turn, can be used to guide stimulation and well operations decisions on future wells/pads. Most quantitative studies of flowback data have primarily utilized rate and pressure data to derive fracture/reservoir properties. However, salinity data contains important additional information that can be used to constrain flowback modeling. In this work, salt transport modeling is combined with a previously-developed frac-through-flowback model based on the dynamic drainage area (DDA) concept in order to constrain the reservoir matrix and hydraulic fracture property estimates. The mechanisms of salt mixing, dispersion/diffusion and advection are captured in the salt-transport model. In previous work, an integrated model comprised of the following components was developed: 1) hydraulic fracture propagation and proppant transport model; 2) leakoff model; and 3) flowback model. The integration of these components has proven useful for a) constraining hydraulic fracture property estimates (e.g. fracture half-length) and b) modeling the initial pressure and saturation conditions in the fractures and reservoir at the start of flowback. The inclusion of salt transport modeling during flowback to match salinity profiles also helps to constrain matrix and fracture property estimates. For this purpose, salt mixing, dispersion/diffusion, and advection during hydraulic fracturing treatment, subsequent shut-in, and flowback are modeled using a finite-difference-based salt-transport model coupled with a black-oil simulator. The salt transport model was validated against the analytical solution for a diffusion-advection problem, while the black-oil simulator was verified with CMG-IMEX. The coupled salt-transport/black-oil simulator was then tested against a field case to demonstrate its practical applicability. Water salinity during flowback was precisely matched using the coupled salt-transport/black-oil simulator for the field case. The matrix permeability evaluated using the frac-through-flowback model was constrained by history matching the flowback salinity data using the developed simulator. Laboratory-derived stress-dependent properties served to reduce the number of simulation runs performed during history-matching. The distribution of chemical species in the reservoir was tracked using the new model. Advection and advection-related dispersion were found to be the dominant mechanisms affecting flowback salinity, contrary to the findings of some previous studies.
- Africa (0.93)
- North America > Canada > Alberta (0.47)
- North America > United States > Pennsylvania (0.46)
- North America > United States > Texas (0.46)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (8 more...)
Empirical Links Between Sub-Surface Drivers and Engineering Levers for Hydraulic Fracture Treatments and the Implications for Well Performance
Stephenson, Ben (Shell Canada) | Bai, Taixu (SEPCO) | Huckabee, Paul (SEPCO) | Tolle, John (SEPCO) | Li, Ruijian (SEPCO) | MacDonald, Jeff (Shell Canada) | Acosta, Luis (Shell Canada)
Abstract Does the sub-surface drive completion design or is the rock less of a concern with industry trends to higher proppant-, fluid- and stage-intensities? To address this challenge it was first necessary to understand; 1) how the sub-surface could potentially influence completion and stimulation design, 2) what are the available engineering levers and moreover, 3) whether well performance has actually been impacted by tailoring completions in different plays from specific case-studies. Although there is a multitude of published field examples of how completion design changes have driven value, clarity around the inter-connectedness with sub-surface variability, either between plays or within a play, is commonly missing. New templates have been developed that describe the conceptual links between the nine key 'Sub-surface Drivers' for hydraulic fracturing and their associated engineering Levers categorized by well-, fluid-, proppant- and stage-design. These templates are a compilation of extensive empirical observations from both operations and field performance reviews incorporating thousands of wells across North America, supported with learnings from geomechanical theory and modeling. The nine Sub-surface Drivers that influence completion design and control the access to hydrocarbons are, 1) mobility, 2) reservoir pressure, 3) gross thickness, 4) layering heterogeneity, 5) rock stiffness, 6) natural fractures, 7) stress anisotropy, 8) risk of fraccing faults and, 9) risk of fraccing out of zone. Drivers 1-7 govern the connectivity, whereas 8 and 9 influence stimulation ineffectiveness. It is proposed that there are approximately fifteen primary engineering Levers related to these nine Drivers, which have been shown to have a measurable impact on completion effectiveness and/or production. Case studies illustrate that the Sub-surface Drivers play a significant role in most plays, but they are not all relevant in every play. The challenge is to acknowledge the variability, or lack of, and pursue completion design optimization goals, while managing the variance in the well performance range. Whereas industry trends of increasing completions intensity have delivered more value in many plays, the Sub-surface Drivers concept have primarily proven useful to mitigate against poor wells in development and explain exploration failures. By developing a systematic set of templates for Drivers and their respective levers, learnings from other operators can be high-graded through the formulation of connectivity analogues with the goal of showing where changes in completion design may be more, or less applicable.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (0.93)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.46)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (37 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (6 more...)
ABSTRACT The Montney play is the most actively drilled unconventional oil and gas producing field in Canada. Compared to North America's top plays, there is the upside potential for completion designs regardless of geology. It is supported by the statistical evidence [1]. Well productivity and project economics of unconventional field development are highly dependent on the effectiveness of hydraulic fracturing. The mechanism of hydraulic fracturing is complicated due to interference between the multiple factors. Not only the geological heterogeneities such as natural fractures but also the stress heterogeneity influence the fracture propagation and fluid flow. To investigate the interference, a multidisciplinary approach is rationalized to model pressure depletion associated stress properties. The primary objective of this study is to optimize the completion design and fracture stimulation operation design. For this purpose, we measured and analyzed the well performance through the data as the first phase of this study to derive the key completion factors; drilling, completion, production volume, and pressure data were analyzed to understand the completion performance and possible controllable factors related to the current completion design. Figure 1 shows the study workflow, the aim of optimizing a well completion design for shale gas wells located in the North Montney area since 2017. In first phase of this study, the production team focused to evaluate the SRV, Stimulated Reservoir Volume, and EUR, Estimated Ultimate Recovery, then, we worked for permeability estimation and validation.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Upper Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.91)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (0.86)
Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic Fracture/Dynamic Drainage Area Leakoff Model Constrained by Laboratory Geomechanical Data
Zhang, Z. (University of Calgary) | Yuan, B. (University of Calgary) | Ghanizadeh, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Williams-Kovacs, J. D. (University of Calgary)
Abstract The application of rate-transient analysis (RTA) concepts to flowback data gathered from multi-fractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic fracture properties. However, the initial fluid pressures and saturations in the fracture network, and adjacent reservoir matrix, are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. A possible approach to recreate these initial conditions is to simulate fluid leakoff during hydraulic fracture propagation (during the stimulation treatment) and subsequent shut-in period prior to flowback. In this study, we present a semi-analytical flow model, coupled with a hydraulic fracture (โfracโ) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semi-analytical model based on the dynamic drainage area (DDA) concept was used to simulate water-based fluid leakoff from a MFHW into a tight oil reservoir with minimal mobile water (Montney Formation) in Western Canada during and after fracturing operations. The model assumes that each fracturing stage can be represented by a primary hydraulic fracture (PHF, containing the majority of the proppant), and adjacent non-stimulated reservoir (NSR) or enhanced fracture region (EFR, area of elevated permeability in reservoir caused by the stimulation treatment). Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through the use of a simple analytical frac model. While this approach was considered novel, several improvements, and additional laboratory constraints, were considered necessary to yield more accurate predictions of flowback initial conditions. In the current work, the modeling approach described above was improved byrepresenting the EFR with a dualporosity system and fully coupling the frac model (used for PHF creation and propagation) with the DDA model for fluid leakoff simulation into the EFR. Improvement 1) was considered necessary to more realistically represent the spatial distribution of fluids in the EFR and associated saturations and pressures. Improvement 2) was considered necessary to more realistically control PHF propagation speed. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously-gathered laboratory data was utilized. Laboratory-derived propped (PHF) and unpropped (EFR) fracture permeability/conductivity data as a function of pore pressure, as well as fracture compressibility data, were used as constraints to the model. The improved model was re-applied to the tight oil field case and yielded more realistic estimates of flowback initial conditions, enabling more confident history-matching of flowback data. The results of this study will be of importance to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring that models are properly initiated.
- North America > United States > Texas (0.68)
- North America > United States > California (0.67)
- North America > Canada > Alberta (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Upper Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- (9 more...)
Combining Statistical Analysis With Simulation to Optimize Unconventional Completions - Upper and Lower Montney Formations, Canada
Mohammed, Omar Q. (North Oil Company) | Kassim, Rashid (Missouri University of Science & Technology) | Britt, Larry K. (NSI Fracturing LLC) | Dunn-Norman, Shari (Missouri University of Science & Technology)
Abstract The Montney Formation which extends from Alberta to British Columbia is one of the largest unconventional gas resources in North America. Production from the Montney Formation comes primarily from the Upper Montney and Lower Montney Formations which vary both from reservoir quality and geomechanical perspectives. Historically, completion and stimulation optimization fell into two distinct categoriesfield observation supported by reservoir and fracture simulation or statistical analysis. Few, if any, statistical studies on optimizing unconventional completions and fracture stimulation combined information from the statistical analysis with that of the simulation. This paper does just that for the Montney Formation by comparing and contrasting the Upper and the Lower Montney completions and fracture stimulation statistical results with a reservoir and fracture simulation study to better understand key drivers for successful stimulation of multiple fractured horizontal wells. Previous work (Mohammed et al., 2016) documented the statistical analysis of 296 cased-hole horizontal gas wells' completions in the Upper and the Lower Montney Formation. The study showed the effect of cased-hole completion and stimulation parameters on gas production performance in both the Upper and the Lower Montney Formations. In this paper, previous statistical results were extended by adding hydraulic fracture modeling using 3D finite element simulator (Stimplan3D). The results from the statistical analysis and hydraulic fracture modeling were compared on a set of parameters such as the effect of the number of clusters per stage (1-to-5), changes in proppant mass (50% decrease or increase) and treatment volumes. This study investigated fracture performance to find the best fracturing practices for the Upper and the Lower Montney.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- (2 more...)
Abstract Recently, several authors have explored new methods for quantitatively analyzing multi-phase flowback data from multi-fractured horizontal wells (MFHW) to extract both fracture and reservoir parameters. These techniques provide much of the same information as long-term rate-transient analysis (RTA), although in a much shorter period of time. Flowback analysis is complicated by a rapidly changing fracture network and wellbore environment, multi-phase flow in the fractures (and possibly the reservoir), completion heterogeneity, as well as other effects which are often not present, or are ignored, when analyzing long-term (online) production data. For quantitative flowback analysis, the current authors have previously presented data-driven, pseudo-analytical methods for estimating key fracture properties (i.e. conductivity and half-length) from high-frequency, short-duration production test data. Models have been developed for both oil and gas wells representing a variety of reservoir and operating conditions. In this work, the models and procedures are extended to apply to more challenging reservoir/completion scenarios and are used in the analysis of several case studies from Canada. Each of the case studies demonstrate either the potential value add of the developed techniques, or a unique extension to the basic analysis methods. The case studies analyzed herein focus on light tight oil plays and consider layered reservoirs, multi-well flowback, and oil fracs in oil reservoirs. Further, the potential capital savings associated with conducting quantitative flowback analysis of early-time production test data is demonstrated. Each case study therefore presents a unique set of challenges that are often encountered in the real world. Numerical simulations are used to validate the sequence of flow-regimes depicted in the models. The methods presented in this paper will serve to partially satisfy the demands of industry to develop new methods for characterizing hydraulic fractures and forecasting production, particularly early in the well life. Through the use of several unique case studies, the wide-spread applicability and versatility of the techniques is demonstrated.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.47)
- North America > Canada > British Columbia (0.46)
- Research Report (0.68)
- Overview > Innovation (0.54)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Otter Park Formation (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (6 more...)
Abstract Multistage hydraulic fracturing technique now applied with horizontal wells and over large areas has enabled commercial production of oil and gas from low-permeability rock formations, changing the energy landscape in North America. In these reservoirs, tons of fracturing fluid and proppants are pumped into the reservoir matrix to create hydraulic fractures and it is important to understand the propagation mechanism of hydraulic fractures and further optimize their properties. In addition, natural fractures are often present in the shale and tight formations, which might be activated during the fracturing process and contribute to the after-stimulation well production rates. In this paper, reservoir simulation is coupled with rock mechanics to predict the well after-stimulation production performance. Firstly, a dual-permeability geological model is built based on field data collected from a well pad in Montney formation, Canada. Fracturing fluid flow in the formation coupled rock mechanics is employed to simulate dynamic hydraulic fracturing process. More specifically, as the continuous injection of fracturing flurry, the effective stress will decrease accordingly. When the effective stress reaches the rock failure criteria, hydraulic fractures will be generated, allowing the fracturing liquid to flow along the fractures. Based on the fracturing operational schedule, dynamic hydraulic fracturing simulation is conducted and results show that hydraulic fractures tend to propagate upward first until it connects the entire formation in the vertical direction. Early production history of the stimulated well is then matched to valid the simulated fracture geometries. Finally, the effects of natural fractures and well bottom-hole pressure on well production are studied. Results show that if natural fracture can be propped or partially propped by the proppants, the production will be increased significantly for shale liquid rich gas plays. This paper provides a significant insights on the fracture propagation and can be a reference for fracturing treatments in unconventional shale reservoirs.
- North America > United States (1.00)
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (9 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (4 more...)
Abstract The dominant flow regime observed in many hydraulically-fractured tight/shale gas wells is linear flow. This flow regime may continue for several years, and will ultimately become boundary-dominated flow, at much later times. Nobakht et al. (2010) introduced a simplified method of production forecasting for tight/shale gas wells which exhibit extended periods of linear flow. The method is simple as it relies principally on a plot of inverse gas rate versus square root time, and it is rigorous in that it is based on the theory of linear flow and combines the linear flow transient period with hyperbolic decline during boundary-dominated flow. In the present work, this simplified method is reviewed and applied to almost 90 wells producing from the Montney formation in N.E. British Columbia, Canada. The vast majority of these wells exhibit linear flow for extended periods of time. The advantages of the simplified forecasting method are: (1) It is not biased towards any flow regimes, as no superposition time functions are used; (2) Reliable forecasts can be obtained without invoking pseudo-time and its associated complexities; and (3) The only parameter that needs to be specified externally is the drainage area. The method can be used for forecasting horizontal wells with multiple hydraulic fractures. By assigning different drainage areas to each fracture, a relationship can be developed between expected ultimate recovery (EUR) and original gas in place (OGIP) assigned to each fracture. This translates into recovery factor versus number of fracture stages. The resulting forecasts can be used directly to examine the economics of multi-stage fracturing.
- North America > Canada > British Columbia (0.70)
- North America > Canada > Alberta (0.69)
- North America > United States > Texas (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- (2 more...)