bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of an API 17TR8 Compliant 18-3/4 Subsea Wellhead System rated to 20,000 psi and 350°F
Authors: Phillips Ryan , Tooley Keegan , Bingham Fred , Rodriguez F. Justin
Published: April 2018

As the industry progresses into deeper waters with reservoirs that require more complicated well designs, there is an increasing need for equipment that can withstand higher pressures, temperatures, casing loads, and structural and cyclic loads. A 20,000 psi 350°F rated 18-3/4″ wellhead system has been developed to meet those needs. The system was designed and qualified to API 17TR8 with the addition of rigorous internal design and testing requirements. The system design is based on the field-proven technology of a legacy 20,000 psi 350°F 18-3/4″ wellhead system (reference OTC paper 19694) which completed development in 2008, prior to the release of API 17TR8. This API 17TR8 compliant wellhead system can support a total of 4,400,000 lb of casing weight inside the high-pressure wellhead housing, including up to 2,400,000 lb of intermediate casing weight in the first position and up to 2,000,000 lb in the second position. The system is provided with annulus seal assemblies (ASA) designed and tested through an extensive qualification plan made up of industry required testing in addition to testing identified by a detailed Failure Modes, Effects, and Criticality Analysis (FMECA). Operators can install and test the first position and second position ASAs, up to 20,000 psi, in a single trip with the use of a specially designed single trip tool. A spring-loaded tool and wear bushing also allows the operators to test the blowout preventer (BOP) to 20,000 psi while isolating the ASAs. The design of each component involved detailed elastic-plastic finite element analysis (FEA) per ASME BPVC Sec. VIII, Div 3 and a rigorous qualification plan generated through the FMECA process. The goal of this paper is to provide an overview of the development (verification and validation) of the 20,000 psi 350°F wellhead system per API 17TR8 and the independent third party (I3P) review as required by BSEE for an HPHT wellhead system.
Building Cloud Services for Monitoring Offshore Equipment and Operators
Authors: Tang S. , Wang R. , Zhao X. , Nie X.
Published: April 2018

Objective/Scope

A cloud based platform is being built to create and maintain a machine's digital twin model, based on the as-built information and the operating data fed from the machine control system. By making the cloud based machine services available to most offshore operators, this platform has the potential to help monitor machine conditions and operator performance at a relatively low cost.

Method, Procedure, Process

Firstly, the cloud digital twin model serves as a vault to store the up-to-date machine data on the cloud for easy access by various parties from different locations. Secondly, when it is connected with a machine control system through a network gateway, operating data can be fed continuously to the cloud platform, enabling the cloud based analytics to digest and derive insights about the conditions of the machine, the performance and behaviors of operators, and the recommended maintenance schedule.

Equipment performance grade is used as indicator of equipment performance.

Results, Observations, Conclusions

Many modern machine controllers have built-in database capability and are connected into a network with an internet gateway. This makes them ideal for working with cloud services to improve on remote monitoring, trouble shooting and maintenance scheduling.

Two application examples, covering a typical drilling system and a crane, are presented. By publishing the up-to-date machine digital twin data on the cloud, which is to be consumed by any computer with internet connection, this platform could help operators streamline operation and maintenance activities, as well as reducing the costs due to the reduced number of site visits by technicians and the lowered expenses following a more optimized maintenance schedule.

Novel/Additive Information

The technologies for this platform are well developed with successful applications in many industries. This cloud platform was initially envisioned to be incorporated in our offshore drilling system and crane offerings to facilitate data sharing and trouble shooting of offshore equipment without sending technicians to site. The same cloud services can be used by operators with equipment from other vendors, with some adjustments on the network interfaces.
BOEM's 3DX-Based Regional Bathymetric Data Set, Deepwater Gulf of Mexico: Automated Seafloor Characterization, Geohazards Assessment, and Engineering Planning
Authors: John Morgan D. , Campbell Kerry J. , Devine Christine A.
Published: April 2018

Unusually detailed bathymetric data that covers most of the northern Gulf of Mexico (GOM) continental slope is now available in the public domain. This data set was compiled and released by the U.S. Bureau of Ocean Energy Management (BOEM) in early 2017. The bathymetric data was derived from the seafloor pick from more than 100 separate 3-D exploration (3DX) seismic data sets. The seafloor detail provided over such a large area of the deepwater U.S. GOM is unmatched as a publicly available data set. This paper describes conditioning this bathymetric data set to facilitate easy handling, and then using this data set for automated mapping and characterization of seafloor conditions, including development of regional seafloor derivative maps. The maps can be used for making preliminary seafloor geohazard assessments as input to various engineering planning activities. The BOEM 2017 data and the maps that can be derived there from would be especially valuable to engineering and design firms and others who do not have ready access to proprietary 3DX or other regional seafloor data.
Subsea Seawater Treatment and Injection - Performance Tests of Filtration Membrane Modules at Simulated Subsea Conditions
Authors: Plasencia Jose , Andreotti Marcelo , Wang Hua , Alam Zamir
Published: April 2018

The use of seawater treatment and injection to increase oil recovery is extensively practiced worldwide. Seawater can be treated at different levels to provide the required water quality compatible with the reservoir for pressure maintenance. In this respect, membrane technologies including ultrafiltration, nanofiltration and reverse osmosis can be used for fines, sulphates and salt removal respectively. The use of subsea treatment systems built on these filtration technologies is proposed as an alternative to bulky and heavy conventional topside systems. Subsea systems can eliminate the need for expensive floating facilities that often have space and weight restrictions. For a reliable operation of a subsea system it is required to verify the filtration membranes performance at water depths that can reach 3000 m (300 bar and 4°C).

Laboratory tests of hollow fiber ultrafiltration (UF), spiral-wound nanofiltration (NF) and spiral-wound reverse osmosis (RO) membrane modules were performed at simulated deep-water conditions to assess their integrity and performance. A high-pressure dynamic testing system, with precision temperature and pressure control was built to enable accurate measurements. Short and long-term dynamic tests, including pressure cycling fatigue tests, were performed by operating membrane modules at the simulated subsea environment (300 bar and 4°C). Static tests were also performed to assess the impact of deep subsea conditions on membrane module structural integrity and membrane physical properties. The results indicate that the tested UF, NF, and RO membrane modules are promising for deep subsea applications. The mechanical integrity and membrane module performance were maintained within the predefined acceptable limits at both static and dynamic test conditions. These promising results are a big step towards the technical feasibility of using membrane technology for subsea seawater injection systems.
Well Construction Process Modeling and Simulation
Authors: Baker Jason , Ferraioli Patrick
Published: April 2018

The objective of this paper is to present a methodology for determining tripping performance at multiple levels of detail. Looking at it from the highest level of a rig fleet, then a singular rig, and its well construction process, then individual machines, machine states and finally specific functions. The intent is to pinpoint the contributors to the critical path processing time and correlate with additional factors impacting performance. This paper highlights the methodology for processing machine data, identifying drill floor activities, showing how specific machine states and functions impact the dynamic critical path of operations.

During offshore oil and gas well construction, a significant amount of time is spent on drilling operations. The operation involves a sequence of manual and semi-automated processes performed in unison as safely and efficiently as possible. The dozens of machines used during these operations operate independently, the driller orchestrates these machines to execute many complex activities. As these machine operations are highly coupled, the delay of any single machine function can impact the critical path of the overall operation, thus reducing the efficiency of the entire operation. Drilling rates within the offshore drilling industry have some degree variation given different wellbore conditions, operating procedures, environmental conditions, equipment designs and drill floor layout among others. Through the life of a well, these operational variations and inefficiencies are not immediately visible in the overall operation. These variations are manifested as invisible lost time, which in turn provides an opportunity to improve the efficiency of the machine, rig and fleet. This paper highlights the challenge of decomposing the drilling operations into its critical path activities and dependencies, then decomposing machine functions into discrete states, and finally operating modes to enable precise measurement of overall system performance. Leveraging commercial simulation software, state machine algorithms were developed to analyze the process using real-time machine data to automatically identify machine states, process activities and capture descriptive statistics. The results provide further insight into system performance that is being used to provide real-time feedback to operations personnel, as well as assisting with post event analysis. The methods developed during this project are also being leveraged in other projects to understand true system behavior and performance, considerations of future performance and to optimize new system designs.
Malikai TLP Project: Health Safety and Environment Measures Implemented for GOAL ZERO
Authors: Ratnasingam Alvin Rajan , Adrian Edmund , Fazilah Ungku Nor , Alex Wilson
Published: April 2018

Malikai TLP is a Deepwater manned platform operated by Shell. The Malikai TLP began construction in 2013. The Malikai TLP brought a huge challenge and complexity in terms of materials, quality control and assurance, interfaces between different contractors and subcontractors, construction and installation requirements and competent and experienced personnel. During the constructions phase, there were 3000-4000 workers based at site working together to build the TLP. There were significant amount of hazards that could be realized due to the types of construction and installation related activities such as working at height, working over water, confined space, working with electrical equipment, blasting, painting, grinding activities, scaffolding, lifting and handling of heavy equipment to name a few. The hazards at the site could have led to severe consequences including fatalities, physical injuries, burns and electrocution. With this realization, the Company implemented numerous measures to address the health, safety and environmental concerns including the welfare, competency and safe working environment for the workers. This paper presents an overview of the measures taken with the hope of achieving GOAL ZERO that emphasizes no harm to any personnel working at the site.
Deepwater Innovations: eXtra Long Oil Tiebacks Technologies
Authors: Gassert Michael , Molli Gianluca De , Calabrese Vito , Magi Stefano , Citi Gianfederico , Rollo Fabrizio
Published: April 2018

The scope of the paper is to present and discuss results of an extended technology development program regarding very long oil tiebacks architectures (50-100km) and related enabling technologies. The program is based on Eni most recent development projects (started up in the last 4 years) contemplating long tiebacks, new technologies implementation and experimental production periods conducted on those projects.

Important field production data and measured performances on development projects have been a key to define the program. Wide ranges of tieback architectures and technologies have been studied. Technology providers and suppliers have been heavily involved. Technology validation and risk analysis approaches were used. Feed design is now ongoing regarding new asset development initiatives. The objectives are to reduce deepwater development costs increasing the distance between new assets and existing production hubs, shallow water areas or even connecting those assets to shore.

A cost effective and flexible extra long oil tie back architecture proves to efficiently work on a wide range of applications and a wide range of design basis parameters. Key enablers are boosting, subsea power distribution, multicontrol communication, thermal management technologies, extensive work on reliability and availability and tailored operations procedures. Maturity levels and way forwards to a potential project execution will be discussed in the paper, including projected economics.

Recent technology development, qualification and testing together with the experience matured on the most recent deepwater projects allow to seriously consider a "full subsea development approach" at long distances from existing hubs or from shore.
A Comprehensive Innovation Method to Assess Uncertainties and Increase Performance of Infill Project in Mature Oilfields
Authors: Shi Hongfu , Ma Kuiqian , He Yifan , Han XiaoDong , Ren Bo
Published: April 2018

During the last 10 years, a series of megaprojects have been implemented to develop new areas and improve the recovery factor of mature oilfields in Bohai Bay, and the oil equivalent of Bohai has kept steady for more than 188 MMbbls for 6 years. There were many challenges in front of the comprehensive adjustment of mature oilfields including difficulties of engineering facilities upgrading, inter well anti-collision, complexity of remaining oil distribution. Driven by the needs of the project, the conductor was innovative and bold in marine engineering, drilling and completion, reservoir engineering to reduce risk, improve efficiency and increase the IRR (internal rate of return). The redevelopment project of S&Q oilfields was a typical example which included 1 FPSO upgrading, 10 platforms, 300 kilometers submarine pipeline and cable, and more than 370 infill wells.
Changing Landscape of Deepwater Field Developments
Authors: Landwehr Marcel M. , Mansfield Steven E.
Published: April 2018

Over the past few years the offshore industry has undergone a profound change.

Operators, contractors and suppliers have been forced to find new ways of working as the industry landscape changes, putting pressure on price and schedules. These new ways of working are taking shape in the form of alliances and mergers within the service industry, while operators take a more holistic approach throughout project lifecycles with their established contracts and suppliers.

This paper will review the changes & how new ways of working minimize interfaces, maximize efficiency and capitalise value-added contributions from the service industry.

This paper will also consider how different ways of contracting are evolving to drive the industry to further change regarding how we engage & balance risk between the various industry players.

Acknowledging the progress and promise of these new engagement models, Operators have requested Suppliers to engage during earlier stages as opposed to the traditional process previously followed.

Early engagement brings project execution expertise and experience while providing an innovative outlet for service providers to submit their best design proposals without the constraints of company-specific requirements. These models also provide opportunities to reduce cost, but more importantly – reduce interface, risk and the critical path of project schedules within this new industry landscape ensuring an earlier return on investment.

These changes will require all players in the offshore industry to focus their efforts to achieve additional improvements that go beyond internal processes, mergers, and acquisitions. Although these are necessary to ensure that the industry remains competitive, they alone won’t be sufficient. Operators, Contractors and Suppliers need to also work together to cause and manage a shift in balance between risks and rewards.

Finally, changes in one part of the industry (e.g. Equipment / Contractor type alliances) provide new opportunities in other sectors where collaboration has not yet materialised.

As such there is a promise of further improvement of cost, risk and schedule when these opportunities are materialised.
Managing Risks in Relief Well Operations: From Planning to Execution
Authors: Poedjono B. , Macresy L. , Sikal A.
Published: April 2018

The complexity of drilling a relief well requires a robust workflow, which defines all actions to be undertaken at each of the drilling phases. This workflow is used for decision making at every organization level from the field level to management.

To ensure successful execution, all risks must be identified, and detailed preventive and mitigation actions put in place. These actions reduce risk to an acceptable and reasonably practical level at all times.

The relief well drilling process needs to be consistent and must contain these key elements: A multidisciplinary team with clearly defined roles and responsibilities at each operations step for optimal communication.A thorough understanding of relief well techniques, methodologies, and processes, including various solutions. These solutions must be confirmed with simulation, communication techniques, well control and fluid dynamic killing modelling, relative positioning with various measurements and their uncertainties, and drilling in the presence of magnetic interference.All team members and third parties should use drilling simulations during the planning phase to identify any gaps, and ensure redundancies are in place. Scenario planning will ease the go/no-go decision making during execution.Incorporating existing workflows into the entire relief well process, such as anticollision risk management and hazard and risk control, to reduce the risk of having multiple sidetracks or having to drill an additional relief well.

This paper will present the relief well workflow process and provide insight into the seven phases of the workflow, including planning, approach target, locate target, follow target, intercept target, killing operations, and plug and abandon operations.
A Novel Coating to Reduce Solids Deposition in Production Systems
Authors: Bethke Gregory K. , Snook Braden , Herrera Gilbert , Kelly Amy E. , Joshi Sanjeev , Jain Shekhar , Choudhary Suresh , Hammami Ahmed , Evans Lee
Published: April 2018

Solids deposition in production systems can cause operational issues and costly mitigation. A novel hydrophobic coating has been developed that decreases deposition of solids, such as asphaltenes, scale and wax, under flowing conditions in well tubulars and flowlines. The coating may potentially lower field development costs by reducing umbilical tubing, chemical injection systems, and insulation that are currently used to manage deposition risks. Lab tests and field trials were used to evaluate the effectiveness of the coating.

Lab tests, from benchtop to large-scale flowloop, were designed and undertaken according to the solid of interest. In all cases, coated test sections were compared to uncoated sections under similar operating conditions. The impact of the coating on asphaltenes deposition was studied using the Organic Solids Deposition and Control (OSDC) device. Three types of scale (i.e. calcite, barite and halite) were investigated using rotating cylinder electrode (RCE) benchtop experiments and a small-scale flowloop. Coating performance with respect to wax deposition was evaluated with over forty flowloop tests. A field trial with a waxy African crude complemented the flowloop results.

Results from the lab tests and the field trial show that the coating does help mitigate the risk of asphaltene, scale and wax deposition under the conditions studied. Benchtop tests with two crude oils showed decreased asphaltene deposition for coated components. Lab results for scale also show a benefit from the coating. Calcite and halite deposition was dramatically lower on coated coupons and flowloop components, respectively, compared to their uncoated counterparts. Barite deposits on the coating were easier to remediate compared to the uncoated surface. The wax flowloop results have been consolidated into an operating envelope describing conditions where there is: no deposition with coating, reduced deposition with coating, and unaffected deposition (i.e. coated and uncoated behave similarly). A wellbore field trial with a waxy African crude validated the flowloop results. Wax deposition in the wells is typically managed with frequent scaping, sometimes as often as several times per day. With the coating applied to the inner wall of the tubular, the coated well showed a 75% decrease in scraping frequency relative to comparable wells with no coating.

This novel hydrophobic coating has been shown to help mitigate asphaltene, scale and wax deposition under the conditions studied. Based on the positive results of the performance testing, a commercial-scale application facility is being designed and constructed by Shawcor. Plans are underway to deploy the coating, where conditions are applicable, throughout the industry.
Intelligent Completions: Design and Reliability of Interval Control Valves in the Past, Present, and Future
Authors: Joubran Jonathon
Published: April 2018

The first intelligent completion was deployed in the Snorre field offshore Norway in August 1997, marking a major milestone for advanced completion engineering, reservoir insight, and production control. For the first time, an operator could manipulate tubing outflow performance at, or near, the sandface inflow node, without intervention or workover, but rather live via remote control using an interval control valve (ICV). Twenty years later, technological advancements have significantly increased the reliability and capability of intelligent completion tools with applications in ultra-deepwater, mature fields, as well as in the cost-sensitive unconventional arena.

This paper discusses the significant technological advancements and reliability of ICVs by comparing the following: case history examples of technology, applications, and installations from the past and present; associated technological and operation challenges with solutions and resulting reliability increases; and a view of the future design and reliability aspects of ICVs with respect to hydraulic vs. electric control and actuation. ICV case history examples are discussed below:

Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement. Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface. History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement. A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation. A Middle East operator's current application for low-cost ICVs. History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.

The steady increase in ICV reliability is the result of advancing technology, as well as continuous improvement in operational procedures. These case histories help detail each advancement.

The future of intelligent completions and ICVs is tied to precision of device control, system reliability assurance, and effective use of sensor data to generate recognizable value. Precision and data require electronic control and transmission; however, hydraulic actuation offers more advantages with current available technology. This paper concludes with an argument for the future of practical ICV installation, zone control, actuation, and closed-loop operator interface.
Emergency Chemical Scavenging of Hydrogen Sulfide During Gulf of Mexico Well Flowback
Authors: Budd N. , Joshi N. B. , Paille A. , Li Q. , Miller T. , Kapadia K.
Published: April 2018

During an initial Drillship flowback of a newly completed subsea GoM well, the produced fluids were found to contain unexpected and significant concentrations of hydrogen sulfide (H2S). Despite no detectable levels of H2S in the native reservoir fluids produced from nearby wells in the same sand zone, the flowback separator gas-phase consistently showed H2S concentrations in excess of 100 ppm. It is believed that the souring was caused by irregularities during the completion phase, and the flowback was suspended indefinitely until the serious HS&E concerns could be addressed.

Collaboration between the operator and the chemical partner resulted in appropriate operating procedures and chemical selection to allow the well to flowback through existing infrastructure. To mitigate the presence of sour fluids in the carbon steel subsea flowline and topsides plant, the chemical partner was able to prove through laboratory testing that a liquid-phase subsea H2S Scavenger application would prove highly effective. To deliver the chemistry, the scavenger was injected topsides (25 ppm scavenger to 1 ppm gas-phase H2S) into a continuous dead oil circulation that would be used mix with the sour fluids at the wellhead and provide a turbulent flow regime for mixing. This stage of the procedure was preceded by a 500-gallon oil-soluble corrosion inhibitor pill delivered between two pigs to protect the infield flowline from any acid gas induced corrosion.

Once well flowback was re-initiated with the treated dead oil circulation, the chemistry was observed to be highly effective at scavenging H2S in the subsea flowline. Draeger tubes and inline gas meters showed no detectable levels of gas-phase H2S during continuous scavenger treatment. To confirm success of the chemical treatment, injection was temporarily ceased and H2S levels were once again detected and began to climb. The value delivered by the relatively small amount of scavenger chemical was tremendous, as the chemical partner was able to help the operator prevent multi-million dollars in workover expenses. Though not immediately quantifiable, the mitigation of topsides HS&E concerns was equally as valuable since the souring was neutralized prior to boarding.
Fluid Loss Control in Smart Bentonite Drilling Mud Modified with Nanoclay and Quantified with Vipulanandan Fluid Loss Model
Authors: Vipulanandan C. , Mohammed A. , Samuel R. G.
Published: April 2018

In order to enhance the performance and sensing properties of the water based bentonite drilling mud hydrophilic bentonite based nanoclay was used. The bentonite content in the drilling muds were varied from 2% to 8% by the weight of water and temperature was varied from 25°C to 85°C. The nanoclay (particle size in range of 12 nm to 20 nm) content was varied up to 1% by the weight of the drilling mud to modify the rheological properties, enhance the sensing electrical resistivity and reducing the fluid loss of the drilling mud. The fluid loss experiments were performed on bentonite drilling muds modified with nanoclay at 100 psi up to about 420 minutes till the end of the fluid loss. Based on the experimental and analytical study the electrical resistivity was identified as the sensing property of the smart drilling mud so that the changes in the properties can be monitored in real-time during construction.

Addition of 1% nanoclay to 8% bentonite drilling mud reduced a fluid loss to zero at 25°C. The results also showed that 1% nanoclay decreased the electrical resistivity of the drilling mud from 15% to 36% based on the bentonite content in the drilling mud and temperature. Compared to the Vocadlo model, Vipulanandan rheological model better predicted the shear stress- shear strain rate relationships all the drilling muds investigated in this study. In all cases, except for the 8% bentonite drilling mud at 25°C, adding 1% nanoclay more than doubled the yield stresses and the maximum shear stress tolerances. The rheological properties of the drilling muds have been correlated to the electrical resistivity of the drilling mud using the Vipulanandan correlation model. The API fluid loss model was compared to the new kinetic Vipulanandan fluid loss model in predicting the experimental results for fluid loss. Compared to the API fluid loss model, Vipulanandan fluid loss model was effective, based on the lower value of root mean square error value, in predicting the short-term and longterm fluid loss with time, nanoclay content and temperature. The new model predicted the short-term and long-term fluid losses very well. This model also has a limit on the total fluid loss but the API model doesn't have a limit.
Lean Semi - A Competitive Floating Solution
Authors: Bruun P. K. , Rikheim T. , Laukeland L. , Bjørk K.
Published: April 2018

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

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

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

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

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

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

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.