|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Summary In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate‐ and pressure‐transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed in this study do not address complex transport mechanisms and complex fracture networks, but do address transient matrix linear flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a, 2012b; Chen and Raghavan 2013) and boundary‐dominated flow (BDF). The methods for BDF are the contacted‐volume methods based on the ending times of linear flow (Wattenbarger et al. 1998; Behmanesh et al. 2015) and the flowing material‐balance (FMB) methods. The Agarwal‐Gardner FMB method (Agarwal et al. 1999) and the conventional FMB method involve plotting rate‐normalized pseudopressure vs. material‐balance pseudotime. We delineate the advantages and limitations associated with each method and identify the best methods of interpretation and analysis. Three different production modes—constant rate (CR), constant bottomhole pressure (BHP) (CBHP), and variable‐rate BHP—are considered. For comparison, various synthetic test data sets generated from a high‐resolution spectral gas simulator, which treats nonlinear gas flow rigorously and accurately to simulate rate‐transient data, is used. Both synthetic noise‐free and noisy‐rate pressure‐data sets considering wide ranges of initial reservoir pressure and BHP, as well as real‐field data sets, are used to compare the methods. For linear flow, the Nobakht‐Clarkson method (Nobakht and Clarkson 2012a, 2012b) yields the best results, although its use is tedious because it requires an iterative procedure. The Chen and Raghavan (2013) method for linear flow seems to provide results that are comparable with the Nobakht‐Clarkson method (Nobakht and Clarkson 2012b) but does not require an iterative procedure. The Ibrahim‐Wattenbarger method (Ibrahim and Wattenbarger 2006) for linear‐flow analysis always overestimates flow capacity compared with the other methods. Among the methods that discuss the ending time of linear flow, it was found that the unit‐impulse method from Behmanesh et al. (2015) provides the best results for predicting gas in place. For BDF, the results show that the Agarwal‐Gardner FMB method (Agarwal et al. 1999) is quite vulnerable to the error in rate/pressure data, whereas the conventional FMB method is more robust to noise and provides more accurate estimates of gas in place.
Summary Hydraulic‐fracturing treatments in shale infill wells are often impacted by existing parent‐well depletion and asymmetrical fracture growth. These phenomena can result in excessive load‐water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials (i.e., far‐field diverting agents) for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings. Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted‐stress environment. A slotted‐disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post‐hit parent‐well condition. Production trends of the influenced wells were compared to area‐specific type curves and offset wells without diverter trials. On the basis of the simulation and testing results, two types of high‐graded far‐field diverter systems were field‐tested in a shale play: dissolvable, extremely fine particulate mixed with a 100‐mesh sand, and mixtures of a nominal 325‐mesh silica flour and a 100‐mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High‐graded blends of the above diverting systems demonstrated superior fracture‐hit and productivity metrics as compared to the base case of not applying far‐field diverters. The silica flour and 100‐mesh‐sand mixture performed on a par with the significantly more expensive blend of dissolvable fine particulate and 100‐mesh sand. Borate‐crosslinked‐guar gel was an effective carrying fluid for transporting diverting materials to the fracture extremities. Statistical analysis of fracture‐hit events shows that the application of far‐field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post‐hit pressure‐falloff rate at the parent wells. On the basis of the area‐specific type curves, pumping far‐field diverters increased the P50 estimated ultimate recovery (EUR) by approximately 6% compared with the base cases of not applying diverters. For all the wells impacted by far‐field diverters, the infill wells saw larger benefits with an increment of P50 EUR by approximately 7% compared with the parent wells.
Hydraulic-fracturing treatments in shale infill wells are often impacted by existing parent-well depletion and asymmetrical fracture growth. These phenomena can result in excessive load-water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials (i.e., far-field diverting agents) for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings.
Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted-stress environment. A slotted-disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post-hit parent-well condition. Production trends of the influenced wells were compared to area-specific type curves and offset wells without diverter trials.
On the basis of the simulation and testing results, two types of high-graded far-field diverter systems were field-tested in a shale play: dissolvable, extremely fine particulate mixed with a 100-mesh sand, and mixtures of a nominal 325-mesh silica flour and a 100-mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High-graded blends of the above diverting systems demonstrated superior fracture-hit and productivity metrics as compared to the base case of not applying far-field diverters. The silica flour and 100-mesh-sand mixture performed on a par with the significantly more expensive blend of dissolvable fine particulate and 100-mesh sand. Borate-crosslinked-guar gel was an effective carrying fluid for transporting diverting materials to the fracture extremities.
Statistical analysis of fracture-hit events shows that the application of far-field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post-hit pressure-falloff rate at the parent wells. On the basis of the area-specific type curves, pumping far-field diverters increased the P50 estimated ultimate recovery (EUR) by approximately 6% compared with the base cases of not applying diverters. For all the wells impacted by far-field diverters, the infill wells saw larger benefits with an increment of P50 EUR by approximately 7% compared with the parent wells.
Atadeger, Aykut (The University of Tulsa) | Batur, Ela (The University of Tulsa and Turkish Petroleum Corporation) | Onur, Mustafa (The University of Tulsa) | Thompson, Leslie G. (Cimarex Energy Company)
Abstract In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate and pressure transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed are based on transient matrix linear flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a, 2012b; Chen and Raghavan 2013) and boundary-dominated flow due to the stimulated reservoir volume (SRV). The methods for boundary-dominated flow are the contacted volume methods based on the ending times of linear flow (Wattenbarger et al. 1998; Behmanesh et al. 2015) and the material balance methods (FBMs); Agarwal-Gardner method (Agarwal et al. 1999) and conventional method involving plotting rate-normalized pseudo pressure versus pseudo time material-balance time. We delineate the advantages and limitations associated with each method and identify the best methods of interpretation and analysis. Three different production modes; constant rate (CR), constant bottomhole-pressure (CBHP), and variable-rate/bottomhole pressure, are considered. For comparison, various synthetic test data sets generated from a high-resolution spectral gas simulator, which treats nonlinear gas flow rigorously and accurately to simulate rate transient data, is used. Both synthetic noise-free and noisy rate/pressure data sets considering wide ranges of initial reservoir pressure and bottomhole pressure as well as real field data sets are used to compare the methods. For linear flow, the Nobakht-Clarkson method yields the best results, although its use is tedious as it requires an iterative procedure. The Chen-Raghavan method for linear flow seems to provide comparable results to the Nobakht-Clarkson method, but does not require iterative procedure. The Ibrahim-Wattenbarger method for linear flow analysis always overestimates flow capacity as compared to the other methods. For boundary dominated flow, the results show that the Agarwal-Gardner FBM method is quite vulnerable to the error in rate/pressure data, while the conventional FBM method is more robust to noise and provides more accurate estimates of gas in place. Among the methods based on the ending time of linear flow, it was found that unit-impulse method based on Behmanesh et al. (2015) provides best results for predicting gas in place.
The Zhou semianalytical method established the relationship between two adjoining segments. The mass balance for each segment (i.e., inflow must equate to outflow) is satisfied (Zhou et al. 2013; Yu et al. 2016, 2017; Xiao et al. 2017, 2018). This method can be used to simulate the fluid flow in complex fractures. As stated, the classic Cinco-Ley semianalytical method is the most-popular method to perform calculations for a well with planar fractures (Cinco-Ley et al. 1978) and nonplanar fractures (Luo and Tang 2015a). Figure 1 compares the Cinco-Ley method and the Zhou method. The figure shows that (1) the Zhou method establishes linkages between two adjoining nodes, whereas the Cinco-Ley method establishes linkages between a node and the wellbore (see red double arrow); (2) for the Fredholm integral equation, the wellbore pressure can be expressed explicitly by the flow rate of each segment (see the equation in Figure 1a). By coupling the Fredholm integral equation into the reservoir equation, the wellbore pressure and flow rate of each segment can be obtained without solving the pressure of each segment for the Cinco-Ley method; (3) the wellbore pressure, however, is expressed implicitly by the flow rate and pressure of the adjoining node for the Zhou method (see the equation in Figure 1b). To obtain the wellbore pressure, the pressure and flow rate of each segment must be solved simultaneously, and an inverse matrix will be used. Thus, more unknowns will be solved for the Zhou method.
Summary Multifractured horizontal wells (MFHWs) have become the most commonly used technology for developing unconventional oil and gas reservoirs. Because unconventional reservoirs are currently the focus of exploration and exploitation around the world, a growing number of researchers and scholars are concentrating on production-performance evaluation of unconventional MFHWs to obtain the stimulated reservoir volume (SRV) or hydraulic-fracture properties, which are usually obtained from expensive reservoir tests or production logs. Rate-transient-analysis (RTA) techniques that use continuous-production and flowing-pressure data have proved to be convenient and applicable approaches to estimate the reservoir parameters and hydraulic-fracture properties. Although many cases or work flows of RTA have been previously studied, most of those works were performed for shale-gas or conventional reservoirs. Few studies on RTA have been conducted for MFHWs completed in tight oil reservoirs, particularly for actual field cases in which the usually scattered production data significantly increase the difficulty in analyzing the production performance. In this research, the authors focus on using convenient and economical methods (RTA techniques) to obtain the SRV parameters and hydraulic-fracture properties that characterize the fracturing-treatment effectiveness of an actual MFHW in a tight oil reservoir, which many engineers and technical personnel expect to achieve. A comprehensive work flow [including production-data filtering, flow-regime diagnosis, straight-line analysis, type-curve matching (TCM), analytical-model analysis (AMA), numerical-model analysis (NMA), and uncertainty and nonuniqueness analysis] has been developed to perform a production-performance analysis of an MFHW completed in a tight oil reservoir. In particular, two approaches for calculating the permeability of SRV (kSRV) and effective half-length of hydraulic fracture (Xf) have been introduced. Moreover, the dual permeability parameters, the storativity ratio, and the interporosity coefficient (ω and λ, respectively), have been derived to enter into the AMA model to improve the accuracy of history matching. With the combination of AMA and NMA, the estimated ultimate recovery (EUR) of an actual MFHW completed in a tight oil reservoir can be predicted. Considering the uncertainty and nonuniqueness of the original reservoir parameters or nature of the adopted methods, a probabilistic analysis using Monte Carlo simulation has been performed to address the uncertainty of the analysis results. In addition, a simplified application of the developed method has been introduced. To demonstrate the feasibility and practicability of the developed work flow, two field cases from an actual tight oil reservoir have been analyzed. The consistent analysis results for field cases validate the developed work flow and proposed methods.
Summary Production from multistage-fractured horizontal wells (MFHWs) in shale reservoirs causes stress changes that further influence the conductivities of hydraulic fractures. Moreover, many shale rocks are strongly anisotropic. The objective of this study is to semianalytically model hydrocarbon-flow dynamics in reservoirs with MFHWs. The effects of stress-sensitive hydraulic fractures and shale anisotropy are considered. First, this study explores the relationship between principal-stress and pore-pressure changes in anisotropic shale. Second, an exponential correlation is further incorporated to describe the fracture conductivities vs. pore-pressure changes in anisotropic shale. The exponential correlation is validated by matching experimental data of fracture conductivities vs. effective stress. The fracture compressibility df in the exponential equation is stress-dependent rather than constant. Next, this study discretizes each hydraulic fracture into several source segments. For each segment in each timestep, pressure distribution is calculated with source/sink functions. Both the stress field and the hydraulic-fracture conductivities are updated according to the pressure distribution with the previously mentioned correlations before starting the next timestep. In addition to the constant-bottomhole-flowing-pressure condition, nonconstant bottomhole pressure (BHP) in real-field cases can also be entered for this semianalytical model. The model is validated by comparing its results with numerical simulations. A series of type curves q vs. t is generated on the basis of model calculations. The type curves are applied to investigate the effects of initial fracture conductivity Fci, initial fracture compressibility dfi, declining rate of fracture compressibility β, shale anisotropy, and the BHP profiles on MFHW transient-rate behavior. To maximize the hydrocarbon production, the BHP profile must be adjusted on the basis of fracture stress-sensitive characteristics. The semianalytical model is used to analyze two field cases with different pwf profiles under the influence of stress-sensitive hydraulic fractures.
Abstract Historically, different fracture diagnostic methods have been used for hydraulic fracturing treatments to obtain estimates of reservoir characteristics, fracture design parameters, and treatment progress. However, the advent of horizontal drilling techniques and expanded interest in unconventional reservoirs has increased the challenges to overcome to achieve a successful hydraulic fracturing treatment. This paper details advancement made to conventional methods of fracture diagnostics to meet these emerging challenges. A comprehensive study was conducted on the latest advancements in different diagnostic techniques. Several published case histories were studied where these techniques were adapted and modified from their conventional form. The effectiveness of the advanced techniques in terms of providing additional information was analyzed. A comparative review of the diagnostic methods was performed to determine individual limitations and to identify fit-for-application scenarios. An attempt was made to classify and categorize them according to the ease of application and usefulness for treatment design and analysis. This study suggests that proper planning, deployment, execution, and analysis of the techniques are essential to helping prevent erroneous conclusions about the treatment and job design. When conducted in unconventional reservoirs, conventional pressure diagnostic methods, as a result of the underlying assumptions of rock properties and fracture geometry, can be interpreted inaccurately. Use of high-fidelity forward models for the inversion of data acquired through these methods can lead to better understanding and help mitigate incorrect interpretation of the results. Similarly, fracture injection-falloff analysis combined with microseismic monitoring and distributed temperature and acoustic (DTS/DAS) data can provide deeper insight into the treatment, particularly for horizontal wells with simultaneously propagating multiple transverse fractures. Thus, a synergistic combination of different diagnostic techniques leads to more effective treatment designs and should be preferred if economically justified. The current work provides information on advanced fracture diagnostic methods and is useful for determining suitable diagnostic techniques for designing hydraulic fracture treatments.
Abstract Multi-stage acid fracturing in a tight carbonate formation can be an alternative to propped fracturing as a relatively cost-effective completion treatment. However the success of the treatment depends on many factors as to whether enough conductivity by acid etching has been created, and weather the selected chemical treatment has worked well in-situ under the specific geologic environment. Thus, observation and evaluation of past practice is important to develop further optimal stimulation procedures. In this paper, an integrated methodology to conduct performance evaluation of multi-stage acid fracturing treatment in a horizontal well is presented. The method is applied to a field case in Tarim Basin in China. The integrated procedure starts with obtaining closure pressure and the formation breakdown pressure. Bottomhole treating pressure is then estimated from surface treating pressure in cases if it is not measured directly. A treatment pressure history match is then conducted to estimate the fracture geometry using commercial software. A 3-D acid fracture conductivity profile is generated using the in-house acid fracture simulator. Then using the reservoir face pressure and the acid fracture conductivity profile obtained by the acid fracture simulator, the cross-sectional flowing area created by acid fracturing fluid is estimated using pressure transient analysis. Evolution of fracture extension and acid etching during the stimulation is calculated assuming a bilinear flow regime. After production starts, a linear flow diagnostic approach provides the cross-sectional area flowing that has the flow from the matrix. This enables us to compare flowing cross-sectional area with induced area by the stimulation, which is defined as treatment efficiency. A field application based on the proposed procedure shows the effectiveness of the approach. The integrated approach provides engineers with additional information as to whether the designed acid fracturing has been performed appropriately under high closure stress field. It is eventually helpful to discuss past practice and improve candidate selectivity in a company decision making process.
Abstract Reliable and fast prediction of fractured well performance is vital for asset evaluation and prudent field development decision making in unconventional, low permeability oil and gas reservoirs. Simple low cost techniques such as decline curve analysis are ill suited of properly accounting for extended transient flow regimes. Numerical simulation techniques on the other hand are unrivaled in capturing geological details and high accuracy in fluid flow description. However, they suffer from high computational expense and often too little relevant data is available. Our objective is to develop an efficient semi-analytical solution that combines the advantages of speed and accuracy from both techniques for forecasts on single well, pad and even field level. Contrary to conventional oil and gas reservoirs, the tight reservoir characteristics allow for the application of analytical solutions to predict the behavior of fractured wells. The depth of investigation is small with spatial property variations having limited influence considering the large local pressure gradients. Fluid flow is mainly of transient nature and less dominated by multi-phase flow effects within the reservoir. Moreover, the typical configuration of an individual well with multiple fracture stage, entire pads with multiple wells or even entire assets allow the application of the superposition in space, providing a cheap means for accurate solution for multi-well problems. This paper presents a transient semi-analytical model based on a tri-linear formulation. It accurately captures fluid flow to a single or multiple fractured wells over the entire life cycle of production, from early linear flow to pseudo-steady boundary driven flow. It is applicable to oil or gas reservoirs with permeabilities ranging from nano-Darcies to approximately one milli-Darcy. It is capable of handling both the vertical and horizontal well type, with either single or multiple fracture stages respectively. Well-bore, stage and pad configurations can be freely parametrized. A tubing head pressure boundary condition is incorporated to model production from those wells more realistically. For shale type reservoirs, a desorption process is incorporated. The model is particularly suitable for quantitative evaluation of field development alternatives involving a large number of fractured wells. The accuracy compared to a high resolution numerical simulation model generally exceeds 90% with a computation speedup factor in the order of one hundred or more. Besides conventional benchmarking with a numerical reservoir simulator, actual field production data from the Marcellus and Eagleford shale wells shows the utility of the new solution. Being both fast and accurate, the technique presented in this paper is ideal for supporting high quality, cost efficient decision making which is crucial in the current low oil price environment.