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Buzios field development has the potential to implement several production systems due to large reservoir volumes. Considering the oil specification, the drive to use standard solutions already in place in Pre-salt area, associated with the high production indexes of the wells, Petrobras decided to tie back all production wells in satellite configuration. These facts, together with geological hazards in the area, lead to a potentially congested seabed scenario. Hence, FPU positioning has been challenging and demanding innovative engineering solutions to optimize FPU mooring as to overcome these challenges and enable FPU positioning close to wells. This optimization gave birth to new issues, such as risk of clashing between mooring lines and lazy-wave flexible risers. Integrated riser and mooring lines dynamic analysis, together with subsea layout assessment were performed to ensure technical and economic feasibility. Furthermore, due to the Buzios reservoir, well design requirements and subsea layout specificities, all FPU were located on the edge of the reservoir and flexible risers were tied back mainly from only one board of each FPU. Hence, enhancing clearance between bow and stern mooring clusters and the optimization of the risers’ configuration were of paramount importance for enabling most of the risers’ connections on the desirable board. FPU mooring optimization led to up to 30% of mooring lines’ radius reduction (horizontal projection), and an average of up to 500m per flowline reduction, saving CAPEX, OPEX and increasing the return on investment.

Over the last 20 years Brazil has been the stage where subsea processing and boosting (P&B) technology has supported and pushed the offshore oil and gas production to overcome its challenges and maximize field production and recovery factor. Subsea Oil-Water and Gas-Liquid Separation Systems, Multiphase Pumps, Electrical Submersible Pumps, Raw Water Injection Systems, and other innovative, enabler, optimizer or even disruptive technologies have been developing and applying in Brazil's fields to increase the NPV of projects and make feasible long tiebacks scenarios. This paper will present a retrospective of the most significant P&B systems developed and deployed in Brazil's fields, their operational experience, lessons learned, the next generation under development to surpass Pre-Salt and brown fields challenges and some initiatives to maximize these technologies applications.

Rubber based systems have been used in subsea thermal insulation for many years and have proven themselves to be reliable and cost efficient. Formulations have been changed over the years, pressing the maximum usage temperature upwards and into the realm of 160 to180°C in a hot-wet environment. Until recently there was a need for high temperature along with pressure vessels (autoclaves) for vulcanisation. This has limited the widespread use of such systems. Recent changes have eliminated the need for autoclaves, however the high temperature vulcanisation hasstill been required. A novel formulation has been developed to address these shortcomings, so that this class of materials could have wider use. This new material employs freely available materials in a unique blend. The material contains no hydrolysable groups and can operate from −40°C to 180°C continuously in air and in a hot-wet environment and retains its resilience and flexibility; and thus opening for use in both high and low temperature systems. The formulation does not include the use of hollow glass microspheres and is, correspondingly, without water depth limitations. A new, highly reliable vulcanisation chemistry allows for a stable latency time for application, with vulcanisation temperatures reduced to 50°C. This allows for rapid hand application and simultaneous vulcanisation on subsea trees, valves, manifolds, etc. The material is self-agglomerating, merging under gentle pressure, and can be applied at high thickness. As the base material has an intrinsically low thermal conductivity, glass-based fillers are not needed. The material adheres well to painted or primed surfaces and to many other materials typically used in the offshore thermal insulation industry. The 2-component material is conveniently combined on site, reducing the need for refrigeration during transport and easing mobilisation logistics and is applied using simple hand tools. Extruded profiles can be used directly on complex structures or combined into sheets for ease of application on more regular shapes in order to optimise application rates. Moulds are not required for application, reducing engineering and fabrication cost, while also shortening mobilisation time. The system has been extensively qualified according to ISO 12736 for continuous use at 180°C. This paper will detail important aspects of the development project along with the results of the qualification testing.

Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned.This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts.The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers.Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections.As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.

A detailed knowledge about the health status of the installed assets is the key for continuous production without unexpected events and downtime, which causes production loss. A major aspect is the prediction of the occurrence of a failure before the affected function is demanded. This is one purpose of the Condition Monitoring (CM), Prognostics and Health Management (PHM) and the application of a Digital Twin. The paper presents the result of an ability analysis for a subsea actuator towards its possibilities to increase the availability through a novel and extensive grade of information. The paper presents the resulting architecture and solution to achieve an actuator design, which is capable to provide a high safety, high reliability and a predictive health management which is prepared for a digital twin application. For this purpose, an applied Condition Monitoring concept is described and shown based on the case study. The analysis and resulting solution is based on a detailed research towards the state of the art. Different available subsea actuators are analyzed towards the communication interfaces and the ability to allow CM. Therefore, the required status and information of the actuator are shown (e.g. Torque, position, temperature, acceleration, water concentration in oil, humidity, pressure, inclinometer). The required environment information about the actuator are evaluated with the help of a failure mode analysis. The different sensor principles provide the necessary information. The paper evaluates the significance of the sensor information towards the CM concept. The data can be provided on different communication interfaces and protocols. These are analyzed towards the satisfaction of the CM requirements. The result of the analysis is a detailed architecture of a CM capable subsea electric actuator including the CM concept. The possible interfaces are shown and the provided sensor data by the actuator. The sensors provide the input for the CM model and the remote accessibility and controllability of the actuator. The result is the novel design of a subsea actuator, which fits perfect in a digitalized subsea environment to increase the availability and controllability including a CM concept.

CABLE JIP research project in 2017-2019 was initiated with the aim of studying the feasibility of deploying a novel semi-static electrical cable for the power take-off from a TLP-type Floating Offshore Wind Turbine (FOWT). Today, expensive dynamic electrical cables are mainly used for the power take-off from demonstrator project FOWTs or from new FOWTs on the drawing board. For a TLP-type FOWT, the use of a semi-static electrical power cable instead of a fully dynamic electrical power cable (umbilical) is an attractive option to reduce the levelized cost of energy (LCoE). However, the electrical power cable in a dynamic offshore environment is vulnerable to failure, either at the floater side or at the seabed touchdown area. Moreover, the electrical power cable for power take-off is typically non-redundant, while the availability of the turbine(s) highly depends on this critical component to transport the produced power to the substation. The paper discusses the results of the CABLE JIP research project, with focus on the verification and calibration of the numerical models for the ULS and FLS assessment of the electrical power inter-array cable for a harsh weather test case with a TLP-type floating offshore wind turbine in 96.5 m water depth.

Gas hydrate formation in natural gas systems and subsea infrastructure can block pipelines and instruments, restrict flow, and lead to safety and environmental hazards in production and/or transportation systems. These problems can lead to substantial economic and HSE risks. Therefore, understanding how, when and where hydrate formation occurs are important factors in developing the hydrate management strategies. This paper addresses the hydrate management strategy in one of the subsea developments in the Gulf of Mexico (GOM). The effects of salinity, water cut, and amount of methanol on hydrate formation and plugging risk were studied in this paper. The experimental results and modeling in advanced thermodynamics software showed that an increase in the concentration of methanol and salts in the autoclave cell leads to a shift of the equilibrium curves, reducing subcooling and hydrate volume fraction while increasing induction time. The results also show that for some under-inhibited systems, the volume fraction of the hydrate slurry is low enough to allow for safe transportation of fluids during various operational conditions.

The challenge in the Oil&Gas industry to remain competitive in a low oil price whilst dealing with minimization of operational risk and uptime asset maximization is leading offshore Companies to evolve thought proactive and predictive maintenance approaches. In the event of unplanned intervention due to anomalies or warning messages at the dispatching center, the decision on the size of the support vessel and its utilization for straordinary maintenance could be time consuming with potential high cost impact, also due to loss of production. Even the new generation of remote condition and monitoring systems, which allow to improve the capability of operators for early warnings and surveillance, provide a reliable solution for emergencies. In this context, resident subsea drones enable on-demand inspection whilst eliminating the need for support vessel and allow operator to manage the risk in continued operations also for dangerous areas restricted to human access. A case study relevant to a new subsea field development have been conducted. Distinctive Reliability, Availability and Maintainability (RAM) analyses have been performed with the aim to get insight on the subsea production system availability considering a resident drone and to demonstrate how the so called "stategic maintainability" can be applied successfully in the decision-making process while reducing the OPEX. The former related to conventional IMR (Inspection, Maintenance & Repair) based on Condition Based and RBI, Risk Based Inspection approach, the latter related to strategic maintenability with resident drones. The application of such analysis required a multi-disciplinary approach together with the possibility of processing historical data in operating conditions. Historical data sources (e.g. OREDA dataset) were collected to obtain failure rates and active repair times typical of subsea equipment. Direct experience gained in over forty years of inspection and maintenance activities together with recent developments on subsea resident robotics allow the understanding of real internvention timing. Results show that resident subsea drones applied for early inspection and light intervention are confirmed timely and costless solution respect to conventional IMR services. They represent the first aid for environmental surveillance and subsea inspection in case of emergency and provide a relevant saving of subsea production un-availability. The economic value emerged from the presented case study represents a step change for OPEX optimization and motivates Best-in-Class Operators to get an insight case-by-case for both green and aging fields.

Brazilian Pre-salts fields lie in approximately 2200 m w.d. in a challenging environment and are often characterized by highly corrosive produced fluids that pushed to the extreme the application of the most advanced material technology and engineering. Nevertheless, Lula, Sapinhoá, Mero and Búzios are definitively world-class prospects with production rates that may exceed 30.000 barrels per day per well. The development scheme of the Pre-salt fields followed the experience and the track record of the large number of deepwater fields that were previously developed in Brazil, in the post-salt regions, and is based on satellite wells tied to the floating production platform by means of dedicated production and service risers (i.e. each well has dedicated production and service lines). This satellite configuration offers the advantage to be simple, straightforward and resilient to field layout changes even during the project execution phase. However, the continuous pressure to which the Oil & Gas industry is exposed in order to increase profitability, reduce cost and, more recently, green house gas emission is encouraging Operators to evaluate different field architectures that are more traditionally implemented in other deepwater provinces outside Brazil and that the recent technology and construction asset developments made suitable also for a potential application in the Pre-salt fields. Moreover, those field architectures that are normally based on commingling of wells production are also prone to provide a faster production ramp-up and a reduced time to break even. This paper presents a description of possible Daisy Chain and Manifold-Based subsea architectures that are suitable to be applied to Brazilian pre-salt fields. The pros and cons of these alternative subsea layouts are explored. Additionally, cost and schedule analyses are presented to show the benefits of such architecture regarding CAPEX and ramp-up compared to satellite architecture, considering the "Brazilian pre-salt" scenario. Finally, a generic proposal for subsea architecture is presented for pre-salt developments jointly with practical solutions for typical operation demands related to flow assurance issues like, for instance, wax and hydrate management.

With increasing demand of subsea processing and surveillance goals Best-in-Class Operators are developing advanced subsea instrumentation and controls to challenge in the next decade: i) a cost-effective way to inspect and repair subsea complex facilities and ii) to reduce the downtime, possibly increase the production performance while preserving the integrity and maintenance of the assets. The so called "Autonomous Subsea Field Development" is a study triggered by an ExxonMobil URC (Upstream Research Company) initiative aimed to explore possible improvements and re-designs of subsea equipment considering the advancing capabilities of ROVs and new generation of Subsea Drones, and driven by the following questions: with the advancements in AUVs and ROVs, can subsea equipment be re-designed to take full advantage of the new capabilities? Can this re-design improve from different perspectives (Availability, Costs, Operations, etc.) a subsea field development? A dedicated study was conducted by SAIPEM to identify the value proposition, technology needs and gaps for future advancement by leveraging on the technological "building blocks" that could be integrated in a subsea field development scheme and on a field operational procedure. Within the study, seven different cases, distinguished by their status of advancement (from Brown to Green Fields) and by the level of penetration of Subsea Drones in the architecture, have been analyzed. A conceptual engineering process, based on the tenets of value engineering was conducted in a holistic fashion covering the full field development facilities during the life cycle in order to steer the conceptual engineering choices that could maximize the project value. Using a systemic Value Engineering approach based on the NPV equation, the study identified the main technological and economic impacts coming from the adoption of Subsea Drones on a current and future Digital Subsea Field exploring the following pillars: i) CAPEX, ii) OPEX, iii) AVAILABILITY, and iv) RISK. In the sequence of six cases investigated, it has been identified how these incoming "subsea capabilities" will be gradually implemented into redesigned subsea architecture and serviced in view of a new Life of Field concept.

Known as HFW-MLP, Mechanically Lined Pipe (MLP) with High Frequency Welded (HFW) host pipes are potentially the most cost-effective bi-metallic pipes for subsea pipelines when corrosion resistant alloys (CRA) are required. However, HFW-MLP has a very limited track record for subsea applications. This paper details a recent programme to qualify MLP with HFW host pipes. The qualification programme has been performed in accordance with DNVGL-ST-F101 (2017) and internal supplementary requirements for reelability and weldability. It considers material testing of HFW-MLP at each manufacturing stage and product qualification including full-scale reeling simulation, anti-corrosion coating simulation and girth welding. Qualification is supplemented with a detailed evaluation of the manufacturing process HFW-MLP is compared to traditional MLP which is supplied with seamless carbon steel as the host pipe or backing steel. This novel product lowers the supply cost, reducing the Capital Expenditure (CAPEX) for subsea pipeline projects. Detailed evaluation of mechanical test results and dimensional inspections using laser profiling assess the impact of the HFW host pipe longitudinal seam weld and conclude that there is no detrimental effect on the performance of the completed MLP. A comprehensive review of full-scale reeling simulations, coating simulations and welding trials is completed, with the conclusion that an HFW host pipe does not adversely affect the ability of the MLP product to be girth welded and to withstand the plastic deformation exerted upon the product during reel-lay installation. It is concluded that HFW-MLP is qualified for subsea pipeline static applications via the reel-lay, S-Lay or J-lay installation methods. The qualification of HFW-MLP provides a more cost-effective solution for the development of corrosive subsea fields by reducing overall product supply and installation costs.

Subsea field development planning can be a complicated undertaking requiring the coordination and collaboration of multiple engineering and commercial disciplines with competing objectives. Thus, finding the optimal development solution can be challenging. To combat this, a data-centric omnichannel digital platform for configuring subsea field developments has been created. The study workflow orchestrated by the digital platform is detailed along with an overview of the data model, functionality, and deliverables. A case study is presented to demonstrate the value delivered using this digital platform. The digital platform is inherently collaborative as it orchestrates specialist engineering tools and their workflows around the same data for study teams to configure subsea development solutions. The platform is composed of: A web-based graphical user interface that allows discipline and product engineers to collaboratively configure the system, products, planning and costing for an entire subsea field development scenario, leveraging the same base data i.e., a single source of truth. A proprietary data model covering system, product (e.g., hardware or equipment), activity planning and costing breakdowns, and; Microservices that directly attach engineering tools and their workflows to the digital platform to automate product design and analysis. A case study is presented to demonstrate the use of the digital platform on a subsea field development prospect and a qualitative comparison with the conventional way of working is made. The case study illustrates the use of a digital hardware configurator (subsea tree system configuration) and the automated planning workflow for an EPCI (Engineering, Procurement, Construction, and Installation) prospect enabled by the digital platform. The results of the case study demonstrate the platform values and benefits the digital platform delivers. The benefits are underpinned by the automated data transfer, the versioning functionality, software logic, and the common base data used by the microservices. The benefits that have been found when compared with the conventional way of working include: Faster validation of alternative development scenarios, meaning that more concepts and sensitivities can be investigated in the same length of time; A reduction in the overall lead time and person hours required to configure and optimize a field development solution; Design risk reduction, and; Efficient and consistent transition of data via virtual handovers. This paper demonstrates a new approach for subsea field development planning using a data-centric omnichannel digital platform called Subsea Studio™ FD, which is shown to deliver benefits over the conventional document-centric way of working. The digital platform brings multiple engineering disciplines together to configure optimal development solutions, accounting for competing objectives. It initiates the digital thread through the project lifecycle and will ultimately culminate in a digital twin during project execution, which can be leveraged throughout the life-of-field to optimize operations.

This paper demonstrates a pioneering technology adaption for using a membrane-based subsea storage solution for oil/condensate, modified into storing clean energy storage in the form of ammonia (as a hydrogen energy carrier). The immediate application will provide an economical alternative to electrification of offshore platforms, instead of using expensive cables from shore. Storing ammonia at the seabed using innovative subsea storage technologies will dramatically reduce CO2 emissions for offshore assets. The fluid will be stored in a safe manner on the seafloor, protecting both personnel and marine life. The next step will be to include subsea ammonia storage as part of the global logistical value chain, which can power the merchant shipping fleet. Clean ammonia can be produced using renewable resources as wind or solar. It focuses on bridging the ongoing oil/condensate storage qualification, adapted into storing ammonia. The large-scale verification test scope is explained, and we show how the test is extended to also prove the concept of safe energy/ammonia storage. The ammonia storage concept is explained, and we show how this can be included as part of a low carbon future. The focus is the immediate market for providing clean power to existing or new offshore assets. The full system solution will encompass storage tanks placed nearby the platforms at safe water depths, riser systems providing fuel to the ammonia power generators, and the tank filling systems. Bridging and adapting technologies from the petroleum industry into renewables shows the importance of utilizing the technology developments and competence of the oil and gas business. The technical evaluations have shown that the oil/condensate storage can be adapted into storing energy/ammonia with minor modifications. Converting hydrogen into ammonia gives slight energy losses, but it is defended by the large economic benefits of storing ammonia versus pressure storage of hydrogen. The paper presents qualification work already completed and how to implement ammonia fuel storage for platforms. In addition, we show the test setup for a large-scale qualification provided by an original equipment manufacturer (OEM) company together with major Operators. Innovative modular design methods have shown that the concept can be included on existing offshore assets, which have limited topside space available. Adding green or blue ammonia as an alternative to power cables from shore have several benefits, and many of the connecting building blocks are falling into place. The main conclusion is how to adapt Novel technologies from the oil industry to store ammonia in a safe way on the seafloor.

Optimal route selection for the subsea pipeline is a critical task for the pipeline design process, and the route selected can significantly affect the overall project cost. Therefore, it is necessary to design the routes to be economical and safe. On-bottom stability (OBS) and fixed obstacles like existing crossings and free spans are the main factors that affect the route selection. This article proposes a novel hybrid optimization method based on a typical Machine Learning algorithm for designing an optimal pipeline route. The proposed optimal route design is compared with one of the popular multi-objective optimization method named Genetic Algorithm (GA). The proposed pipeline route selection method uses a Reinforcement Learning (RL) algorithm, a particular type of machine learning method to train a pipeline system that would optimize the route selection of subsea pipelines. The route optimization tool evaluates each possible route by incorporating Onbottom stability criteria based on DNVGL-ST-109 standard and other constraints such as the minimum pipeline route length, static obstacles, pipeline crossings, and free-span section length. The cost function in the optimization method simultaneously handles the minimization of length and cost of mitigating procedures. Genetic Algorithm, a well established optimization method, has been used as a reference to compare the optimal route with the result from the proposed Reinforcement Learning based optimization method. Three different case studies are performed for finding the optimal route selection using the Reinforcement Learning (RL) approach considering the OBS criteria into its cost function and compared with the Genetic Algorithm (GA). The RL method saves upto 20% pipeline length for a complex problem with 15 crossings and 31 free spans. The RL optimization method provides the optimal routes, considering different aspects of the design and the costs associated with the various factors to stabilize a pipeline (mattress, trenching, burying, concrete coating, or even employing a more massive pipe with additional steel wall thickness). OBS criteria significantly influence the best route, indicating that the tool can reduce the pipeline's design time and minimize installation and operational costs of the pipeline. Conventionally the pipeline route optimization is performed by a manual process where the minimum roule length and static obstacles are considered to find an optimum route. The engineering is then performed to fulfill the criteria of this route, and this approach may not lead to an optimized engineering cost. The proposed Reinforced Learning method for route optimization is a mixed type, faster, and cost-efficient approach. It significantly minimizes the pipeline's installation and operational costs up to 20% of the conventional route selection process.

Subsea water treatment technology for water injection provides a solution for an optimized water injection strategy on both green and brownfield applications. There are no space and weight constraints on the seabed, which enables simple, flexible, and reliable designs. A full-scale sulfate removal and low salinity plant designed for seabed operation with minimum maintenance intervention has been in operation for ten months without any chemical cleans. This paper reviews the performance results used to predict the life and longevity of a subsea sulfate removal unit (SRU) for a field application in the North Sea. The ability to reliably predict the potential risks and serving life of a system is crucial for the success of subsea processing equipment. Results from a test conducted over ten months evaluated the key design parameters such as SRU membrane permeate flux, recovery rate, and analyzed membrane fouling behavior during the test period. Lessons learned from the testing are incorporated into the model for more accurate and reliable membrane life prediction. Field data was analyzed to extrapolate aging factors that are used in the membrane design projection software. The projection software simulated aging performance of the membrane over the membrane lifespan under subsea operation conditions, and the results were applied to determine operating philosophy, maintenance, and intervention interval for the subsea plant. Lessons learned from this field study were discussed and used as guidelines for the next phase full-scale design and practice. This novelty field practice establishes a break-through step towards full implementation of subsea seawater treatment and injection for increased oil recovery (IOR) and enhanced oil recovery (EOR) purposes. This firsthand data helps the operators to optimize the operation on the seabed, which minimizes the downtime and demonstrates promising advantages of CAPEX and OPEX saving in the long run.

Drag reducing agents (DRAs) are a cost-effective method to reduce pipeline pressure losses and maximize flowrates of onshore and offshore pipelines with over 40 years of proven results. With recent developments, production can also be significantly increased by injecting DRA into flow restricted subsea flowlines. This paper will provide a summary of the development and testing of a full-scale prototype subsea DRA storage and injection unit built to achieve the industry goal of alleviating flow restricted subsea pipelines. While DRA applications are proven in thousands of offshore and onshore applications, it has never been successfully injected subsea. System integration testing (SIT) is currently under way on the prototype unit, after which it will be qualified for offshore use. The technology is covered by numerous patents issued and pending in the US and other countries.

Riser base gas lift is conventionally used in deep water fields to minimize backpressure on wells, smooth start-up transients, and mitigate slugging in the flowline-riser system which can cause disruption in the topside facilities. The effectiveness of riser base gas lift depends on several factors, such as the reservoir performance, the fluid properties, the field architecture, and the topography. There are several technical solutions available to deliver the lift gas to the riser base. Such technical solutions differ in terms of lift-gas supply method (distributed vs point-to-point), riser specifications, and overall system complexity. The selection of technical solution has the potential for minimizing infrastructure. Available solutions include bundled risers and concentric riser configurations that allow gas lift functions to be integrated with the main production conduit. The evaluation of riser base gas lift effectiveness and the selection of the most appropriate technical solution is typically performed early in the field development cycle. This paper presents a review of the available subsea gas lift technical solutions and discusses an evaluation process, including criteria for the selection of the most appropriate solution. The presented case study assumes a deep water Gulf of Mexico field, in which the main subsea system consists of two wet insulated piggable flowline loops. Key decision drivers were flow assurance requirements, complexity, operability, impact on field layout, interfaces, installation, and schedule are discussed. This holistic approach aids the selection of the most appropriate riser base gas lift system in the early field development cycle.

Kinetic Pressure Control has developed the 18 ¾" 15000 psi blowout stopper (KBOS) system for applications on all subsea well activities. The 18 ¾" 15000 psi systems builds upon the successful development of the 5-1/8" 15000 psi KBOS system for surface BOP applications[5]. The system can be configured within the existing subsea BOP, by replacing a casing shear ram or blind shear ram, or can be configured as a shut-in device below the BOP. The KBOS system provides a significant improvement over existing shear ram technology, providing the ability to shear/seal any items in the wellbore, which reduces the likelihood of a blowout, resulting in an improved risk profile. The KBOS is a proprietary design which uses a pyro-technical, electrically initiated process the actuate the shearing process. The system has been designed and tested to actuate and shear/seal in milliseconds, under full wellbore flowing conditions and meets NACE/ISO sour service requirements without exemptions. The control system includes real-time monitoring and function testing capabilities, and requires minimal in-service maintenance, as the working components are isolated from the wellbore fluids. A computational predictive model has been developed, with a test regime conducted to validate the model results. A full qualification program, with 3rd party certification, has been completed to industry standards. Shearing tests have been conducted for a large range of tubulars which have been challenging to shear with existing technology. These include: 9 ½" drill collars, combinations of large OD casing and inner strings, high strength drill pipe and tool joints, wireline, and production tubing. A subsea test of the system was successfully performed in 2019 to shear large OD casing and inner string. The KBOS system utilizes technology from other industries (ballistics, military, automotive) to provide improved shearing and sealing capabilities for all well activities (drilling, completion, intervention). The improved shearing/sealing capacity and reduced time enable a reduced likelihood of a blowout and improved risk profile

The development of Subsea Chemical Storage & Injection (SCS&I) technology is a continuation of the trend to move more of the hydrocarbon production systems subsea. This is driven by a need to make exploitation of remote resources profitable; unlock single-line long tie-backs and subsea to shore architectures, and to enable tie-ins with otherwise constrained topside infrastructure. The SCS&I System is also a significant contributor to the development of "All-Electric" subsea architecture where the umbilical is reduced to a power and communication cable only. TechnipFMC https://www.technipfmc.com/ and Total https://www.total.com/en are collaborating to develop and qualify the SCS&I technology components and system. In order to make the SCS&I technology competitive and field developments profitable, the reliability of the equipment is paramount. The HAMPRO 70V injection pump is one key component in the system for which high reliability must be ensured. The objective of the qualification program is to confirm the adequate performance of the HAMPRO 70V pump in the following areas: The reliability of the chemically exposed parts and the impact of chemical fluid cleanliness The reliability of the pump and motor rotating parts and the impact of lubricant performance The reliability of the electrical components The impact of transient behaviour on the pressure compensation system, rotating parts and electrical components Due to the similarity of design, smaller versions of the HAMPRO pump will also be qualified by the activities in the program.

This paper presents the development and qualification of a novel Subsea Electric Actuator, especially designed for rotary small-bore valves. One of the main challenges was to design an electric actuator which is as compact as the existing hydraulic actuators, but able to provide a fail-safe mechanism by field-proven springs and full integration of all necessary components, including the electric drive and controls, inside of a compact enclosure. Furthermore, the design team had to considerably reduce its power consumption and weight in comparison to existing solutions. Finally, the system was designed for lean manufacturing, allowing considerable cost-saving benefits for all the partners due to extensive standardization work. The paper shows the engineering requirements obtained by interviewing different users, the design methodology applied and the qualification of the new system up to TRL 3 with Digital Twin and Rapid Prototyping. Finally, an outlook is presented with the planned TRL 4 and TRL 5 qualification tests and a summary of the technical and economic benefits for the users of this novel Subsea Valve Actuator.

Subsea HPHT components may be evaluated utilizing a fracture mechanics-based approach as per guidelines in API RP 17TR8 and ASME Section VIII Division 3. Typically, the assessment is performed based on methods described in API 579-1/ASME FFS-1 and BS7910. The analysis is performed to determine critical flaw sizes and estimate the fatigue life of a growing crack as a means of establishing inspection intervals for the equipment. In most cases, the assessment is based on a linear elastic fracture mechanics approach. The effect of plasticity is generally included via the use of a failure assessment diagram (FAD); however, even with this approach the effect of plastic strain around the crack is not explicitly considered. The assessment standards do not provide clear guidance for cases involving a crack which is located within a region of large-scale plastic strain. For these cases, API 579, Annex 9G.5 recommends utilizing a driving force method whereby the J-integral is directly evaluated from an elastic-plastic finite element model. This paper presents such an approach. A simplified representative geometry is considered for this study. A region of a stress concentration, such as is typically encountered near an internal radius is considered. Such a region can potentially show localized plasticity. J-integral is calculated by explicitly modeling a series of cracks of increasing depth through this zone of plasticity and the results are compared to the different methodologies described in API 579-1/ASME FFS-1 and BS7910. Cracks are modeled both completely and partially enveloped within the plastic zone. Results are summarized and compared, highlighting the key differences between different analysis approaches with the aim of identifying the most conservative assessment method for different crack sizes. Additionally, the effect of large-scale plasticity on the crack driving force is determined relative to similar conditions without plasticity. The results indicate that for cracks lying within the regions of localized plasticity, using an API579 Level 2 approach coupled with extracting elastic-plastic through wall stresses from an uncracked geometry may result in significant under prediction of the driving force. Conversely, extracting linear elastic stresses from an uncracked geometry may significantly over predict the driving force and may prove too conservative for determining acceptable crack sizes. This paper presents a comprehensive comparison of different analysis approaches used for evaluating cracks in subsea equipment. The results indicate that, for HPHT equipment with increased safety implications, a detailed elastic plastic fracture mechanics evaluation of the cracked geometry should be performed for cases in which localized plasticity is expected to occur.

Objectives/Scope This paper presents how a brazilian Drilling Contractor and a startup built a partnership to optimize the maintenance window of subsea blowout preventers (BOPs) using condition-based maintenance (CBM). It showcases examples of insights about the operational conditions of its components, which were obtained by applying machine learning techniques in real time and historic, structured or unstructured, data. Methods, Procedures, Process From unstructured and structured historical data, which are generated daily from BOP operations, a knowledge bank was built and used to develop normal functioning models. This has been possible even without real-time data, as it has been tested with large sets of operational data collected from event log text files. Software retrieves the data from Event Loggers and creates structured database, comprising analog variables, warnings, alarms and system information. Using machine learning algorithms, the historical data is then used to develop normal behavior modeling for the target components. Thereby, it is possible to use the event logger or real time data to identify abnormal operation moments and detect failure patterns. Critical situations are immediately transmitted to the RTOC (Real-time Operations Center) and management team, while less critical alerts are recorded in the system for further investigation. Results, Observations, Conclusions During the implementation period, Drilling Contractor was able to identify a BOP failure using the detection algorithms and used 100% of the information generated by the system and reports to efficiently plan for equipment maintenance. The system has also been intensively used for incident investigation, helping to identify root causes through data analytics and retro-feeding the machine learning algorithms for future automated failure predictions. This development is expected to significantly reduce the risk of BOP retrieval during the operation for corrective maintenance, increased staff efficiency in maintenance activities, reducing the risk of downtime and improving the scope of maintenance during operational windows, and finally reduction in the cost of spare parts replacementduring maintenance without impact on operational safety. Novel/Additive Information For the near future, the plan is to integrate the system with the Computerized Maintenance Management System (CMMS), checking for historical maintenance, overdue maintenance, certifications, at the same place and time that we are getting real-time operational data and insights. Using real-time data as input, we expect to expand the failure prediction application for other BOP parts (such as regulators, shuttle valves, SPMs (Submounted Plate valves), etc) and increase the applicability for other critical equipment on the rig.

This paper presents a solution for subsea storage of chemicals, where the conventional solid barriers between the chemical and sea water are replaced by a liquid layer, forming a liquid stacking tower inside a vertical tank. It can deal with most of the chemical formulations, providing a pressure balanced system based on barriers that are inherently damage-free. The storage units are easy to integrate and maintain as their design is simple. The benefits of the technology are discussed, also providing an overview of the ongoing qualification programme.

The offshore drilling industry is advancing technologies to extend deep water drilling technologies and attain feasibility of operations at deeper depths and higher pressures. However, shallow water operations themselves pose a certain unique set of challenges that need to be addressed with customized and innovative solutions. While shallow water poses certain benefits and conveniences to the operations, like ease of retrieval and better access to wells, there are significant challenges in terms of operational down time caused by limited operability and poor drilling riser and subsea hardware fatigue performance. Shallow water operations do not have the advantage of deep water drilling where the motions and loads imparted to the subsea blowout preventer (BOP) are relatively decoupled and damped out by hydrodynamic damping from the significant length of the water column. Thus, the vessel motions and wave hydrodynamic loads imparted on the riser are transferred to the wellhead and subsea hardware. In this paper the fatigue challenges encountered for drilling wells in 530 ft water depth from a sixth generation moored semi-submersible rig are explored. The fatigue loading is critical for the subsea tree connector which is characterized by a high stress amplification factor (SAF). Multiple riser space-out solutions were evaluated including fairings, helically-grooved buoyancy, joints with rope, and modifications to the telescopic joint each of which will be presented in the paper along with combination of different damping parameters to optimize the fatigue performance. The paper will present the subsea tree connector fatigue performance for different riser space-out options and make recommendations for future operations with similar conditions. Other challenges encountered in fatigue evaluation will be discussed. This will highlight the current assumptions and unknowns in data that can form the subject of evaluation for a future joint industry study.

In projects to develop offshore production in Brazilian pre-salt fields, an innovative model of subsea manifolds is being used, based on shared-actuation control (SAC) for the remote operation of valves. The control solution, which comprises the first full-electric robotic tool designed to operate in ultra-deep waters, has achieved an important mark in 2020, with the commissioning and start-of-operation of the first fabricated unit. In this article, we present lessons learned and discuss relevant specifications and programs of the technological development that contributed for the results obtained so far. Considering aspects on conception, technology, and environment of application, the pre-salt SAC required the adoption of new solutions on several disciplines of subsea engineering. As a typical case of technological development, the design process comprised decisions on engineering requirements and the establishment of a comprehensive qualification program. Now, after the first robot completing critical stages at field, such as subsea deployment, functional testing, and integration with the subsea system, we obtain a set of performance results that serve us to evaluate e.g. how effective were the selected technical specifications and testing routines, used throughout the engineering program. This discussion also provides possible adjustments in the overall development plan, considering its application as new generations of SAC arise. The commissioning in 2020 of the first robot resulted in its full integration with the subsea manifold and the correspondent production system, contributing to water-alternating-gas injection in the pre-salt field Tupi Extremo Sul. A second subsea system featuring the same model of robotic tool, for manifold control, is in advanced schedule in 2021 for integration in Búzios II, another pre-salt field in Brazil. Confirming the advantages that we could expect with the adoption of SAC in subsea equipment, the pre-salt SAC allowed a series of optimizations on design of the robot-controlled manifold. The robot tool replaced all the hydraulic actuators that traditional control systems, based on electric-hydraulic multiplexing, would require to implement remote controlling of the manifold valves. This led to a significant reduction on sizes and weight of the manifold structure.

Subsea flexible pipelines removal is subject to order restrictions, mostly caused by crossings. It is proposed to create a computational algorithm to design an optimal order of vessel intervention over a field. A real field was studied, and, from it, the mathematical base model was created upon graph theory, with great correlation with the minimum feedback arc set problem. Vessel movements were discretized and reduced to removal, reposition, and cut, leading to a state search. A-star algorithm was implemented to guide the search for the solution. Then, the complete algorithm was built, tested in a minimal environment, and finally applied to the real instance. To improve performance, a beam search filtering was envisioned, using seven ranking functions. Constructed model is suspected to be NP-hard, by correlation to minimum feedback arc set problem, leading to a large space search. Instances containing under 100 crossings were solved optimally, without needing any assistance. After implementing the heuristics and beam search, solution time was lowered by about 20 times, demonstrating the effectiveness of the technique. Also, ranking functions for pipe repositioning based on crossing count led to better results than crossing density. For cutting, an approximation based on feedback arc set was used. GreedyFAS was employed and gave satisfactory results. Bigger instances containing around 3000 crossings could not be solved optimally in a reasonable time, even with the heuristics. Improvements in A-star estimation function and bound the solution branches might lead to an optimal solution for these larger instances. Model proposed simplifies the operational order decisions and helps build the scheduling of operations. As it is based on state search, other aspects in logistics, vessel capacities and steps in decommissioning processes may be added, adjusting the neighboring weights and branching, keeping the same core.

Objectives/Scope The project was a 2km, electrically heat-traced, subsea pipe-in-pipe (PIP) system for transportation of a bitumen-like material across a shipping channel. Due to the viscosity of the bitumen, it must be transported at a minimum of 160°C; has a normal pipeline operating temperature of 200°C; and a design temperature is 228°C. Methods, Procedures, Process Due to the high operating temperature, pre-stressing and backfilling the PIP was required to lock in stresses at an intermediate pre-stressing temperature. The electrical heat-trace wires (installed to heat up the inner pipe and prevent setting of the bitumen during cooldowns) were used to achieve this pre-stressing during the fabrication process. The heating schedule causes high stress levels and require advanced engineering analyses to model the behaviour of the inner and outer pipe during the fabrication, installation, pre-stressing, and operation. The complex loading history of the inner pipe and the expansion spools was included in the global 3D, finite element (FE) models that were used to validate the pipeline profile, backfilling, pre-stressing temperature, and sequence of operations. Results, Observations, Conclusions The complex buckling behaviour of the inner pipe is presented and shown to be within DNV GL OS-F- 101 code limits. The end expansion during the various stages of pre-stressing is presented and compared to observed behaviour. The loads and stresses in the bulkheads are presented and shown to be acceptable. The analysis demonstrates that the pipeline system can be safely installed and operated up to the maximum design temperature of 228°C. Novel/Additive Information The project used pre-stressing by heating the inner pipe to an intermediate temperature before coupling the inner pipe to the outer pipe. The purpose of the pre-stressing was to manage the high axial stresses making it feasible to achieve the high design temperature of 228°C. Pre-expanding of the expansion spools at either end of the subsea pipelines was also used due to the space limitations. Innovative engineering analysis and construction methods were used to ensure the integrity of the inner pipe during the pre-stressing process and operation.

Wellhead connectors form a critical part of subsea tree production systems. Their location in the riser load path means that they are subjected to high levels of bending and tension loading in addition to internal pressure and cyclic loading. As more fields continue to be discovered and developed that are defined as High Pressure and/or High Temperature (HPHT) these loading conditions become even more arduous. In order to ensure the integrity of HPHT components, industry requirements for components are setout in API 17TR8. This technical report provides a design verification methodology for HPHT products and some requirements for validation testing. The methodology provides detail on the assessment of static structural and cyclic capacities but less detail on how to assess the functional and serviceability criteria for wellhead connectors. Similarly, API 17TR8 does not include prescriptive validation requirements for wellhead connectors and refers back to historical methods. This paper describes a practical application of the API 17TR8 methodology to the development of a 20k HPHT connector and how it was implemented to verify and validate the connector design through full scale tests to failure. A methodology was developed to meet the requirements of the relevant industry standards and applied to the connector to develop capacity charts for static combined loading. Verification was carried out on three dimensional 180° FEA models to ensure all non axi-symmetric loading is accurately captured. Connector capacities are defined based on API 17TR8 criteria with elastic plastic analysis (i.e. collapse load, local failure and ratcheting), functionality/serviceability criteria defined through a FMECA review and also including API STD 17G criteria including failure modes such as lock/unlock functionality, fracture based failure, mechanical disengagement, leakage and preload exceedance. These capacities are validated through full scale testing based on the requirements of API 17TR7 and API STD 17G with combined loading applied to the Normal, Extreme and Survival capacity curves (as defined by "as-built" FEA using actual material properties). Various test parameters such as strain gauge data, hub separation data, displacements, etc. were recorded and correlated to FEA prediction to prove the validity of the methodology. Further validation was carried out by applying a combined load up to the FEA predicted failure to confirm the design margins of the connector. Post-test review was carried out to review the suitability of the requirements set out in API 17TR8 and API STD 17G for the verification and validation of subsea connectors. The results build on previous test results to validate the effectiveness of the API 17TR8 code for verification and validation of connectors. The results show that real margins between failure of the connector and rated loads are higher than those defined in API 17TR8 and show that the methodology can be conservative.

The reliability of subsurface barrier valves has long been an industry problem. This can lead to costly interventions, especially apparent in deep-water subsea markets. This paper describes the world's first deployment of multicycle barrier valves in 2 subsea wells in Australia that uses innovative methods of both remote activation and triggering, that have been previously unavailable on the market, and attain a step change in reliability. The remote activated barrier valves were deployed as part of a subsea gravel pack system. They were initially run in hole (RIH) open as part of the lower completion, then closed mechanically. The valve was subsequently opened via Radio Frequency Identification (RFID) tags and then closed again mechanically to allow the running of the upper completion. Frequency modulated pressure cycles were applied to the well to open the valve and allow the well to flow. The valve functioned exactly as planned, and it was demonstrated that it could be closed multiple times on a semi-sub vessel. The valve was then opened via RFID tags conveyed on wash pipe. This is a much more reliable method when in high debris environments. The valve was opened for the final time via frequency modulated pressure cycles. These are better able to be transmitted through debris and are not affected by other hydraulic events in the well. The hydraulic pump that is used to actuate the tool provides a constant force directly to the ball valve mechanism and is not subject to failures over time like existing gas charges, ratchet mechanisms or springs. The RFID, Mechanical or pressure cycles used to trigger the valve offer a huge increase in operational flexibility that have never been able to be realized with existing technologies.

Positioning and installation of a floating production unit requires mobilization of necessary marine spread associated with comprehensive engineering preparation. Risk based rules and regulation define certain criteria as general guideline but to be firmed and verified based on risk assessment. This paper reviews the criteria in a tropical area with congested subsea facilities where the squall wind brings some risks to the installation and with subsea facility as already installed or wet-stored which makes the normal criteria more difficult to be met. With reference to a successful recent installation, procedure for the installation in terms of engineering assessment and operational works proposed. In this paper, risks and uncertainties with an offshore floating unit are presented based on marine spread with variation in their characteristics and reliability, mooring system characteristic and redundancy, engineering and installation team capabilities. Practical possibility considered to mitigate the given risks and based on that, positioning and installation criteria revisited against the general criteria as come from standard. Relevant engineering analyses are proposed with the type of results expected. As results, a practical procedure for an installation with recommended sequences, type and characteristics of marine spread and mooring equipment are provided. Some recommendations are provided for field development and overall project schedule to be considered in an early stage of a project to ease the installation phase and reduce risks and costs. Some key engineering analyses for station keeping and line transfer are proposed to verify capacity of the proposed installation spread against the possible environmental and operation scenarios. This paper provides some further clarity in terms of installation criteria and procedure for positioning and installation of offshore production units particulary for the spread moored system with reference to a successful installation campaign in tropical area subject to squall and congested subsea field.

Objectives/Scope Subsea production control systems are unique because they operate using electrical power and communications but in an underwater environment. Over time water ingress into an electrical distribution system can cause degradation of system electrical integrity. The objective of this paper is to show how these issues arise, to discuss methods for finding the location of integrity faults, and to give an example of how integrity faults can be located, what action can be taken to effect repairs, and how to mitigate against further recurrence. Methods, Procedures, Process Since it is not normally possible to determine the location of subsea electrical faults using visual methods alone, various other methods can be used such as Time Domain Reflectometry (TDR), Insulation Resistance (IR) measurements and branch isolations. In addition to the complexities of determining a fault location subsea, the situation is further complicated by difficulties in gaining access to potential subsea fault locations using divers or Remotely Operated Vehicles (ROVs). This paper will show the fault diagnosis procedures that were employed in determining the location of an electrical fault in a subsea production control system and will also discuss the issues and the procedures used in order to gain access to potential fault locations such as opening hatches and removing protection covers under water. Results, Observations, Conclusions The results of this work were the safe and successful location and remediation of the subsea electrical fault. The subsea production control system was restored to full operation and there were no HSE incidents during the work. The performance of the system continues to be monitored and analysed for signs of any new degradation. Novel/Additive Information This paper will present information that will be of benefit to others in the subsea industry who are facing electrical integrity issues in subsea production control systems. The benefits that can be gained are both in terms of testing strategies that can be followed and in potential new technologies that can be deployed.

Subsea jumpers are tie-in systems with a characteristic M-shaped geometry, employed to connect subsea facilities such as wellhead trees to manifolds. During well restart after a prolonged shut-down, subsea jumpers are exposed to a significant driving force for hydrate formation. Employing the recently-constructed HyJump flowloop, designed to mimic subsea jumpers operating at hydrate forming conditions, an experimental campaign was conducted to assess the influence of pipeline temperature, gas flow rate, liquid inventory, and inhibitor content on hydrate deposition during simulated shut-down and restart operations. In this work, we acquired baseline data on the gas sweep efficiency in HyJump for a wide range of gas restart velocities to characterize hydrodynamic behaviour in the absence of hydrates. Preliminary experiments were also conducted to evaluate the jumper operability in hydrate forming conditions. The HyJump flowloop consists of a test section connected to independent gas and liquid injection equipment at the inlet and gas separation facilities at the outlet which allows a continuous recirculation of gas and a once-through pass of the liquid. The test section has a complex geometry, with three identical low points and two high points with horizontal length of 12′ 10˝ and 7′ 7˝, respectively, and total height is 13′ 2˝. The test section is equipped with 12 pressure and temperature sensors regularly distributed, a MEG sensor in the second low point, a throttling valve downstream of the first high point to mimic the wellhead choke, and a viewing window at the outlet. In gas sweep experiments, each of the three low points was loaded with 1.6 gallons of water and natural gas at 1200 psi. During these tests, the pipeline temperature was maintained above 60 °F where hydrates are not expected to form. The system was maintained for six hours at a pipeline temperature of 41 °F (17 °F sub-cooling) for hydrate formation tests. Gas sweep velocities were varied in a range between 0.06 and 3 ft/s. The results illustrate that a superficial gas velocity of 3 ft/s was required to fully remove liquids from the jumper. However, gas velocities below 0.16 ft/s did not result in any substantive changes to the liquid inventory. Thus, low flow restart conditions could offer a significant driving force for hydrate formation in the jumper at low temperature. The preliminary gas restart tests conducted in hydrate forming conditions provided clear evidence of hydrate deposition at gas velocities below 0.16 ft/s. Hydrate formation in subsea jumper spools is poorly understood and a rare topic of discussion within scientific literature. This unique "HyJump" facility offers new insight to assist operators mitigate the risk of hydrate blockage by manipulating gas restart rates after well shut-down in the absence of (or with severely limited) chemical inhibition.

The award-winning Subsea Equipment Australia Reliability (SEAR) Joint Industry Project (JIP); is a partnership led by Wood with participation from a group of operators namely Chevron Australia, ConocoPhillips, Inpex, Santos, Shell Australia and Woodside. Now delivering Phase 6, the JIP is focused on collaboration and knowledge sharing in order to improve the competitiveness of Australia's oil & gas industry by addressing critical challenges associated with subsea equipment failing prematurely. This paper will provide an overview of the SEAR JIP and outline lessons learned, and value created. Results from the reliability database will be presented as well as findings from ongoing field trials on the four living laboratories deployed in different geographic locations and water depths in Northern Australia. This paper will also discuss challenges associated with subsea controls umbilicals that are prone to emit hydrogen gas and fluids at the surface facility through the electrical junction boxes. The end goal of SEAR JIP is to develop an industry wide recommended practice, with regional guidance notes for equipment and field design. The recommended practice is intended to reduce operating cost for existing and future projects, while identifying technologies that are specific to Australian waters.

Practical aspects and the application of lateral buckling mitigation for subsea pipelines with Residual Curvature Method (RCM) are discussed in this paper. The main purpose of this paper is to promote the RCM in the Asia Pacific region as a practical and a cost-effective alternative to the existing buckle initiation methods for subsea pipelines. The RCM is assessed and compared with two existing buckle initiation methods (i.e. sleeper and zero-bend radius) using finite element analysis. The build-up of the effective axial force is the key driving mechanism in inducing a buckle in the pipeline. The effective axial force builds up along the pipeline with buckle length and the critical buckling force for buckle mitigation methods mentioned above are presented for comparison. Some practical aspects and design considerations of the RCM are also discussed. The local residual curvature section, which so far has been applied with reel-lay vessels can be implemented with S-lay vessels as a buckle mitigation scheme. Discussion on a proposal to consider the use of RCM with S-lay vessel is also covered. Additionally, the advantages and disadvantages of RCM are compared with respect to the technical challenges, the construction cost and time, handling operations and installation. This paper shall provide some good exposure to practising engineers and local/international operators in the Asia Pacific region with a relatively new and efficient method for lateral buckling mitigation and has, to date, been utilized for shallow water pipelines installed by reel-lay vessels.

The Deepwaters of the US Gulf of Mexico are traditionally the province of the major international oil companies. Independent exploration and operating companies who make discoveries face more difficulty in finding viable options to developing and exploiting their found reserves. Many parts of the offshore industry have worked diligently to find ways to cut development costs for the Independent Operator. In addition to cost, an Independent Operator that is unable to finance its own development faces additional risk in finding options to exploit a discovery. It is here where an independently operated Midstream solution may benefit the Independent Operator. The authors propose examining existing business and operating models in which a Midstream approach may be applied in order to provide wholly independent gathering solutions in Deepwater. The concepts that make such a solution different from other field developments are explored including the business model of how this solution may be sponsored, financed and operated.

The integrity of subsea pipelines is required to be verified through external surveys and inline inspection to ensure safe operation. If free spans based on external subsea inspection exceed the design calculated allowable free span length, free span corrections are performed by placing grout bags or mechanical supports along the span. However, as free span corrections are very costly, therefore, further free span assessment should be performed prior to any subsea intervention. An alternative approach of "local free span analysis" is proposed to optimize the free span corrections. Local free span assessment can be performed for each survey span exceeding allowable span length taking into consideration the relevant input data applicable for the specific free span location rather than for a section of the subsea pipeline. It shall be noted that during design phase, allowable free span lengths are calculated by dividing the total pipeline length into segments, and for each segment the worst case input data is conservatively taken. On the contrary, local free span analysis approach considers key input factors such as effective axial force, wave and current (environmental) data, water depth and pipe-soil interaction parameters pertinent to explicit span location. Local free span analysis has been successfully applied for free span assessment of a number of operating and new subsea pipelines. This paper will present case studies where revised allowable free span lengths have been calculated prior to previous approach of direct subsea intervention and highlight the associated benefits. Local free span assessment approach will significantly reduce the number of required free span corrections especially for long length subsea pipelines. The optimization of free span corrections will result in significant cost savingsas well as schedule improvement.

A new technology called Local Heating offers the possibility of significantly raising the temperature of the multiphase production fluid in order to improve flow assurance and consequently the economics of field developments. Heating the flowlines is a way to overcome the thermal constraints, mitigate hydrate & wax risks and provide operational flexibility. Indeed, in the case of long tiebacks, very deepwater applications or when the fluid temperature at the wellhead is too low, conventional flow assurance solutions might be very expensive or even not applicable. While other heating technologies such as DEH and Heat Tracing have been designed mainly to operate under transient operations (start-up, shutdown, preservation), this heating technology can be operated continuously during production and also during transient operations as long as there is fluid circulation in the flowline. The device is a very simple and robust system integrated into a compact subsea module, installed in parallel or in-line with the main flowline and which can be retrieved for maintenance or relocated. It is compatible with any type of field architecture and can be implemented either on greenfields or brownfields. In the case of greenfields, the use of Local Heating could also be a way to mitigate uncertainties on production fluid temperature or solve an unexpected poor thermal performance of the design. This solution is based on induction and is therefore able to provide very high-power levels (several MW) with a compact module. The temperature is continuously monitored throughout the heating module by means of fiber optic distributed sensors. The technology is fully compatible with preservation by flushing and allows pigging in the event of deposits. The main principles of the technology will be described in the paper, as well as a preliminary design performed for a specific case provided by an operator. The paper will also present the qualification work recently performed including heating performance lab tests using a small-scale submerged prototype operated under atmospheric conditions with multiphase fluid. The tests have confirmed the good electrical and thermal behaviour of the system. The paper finally describes the last qualification phase the objective of which is to install a subsea pilot to be connected to a subsea production system on a field located in Brazil. The intention is to perform this work in the frame of a Joint Industry Project.

In recent years, monitoring of the subsea BOP in order to keep track of movements, loads, and fatigue accumulation on subsea wellheads has been performed. On the Norwegian Continental Shelf, more than 50% of the semisubmersible drilling rigs have equipment for measuring the motion and load on the subsea BOP. A typical setup is to have motion sensors installed and calculate the loads on the lower part of the BOP and the subsea structure from indirect methods where knowledge of system parameters such as tension, weights and drag coefficients is used to establish the loads. Direct measurement of the load using strain gauges or LVDT's has proven challenging due to time consuming installation, fragile measurement equipment, and difficulties finding suitable areas to mount the sensors. The objective of this paper is to present a novel sensor technology that allows for accurate measurement of strains in a wide measuring range. In contrast to existing measuring equipment this new sensor technology enables a compact, robust, and easy to install strain sensor. The new sensor is small enough to be mounted behind the bolts/ nuts on an 18 ¾″ BOP flange neck. The sensors can be used to increase the accuracy and reduce unnecessary conservatism in the measured wellhead loads. This can again reduce the need for expensive load reducing measures or disconnects. This paper will present the core principles of the new strain sensor. Laboratory tests showing the performance and accuracy of the sensor will be shown, and the benefits of this sensor versus existing technologies will be demonstrated. The introduction of this new sensor enables direct measurement of the loading on the subsea wellhead system. The new measuring process will be presented and compared with the traditional indirect measurement process. This comparison will illustrate where in the measuring process increased accuracy and reduced conservatism can be achieved, and then quantifying the improvements. Further, the paper will present results from use of the sensor in actual measurement campaigns from drilling operations in harsh environment on the Norwegian Continental Shelf. The paper will present the findings from the first measuring campaigns using this new sensor technology. The measured results will be compared with the traditional indirect measurement method and the improvement, in terms of reduced conservatism and increased accuracy, will be shown. Then finally, the consequence in terms of reduction on measured extreme and fatigue load, will be presented. This paper will show how new sensor technology can be used to obtain more accurate and less conservative measurements of the loading on a subsea wellhead system in order to reduce the need for expensive load reducing measures.

This paper focuses on the benefits of removing existing control boundaries between subsea system components/parts and the automation setup located topsides on the platform (or onshore). The paper describes the communication architecture of existing subsea control systems used today and proposes a new architecture with boundaries removed. This new setup would utilize the same physical (i.e. fiber-optic) communication channels as present systems. For illustrative purposes, a use case for the proposed system will be presented on an anti-surge setup for a subsea pump/compressor. Existing subsea control systems today are intended for and used to control hydraulic valves in subsea production setups. The design and behavior of these systems make them not optimal for anti-surge control (among other applications). Interfaces and communication protocols used in the proposed use case are based on open industry standards, resulting in a vendor-agnostic system with no proprietary or company-specific solutions, and no boundary between the subsea and topside/onshore located parts. Potential benefits of the proposed system would include reduced latency, along with the combining of several measured values for increased accuracy over a larger scale, illustrated with an anti-surge example. This could enable operators to realize cost savings through optimization and increased production over the life of the installation. As the paper will describe, the system also has the potential to reduce both CAPEX and OPEX.

The objective of the campaign was to safely and efficiently complete a plug-and-abandonment (P&A) operation in a harsh Norwegian North Sea well using a high-performance conductor-recovery tool. The operation used the newly reinvented, second generation mechanical, outside-latch, single trip (MOST) tool system. Along with recovering the subsea wellhead, the associated casing strings and conductor were to be cut and retrieved. The standard MOST tool is a field-proven system, which latches externally to the wellhead, then cuts and recovers subsea wellheads. The newly released second generation system is a reinvented P&A tool that includes several innovative technologies to increase tool capabilities and performance. The latest release of the MOST tool includes a newly designed tension-cut mandrel, nonrotating flexible stabilizer (NRFS), large-diameter cutter, and high-angle knives. The system confirms the cut without the need for tripping, easily latches and releases to inspect the cutting knives, and does not cause damage to the internal wellhead sealing profile. Furthermore, the external-latch mechanism helps to prevent swarf buildup by allowing more flow area in the high-pressure wellhead, which permits the cuttings to easily exit. The latch and unlatch function can also be visually confirmed using a remotely operated vehicle (ROV) on the seafloor. External latching provides superior lateral support for the wellhead assembly to eliminate any lateral whipping that might impede cutting. The second-generation design of the MOST tool, with the tension-cut mandrel, provides pulling capabilities up to 1,000,000 lb (453,592 kg) and fail-safe features, which enable the outside latch to be released by the ROV, if needed. The newly deployed system successfully recovered multiple subsea wellheads in Norway and demonstrated its operational effectiveness with reduced cutting times compared to traditional cut-and-pull operations. With advanced features, the subsea wellhead-retrieval system reduces rig time by cutting and retrieving multiple cemented or uncemented strings in a single trip. The NRFS and large-diameter cutter increase stabilization and minimize vibration during cutting, and the high-angle knives increase cutting efficiency when compared to traditional retrieval systems. The MOST system supports quick wellhead recovery, minimizes operational expenditure, and reduces rig time. The new developments to the next generation MOST tool system give the customer several additional application choices. The various interchangeable components allow for a wide range of cutting options including abrasive cutting, tension cut, motor cut, and umbilical support for laser cutting.

Mobile mudmats are increasingly adopted as foundation solution for subsea structures in offshore field developments, to allow their horizontal movement under the cyclically imposed expansion/contraction operating loads from the connected lines. The foundation compliance grants the dissipation of the applied loads while the structure slides on the seabed and the required base dimensions are reduced. Foldable solutions can even be installed integrated with the related lines, passing through the pipelay vessel tower. The described experience is based upon design and installation of mobile mudmats for subsea structures in the last twenty years of activity in several deepwater areas all over the world. The design has been improved with time and its robustness has been demonstrated using alternative analytical approaches and Finite Element Model of the system with proper definition of soil-foundation behavior through equivalent springs. The geotechnical engineering effort focused to ensure the foundation adequate bearing capacity and its ability to slide under repeated thermal/pressure expansion loads during design lifetime, without developing excessive settlements and pitch/roll unacceptable rotations that could compromise the system performance. The purpose of the present work is to raise awareness of the need for reference international criteria for the design of mobile foundations, which represent an important solution for a subsea field development. Available Codes and Standards do not cover the relevant aspects of the mobile foundation engineering: they are based upon fixed foundation concept, which is expected to be stable under all the applied load combinations without developing any significant displacement. The mobile foundation engineering challenge is to accept that a failure mechanism develops in sliding condition while proper design criteria of system stability and reliability are fulfilled. Valuable and impressive research works have been carried out and published on the subject in the recent years. However, for practical application, specific criteria are required to provide a unique basic reference for design (minimum safety requirements/methodology/guidelines), which might be supported or not by more detailed and complex approaches, as occurs for traditional "fixed" foundations. Subsea structures could be regarded in the future as special components of the pipeline with a proper methodology to investigate their interaction with the seabed for the subsequent structural analyses.

The Intervention and well P&A are considered high-risk and complex operations that must be carried out in a fully managed and controlled environment. This can be achieved through enhancing the existing intervention systems or introducing new solutions. The intervention riser system and the riser-less open-water abandonment module introduce new technologies that will expand today's operating envelope to deeper and higher temperature environments while maintaining costs and risks firmly under control. Improved synergies can also be achieved through new alliances when different types of operating assets are lumped together, delivering seamless service through integration.

The paper seeks to address the challenges faced by High Pressure High Temperature (HPHT) subsea pipelines buckling mitigations and presents a new innovative solution that was evaluated from 2012 to 2016 and first deployed in 2017 then surveyed in 2018 after almost 6 months of operation. Laboratory tests, field tests, small scale tests, full scale tests, analytical derivations and finite element analyses were developed and used to mature the rotating buoyancy technology configuration as a new innovative solution. High pressure and/or high temperature subsea pipelines may experience lateral buckling which require special considerations to mitigate excessive plastic deformation and fatigue during start up and shut down cycle events. One of the widely used mitigation consists of attaching fixed buoyancy modules on engineered sections of the pipeline system. However, postproduction subsea surveys and engineering evaluations showed the currently used buoyancy mitigation methods create large soil berms that may significantly reduce pipeline fatigue life and the opportunity of life extension of the pipeline system. The rotating buoyancy system was developed to help solve this problem and increase the solution robustness to enable potential life extension and possibly reduce the stringent welding requirements at the buckled sections. It represents a step change in the way risks associated with buckling of high temperature and/or high pressure pipelines are managed and effectively mitigated. Between year 2015 and 2016, small scale and large-scale tests were performed using prototype fixed and rotating buoyancy modules to compare the current and new mitigation methods. This paper outlines the methods by which pipe-soil interaction can be simulated. It describes the validation and verification conducted, through experimental testing on both newly developed small-scale and large-scale testing rigs, coupled with computational modelling and analytical predictive calculations. The paper highlights the challenges faced when replicating seabed conditions and pipeline movements. It also highlights novel design aspects which offer improved traction in soft clay environment. The paper also presents the lessons learned during the 2017 offshore installation campaign and the 2018 results of the in-situ survey of the rotating buoyancy modules after the first 6 month of operations and future plans for next generation rotating buoyancy systems including digitalization. The subsea rotating buoyancy is a novel simple system deployed to provide a robust mitigation of subsea pipelines lateral buckling. It provides opportunity for potential increase of subsea pipeline life extension and potentially helps decrease the stringent welding requirement of the pipeline at the buckled sections.

A major operator in the Norwegian continental shelf recently implemented an improvement program focused on increasing standardization and efficiency on subsea well operations. By including a Vertical Christmas Tree (VXT) rather than a Horizontal Christmas Tree (HXT) in their subsea completion design, several wells can be batch completed with a rig. VXT Installation can then be completed with an Installation, Maintenance, and Repair (IMR) vessel, eliminating the need for a Rig or Light Weight Intervention (LWI) vessel. In order to use an IMR vessel for VXT installation, a new method needed to be developed for the establishment/removal of a temporary second barrier between the well and subsea completion. The goal was to achieve a barrier valve solution that would be installed as part of the completion string. Furthermore, without requiring intervention via wireline or an LWI, it would accomplish three positional phases: open, closed, and then open again. The tool would be installed in the open position, allowing for all standard completion operations to be conducted. For example, lighter fluid could be pumped into the tubing prior to setting a packer, allowing for bull heading in a well control situation. By incorporating the valve into the completion string and ensuring the well design and operation is planned accordingly, wireline intervention can be entirely avoided The more common methods for suspension and initiation of subsea wells during BOP removal and VXT installation include installing shallow set bridge plugs in the tubing and/or a tubing hanger plug. The intervention plugs would then be removed using a riserless LWI vessel. This method is often associated with high cost and enhanced operational risk. A technology group was assembled in order to close the technical gaps inhibiting a fully intervention-free operation for completion installation. Technology personnel from both the operator and service company worked together closely to develop a glass plug solution that met all the necessary requirements needed to overcome this challenge while still minimizing associated risk. The proposed solution is a barrier valve to be integrated as part of the completion string; using glass plug technology, it will accomplish three positions: open, closed and then open again. The glass plug will first be installed with the bypass ports in open position, allowing for standard completion activities to be conducted. For example, an operator would still be able to accomplish bull heading in the event of a well control situation. The bypass is shifted to the closed position after a predefined number of tubing pressure cycles have acted on the glass plug system. Once the bypass is closed a ISO14310 V0Q1 well barrier is established. The glass plug barrier is only shattered after the tubing above the glass has been subjected to a predefined number of pressure cycles while applying a specific overbalance. After, the barrier element has shattered the valve it activates its final open state, resulting in full bore ID through the valve. This was developed and qualified according to ISO 14310 V0Q1 / ISO 28781 V1Q1 and installed in less than a year. By utilizing this glass plug the drilling rig can batch complete subsea wells and at a later stage batch install the VXT with an IMR vessel. The product can also be installed as part of conventional completion string were shallow barrier is required, eliminating the need of intervention. By implementing this technology, the operator saves time and cost addition to reduced HSE exposure associated with well intervention.

Produced water is the largest volume waste stream in oil and gas production and is a particular problem for late-life operation of oil fields. The huge waste volumes result in two obvious consequences and cost drivers; fast declining reservoir pressure and tremendous power used to handle it. Produced water reinjection has been used as a main strategy for both managing produced water volumes and supporting reservoir pressure. Treating produced water subsea as close as possible to the production wells has several advantages such as smaller topside footprint, minimizing the energy demand and associated emissions, reducing the well back pressure and increasing production rates. While some work has been done in the past on subsea use of deoiling hydrocyclones, robust high performance subsea produced water treatment equipment and processes have not yet been made available. The Compact Flotation Unit (CFU) is a well proven technology for topside use and has been considered promising for subsea use, but never before been tested at subsea relevant pressures. Aker Solutions with partners Aker BP, Equinor and Total and support from Research Council of Norway have successfully run a joint industry project to qualify this technology for subsea application. Pilot testing of a subsea CFU was carried out in Equinor's large scale test facilities in Porsgrunn, using crude oil, natural gas and synthetic produced water. The pilot CFU was tested with pressures significantly above that used for conventional topside CFUs, and at various temperatures. Gas bubbles were injected by use of ejectors designed to provide the desired bubble size. Oil droplet size, flow rate and oil in water concentration were the major control variables in addition to pressure and temperature. The effect of injection of flocculant was also investigated. The main topic of interest was the oil removal efficiency of the CFU under high pressure. The analyses of the results showed that the CFU's efficiency improved with increase of the operational pressure. This was likely to be related to the changes of physical properties of gas, oil and water as pressure increases, and the changing balance between physical phenomena in the process. The CFU also demonstrated robust performance with a large turndown ratio. Test of flocculant at high pressure showed instant and substantial improvement in the CFU efficiency, and the effect of flocculant was not compromised by the high pressure. The promising results suggest that CFU performs well at elevated pressure and is a viable solution for subsea produced water treatment.

Cost reduction, deep water, long-step outs, HSE (Health, Safety and Environment) and reduction of carbon footprint drive the change from hydraulic to all-electric subsea control systems in the offshore oil and gas production. The main challenge of an all-electric control system is the safe and reliable actuation of the valves on the tree. A battery provides the power and energy to supply the electric actuators to close the valves in case of an ESD (Emergency Shutdown). The paper presents the qualification program developed to access the performance and safety over the design life of 25 years together with the results after a 3-year qualification program. The qualification program was based on a risk assessment taking into consideration the uncertainties associated to this novel subsea technology and the API 17F for qualification requirements. The qualification program developed covers the following main sections: Misuse (destructive testing), Cycle Testing, Environmental Testing and EMI (Electro-magnetic Interference) testing. To access the state of health a large signal EIS (Electrochemical Impedance Spectroscopy) has been developed and applied throughout the qualification program together with the DC-resistance and capacity measurements. For the cycle testing a DoE (Design of Experiment) methodology has been applied to develop a test plan which includes the parameters: temperature, cycles and idle time. The testing was performed on 30 cells in parallel. The qualification results show a degradation of the battery depending on the parameter sets. The EIS measurements correlate with the degradation of the battery performance. The testing parameters range from −4°C to 50°C to stimulate an increased degradation. A reference group was used to access the acceleration factor for the increased temperature. The DC (Direct Current) measurements show an increase of the internal resistance over time. The results provide details for a qualification program for subsea batteries in order to access the performance over the lifetime of 25 years. The program includes additional testing and monitoring compared to the API 17F requirements for PCBs (Printed Circuit Boards). The qualification program also provides information about the degradation kinematics of Li-Ion Batteries over the design life of 25 years. Based on the results of the qualification program a design life of 25 years can be concluded.

Maximizing the use of existing topside facilities is an attractive approach to reduce project CAPEX and therefore unlock new reserves. However, as the tieback length to the host increases, technical and economic challenges arise. These include flow assurance, and costs of the umbilical and flowlines which inherently increase with length. These aspects, together with others independent from the length, such as power and space availability, have a significant impact and could result in making the project unfeasible or uneconomical. Technologies developed in recent years, or in their final stage of qualification, play a significant role, not only in solving the technical challenges, but also in finding cost-effective configurations, either by reducing and/or staggering capital and operational expenditures or by extending reserves recoverability or also by reducing significantly the risks associated with a development. In order to appreciate these advantages, different configurations have been outlined starting from those allowed by the conventional technologies and comparing them to the ones enabled by the new technologies. Actual advantages of each technological "bricks", considered alone or in synergies, depend on the specific projects and can be identified in a timely manner thanks to early engagement of Contractor in the architecture and associated pricing of subsea tiebacks. The paper will present a platform of technologies, their maturity status and how they can be integrated in novel architectures in an economic manner. Such technologies include: Boosting Distributed and local heating Subsea water treatment and injection Subsea separation Subsea chemical storage and injection All electric control system Local power generation

Valves and actuators are key building blocks to realize subsea processing plants. Both isolation and control valves are key elements for operating processes such as water treatment and injection, boosting and separation. In order to increase the performances and to eliminate the hydraulic lines within the umbilicals, a retrievable configuration to drive both types of valves sharing the same electric actuator has been developed.For a subsea water treatment application, and to manage its backwashing function, a dedicated development and qualification plan has been implemented, to cater for the associated high number of cycles.This requirement was new considering that common subsea applications call for a total number of actuations in the order of around one hundred, while to implement these backwash sequences, isolation valves need to be capable of thousands of complete cycles and control valves of hundreds of thousands of small adjustments.This paper addresses how the design of subsea valves and actuators has been qualified to TRL4 through both analysis and test campaigns on dedicated prototype units in compliance with API 17N or DNV RP A203, API 17F, API 6A and API 17D.Saipem performed a market review to map the existing technologies and understand potential gaps against the needed performances for isolation valves, control valves and relevant actuations. Based on the results of this review, the key providers were selected to undertake the technology qualifications required to close the identified gaps.Working in team with the technology providers, three dedicated technology qualification plans were defined to ensure the suitability of each technology. The activities identified in these plans include both analyses and performance/endurance tests on prototypes. These activities were considered to mitigate risks associated with the failure modes identified during the FMECAs.The envelope of the performance set as the basis of each technology qualification plan allows the extension of the deployment of these technologies in different subsea processes.The isolation valve qualification plan was successfully completed in 2018, while the control valve and the electric actuator qualification plans will be completed by end of 2019, establishing a new reference for the utilization of subsea valves in complex subsea processes, such as subsea water treatment and injection systems or subsea separation systems.The presentation and paper will introduce the elements of novelty and will describe the process, the challenges and the results of the technology qualification.The technology qualification plans will be presented, including the initial readiness level assessment, the outcomes of the FMECAs and the qualification activities, which include:high-cycling isolation valves: analyses, mock-up tests, prototypes hyperbaric and endurance tests; high-cycling control valves: analyses and endurance tests; high-cycling all electric actuators analyses, mock up tests, temperature of electronic boards, pressure, shock and vibrations tests (API 17F) and prototype functional and endurance tests.

The world's first full-scale subsea plant for production of sulphate free or low salinity water for IOR and EOR purposes has been designed, procured, constructed, and commissioned. This has been achieved with the involvement and support of an original equipment manufacturer, the Norwegian Research Council, and several offshore oilfield operators. The full-scale subsea treatment plant has undergone qualification in accordance with API 17N, and this paper shares key design aspects of the plan, operational experience, and the water quality results achieved. Subsea seawater treatment for water injection has several inherent advantages compared to topside treatment. One significant aspect is the increased flexibility afforded to reservoir engineers in improving effective reservoir management by providing the opportunity to implement any desired water injection capacity, anywhere and anytime. In addition, the ability to provide 'tailor made' water for injection into oil reservoirs is seen as a game changing opportunity for offshore oilfield production companies wishing to produce more, produce faster, and produce cheaper. The process advantages of the seawater treatment plant being on the seabed allows for a design that is simplified compared to a corresponding topside plant. This system design is explained in the paper and how it translates into improved reliability and availability. The all electric design also has the capabilities to be installed, moved, and reused on the seabed with minimum impact on topside infrastructure. This paper provides information that has not been presented before about the novel subsea seawater treatment process. It shares commissioning and operational knowledge gained during a six month test period and includes water quality results achieved at progressive points through the treatment plant. The ability to operate a water treatment plant on the seabed necessitates instrumentation and control that provides good condition monitoring of equipment and the ability to check and control water quality. The novel methods that have been employed and tested on this treatment plant are discussed. The treatment plant has been fully tested and is now available to clients for installation and operation on an offshore field. Lessons learnt are shared along with showing how the treatment design can be used to provide high-quality water on a wide range of field applications at any stage of a field's lifetime. There are several aspects of the design that reduce the health, safety and environment (HSE) impact of water injection in general, including; lower power consumption (reducing carbon footprint) and no (or significantly reduced) liquid chemical requirement; hence, lower handling exposure for operators.

Quantitative prediction of gas hydrate formation risk is critical for the successful implementation of risk-based approaches to hydrate management in subsea production. Here we use a high pressure, stirred, automated lag-time apparatus and a high pressure acoustic levitator to experimentally obtain smooth probability distributions describing stochastic hydrate formation. Robust, repeatable hydrate nucleation and growth rate probability distributions as a function of induction time and subcooling are measured for various gases, shear rates and inhibitor dosages in systems with interfacial areas ranging from (0.1 to 60) cm2. The results reveal that new engineering models can be used to reliably predict hydrate formation probability. Importantly these new models have solid theoretical foundations which enables them to be generalized with confidence to industrial systems.