bluuebunny/crossref_metadata_2025 huggingface dataset:
Advancements in Downhole Drilling Tool Placement for Highly Deviated Wells and ERD Applications
Authors: Bouaziz Souhail , Cummings Jerry , Rebellon Jorge , Barton Steve , Yankow Anna
Published: September 2011

With the discovery of shale plays around the world, there has been an increase in the prevalence of highly deviated wells and extended reach drilling. Both highly deviated wells and extended reach drilling present drilling challenges; modeling is required at various stages of the well and several considerations must be taken into account. In addition, detailed torque and drag analysis along with a comprehensive analysis of hydraulics programs must be performed to ensure the down hole equipment used for the application meets the challenging requirements. One of the most important considerations that should be taken into account is jar placement.

The intricacies of jar placement are typically misunderstood and often over-looked. Good, sound technical recommendations on jar placement are generally hard to come by. Yet, legitimate technical advice on jar placement can ultimately ensure the use of optimal operational guidelines when drilling in highly deviated wells and using extended reach drilling. In these instances, conventional jar placement knowledge does not always apply.

Highly deviated wells and extended reach drilling present unique drilling challenges such as the possibility of getting stuck in two different sections of the well bore. Computer modeling is currently used to predict any down hole loads that would hinder the operation of a drilling jar used in such an instance. This paper provides an analysis of jar placement in highly deviated wells and promotes the use of two drilling jars in the drill string. In addition, consideration is given to jar placement calculations which are further discussed in order to provide optimal impact and impulse result recommendations. A set of operational guidelines also has been included, ensuring that optimal results are obtained when using two jars in the drill string.
A Novel Screening Method for Selection of Horizontal Refracturing Candidates in Shale Gas Reservoirs
Authors: Sinha Shekhar , Ramakrishnan Hariharan
Published: September 2011

A novel method to rapidly screen potential horizontal refracturing candidates utilizing production performance and completion data analysis is presented. Candidate selection methods based solely on production comparison analysis are not very effective (Reeves, 2000). Integration of initial hydraulic fracture completion details augments the process and helps in screening understimulated wells in different production classes. To accomplish this, a new index called a "completion index" is defined after analysis of the completion parameters, production behavior and their inter-relationship. Typically, a completion index will be based on the well completion and stimulation job parameters, such as completion type, fluid volume, proppant volume, completed interval length, number of stages etc. The production index is a time normalized production indicator representative of longer-term production or expected ultimate recovery. A crossplot of production indicators and the completion index is used in the initial screening of potential candidates.

This method enables fast and efficient screening of wells with a below- average completion index and similar production index from thousands of wells. The screened candidates can then be taken to a higher tier of analysis that integrates the production performance and completion information with available petro-physical data and geological information. A reservoir quality indicator along the horizontal laterals can be extracted from the reservoir model and analyzed with completion index to better understand the production drivers.

Based on the data sets studied from Barnett shale areas it was possible to rapidly shortlist 15–20% of the wells from a large well population for further detailed analysis. Wells with an average and higher production index with below average completion index proved to be better candidates in terms of economic payout.
Submicron-Pore Characterization of Shale Gas Plays
Authors: Elgmati Malek , Zhang Hao , Bai Baojun , Flori Ralph , Qu Qi
Published: September 2011

Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40–50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet).
Applying Real Time Well Performance Monitoring to a Mature Asset in Gabon: Case Study, Operational Feedback and Lessons Learned for Upcoming Deployments
Authors: Gibert Gaël , Simba-Ngabi Marcellin , Lestage Jean-Renaud
Published: September 2011

This paper describes the process of development, deployment and operation of an in-house integrated real time solution for Well Performance Monitoring (WPM) dedicated to mature asset in Gabon that took place in 2008. Particular focus is given to the assessment of how initial objectives in terms of functionality and practical benefits - namely daily diagnosis, setting and asset-wide optimization - have been fulfilled. The last part details how the lessons learned during this period allowed Total Gabon to extend in an efficient way the WPM solution to another mature oilfield of its portfolio, as part of a major rejuvenation and additional development programme.

The proposed material is of direct application for whoever is to develop, deploy or use a real time monitoring solution involving one or several of the following features: multiple databases, multi-disciplinary teams, workflow oriented approach, modelling and optimisation, shared application. It is of particular use to anyone involved in mature asset production optimization. Several key success drivers are highlighted and illustrated through detailed examples: –Identify and involve key users–Promote early operational feedback–Audit instrumentation, communication, network, databases, applications and models–Identify and prepare necessary adjustments of business processes–Avoid project overselling–Provide impeccable and proactive user support–Initiate and maintain momentum

This paper provides an un-biased feedback from the end-user point of view based on three years of extensive use and testing in real operations. Moreover, technical and organizational issues faced during the early deployment phase are thoroughly discussed, focusing on the importance of change management. Finally, the paper describes how it has been possible to capitalize upon the initial experience in order to improve the efficiency of the deployment of the WPM solution on a second asset.
Predicting Wellbore Dynamic-Shock Loads Prior to Perforating
Authors: Burman Jack , Schoener-Scott Martin , Le Cam , Suire David
Published: September 2011

Oilwell casing perforating has been used in the industry since 1932 and was pioneered by the Lane-Wells Company who introduced the bullet-gun perforating technique. Shortly after the introduction of the bullet gun, explosive jet perforators were introduced, which provided a different and more aggressive way to perforate casing.

With the increased demand for oil and gas over the past decades, operators have been forced to explore deeper, hotter reservoirs to find the most prolific reservoirs. These deepwater opportunities have required constant changes to equipment and services to increase their technical capabilities for performing in more critical environments. Perforating with higher-shot densities, propellants, and larger perforating guns has been ongoing to meet these new challenges.

A major problem with these increases, however, is the difficulty in predicting dynamic wellbore behaviors that cause tubulars to collapse and bend and packers to unset as perforating guns were detonated. Research to understand the pressure behavior during the perforation event, in addition to the solid loading that is imparted to the tubulars, packers, and other completion hardware in the perforating assembly, was needed to enable the industry to go forward with a high level of confidence that wells could be completed safely and cost effectively.

This paper discusses a shock-wave computer modeling program that evaluates the mechanical risk factors of well components to ensure that the health, safety, environment, and service quality needs in a design are addressed. A time-marching, finite-differences technique is applied as the numerical method for both fluids and solids. The software is installed on a personal computer and typically executes the models within several minutes to several hours, depending on the complexity of the job design.

The physics-based model has been validated (Schatz et al. 1999; Schatz et al. 2004) with special high-speed recorders that sense pressure, temperature, and acceleration at a sampling frequency of 115,000 samples per second.

This paper provides data from offshore oil and gas wells in the Gulf of Mexico to demonstrate the success of the design.
A Practical Guide to Interpreting Microseismic Measurements
Authors: Cipolla C. , Maxwell S. , Mack M. , Downie R.
Published: September 2011

Thousands of hydraulic fracture treatments have been monitored in the past ten years using microseismic mapping, providing a wealth of measurements that show a surprising degree of diversity in event patterns. Interpreting the microseismic data to determine the geometry and complexity of hydraulic fractures continues to be focused on visualization of the event patterns and qualitative estimates of the "stimulated volume", which has led to wide variations and inconsistencies in interpretations. Comparing the energy input during a hydraulic fracture treatment and resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation. The vast majority of the energy is consumed in aseismic deformation (tensile opening) and fluid friction (Maxwell et al. 2008). Proper interpretation of microseismic measurements should account for both seismic and aseismic deformation, coupling the geomechanics of fracture opening and propagation with the shear failures that generate microseisms.

Interpretation of microseismic measurements begins with an evaluation of location uncertainty, using signal-to-noise ratios and error ellipsoids, along with event moment magnitude. In some cases, microseismic event location uncertainty is erroneously interpreted as fracture complexity. The next step is to normalize the data and correct for observation well bias, both distance and azimuth, including use of seismic radiation patterns. Without these corrections fracture behavior from well to well or stage to stage (especially in horizontal wells) can easily be misinterpreted. Advanced geophysical processing that describes the failure mechanisms in more detail may also aid in the interpretation. The final step in the interpretation is to include the geomechanics of the overall process, accounting for the fracture treatment volumes injected, the net pressure in the hydraulic fracture(s) and the shear failures that generated the microseisms. This final, critical step is often overlooked when interpreting microseismic measurements. The paper provides a comprehensive, yet practical guide to the interpretation of microseismic measurements.
Understanding Hydraulic Fracture Variability through Integrating Microseismicity and Seismic Reservoir Characterization
Authors: Maxwell S. C. , Pope T. , Cipolla C. , Mack M. , Trimbitasu L. , Norton M. , Leonard J.
Published: September 2011

Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity. The increased level of microseismic deformation and corresponding fault-related source characteristics correlated with the presence of a pre-existing fault identified by edge detection/ant tracking algorithms applied to seismic reflection data. In cases where the wells were far from pre-existing faults simple, planar hydraulic fractures were observed, although there was a tendency to grow towards regions of low Poisson's ratio based on amplitude versus offset inversion of the seismic reflection data. The tendency for the hydraulic fractures to be asymmetric and grow preferentially towards the low Poisson's ratio region is attributed to material property changes and associated lower stresses in these regions. Integrating microseismic interpretations and fracture treatment data with enhanced reservoir characterization has been used to rethink well placement and completion designs, resulting in improved well performance.
Improved Basin Analog Approach to Characterizing Frontier Basins for Unconventional Gas Resource Potential
Authors: Cheng Kun , Wu Wenyan , Holditch S. A. , Ayers W. B. , McVay D. A.
Published: September 2011

During the past decades, investigation of unconventional gas resources has become a significant area due to its promising outlook of meeting the future energy needs. When the unconventional gas resources, especially those in frontier basins, expose a set of challenging issues that both knowledge and practice are very limited, basin analog analysis has been employed for preliminary assessments of frontier plays.

For basin analog, it compares a comprehensive spectrum of features between the target basin and reference basin, and this process involves large-volume data with broad value ranges. To rapidly and effectively evaluating the unconventional hydrocarbon resource potential in frontier basins (i.e., the target basins), basin analog approach has been proposed since 2008, in combination with a database populated with well-characterized geologic and petroleum systems information of North America basins that have significant unconventional resource development (i.e., the reference basins). The continuing investigation has been based on the public literature, and it is noted that data of many petroleum systems are incomplete that cannot cover the entire comprehensive parameters. This problem is inherently typical of the unconventional basins: many unconventional petroleum systems are newly developed and the characterization data are unavailable; or the unconventional basins, especially for the frontier basins, are exploratory with many plays undeveloped or in the very early development stage. Another major problem in analyzing basin analog is that parameters are usually multi-valued due to the wide range of petroleum systems.

In this paper, we analyzed the previous approaches of basin analog analysis and proposed an improved solution to the problems. The improved method is based on extracting the characterized parameter distributions in basin scale, and compares distributions by using probability theory and information theory. This method can not only solve the incomplete analog and multi-value comparison problems to achieve more accurate results, but also directly reflect the quantified distributions of different parameters in multiple basins simultaneously. Also discussed are validation of the analogous relationships by basin resource distributions and the further usage of the improved basin analog analysis for estimating unconventional resource volumes in frontier basins.
Shale Permeability Determined by Simultaneous Analysis of Multiple Pressure-Pulse Measurements Obtained under Different Conditions
Authors: Civan Faruk , Rai Chandra S. , Sondergeld Carl H.
Published: September 2011

Several pressure-pulse measurements are conducted on similar plugs extracted from various tight-shale formations under different boundary conditions. A theoretically rigorous model-assisted analysis of a number of data sets is carried out for achieving uniqueness in determination of intrinsic shale permeability. The best estimate values of the unknown parameters, including the Langmuir volume and pressure, and the intrinsic permeability of the shale samples at a reference condition are determined by matching the numerical solution of our improved non-Darcy model simultaneously to several sets of the observed pressure-pulse transmission data. Simultaneously, we delineate the dominant characteristics of the apparent permeability and the contribution of the various flow regimes. It is concluded that our improved method provides a better match to the pressure-pulse decay tests than the previous models which assumed Darcy flow. Further, our formulation allows for model-assisted extrapolation to other conditions once the unknown parameter values have been estimated under laboratory testing conditions.
Palynofacies Analysis and Submicron Pore Modeling of Shale-Gas Plays
Authors: Elgmati Malek , Zobaa Mohamed , Zhang Hao , Bai Baojun , Oboh-Ikuenobe Francisca
Published: September 2011

The present study combines palynological applications with advanced microscopic techniques to characterize the Utica, Haynesville and Fayetteville shale-gas source rocks. This unprecedented approach could offer an alternative way to measure the total organic carbon (TOC) content using the 2D subsurface Scanning Electron Microscope (SEM) images. This approach is considered to be a faster and inexpensive method compared to conventional geochemical analyses. Palynofacies analysis provided valuable information about kerogen type and its degree of thermal maturation, which are key parameters in shale-gas exploration. Moreover, it qualitatively allowed the estimation of important organic geochemical parameters such as vitrinite reflectance (Ro %) and numerical thermal alteration index (TAI). New high resolution microscopic solutions have successfully been exploited for source rock characterization at both micro- and nano-meter scales. In-situ Focused Ion Beam (FIB) and Scanning Electron Microscope (SEM) technologies provided new insights into rock fabrics such as porosity, permeability, tortuosity, anisotropy and kerogen content. Serial sectioning and sequential imaging using dual beam SEM/FIB instrument were implemented successfully to characterize the 2D kerogen content and 3D submicron-pore structures. Moreover, pores were found in organic matters with the size of nano level and occupy 40–50% of the kerogen body. A successful example of reconstructed 3D pore model from Fayetteville Shale is presented.
A Semianalytical Approach to Estimating EUR in Unconventional Reservoirs
Authors: Kabir C. S. , Lake Larry W.
Published: September 2011

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

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

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

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

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

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

Current 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

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

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

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 >>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

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

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

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.
The Effect of Microporosity on Transport Properties in Tight Reservoirs
Authors: Mehmani Ayaz , Tokan-Lawal Adenike , Prodanovic Maša , Sheppard Adrian P.
Published: September 2011

Diagenetic changes (e.g. cementation, compaction) in tight gas sandstones (TGSS) often disconnect the original, inter-granular pore space and further create microporosity within the original grains (e.g. by dissolution) or by filling the inter-granular porosity with clay. A petrophysically rigorous fundamental model of TGSS that accounts for microporosity would make the evaluation, development and stimulation of tight gas sandstone development more robust. The reduced connectivity of matrix pores has a profound effect on transport properties such as absolute and relative permeability, resistivity and capillary pressure - saturation relationships. To address this, we construct networks that incorporate both inter-granular (primary) porosity and microporosity, and use a network model to estimate flow properties. We present algorithms to geometrically match pore throat networks from two separate length scales that can be extracted directly from 3D rock images, or be constructed to match the relevant measured properties. Microporosity and its spatial distribution have a profound effect on the relative permeability curve. When inter-granular network is disconnected (but the microporous region is not), we provide capillary pressure - saturation curves in cases thus far unresolved with any other type of modeling. The results from model media reasonably match published experimental data. While we are motivated by TGSS, with suitable characterization the model is applicable to other reservoirs with dominant microporosity component (shale, carbonates).
Design and Examination of Requirements for a Rigorous Shale-Gas Reservoir Simulator Compared to Current Shale-Gas Simulators
Authors: Andrade Juan , Civan Faruk , Devegowda Deepak , Sigal R. F.
Published: September 2011

The necessary and sufficient conditions of the design parameters that should be considered to build proper shale-gas reservoir simulators are investigated. The design requirements are established based on the theoretical studies of flow through extremely low permeability porous media, ion milled SEM images of the nano-geometry of shale-gas reservoir formations, laboratory petrophysical measurements, and the available production and stimulation information. This paper presents a critical discussion of the relevant aspects such as the reservoir formation structure, fluid storage and transport mechanisms, and gradual non-equilibrium motion and dynamic distribution of fluids in the pore system. Then, an overview of the capabilities of the commonly used reservoir simulation software is presented in view of the identified requirements of shale gas reservoirs. Quantitative comparisons between the alternative formulations against the conventional formulations are also presented with several examples using an in-house simulator developed in this study. Areas needing new fundamental formulations and further research for proper shale-gas reservoir modeling are delineated. This paper provides important insights and guidelines for development of adequate numerical simulators that can correctly accommodate for the proper description of the relevant phenomena, and predict gas production and water displacement in shale-gas reservoirs.