bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Semianalytical Approach to Estimating EUR in Unconventional Reservoirs
Authors: Kabir C. S. , Lake Larry W. 
Published: September 2011

Abstract
Marginal economics underscores the importance for accurate estimation of production profile and expected ultimate recovery or EUR in unconventional resources. While the Arps family of type-curves and the stretched-exponential model appears to yield reasonable estimation of EURs, all insufficiently explain the intrinsic behavior of unconventional reservoirs. This study introduces and applies a new semianalytical approach for estimating production profile and EUR, validated by numerical simulations and verified by field data for unconventional gas and oil reservoirs.
We obtained analytical solutions by considering concentric compressibility elements, analogous to electrical capacitors, in series using the continuity equation to obtain production from conceptual geobodies. This configuration mimics decreasing contributions from a series of concentric reservoir segments into the well with increasing distance from the stimulated-reservoir volume or SRV. The analytical formulation captures production behavior of early-time and SRV-dominated flow patterns, leading to good estimation of expected-ultimare recovery or EUR.
Integrating All Available Data to Improve Production in the Marcellus Shale
Authors: Ejofodomi Efe , Baihly Jason , Malpani Raj , Altman Raphael , Huchton Terry , Welch David , Zieche Jerry 
Published: September 2011

Abstract
Shale gas exploitation has dominated the E&P landscape in North America for nearly a decade. There is a great deal of competition for shale acreage in the US, and leasing occurs rapidly once a new shale play is discovered. It can cover tens of thousands of acres and are often selected based on limited data, mainly vintage paper logs, mud logs, and access, cost, and availability considerations. Rarely are core, seismic or modern log data available to the operator. Capturing data in exploratory vertical wells is crucial, but comprehensive integration of the data to optimize horizontal well design is often overlooked.
This paper discusses one operator's approach to fully integrate data captured in the Marcellus Shale in order to optimize horizontal well performance. Based upon insight from the study, the operator wanted to make more informed asset management decisions, improve economics, and look for future investment opportunities. Data were captured from vertical offset exploratory wells and an initial horizontal pilot well. The data that were acquired and incorporated into the study included field-wide seismic and data, as well as mineralogical, geomechanical, well plan, drilling, completion, microseismic, and production data from the aforementioned wells.
A comprehensive study was performed incorporating the data to optimize the design of a horizontal well in the Marcellus Shale. This study was performed to get the operator up the learning curve in a short time period rather than by trial and error on wells. The first step in the study involved constructing a field-wide 3D static geologic model using the data captured above to determine the best petrophysical and structural areas to drill new wells. A reservoir model was then constructed with existing production, fracture, and microseismic data as well as the geologic model. The reservoir model was then used to forecast various production scenarios, including lateral length, number of stages, and perforation cluster spacing. Various fracture models were also included in the analysis to determine height growth and complexity.
The results of these geologic, reservoir, and fracturing models were used to optimize the design of a second horizontal well drilled in the area of interest. The production increase between the first and second horizontal well was analyzed on a percentage basis. Lastly, recommendations were made for further well design enhancements based upon the study findings and the results of the second horizontal well.
Automated Pressure Transient Analysis - Using Smart Technology
Authors: Rees Hugh , Foot John , Heddle Richard 
Published: September 2011

Abstract
This paper describes the current use of continuous live data feeds to estimate reservoir pressure automatically from build-up analysis - in real time - and to evaluate well performance from well testing automatically – also in real time.
Since 2002 much work has been done to create the Field of the Future™ Integrated Surveillance Information System (ISIS) -a universally deployable, global software application that can process continuous data feeds from remote sites, perform calculations on the data in real-time (such as virtual flow-metering of wells) and visualise the results for the user on a web browser. With these underlying calculations already complete and extending to phase rates down-hole and at surface, the current well flowing status (which wells flow through which facility components, production reconciliation, and more) there was already a mature and solid foundation on which to build a pressure analysis engine and a flow-test module.
This original pressure transient analysis (PTA) concept was to provide permeability, skin and reservoir pressure estimates using traditional build-up/fall-off techniques but with no engineer intervention required other than to approve the results. The outcome was a technology has been deployed globally and has now been in service since 2009. Using this system data is collected every time there is a shut-in event on every well for which the tool is enabled. Smart scheduling is adopted during a complete field shut-in so that all wells can be interpreted together.
The technology was built in parallel with a tool for recording production flow tests using flow-meter or separator data. Using smart systems to estimate the quality of flow tests, and combining the results with sampling and other data, a powerful system now exists to provide consistent, and fully auditable, results that can be used by reservoir modelling tools and other systems. It was deployed in 2007.
Examples are given describing use of the technology and where business has been impacted by it.
Field of the Future is a registered trademark of BP.
The following text is a manuscript for an e-poster and should be considered in conjunction with the electronic presentation that accompany it. Graphic material resides within the presentation.
Automation of the Oilfield Asset via an Artificial Intelligence (AI)-Based Integrated Production Management Architecture (IPMA)
Authors: Bravo César , Saputelli Luigi , Castro José Aguilar , Rios Addison , Rivas Francklin , Aguilar-Martin Joseph 
Published: September 2011

Abstract
Integrated Asset Management (IAM) is highly complex and requires the combined effort of several disciplines and technological tools. The orchestration of disciplines, workflow tools, and available data are paramount issues in the oil and gas industry today. Resource negotiation, communication language, and decision-making protocols are minor issues that exacerbate the problem, resulting in poor and delayed decision making.
This study approaches these challenges through the implementation of innovative, distributed artificial intelligence (AI)-based architecture, designed for automated production management. This architecture, known as the Integrated Production Management Architecture (IPMA), has three layers: a connectivity layer, which allows access to the process information sources; a semantic layer, which establishes an ontological framework to guarantee the process-information integrity during the data interchange process developed between the applications that belong to the Enterprise Technology Information Platform; and a management layer, which automates the production process workflows using oilfield multi-agent systems and electronic institutions.
A virtual oilfield, based on a commercial-integrated production model (IPM) and history-matched data, was used to show the benefits of the proposed approach. The IPM had the following configuration: Three reservoirs, eight oil wells, one flow station, and several gathering pipelines. The IPMA's objective was to maximize asset revenue under different constraint scenarios and changing operational events. The reactive capacity of the architecture, the effective communication between the agents, and the proposed oilfield ontology were tested successfully. In this sense, the well function of the three layers of IPMA was demonstrated.
This study also outlines the use of ontologies and AI techniques that are important factors in future developments of IT solutions for the oil production industry.
A New Method for History Matching and Forecasting Shale Gas Reservoir Production Performance with a Dual Porosity Model
Authors: Samandarli Orkhan , Al-Ahmadi Hasan , Wattenbarger Robert A. 
Published: September 2011

Abstract
This paper presents a new method for history matching production of shale gas wells and future forecasting. The method is based on linear dual porosity analytical solutions which includes horizontal wells with multistage fractures.
A linear dual-porosity model assumes hydraulic fractures as a secondary porosity system and conduit to flow. Homogeneous matrix blocks are sources of primary porosity that feed fluids to the hydraulic fractures. A Systematic analysis was done to determine the main parameters affecting transient flow regimes. Since main flow regimes observed in the field are Bilinear and Linear, more attention was given to those regimes to match with the field data. Analytical solutions are modified for gas properties and desorption of gas from matrix surface.
Besides constant bottomhole pressure production, variable bottomhole pressure cases are also included in this paper. The proposed method was applied to history match the production of shale gas wells from the Barnett, Woodford, and Fayetteville plays. The main parameters found from history matching are effective matrix and fracture permeabilities and fracture half-length. In wells with successful matches, future production can be forecast with some confidence.
Closed-Loop Reservoir Management: Do We Need Complex Models?
Authors: Gildin Eduardo , Lopez Thomas Jai 
Published: September 2011

Abstract
Recently, history matching and optimization were brought together in the oil industry into an integrated and more structured approach called optimal closed-loop reservoir management. Closed-loop control algorithms have already been applied extensively in other engineering fields, including aerospace, mechanical, electrical and chemical engineering. However, their applications to porous media flow, such as - in the current practices and improvements in oil and gas recovery, in aquifer management, in bio-landfill optimization, and in CO2 sequestration have been minimal due to the large-scale nature of existing problems that generate complex models for controller design and real-time implementation. Basically, three sources of high-dimensionality can be identified from the underlying reservoir models: size of parameter space, size of state space, and the number of scenarios or realizations necessary to account for uncertainty. In this paper we will address type problem of high dimensionality by focusing on the mitigation of the size of the state-space models by means of model-order reduction techniques in a systems framework. We will show how one can obtain accurate reduced order models which are amenable to fast implementations in the closed-loop framework by means of model predictive controllers (MPC).
Impact of Natural Fractures in Drainage Volume Calculations and Optimal Well Placement in Tight Gas Reservoirs
Authors: Kang SukSang , Datta-Gupta Akhil , Lee W. John 
Published: September 2011

AbstractCurrent practice of well placement in tight gas reservoirs generally involves the use of empirical correlations based on reservoir properties and analysis of past production and pressure histories and/or pressure maps from flow simulation. No rigorous procedure is available to compute well drainage volumes in the presence of permeability heterogeneity controlled by the distribution and orientation of natural fractures. The situation is complicated by the routine use of horizontal and complex wells in tight gas reservoirs and the presence of multistage hydraulic fractures. The computation of drainage volume will be critical to our understanding of the interaction between existing wells, potential infill locations and the estimated ultimate recovery (EUR) computations for infill wells.We propose a rigorous approach for well drainage volume calculations in tight gas reservoirs based on the flux field derived from dual porosity finite-difference simulation and demonstrate its application to optimize well placement. Our approach relies on a high frequency asymptotic solution of the diffusivity equation and emulates the propagation of a ‘pressure front’ in the reservoir along gas streamlines. The proposed approach is a generalization of the radius of drainage concept in well test analysis (Lee, 1982). The method allows us not only to compute rigorously the well drainage volumes as a function of time but also examine the potential impact of infill wells on the drainage volumes of existing producers. Using these results, we present a systematic approach to optimize well placement to maximize the EUR.We demonstrate the power and utility of our method using both synthetic and field applications. The synthetic example is used to validate our approach by establishing consistency between the drainage volume calculations from streamlines and the EUR computations based on detailed finite-difference simulations. We also present comparison of our approach with analytic drainage volume calculations for simplified cases. The field example is from one of the tight gas fields in the Rocky Mountain region. We utilize the streamline-based drainage volumes to identify depleted sands and generate a reservoir ‘depletion capacity’ map to optimize infill well placement based on the undepleted and undrained regions. The field application clearly demonstrates a systematic approach to optimal well placement in tight gas reservoirs.
Practical Aspects of Reserve Determinations for Shale Gas
Authors: Strickland R. , Purvis D. , Blasingame T. 
Published: September 2011

Abstract
Shale gas currently provides 20% of domestic supply, is targeted by half of the gas-directed drilling rigs, and represents the large majority of domestic resources. However, modern shale plays, their development strategies and their engineering analysis are young by comparison to those of conventional reservoirs. Uncertainty in shale gas reserves has significant implications at both the micro and macro levels.
Conventional reservoir engineering tools must be viewed as potentially inadequate (or even inappropriate) for the evaluation of shale gas performance primarily because of the extremely low aggregate permeability of these systems, but also because of other unique aspects of the systems. Reservoir modeling (simulation) has an important role as an assessment and prediction tool; however, the character of the reservoir (induced and enhanced natural fractures) must be considered, as well as the geological and fluid characteristics. Rate-transient analysis (modern decline analysis) techniques are also more rigorous and have been expanded and adapted to fit the uniqueness of shale gas production. Application of each method for shale gas is discussed, including methods and limitations. These two techniques more closely represent the physics of shale gas production, but their implementation is often prohibitive.
By way of necessity, much engineering evaluation is performed using Arps decline curve analysis. This technique is argued by some to be inappropriate due to a lack of theoretical support and demonstrated tendency to over-estimate reserves in tight gas systems. Given the limitations, practical methods exist to reduce error associated with its use. A newer decline method, power-law exponential, is also investigated.
Optimizing Fracture Stages and Completions in Horizontal Wells in Tight Gas Reservoirs Using Drainage Volume Calculations
Authors: Sehbi Baljit S , Kang Suksang , Datta-Gupta Akhil , Lee W. John 
Published: September 2011

Abstract
Horizontal well technology is now considered a standard completion practice in unconventional gas reservoirs. With significant improvements in the drilling and completion technology, many tight gas and shale gas prospects have become economically viable. Optimizing location, distribution and the number of stages of hydraulic fractures is an important issue in tight gas reservoir completions, particularly for horizontal and complex wells.
The paper presents a fast approach to optimizing well completions in tight gas reservoirs using a rigorous semi-analytic computation of well drainage volumes in the presence of multiple stages of hydraulic fractures. Our approach relies on a high frequency asymptotic solution of the diffusivity equation and emulates the propagation of a ‘pressure front’ in the reservoir along gas streamlines. The proposed approach is a generalization of the radius of drainage concept in well test analysis (Lee, 1982). The streamlines are computed from the pressure and velocity distribution derived from finite difference simulation. This makes the approach completely general and capable of handling complex spatial reservoir heterogeneity and arbitrary well conditions. Furthermore, the streamline approach is visual, intuitive and allows us to examine the interactions between the hydraulic fractures, reservoir heterogeneity and the implications on the drainage volumes and EUR calculations.
A field example is presented to demonstrate the application of our approach by optimizing well completions in a horizontal well recently drilled in the Cotton Valley formation. We first apply the proposed drainage volume calculations to an existing vertical well and identify its ‘region of influence’ along with the potential interference from the proposed horizontal well. We then apply the drainage volume concept to the proposed horizontal well and examine the effects of different number of hydraulic fracture stages. The combined drainage volumes from the vertical and horizontal well are calculated as a function of the number of fracture stages to determine the point of diminishing return and to optimize the number of fracture stages. The results are found to be consistent with independent analysis based on rate profiles from numerical simulation and NPV calculations.
Investigation of the Relationship between Organic Porosity and Thermal Maturity in the Marcellus Shale
Authors: Curtis Mark E. , Ambrose Ray J. , Sondergeld Carl H. , Rai Chandra S. 
Published: September 2011

Abstract
Thermal maturity is important in determining whether shales containing organic material have produced hydrocarbons and whether those hydrocarbons are oil or gas. One method used to determine the thermal maturity of shales is vitrinite reflectance. Recently nanoscale pores have been observed in the organic material of different gas shales by scanning electron microscopy (SEM). These pores vary in size, number, and density. One possible explanation to the origin and diversity of these pores is that they are formed during the generation of hydrocarbons and thus would be affected by the thermal maturity of the shale.
Using focused ion beam milling (FIB) and SEM imaging, the organic porosity of Marcellus shale samples with vitrinite reflectances of Ro=1.1+ and Ro &gt;&gt;3.1 have been compared. The pores within the organic material have been investigated in relation to thermal maturity. Understanding the relationship between the porosity of the organic material and thermal maturity has implications for many gas shale parameters including the density of the organic material, and therefore total organic carbon (TOC), free and adsorbed gas in place (GIP), the wettability of the shale, and transport properties.
Production Analysis in Unconventional Reservoirs — Diagnostics, Challenges, and Methodologies
Authors: Ilk D. , Jenkins C. D. , Blasingame T. A. 
Published: September 2011

Abstract
The analysis of production data in unconventional reservoirs to determine well/reservoir properties, completion effectiveness, and estimate future production has become popular in recent years. However, production analysis in unconventional reservoirs is a challenging task because of the non-uniqueness associated with estimating well/reservoir properties. Various analysis methodologies exist in the literature, but no single methodology is robust enough to characterize the production data and forecast production. Therefore, from a conceptual standpoint, we believe that production analysis in unconventional reservoirs should not be a "single-method based" application. Instead, multiple analysis techniques combined with diagnostic tools have to be utilized, and challenges associated with the analysis have to be recognized.
This work attempts to provide a review of the existing production analysis and diagnostic techniques as well as to identify the challenges associated with production analysis in unconventional reservoirs. We present an extensive evaluation of the diagnostic tools for assessing data viability, checking data correlation along with flow regime identification. Based on diagnostics and analysis results, we demonstrate the use of forward modeling (simulation) to predict future performance of single/multiple well(s) for various production/completion and field development scenarios. Field examples from a wide range of unconventional reservoirs are used to describe the application of the methodology.
Real-Time 3D Intelligent Portal
Authors: Buyl Marc de , Mazula Nelia 
Published: September 2011

Abstract
The Intelligent 3D Portal is a game-changing technology, where the 3D Virtual Reality (VR) model of an operating asset becomes the primary interface, through which users are able to quickly access and update engineering, maintenance and operational data, as well as to plan and simulate work activities in an accurate replication of their physical asset, be it the producing platform, the FPSO or the drilling ship.
A Practical Solution for Booking PUD Reserves in a Resource Play Using Probabilistic Methods
Authors: Dobson M. L. , Lupardus P. D. , Divine T. W. , McLane M. A. 
Published: September 2011

Abstract
A practical probabilistic method is presented to administer the evaluation of proved undeveloped (PUD) oil and gas reserves in resource plays. In 2009, the Security and Exchange Commission (SEC) adopted revisions to the oil and gas reporting rules which allowed for the opportunity to use probabilistic methods in the evaluation and disclosure of PUD locations that are more than one spacing unit away from existing production. The revisions to the "Modernized SEC Rules" created a need for improved methods to evaluate and disclose probabilistic reserves. The objective of this paper is to present a new and practical probabilistic method for PUD reserve reporting that addresses the SEC requirements. The paper addresses the issues of proved reserve volumes per PUD location, proved well spacing, and "sweet-spots".
The useful method may be applicable to a broad range of subjects, such as professional expertise, individual ownership positions, and geologic play situations. The figures and principle steps of the method are presented using the Fayetteville Shale as an example. The method was developed specifically to comply with the Modernized Rules, to be consistent with statistical principles, and to accommodate ownership situations while maintaining an expectation of being practical to use.
The first paper (Dobson 2011) in this series of three introduced a new method of describing the proved area in a resource play. The third paper will present a practical justification for this probabilistic approach. In this paper, historical production statistics are used to evaluate the method's ability to comply with reasonable certainty in a forecast at specific PUD locations.