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Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
Abstract This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient. Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes. Bachman et al (2012, 2015), Hawkes et al (2018) and Nicholson et al (2019) advanced DFIT analysis by using the Pressure Transient Analysis (PTA) technique. This allows the identification of flow regimes useful for understanding fracture geometry and closure behavior beyond that available from more familiar G-function analysis techniques. In this paper DFITs from the Duvernay, Montney, Rock Creek and Cardium formations of Western Canada are analyzed using the PTA method. Particular attention is given to Early-Time Flow Regimes (ETFRs) present between the end of pump shut-down (End of Job Instantaneous Shut-In Pressure, EOJ ISIP) and the 3/2-slope Nolte flow regime. Identification of pressure gradients at the start and end of these flow regimes is of vital importance to the interpretation process. This allows the authors to build on case histories of DFIT-derived fracture geometry interpretations presented in Nicholson et al (2017, 2019). Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient.
Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes.
Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
Abstract This paper will benefit engineers and geoscientists interested in creating representative hydraulic fracture simulation models and optimizing commercial-scale fracture treatments. The paper focuses on the emerging Duvernay shale formation in Alberta, Canada. Well fracturing pressures are often significantly higher than the Overburden (OB, lithostatic) pressure. Pressures above OB likely create horizontal (hz) bedding plane fracture components since sedimentary rocks are almost always weaker along bedding planes. Most fracture design simulators do not account for the simultaneous existence of multi-plane fractures (Figure 1). Therefore, scaled treatment designs for optimizing fluids, proppant schedules and production performance may be flawed. A key question is: What proportion of the overall fracture volume do horizontal-plane features take? The answer can be sought using the Pressure Transient Analysis (PTA) workflow for Diagnostic Fracture Injection Tests (DFITs) described by Bachman et al (2012, 2015) combined with simple PKN and GDK fracture models to represent the hz and vertical plane fracture components. DFIT analysis techniques and interpretation are hotly debated topics of late. The authors believe a portion of the gap in the understanding of how hydraulic fractures behave is a result of assuming fracture components are fully, or dominantly, vertical. Analysts often interpret high fracturing pressures as tortuosity or near-well friction. However, during the fall-off period after pumping a DFIT, pressures above OB can persist for up to 20 minutes after pump shut-down. Analysis of these tests often exhibit early-time radial flow signatures which are coincident with the OB gradient of ~22kPa/m (1psi/ft) also indicative of hz plane fractures. In Nicholson et al 2017 four field DFIT examples were presented showing strong evidence of hz plane fractures in various depths and formations found in the Western Canadian Sedimentary Basin. In the current paper DFIT PTA analysis is applied to two West Shale Basin Duvernay datasets. A physical model is presented (Figure 1) that incorporates the in-situ stress regime, rock fabric, and pore pressure and that allows history matching of DFIT leak-off and closure behavior for fractures above OB pressure. Simple calculations are provided to estimate the volume and dimensions of these same components for a small volume, single viscosity, no-proppant injection DFIT. This unique approach provides a valuable calibration point for building more advanced simulation models.
Abstract Mini-frac or Diagnostic Fracture Injection Tests (DFITs) are typically performed to understand hydraulic fracturing behavior and calculate reservoir properties in low-permeability oil and gas wells.Four wells, all from Western Canada Sedimentary Basin (WCSB) settings, are reviewed. The first two wells are at substantially different depths but each is within a thrust-fault stress setting (minimum stress = vertical stress). The third well is in a strike/slip stress environment, and the fourth is in a normal stress environment. Traditional DFIT interpretation relies on the G-Function plot. This plot frequently indicates Height Recession/Transverse Storage (HR/TS), which has a concave-upward trend, or "belly", on the G-dP/dG curve. Alternatively, some highly complex behavior can be seen prior to the onset of Nolte flow. The Pressure Transient Analysis (PTA) based Bourdet/Primary Pressure Derivative (PPD) log-log plot sometimes shows what would be considered a pre-closure radial flow regime. For a shallow thrust fault setting this can be an indicator of horizontal plane tensile fractures and a second higher closure stress. For the other stress regimes, radial flow can result from horizontal bedding plane slip at pressures below the overburden stress gradient. This requires that the coefficient of friction at the interface, fracture pressures, and in-situ stress are within a certain range. A simple mathematical model based upon the PKN hydraulic fracture geometry is developed to show how bedding-plane slip can occur even in a normal stress setting. Further mathematical modeling is then developed to show the extent to which bedding-plane shear fractures can occur in comparison to the vertical fracture component. This has implications for DFIT analysis and full-scale hydraulic fracture treatment design. Lastly, concepts are proposed for possible modifications to the design of hydraulic fractures where bedding-plane fractures may occur.
Abstract The Montney formation In NE British Columbia and NW Alberta is one of the largest economically feasible resource plays in North America. It contains both gas and liquids rich light ends. Horizontal multi-staged fracturing is the method for developing this vast resource. Prior to hydraulically fracturing the wellbore, the toe stage is frequently mini-fraced to obtain reservoir and geomechanical properties. Interpreting these mini-fracs, commonly referred to as DFIT’s (Diagnostic Fracture Injection Tests), has proved to be a challenge using traditional combination G Function and square root plots. It is always important to ensure that all data being analyzed is associated with a reservoir response and not wellbore behavior, surface operational interruptions or data quality issues. Some of these challenges can be overcome when using some new techniques for mini-frac Fall-off analysis, which will be discussed in this paper. Various pressure transient analyses (PTA) based interpretation techniques have been introduced to the industry over the last couple of years for the determination of closure pressure (Bachman et al. 2012, Mohamed et al. 2011 and Marongiu-Porcu et al. 2011). From a theoretical viewpoint, unification of the fields of traditional PTA and mini-frac interpretation has been achieved. We recommend that the standard PTA based log-log derivative plot using equivalent time is included in the analysis of mini-frac / fall-off tests. This plot is rarely, if ever, used in current interpretations. For mini-frac interpretation, the starting point should now be the standard PTA based log-log derivative plot. The primary pressure derivative (dp/dt) curve should also be added to the log-log derivative plot as an independent flow regime identification technique. This now gives two independent flow regime identification techniques in one plot. The power of the primary pressure derivative to enhance the interpretation of closure and flow regime identification will be illustrated. Subsequently, flow regime specific plots can be constructed to enhance the interpretation. A number of field examples from the Montney formation in the Farrell Creek area of NE British Columbia are illustrated using a systematic PTA interpretation methodology demonstrating multiple closure events, high fracture extension pressure gradients of 34.0 kPa/m, non-Darcy pressure derivative diagnostics and observation of complex fracture orientation.
Abstract Over the last several years, horizontal drilling and multi-stage hydraulic fracturing have become the norm across the industry and proved crucial for economic production of natural gas from unconventional shale gas and ultra tight sandstone reservoirs, also referred to as nano-Darcy reservoirs. Following the success of the Barnett shale, horizontal drilling and multi-stage hydraulic fracturing has spread across North America with new emerging shale gas plays such as the Eagle Ford, Woodford, Haynesville, Marcellus, Utica, Horn River changing the industry’s landscaping. In the current economic environment of high drilling and completion costs, coupled with lower commodity prices, the economic success of shale gas developments has become reservoir specific. Evaluation of well’s initial performance in a particular field and especially the ability to accurately predict the long term production behavior and EUR is critical to the efficient deployment of large capital investments. Field analogies making use of arbitrary "type curves" can have a significant negative impact on the project’s bottom line. With the growing number of multi-stage horizontal wells producing from shale gas reservoirs, many "unconventional" production analysis techniques have been developed based on new concepts such as stimulated reservoir volume (SRV), fracture contact area (FCA), or sophisticated mathematical relationships (power law decline curves, linear flow type curves, to name a few). These sophisticated engineering processes are well documented in the literature and have been presented at numerous industry work shops and conferences. However, for the majority of these techniques there is one common reoccurring theme: performance evaluation of shale gas production cannot be analyzed using conventional methods (e.g. Darcy’s Law). This paper will demonstrate how the conventional approach of reservoir characterization, well performance evaluation and forecasting, can be implemented for all unconventional gas reservoirs, using traditional well testing and production data analysis techniques. We will present one simple analytical model based on the solution of the pseudo steady state equation and will introduce the concept of a shale gas normalized production plot. In our view, the shale gas normalized production plot is one type curve generally applicable to any shale gas reservoir. Finally, pre-frac in-situ testing techniques will be reviewed and special consideration will be given to the perforation inflow diagnostic (PID) testing. We will emphasize the importance of specific reservoir parameters (pore pressure and in-situ shale matrix permeability) and show their impact on drilling and completion strategy and design. Field case examples including well test results and production data from wells completed in several shale gas reservoirs are presented.
Abstract Tight reservoirs stimulated by multistage hydraulic fracturing are commonly characterized by analyzing the hydrocarbon production data. However, analyzing the available hydrocarbon production data mainly determines the fracture-matrix interface. This analysis is not enough for a full characterization of the induced hydraulic fractures. Before putting the well on flowback, the induced fractures are occupied by the compressed fracturing fluid. Therefore, analyzing the produced fracturing fluid should in principle be able to characterize the induced fractures, and complement the production data analysis. We develop a rate transient model for describing the fracturing fluid flowback. We also make various diagnostic plots for understanding the flowback behavior of three fractured horizontal wells. The diagnostic plots indicate three separate flowback regions. In the first region, water production dominates while in the third region hydrocarbon production dominates. In the second region, water production drops and hydrocarbon production ramps up. In general, we observe a linear relationship between rate normalized pressure (RNP) and material balance time (MBT) for the three regions. However, the proposed model can only describe the response of the first region. We successfully determine the hydraulic fracture permeability by history matching the early time flowback data. We conclude that the flowback analysis can complement the production data analysis for a comprehensive fracture characterization. The presented study encourages the industry to start careful measurement of the rate and pressure data immediately after putting the well on hydraulic fracture flowback.
Abstract Conventional completions and testing methods of low permeability gas reservoirs involve the cost and logistics of balanced and underbalanced perforating, next day stimulation treatment, surface production equipment, and the need for flaring during clean-up operations. In Canada, due to government regulations, operators will conduct the buildup test immediately after one or two day of clean-up operation. This practice has resulted in post-frac welltest analysis being masked by fracture fluid still present in the proppant pack and formation, resulting in misleading estimates of reservoir and fracture parameters important for production forecasting and completion evaluation. Perforation Inflow Diagnostic, referred as PID testing, is a modern testing technique designed to deliver in a cost-effective manner valuable reservoir information such as: reservoir pressure, formation flow capacity, unstimulated gas inflow rate potential and near wellbore damage conditions prior to the fracture treatment. The advantages of PID testing are numerous: capability of accurate measurement of very low gas rates in low permeability (tight) gas wells (often reported as too small to measure), provides a safe testing environment, ensures secrecy and it defines itself as a green well testing procedure since it does not require flaring or venting of natural gas. PID testing is simply the surface and/or subsurface monitoring of the pressure response following extreme underbalanced perforating conditions, using electronic pressure recorders capable of high sampling rate. Unlike conventional testing procedures, the surface valve is closed during the entire test period and the formation fluids are produced into the closed chamber (casing and/or tubing volume). The measured pressures are converted to corresponding gas rates, based on the well-established closed chamber theory. PID testing therefore allows the collection of pressure and rate data required to derive the in-situ matrix permeability, wellbore skin and reservoir pressure. Introduction In the Western Canadian Basin (WCB), drilling and completion operations are often complicated and limited due to spring thaw and restricted road access in the summer. As a result, a large number of wells are drilled and completed between the winter months of December to March. During these 4 months of high peak activity, wells are drilled, cased, perforated, stimulated, flow tested for evaluation and tied-in for commercial production. The completed intervals sometimes are suspended for up-hole potential, or abandoned due to disappointing production performance. As a cost reduction measure during the completion operations, the wellbore is filled with frac fluid prior to perforating. Although this practice can save rig time, it will make it practically impossible to differentiate a good quality reservoir response versus a poor reservoir response, immediately after perforation. Moreover, numerous operators are even foregoing the post-frac evaluation process by only conducting a single pressure measurement on the well for regulatory compliance and then placing the well immediately on production. Ideally, post-frac buildup evaluations should be performed 30 – 90 days after production to ensure proper clean-up conditions, however this practice is uneconomical due to the extended buildup durations required to achieve pseudo-radial flow conditions. Therefore, a large number of wells are completed based on historical practices or analogous offset wells. Open-hole or cased-hole logs and petrophysical analysis contribute to the identification and estimates of some reservoir parameters, providing values for net pay (h), effective porosity (Öeff), irreducible water saturation (Sw) and an indicator of permeability (k-index). Besides reservoir permeability, reservoir pressure is a key parameter in determining fluid selection and fracturing treatment size.