bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design for HSE: Improving Equipment and Product Safety by Reducing Risk through the Integration of HSE into the Design Life Cycle
Authors: Jee V. J. , Kubala G.. , Mayes J. C. 
Published: June 2014

Abstract
Well site operations utilize many types of equipment which can involve health, safety and environment (HSE) aspects. Changes in equipment design in the industry have often been made in reaction to incidents or in reaction to changes in legislation and regulatory standards.
This reactive approach can reduce the safety margin of the equipment when engineering teams become focused on minimum standard compliance rather than overall safety. This can be an increasing concern where the equipment is new and novel as the speed of design changes may outpace changes in regulation, and there is less in-use experience on which to base the risk analysis. It can also increase overall cost if changes in design are made at later stages in development.
In order to move to a more proactive approach for HSE in engineering, an oilfield services company formally implemented a program to integrate HSE aspects into the equipment design cycle. The program not only considers the operational risk of the equipment but also considers the risks in the verification and testing phases, and during manufacturing. Key elements to this implementation are:HSE competency and training of engineers, designers and project managers.Documented standards and best practices that can foster intelligent reuse.Project management framework that guides development teams in identifying risk in all areas, including HSE.Integrating HSE personnel with design teams to understand the functional and business requirements and constraints.
Proactively introducing HSE requirements early, and continuously, during engineering projects can positively affect design, making the resulting equipment safer to use and reducing costs due to non-compliance and design re-work.
Application of Computers to the Interpretation of Well Logs
Authors: Tuman Vladimir S. , Bollman Dorothy 
Published: June 2014

Abstract
Available digital computers can be effectively used for the interpretation of well logs by the following procedure:digitizing the well log data,preparing the programs to process the data, andanalysis and evaluation of the results.
Types of available digitizing units are discussed. At present, the cost of digitization is greater than the cost of processing the same data by a computer. Consequently, further developments will be required to reduce the cost of getting the data in digital form.
An effort is made to indicate how to write a program for a digital computer, and a step-by-step example is worked out. Some examples processed on the computer for the formations in the Illinois basin are also included. Five programs prepared at the U. of Illinois are discussed. Detailed flow charts for four of these programs, including the "Discriminating Routine Program", are given. This program discriminates sands or porous beds from shales. It is the basic program for the automatic processing of the well logs which will control the over-all operation of the computer. It also can be used by geologists who are interested in sand/shale counts.
A rough economic study of the problem indicates that it will be advantageous to encourage service companies in the future to offer digitized well logs.

Introduction
High-speed computers are useful in handling two types of problems:a group of complex problems which have a very large number of operations; andone or more problems where there is a need for varying the parameters and, consequently, for repeating the operations a large number of times.
The thorough evaluation of well logs embraces both groups of problems.
Creating a Culture of Safety and Reliability in the Offshore World
Authors: Spigener Jim 
Published: June 2014

Abstract
Most organizations in the offshore oil industry have squeezed all of the performance they can get from traditional approaches to procedures, rules, and other administrative controls. Adding more programs to an already overtaxed workforce is not only undesirable and costly but can actually be detrimental to safety, environmental, and cost performance. Operators don’t need more things to do but a way to get more out of what they are already doing. Operational reliability and execution are the keys to effective performance. And this means developing a safety culture that engages people at all levels to fully commit to doing the right thing at the right time in the right way. This paper will discuss research findings that demonstrate how a strong safety culture leads to operational reliability and is the leading factor that sets the very best performers in offshore drilling apart from their counterparts.
Aeration and Microfiltration for Solids Removal of Produced Waters from the Barnett Shale
Authors: Palmgren Tor H. , Fajt James R. , Danilov Alexander G. , Burnett David B. 
Published: June 2014

Abstract
Suspended solids are typically removed by mechanical and or chemical methods. Microfiltration commonly requires some treatment to remove large particles, and oil and organics that can affect filter production rates. The extent of total water treatment required depends on quality of the raw water and the disposition of the treated water. Total suspended solids (TSS) removal may often be sufficient treatment to meet a given target and satisfy key chemical performance criteria for water re-use for the formulation of hydraulic fluids.
This study explored the use of aeration and settling to reduce iron content of produced water prior to filtration with a 10-µm bag filter and with hollow fiber, stainless steel and ceramic filters of submicron porosity. It was determined that aeration with compressed air for sufficient time to oxidize the iron was an effective treatment to convert ionic iron to particulate iron oxide in a produced water sampled from an unconventional gas well in the Barnett Shale near Dallas in Arlington TX.
The 10-µm bag filtration proved inadequate for achieving any significant reduction of turbidity, particle count or iron reduction. However, the filters rated to remove particles smaller than one micron proved useful. A comparison of different submicron-rated filters, comprising hollow fiber, stainless steel and ceramic membranes, all capable of removing particles greater than 1 µm when used in the treatment of mixed aerated water and settled aerated water, showed no major difference in their gross performance of TSS reduction or their ability to remove iron oxide particles. All the submicron filters reduced the water turbidity and particle count by more than 90% and reduced total iron to a concentration that was below detection limit.
Addressing Well and Field Infrastructure Siting Challenges in the Wetlands and Streams of the Haynesville, Marcellus, Utica, and Eagle Ford Shale Plays
Authors: Krauss Russell F 
Published: June 2014

Abstract
As U.S. shale play activities move from appraisal to production phase, it is increasingly difficult for surface operations to avoid impacts to environmentally sensitive wetlands and streams. Many shale plays are located in areas more visible to the general public than ever before in the history of domestic onshore oil and gas field development. Shale play development for oil, natural gas and natural gas liquids, has therefore resulted in increased scrutiny by agencies causing successful operators to be more proactive in the siting of wells and associated field infrastructure including access roads, flowlines, and gathering systems. Complex regulatory regimes must be navigated by producers and operators in each shale play and, although operating under standardized Federal regulations, are required to address the preferences of each regulatory agency, and in many cases, individual regulators themselves.
Working under new rules since 2008, regulatory agencies require offsets for unavoidable impacts to wetlands and streams to occur in the watershed where the impacts will occur. With limited mitigation acreage available in areas where surface rights are locked up by landowners and operators, and the increased visibility of environmental risk and liability from field operations, the need for proactive, creative wetland and stream mitigation solutions is self-evident.
In the Pennsylvania Marcellus Shale, streams need to be crossed every 2,000 feet, often needing both a state and Federal permit. In the Louisiana Haynesvlle Shale, every fifth well pad typically requires a permit under Section 404 of the Clean Water Act. In the Eagle Ford shale, what is now an access road was once a dry streambed, which potentially should have been permitted, if indeed it was not.
A multitude of functional assessment methodologies are employed by regulatory agencies to assess project-related impacts on habitat functions and values. Even within a single shale play, these methods abound. Only through proactive understanding of complex regulatory regimes in each shale play can operators, producers and infrastructure providers plan for solutions early in their project life cycle, to eliminate operational risk and control their own destiny with regard to managing risk and operational liability in these environmentally sensitive areas.
Unique System for Managing Data From Oil and Gas Operations
Authors: Veil J. A. , Jehn P. , Fine M. J. , Griffith B. G. 
Published: June 2014

Abstract
State agencies have the primary responsibility for overseeing and regulating oil and gas operations. Those operations generate a large amount of data. Managing the data in an effective and coordinated way presents challenges to federal, state, and local agencies and to other interested users. In 1992, the U.S. Department of Energy (DOE) provided initial funding to the Ground Water Protection Council (GWPC), a national association of state agencies, to develop the Risk Based Data Management System (RBDMS), a family of software applications that allows management of data associated with oil and gas operations. The RBDMS software is used for a variety of purposes including: managing operator and bonding information; the permitting processes; tracking well locations and construction details; tracking production data; assessing the impacts of injection wells on underground sources of drinking water; and tracking inspections, compliance, and other enforcement activities. Since its inception, RBDMS has relied on a combination of DOE’s financial support and matching funds and feedback from the 21 states that use the system to keep it updated and to incorporate new features. RBDMS has recently added a variety of new features that are discussed in the full paper. The paper and presentation will show many of the features and capabilities of RBDMS that can be useful to oil and gas companies, researchers, and other interested persons.
Prediction of Stimulated Reservoir Volume and Optimization of Fracturing in Tight Gas and Shale With a Fully Elasto-Plastic Coupled Geomechanical Model
Authors: Nassir M.. , Settari A.. , Wan R.. 
Published: June 2014

Summary
Hydraulic fracturing is essential for the economic development of tight gas reservoirs and shale-gas reservoirs. Current techniques are unable to predict the stimulated-reservoir-volume (SRV) dependence on fracturing-job and rock-mechanics parameters, which precludes any meaningful optimization. In the authors' previous work on the SRV-propagation prediction, the combined tensile/shear fracturing model applied to the fracturing of tight gas formations has shown the creation of a relatively narrow, focused SRV that resembled behavior dominated by a single fracture. In this work, the model has been significantly improved by the implementation of a rigorous full Newton elasto-plastic solution of the geomechanics of rock containing induced fractures. The results reveal interesting features of complex-fracture propagation in tight formations, which are in broad agreement with the shapes of SRVs obtained from microseismic imaging.
The developed code is flexible enough to allow either tensile or shear fracturing or the occurrence of both to be examined on the basis of initial reservoir conditions. Different cases of 2D and 3D simulations will be presented that demonstrate some important features of the process. First, it is found that a wide SRV can result in cases in which initial reservoir conditions are close to the shear-fracturing point, such as in formations with microfractures, partially cemented natural fractures, and abnormally high initial pore pressure. Second, the SRV width is found to depend on the horizontal stress contrast, as expected. Third, wide SRV growth is associated with constant or increasing pumping pressure necessary for further failed-zone growth as a result of the loss of elastic coupling by off-planar failure propagation. Further, under high injection pressure, an efficient fracture elasto-plastic constitutive model developed can drive both maximal and minimal effective stresses to zero or tensile, and, therefore, the creation of tensile fracturing can be predicted simultaneously with shear fracturing. This will then provide a means of modeling proppant transport. The new model is a significant step toward the development of an integrated predictive tool for the optimization of shale-gas development.
Evolution of Drilling and Completions in the Slave Point To Optimize Economics
Authors: Lerner Nolan , Schaab Brent , Garcia Juan , Bianco Dan , Thomas Scott , Thompson Jason , Hollan Jeremy 
Published: June 2014

Summary
This paper will detail the technological evolution of drilling and completion practices used to optimize the economic development of the Slave Point carbonate platform, specifically in the Evi and Otter fields in northern Alberta, Canada. The Slave Point platform was initially targeted for conventional production by means of vertical wells in the early 1980s. Success was marginal because of the unpredictability of localized porosity development. As a result, the full-scale commercial development of this resource was deemed uneconomic because of poor reservoir quality. More recently, however, horizontal-drilling and multistage-fracturing technology has allowed operators to open up lower-porosity horizons to improve flow capacity, to improve recoveries, and to allow for commercial development from zones previously deemed uneconomic.
The Slave Point has a greater thickness and is less permeable than other tight-rock plays in Alberta, such as the Cardium and Viking. It produces high-quality, light oil with low water- and solution-gas-production rates. Despite high estimates of original oil in place (OIP) of approximately 3 to 10 million bbl per section, horizontal-well rates are still challenged because of the lower permeability through the pay section. In this regard, the continued deployment of innovation and technology has been critical in improving well-production performance, compressing project costs, and ultimately optimizing project economics.
The focus of this paper is solely on one of the major Slave Point operators who has drilled 49 horizontal wells that account for 200 000 m (656,000 ft) drilled and 1,350 fracture stages in the Evi and Otter Slave Point fields since 2008. This operator has continually deployed advancing technologies to improve project economics. The information will be presented in terms of the influence of technology on well design, the optimization and deployment of the various technologies, and the demonstrated improvement on productivity and reserves recovery. The discussion will focus on three development phases that highlight the progression from vertical to horizontal technology:
Vertical Appraisal Single-Lateral (SL) Development Dual-Lateral (DL) Development
The case studies presented will demonstrate clearly the production impact from the use and application of these technologies. The methods and lessons learned through the use of DLs, openhole junctures, and openhole multistage systems can be applied to other unconventional formations.
Enhanced Jetting Tool Integrated with Sand/Well Vacuuming Technology Optimizes Cleaning and Stimulation for Heavy-Oil Wells
Authors: Duque E. D. , Diaz J. D. , Pineda R. , Marin C. , Núñez M. 
Published: June 2014

Abstract
The Orinoco Oil Belt (OOB) is located in the southern strip of the eastern Orinoco River basin in Venezuela, with a total area of 55,314 km2. This formation represents the largest heavy-oil reserves from unconsolidated sandstones in the world. Unfortunately, sand production is a common problem associated with this type of formation. In addition, it is very challenging to successfully remove solids and stimulate large, highly deviated wells with low bottomhole pressures.
Since 1999, a technology combining concentric coiled tubing (CCT) with a jet pump has been used in the OOB to remove solids and fluids (stimulation treatments, drilling fluids, etc.) from the wellbore. Due to the characteristics of these heavy-oil wells, with their unconsolidated sands and highly deviated well paths, sand/well vacuuming technology (SWVT) has become the main alternative for intervention operations such as sand cleanouts, stimulations, drilling fluid removal, and any kind of job requiring the use of coiled tubing.
Conventional SWVT permits changing the configuration of the tool into two modes: sand vacuuming for solids removal, and well vacuuming for fluids recovery. During SWVT operations, two main scenarios exists where it is necessary to change the bottomhole assembly (BHA) used with SWVT for a regular BHA with enhanced jetting, thereby requiring extra runs to finish the jobs.Breaking through hard bridges formed by sand and oil or by solid materials as elastomers from progressive cavity pumps.Pumping down chemical stimulations treatments.
To overcome the issues resulting from cleaning and increasing efficiency with stimulations jobs in a single run (avoiding extra running of different BHAs), an improved SWVT with a jetting switch has been developed, incorporating a third mode: high jetting. In this mode the SWVT BHA can handle higher fluid rates and achieve the necessary impact pressure to break solids bridges or to perform stimulations jobs efficiently. This paper discusses the implementation of this tool in the OOB and explains the results in terms of efficiency increase and best practices for this type of intervention.
The Use of Inhibition Kinetics and NMR Spectroscopy in Thermal Stability Study of Scale Inhibitors
Authors: Wang Wei , Kan Amy T. , Yan Chao , Tomson Mason B. 
Published: June 2014

Abstract
As the oil and gas industry is making firm stride in deepwater exploration and development, possible thermal degradation of scale inhibitor molecules poses a great challenge for scaling control and flow assurance for high temperature reservoirs. Although extensive research has been conducted to test thermal stability of scale inhibitors, little work has been devoted to study the thermodynamics/kinetics of thermal degradation of scale inhibitors. In this work a novel and efficient testing approach based on inhibition kinetics has been developed and successfully applied to determine the fraction of the initial inhibitor molecules in preheated samples of scale inhibitors with various generic chemistries. Moreover, for the first time, we have modeled the kinetics of inhibitor thermal degradation based on the integrated first-order rate equation and Arrhenius equation, with good agreements between the model predictions and experimental data. The preheated scale inhibitors have been analyzed by nuclear magnetic resonance (NMR) spectroscopy for organic compound characterization. Our results and predictions based on inhibition testing assay are consistent with the 31P/1H NMR analyses. This work has enabled an in-depth understanding of the time and temperature dependence of thermal degradation of scale inhibitors, and facilitates the rational selection and deployment of scale inhibitors for high temperature oil and gas production.
Measurement and Prediction of Thermal Degradation of Scale Inhibitors
Authors: Wang Wei , Kan Amy T. , Zhang Fangfu , Yan Chao , Tomson Mason B. 
Published: June 2014

Summary
As the oil and gas industry is making firm strides in deepwater and shale exploration and development, possible thermal degradation of scale-inhibitor molecules poses a great challenge for scaling control and flow assurance for high-temperature reservoirs. Although extensive research has been conducted to test thermal stability of scale inhibitors, little work has been devoted to study the thermodynamics/kinetics of thermal degradation of scale inhibitors. In this work, a novel and efficient testing approach based on inhibition kinetics has been developed and successfully applied to determine the fraction of the active inhibitor molecules in preheated samples of scale inhibitors with various generic chemistries. Moreover, for the first time, we have modeled the kinetics of inhibitor thermal degradation on the basis of the integrated first-order rate equation and Arrhenius equation, with good agreements between the model predictions and experimental data. The preheated scale inhibitors have been analyzed by nuclear-magnetic-resonance (NMR) spectroscopy for organic-compound characterization. Our results and predictions based on inhibition testing assay are consistent with the 31P/1H NMR analyses. This work has enabled an in-depth understanding of the time and temperature dependence of thermal degradation of scale inhibitors, and facilitates the rational selection and deployment of scale inhibitors for high-temperature oil and gas production.
Novel Scale Remediation for Steam Assisted Gravity Drainage (SAGD) Operations
Authors: Cheung Timothy , Scheck Michael 
Published: June 2014

Abstract
Shell runs a Steam Assisted Gravity Drainage (SAGD) operation at the Orion field in Alberta, Canada. Pressure drops during bitumen and water recovery can lead to precipitation and buildup of scales which can plug up well equipment and lead to an increase in differential pressure and lower production. Early attempts to remove such blockages with high pressure steam or salinity-altering brine injections resulted in transient returns to normal operations but with diminishing returns. Acid treatments to dissolve the scale encountered problems with corrosion and an inability to handle the discovery of the presence of acid insoluble scales. Alterations to the operating conditions such as pH along with the addition of a chelating agent, EDTA, were successful in treating both types of scales. As a result, differential pressures and steam to oil ratios decreased while oil production grew. This treatment was extremely cost-effective and payout was on the order of a few days.