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Osareni C. Ogiesoba - One of the best experts on this subject based on the ideXlab platform.
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Examples of seismic diffraction imaging from the Austin Chalk and Eagle Ford Shale, Maverick Basin, South Texas
Journal of Petroleum Science and Engineering, 2017Co-Authors: Osareni C. Ogiesoba, Alexander KlokovAbstract:Abstract Diffraction events are recorded along with reflection data during seismic acquisition. However, after processing, final migrated stack data are devoid of diffraction events, which have been collapsed to discrete points, smoothed out, and overshadowed by reflection events. Thus, diffraction events that ought to be available for analysis of the subsurface are lost. In this study, we extract diffractions from 3D stack and then build a 3D diffraction volume that not only images faults but also contains amplitude information used to examine lithological composition in fault zones within the Austin Chalk and Eagle Ford Shale in South Texas. We then transform the diffraction data into amplitude envelope volume. This seismic attribute, together with clay volume (V clay ) data, is extracted along interpreted horizons and fault planes. Cross plots between seismic attributes and V clay show that V clay increases with increasing diffraction energy. In addition, we observe that the higher the diffraction energies, the higher the fluid saturation, suggesting higher impedance contrast at diffraction points. Furthermore, cross plots between instantaneous dominant frequencies extracted from the diffraction-image volume and amplitude envelope show that within the hydrocarbon-saturated zones, the dominant frequency is approximately constant and in the low-frequency range between 25 and 33 Hz. However, outside the hydrocarbon zones, the dominant frequency increases as the amplitude envelope decreases. Maps of instantaneous dominant frequency extracted from the upper and lower Eagle Ford Shale reveal that areal distribution of low-dominant-frequency zones is coincident with high diffraction energy and hydrocarbon saturation. Based on the foregoing, we conclude that by analyzing diffraction data, it is possible to infer likely sediment variation and hydrocarbon sweet spots within the Eagle Ford Shale and other Shale resource plays.
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Seismic-attribute identification of brittle and TOC-rich zones within the Eagle Ford Shale, Dimmit County, South Texas
Journal of Petroleum Exploration and Production Technology, 2014Co-Authors: Osareni C. Ogiesoba, Ursula HammesAbstract:Analysis of 3D poststack seismic attributes can be used to identify areas of high exploration potential within Shale resource plays. We integrated seismic attributes and acoustic impedance (AI) with wireline logs to determine total organic carbon (TOC) distribution within the Eagle Ford Shale in South Texas. We computed TOC from wireline logs using the Δ Log R method and then used seismic attributes to predict TOC and deep-resistivity log distribution, and identify brittle zones within the seismic survey. Our results show that high-TOC and high-resistivity zones are laterally more continuous in the south part of the survey. In the north, continuity of these properties is broken by NE–SW-trending faults having throws ranging from about 10 to 100 ft (3–30 m). High resistivity occurs in high-quality-factor ( Q ) attribute zones. Although the relationship is nonlinear, resistivity and TOC increase as Q increases. That is, both properties increase with increasing bed resistance suggesting increasing carbonate. Two high-resistivity zones, an upper resistive bed and a lower resistive bed, are identified within the Eagle Ford Shale. Additionally, because a strong positive linear relationship exists between AI and Q , Q can be used to identify brittle zones. Compared to other attributes used in identification of brittle zones, Q is faster and cheaper to compute from 3D poststack seismic data. Therefore, Q could serve as a quicker, alternate method of identifying brittle zones within the Eagle Ford Shale.
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Seismic multiattribute analysis for Shale gas/oil within the Austin Chalk and Eagle Ford Shale in a submarine volcanic terrain, Maverick Basin, South Texas
Interpretation, 2013Co-Authors: Osareni C. Ogiesoba, Raymond L. EastwoodAbstract:We conducted seismic multiattribute analysis by combining seismic data with wireline logs to determine hydrocarbon sweet spots and predict resistivity distribution (using the deep induction log) within the Austin Chalk and Eagle Ford Shale in South Texas. Our investigations found that hydrocarbon sweet spots are characterized by high resistivity, high total organic carbon (TOC), high acoustic impedance (i.e., high brittleness), and low bulk volume water (BVW), suggesting that a combination of these log properties is required to identify sweet spots. Although the lower Austin Chalk and upper and lower Eagle Ford Shale intervals constitute hydrocarbon-sweet-spot zones, resistivity values and TOC concentrations are not evenly distributed; thus, the rock intervals are not productive everywhere. Most productive zones within the lower Austin Chalk are associated with Eagle Ford Shale vertical-subvertical en echelon faults, suggesting hydrocarbon migration from the Eagle Ford Shale. Although the quality factor (Q) was not one of the primary attributes for predicting resistivity, it nevertheless can serve as a good reconnaissance tool for predicting resistivity, brittleness, and BVW-saturated zones. In addition, local hydrocarbon accumulations within the Austin Chalk may be related to Austin TOC-rich zones or to migration from the Eagle Ford Shale through fractures. Some wells have high water production because the water-bearing middle Austin Chalk on the downthrown side of Eagle Ford Shale regional faults constitutes a large section of the horizontal well, as evidenced by the Q attribute. Furthermore, the lower Austin Chalk and upper Eagle Ford Shale together appear to constitute a continuous (unconventional) hydrocarbon play.
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seismic multiattribute analysis for Shale gas oil within the austin chalk and Eagle Ford Shale in a submarine volcanic terrain maverick basin south texas
Interpretation, 2013Co-Authors: Osareni C. Ogiesoba, Raymond L. EastwoodAbstract:AbstractWe conducted seismic multiattribute analysis by combining seismic data with wireline logs to determine hydrocarbon sweet spots and predict resistivity distribution (using the deep induction log) within the Austin Chalk and Eagle Ford Shale in South Texas. Our investigations found that hydrocarbon sweet spots are characterized by high resistivity, high total organic carbon (TOC), high acoustic impedance (i.e., high brittleness), and low bulk volume water (BVW), suggesting that a combination of these log properties is required to identify sweet spots. Although the lower Austin Chalk and upper and lower Eagle Ford Shale intervals constitute hydrocarbon-sweet-spot zones, resistivity values and TOC concentrations are not evenly distributed; thus, the rock intervals are not productive everywhere. Most productive zones within the lower Austin Chalk are associated with Eagle Ford Shale vertical-subvertical en echelon faults, suggesting hydrocarbon migration from the Eagle Ford Shale. Although the quality ...
Raymond L. Eastwood - One of the best experts on this subject based on the ideXlab platform.
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Seismic multiattribute analysis for Shale gas/oil within the Austin Chalk and Eagle Ford Shale in a submarine volcanic terrain, Maverick Basin, South Texas
Interpretation, 2013Co-Authors: Osareni C. Ogiesoba, Raymond L. EastwoodAbstract:We conducted seismic multiattribute analysis by combining seismic data with wireline logs to determine hydrocarbon sweet spots and predict resistivity distribution (using the deep induction log) within the Austin Chalk and Eagle Ford Shale in South Texas. Our investigations found that hydrocarbon sweet spots are characterized by high resistivity, high total organic carbon (TOC), high acoustic impedance (i.e., high brittleness), and low bulk volume water (BVW), suggesting that a combination of these log properties is required to identify sweet spots. Although the lower Austin Chalk and upper and lower Eagle Ford Shale intervals constitute hydrocarbon-sweet-spot zones, resistivity values and TOC concentrations are not evenly distributed; thus, the rock intervals are not productive everywhere. Most productive zones within the lower Austin Chalk are associated with Eagle Ford Shale vertical-subvertical en echelon faults, suggesting hydrocarbon migration from the Eagle Ford Shale. Although the quality factor (Q) was not one of the primary attributes for predicting resistivity, it nevertheless can serve as a good reconnaissance tool for predicting resistivity, brittleness, and BVW-saturated zones. In addition, local hydrocarbon accumulations within the Austin Chalk may be related to Austin TOC-rich zones or to migration from the Eagle Ford Shale through fractures. Some wells have high water production because the water-bearing middle Austin Chalk on the downthrown side of Eagle Ford Shale regional faults constitutes a large section of the horizontal well, as evidenced by the Q attribute. Furthermore, the lower Austin Chalk and upper Eagle Ford Shale together appear to constitute a continuous (unconventional) hydrocarbon play.
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seismic multiattribute analysis for Shale gas oil within the austin chalk and Eagle Ford Shale in a submarine volcanic terrain maverick basin south texas
Interpretation, 2013Co-Authors: Osareni C. Ogiesoba, Raymond L. EastwoodAbstract:AbstractWe conducted seismic multiattribute analysis by combining seismic data with wireline logs to determine hydrocarbon sweet spots and predict resistivity distribution (using the deep induction log) within the Austin Chalk and Eagle Ford Shale in South Texas. Our investigations found that hydrocarbon sweet spots are characterized by high resistivity, high total organic carbon (TOC), high acoustic impedance (i.e., high brittleness), and low bulk volume water (BVW), suggesting that a combination of these log properties is required to identify sweet spots. Although the lower Austin Chalk and upper and lower Eagle Ford Shale intervals constitute hydrocarbon-sweet-spot zones, resistivity values and TOC concentrations are not evenly distributed; thus, the rock intervals are not productive everywhere. Most productive zones within the lower Austin Chalk are associated with Eagle Ford Shale vertical-subvertical en echelon faults, suggesting hydrocarbon migration from the Eagle Ford Shale. Although the quality ...
Chris Carpenter - One of the best experts on this subject based on the ideXlab platform.
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A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale
Journal of Petroleum Technology, 2014Co-Authors: Chris CarpenterAbstract:This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169010, ’A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale,’ by C. Kraemer, SPE, B. Lecerf, J. Torres, SPE, H. Gomez, and D. Usoltsev, SPE, Schlumberger, and J. Rutledge, SPE, D. Donovan, SPE, and C. Philips, SPE, Marathon Oil, prepared for the 2014 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed. Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs, as is often the case in the Eagle Ford Shale. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even farther to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced-fracturing technique has been developed on the basis of a novel composite fluid comprising degradable fibers and multisized particles. Introduction In Eagle Ford Shale completions, which typically rely on limited-entry principles, the distribution of fluid flow is a function of fracture initiation and propagation pressure, differential pressure on perforations, and net pressure of the stimulation treatment. New injection-evaluation and logging techniques demonstrated the possibility of significant variations in fracture-gradient anisotropy and formation fluid-flow distribution over the intervals of horizontal wells. Recently, several operators in the Eagle Ford play revised their completion strategy and decided to increase differential pressure on perforations by reducing the number of perforation clusters per stimulation stage. This approach requires a larger number of wireline interventions to place the additional necessary bridge plugs and is accompanied by longer subsequent coiled-tubing milling operations. A solution was needed to increase the number of perforations being stimulated without increasing the complexity of operations, the associated time, and the costs. Increasing Contact, Not Operational Complexity Chemical diversion has been proposed as a cost-effective and faster alternative to mechanical techniques for isolating perforations and forcing fluids into previously unstimulated portions of the reservoir. Numerous materials (e.g., benzoic acid flakes, rock salt, fracturing balls, and rubber-coated neoprene balls) are commercially available for this purpose, but none was found to provide reliable diversion. The sequenced fracturing technique described here introduces a composite fluid that temporarily plugs zones that were previously stimulated and diverts fluids to understimulated regions. The composite fluid overcomes the limitations of traditional chemical diverters by coupling degradable particles of a wide size distribution.
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Unconventional-Asset-Development Work Flow in the Eagle Ford Shale
Journal of Petroleum Technology, 2014Co-Authors: Chris CarpenterAbstract:This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168973, ’Unconventional-Asset-Development Work Flow in the Eagle Ford Shale,’ by David Cook, Kirsty Downing, Sebastian Bayer, Hunter Watkins, Vanon Sun Chee Fore, Marcus Stansberry, Saurabh Saksena, and Doug Peck, BHP Billiton Petroleum, prepared for the 2014 SPE Unconventional Resources Conference - USA, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed. Development of the Eagle Ford Shale typically consists of horizontal wells stimulated with multiple hydraulic-fracture stages. This paper presents a pragmatic integrated work flow used to optimize development and guide critical development decisions in the Black Hawk field. Geoscientists and reservoir and completion engineers worked collaboratively to identify optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells. Introduction In 2008, the operator drilled several successful wells in the Hawkville field of what would become the Eagle Ford Shale play. Early results led to substantial land acquisition. The Eagle Ford, while continuous over wide sections, varies substantially in terms of fluid and rock properties. Fig. 1 shows a cross section for an arbitrary line through Black Hawk and Hawkville to the Maverick basin, showing the relative changes in thickness and Young’s modulus. An understanding of the characterization of Shale systems for simulation has evolved rapidly. Flow contributions from natural fractures, induced fractures, and matrix rock along with the nature of the hydrocarbon deposit itself should be considered. Perhaps even more important is regional variation. In the world of conventional assets, property estimation needs to be reliable only for a small geographical area, often within one sandstone structure of a few square miles at most. This can be compared with the scale of the play in Fig. 1. For conventional reservoirs, standardized laboratory methods and years of research and trial and error have educated our approaches to well-defined best practices. In Shale plays, these have not yet been fully worked through and adopted by consensus, often leaving the owner of the asset as the arbiter of methodology.
Thomas Alwin Blasingame - One of the best experts on this subject based on the ideXlab platform.
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A Production Characterization of the Eagle Ford Shale, Texas - A Bayesian Analysis Approach
Day 1 Wed May 17 2017, 2017Co-Authors: Nefeli Moridis, Yasser Soltanpour, Zenon Medina-cetina, W. John Lee, Thomas Alwin BlasingameAbstract:Abstract We began this research by asking "Can we use Bayes' theorem to supplement available decline models and improve the accuracy of our estimates of ultimate recovery?" This study focuses on the Eagle Ford Shale, and in particular, on oil wells in the Greater Core Eagle Ford Area. Our goal was to develop a method based on a probabilistic approach to identify, characterize, and better model well production based on standard decline models To attempt to answer this question, we first obtained data for 68 wells in the Greater Core of the Eagle Ford Shale, Texas. As process, we eliminated the wells that did not have enough production data, wells that did not show a production decline and wells that had too much data noise, leaving eight wells. We then performed decline curve analysis (DCA) using the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) models (the two most common DCA models), consisting in user-guided analysis software. Then, the Bayesian paradigm was implemented to calibrate the same two models on the same set of wells. The primary focus of the research was the implementation of the Bayesian paradigm on the eight-well data set. We first performed a "best fit" parameter estimation using least squares optimization, which provided an optimized set of parameters for the two decline models. This was followed by using the Markov Chain Monte Carlo (MCMC) integration of the Bayesian posterior function for each model, which provided a full probabilistic description of its parameters. This allowed for the simulation of a number of likely realizations of the decline curves, from which first order statistics were computed to provide a confidence metric on the calibration of each model as applied to the production data of each well. Results showed variation on the calibration of the MH and PLE models. The forward models (MH and PLE) overestimated the ultimate recovery in the majority of the wells compared with the Bayesian calibrations, proving that the Bayesian paradigm was able to capture a more accurate trend of the data and thus able to determine more accurate estimates of reserves. In industry, the same decline models are used for unconventional wells as for conventional wells, even though we know that the same models may not apply. Based on the proposed results, we believe that Bayesian inference yields more accurate estimates of ultimate recovery for unconventional reservoirs than deterministic DCA methods. Moreover, it provides a measure of confidence on the prediction of production as a function of varying data and varying decline models.
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A Well Performance Study of Eagle Ford Shale Gas Wells Integrating Empirical Time-Rate and Analytical Time-Rate-Pressure Analysis
Day 3 Thu February 11 2016, 2016Co-Authors: A. S. Davis, Thomas Alwin BlasingameAbstract:Abstract In this work, our purpose is to create a "performance-based reservoir characterization" using production data (measured rates and pressures) from a selected gas condensate region within the Eagle Ford Shale (S. Texas). We use modern time-rate ("decline curve") analysis and time-rate-pressure ("model-based") analysis methods to analyze/interpret/diagnose gas condensate well production data. We estimate reservoir and completion properties — specifically: formation permeability, fracture-face skin effect, fracture half-length, and fracture conductivity. We correlate these results with known completion variables — specifically: completed lateral length, total proppant, total water used, and type of hydraulic fracturing fluid. We use the time-rate and time-rate-pressure analyses to forecast future production and to estimate ultimate recovery. Finally, we apply pressure transient analysis methods to those cases where the production history contains shut-in periods of sufficient duration to provide resolution in the pressure build-up data to identify reservoir features and qualitatively validate completion effectiveness. It is noted that ONLY surface pressures are available for the wells considered in this study. We utilize industry-standard software to perform single well rate-time "decline curve" analyses. The traditional "modified-hyperbolic" time-rate model was used as the "basis" relation and the "power-law exponential" time-rate model was used as a check/validation (the power-law exponential model tends to be a more conservative relation for generating forecasts and estimating ultimate recovery). We also utilize industry-standard software to perform single well time-rate-pressure "model-based" analyses --- this methodology is also known as Rate Transient Analysis (RTA). In this work we used the full analytical model for the performance of a Multi-Fracture Horizontal Well (as opposed to a proxy or numerical model). We use Microsoft Excel and a commercial statistical software package to correlate the production analysis results with the measured completion parameters to create "design" relations for well completions — specifically correlations of estimated ultimate recovery with completion variables (completed lateral length, total proppant, total water used, and type of hydraulic fracturing fluid). Finally, we utilize industry-standard software to perform pressure transient analysis on the cases where the quality and relevance of the shut-in pressure data warranted such analyses. In this work, we "cross-validate" the estimated ultimate recovery results by comparison of the time-rate and time-rate-pressure analysis results The correlation of EUR with completion variables, we propose, is shown to be statistically relevant for almost all combinations of variables, and the correlation relation should be applicable for creating completion designs. The analysis of surface-derived pressure transient data is successfully demonstrated for several cases taken from the gas condensate region of the Eagle Ford Shale (S. Texas). The work we perform in this thesis clearly demonstrates the validity of using empirical (time-rate) and analytical (time-rate-pressure) analysis methods for the purpose of characterizing well performance for wells in the gas condensate region of the Eagle Ford Shale (S. Texas).
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Production Analysis in the Eagle Ford Shale -- Best Practices for Diagnostic Interpretations, Analysis, and Modeling
All Days, 2012Co-Authors: Dilhan Ilk, Neal J. Broussard, Thomas Alwin BlasingameAbstract:Abstract The Eagle Ford Shale (South Texas, USA) is emerging as the foremost "liquids-rich" Shale play in North America. As such, the use of production data analysis in the Eagle Ford Shale has tremendous importance in: Determining well/reservoir properties; Establishing completion effectiveness; and Estimating future production. The Eagle Ford Shale presents additional difficulty in the form of fluid behavior characterization. Near-critical PVT behavior (as in the case of the Eagle Ford Shale) is an important component of well performance, which cannot be overlooked during analysis and modeling. The results of this work address the common challenges encountered during production analysis and modeling of the Eagle Ford Shale wells. In particular, it is shown that significant differences are observed in production forecast due to characterization of the fluid. This work provides a systematic workflow to analyze and forecast production data in near-critical reservoirs with examples from the Eagle Ford Shale and delivers more insight into analysis of production data in unconventional "liquids-rich" reservoirs, and offers to decrease the uncertainty related with production forecast that is mainly caused by lack of understanding of "near-critical" fluid behavior.
Walter B Ayers - One of the best experts on this subject based on the ideXlab platform.
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Quantitative Evaluation of Key Geological Controls on Regional Eagle Ford Shale Production Using Spatial Statistics
Day 2 Thu February 16 2017, 2017Co-Authors: Yao Tian, Walter B Ayers, William D. Mccain, Huiyan Sang, Christine Ehlig-economidesAbstract:Abstract Recent progress has increased our understanding of key controls on the productivity of Shale reservoirs. The quantitative relations between regional Eagle Ford Shale production trends and geologic parameters were investigated to clarify which geologic parameters exercise dominant control on well production rates. Previously, qualitative correlations for the Eagle Ford Shale were demonstrated among depth, thickness, total organic carbon (TOC), distribution of limestone beds, and average bed thickness with regional production. Eagle Ford production wells are horizontal, but it was necessary to use vertical wells that penetrated the Eagle Ford to map reservoir properties. No wells in the data base had both production and geological parameters, thus geological parameters could not be directly related to individual well production. Therefore, spatial interpolation methods based on kriging and Markov Chain Monte Carlo (MCMC) sampling algorithms were utilized to integrate data sets and predict geological properties at production well locations. The spatial Gaussian Process regression modeling was conducted to investigate the primary controls on production. Results suggest that the 6-month cumulative production from the Eagle Ford Shale, in barrels-of-oil equivalent (BOE), increases consistently with (a) depth, (b) Eagle Ford thickness (up to 180-ft thickness), and (c) with TOC (up to 7%). Also, when the number of limestone beds exceeds 12, production increases with the number of limestone beds. The corresponding significance code indicates that the parameters most significant to production are TOC and depth (which relates to pressure). Concepts and models developed in this study may assist operators in making critical Eagle Ford Shale development decisions and should be transferable to other Shale plays
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Eagle Ford Shale play economics u s versus mexico
Journal of Natural Gas Science and Engineering, 2017Co-Authors: Ruud Weijermars, Nadav Sorek, Deepthi Sen, Walter B AyersAbstract:Abstract The decline of domestic natural gas supply and rising demand requires Mexico to import 1/3 of its annual gas consumption of 2.5 trillion cubic feet (Tcf). Yet, Mexico's estimated resource of technically recoverable Shale gas (545 Tcf) is the 6th largest such gas resource in the World. Much of Mexico's Shale gas resource is in the Eagle Ford Shale, which is a mature Shale gas and oil play in the U.S. To aid in determination of whether development of the Eagle Ford Shale in Mexico could reduce the country's dependency on natural gas imports, we evaluated the potential of Mexican Shale acreage by comparing the after-tax net present value (NPV) and internal rate of return (IRR) of Eagle Ford Shale wells on either side of the U.S.-Mexico border. The initial development of Mexican acreage occurs with a much larger well-spacing (leading to higher acreage acquisition cost per well), which would require 25% higher development cost as compared to Texas acreage. Consequentially, Texas wells have better net present value (NPV) and higher internal rate of return (IRR) than Mexican wells, in general. The principal explanation is that the signing bonus will be much higher in Mexico than in Texas, partly effectuated by the lower well spacing for unrisked acreage. Results of our study provide potential operators and investors with a preliminary indication of Eagle Ford Shale well economics in Mexico. Our study includes sensitivity analyses for both non-escalated and escalated gas prices, for drilling and completion (D&C) costs, and for leasehold cost. The economic appraisal accounts for both single- and multiple-well development scenarios with P10, P50 and P90 production forecasts.
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Quantitative Evaluation of Key Controls on Eagle Ford Shale Gas Condensate Production Using History Match and Sensitivity Analysis
Day 1 Wed September 21 2016, 2016Co-Authors: Yao Tian, Walter B Ayers, William D. Mccain, Christine Ehlig-economidesAbstract:Abstract In 2014, U.S. crude oil reserves exceeded 39 billion barrels, the fourth-highest on record, and proved reserves of natural gas increased to 388.8 trillion cubic feet, surpassing the record from 2013 (EIA 2015). The Eagle Ford Shale is a primary contributor to the added U.S. proved oil and gas reserves (EIA 2015). Successful exploration and development of the Eagle Ford Shale play requires reservoir characterization, recognition of fluid regions, and the application of optimal operational practices in all regions. Various approaches have been used to determine which geologic parameters have the greatest influence on Eagle Ford Shale well productivity. Previously, regional statistical studies of production and geologic parameters were employed to analyze the relative importance of depth, thickness, and total organic carbon content on cumulative production. Regression coefficients and P values were examined. Although those studies provided insights to regional controls on Eagle Ford production trends, understanding which geologic parameters have the greatest impact on production performance of individual wells required more detailed simulation models. Based on the frameworks provided by stratigraphic and petrophysical analyses, a single well compositional model for a representative Eagle Ford gas condensate well was built, and history matching based on production and pressure data was performed. PVT reports were available to simulate phase behavior. Multiple good history matches were obtained by varying a set of uncertain input parameters, such as water saturation, and relative permeability. Porosity and permeability were modeled as functions of pressure to consider reservoir compaction effects. The distribution of parameters from various history match results was plotted, allowing their impacts on the production behavior of the well to be quantitatively correlated and analyzed. This approach was preferred to traditional sensitivity study approaches, where a single parameter is changed each time, and the ranges of the parameters are not guided by historical data. In addition, interactions among the parameters cannot be considered without history matching. Well deliverability was also modeled to optimize the oil production rate by designing appropriate operational parameters. Hydraulic fracture geometry and reservoir drainage area are the dominant controls on production. Reservoir modeling suggests low bottomhole flowing pressure was the key to optimizing cumulative gas condensate production. Minor changes in porosity significantly impact production Eagle Ford Shale condensate production, whereas production is less sensitive to variations of water saturation and matrix permeability. Concepts and models developed in this study may assist operators in making critical Eagle Ford Shale development decisions, including optimizing individual well performance.
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Regional Impacts of Lithologic Cyclicity and Reservoir and Fluid Properties on Eagle Ford Shale Well Performance
Day 2 Wed April 02 2014, 2014Co-Authors: Yao Tian, Walter B Ayers, William D. MccainAbstract:Abstract Since 2008, the Eagle Ford Shale has been one of the most active U.S. oil and gas plays. Regional variations of the frequency (cyclicity) and thickness of organic-rich marl and limestone interbeds influence well completion design, and these variations may be related to well production performance. To better understand the impacts of lithologic cyclicity and reservoir and fluid properties on well performance, we conducted an integrated, regional study using well logs, production data, and PVT reports. Regionally, the Eagle Ford Shale is composed of 3 units. The Lower Eagle Ford consists of cyclic, interbedded organic-rich marl and limestone. To analyze lithologic cyclicity of the Lower Eagle Ford Shale in South Texas, We evaluated gamma ray logs from more than 500 vertical wells. A Matlab script was developed to count the numbers of organic-rich marl and limestone interbeds. Average bed thickness was calculated at each well and was mapped regionally. The numbers of both limestone and organic-rich marl interbeds increase from less than 2 in the northwest to more than 20 on the southeast. Lithologic cyclicity is greatest in La Salle and Karnes Counties, which are the most productive gas and oil regions, respectively. Eagle Ford Shale reservoir and fluid properties from PVT reports were mapped to further evaluate regional variations of fluid types and well performance. Reservoir pressure, pressure gradient, oil gravity, and gas specific gravity were mapped. Reservoir pressure and pressure gradient are greatest on the northeast. Oil gravity and gas specific gravity maps suggest increasing thermal maturity from northwest to southeast, with increasing depth. Well production rates are strongly influenced by lithologic cyclicity, pressure, and fluid properties. Understanding these relations in the lower Eagle Ford Shale should assist with optimizing completion design and stimulation strategies. The results of this study provide a better understanding of Eagle Ford Shale reservoir characteristic and well performance, and the study approach may be used to assess productivity of other Shale plays.
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The Eagle Ford Shale Play, South Texas: Regional Variations in Fluid Types, Hydrocarbon Production and Reservoir Properties
All Days, 2013Co-Authors: Yao Tian, Walter B Ayers, William D. MccainAbstract:The Eagle Ford Shale is one of the most active U.S. Shale plays; it produces oil, gas condensate, and dry gas. To better understand the regional and vertical variations of reservoir properties and their effects on fluid types and well performance, we conducted an integrated, regional study using production and well log data. Maps of the average gas-oil ratio (GOR) of the first three production months identified four fluid regions, including black oil, volatile oil, gas condensate, and dry gas regions. Maximum oil production occurs in Karnes County, where first-month oil production of most wells exceeds 5,000 barrels (bbl). The most productive gas region is between the Stuart City and Sligo Shelf Margins, where first-month gas production of most wells exceeds 60 million cubic feet (MMcf). Eagle Ford Shale petrophysical properties were analyzed in individual wells and were mapped to clarify the regionally variations of Eagle Ford Shale reservoir properties and their controls on fluid types and well performance. In comparison to the upper Eagle Ford, the lower Eagle Ford Shale has high gamma ray, high resistivity, low density, and long transit time values; we infer that the lower Eagle Ford Shale has higher total organic carbon and lower carbonate content than the upper Eagle Ford Shale. Integration of production and geological data shows that thermal maturity and structural setting of the Eagle Ford Shale strongly influence fluid types and production rates. Plots of GOR vs. time for individual wells were constant in different reservoir fluids. Results of this study clarify causes of vertical and lateral heterogeneity in the Eagle Ford Shale and the regional extents of fluid types. Understanding of the reservoir property differences between upper and lower Eagle Ford Shale should assist with optimizing completion design and stimulation strategies. The results may be applicable to similar developing Shale plays.
