bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cost-Effective Ultralarge-Diameter Polycrystalline-Diamond-Compact-Bit Drilling in Deepwater Gulf of Mexico
Authors: D'Ambrosio Piero , Hart Sofiri , Prochaska Ernest , Bouska Reisha , Tinsley Douglas 
Published: June 2014

Summary
Ultralarge-diameter polycrystalline-diamond-compact (PDC)-bit drilling is a fast-growing cost-effective solution in high-tier deepwater drilling operations in the US Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller-cone (RC) (IADC Code 111-115) drill bits on positive-displacement motors (PDMs) in these ultralarge-diameter intervals. Cost savings on drilling fluid alone, in the form of rate-of-penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on rotary-steerable-system (RSS) drilling assemblies.
New robust high-torque-capacity topdrives, stronger drillpipe (DP) connections, larger-diameter RSS tools, and improved mud programs have all largely contributed to this step change in drilling performance. In addition, evolved bit and bottomhole-assembly (BHA) design, efficient operating parameters, improved hydraulics, and vibration-prediction modeling have all aided in the success of these runs.
Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to, BHA steerability, rig-equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling-fluid displacement, DP torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others.
This paper will concentrate on the multiple aspects of ultralarge-diameter riserless PDC-bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower-cost-per-foot approach through the potential reduction of drilling time in these challenging applications.
Managed Pressure Drilling Experience on deepwater application in West Africa
Authors: Sammat E. , Pavesi R. , Besenzoni L. , Copercini P. 
Published: June 2014

Abstract
Since hydrocarbon reserves located in benign environments are more difficult to find, the oil and gas industry has been forced to gravitate toward more complex and challenging accumulations. The difficulties faced therein often increase non-productive time (NPT), costs and risk. The deep water offshore West Africa exemplifies this scenario, requiring new and innovative ways to economically locate and exploit smaller reserves. Managed pressure drilling (MPD), despite being a relatively new technology, has been progressively proven as one that can significantly change the way wells are drilled—not only reducing NPT but also enabling access to reserves in areas previously considered undrillable while reducing the associated risks.
The high cost of offshore drilling means that offshore MPD delivers significant savings when NPT associated with fluid losses or a well control event are eliminated. Drawing from past successful experience where the circulating device and MPD system were used on a high-pressure/high-temperature (HPHT) well enabled reaching all the well targets, it was decided to use this combination of technologies to drill this challenging well.
This paper discusses the application of the combination of the circulating device and MPD system on a deepwater well in Ghana, West Africa. This MPD technique was used from the start—drilling the 14-3/4 in. section to the end of drilling a 8-1/2 in. section on deepwater application in West Africa. One of the main benefits of using this MPD technique was to control the bottomhole pressure drilling through inherently unstable zone. This helped drilling to target depth while effectively handling influxes with significant time savings. The planning, development and execution phases of the MPD project are detailed in this technical paper.
The Use of Sidewall Core Analysis in Formation Evaluation
Authors: Koepf E.H. , Granberry R.J. 
Published: June 2014

Abstract
Analytical techniques and procedures which permit accurate measurement of important physical properties and of fluid content of sidewall core samples as received in the laboratory are available. However, hole conditions prior to and during sampling affect the values as measured on the core samples. Also, the impact of the percussion sampler in the sampling process alters some of the physical characteristics of the sample. Comparisons of data on conventional and sidewall core samples and experience have shown the general direction of these effects. Normally, formations along the Gulf Coast have a greater productive capacity than the sidewall core sample data indicate. Water saturations associated with gas, condensate or oil production are greater in sidewall than in conventional core samples. Sidewall core data are valuable as exploratory aids, but data from conventional or wireline cores are generally required for evaluating recoverable reserves, the distribution of reservoir fluids and formation flow characteristics.
Sidewall core data usually establish the presence or absence of hydrocarbon content and indicate the probable type of production. Measured permeability and porosity values indicate productive capacity. The data show gas-oil and water-oil contacts. Sidewall sample data are particularly valuable as a basis for "calibrating" electrical log data. They are used to check lithology changes indicated by log data, and they permit evaluation of thin and stray sands. Sidewall core samples probably provide the most reliable data normally obtained on "dirty" or ashy sand zones which show low resistivity on the electrical logs, on sand sections drilled with high-salt-content muds and on shallow bentonitic sands containing fresh water. Consideration of both sidewall core analysis data and electrical log data together increases the value of each. In many instances, it is necessary to consider both types of data in arriving at a correct interpretation. Greatest value can be obtained from the sidewall core data if the analyst has an electrical log of the zone as a guide for general formation characteristics and for zoning the various samples.
Experience from Hardware-In-the-Loop Testing of Drilling Control Systems
Authors: Pedersen Tom , Smogeli Øyvind 
Published: June 2014

Abstract
Modem Drilling ships and rigs have advanced computer systems for dynamic positioning, power generation and distribution, and Drilling operations. It is well known that software errors may lead to delays and non-productive time, and compromise safety. While the testing and verification regime for structures and machinery systems is well established, most of the computer systems on today's Drilling vessels are put into operation without independent testing and verification. Hardware-In-the-Loop (HIL) testing is a well proven test methodology from several other industries. It facilitates systematic testing of control system design philosophy, functionality, performance, and failure handling capability, both in normal and off-design operating conditions, and is conducted in a virtual test-bed where there is no risk to man, vessel, or equipment. Automatic Drilling systems which rely on software to function properly often consist of a combination of components delivered by several suppliers. This means that also control system software from several suppliers must run and work together as an integrated system in order to maintain safety and achieve the desired operational performance. Marine Cybernetics has finalized testing of Drill floor control systems for 7 rigs, involving 9 different vendors. This paper presents experiences from these projects in terms of project execution, test timing and vendor cooperation and participation. Examples of typical observations are also presented.
Experience From Hardware-in-the-Loop Testing of Drilling Control Systems
Authors: Pedersen Tom , Smogeli Øyvind 
Published: June 2014

Summary
Modern drilling ships and rigs are equipped with advanced computer systems for dynamic positioning, power generation and distribution, and drilling operations. It is well-known that software errors may lead to delays and nonproductive time and may compromise safety. Although the testing and verification regime for structures and machinery systems is well-established, most of the computer systems on today's drilling vessels are put into operation without independent testing and verification.
Hardware-in-the-loop (HIL) testing is a test methodology used in several other industries. It facilitates the systematic testing of control-system design philosophy, functionality, performance, and failure-handling capability, in both normal and off-design operating conditions, and is conducted in a virtual test bed in which there is no risk to personnel, vessel, or equipment.
Automatic drilling systems that rely on software to function properly often consist of a combination of components delivered by several suppliers. This means that, to maintain safety and to achieve the desired operational performance, control-system software from several suppliers must also run and work together as an integrated system.
Marine Cybernetics has finalized the testing of drill-floor control systems for seven rigs, involving nine different vendors. This paper presents experiences from these projects in terms of project execution, test timing, and vendor cooperation and participation. Examples of typical observations are also presented.
The Stability of a Pipe Stand Racked in a Derrick, Part 2—A General Pipe-Stand Model
Authors: Sawaryn S.J.. J. , Pattillo P.D.. D. 
Published: June 2014

Summary
This paper builds on the information contained in Part 1 (the body of the paper preceding the appendices) and presents a general pipe-stand model. The model is based on the Fourier-series solution of the energy equation for calculating the deflection and buckling condition of an inclined, nonuniform pipe stand with an arbitrary number of intermediate loads and stick-up above the top racking board. Full details of the derivation and algorithms are included in the paper. This flexible approach is used to examine more-complex, practical situations that include the buckling sensitivity to the position of the upper support and added loads such as tool joints or running tools racked with the stand.
Using a Fourier-sine-series solution avoids dealing with the less familiar higher-order functions encountered in Part 1, so the algorithms can be coded with standard spreadsheet functions. This approach also increases the model's capability and practical worth, providing a tool suitable for field use. The results for loaded, uniform stands compare within 0.01% with the limiting cases represented by the analytical solutions presented in Part 1. Nonuniformity of the stand can add significantly to the number of series terms required.
Several practical examples are used to illustrate the model's application, including the analysis of the stand with a heavy intermediate load where buckling occurred. The model successfully distinguishes between the buckled and nonbuckled conditions.
Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood
Authors: Tavassoli Shayan , Lu Jun , Pope Gary A. , Sepehrnoori Kamy 
Published: June 2014

SummaryClassical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world's largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.
Generalized Field-Development Optimization With Derivative-Free Procedures
Authors: Isebor Obiajulu J. , Ciaurri David Echeverría , Durlofsky Louis J. 
Published: June 2014

Summary
The optimization of general oilfield development problems is considered. Techniques are presented to simultaneously determine the optimal number and type of new wells, the sequence in which they should be drilled, and their corresponding locations and (time-varying) controls. The optimization is posed as a mixed-integer nonlinear programming (MINLP) problem and involves categorical, integer-valued, and real-valued variables. The formulation handles bound, linear, and nonlinear constraints, with the latter treated with filter-based techniques. Noninvasive derivative-free approaches are applied for the optimizations. Methods considered include branch and bound (B&B), a rigorous global-search procedure that requires the relaxation of the categorical variables; mesh adaptive direct search (MADS), a local pattern-search method; particle swarm optimization (PSO), a heuristic global-search method; and a PSO-MADS hybrid. Four example cases involving channelized-reservoir models are presented. The recently developed PSO-MADS hybrid is shown to consistently outperform the standalone MADS and PSO procedures. In the two cases in which B&B is applied, the heuristic PSO-MADS approach is shown to give comparable solutions but at a much lower computational cost. This is significant because B&B provides a systematic search in the categorical variables. We conclude that, although it is demanding in terms of computation, the methodology presented here, with PSO-MADS as the core optimization method, appears to be applicable for realistic reservoir development and management.
Estimation of Mutual Information and Conditional Entropy for Surveillance Optimization
Authors: Le Duc H. , Reynolds Albert C. 
Published: June 2014

Summary
Given a suite of potential surveillance operations, we define surveillance optimization as the problem of choosing the operation that gives the minimum expected value of P90 minus P10 (i.e., P90 – P10) of a specified reservoir variable J (e.g., cumulative oil production) that will be obtained by conditioning J to the observed data. Two questions can be posed: (1) Which surveillance operation is expected to provide the greatest uncertainty reduction in J? and (2) What is the expected value of the reduction in uncertainty that would be achieved if we were to undertake each surveillance operation to collect the associated data and then history match the data obtained? In this work, we extend and apply a conceptual idea that we recently proposed for surveillance optimization to 2D and 3D waterflooding problems. Our method is based on information theory in which the mutual information between J and the random observed data vector Dobs is estimated by use of an ensemble of prior reservoir models. This mutual information reflects the strength of the relationship between J and the potential observed data and provides a qualitative answer to Question 1. Question 2 is answered by calculating the conditional entropy of J to generate an approximation of the expected value of the reduction in (P90 – P10) of J. The reliability of our method depends on obtaining a good estimate of the mutual information. We consider several ways to estimate the mutual information and suggest how a good estimate can be chosen. We validate the results of our proposed method with an exhaustive history-matching procedure.
The methodology provides an approximate way to decide the data that should be collected to maximize the uncertainty reduction in a specified reservoir variable and to estimate the reduction in uncertainty that could be obtained. We expect this paper will stimulate significant research on the application of information theory and lead to practical methods and workflows for surveillance optimization.
The Multiscale Finite-Volume Method on Stratigraphic Grids
Authors: Møyner Olav , Lie Knut-Andreas 
Published: June 2014

Summary
Finding a pressure solution for large and highly detailed reservoir models with fine-scale heterogeneities modeled on a meter scale is computationally demanding. One way of making such simulations less compute-intensive is to use multiscale methods that solve coarsened flow problems by use of a set of reusable basis functions to capture flow effects induced by local geological variations. One such method, the multiscale finite-volume (MsFV) method, is well-studied for 2D Cartesian grids but has not been implemented for stratigraphic and unstructured grids with faults in three dimensions. We present an open-source implementation of the MsFV method in three dimensions along with a coarse partitioning algorithm that can handle stratigraphic grids with faults and wells. The resulting solver is an alternative to traditional upscaling methods, but can also be used for accelerating fine-scale simulations. To achieve better precision, the implementation can use the MsFV method as a preconditioner for Arnoldi iterations using the generalized minimal residual (GMRES) method or as a preconditioner in combination with a standard inexpensive smoother.
We conduct a series of numerical experiments in which approximate solutions computed by the new MsFV solver are compared with fine-scale solutions computed by a standard two-point scheme for grids with realistic permeabilities and geometries. On the one hand, the results show that the MsFV method can produce accurate approximations for geological models with pinchouts, faults, and nonneighboring connections, but on the other hand, they also show that the method can fail quite spectacularly for highly heterogeneous and anisotropic systems in a way that cannot efficiently be mitigated by iterative approaches. Thus, the MsFV method is, in our opinion, not yet sufficiently robust to be applied as a black-box solver for models with industry-standard complexity. However, extending the method to realistic grids is an important step on the way toward a fast and accurate multiscale solution of large-scale reservoir models. In particular, our open-source implementation provides an efficient framework suitable for further experimentation with partitioning algorithms and MsFV variants.
Assessing the Potential Impact on Extractive Industries of IFC's Revised Social Standards
Authors: Wasserstrom Robert , Gerrits Robert 
Published: June 2014

Abstract
The International Finance Corporation (IFC) adopted its Policy on Environmental and Social Sustainability and Performance Standards in April, 2006. These standards are aimed at encouraging better management of environmental and social risk in major capital investments. They are often used as de facto benchmarks or regulatory guidelines in oil, gas and mining projects, even where IFC is not directly involved. The eight Performance Standards cover key operational areas: environmental and social management systems, including risk assessment and evaluation (PS1); labor and working conditions (PS2); resource efficiency and pollution prevention (PS3), community health, safety and security (PS4); land acquisition and involuntary resettlement (PS5); biodiversity conservation and sustainable management of living natural resources (PS6); indigenous people (PS7); and cultural heritage (PS8). In January, 2012, IFC issued revised standards based on three years’ experience with them.
This paper focuses on IFC’s revised social performance standards (PS 1, PS5 and PS7, with reference to others) and analyzes their potential impacts on the oil, gas and mining industries. These standards introduce broad-based concepts that will require many companies to modify their existing development strategies. Such concepts include a defined hierarchy of stakeholder engagement; access to natural resources as a potential impact on land acquisition and resettlement; the importance of ecosystem services to human communities; and "Free, Prior and Informed Consent" during project development (FPIC). For each social standard, we focus on (a) new requirements or significant modifications of existing requirements; (b) expected pathways for implementation; (c) desired outcomes; and finally, (d) how compliance with new requirements might be assessed.
Potential implications for extractive industries are significant because new requirements are likely to increase the complexity of social risk assessment and management – for example, by providing broadly expanded access to communities, ethnic minorities, local leaders and NGOs. In turn, increased complexity often translates into greater uncertainty and extended timelines for project design and implementation. In an era of growing resource nationalism, global advocacy and more empowered stakeholders, the consequences of uncertainty – and the need for better management systems – will fall heavily on private companies. This paper will outline broad strategies to meet such challenges.