bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lean Semi - A Competitive Floating Solution
Authors: Bruun P. K. , Rikheim T. , Laukeland L. , Bjørk K. 
Published: April 2018

Abstract
A low oil price challenges the Operator's field economy for development of deepwater marginal fields. Using typical development solutions proposed in the past 10 years regime with high oil price such developments may not be economically viable to develop, therefore operators call for cost-effective solutions that enables development with today's oil price.
In response to this request a production floater for development of marginal fields has been developed. Equipment vendors were involved in the design process to ensure use of their preferred standard solutions. The target was a processing capacity of 60 000 barrels of liquids with a requirement of a not to exceed topside weight of 6000 tonnes arranged on one deck level. This weight was used in sizing the hull giving the topside designers an early layout area limitation. Conventional proven solutions were used as platform building blocks. The standard Aker un-manned hull (Blind Faith) and a flat top deck with wet truss (Njord A) were combined to form the basis for the topside design using skid-based low weight modules with standardized equipment. A process on removing "nice to have" and heritage from other projects gave a strict project design focus for the equipment selection needed to fulfill safety and functional requirements.
The standard Aker un-manned hull with a flat top deck is used in the design considering 100 to 400m water depth. Typical North Sea functionality and redundancy requirements have been challenged using conventional standardized low weight equipment modules with a campaign based maintenance and repair philosophy. The concept has its base as a product to be used for fields with characteristics in proximity of the proposed design basis, hence, the Operator will have a platform which offers a low CAPEX and OPEX cost compared to a tailor made solution, but with some limitation as compared to a tailor made solution. The design process resulted in a concept with 60 000 barrels of liquids capacity having a topside operating weight of 6000 tonnes designed according to Norsok safety requirements. When comparing to a traditional North Sea platform with similar production capacity 30% weight reduction of the topside was achieved. The cost estimate performed, including the vendor equipment cost, show a further cost reduction. The product type combined with such lean design process inspired the name for the product; the Lean Semi.
The study method represents a different method to do concept studies where the topside weight is constrained and focus is on designing for a highest possible production capacity given this limit. The paper presents this process and the resulting design.
HPHT Technology Development & Approval: Verification and Validation in the Context of the BSEE Regulatory Process
Authors: Kusinski Greg J. , Vaclavik Matt , Hansen Paul , Fury Sandi 
Published: April 2018

Abstract
The engineering, design, qualification, and implementation of drilling, completion, production, and intervention equipment for high-pressure/high-temperature (HPHT) developments is currently underway to enable next frontier of projects in the Gulf of Mexico (GoM). As HPHT technology is being developed, it is prudent to recognize that such a technology is only "of value" when it can be used and deployed, hence, create a utility. This is enabled through a robust qualification, verification and regulatory approval.
Per the Code of Federal Regulations, the Bureau of Safety and Environmental Enforcement (BSEE) regulates the oil and gas, exploration, development, and production operations on the Outer Continental Shelf (OCS). BSEE has a set of well-established regulatory processes to facilitate approval of OCS major capital projects. For example, through the Deepwater Operations Plan (DWOP) BSEE grants approvals to Operators for site specific named OCS projects. Through this process, per 30 CFR 250.804, prior to equipment installation in an HPHT environment, an operator must submit detailed reports, to demonstrate that the equipment can perform in the applicable HPHT environment.
Unlike historical OCS projects with pressures less than 15,000 psi and temperatures less than 350°F where subsea production equipment is governed by codes and standards referenced in 30 CFR 250.804(b), equipment required for well completion or well control in HPHT environments in most instances exceeds the ratings prescribed in these historical codes and standards. This paper discusses the requirements set forth by BSEE for Independent Third-Party (I3P) verification of HPHT equipment fitness for service as well as the distinction between 1) BSEE Acceptance of Verification of Equipment Technical Specifications and 2) BSEE Approval of the use of HPHT Equipment that meet or exceed Project Specific Functional Specifications. The necessary steps that must take place to achieve first oil for frontier project are discussed from the perspective of technical readiness. Other decision criteria are out of the scope of this paper. This paper discusses aspects of technology assessment, development, qualification, independent verification, steps that lead to technology acceptance and BSEE project approval.to
Artificial Intelligence: Steps to Transforming Offshore E&P for Vastly Improved Business Outcomes
Authors: Gruss Alec 
Published: April 2018

Abstract
This paper provides non-technical decision-makers in the offshore E&P industry with an overview of artificial intelligence and machine learning applications relevant to optimizing platform operations. It describes the benefits of using these applications to tap a platform's most underutilized asset — its data troves — using these applications to enhance decision support and drive better business outcomes, even new business models. Examples and use-case scenarios are provided, along with a step-wise approach for implementing the applications to unlock business value.
DeepStar Advanced Materials Program for Offshore HPHT Development
Authors: Gomes Joseph , Shamshy Shakir 
Published: April 2018

Abstract
DeepStar is a member funded industry technology development program focused on advancing technologies to meet its members’ global offshore business needs in collaboration with oil companies, technology vendors, service providers, and academic/research institutes.
This paper outlines DeepStar's strategies related to its holistic approach to technology development and the current and previous projects the program has completed related to High Pressure High Temperature (HPHT). Within this paper, four technical projects will be highlighted summarizing the technology development lifecycle that was developed within our program that incorporates a systematic approach to the development of HPHT equipment. Starting with Standardized Material Selection Basis of Design(MSBOD) and Equipment Testing Guidelines Criteria, follow by 20 ksi Systems Verification which reviews the API 17 TR8 standard. Follow by qualification testing of ultra-deepwater 20 ksi Composite Tubular, and completing this paper by highlighting work on 20 ksi Systems Validation testing reviewing API 17 TR8 standard on simple, moderate and complex geometry components.
Our CORE membership including over 20 organizations including international oil and gas companies, technology developers, service companies, EPC companies, and academic universities whom employ hundreds of thousands of people and operating in all of the world's deepwater and ultra-deepwater basins. Our members provide the guidance of the technical program to ensure that the program is focused on the right technical challenges and leveraged to produce meaningful and value-added results.
While the manufacturing and service sector members compete fiercely, the projects completed by our program are considered non-competitive area between the operators and our other members, thus a suitable space for collaboration. This includes projects which are critical to support reliable and safe operations in which solving a problem for one deepwater operator can be integrated into the entire offshore industry. As such, the program provides an outstanding opportunity for Subject Matter Experts (SMEs) to collaborate and foster the exchange of ideas and potential solutions. For more information on DeepStar program, please visit www.theDeepStar.com.
Design and Qualification of a 20,000 psi Rated Annulus Seal Assembly
Authors: Tooley Keegan , Phillips Ryan , Bingham Fred , Garrett Timothy , Rodriguez F. Justin 
Published: April 2018

Abstract
The HPHT Metal-to-Metal Annulus Seal Assembly provides an all metal gas tight seal for the annulus between the 18 3/4″ wellhead housing and in-wellhead casing hangers. The seal is weight set with running string weight to achieve a low-pressure seal, then energized and locked using the running tool by applying pressure below the BOP. It locks directly to the casing hanger via the casing hanger lock ring while the wellhead housing lock ring secures the seal assembly and casing hanger to the wellhead housing. Both lock rings provide a verification that the casing hanger and seal assembly are installed correctly. The seal is run in a single trip with the casing hanger, and if the seal fails to set, it is automatically retrieved with the running tool, leaving the casing hanger installed; the seal can then be re-run on a separate tool.
The seal is API 17TR8 compliant and qualified to 20,000 psi bore pressure and 15,000 psi annulus pressure from 0°F to 350°F. It is also fit for sour service as it is made from NACE MR0175 compliant materials.
This design is based on the field-proven technology of an existing Metal-to-Metal Annulus Seal Assembly. The design process involved detailed elastic-plastic finite element analysis and a FMECA-driven qualification approach involving a crossfunctional team consisting of experienced personnel. The FMECA was essential in developing the Metal-to-Metal Annulus Seal Assembly by defining necessary additional testing beyond that required by the industry or customers.
The following qualification tests were successfully completed on two independent annulus seal assemblies (proving repeatability):
Seal #1: PR2 per API Specification 6A, 20th Ed., Annex F, Subclause F.2.23: 20,000 psi bore x 11,000 psi annulus, 0°F-350°FAmbient temperature hydrostatic extended cycle testing per API Specification 17D, 2nd Ed., Subclause 5.1.7: 200 × 20,000 psi bore pressure cycles, 200 × 11,000 psi annulus pressure cycles
Seal #2: Worst case discharge simulation: 20,000 psi bore × 11,000 psi annulus, 0°F-350°FPR2 per API Specification 6A, 20th Ed., Annex F, Subclause F.2.23: 20,000 psi bore × 15,000 psi annulus, 0°F-350°FAmbient temperature hydrostatic extended cycle testing per API Specification 17D, 2nd Ed., Subclause 5.1.7: 200 × 20,000 psi bore pressure cycles, 200 × 15,000 psi annulus pressure cycles
New Standard for Standards
Authors: Brechan B. , Dale S. I. , Sangesland S. 
Published: April 2018

Abstract
Digital well planning, construction and maintenance have a lot of potential for cost reduction and improved HSE. Developing a software model to replace many of the tasks performed by humans can reduce administrative tasks and enables more focus on the quality of plans and operations. One single model to overlook engineering and activity through the life cycle of wells from the planning phase, through construction, production, maintenance to the final plugging unlocks many potential improvements. One possible feature for a Life Cycle Well Integrity Model (LCWIM) is to embed industry standards to supply guidance and recommendations during the life cycle of a well. Changing the format of standards so both computers and humans understand their content can benefit the planning and operational phases of well construction, intervention, production and finally plugging.
Typically, standards are used broadly in the planning phase. However, in the later phases of the life cycle of the well, it is often more difficult to accommodate both changes in operations and updates to industry standards. Embedding the industry "best practice" into software for planning well construction and maintenance, can prevent potential human errors and ensure an appropriate well construction. Having standards as "digital eye" on the engineering and well construction parameters can help to ensure safer operation and help to ensure that no regulations are overseen due to human error.
Standards can be considered a collection of experiences gathered over decades in the industry, and they represent the common ground for description of methods and procedures for safe and sustainable operations. When digital well planning gradually replaces the traditional manual planning processes, the vast experience of standards can support engineers more actively and directly compared to text documents. This paper describes an approach to merge the digital version of a standard into the LCWIM so it actively provides relevant information to ongoing operations similar to a help function. The user would experience this as "relevant information" by just a mouse-click. The method of choice elaborated in this article shows a life cycle standard in the shape of an active support module to the LCWIM. The reasons behind the selected approach is twofold: (1) LCWIM is a life cycle tool, which incorporates life cycle standards to support all activities in all phases, (2) Standards support LCWIM by verifying that tests and procedures are in compliance.
The focus of this paper is to demonstrate how a life cycle standard like the NORSOK D-10 Rev. 4, June 2013 can be completely digitalized to take an active part in planning and operations. The scope is limited to section 5.6 "Casing design" with elaboration of section 5.6.3 "Load cases" to stepwise show one way the standard can become interactive.
A Simplified Model for Steady-State Pseudo-Slug Flow
Authors: Soedarmo Auzan , Pereyra Eduardo , Sarica Cem 
Published: April 2018

Abstract
Pseudo-slug flow is widely encountered in petroleum production systems, such as in upward inclined pipelines and deviated wells with liquid loading issues. To author's knowledge, there is no model yet available to predict the behavior of this flow pattern. This study presents a simple model to predict the design parameters of pseudo-slug flow (pressure gradient and liquid holdup).
The modeling approach relies on the fact that pseudo-slug structure involves a continuous gas passage despite of apparent intermittency as a whole. Consequently, pseudo-slug flow is treated as a segregated flow with very large waves rather than a conventional slug unit cell. A modeling approach combining drift-flux and two-fluid models is proposed in this study. This method eliminates the need to arbitrarily prescribe the interfacial friction factor correlations for pseudo-slug, which would conceivably differ from those of stratified/ wavy/ roll-waves flow reported in literature. A new closure relationship is needed for pseudo-slug flow drift-flux coefficients, which are easily derivable from experimental data in literature.
Iterative procedure requirement to run the proposed model is minimal, which is an advantage for practical application. Additionally, this modeling approach does not produce multiple solutions, which may be exhibited by conventional two-fluid model. Pseudo-slug flow experimental data are collected from literature for benchmarking purpose. The accuracy of pressure gradient and holdup predictions of the proposed model is better than two state-of-the-art multiphase flow simulators, which generally treat pseudo-slug as slug flow. The values of interfacial friction factor naturally emerge in the calculation instead of being prescribed by a closure relationship. These calculated values exhibit sensible physical relations with pseudo-slug characteristics observed experimentally. The closure relationships for drift-flux coefficients remain to be improved in the future as more pseudo-slug experimental data become available.
Data Management and Digitalisation: Connecting Subsea Assets in the Digital Space
Authors: Murray John , Eriksson Klas 
Published: April 2018

While topside plants have made progress in the field of digitalisation, subsea plants are lagging behind. Due to inherent differences between topside and subsea plants (e.g. frequency and ease of changes), certain areas of digitalisation also provide more value than others.
A topside plant is in a state of constant change, while a subsea production tree is ideally installed and never touched for 25 years. For example there is no need to update the 3D model of the tree every year, while it may be cost effective to do so for a topside platform.
The paper discusses digitalisation benefits in the areas of operating, maintaining and upgrading subsea plants, focusing on current and near term areas ("low hanging fruit"). This is part of a general effort to reduced cost for subsea plants.
Longer stepout become possible using DC power and fibre-optic communication systems and along with this comes the ability to connect new sensors that provide valuable insight.
IOT sensors can be attached to products to monitor equipment during manufacturing, storage, transport, deployment and in operation. These can provide insight into weaknesses in the equipment which reduces its lifetime or identify improvements to handling or operation to extend product life.
In the operating domain, one focus is on making information easily available to the control room operator, reducing alarms, and tuning the control system for optimum performance. The goal is here to maximize production while avoiding or minimizing costly shutdowns. While the control room operator is mainly concerned with keeping the plant running while avoiding trips, onshore personnel monitor the plant with longer term views, e.g. for automatically identifying trends that indicate future failures or for proactive maintenance planning. Key to this is developing intelligent systems with visualization that highlights the most important information.
In the maintenance domain, focus is on Condition Monitoring and Condition Based Maintenance. Certain deterioration mechanisms can be tracked remotely, and intervention planned in advance. A planned intervention may give a 1 day shutdown, while an unplanned can give a 30 day shutdown. Any advance warning that equipment is about to fail thus results in shorter shutdown, and less deferred production. Examples of algorithms in recent and current use and under development are presented.
Current advances in Big Data and Data Analytics are discussed in relation to how these can support lifecycle monitoring, operational support and product design improvements.
RB-FEA Based Digital Twin for Structural Integrity Assessment of Offshore Structures
Authors: Sharma Partha , Knezevic David , Huynh Phuong , Malinowski Grzegorz 
Published: April 2018

The reduced basis finite element analysis (RB-FEA) technology was utilized for performing structural analyses of a semisubmersible drilling rig. The digital twin of the drilling rig based on the RB-FEA technology is about 1000 times faster to analyze than a conventional FEA model, without any compromise in the accuracy of the solution. The global model was established by integrating the individual components of the RB-FEA model with associated material properties, loads, and boundary conditions. The software for mapping of the wave loads (generated by software such as WAMIT/WADAM) onto the hull structure of the drilling rig was developed. Time domain strength and fatigue analyses were then performed for the whole structure that also included the highly refined fatigue sensitive regions of the drilling rig.
The results from the study demonstrated the efficiency and the accuracy of the RB-FEA based technology. The speedup and level of detail achieved through the RB-FEA technology is a key enabler for the digital twin technology since it enables true condition-based modeling of large and critical assets, allowing all relevant structural details to be included in the model, along with sensor and inspection-based condition data such as cracks, corrosion, and damage due to impact or collision. Asset life extension – enabled by the digital twin and condition-based monitoring using sensor systems – is the key to capitalizing on the value of existing facilities that are operating near (or beyond) their original design life.
Natural Gas Hydrates to Enable the Safe, Sustainable, and Economical Production of Offshore Petroleum Reserves
Authors: Kezirian Michael T. , Phoenix S. Leigh 
Published: April 2018

Abstract
This research presents a novel approach using Natural Gas Clathrate Hydrates (NGH) for the production of natural gas from deep-water petroleum reserves. Liquefied Natural Gas (LNG) has limitations associated with its enormous capital cost (requiring significant production capacity), inherent hazards, and environmental impact.
Storage and transport of natural gas must address the economic, safety and environmental requirements, as a whole, by designing the supply chain as an end-to-end process. The solution is the production of NGH at depths where the in situ pressure and temperature inherently favor the formation in situ, based on thermodynamics and kinetics. The remaining system is then created in order to manage these products. The engineering design, safety analysis and business case are assessed concurrently in order to optimize the system and meet all of the requirements.
Containment technology, originating from space exploration, is adapted so that it will be strong, durable, flexible and lightweight. The processing rate and dimensional parameters are selected to mitigate system losses and energy dissipation during long distance ocean transport. The resulting proposed process is economically assessed to be significantly cheaper for the production of natural gas. It can be applied for small production rates and replace operations which flare gas byproducts. Theoretically, it could be scaled for the production of large natural gas fields. The proposed system presents an inherently safer system as the hazards inherent with compressed natural gas (CNG), LNG and pipeline are eliminated by design. There is no handling of compressed or cryogenically cooled fluids, and the transfer from platform to carrier is eliminated. Consistent with the industry direction to move crude oil processing to the bottom of the ocean, the new process can be managed autonomously and avoid the hazards associated with adverse weather conditions. A resulting by-product from this new process is significantly-desalinated water originating in the deep ocean away from man-made pollutants. It is proposed that this by-product can either be post-processed to yield potable water or used as-is, replacing consumption of local resources.
The proposed system can be utilized to produce natural gas reserves which would otherwise be considered as stranded reserves. It can serve markets which are too small or ports are too shallow to handle the delivery of LNG from standard carriers. A Patent Cooperation Treaty application on this proposed method was filed and received a favorable preliminary review by the United States Patent and Trademark Office; claims were found to be novel and useful.