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Collaborating Authors
Drillstem/well testing
Abstract During hydraulic fracturing process, different hydraulic loading and stress status of formations result in hydraulic fractures with various geometries and properties. Several propagation models including PKN and KGD have been widely applied in fracturing design and implementation. However, in the process of post-stimulation modeling, fractures are usually simplified with uniform geometries and conductivity distribution; therefore the effects of actual fracture geometry and proppant properties on the well transient pressure and production performance remain unclear. This study intends to comprehensively study the fractured wells with 2-D and 3-D non-uniform geometry and conductivity distribution. In the development of shale gas reservoirs and tight oil formations, horizontal well multistage fracturing is the key technology. The modeling results presented in this paper can help offer valuable information of reservoir properties, evaluate the conductivity distribution of propped fractures, simulate more realistic fracture configurations, and help optimize fracture treatment process and fractured wells’ performances with improved accuracy. A semi-analytical approach coupling fluid flow in reservoir and fractures existed in more realistic shape with non-uniform conductivity distribution has been developed to obtain well transient pressure and production responses. Source and sink function method is utilized to solve unsteady state flow problems of fluid flowing from reservoir to non-uniform fractures with geometries that are well defined in PKN, KGD and other generally ideal models. The effect of fracture conductivity with linear and stepwise distribution, and elliptic fracture shape variations has been investigated. Comparison study has been highlighted to illustrate effects of fracture geometry and conductivity distributions. Realistic hydraulic fractured wells with non-uniform fracture geometry and conductivity have been studied to showcase a consistent workflow of entering fracture properties from hydraulic fracturing models and outputting fractured well performance prediction in post-stimulation reservoirs. Instead of assuming pseudo-steady state flow status between reservoir and fracture, unsteady state flow problems related to non-uniform fracture geometric have been solved in a semi-analytical manner with solution of near analytical accuracy. More realistic fracture geometries estimated from fracture propagation models can be entered into post-stimulation models without idealized simplification; thus the gap between fracture propagation and post-stimulation modeling has been fulfilled.
Incorporating Geomechanical and Dynamic Hydraulic Fracture Property Changes into Rate-Transient Analysis: Example from the Haynesville Shale
Clarkson, C. R. (University of Calgary) | Qanbari, F.. (University of Calgary) | Nobakht, M.. (Encana Corporation and University of Calgary) | Heffner, L.. (Goodrich Petroleum)
Abstract It is well-known that many unconventional reservoirs experience porosity and permeability changes with pressure change during production. In recent work, authors have incorporated geomechanical modeling into production analysis procedures to account for stress-sensitivity of permeability of unconventional gas reservoirs, such as shale gas. Such corrections are necessary for deriving both accurate estimates of reservoir and hydraulic fracture properties from rate-transient analysis and for developing accurate long-term forecasts. Some shale gas reservoirs are unique in that dynamic changes may occur in both the induced hydraulic fracture AND matrix permeability, which could have a substantial impact on shale gas productivity. Stress-dependence of shale gas permeability has been quantified in the lab by several researchers, but measurements of this kind for propped or unpropped fractures under in-situ conditions are less routinely measured. For the latter, a variety of mechanisms, caused in part or wholly by stress changes in the induced hydraulic fracture, could lead to conductivity changes. In the current work, we investigate the impact of both stress-dependent matrix permeability and fracture conductivity changes on 1) rate-transient signatures and 2) derived reservoir and hydraulic fracture properties. Stress-dependent matrix permeability is incorporated into rate-transient analysis using modified pseudopressure and pseudotime formulations, and fracture conductivity changes are approximated by applying a time-dependent (dynamic) skin effect. We demonstrate that when rate-transient analysis incorporates both matrix permeability changes and dynamic skin, the resulting rate-transient signature looks very similar to other shale plays (long-term transient linear flow). Uncorrected data appear to have a very short transient linear flow period, followed by apparent boundary-dominated flow. The impact of the applied corrections on estimates of system permeability and fracture half-length is demonstrated as is the impact on production forecasts.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (0.84)
- Research Report (0.46)
- Overview (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract A common way to produce hydrocarbons from tight reservoirs is to use horizontal wells with multiple hydraulic fractures. In many cases, fractures do not have a simple bi-wing shape, but are branched. For modeling purposes, branch-fracturing can be represented by a high permeability region near each fracture, while the bulk of the space between the fractures remains unstimulated. This paper presents an analytical model to simulate the flow rate and pressures for such a reservoir system. The model is a variation on the tri-linear flow solution. It is simple, and flexible enough to be applicable to multi-frac horizontal wells. The model takes into account three linear flow regimes: flow within the fracture (at very early time), flow within the stimulated region towards the fracture and flow within the un-stimulated region towards stimulated region. The model was validated by comparing its results with synthetic data sets generated using numerical simulation; the results showed excellent agreement. This paper illustrates the various flow regimes and how they are affected by reservoir and completion parameters. The characteristic features of each flow regime are demonstrated using typecurves. History matching of actual field case is presented to illustrate the practicality of the model. The proposed analytical solution provides a practical alternative to numerical solutions, and saves significant computational time.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
The Bakken formation in the Williston Basin has been rapidly developing since 1980s; however, the recent advancements in horizontal well completion and stimulation technology play a key role in the success of today's Bakken production. Pressure buildup tests, mini-DSTs and mini-frac tests are valuable sources of information for determining key reservoir properties, such as permeability. The Bakken formation is comprised of an upper and a lower organic-rich black shale and a middle silty dolostone or dolomitic siltstone, and sandstone member. The Bakken is overlain by the Lodgepole formation which consists of a dense, dark gray to brownish gray limestone and a gray calcareous shale and underlain by the Three Forks formation which is composed of thinly interbedded greenish gray and reddish brown shale, light brown to yellow gray dolostone, gray to brown siltstone, quartzite sandstone and minor occurrences of anhydrite (Kume, 1963). Historically, horizontal wells in the Bakken were drilled in the Upper Bakken formation while the recent developments have changed the focus to the Middle Bakken and Three Forks formations. Historically, when a reservoir interval has been productive it has been attributed to natural fractures (Murray, 1968). Natural fractures include regional fractures, local stress fractures and local micro-fractures resulting from pore fluid over-pressuring. Although fractures are typically determined by examining cores, image logs, and structural curvature, pressure transient tests could provide additional insight in deciphering the presence of fractures and their flow contribution.
- North America > United States > North Dakota (1.00)
- North America > Canada (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage. Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico—located in the North-East area of the country and bordered with South Texas in the USA—problems still persist. This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension. This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Wyoming > Sweetwater County (0.41)
- North America > United States > Texas > Vicksburg Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Queen City Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (31 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Tight reservoirs stimulated by multistage hydraulic fracturing are commonly described by a dual porosity model. This model consists of homogeneous matrix blocks separated by vertical hydraulic fractures. This paper hypothesizes that the production data of some fractured horizontal wells may also be described by a triple porosity model. The third medium can be either reactivated natural fractures or thin horizontal beds with a higher permeability. We test this hypothesis by extending the existing triple porosity models to develop an analytical procedure for determining the reservoir parameters. We derive the simplified equations for different regions of the rate-time plot including linear and bilinear flow regions. These equations can be used to calculate the effective fracture half-length, matrix permeability and length of micro-fractures. We use the proposed model to analyze the production data of two wells drilled in Barnett shale. The results show that a dual porosity model is more appropriate for describing Barnett shale data. Even if the micro-fractures are present they are not inter-connected and the length scale is much smaller than the hydraulic fracture spacing. The second part of this paper focuses on analyzing production data of tight oil reservoirs. We plot rate-normalized pressure (RNP) versus material balance time (MBT) of two wells drilled in Cardium and Bakken formations. We observe a half-slope followed by a unit-slope in both cases. This paper hypothesizes that the half slope reflects the linear transient flow regime, and the unit slope reflects the linear pseudosteady state (PSS) flow. We test this hypothesis by developing a new model for pseudo steady state flow when pressure interference occurs between two adjacent hydraulic fractures. We determine the reservoir properties by both PSS and transient analysis methods. For Cardium well, both methods give very close results. For Bakken well, both methods give relatively close results. We conclude that analyzing the late time production data of tight oil wells complement the linear transient analysis and can be used to calculate the stimulated reservoir volume, which can eventually help the industry to optimize the fracturing operation.
- North America > Canada > Alberta (0.94)
- North America > United States > Texas (0.87)
- North America > United States > South Dakota (0.69)
- (3 more...)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.75)
- Geology > Geological Subdiscipline (0.69)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (31 more...)
Abstract Stimulated Reservoir Volume (SRV) is an engineering concept developed for the purposes of quickly evaluating the effective well drainage area and analyzing the actual performance of a multistage horizontal well in tight formation. Usually SRV is defined using microseismic event mapping. However, there are many other factors hindering the realization of the correct SRV value and largely impairing its engineering application. A simplified integrating model with multiple regions that combines the near wellbore engineered reservoir area, the SRV region, the original tight formation area and the outbound reservoir region, named as region I, II, III and IV, respectively, were built and analyzed systematically, where the region I confines the horizontal wellbore with multiple artificial hydraulic fractures and allows the integration of complex skin factor distribution, region II intends to capture the influence of SRV under various parametric settings such as fracture networking and matrix-fluid mobility variations, region III accommodates the general geological information for the original large scale tight formation environment and region IV supports the information input for the outbound reservoir environment. The multiple region modeling has been successfully built and applied to understand the relationship among wellbore, fracture, SRV and original reservoir formation. Theoretical study on the transient pressure and rate responses were conducted to address the technical challenge encountered. The results, presenting in a type curve format under various conditions, have shown that SRV region is strongly related to the fracture influenced/dominated boundary flow regime and appears as a region possessing a less than 1 slope in pressure and reciprocal rate derivative curves, which indicates that the flow process has reached the theoretical SRV boundary, i.e., the fracture influenced area/boundary. However, the derivative value would not reach one due to the inflow from the outside original reservoir region. This phenomenon is a symbolic feature of tight formation with SRV connectivity, as many field cases have been so indicated. This work allows a quick estimation of SRV region, a better understanding of the influence of the complicated wellbore configurations and a way to characterize the reservoir connectivity between SRV and original/outbound tight formation reservoir.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Field > Barnett Shale Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.98)
- (7 more...)
Abstract Multi-stage fractured horizontal wells (MFHW) in unconventional resource plays often present formidable reservoir management challenges, particularly with regard to capital utilization and allocation. In this study, well performance histories of some 74 wells in the Montney siltstone play were investigated with a common and consistent analytical framework. Parameters determined from the analyses are key indicators of the combined result of reservoir quality and hydraulic fracture performance (subsurface and completions). The analytical approach utilized in this study was then used to provide robust physics-based forecasts that directly recognize and incorporate interpretation non-uniqueness. Through a forecasting regimen that explicitly provides expected ranges of results, insights and conclusions in field optimization, well spacing and completions design have been drawn. A real distribution of well productivity and predicted recovery enabled identification of "sweet spots". Openhole completions technique did not show poorer performance compared to limited entry style completions, though further evaluation and surveillance would seem warranted. Wells that were flowing under a "high-drawdown" showed a lower productivity, higher completion resistance (skin) to flow, and lowest predicted final recovery. Wells completed at 50 m fracture spacing and 30 tonnes of proppant per cluster performed similarly to 100 m spacing and 60 tonnes per cluster, suggesting no apparent difference in capital efficiency between these two completion styles. Results indicate that the frac half lengths in the 50 m cluster spacing wells are shorter compared to wells with 100 m cluster spacing (based on the reduction in the amount of proppant pumped per cluster). Trends of estimated original gas-in-place inside the SRV and predicted 30-year recovery for wells drilled at close well spacings, (closer than 400 m between wellbores) indicate effects of inter-well interference. Performance of wells at 200 m well spacing seem to be affected the most by inter-well interference. A consistent workflow for analyzing well performance and predicting future performance of MFHW in unconventional gas wells is presented that provides a means to assess the impact of business and development decisions and determining practices worth replicating across the Montney play.
- North America > United States (1.00)
- North America > Canada > Alberta (0.67)
- North America > Canada > British Columbia (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.72)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Executing Minifrac Tests and Interpreting After-Closure Data for Determining Reservoir Characteristics in Unconventional Reservoirs
Ewens, S.. (Fekete Associates Inc.) | Idorenyin, E.. (Fekete Associates Inc.) | O’Donnell, P.. (Fekete Associates Inc.) | Brunner, F.. (Fekete Associates Inc.) | Santo, M.. (Fekete Associates Inc.)
Abstract Pore pressure (pi) and flow capacity (kh) are difficult to ascertain in ultra-low permeability formations due to poor inflow prior to stimulation. Furthermore, radial flow does not develop in horizontal wells completed with massive multi-stage hydraulic fractures. As a result, industry is turning to alternate testing methods, conducted prior to the main hydraulic fracture treatments. Of these, minifrac tests are rapidly gaining acceptance as the most practical way to obtain good estimates of pore pressure and flow capacity in unconventional reservoirs. Unfortunately, these test objectives are often unrealized when design and execution of the minifrac test are conducted with other objectives in mind. Even after a mechanically successful test has been concluded, there can be confusion over how to interpret the after-closure data. This paper outlines recommended operational guidelines for conducting minifrac tests with the purpose of estimating pore pressure and flow capacity. In addition, various aspects of after-closure analysis are investigated and examples are used to show that all after-closure analysis techniques, when applied correctly, are applicable and give consistent estimates of pore pressure and flow capacity. The power of using analytical models to enhance after-closure analysis is demonstrated.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Rate- and pressure-transient analysis of unconventional gas and oil reservoirs is a challenge because of complex reservoir characteristics that dictate flow. An important flow regime for analysis of these reservoirs is transient linear flow, which can be associated with linear flow to induced hydraulic fractures or to horizontal wells. One of the complications in the analysis of this flow regime is stress-sensitivity of porosity and permeability. This work aims to provide a method for analyzing transient linear flow in reservoirs with stress-sensitive permeability. Flow of a compressible fluid in a stress-sensitive formation is governed by a nonlinear second order partial differential equation (PDE) with nonlinearities in both the accumulation and flow differential terms. A version of the Kirchhoff transformation is used to make the accumulation term linear, while a monotonically varying nonlinearity (as a function of a new pseudopressure function introduced in this work) exists in the flow differential term. The transformation, however, does not introduce any nonlinearity to the constant-wellbore pressure-condition, which is the case for constant well flow rate. An exact solution of the transformed nonlinear PDE is provided for pressure distribution and flow rate calculations. The results are compared with approximate solutions in which fluid and rock properties are considered to be constant and evaluated at a specified pressure, as obtained by the error function (erf) solution. The results show that, at the wellbore, the value of the slope of the square-root of time plot (reciprocal of flow rate vs. square-root of time) can be used to calculate one of the two parameters, permeability modulus or initial permeability. This is the case if the derivative of the Kirshhoff parameter with respect to the Boltzmann variable is known for different values of fluid and rock compressibility, permeability modulus, and pressure drawdown. In this study, the Fujita’s method is used to calculate the derivative for some ranges of the affecting parameters. The results are presented as plots which can be used for analyzing the production data.
- North America > United States (0.93)
- Europe > United Kingdom > England (0.28)
- Europe > Norway > Norwegian Sea (0.24)