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Clarkson, Christopher R. (University of Calgary) | Williams-Kovacs, Jesse (University of Calgary and Sproule Associated Limited) | Zhang, Zhenzihao (University of Calgary) | Yuan, Bin (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | Hamdi, Hamidreza (University of Calgary) | Islam, Arshad (Baytex Energy Corp.)
Abstract Recently it has been demonstrated that rate-transient analysis (RTA) performed on flowback data frommulti-fractured horizontal wells (MFHWs) can provide timely estimates of hydraulic fracture properties. This information can be used to inform stimulation treatment design on upcoming wells as well as other important operational and development decisions. However, RTA of flowback data may be complicated by rapidly changing operating conditions, dynamic hydraulic fracture properties and multi-phase flow in the fractures, complex fracture geometry, and variable fracture and reservoir properties along the MFHW, among other factors. While some constraints on RTA model assumptions may be applied through a carefully-designed surveillance and testing program in the field (e.g. to constrain fracture geometry), still others require laboratory measurements. In this work, an integrated flowback RTA workflow, designed to reduce uncertainty in derived hydraulic fracture properties, is demonstrated using flowback data from MFHWs producing black oil from low-permeability reservoirs in the Montney and Duvernay formations. The workflow includes rigorous flow-regime identification used for RTA model selection, straight-line analysis (SLA) to provide initial estimates of hydraulic fracture properties, and model history matching of flowback data to refine hydraulic fracture property estimates. The model history matching is performed using a recently-introduced semi-analytical, dual-porosity, dynamic drainage area (DP-DDA) model that incorporates primary (propped) hydraulic fractures (PHF) as well as a dual-porosity enhanced fracture region (EFR) with an unpropped (secondary) fracture network. Inclusion of both the PHF and EFR components addresses the need to incorporate both propped and unpropped fractures and fracture complexity in the modeling. The DP-DDA model is constrained using estimates of propped fracture conductivity and unpropped fracture permeability (measured as a function of stress), and unpropped fracture compressibility values, obtained in the laboratory for Montney and Duvernay core samples. Use of these critical laboratory data serves to improve the confidencein the modeling results. The case studies provided herein demonstrate a rigorous workflow for obtaining more confident hydraulic fracture property estimates from flowback data through the application of RTA techniques constrained by both field and laboratory data.
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.
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 (‘frac’) 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.
Abstract In recent years, several papers have been published on the subject of rock properties, stress and permeability models in the Vaca Muerta unconventional formation, with the intention of understanding fractured well performance. In most cases, however, these publications have failed on providing sufficient information to adequately describe the generated models, nor have studied in detail the benefits and limitations of applying different schools of thought and incorporating field measurements during the design and evaluation of hydraulic fractures. This work seeks to explain a systematic approach to characterize, constrain and validate such models through integration of prefrac diagnostic injections, core data, independently-determined fracture dimensions, and postfrac production data. The final objective is to build predictive models that can be used to improve completion strategies in this promising but still immature play.
Abstract Multiple fracture placements in single wells have a sixty year history with first applications soon after hydraulic fracturing was patented. Fracturing technology has been applied to offshore deviated wells, sand control wells, tight gas, coal, chalks, shales and conglomerates in turn as "conventional" reservoir limits were reached and each "new unconventional" reservoir was encountered. As fracturing technology was adapted to make an "unconventional" reservoir into a conventional reservoir, the adaptations and evolutions needed became part of the technology tool box waiting for the next challenge. Each innovation improved and stretched the reach of completions and production engineering as new findings were incorporated to monitor, model, optimize and extend the ranges of fracturing use for high and low temperatures, high stress formations and a variety of other challenges. This review looks at the development of multi-fractured wells from its first application in vertical wells where one well could now do the task of three wells, to the first modern application of highly multi-fractured horizontal wells used in chalks, shales and tight oil and gas reservoirs. The technical focus is on the learning procession covering details of casing wear, cyclic pressure application, isolation mechanisms, perforation placement, well spacing and fracture spacing. The technical literature and field learnings have both been searched for applicable information with a surprising variety of engineering application details brought forth that are useful in optimizing a single well or a whole development.
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.
Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 24-26 January 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract We conducted a series of hydraulic fracture initiation tests with fractured natural rock samples. The objective is to characterize the interaction between hydraulic fracture initiation and natural fracture infiltration and opening. The natural fracture was simulated by cleaving a rock cube into two or three layers and putting the parts back together. The hydraulic fracture is initiated by pressurizing the borehole drilled perpendicular to the layers.
Abstract In the design of hydraulic fractures, it is necessary to make simplifying assumptions. Fifty years ago, our industry was mathematically obliged to describe fractures as simple, planar structures when attempting to predict fracture geometry and optimize treatments. Although computing tools have improved, as an industry we remain incapable of fully describing the complexity of the fracture, reservoir, and fluid flow regimes. Generally, we make some or all of the following assumptions:–Simple, planar, bi-wing fractures –Completely vertical fractures with perfect connection to the wellbore –Flow capacity that is reasonably described by published conductivity data –Predictable fracture width providing dependable hydraulic continuity (lateral and vertical continuity) To forecast production from these fractures, we frequently make the additional assumptions:–Reservoir is laterally homogeneous –Modest/no barriers to vertical flow in formation (simplified description of layering compared to reality) However, we must recognize that all of these assumptions are imperfect. This paper will investigate the evidence suggesting that fractures are often subject to:–Complicated flow regimes –Complicated geometry –Irregular frac faces –Imperfect proppant distribution –Imperfect hydraulic continuity –Imperfect wellbore-to-fracture connection –Residual gel damage, possibly including complete plugging or fracture occlusion Additionally, reservoirs are known to contain flow barriers that amplify the need for fractures to provide hydraulic continuity in both vertical and lateral extent. The paper appendix tabulates the results from more than 200 published field studies in which fracture design was altered to improve production. Frequently the field results cannot be explained with our simplistic assumptions. This paper will list the design changes successfully implemented to accommodate real-world complexities that are not described in simplistic models or conventional rules of thumb. Field examples from a variety of reservoir and completion types [tight gas, modest perm oil, coalbed methane, low rate shallow gas, annular gravel packs] will be provided to demonstrate where the field results differ from expectations, and what adjustments are necessary to history-match the results.
Recent advances in hydraulic fracture mapping technologies have provided a wealth of information on fracture propagation in numerous geologic settings. Prior to such detailed measurements of actual fracture growth, fracture propagation was either assumed to be simple (single planar fracture) or the complexity was inferred based solely on fracturing pressure data. The nature or detail of this inferred fracture complexity and how it related to actual fracture growth (real fracture geometry) could not be determined. This resulted in significant uncertainty in fracture modeling, treatment designs, and many times, sub-optimum field development. This paper illustrates the application of the various methods and techniques available to diagnose fracture complexity, including simple pressure diagnostics such as G-function pressure decline analysis and sophisticated microseismic and tiltmeter fracture mapping technologies. After identifying complexity in hydraulic fracture growth, this information must be integrated with fracture, reservoir, and geologic models to properly evaluate stimulation, completion, and develop options; however, without properly identifying the nature and detail of the fracture complexity, the solution can many times be wrong - resulting in economic loss.
This paper documents field observations of different mechanisms that result in fracture complexity and the corresponding physics that govern fracture growth in these reservoirs. These field observations of fracture complexity are supplemented by and related to results from mine-back and core-through experiments to better understand the relationship between fracture complexity, rock properties, and geology. Distinguishing between the various types of fracture complexity and properly modeling these complexities (in both reservoir and fracture models) can lead to significantly different treatment designs and field development strategies. The paper includes field case histories that document how the remediation of fracture complexity can lead to stimulation success, while in other cases it is the exploitation of fracture complexity that is the key to success.
Abstract The term "unconventional reservoir" has different meanings to different people. Certain reservoirs termed unconventional have a rock matrix consisting of inter-particle pore networks with very small pore connections imparting very poor fluid-flow characteristics. Abundant volumes of oil or gas can be stored in these rocks, and often the rock is high in organic content and the source of the hydrocarbon. Yet because of marginal rock matrix quality, these reservoirs generally require both natural and induced fracture networks to enable economic recovery of the hydrocarbon. Rock types in this class include shale and coalbed methane (CBM.) The term shale is a catchall for any rock consisting of extremely small framework particles with minute pores charged with hydrocarbon and includes carbonate and quartz-rich rocks. Another type of unconventional reservoir is stacked pay units exhibiting somewhat better pore characteristics than in the case outlined above but with the individual units tending to be lenticular in shape and having an extremely small size or volume. These two classes of unconventional reservoirs are amenable to well stimulation and will be the focus of this paper. The above rock types when commercially exploited are known as resource plays. Once a low-priority, the depletion of conventional reservoirs and improving price for oil and gas has driven unconventional reservoirs to an important place in the oil and gas industry. In some regions (i.e., Rocky Mountain province), unconventional reservoirs represent the primary target of current activity and remaining hydrocarbon development. Given their unique petrophysical properties, each type of unconventional reservoir requires a unique approach to well stimulation, with often differing objectives than exist with conventional reservoir types. This paper reviews the characteristics of the basic unconventional reservoir types, lessons learned and successful stimulation practices developed in completing these reservoirs, and areas for improvement in treatment and reservoir characterization and treatment design. Introduction Unconventional reservoirs amenable to hydraulic fracturing are generally hydrocarbon-rich rocks with poor matrix characteristics. By matrix is meant the inter-particle pore network of the rock mass, with pore connections determining the rate of fluid flow from pore to pore or from pore to large flow channel (i.e., solution mold, fracture, or wellbore.) In unconventional reservoirs, pore interconnections are extremely small, significantly reduced in aperture by the liquid wetting-phase, and consequently fluid flow is extremely low. In the case of oil or gas-condensate reservoirs, low mobility of the viscous liquid phase and multi-phase flow worsens the situation. Sometimes, a change in reservoir fluid mobility within the accumulation causes a loss of commerciality and bounds the limits of the pay within the field. This is the case in the in the Codell sandstone (Wattenberg field, DJ Basin, northeast Colorado) as the thermally-influenced in-situ hydrocarbon phase changes from gas to oil along the boundaries of the field. A dense network of natural fractures or a combination of fractures and solution channels with adequate apertures are generally needed to enable flow of hydrocarbons at commercial rates, and drainage of the reservoir to a significant degree. Even with an improved pricing environment, the marginal flow properties and recovery factors of most unconventional reservoirs make necessary a continuous effort to reduce costs and improve efficiencies in all aspects of drilling, completing and producing these wells. Many of the recent improvements and innovations in well completions and hydraulic fracturing have been focused as much on the cost aspect as with improving well productivity.