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Brinkley, Kourtney (Devon Energy) | Ingle, Trevor (Devon Energy) | Haffener, Jackson (Devon Energy) | Chapman, Philip (Devon Energy) | Baker, Scott (Devon Energy) | Hart, Eric (Devon Energy) | Haustveit, Kyle (Devon Energy) | Roberts, Jon (Devon Energy)
Abstract This case study details the use of Sealed Wellbore Pressure Monitoring (SWPM) to improve the characterization of fracture geometry and propagation during stimulation of inter-connected stacked pay in the South Texas Eagle Ford Shale. The SWPM workflow utilizes surface pressure gauges to detect hydraulically induced fracture arrivals athorizontal monitor locations adjacent to the stimulated wellbore (Haustveit et al. 2020). A stacked and staggered development in Dewitt County provided the opportunity to jointly evaluateprimary completion and recompletion efforts spanning three reservoir target intervals. Fivemonitor wells at varying distances across the unit were employed for SWPM during the stimulation of four wells. An operational overview, analysis of techniques, correlation with seismic attributes, image log interpretations, and fracture model calibration are provided. Outputs from this workflow allow for a refined analysis ofthe overall completion strategy. The high-density, five well monitor array recorded a total of 160 fracture arrivals at varying vertical and lateral distances, with far-field fracture arrivalsprovidingsignificant insight into propagation rates and geometry. Apronounced trend occurred in both arrival frequency and volumes pumped as monitor locations increased in distance from the treatment well. Specific to target zone isolation, it was identified that traversing vertically in section through a high stress interval yielded a 30% reduction inarrival frequency. An indirect relationship between horizontal distance and arrival frequency was also observed when monitoring from the same interval. A decrease in fracture arrivals from 70% down to 8% was realized as offset distance increased from 120 to 1,700 ft. The results from this study have proven to be instrumental in guiding interdisciplinary discussion. Assessing fracture geometry and propagation during stimulation, particularly in the co-development of a stacked pay reservoir, is paramount to the determination of proper completion volume, perforation design, and well spacing. Leveraging the observations of SWPM ultimately provides greater confidence in field development strategy and economic optimization.
Abstract The purpose of this paper is to present a technique to estimate hydraulic fracture (HF) length, fracture conductivity, and fracture efficiency using simple and rapid but rigorous reservoir simulation matching of historical production, and where available, pressure. The methodology is particularly appropriate for analysis of horizontal wells with multiple fractures in tight unconventional or unconventional resource plays. In our discussion, we also analyze the differences between the results from decline curve analysis (DCA) approach and the Science Based Forecasting (SBF) results that this work proposes. When we characterize fracture properties with SBF, we can do a better job of forecasting than if we randomly combine fracture properties and reservoir permeability together in a decline-curve trend. The forecasts are significantly different with SBF, therefore fracture characterization plays an important role and SBF uses this characterization to produce different (and better) forecasts.
Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.
Abstract Pressure-transient analysis (PTA) is widely used in the industry to estimate fracture half-length, height, and skin due to hydraulic fracturing as well as reservoir parameters. PTA studies focus on pressure data from long shut-in periods and diagnostic fracture injection tests (DFITs), while analyzing the pressure data recorded during the hydraulic fracture treatment has been overlooked. This paper details the state-of-the-art in applying pressure transient analysis to better estimate hydraulic fracture conductivity and dimensions and improve treatment designs stage by stage. The initial portion of this paper describes the application of a novel and low-cost diagnostic method for post-fracture analysis. The bulk of the paper is dedicated to present case histories that illustrate the PTA of the recorded pressure data during treatment to obtain estimates of fracture dimensions and conductivity. The pressure recorded during each stage is processed to ensure the proper data quality and the pressure falloff at the end of the stage is filtered out. The pressure is then analyzed for multi-cluster, finite-conductivity fractures, to obtain the fracture half-length, conductivity, and leakoff. Calculated parameters from each stage are compared to provide insights into the hydraulic fracture design and confirm the adequacy of the treatment design along the well. The results from stage leakoff pressure analysis are very valuable in confirming relative fracture conductivity and providing a qualitative measure of fracture length and height. The total stimulated reservoir area (SRA) calculated using the proposed method yields comparable values to SRA obtained from buildup analysis. The information provided is as valuable and comparable as that from direct near-wellbore diagnostics, such as radioactive traces, temperature logging, real-time micro-seismic monitoring, and production logging. The paper proposes a novel, low-cost analytical PTA method for estimating fracture dimensions, skin, and leakoff coefficient. We illustrate – with several field cases – that conventional post-fracture techniques can be integrated with the stage by stage PTA analysis to provide not only a more consistent and systematic analysis but also a more accurate assessment of treatment effectiveness. The findings of this paper help improve the efficiency of multistage hydraulic fracturing stimulation of horizontal wells.
There are many factors that the engineer must consider when analyzing the behavior of a well after it has been fracture treated. The engineer should analyze the productivity index of the well both before and after the fracture treatment. Other factors of importance are ultimate oil and gas recovery and calculations to determine the propped fracture length, the fracture conductivity, and the drainage area of the well. Post-fracture treatment analyses of the fracture treatment data, the production data, and the pressure data can be very complicated and time consuming. However, without adequate post-fracture evaluation, it will be impossible to continue the fracture treatment optimization process on subsequent wells. Many of the early treatments in the 1950s were designed to increase the productivity index of damaged wells.
The emergence of unconventional resources as a viable source of energy in the US is the combined result of persistent exploration efforts and development of new drilling, completions, and stimulation technologies. However, it is estimated that nearly 90% of tight oil and 65% of shale gas will be left in the reservoir using current methods of production (US Energy Information Administration, 2013). For the US to move "steadily towards meeting all its energy needs from domestic resources by 2035" (Bloomberg, 2013), proper management of its unconventional resources to achieve long-term sustained production and improved recovery is of significant interest to all stakeholders. While exploration, well construction, and stimulation will continue to be critical for unconventional resource recovery economics, sustained productivity and effective depletion are expected to be growing challenges in the way ahead for unconventional reservoirs. Wells in tight unconventional plays enjoy a high initial production (IP) rate accompanied by a high decline rate (Figure 1).
The Bakken is one of the most prolific plays in North America, but, even with the deployment of horizontal wells and hydraulic fracturing, anticipated recovery factors under primary depletion are usually in the range of 10 to 20%. Waterflooding has been a commonly deployed technology in conventional reservoirs to enhance recovery beyond primary depletion. However, the Bakken's ultratight, largely oil-wet nature limits the potential of waterflooding. As an alternative, an optimally spaced well-to-well surfactant-flooding technology is proposed. Recent studies focusing on wettability alteration by use of surfactant in the Bakken have shown strong potential.
The volume of the oil phase formed in the matrix mostly stays below the residual oil saturation. The gas huff'n' puff process has demonstrated potential in improving recovery from tight oil reservoirs. The objective of the study described in this paper was to investigate the feasibility of huff'n' puff enhanced oil recovery (EOR) in a gas-condensate reservoir. Compositional analyses of fluid samples, taken from early production of three wells located a few miles apart from each other in Eagle Ford, were used to build the black-oil, volatile-oil, and gas-condensate fluid models. The produced field gas was selected as the only viable option for injection.
Summary The objective of this study is to develop a new method that leads to diagnostic charts that quantify the pressure response between two interfering wells. Analytical linear flow models for single hydraulic fracture are used to develop a fracture hit model, which is next verified with a numerical model for validity. An analytical two‐fracture model is then developed to simulate flowing bottomhole pressure (BHP) of a shut‐in well, which interferes with the other well through a fracture hit, during well‐testing for a short‐term period. From the insight of two‐fracture analytical model, a dimensionless pressure scalar, which is proportional to square root of time, is proposed to summarize the interference level between two wells. Utilizing such proportionality between the defined dimensionless pressure scalar and square root of time, a diagnostic chart for quick assessment of the production interference level between wells is developed. Such diagnostic chart is also applied to interference caused by multifracture hits that a multistage fractured horizontal well with history match performed from the Eagle Ford formation is considered as a parent well for production interference quantification. A new identical horizontal well, which is just fractured but is not in production, is assumed parallel to the pre‐existing well. The result shows that when the percentage of fracture connection increases, the slope of dimensionless pressure scalar vs. square root of time increases proportionally to the percentage of fracture connection. Because the slope of dimensionless pressure scalar vs. square root of time is between 0 and 1, it can be used to quantify the well production interference level under different situations.
Abstract The first objective of this work is to determine the volume of hydrocarbon that can be moved from Resources other than Reserves (ROTR) to Reserves, or from Proved Undeveloped Reserves (PUD) to Reserves based on well placement. The second objective is to create a model that incorporates the production history and forecasted estimated ultimate recovery (EUR), in this case by implementing multi-segment decline curve analysis (DCA) as presented in URTeC 336 (Moridis et al.(2), 2019). To perform this analysis, we selected 38 wells from a Permian Basin dataset available to Texas A&M University. The first portion of this work involves running a sensitivity analysis to determine the spatial well relationships that may trigger movements in certain regulatory frameworks. A successful well may promote the offsetting 2P wells to PUD wells. We incorporate the methodology in SPEE Monograph 3 (2013) for estimating PUD volumes beyond immediate offset locations that can be used to estimate the Reserves and possibly Contingent Resources in some situations. The question we aim to answer is: How do we move the PUDs to proved developed producing (PDP) Reserves? In the second part of this work, we create a model which includes the production history and the forecasted EURs. As time moves forward, continuity and consistency must be maintained across the model. Assume the following scenario: we plan to move a volume "x" from 1C Contingent Resources to1P Reserves, but we can only book 0.7 x as 1P Reserves. The model must reflect the fraction of the volume x that was actually moved and how it depends on, for example, commodity price contingencies. The remaining 0.3 x volume that was not classified as Reserves must be accounted in the model. The continuity of the model through time will track the volumes, and it needs to be able to do so consistently.