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Abstract The paradigm shift towards horizontal well drilling with multiple fracture stages to exploit unconventional plays has unsurprisingly resulted in a rapid growth of questions regarding the interpretation of the associated well performance signatures on log-log diagnostic and specialized analysis plots. Log-log diagnostic plots perhaps best illustrate the sequence of flow-regimes which may result from this completion type. However, the long-term behavior one should expect to see on a square-root-time plot from the sequence is seldom presented in the literature, in spite of the ubiquitous use of linear flow specialized plots for unconventional well performance analysis. This paper addresses frequently asked questions regarding the meaning of the commonly observed negative y-intercepts on these plots. Using multi-frac horizontal well analytical models, synthetic production data sets were generated to evaluate various hydraulic-fracture geometries. The resulting data signatures are presented on a dimensionless specialized plot to reveal the behavior of the early linear, transitional and (late) compound linear flow regimes. This study illustrates that negative intercepts are typically created from the transitional period following the first linear flow and quantifies both the magnitude and sign of the resulting intercept produced from compound linear flow based on various hydraulic fracture length and spacing combinations. Using a field example, this work also demonstrates that false interpretations of compound linear flow may arise due to the misinterpretation of the prolonged transitional flow period between the first and second linear flow regimes.
Abstract Success of the unconventional multi-fractured horizontal well revolution depends on creation of a Stimulated Reservoir Volume (SRV). Advances in stimulation technology have been geared towards creating increasingly larger SRV's. However, the techniques for evaluating the size and shape of the SRV from production data analysis have not kept pace, and need to be improved. In this paper, we review the diagnostic methods that are currently used, and share learnings obtained from analyzing hundreds of unconventional wells from different unconventional plays. We describe the existing specialized analyses, namely plots utilizing square-root of time (and other time functions), along with type curves that were developed for Compound Linear Flow. We demonstrate that even though these type curves do not account for SRV, they can still be used partially to learn about the SRV characteristics. We have studied the behavior of the EFR (Enhanced Frac Region) model and show how it deviates from the Compound Linear Flow type curves. We demonstrate that what is often considered to be linear flow is only a transition between two flow regimes and results in misinterpretation of the linear flow parameters, and consequently, of SRV properties. We have developed a new EFR type curve that helps characterize the SRV. It should provide a better understanding and interpretation of the currently accepted multi-fractured horizontal well/reservoir system, and improve the diagnostic analysis that precedes and reinforces modeling.
Abstract Quantitative production analysis of tight gas reservoirs has historically been a challenge due to complex reservoir characteristics (ex. lateral and vertical heterogeneity, stress-sensitivity of permeability and porosity), induced hydraulic fracture properties in vertical wells (ex. multi-phase flow, conductivity changes, complex fracture geometries), operational complexities (ex. variable back-pressure, liquid-loading) and data quality (infrequent rate or flowing pressure reporting). All of these challenges conspire to make extraction of reservoir (kh and OGIP) and hydraulic fracture properties (xf and fracture conductivity) soley from production/flowing pressure data difficult, often resulting in non-unique answers. In recent history, there has been the added complication that tight gas (and most recently shale gas) reservoirs are now being exploited with horizontal wells, often stimulated using multiple hydraulic fracture stages, which imparts greater complexity on the analysis. Flow regime identification, which is critical to the correct analysis, is more complicated than ever owing to the number of possible flow regimes encountered in such wells. A case study is presented in which it is demonstrated that modern post-fracture surveillance data, such as microseismic and post-frac production logging, aids in both model identification and model calibration, which is critical to the analysis of hydraulically-fractured horizontal wells completed in tight gas formations. A workflow is presented in which offset vertical wells (to the horizontal wells) are first analyzed to obtain estimates of kh and hydraulic fracture properties, followed by commingled-stage and single-stage production analysis of the multi- (transverse) hydraulic fracture horizontal wells. Microseismic data is incorporated into the analysis of the horizontal wells to 1) understand the orientation and degree of complexity of the induced hydraulic fractures and 2) constrain interpretations of effective hydraulic fracture lengths from production data analysis. It is also demonstrated that once the commingled stage analysis of the horizontal wells is completed, the total interpreted effective hydraulic fracture half-length may be allocated amongst the stages using a combination of production logs and tracer logs. The primary contribution of the current work is the presentation of workflows, emphasizing the integration of various data sources, to improve production analysis of multi-frac’d horizontal wells completed in tight gas formations. In addition to the workflows, it is shown that a combination of advanced production analysis approaches, including methods analogous to classic pressure transient analysis, production type-curve matching and simulation, may be necessary to arrive at a unique analysis.
Abstract Low-permeability (tight) oil reservoirs have emerged as a significant source of oil supply in North America. Hydraulic fracturing techniques combined with horizontal well technology have enabled commercial production from oil and gas reservoirs with absolute permeability < 0.1 md, and recently in gas reservoirs with permeability in the nanodarcy range. Techniques for quantitative analysis of ultra-low permeability reservoirs completed with hydraulically-fractured horizontal wells are in their infancy; complications that have slowed development of these techniques include complex reservoir behavior, such as dual porosity effects, multi-layer behavior, multi-phase flow and non-static absolute permeability, and complex flow behavior associated simultaneous flow of multiple hydraulic fractures into horizontal wells. Although analytical models have been and currently are being developed to simulate well performance associated with these complexities, systematic methods for analyzing production for the purpose of quantifying reservoir and hydraulic fracture properties have not been discussed in detail in the literature for tight oil reservoirs. This paper examines the use of classic rate-transient techniques (flow-regime analysis, type-curve methods and simulation) for analysis of tight oil reservoirs. Single-phase (oil) flow associated with undersaturated black oil reservoirs (above bubble point) is the focus of this work. Simulated cases of multi-fractured horizontal wells completed in single porosity reservoirs, as well as naturally-completed horizontal wells in transient dual porosity reservoirs are analyzed. In all cases, the proposed integrated rate-transient analysis approach provided reasonable estimates of (simulator input) hydraulic fracture and reservoir properties. A field case of a multi-fractured horizontal well completed in a low-permeability area of the Pembina Cardium Field, Western Canada, is also given. Finally, a simplified method for forecasting horizontal wells completed in single and dual porosity media, using inputs derived from flow-regime analysis, is introduced.
Abstract The primary objective of this paper is to demonstrate the practical value of type curve matching, as a complimentary technique to standard diagnostic plots, in the interpretation of production data from complex multi-stage horizontal wells. The approach is based on the usage of Compound Linear Flow Type Curves (Liang et al, 2012). Our methodology involves identifying the transition from early to late (compound) linear flow that would typically be expected in a multi-stage fractured completion. The "shape" of this transition can be a good indicator of the geometry of the system- specifically degree of stimulation efficiency along the lateral, in relation to the effective fracture half-length. This approach has been applied to several producing wells in the Eagle Ford (nanodarcy reservoir) and Bakken (microdarcy reservoir). As a result of using CLF type curves, we are able to estimate stimulation efficiency along the lateral, with reasonable confidence. The stimulation efficiency is defined as the effective stimulated horizontal well length divided by the actual horizontal well length. In addition, we are able to estimate stimulated reservoir width in a reasonably objective and consistent way. These results can be used to seed analytical models for subsequent history matching and forecasting. Diagnostic methods currently used for interpreting performance of multi-stage horizontals are based on identifying specific flow regimes using specialized plots (eg- square root time and flowing material balance). These methods are limited, in that they don't consider the transition periods, which in some cases can dominate the production history. Type curve matching is a good compliment to the standard diagnostic plots, providing an independent and objective method of characterizing the reservoir. Historically, type curve matching has been proven as a valid technique for interpreting production data (Fetkovich, Blasingame, Agarwal et al). However, with the advent of complex multi-stage completions in tight fractured reservoirs, the existing conventional models are no longer useful. The recently introduced CLF type curves are more appropriate for unconventionals. This work represents the first detailed case study where type curve matching is applied to an unconventional oil and gas play.