bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effective Implementation of High Performance Water Based Fluid Provides Superior Shale Stability Offshore Abu Dhabi
Authors: Mehtar Mohammed , Brangetto Martial , Soliman Ahmed Abou , Mielke Scott , Alfonzo Nelson , Young Steve 
Published: February 2011

Abstract
Drilling offshore Abu Dhabi presents some unique challenges primarily related to wellbore instability in directionally drilled wells through the unstable Nahr Umr and Laffan shale formations. This not only affected drilling performance and cost millions of dollars due to non-productive time (NPT), but had also placed constraints on the Company’s field development plans, as it was not possible to drill high deviation wells through these shales with a high degree of success. It was a major challenge to develop and engineer a water-based drilling fluid that could effectively eliminate shale instability encountered while drilling these high deviation wells.
The stabilization of these highly laminated shales required an effective synergistic blend of products to both maintain the chemical stability of the shales and minimize the transmission of fluid pressure into the shales, while sealing both natural and induced micro-fractures. The development of the ideal types and blend of products, treatments and engineering techniques tailored to these specific rock requirements is crucial to drilling success. The net result of the correct application of this unique drilling fluid system has been to mitigate the incidences of cuttings accretion, wellbore instability, time-related failure and induced losses into permeable formations, thereby eliminating drilling non-productive time.
This paper describes the development and field application of a uniquely engineered water-based drilling fluid that demonstrates enhanced shale stabilization properties, much like the invert emulsion systems, but without the associated waste management equipment and logistics and environmental exposure. Additionally, the development and use of a new class of sealing additives is outlined showing how improved stabilization of the wellbore can be achieved while drilling these older, highly laminated shale formations. Extensive laboratory work was carried out under simulated conditions, on both the fluid system and sealing additives to optimize the fluid formulation. Thereafter, successful field applications were carried out in high inclination wells in the area. Drilling performances were greatly enhanced compared to conventional fluid systems, which accrued significant cost savings to the operator. Further, there is additional flexibility to drill high deviation wells through these shales, as required to reach a reservoir target. This development approach and the use of the unique stabilization additives can be utilized in many other areas where issues of wellbore instability in older and laminated or fractured shales exist.
Surface Microseismic Mapping Reveals Details of the Marcellus Shale
Authors: Hulsey B. J. , Cornette Brian , Pratt David 
Published: February 2011

Abstract
The mapping of microseismic events induced by hydraulic fracturing plays an important role in well completion and design. This is especially true in a newly developing area of gas producing shales. In this case study, we will show how the microseismic monitoring of a hydraulic fracture treatment in the Marcellus Shale identified a pre-existing natural fault which intersected the wellbore. The data from nearby wells indicated several possibilities of structural evolution affecting the producing formation. These range from regional reverse or strike-slip faulting to small displacement local reverse faulting. The hydraulic fracture stimulation was monitored using a 10 line, radial surface array composed of 1000 vertical component geophone stations. The treatment consisted of seven perforated stages stimulated with slickwater and proppant.
Microseismic activity mapped during the early stages of the treatment is consistent with the regional stress direction and indicates that stages 1-4 activated natural fractures oriented along the maximum horizontal stress direction. During stages 5 and 6, the hydraulic fracture encountered a pre-existing natural fault. A source mechanism was determined for events occurring along the fault, identifying oblique failure with strike-slip and reverse faulting along the steeply dipping fault with SSE strike. This indicates that the regional strike-slip fault, with a strike similar to the break we observed at other offset wells, is most likely responsible for the geological evolution of this formation.
Fracture Extent and Zonal Communication Evaluation Using Chemical Gas Tracers
Authors: Mulkern Mark , Asadi Mahmoud , McCallum Scott 
Published: February 2011

Abstract
Chemical gas tracers have been used in gas flood projects to evaluate interwell communications, formation heterogeneity, channeling, and to calculate volumetric sweep efficiency. For the first time, these tracers are used to evaluate the extent of fracture communication with offset wells and also to evaluate zonal communication between four hydraulically fractured reservoirs. The four horizontal wells are drilled and completed in Berea, Chagrin, Lower Huron Siltstone, and Lower Huron reservoirs. Each well was individually fractured with nitrogen gas in nine stages. A different chemical gas tracer was injected in each of the horizontal wells during the fracture stages with the carrier gas. Upon the completion of each fracture treatment, the well was shut-in to frac the next well. Upon the completion of the last fracture treatment, the well was shut-in for the reservoir pressure to stabilize before all four wells were put back on production. Flowback gas samples were collected at the wellhead for tracer detection analysis and hence flowback analysis. In addition, produced gas samples were collected at the offset wells for gas tracer detection to evaluate the extent of the fractures, interwell communication and formation heterogeneity. The results of flowback, zonal communication and extent of fracturing are presented in detail.
A Practical Approach for Production Data Analysis of Multilayer Commingled Tight Gas Wells
Authors: Ali T. , Cheng Y. , McVay D. A. , Lee W. J. 
Published: February 2011

Abstract
This paper proposes and validates a robust methodology to estimate fracture properties (half-length and conductivity), formation permeability, and, where possible, drainage area of individual layers in hydraulically fractured vertical gas wells producing commingled from multiple layers. Estimation of these fracture and individual layer properties is required to evaluate fracture treatment effectiveness and forecast future production for these wells.
To achieve our objectives, we applied an analytical elliptical flow solution to analyze production data from hydraulically fractured vertical tight gas wells producing from multilayer reservoirs. We were able to estimate the fracture half-length, formation permeability, and minimum drainage area of each layer. This study considered variations in completion details, initial reservoir pressures, reservoir temperatures, and other reservoir parameters in layers producing simultaneously.
The technology we developed includes the following components used in our analysis: flow rate allocation using available production logging test data, deconvolution to convert variable-rate pressure data into constant-rate pressure responses, identification of the elliptical flow regime, and analysis of elliptical flow data. We developed and present a new technique to identify the elliptical flow regime. We validated our method with synthetic data generated with a reservoir simulator.
Facilities Design for Transport of Fluids with GRE Line Pipes – ISO 14692-3 Application –
Authors: Stupenengo Franco A. 
Published: February 2011

Abstract
GRE pipes have a distinct advantage in the transport of fluids, both liquids and gases, comparing with carbon steel pipes. This is mainly due to the lower surface roughness inside the pipes and higher corrosion resistance for most service conditions to which they may undergo in the oil and gas industry.
The systems design for the transport of fluids through GRE pipe is performed simultaneously responding to the three following basic requirements: a) hydraulic design, b) structural design; and, c) study of system vulnerabilities.
In this paper it has been introduced and explained the procedure described by ISO 14692-3, it has been also introduced a pipeline Case Study, for which it had been get two alternative products that fulfill the Case Study Hydraulic Design requirements and are submitted to the Structural Design. It is demonstrated that once analyzed them by the Structural Design, it has been detected the need to redefine the pre-selected products choosing a higher pressure rating.
Depositional Environments Being Investigated by the National Energy Technology Laboratory NETL for Potential Geologic Storage of CO2
Authors: Dressel Brian , Olsen David , Brown Bruce , Plasynski Sean , Litynksi John 
Published: February 2011

Abstract
A need exists for further research on carbon sequestration technologies to capture and store carbon dioxide (CO2) from stationary sources that would otherwise be emitted to the atmosphere. Carbon Capture and Storage (CCS) technologies have the potential to be a key technology for reducing CO2 emissions and mitigating global climate change.
Deploying these technologies on a commercial-scale will require geologic storage formations capable of (1) sequestering large volumes of CO2, (2) receiving CO2 at an efficient and economic rate of injection, and (3) retaining CO2 safely over extended periods. Eleven major types of depositional environments, each having their own unique opportunities and challenges, are being considered by the U.S. Department of Energy (DOE) for CO2 storage. These different classes of reservoirs include deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef. Basaltic interflow zones are also being considered as potential reservoirs.
DOE has recently completed a study which investigates the geology, geologic reservoir properties and confining units, and geologic depositional systems of potential reservoirs and how enhanced oil recovery and coal bed methane are currently utilizing CO2. It looks at the classes of geologic formations that have been identified as having the potential to be CO2 reservoirs, their distribution and potential storage volumes.
This study also discusses the efforts that DOE is supporting to characterize and test small and large scale injections of CO2 into these different classes of reservoirs. These tests are important to better understand the directional tendencies imposed by the depositional environment that may influence how fluids flow within these systems today, and how CO2 in geologic sequestration is anticipated to flow in the future. Although diagenesis has modified fluid flow paths during the intervening millions of years since they were deposited, the basic architectural framework created during deposition remains. Geologic processes that are working today also existed when the sediments were initially deposited. Analysis of modern day depositional analogs, evaluation of core samples, outcrops and well logs from ancient subsurface formations give an indication of how formations were deposited and how fluid flow within these formations is anticipated to flow.
Imaging Texture and Porosity in Mudstones and Shales: Comparison of Secondary and Ion-Milled Backscatter SEM Methods
Authors: Milner M. , McLin R. , Petriello J. 
Published: February 2011

Abstract
Observations from a number of unconventional reservoirs lead us to conclude that four major pore types exist in fine-grained reservoir and non-reservoir rocks, that they are effectively connected, and that pore sizes from nanometers to microns must be considered when evaluating size distributions. This paper uses SEM imaging of Haynesville, Horn River, Barnett and Marcellus Shales to illustrate that pore types other than those hosted by organics are present in unconventional shale gas reservoirs, and that they are continuous and connected to kerogen-hosted pores. In addition, we present evidence that the maximum size of pores originating in organic matter is determined by the size of the kerogen mass (in the case of organic particles) or the geometry of enclosing crystals (in the case of amorphous, pore-filling kerogen). Pairs of secondary and ion-milled backscatter SEM images address the misconception that large pores observed in secondary electron images are grain pullouts.
2-D image analysis and 3-D volumetric reconstructions to study pore distributions should take rock microtexture and the various pore types into consideration. A combined method using thin section textural analysis, XRD, and SEM imaging is recommended to address scaling issues when choosing samples for 2-D and 3-D volumetric analysis.
Effluent Metering and Liquid Gas Ratio Analysis
Authors: Conrad L. M. , Howell K. 
Published: February 2011

Abstract
Beginning in 2007, the Industry Measurement Group (IMG) undertook a two year initiative focused on creating technically based regulations that would allow for improved economics on low pressure, low liquid gas plays in Western Canada. The initiative was supported by the Canadian Association of Petroleum Producers (CAPP) and led to a joint CAPP/IMG review of Effluent metering applications and the associated testing requirements for gas wells set forth by the regulatory authorities in British Columbia and Alberta.
The Canadian Association of Petroleum Producers (CAPP) is the voice of Canada's upstream oil, oil sands and natural gas industry. CAPP represents companies that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP's member companies produce about 90 per cent of Canada's natural gas and crude oil.
The Industry Measurement Group (IMG) represents 100 members from upstream, transmission, provincial and federal organizations. IMG is recognized by CAPP as a formal voice for measurement related activities in the Western Canadian Oil and Gas Industry. The objectives of the IMG organization include the identification of common areas of concern relating to measurement and encouraging co-operation in establishing action plans, increasing awareness of measurement issues and fostering beneficial relationships. IMG also acts as a liaison between the industry and regulatory bodies in the development of industry accepted standards for measurement activities.
The examination of metering applications and testing requirements for gas wells in British Columbia and Alberta led to the conclusion by both industry and the regulator that there was merit in conducting a timely multi-jurisdictional review. The primary objectives of the joint CAPP/IMG review were two fold. Firstly, it brought all parties together to form a common framework for Effluent metering application and testing expectations, based on a risk and volumetric approach. Secondly, it supported an economical approach to the continued development of unconventional gas resource plays in Alberta and British Columbia, with a focus on well-site infrastructure and operational cost optimization.
This paper will provide the reader with insight into well testing requirements and the benefits of creating technically based, pragmatic regulations. The paper will also demonstrate how through the use of existing regulatory documentation, the CAPP/IMG project team was able to develop a new practical and pragmatic regulatory framework and policy for Effluent metering and well testing, which provides a common regulatory and industry approach across Alberta and British Columbia.
Automated Monitoring of a Hydraulic Fracture by Coalescence Microseismic Mapping
Authors: Woerpel J. Craig , Maxwell Shawn , Underhill Bill , Wolfe James 
Published: February 2011

Abstract
Coalescence microseismic mapping (CMM) is a method of hypocenter determination that does not require any human interaction during microseismic monitoring. Microseismic events can be detected, located and displayed on a laptop computer screen within seconds of their origin time. This paper describes both the method and results of a horizontal well case study in a tight gas reservoir.
A Simple Decline-Curve Analysis Approach for Evaluating Gas Reserves and Predicting Future Production in Gas Reservoirs
Authors: Bahadori A. , Vuthaluru H. B. 
Published: February 2011

Abstract
Decline curves are one of the most extensively used forms of data analysis employed in evaluating gas reserves and predicting future production. The parameters determined from the classical fit of historical data can be used to predict future production. The decline-curve analysis technique is based on the assumption that past production trends and their controlling factors will continue in the future and, therefore, can be extrapolated and described by a mathematical expression. In the present work, simple-to-use predictive tool, which is easier than existing approaches, less complicated with fewer calculations, is formulated to arrive at an appropriate estimation of nominal (initial) decline rate, and the Arps’ decline-curve exponent. The results can be used in follow-up calculations for analysis of past trends of decline in production performance i.e., rate versus time and rate versus cumulative production plots, for wells as well as reservoirs. The proposed simple-to-use approach can be of immense practical value for reservoir engineers and scientists to have a quick analysis on the production decline-curve of past trends of wells and reservoirs for wide range of conditions without the necessity of any field test measurements and/or trials. In particular, petroleum engineers would find the proposed approach to be user friendly involving transparent calculations with no complex expressions for their applications.
Systematic Team Approach Delivers Massive Performance Improvements in Shale Gas Play
Authors: Barton Steve , Lockley Russ , MacLeod Andrew M. , Pierce Garrett 
Published: February 2011

Abstract
The paper focuses on drill bit development for a specific natural shale gas play located within North America. These wells require advanced horizontal drilling techniques and extensive hydraulic fracturing to make them economically attractive. This paper details how a major operator has been able to make radical improvements in drilling performance in this area, leading to significant cost reductions.
A typical well consists of a vertical section, build section, and a final horizontal leg. When the operator started this project in 2008, the objective was to drill this entire main hole in just three bit runs; one for each directional leg described prior. In actuality, twelve to fourteen bits were utilized, averaging over forty days from drill-out to section TD. This made the economic viability of further development questionable.
A team approach enabled bit design modifications and improvements to be implemented in a controlled, continuous, and closely monitored program. A key component of this was the development of a unique flexible bit design developed specifically for directional applications in coordination with a leading supplier of motors. These bits contain novel features that allow rapid design modifications to be performed locally, significantly reducing response time, and allowing the program to proceed at a much faster pace than previously possible.
Within a matter of months, this systematic cooperative approach enabled the operator to achieve the initial objective of drilling the interval in 3 bit runs, but also their subsequent objective of drilling the interval in just two bit runs. Days to drill this section were drastically reduced from over forty to less than twelve days. The savings produced by this huge improvement in drilling performance has greatly assisted the economic viability of continued development in this basin.
Fast Track Reservoir Modeling of Shale Formations in the Appalachian Basin. Application to Lower Huron Shale in Eastern Kentucky.
Authors: Grujic O. , Mohaghegh S. D. , Bromhal G. 
Published: February 2011

Abstract
In this paper a fast track reservoir modeling and analysis of the Lower Huron Shale in Eastern Kentucky is presented. Unlike conventional reservoir simulation and modeling which is a bottom up approach (geo-cellular model to history matching) this new approach starts by attempting to build a reservoir realization from well production history (Top to Bottom), augmented by core, well-log, well-test and seismic data in order to increase accuracy. This approach requires creation of a large spatial-temporal database that is efficiently handled with state of the art Artificial Intelligence and Data Mining techniques (AI & DM), and therefore it represents an elegant integration of reservoir engineering techniques with Artificial Intelligence and Data Mining. Advantages of this new technique are a) ease of development, b) limited data requirement (as compared to reservoir simulation), and c) speed of analysis.
All of the 77 wells used in this study are completed in the Lower Huron Shale and are a part of the Big Sandy Gas field in Eastern Kentucky. Most of the wells have production profiles for more than twenty years. Porosity and thickness data was acquired from the available well logs, while permeability, natural fracture network properties, and fracture aperture data was acquired through a single well history matching process that uses the FRACGEN/NFFLOW simulator package.
This technology, known as Top-Down Intelligent Reservoir Modeling, starts with performing conventional reservoir engineering analysis on individual wells such as decline curve analysis and volumetric reserves estimation. Statistical techniques along with information generated from the reservoir engineering analysis contribute to an extensive spatio-temporal database of reservoir behavior. The database is used to develop a cohesive model of the field using fuzzy pattern recognition or similar techniques. The reservoir model is calibrated (history matched) with production history from the most recently drilled wells. The calibrated model is then further used for field development strategies to improve and enhance gas recovery.