bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Rate Transient Analysis Workflow in Unconventional Reservoirs: Horn River Shale Gas Case Study
Authors: Virués C.. , Chin A.. , Turco F.. , Anderson D.. 
Published: November 2013

Abstract
The Horn River Basin is a shale gas play located along the northern border between British Columbia and the North West Territories, in the Western Canadian Sedimentary Basin. This unconventional reservoir utilizes horizontal wells with multistage fracture completions in order to produce fluids from the very low permeability shale. As with many other emerging shale plays, the Horn River play presents significant challenges to operators who are tasked with understanding, developing and producing the play as optimally as possible. Rate Transient Analysis (RTA) utilizes continuous production and flowing pressure data to characterize the reservoir and completion, for the purposes of reserves assessments, supporting field development and completion strategy and for supporting decisions around capital allocation. It has proved to be a very helpful tool for accelerating the "learning curve" of well performance in new plays, for which well - established best practices do not exist.
The purpose of this work is to illustrate how RTA can be applied in the Horn River, using a reliable, repeatable and technically sound workflow. To accomplish this, daily production data from eight multi-stage horizontal wells in the Horn River was analyzed using standard RTA techniques, including type curves, flowing material balance, specialized plots and analytical models. In addition to the standard approach, a probabilistic approach to RTA using Monte Carlo simulation is also included in this work, to address the significant non-uniqueness that exists in modeling unconventional reservoirs. The findings of this paper will include long term production forecasts, as well as our best estimation of reservoir and completion characteristics.
Scale Effect of 3D Heterogeneous Porous Media on Geo-Fluid Characteristics: Insight from Massively Parallel Lattice Boltzmann Computing
Authors: Gao Jinfang , Xing Huilin , Li Qin , Rudolph Victor , Golding Sue D. 
Published: November 2013

AbstractMicro-CT scans provide visualization of core samples that can be used to quantify physical properties important for subsurface flow including, as examples, porosity and pore size distribution, pore connectivity and permeability, amongst many others. 3D scans can deliver a very high level of detail, but at a cost of many hours of scan time. This also implies enormous numerical datasets and associated computational processing load. It is therefore important to understand (1) the voxel resolution that is required to retain physical structure fidelity (e.g., pore size and tortuosity) and (2) the smallest sample size that provides reliable and representative transport calculations (e.g., directional permeability and connectivity). As an application example, we analyze a 3D sandstone sample from the Chinchilla area of the Surat Basin comprising a cuboid of 6.6 mm × 6.6 mm × 12.276 mm. The CT image at 6.6 μm voxel resolution generates 1.86 billion grid elements. The work then examines the effect on physical properties and flow simulation of coarsening the voxel resolution, and reducing the physical size of the sample. For each of the different cases relating to voxel size, the major physical properties are evaluated. For different sample sizes at constant (small) voxel size, the fluid flow is modeled using a lattice Boltzmann method (LBM) on multicore supercomputers. The LBM is efficient and convenient for application in parallel computing, which is required to meet the computational resources needs of 3D simulations with large datasets. Comparison of the results obtained at different resolution scales reveals the minimum representative elementary volume (REV) for voxels to characterize the physical features of porous media, and for sample sizes that effectively eliminate boundary effects, capturing and describing the transport phenomena that underpin reservoir analysis.
The Use of Net Pay Concepts in the Exploitation of Shale-Gas Deposits
Authors: Worthington Paul F. , Majid Azlan A. 
Published: November 2013

Abstract
The role of net pay in unconventional reservoirs continues to evolve as a design criterion for reservoir stimulation and well completions. Unlike conventional reservoirs, shale-gas development is not yet at the stage where longstanding net pay protocols have been tried and tested. Therefore, any protocol has to be regarded as being at a pilot stage, especially in view of the pronounced complexity of shale-gas systems. This state of affairs is progressed by adopting a set of net pay criteria and transposing this into a generic petrophysical workflow that interfaces with other key disciplines such as geochemistry and geomechanics. Essential parameters are total organic carbon (in the setting of thermal maturity), fracturability (based on sand volume fraction and thence brittleness), natural fracture density, effective gas permeability, and total porosity as an input to gas in place. The deliverables in the form of target net pay intervals are based on functional cut-offs for each given reservoir system and for different appraisal fronts within the same reservoir system. This is important because different methods of reservoir zonation can result in very different zonal characteristics and associated parametric relationships. The estimation of uncertainty in cut-off specifications and its impact on the resulting net pay intervals has been approached with reference to a commensurate suite of characterizing well logs groundtruthed by core analysis in at least one key well. These considerations lead to specific ranges of cut-offs for immediate application. Thus, the identification of net pay and thence candidate intervals for completion is placed on a quantitative footing. This is an important contribution to development planning in these highly complex unconventional systems.
The Future of Integrated Groundwater and CSG Simulation - Modeling the Surat Basin, Queensland, Australia
Authors: Howell S , Guiton S , de Verteuil D , Campbell L , Vaughan R , Ryan D , Curum N , Coulibaly K 
Published: November 2013

Abstract
This paper will present a workflow describing the integration of hydrogeological and coal-seam gas (CSG) simulation models into one regional 3D numerical flow model covering an area of 197,000km2 of the Surat B asin, Queensland, Australia. The model is designed to allow QGC to further understand and quantify the potential impacts of CSG production from the QCLNG project on the regional groundwater system and to synthesise geological, hydrogeological and engineering data into a one-Earth model.
The model combines knowledge and concepts from previous work including regional-scale single-phase hydrogeological models using MODFLOW, and more local-scale modeling of the Walloon Subgroup using ECLIPSE* 100. It incorporates a hydrogeological conceptualization, a structural and stratigraphic interpretation; property modeling (taking into account public and QGC well data); an ECLIPSE* model and several calibration steps together with the dual-porosity/dual-phase flow behavior inherent to CSG simulation. This paper will demonstrate that via one model, it is possible to simulate the potential effects of CSG production on the groundwater environment, including both the localised dual-phase effects of CSG production and more regional-scale single-phase groundwater movement.
New Integrated Method for Petrophysical Evaluation of Shale Gas: A Case Study in Weiyuan Field
Authors: Yu D. G. , Zhao Z. A. , Wang Y.. 
Published: November 2013

Abstract
Exploration for shale gas plays has proved economically viable in North America and has changed the way E&P companies address unconventional reservoirs. After Chinese governments drafted the 12th Five-Year Plan—an initiative designed to rebalance economics in various themes, including energy—gas shale exploration became a hot topic. Shale reservoirs comprise the source, seal, and the reservoir, and production is stimulated by hydraulic fracturing treatments. Modeling that predicts economic productivity and optimal fracture stimulation design is critically based on the detailed, integrated petrophysical evaluation for gas shale plays.
This paper presents an integrated approach to the petrophysical evaluation of resources in the Weiyuan field, the biggest gas shale play in China. Our approach integrates different types of data, including standard formation evaluation logs, geochemical logs and advanced acoustic logs. These data, when combined, provide answers about the reservoir quality and the completion quality. The reservoir quality is established by the information from conventional formation evaluation log and geochemical logs, which include TOC, mineralogy, porosity and gas in place etc. The completion quality is established by the analysis of advanced sonic measurement and resistivity image log, which include geomechanical parameters, natural fractures and induced fractures etc. In this new integrated petrophysical evaluation method, elemental capture spectrometry and advanced acoustic measurements are the keys for estimating reservoir and completion quality. Capture spectrometry measurements provide the accurate mineral content information that is important for ascertaining reservoir quality. Advanced acoustic data can provide the 3D geomechanical parameters and stress estimates required for fracture job design. After integrating reservoir and completion quality, the fracture design is optimized; components include outlining stages, perforation methods, intervals and fracturing fluids.
This integrated evaluation method is being used to establish the petrophysical and geomechanical properties of the Weiyuan gas shale target and also can be applied to other gas shales in China.
An Integrated Disciplinary Approach Towards Hydraulic Fracturing Optimization of Tight Oil Wells in the Ordos Basin, China
Authors: Li Xi Sheng , Wu Liu Pei , Yin Luo , Judd Tobias 
Published: November 2013

Abstract
Exploiting the vast quantities of in-place oil in some of China's large sedimentary basins will require understanding and identifying where new technologies and techniques can be applied to maximize production. Exploration in the Ordos basin in north-central China has demonstrated that tight oil reservoirs, such as the Chang 7 formation, are widely distributed; however, they remain relatively underdeveloped. These reservoirs are buried below the conventional oil layers, differ from them by geological composition, and their thin pay zones and low permeability present development challenges.
As part of a standard exploration and appraisal program, multiple vertical wells have been drilled to characterize the Chang 7 reservoir quality, and many were completed with only one hydraulic fracturing stage. Unfortunately, average hydrocarbon production was often low, and horizontal well completions with multiple transverse hydraulic fracturing treatments were required to obtain commercial flow rates. Part of the integrated workflow developed for the stimulation program requires the capture of reservoir, geological, and geomechanical properties for use in the design of the stages. The perforations were designed to allow for effective fracturing treatments across the lateral and were placed using the abrasive perforating technique. Additionally, one of these vertical wells was used for real-time microseismic fracturing monitoring to evaluate fracture geometry, fracture orientation, and azimuth.
Real-time technology and an integrated workflow effectively increased the understanding of where, when, and how to deploy hydraulic fracturing treatments in the lateral section of the study well. This optimization has resulted in more than an 8-fold increase in production compared to that from vertical wells. Considered a breakthrough, this project has resulted in the planning for additional horizontal wells.
Production Data Analysis of CBM Wells in Surat Basin
Authors: Sugiarto I.. , Jiang J.. , Sharma V.. , Mazumder S.. 
Published: November 2013

Abstract
The advancement in Production Data Analysis (PDA) techniques allows the determination of useful reservoir properties such as permeability, drainage radius and original gas in place (OGIP). Recent publications (Clarkson8 et al 2007; Clarkson9 et al 2008) demonstrate the modification of production type-curves and material balance methods for Coalbed Methane (CBM) reservoirs.
One of Arrow Energy's projects is located in the Surat basin in Queensland. The coals intersected in the Surat Basin are members of the Walloon Coal Measures (Walloon Subgroup) which are divided into the Juandah Coal Measure and the Taroom Coal Measure. The Walloon Coal Measure architecture is an inter-bedded coal, siltstone and sandstone sequence. The coals are generally thin with permeability ranging from 5–5000 mD. The Walloon subgroup coals are classified as high volatile bituminous. The Surat Basin has been developed using vertical and deviated wells penetrating the whole sequence. The Surat Basin coal reservoirs can be undersaturated or saturated. In the undersaturated case, single phase flow of water occurs during the early dewatering period. In the saturated case, two-phase flow of gas and water occurs at initial production.
Arrow Energy has produced from the Surat Basin since 2006. The large amount of production data serves as a valuable source for PDA. Results indicate that the flow regime is dominated by linear flow during the transient period followed by boundary-dominated flow. A flowing material balance method is used to validate reservoir parameters from well simulation history matching and type-curves methods. The reservoir parameters such as permeability, drainage radius and OGIP obtained from all the methods are compared and quality checked. The decline curve analysis (DCA) method is performed on wells which have entered boundary-dominated flow to obtain the estimated ultimate recovery (EUR) and recovery factor.
The PDA study is carried out for approximately 250 existing production wells in the Surat Basin. The reservoir parameters obtained from the various methods agree with one another, indicating reliable results. The permeability values obtained from this study are within the range of the Drill Stem Test (DST) results in the Surat Basin.
Water Saturation Evaluation of Murteree and Roseneath Shale Gas Reservoirs, Cooper Basin, Australia Using Wire-line Logs, Focused Ion Beam Milling and Scanning Electron Microscopy
Authors: Ahmad Maqsood , Haghighi Manouchehr 
Published: November 2013

Abstract
Roseneath and Murteree organic shales in Nappamerrie trough are part of most prolific unconventional gas reservoirs in Cooper Basin, South Australia. The cumulative effect of rocks, minerals, fluids and organic content in these shale gas reservoirs has been investigated and incorporated using Archie's equation and other resistivity models such as Indonesian, Siamandoux and total shale model for water saturation evaluation. In this study, wireline logs have been calibrated with QEMSCAN and FIB/SEM images.
We have found that the shale content in Murteree formation is around 50% using QEMSCAN analysis. Also, it is found that using Steiber formula, the shale volume is close to 50%. Therefore, the Steiber formula is selected as the proper correlation to estimate shale content for Murteree formation. Furthermore, the free porosity of Roseneath and Murteree shale was measured to be 2% based on QEMSCAN and CT scanning. Then, Using Wyllie formula for sonic porosity with Hilchie's correction factor, the porosity was also determined close to 2%. Thus, Wyllie formula with Hilchie's correction factor was also found to be the appropriate correlation for porosity calculation in Roseneath and Murteree shale.
For water saturation, both Simandoux and Indonesian correlations were shown to give reasonable results. However, it is found that if free porosity is more than 9%, both total shale and Archie models can also give acceptable results. The sensitivity of true resistivity in water saturation calculation was investigated as well. Furthermore, the evaluation of Archie's parameters (cementation exponent, m, tortuosity factor, a, and saturation exponent, n) were examined. Also, FIB/SEM images show that brine and organic matters are both attached to the clay particles which have caused a modified true resistivity for the shale.
Implementation of Wireline Formation Testing Configuration for the Evaluation of Coal Seam Gas Plays in Surat and Bowen Basins in Australia
Authors: Pourabed Hamid Reza , Harfoushian Jack H. , North Tim 
Published: November 2013

Abstract
A coal seam gas (CSG) to liquefied natural gas (LNG) project in Queensland, Australia, has an active exploration and appraisal program in support of future development activities. Critical to exploration and appraisal is the evaluation of permeability, skin, and reservoir pressure. Drill stem testing (DST) has been the most common form of evaluation since the inception of the industry in Queensland over the last 10 years. DSTs commonly used in the CSG industry are modified ‘slug’ tests in which a water cushion provides hydrostatic backpressure on the formation to reduce the likelihood of gas break-out and two-phase flow. Although DSTs have become an industry-accepted method for evaluating permeability, skin, and extrapolated reservoir pressure, there are some disadvantages to this approach.
A new wireline formation testing technique addresses the evaluation objectives of CSG testing in the Surat and Bowen basins. In addition to efficiency and cost-effectiveness, the approach provides additional testing flexibility; this includes the ability to manage a broad range of drawdown and inflow rates, extending its applications from very low to high permeability coals. Additional applications include step-rate tests, across both the Walloon coal measures of the Surat basin and the Bowen basin's Bandanna formation.
Evaluating Treatment Methods for Enhancing Microfracture Conductivity in Tight Formations
Authors: Nguyen Philip D. , Vo Loan K. , Mock Brian D. , Loghry Ray A. 
Published: November 2013

Abstract
Most microfractures generated within a complex fracture network return to a closed state soon after the release of hydraulic pressure, unless propping agent has been successfully placed inside these fractures. However, particle size and proppant density control the success of such placement. This paper presents the results of a laboratory study that demonstrates and quantifies the effectiveness of methods for enhancing and sustaining the conductivity of microfractures in tight formations.
This study examines the conductivity performance of placing microproppant particulates compared to performing an acid fracturing treatment in a created fracture. Various shale core samples were obtained and split along the core length to create artificial fracture faces. Before placement of microproppant into the fracture, the split core fracture faces were first treated with an aqueous-based surface modification agent (ASMA) solution that creates tacky sites to capture any proppant exposed to the treated surface and to mitigate proppant settling. This was then followed by exposure to microproppant slurry. The core halves were then reassembled for core flow testing under closure stress. An acid fracturing treatment administered through the split core fracture involved injection of a sequence of materials that slowly releases organic acid and inorganic acid to etch fracture faces, forming gaps or channels within the fractures, by allowing acid to efficiently dissolve the solid structures on the split core fracture faces.
The experimental results are presented by examining the reliability of ASMA treatments to mitigate proppant settling. A permeability comparison of the fractured cores, with and without treatment with ASMA and proppant slurry, demonstrates a dramatic increase to permeability in the treated cores. Permeability measurements of acidized split cores also demonstrate a drastic improvement compared to those of untreated split cores, indicating the importance of maintaining acid activity to maximize fracture etching effectiveness.
Technology Advances in the Understanding of Reservoir Performance in the Woodford Shale Gas Field, Arkoma Basin, USA
Authors: Carragher Paul , French Samuel 
Published: November 2013

Abstract
Since drilling of the very first horizontal well in 2005, more than 1500 horizontal wells have been brought into production in the Devonian-aged Woodford shale gas field in the Arkoma Basin of Oklahoma, USA. In 2008, through a combination of trades and purchases of acreage, BP consolidated its position as the first Major International Oil Company in the Woodford field and has subsequently drilled more than 200 horizontal wells and gained a working interest in a further 981 wells.
Across the field area of more than 3000sqkm, initial stabilised production rates range from 2 to 8 million standard cubic feet per day and estimated per-well recovery (EUR) ranges from 2 to 7 bcf per well. Improvement in the prediction of this highly variable well performance in this unconventional reservoir is seen as critical in the economic design of the field development. To assist in understanding and prediction of this large variation in well performance, BP has designed and applied a number of evaluation technologies that have enabled the integration of well operations data and reservoir characteristics. In a core operations area covering approximately 340sqkm, BP has conducted closely controlled operational experiments in numerous aspects of reservoir management and well completion. These have included research in determination of optimal well spacing, selection of horizontal well lateral lengths and variation in frac stage spacing. Through analysis of all the available production and operational data, it has been possible to construct a Performance Indicator (PI) tool through which production variations across the field could be visualized. This approach has demonstrated that the variation of well performance is best related to geological or more general subsurface trends rather than well-completion or other operational design issues. Integration of these data has enabled BP to significantly improve the accuracy of production forecasts for both short and long-term field performance. Critical elements in the success of this project include key advances in understanding the importance of subsurface structural complexity, the impact and prediction of local variation in the shale reservoir characteristics and the careful management of changes in well design and completion methods. Together, these have enabled the accurate prediction of reservoir geological risk and allowed better definition of specific areas of the field where well performance could be expected to be at its best. Direct benefits of this integrated evaluation have included the the prediction of reservoir performance of new infill wells, identification of areas in the field where development well spacing could be reduced and gaining manangement support for a proposed refraccing programme.