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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 Obtaining high-resolution borehole images in oil-based mud (OBM) from logging-while-drilling (LWD) tools has been made possible through the recent development of ultrasonic imaging technologies. High-resolution acoustic impedance images enable reservoir evaluation through the identification of faults and fractures, bedding and laminations, and assessment of rock fabric. This paper presents examples of high-resolution images from a 4¾-in. ultrasonic imaging tool in OBM applications and discusses their value in assessing reservoir quality. This paper provides details of field trials of an LWD ultrasonic imaging tool for use in boreholes ranging from 5¾ to 6¾ in. High-resolution images detailing both borehole caliper and acoustic impedance in both vertical and horizontal wellbores are shown, illustrating the high level of formation evaluation now available when OBM is used. The methodology used to address the impact of tool motion on the impedance images will also be covered. The value of real-time data on borehole stability assessment will be discussed, along with additional applications made possible from the real-time data, such as wellbore placement enhancement. Both real-time and recorded data from field trials show the potential applications for the ultrasonic imaging tool. High-resolution impedance images covering different formations and lithologies show bedding planes and laminations and enable the calculation of stratigraphic dip, while the identification and assessment of fractures show the potential to aid operators during the development of their hydraulic fracturing program. Borehole caliper and shape assessment in real time can be used to modify the drilling parameters and to adjust mud weight, while providing an input into geomechanics assessment. The LWD logs presented illustrate the factors that influence data quality and the methodology used to ensure high-resolution images are available in both vertical and high-angle wellbores using OBM. A direct comparison between data acquired while drilling and while re-logging sections is shown, highlighting the repeatability of the measurement while also illustrating the impact of time-since-drilled on the borehole. A comparison with wireline measurements highlights the potential for using the high-resolution LWD images as an alternative to wireline, where cost and risk of deploying the wireline may be high. The ability to collect high-resolution images in OBM in wellbores ranging from 5¾ to 6¾ in. ensures that increased reservoir characterization is possible, leading to significant improvements in determining the viability of unconventional and other challenging reservoirs. The high-resolution amplitude images are comparable with those available on wireline technologies, and the real-time application of borehole size and shape for input into wellbore stability and geomechanics analysis ensures that common drilling hazards can be avoided.
Tang, Hewei ((currently with Sanchez Oil and Gas)) | Yan, Bicheng ((currently with Sanchez Oil and Gas)) | Chai, Zhi (Texas A&M University) | Zuo, Lihua (Texas A&M University) | Killough, John (Texas A&M University) | Sun, Zhuang (University of Texas at Austin)
Summary Well interference is a common phenomenon in unconventional‐reservoir development. The completion and production of infill wells can lead to either positive or negative well‐interference impacts on the existing producers. Many researchers have investigated the well‐interference phenomenon; however, few of them attempted to apply rigorous simulation methods to analyze both positive and negative well‐interference effects, especially in two different formations. In this work, we develop a comprehensive compositional reservoir model to study the well‐interference phenomena in the Eagle Ford Shale/Austin Chalk production system. The reservoir model considers capillary pressure in the vapor/liquid‐equilibrium (VLE) equation (nanopore‐confinement effect), and applies the embedded discrete‐fracture model (EDFM) for dynamic fracture modeling. We also include a multisegment‐well model to characterize the wellbore‐crossflow effect introduced by fracture hits. The simulation results indicate that negative well‐interference impact is much more common in the production system. With a smaller permeability difference, the hydraulic‐fracturing effect can lead to a positive well‐interference period of several hundred days. The nanopore‐confinement effect in the Eagle Ford Shale can contribute to the negative well‐interference effect. We also analyze the impact of other factors such as initial reservoir pressure, matrix porosity, initial water saturation, and the natural‐fracture system on the well performance. Our work provides valuable insights into dynamic well performance under the impact of well interference.
ABSTRACT Imaging technologies from azimuthal logging-whiledrilling (LWD) tools provide valuable insight into borehole conditions and address multiple drilling and formation evaluation applications, such as wellbore stability assessment and fracture and bedding plane analysis. Although high-resolution images are widely available for water-based mud applications, such as from azimuthally focused resistivity tools, their availability in oil-based mud applications is limited. This paper presents field test results from a 4%-in. ultrasonic imaging tool that provides high-resolution borehole caliper and acoustic impedance images, independent of the mud type used. Analysis of data sets collected in oil-based mud with varying mud weights under multiple drilling conditions are provided, highlighting the suitability of the imaging technology for multiple while-drilling applications. Log data and analysis from the field test wells illustrate the deliverables from both the caliper measurement and the acoustic impedance measurement. Caliper deliverables detailed include: average hole size calculation for input into cement volume calculation, as a borehole quality indicator, and for environmental corrections for other LWD sensors; borehole ellipse and azimuthal sector image plot outputs for real-time geomechanics analysis; and high-resolution borehole images for the identification of faults and fractures. Acoustic impedance deliverables detailed include: real-time images for potential porosity steering applications; and high-resolution memory images for detailed analysis of faults and fractures, and geological and lithological analyses of bedding planes, laminations, and determination of stratigraphic dips. The caliper and acoustic impedance data sets are compared directly with corresponding wireline measurements, including a multifinger caliper and ultrasonic imaging tool. An overview of the tool geometry and associated sensor physics is given, along with details of the laboratory setup and testing performed to evaluate the sensors and the associated measurements and images. Details of the field tests, which illustrate the steps taken to ensure the sensors were evaluated across different lithologies from vertical to horizontal, using different mud weights, logging speeds, and drillstring rotation parameters are described. The logging program was optimized to obtain direct correlation with wireline data sets and maximize image quality. Analyses of the deliverables from the field trials illustrate the value that the ultrasonic caliper and acoustic impedance measurements provide to a variety of LWD applications in boreholes ranging from 5¾ to 6¾ in., adding high-resolution imaging capability to oil-based mud systems. The excellent comparison with wireline measurements demonstrates the potential for the LWD logs to be used as the primary imaging solution in applications where deployment of wireline technologies is either risky or costly, such as in high-angle or horizontal wells, while enabling the same high level of formation evaluation.
Summary The Eagle Ford shale (EFS) is the largest single economic development in the history of the state of Texas and ranks as the largest oil and gas development in the world on the basis of capital invested. Between 2008 and the present, the EFS has become one of the most heavily drilled rock units in the US and is the most-active shale play in the world. This paper presents a completion-optimization framework for unconventional plays. The framework uses well-production performance analysis to estimate the fracture characteristics, and assists in diagnosing potential low-productivity issues. The framework enables precompletion planning, real-time completion operations monitoring, and post-completion evaluation of the design effectiveness, and it optimizes future designs. The key components of the framework are prospectivity analysis, completions optimization, and well-performance analysis. Prospectivity analysis provides the map of reservoir quality and rock quality across the play. Precompletion planning, a component of completions optimization, is driven by prospectivity analysis with the goal to design the best completion on the basis of the rock-quality data available. During completions monitoring, the designs are updated on the basis of the actual field pump rates and quantities of proppant pumped to estimate actual hydraulic- and propped-fracture characteristics. The effective fracture geometry is determined on the basis of well-production calibration. Wellbore and completion problems could be diagnosed in this analysis, including damage of fractures, fluid behavior, and well interference. We applied this framework to wells completed in the EFS. The reservoir-quality variability is based on petrophysical evaluation of logs acquired on all study wells. The characteristics of propped fractures were estimated on the basis of geomechanical modeling of actual field pumping measurements. Even though the fractures extended above and below the target interval of the EFS, they were successful in creating the desired half-length from a design point of view. It was also observed that not all the clusters matured, because of the stress-shadow effect. The produced fluids in these wells ranged from black oil to gas condensate. Well interference was observed as a production penalty factor in well-performance analysis. The behavior of current wells was used to design optimal completions for wells that were planned to be completed. This framework uses common data sets collected by a majority of operators. It provides intelligence for completion optimization of future wells after thorough investigation into fracture design, completion operation, and effective fracture characteristics. It is a systematic approach to optimized single-well design and field development (multiple wells, pad drilling).
Abstract The Eagle Ford Shale (EFS) is the largest single economic development in the history of the state of Texas and ranks as the largest oil & gas development in the world based on capital invested. Between 2008 and the present, the EFS has become one of the most heavily drilled rock units in the United States and is the most active shale play in the world. This paper presents a completion optimization framework for unconventional plays. The framework utilizes well production performance analysis to estimate the fracture characteristics and assists in diagnosing potential low productivity issues. The framework enables pre-completion planning, real time completion operations monitoring and post-completion evaluation to evaluate design effectiveness and optimize future design. The key components of the framework are Prospectivity Analysis, Completions Optimization and Well Performance Analysis. Prospectivity analysis provides the map of Reservoir Quality (RQ) and Rock Quality (RkQ) across the play. Pre-completion planning, a component of Completions Optimization, is driven by Prospectivity Analysis with the goal to design the best completion based on the Rock Quality data available. During completions monitoring, the designs are updated based on actual field pump rates and quantities of proppant pumped to estimate actual hydraulic and propped fracture characteristics. The effective fracture geometry is determined based on well production calibration. Wellbore and completion problems could be diagnosed in this analysis, including damage of fractures, fluid behavior, and well interference. We applied this framework to wells completed in the Eagle Ford Shale. The Reservoir Quality variability is based on petrophysical evaluation of logs acquired on all study wells. The characteristics of propped fractures were estimated based on geomechanical modeling of actual field pumping measurements. Even though the fractures extended above and below the target interval of Eagle Ford Shale, they were successful in creating the desired half-length from a design aspect. It was also observed that not all the clusters matured because of the stress shadow effect. The produced fluids in these wells ranged from black oil to gas condensate. Well interference was observed as a production penalty factor in well performance analysis. The behavior of current wells was used to design optimal completion for wells planned to be completed. This framework utilizes common data sets collected by majority of operators. It provides intelligence for completion optimization of future wells after thorough investigation into fracture design, completion operation, and effective fracture characteristics. It is a systematic approach to optimized single well design as well as field development (multiple wells, pad drilling).
Copyright 2014, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition held in Madrid, Spain, 8-9 April 2014. This paper was selected for presentation by an SPE/IADC 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 or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, 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 or the International Association of Drilling Contractors 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/IADC copyright. Abstract Conventional drilling methods initially utilized to drill an east Texas HPHT well, presented in this case history, ultimately failed after six attempts were made by an independent operator to drill a "straightforward" horizontal wellbore. The subject HPHT well proved extremely challenging with reservoir BHT of 334 F and approximate 13,900 - 14,500 psi reservoir pressure. The well was plagued by several drilling problems including multiple well-control incidents, a casing failure, surgeswab issues, stuck pipe incidents, trip problems, directional control issues, and finally a blowout.
Abstract The Austin Chalk formation has seen several active development booms over the past 35 years due to new technologies. Recently, a program was undertaken to test multistage fracturing technology in the Giddings Austin Chalk field to determine if sufficient additional reserves could be unlocked to spark another development boom. This paper highlights the challenges encountered during the project from the initial reservoir simulation and well candidate selection through system design and installation and treatment design. The Austin Chalk formation has seen considerable horizontal development across Texas as operators chased areas of concentrated natural fractures. Significant quantities of hydrocarbons are apparently trapped in the tight carbonate matrix between the widely spaced fractures along the proven productive edge of the field. Many of the wells in these areas have poorly drained the Austin Chalk due to limited natural fracturing. Multistage fracturing has the potential to reach the insufficiently drained matrix blocks by isolating portions of formation between the natural fractures. A total of 16 openhole multistage hydraulic fracturing completion systems have been run in the Giddings Austin Chalk field across four different counties in an effort to increase EUR’s from existing wells and to extend the economic boundaries of the formation. Simulation work done at the outset of the project pointed towards economic incremental recoveries from multistage hydraulic fracturing. This work also helped validate initial candidate selection. It was found that openhole multistage systems can be run into the Austin Chalk, but it was learned that due to high formation friction factors, careful design work was necessary to ensure that the completion equipment could be run to the desired depth. Results to date have shown that multistage fracturing can increase recovery from existing wells in poorly fractured areas as well as allow for economic development of previously uneconomic fringe areas.