Industry-wide standardization is needed for operators to manage the $3 trillion in CAPEX expenditure forecast for 2018-2025 ( Global Data, 2018 ), while maintaining competitiveness and mitigating risks. With the backing of the World Economic Forum, Joint Industry Program 33 (JIP 33) was initiated to drive industry-level standardization for the procurement of equipment items, moving the industry structurally – across the value chain - towards common engineering designs and solutions established by means of cross-company collaboration. Fourteen (14) standard specifications have been delivered to date. Their adoption by 12 major operators is being measured and is progressing well. This enables the program to capture and evaluate successes, challenges, key learnings and feedback. The program is also establishing a process for future maintenance of JIP33 specifications in order to achieve sustained benefits. A further 35-40 supplementary specifications are being developed, based on recognized industry or international standards by the end of 2020. This paper will present the status of the JIP33 program and showcase some of its early successes, challenges and learnings. Experience with digital requirement developments will be shared, as well as learnings from the adoption and use of the Phase 1-2 specifications by JIP33 members.

De-manning of offshore processing facilities presents an opportunity for significant CAPEX and OPEX savings for operators, is inherently safer and may be an enabler for marginal oil and gas developments. Unmanned wellhead platforms are common, however de-manning of significant oil and gas processing facilities has not been achieved to-date. This paper presents a conceptual design for a Normally Unmanned Installation (NUI) with full processing of well fluids to export specifications. By using novel and innovative solutions, a design with reduced equipment count, platform weight and attendance is proposed. The design is technically ready for implementation whilst meeting the functional requirements of an offshore processing facility. A functional specification was developed for the platform; it was important that the design is transferrable, therefore this functional specification was kept broad. The platform was expected to process well fluid to typical pipeline export specifications. To test the design, commerciality was tested against a "Reference Case", traditional manned platform. Full subsea processing was investigated but discounted due to a lack of technical readiness. Traditional approaches to platform design were challenged at every level, from platform access methods to the requirement for platform power generation. The key drivers for manning were investigated, identifying the target areas for simplification. An optimal platform design was then identified integrating the latest techniques and technology. The NUI CAPEX was compared versus the Reference Case. Ground-up OPEX estimates were prepared to quantify the reduction in attendance and achievable savings. The resulting NUI design achieves an approximate 60% reduction in equipment weight compared with a traditional manned platform, leading to a CAPEX reduction of around 30%. Significant reduction is achieved by removal of living quarters, and therefore life support systems from the facility. Power import allows maintenance-heavy power generation to be removed. The optimised NUI delivers a reduction in OPEX of around 50% when compared to a traditional manned facility. Digital strategies such as predictive maintenance, robotic inspection and remote monitoring reduce the reactive maintenance hours offshore by up to 85% while maintaining platform availability. Walk-to-Work platform access is a mature technology and offers cost savings when compared with helicopter access and there is the potential for sharing of walk-to-work systems between assets and industries. Walk-to-Work access has the advantage that no permanent living quarters are required. A significant reduction in fabric maintenance manhours is achieved by carrying out inspection remotely. The truly innovative and disruptive solution for unmanned facilities is the subsea factory on the floor. At the time of writing, the technology is not of the required maturity and it does not offer a viable solution. As this technology matures the potential exits to create a truly differentiated, facility of the future.

The API 20S Standard is designed to play a crucial role in leveraging Additive Manufacturing (AM) to foster innovation in the oil and gas industry. The paper, in association with the standard, will facilitate the understanding of how AM will enable equipment design improvements, faster prototyping, and better inventory management. By way of discussing the progress, challenges, and lessons learned from the standardization process, the paper aims to encourage a safer, broader, and faster adoption of AM technologies in the mainstream oil and gas applications. The paper will summarize the streamlining process, feedback from the API 20S task group, and current status of the standardization efforts. Additionally, upcoming challenges and the potential for the oil and gas industry industries to contribute to the standard will be summarized. The paper will also showcase a novel tiered approach (Additive Manufacturing Specification Levels) to allow the users of the document to match different levels of criticality.

This paper describes developments in the fatigue counter methodology and how digitalization is used to deliver valuable online technical service. The fatigue counter methodology consists of using a combination of autonomous and online motion response sensors directly installed on the riser and interfacing Floating Production Storage and Offloading vessel (FPSO) structures. The measured environmental data, FPSO and riser response data are utilized in a machine learning (ML) environment to build more realistic riser response and fatigue prediction models. The results of this is significant reduction in uncertainties, enabling live riser fatigue predictions and providing a basis for life extension and improved accuracy of riser and vessel response analysis. As there is a need to run some risers at higher pressures, the optimum time periods for such high-pressure service can be found without compromising the flexible riser service life. A recent field case is presented whereby the fatigue counter ingest, process and present data on a modern digital infrastructure. The full service was setup based on available onboard sensors including a 6 degree of freedom (DOF) vessel motion response unit (MRU), temperature and pressure transmitters and forecast model for weather. Input and output data are shared through well documented and safe application program interfaces (APIs) between the operating company and the fatigue counter 3rd party service. The operating company receives live updates of accumulated fatigue damage and remaining service life. This enables the operating company to build contextualized and high value dashboards presented on their organizational front end. The paper illustrates the power and applicability of combining modern numerical methods with digital techniques, made possible by streaming input and output data on safe and well documented APIs.

This paper focuses on the development of the world's first high-voltage (HV) 45kV, wet-mate connector system 1 qualified in accordance with the Subsea Electrical Power Standardization (SEPS) SP-1001 Penetrators and Connectors cross-operator standard. The connector is rated for water depths up to 3,000 meters and is a key enabler of numerous offshore applications, including subsea electrical power grids; independently retrievable, high-power step-down transformers for long step-out subsea gas compression; cost-effective installation of deepwater pipelines with direct electrical heating (DEH); and simplified repair of deepwater high-voltage umbilical power cores (among others). The high voltage and current rating of the connector provides the opportunity for commonality between the primary and secondary of a subsea transformer. This reduces the cost of mating tools, protective caps and test equipment, thus improving the economics of utilizing wet-mate connectors, which can often be cost-prohibitive. The paper discusses the growing need for a clear industry standard that covers the development and qualification of HV wet-mate electrical connectors. It also explores the inherent challenges of subsea electrical connectors, including long-term reliability, subsea module integration activities, and long-term effects of sea-water immersion on insulating materials. These were identified through a policy of continuous stakeholder engagement and a thorough review of 40 years of low- and medium-voltage connector design. To illustrate the benefits that HV wet-mate connectors can provide, multiple use cases are discussed, including long step-out subsea compression; deepwater pipeline DEH; and HV umbilical repair.

Equinor & Total are developing an All-Electric Subsea (AES) to replace existing electrohydraulic systems for a standardized water depth independent VXT system. This system will fit the "Subsea Factory" development by Equinor where electric actuation of chokes, manifold and process valves already are implemented. Several development programs are underway with SPS contractors and technology frontrunners in the industry of subsea electrification. This in order to meet the need for new flexible and cost-efficient subsea production system (SPS) with increased safety level and enhanced condition monitoring facilities. Method/Procedure/Process The strategy for the AES initiate is develop SPS vendors in order to establish cost effective solutions and standardisation of products and interfaces. Develop a joint operator specification targeted for international use. The AES development program incorporates a system approach covering topside, SPS, downhole applications etc. The intention is to ensure that the advantages with an all-electric approach is utilised for all aspects, i.e. with respect to cost, project execution, operational flexibility, standardization. Results / Conclusions This paper will present the current status of the AES development covering: The fundamental features and the potential of the All Electric technology and concepts Status of the all-electric with respect to technology qualification The activities undertaken to close the technology gaps The implementation of all electric SPS solutions Joint operator specification to ensure uniform standardization approach

As Additive Manufacturing (AM) progresses forward to industrial production, there is a predominant need for standardization to ensure consistency and reliability. Development of industry accepted standards and guidelines is necessary for qualification and certification of AM parts across several industries. AM affords several advantages when compared to conventional manufacturing, including weight reduction, part consolidation, design freedom and inventory reduction, and has demonstrated its potential in industries such as aerospace. Since it is a relatively new manufacturing technology, there is a lack of testing and inspection procedures specific to AM, which hinders the development of standards. Existing testing procedures were developed for traditionally manufactured parts that are not directly applicable to AM processes. A number of Standards Development Organizations are working towards developing guidelines and standards for various processes in the AM value chain. An overview of the current status of Standard Development Organization's activities in the field of AM will be presented, focusing on gaps and industry specific requirements. Specifically for applications in oil and gas, pertinent standards need to be developed to enhance operational and environmental safety, efficiency and sustainability.

Joint Industry Program 33 (JIP33) has been established through the International Oil & Gas Producers Association (IOGP) with the backing of the World Economic Forum (WEF) to drive industry level standardization for the procurement of equipment and packages. Phases 1 and 2 which ran from 2016 through to 2018 have together delivered 14 specifications which are now being adopted and implemented by Operating Companies. These phases demonstrated the feasibility of cross-company collaboration to deliver common technical requirements in specifications. The technical specifications and associated information and quality requirements and standardised purchaser datasheets were all produced in document form only. Work processes to develop these deliverables also followed a traditional document-based approach, involving collaboration with up to 10 Operating Companies on a global basis. To generate the full range of JIP33 specifications needed for oil and gas procurement activity JIP33 will now seek to enhance the capacity, efficiency and auditability of specification development through digitalisation of the specification development and maintenance process through the use of Requirements Management tools, supporting both digital and document-based outputs. JIP33 is currently developing 35-40 supplementary specifications as supplements to established international standards using a digitalised process. This involves collaboration between 12 participating Operating Companies on a global basis. The Oil and Gas industry is spending significant sums on digitization and digitalization of workflows, services and interfaces. This paper presents the approach to implementing a digitalised method to specification development, how this benefits industry level collaboration and the efficiency gains compared to traditional document-based approaches. It also considers the challenges and cultural changes needed in the industry to fully capture the benefits from digitalised requirements management and future opportunities to extend and imbed this into project procurement work processes.

The objective of this paper is to evaluate and analyze energy savings and process optimization opportunities in the gas-oil separation plants (GOSPs) in upstream surface facilities. This approach resulted in the development of a new design for a compact gas-oil separation plant (C-GOSP) to meet the crude oil export specifications with less process equipment and operating costs, and higher oil product yield compared to conventional GOSPs. The new design was materialized as patents granted by the U.S. Patent and Trademark Office (USPTO). The innovative C-GOSP is based on the integration of the gas compression system with production traps to conserve energy consumption and minimize capital cost and increase crude production. Atmospheric and hot discharge gas from low pressure compressors will be rerouted and directly mixed with the incoming wild crude before entering the production traps. This process will result in simultaneously cooling the compressors' discharge gas and heating the incoming crude while increasing crude production. Hysys simulation was used to model and verify the feasibility of the C-GOSP. A 300 MBD production facility was used to benchmark the Hysys simulation model and to verify the feasibility of these promising energy saving opportunities. The extensive process simulation modelling using Aspen Hysys and benchmarked with the actual plant energy consumption revealed the feasibility of this innovative C-GOSP, which will result in the following benefits: Lowering the capital cost by eliminating the compressors discharge after coolers, liquid pumps, discharge KO drums and minimize the surface area of the crude heat exchangers. Lowering operating cost by eliminating the after coolers and heating medium required to heat the crude. Increase crude production yield by condensing the heavy hydrocarbon from the gas stream. Minimize the spacing requirements, which make ideal for offshore applications. The innovative approach of direct heating and cooling by mixing of hot and cold streams is superior to any other optimization approach. Consequently, a patent was granted from the USPTO on July 17, 2018, for the innovative C-GOSP. The patent number is 10023811.

As more organizations incorporate additive manufacturing systems to produce production parts, it is becoming clear that successfully moving beyond prototyping requires a more advanced and thoughtful qualification strategy. To achieve the desired outcomes, organizations in the oil and gas sector now need to learn how to build a methodical and scalable system for measuring and characterizing materials, processes, and parts. This paper will discuss best practices and standards for developing and executing a successful strategy for both metals and polymers -- from benchmarking properties, to creating appropriate operating/storage instructions, to testing and then ultimately digitally tracking the lifecycle of materials throughout a production workflow. This will include a review of industry best practices that could be used to determine accuracy, part yield, and cost efficiencies of the additive manufacturing processes. The manuscript will summarize key findings illustrating the significance of process variables within the entire additive manufacturing workflow. This includes elements of the design, material inputs, process parameters, post processing, and inspection. The critical nature of this information for building a scalable Additive Manufacturing process for production will be discussed. Additionally, the importance of ensuring the process is robust will be reviewed in the context of setting up an Additive Manufacturing facility incorporating key elements such as safety standards and operating procedures that empower teams to deliver on production requirements. Finally, a detailed framework will be presented to assist engineers in oilfield applications build a specification list for Additive Manufactured parts. The literature for quality management in the additive manufacturing is very limited in scope. This makes it difficult for organizations to assess the usefulness of the technology for their operations beyond an R&D capacity. The information provided in this paper shows the critical considerations and approaches that should be applied in oilfield applications.

This paper presents a multitude of lessons learned during the 5 years spent on the design, manufacturing and delivery of the on- and off-vessel mooring components for the Appomattox semi-submersible. Appomattox is Shell's newest and largest deepwater oil & gas production asset in the Gulf of Mexico (GoM). It was successfully moored about 260 kilometers Southeast of New Orleans, in June 2018 using a 16-point chain-polyester-chain mooring system. It was the culmination of the work done by a dedicated team of Shell civil-marine engineers, mooring equipment suppliers and an offshore installation contractor. Shortly after completion of mooring lines hook-up operations, the polyester ropes were pre-stretched, and the FPS was moved into position for the start of the Steel Catenary Riser (SCR) system installation. Appomattox started production in May 2019. The mooring equipment has so far been performing as expected. The delivery of Appomattox mooring components was particularly challenging due to an unusually large number of stringent constraints including: 40-year design life, first application of fairleads with underwater chain stoppers in the GoM to mitigate out-of-plane chain link bending fatigue, polyester rope properties fine-tuned to ensure that installation and in-service requirements are met, stringent inspection oversight to enforce project-specific requirements, Thermal Spray Aluminum (TSA) on portions of the platform chains and novel chain handling equipment and method for mooring lines hook-up operations, just to mention a few. The design of the overall system and management of the mooring equipment vendors was performed using mostly in-house resources. The paper starts with some general information about the Appomattox development. The three subsequent sections present the mooring system, the delivery team and the overall timeline. The lessons are then organized in sections by mooring component types (on-vessel, polyester ropes, chains, and various connectors). Some reflections on how stakeholders influenced certain characteristics of the mooring components are disseminated throughout the paper. The paper also includes some observations about how the equipment performed in the field even though the lessons learned about the commissioning and offshore installation are left for a separate future paper.

Oil and gas companies are focusing to solve the challenges of high-cost, high-risk and adverse market conditions in offshore production. These ongoing challenges and uncertainties with the fluctuating oil prices and increasing regulatory and safety requirements, have prompted oil and gas companies to explore ways to improve efficiency and productivity through standardization. Many of the offshore projects were analyzed before the launch of Unified Bulk Joint Industry Project (UBJIP) which has evolved in various phases. The main objective of the paper is to discuss the standard specification of Electrical and Instrument(E&I) components, Piping and Structure material. It is essential to state a defined significant purpose and benefit of the standardization work and assure that the actual efforts contribute to the overall savings. This paper focuses on the common specification in compliance with a cross-industry specification and includes details of the planning and execution of on-going standardization program. When standardizing, there are several considerations. The selection of bulk material is based on high-volume value and quality aspects which have significant impact when prioritizing among the components. The methodology adopted to develop the standard specifications of bulk items (for Electrical & Instrumentation, Piping and Structure) is identified by performing the gap analysis among local regulations, industry standards and major offshore project specifications. The developed standard specifications are based on evaluation and verification with prototype risk and business case studies. The findings of this paper cover the new standardization specification for cable glands, cable terminations and penetrations, pipe supports, flange management systems and outfitting. In some cases, the lack of international standards and codes in some areas was identified where the gaps were filled with the new UBJIP standard specifications. The significance and benefit criteria for standardization focuses on cost, weight, construction efficiency, compatibility, safety requirements and operational maintenance. The novel aspects of this paper address the challenges posed in design, materials, and procedures to meet a cross-industry specification, i.e. UBJIP IOSS (Integrated Offshore Standard Specification, soon to be incorporated into an ISO/IEC specification). The future steps and roadmap towards global standards are covered in this paper.

This paper presents the results of design and field execution of sand control completions for Raven High Pressure High Temperature (HPHT) gas field in Egypt. The reservoir contains stacked channel formation sands, that require sand control completions. The completions design is complicated due to combination of sand control and HPHT environment where industry has limited experience. The selected completions type was an Open Hole Gravel Pack (OHGP) with a pre-drilled liner. A series of lab testing has been conducted to design and qualify completions fluids. The lab test program included formation damage tests, shale stability tests under dynamic and static conditions, materials and fluids compatibility tests and others. The downhole completions hardware was specifically designed to allow effective displacement from oil based mud to completion brine fluid with subsequent gravel pack placement. The circulating gravel pack placement technique was selected using Cesium Formate brine as a gravel carrier fluid. The field installation campaign of the selected completions method is currently underway with 4 wells already successfully being completed. All completed wells demonstrated excellent well performance results with very low completions skin. The well flow-back and test results exceeded expectations, indicating the entire reservoir sand was contributing to flow, demonstrated greater than predicted Productivity Index (PI) with minimal skin damage. Sand control integrity was achieved with full gravel pack efficiency.

As the offshore wind industry matures and projects begin to expand to deeper water regions, various floating systems are being considered to support wind turbines. This paper explores the feasibility of a Tension Leg Platform (TLP) support system anchored with synthetic rope tendons attached to a gravity base template to provide a platform for a wide range of water depths with acceptable operating nacelle accelerations. In this paper, the NREL 5MW wind turbine is selected in order to provide a comparison to previous studies of steel tendon TLPs. A fully-coupled numerical modeling tool is used to assess the effects of extreme irregular sea loads on the TLP. A series of numerical simulations are carried out to compare the response of a Single Column (SC) TLP for three different water depths and three different environments. The responses are compared with the steel tendon model. The use of synthetic rope tendons potentially offers more efficient installation options and enlarges the range of acceptable water depths. The use of a gravity base/suction pile foundation may improve the installation cost and schedule. The fully coupled nonlinear, time domain analysis tool used provides a unique look into the fully operating wind turbine under stable motion characteristics of the TLP.

Many oil majors have their own in-house safety standards, engineering and design practices. At the same time, industry groups and various local authorities have developed their own codes, standards and recommended practices. On top of this, each classification society has its own set of rules for building offshore structures and machinery. As a result of the various requirements, highly complex specifications unique to each project are developed. The offshore project standardization effort seeks to find acceptable common ground between the numerous individual standards and requirements to reduce costs and increase efficiency in offshore engineering, procurement and construction (EPC) projects. As part of the standardization project, the specifications for the major topside equipment were developed to simplify procurement of machinery packages. In addition, bulk materials, outfitting design and the best practices for welding and inspection were standardized for construction efficiency. A gap analysis was performed, comparing executed project specifications, industrial standards, and international and local regulations. The specifications were then harmonized focusing on construction efficiency, compatibility and operational maintenance, and with the safety requirements. A major driver in this activity was to adopt marine practices for offshore application without compromising safety and quality. Feedback on the process was obtained from an advisory group made up of owners, operators, engineering companies, vendors and shipbuilders. Two standardization cases are presented as examples. The first is the standardization of topside piping material which resulted in the enhanced compatibility of materials and provision of greater construction flexibility, addressing material chemical composition, sour service application, wall thickness, test procedures and acceptance criteria. Secondly, a harmonized specification was developed for an air compressor package which meets the requirements for the design, inspection, testing, installation and commissioning for offshore application. The proposed standard project specifications help to reduce the potential for a manufacturer to misunderstand an owner's unique standards and requirements, and provide an opportunity to bring about cost reduction especially in unnecessary engineering and documentation.

A revolutionary application of existing technology, driven by the downturn in the industry, has enabled operators to adopt the high-quality existing standards of service companies instead of implementing project-specific, single-use requirements and documentation. This has created economic viability through total expenditure (totex) reductions as well as early production benefits for operators. This paper showcases how one operator and supplier achieved a 12-month subsea tree delivery while minimizing cost through standardization. Legacy project execution models make a 12-month subsea tree delivery unachievable while driving up costs through extended alignment phases, large project teams, and procurement of project-specific components. Achieving prealignment through robust documentation, technical workshops, and a unique approach to assessing risk of perceived gaps between organizations has proven successful in the execution of an offshore project in the Caspian Sea and clearly highlights the benefits of standardization. An enhanced industry-standard offering leads to both competitive and sustainable advantages, ensuring marginal fields are economically viable. The objective of a standard system offering is delivering a subsea production system at maximum capital efficiency and minimal lead time to optimize operators' return on investment while driving industry-leading safety, peak reliability and uptime, and superior quality. The Caspian Sea project execution methodology will discuss the benefits achieved in using standard products in a subsea production system and elaborate on the potential further benefits this approach would have on a larger brownfield application.

Anadarko started the initial development and qualification of 20 ksi equipment in 2013 for a Gulf of Mexico (GoM) project. That journey included an analysis of using depth-adjusted working pressure of 15 ksi equipment that allowed exploration and appraisal drilling of a high-pressure GoM prospect. It continued with the goal to develop and qualify a complete set of 20 ksi equipment for a deepwater GoM high-pressure development. The scope of development and qualification of High-Pressure, High-Temperature (HPHT) equipment included: 20 ksi deepwater Mobile Offshore Drilling Unit (MODU); 20 ksi subsea Blowout Preventer (BOP); 20 ksi Completions equipment for the upper completion including a subsurface safety valve, packers, chemical injection, wireline plugs, etc.; 20 ksi Intervention equipment including a thru-riser intervention string, a Tree Tieback Tool, workstring connection and an Integrated Workover Control System (IWOCS); 20 ksi Subsea Production equipment including wellhead, tree and a High Integrity Pressure Protection System (HIPPS). Anadarko formed the ‘20A project team’ initiative in order to qualify these critical deepwater components with a Rated Working Pressure (RWP) greater than 15 ksi. This project is coming to a close in 2019, with the qualification of over 200 components and assemblies to industry standards and meeting U.S. government requirements. This six year development journey of 20 ksi equipment development and qualification presented challenges and achieved breakthrough technologies for the industry. This journey, its organizational approach using systems engineering techniques and integration processes are presented.

This paper will briefly discuss past work in the DeepStar® Global Offshore Technology Development Program in Subsea Systems committees DeepStar® 12302 20 ksi Systems, demonstrating the usage of API 17TR8 for verification of a 20 ksi component. Furthermore, a collaborative group of operators have created a new DeepStar satellite program and will share the status of a newly embarked venture to demonstrate the complete design process from the second edition of API 17TR8, including both verification and validation. Building off past work, and incorporating current industry standards, SI will provide an example analysis that applies independent usage of API 17TR8. The process of developing this report will continue to allow current 20 ksi contributors and operators to comment on the scope of work in both the verification analysis and validation testing protocol. This will help put into practice the use of API 17TR8 document and provide an independent example of its use. A verification assessment will be performed using API 17TR8 on two assemblies – one specifically targeting global collapse failure modes, and one specifically targeting serviceability failure modes. Like past work, this project includes (1) Generation of Functional Specification, (2) generation of a Failure, Effects, and Criticality Analysis (FMECA), (3) design verification, (4) development of a validation protocol, (5) extreme and survival limits, and (6) a comparison of design and theoretical total life. Beyond the scope of past work, the current validation testing will be performed and will include (1) material characterization, (2) testing to validate the models used in the Load Resistance Factor Design (LRFD) for the global criteria and (3) testing to identify normal, extreme and survival externally applied bending moments, as well as global plastic collapse and serviceability failure modes. This project will provide the industry with a detailed case study and demonstrate the verification and validation processes of nonproprietary subsea hardware component systematically using API 17TR8 methodology.

The Advanced Technology Lab has developed a Fire Test Facility that became operational in spring 2015. This paper describes a fresh approach to the systems engineering process path taken during development to capture new capabilities and opportunities for such a system. New functions and safety features are discussed, as compared to the original system that was replaced. Recent fire incidents on offshore rigs have increased interest in meeting rigorous standards for fire safety. As a result of a needs assessment, a replacement Fire Test Facility (FTF) was developed in order to test offshore equipment. Offshore valves and connectors on rigs must be certified to withstand sustained fire conditions per American Petroleum Institute (API) standards 6FA/B/C. The requirements include surviving fire temperatures up to 1800 F for a period of 30 minutes, while holding internal pressure and even withstanding bending loads. Updated safety regulations at the company led to a review of the original Fire Test Facility, and it was determined that a new system was necessary to incorporate blast protection, controls automation, and situational awareness. After establishing needs and goals from our internal customer, derived requirements were generated. Using the company’s system engineering "engine", this led to a design that met customer requirements and enhanced safety. Improvements over the original system include a 6-sided bunker structure, passive ventilation, gas safety purges, remote operation to keep workers outside the hot zone, and real-time charting to assess test performance. After integration of the facility, a verification matrix was used to assess system functionality and performance. The improved system allows for quicker test turnaround, and more refined burn tests at reduced costs compared to using external test facilities. Mock fire tests can be performed to assess "what-if" conditions prior to actual testing of equipment. Several tests were successfully performed to API standards. Results and observations throughout the systems engineering process, including systems integration and checkout of the Fire Test Facility are provided.

Experiences from a chemical supplier perspective are presented to define, optimize and manufacture a surfactant for use with seawater in an offshore enhanced oil recovery (EOR) test. This includes laboratory screening test results followed by quality control checks during manufacture. The surfactant concentrate was successfully manufactured, diluted with seawater, and injected as the main component of a surfactant-polymer (SP) formulation. A branched C 12,13 -alcohol-7PO-sulfate surfactant was designed for use with seawater. Particular pH buffer chemicals were screened for inclusion with the manufactured surfactant concentrate to give compatibility with seawater. The optimization of the surfactant concentrate with buffer included tests to assure acceptable aqueous solubility, storage stability and rheology. A quality control protocol was used that included decision gates with the operator and key stakeholders. Laboratory testing showed good aqueous solubility of the branched C 12,13 -alcohol-7PO-sulfate in seawater with about 3.5% TDS and 1800 ppm divalent ions (minor calcium and major magnesium ions). The pH buffer selected for this application gave a pH of 7 to 9 to: Prevent precipitation of Ca and Mg divalent cations that could otherwise lead to fluid injectivity issues, and Keep the pH stable and above 7 (preventing acid-catalyzed hydrolysis of the sulfate group) for good storage stability of the surfactant concentrate from time of manufacture to time of use. Ultimately, a 15% AM surfactant concentrate with Newtonian viscosity characteristics was manufactured and deployed due to transfer equipment handling requirements. However, for the future, concentrations of 70+% AM, also with Newtonian rheology, are possible for deployment. Implementation of the surfactants in EOR to date has been largely restricted to onshore applications due to the challenges associated with offshore use. This paper provides a real-world example of the manufacture of a surfactant concentrate that was used in an offshore SP field project from the perspective from a chemical supplier. Information relating to the quality assurance and control during surfactant concentrate upscaling is also critical and included in this paper.