Today, the gas associated with oil production is becoming an environmental concern for existing fields when it is flared. There are substantial quantities of associated gas still burnt at fields every year. When offshore, the reinjection of such associated gas into the reservoir is not always technically feasible, it is expensive, and may become a blocker for new offshore oil developments. Associated gases can be monetized in the form of LNG produced directly offshore, it can become an enabler of new oil projects, and a means to reduce CO 2 emissions and meet commitments. LNG production at sea can be achieved at a competitive CAPEX, by using an innovative mega-module concept. Furthermore, when treating rich associated gases, the production and export of high-value liquid by-products - LPG and condensates and even possibility ethane - can greatly improve the economics of LNG production itself by creating additional revenues, at a marginal increment cost thanks to the integrated process and utilities functionalities, while keeping the possibility to adjust to several LNG market specifications.

Pipelines are coated with insulating material that minimizes heat losses to the environment. Reeled pipe can experience nominal bending strain in the order of 1% to 2%. Thick coating on the pipe is inherently more highly strained, because of concentrations that occur at the interface between parent coating and field joint coating. Occasionally, contractors who specialize in pipe-lay using the reeling method have experienced difficulties relating to unexpected disbondment and cracks in coating at these interfaces. Any disbonded coating is routinely identified and repaired, but it is important to understand the influential factors that could lead to this type of coating disbondment. It is known in the industry that parameters such as temperature, reeling speed and pipe tension are influential but the relative influence of the factors is not well understood. In addition, there is currently no industry code or recommended practice that proposes the strain levels that the coating could safely withstand prior to cracking. This paper addresses thermo-mechanical aspects of coating design and presents a novel approach to quantify which parameters have the largest influence. In the presented assessments, coating strain was assessed using finite element analysis. Material input was selected from a combination of typical values and specific laboratory test results for polypropylene (PP) and injection molded polypropylene (IMPP). An essential aspect was that the mechanical and thermal properties of the PP were related to temperature and strain rate. Strain rates in the coating during reeling operations were obtained from global FE models. Detailed local FE models incorporated all the material and load inputs and temperature conditions that are necessary to determine peak strain values in the coating; the peak strain values would indicate the locations of potential coating disbondment. The study is purely a strain assessment and excludes any potential for defects or delamination in the coating that could result from its manufacturing process. This strain-based study revealed that coating temperature during reeling is the most influential factor on strain level in the coating. Reeling speed and pipe tension are parameters providing secondary influences.

Pipeline corrosion is a major identified threat in the offshore oil and gas industry. In this paper, a novel computer vision-based digital twin concept for real-time corrosion inspection is proposed. The Convolution Neural Network (CNN) algorithm is used for the automated corrosion identification and classification from the ROV images and In-Line Inspection data. Predictive and prescriptive maintenance strategies are recommended based on the corrosion assessment through the digital twin. A Deep-learning Image processing model is developed based on the pipeline inspection images and In-Line Inspection images from some previous inspection data sets. During the corrosion monitoring through pipeline inspection, the digital twin system would be able to gather data and, at the same time, process and analyze the collected data. The analyzed data can be used to classify the corrosion type and determine the actions to be taken (develop predictive and prescriptive maintenance strategy). Convolution Neural Network, a well known Deep Learning algorithm, is used in the Tensorflow framework with Keras in the backend is used in the digital twin for corrosion inspection. CNN algorithm will first detect the corrosion and then the type of corrosion based on image classification. The deep-learning network training is done using 4000 images taken from the inspection video frames from a subsea pipeline inspection using ROV. The performances of both the methods are compared based on result accuracy as well as processing time. Deep Learning algorithm, CNN has approximately 81% accuracy for correctly identifying the corrosion and classify them based on severity through image classification. The processing time for the deep-learning method is significantly faster, and the digital twin generates the predictive or prescriptive strategy based on the inspection result in real-time. Deep-learning based digital twin for Corrosion inspection significantly improve current corrosion identification and reduce the overall time for offshore inspection. The inspection data loss due to the communication interference during real-time assessment can be eliminated using the digital twin. The image data can recover the required features based on other features available through the previous inspection. Furthermore, the system can adapt to the unrefined environment, making the proposed system robust and useful for other detection applications. The digital twin makes a recommended decision based on an expert system database during the real-time inspection. The complete corrosion monitoring process is performed in real-time on a cloud-based digital twin. The proposed pipeline corrosion inspection digital twin based on the CNN method will significantly reduce the overall maintenance cost and improve the efficiency of the corrosion monitoring system.

Objectives/Scope Deposition inspection sensor based on electrical tomography has been proposed recently. In this work, a next generation electrical tomography sensor is introduced and a novel mathematical approach for the estimation of the deposit thickness is described. It is essential for the pipeline operators to keep the lines open for smooth flow and high flow efficiency. Deposit thickness, deposit type and location of deposit is required for optimal pipeline cleaning. The usage of chemicals as well as number of cleaning pig runs can be optimized based on the information that intelligent pig is giving. Methods, Procedures, Process In electrical tomography, electrodes are attached on the surface of the sensor and excitations are applied to some electrodes and responses are measured from other electrodes. The electrical properties of the medium are estimated based on these measurements. In pigging applications, the distribution of electrical properties between the PIG surface and metal pipe is estimated. The thickness and type of deposit (wax/scale) can be identified from the estimated electrical properties. In the proposed approach the estimation of the parameters is done by using a novel deep neural network based approach. In practice, number of measurements that are analyzed after each PIG run can be hundreds of thousands. The neural network based approach was chosen in order to achieve reasonable computational efficiency (computation time) in real applications with large amounts of data. Results, Observations, Conclusions The introduced sensor is for 12-inch lines and designed to be used when the oil line is filled with water. This sensor was tested in a laboratory test line with artificial deposit samples. After these tests and calibration, the sensor is deployed to be used in real pipe line inspections. The major challenges in pipe line runs include the movement of the sensor during measurements, electrical noise and changing excitations. In the neural network model, the position of the PIG is estimated simultaneously with the electrical properties and the effect of all these aforementioned uncertainties are also modelled. Based on the results conclusions can be drawn on the efficiency and performance using neural networks and the high suitability of electrical tomography for deposit mapping. Novel/Additive Information In this study, it is shown that intelligent pig based on the electrical tomography can be used reliable for deposit inspection. Furthermore, the computation approach based on the deep neural network is computationally efficient and it is tolerable for measurement noise and other uncertainties in real measurements.

Since 2007 the traffic volumes in the arctic seas have substantially increased, especially in the North-East Passage following the development of major oil and gas projects. In development of icebreaking LNG tankers the selection of propulsion system is playing a major role determining the vessel performance, safety and icebreaking capability. Recent success of YAMAL LNG project has led to accelerated development of new arctic LNG projects, such as Arctic LNG2. This paper will introduce some outstanding operational results from the revolutionary icebreaking LNG Carriers with modern azimuth propulsion system. This paper describes the methodology to use remote diagnostics systems (RDS) onboard ice-going LNG carriers to continually record, consolidate, upload, and analyze ice-breaking propulsion performance. We will further describe how vessel operational experience and RDS data can be used in development of icebreaking LNGC propulsion design and product development. The special focus in this paper will be given on propulsion system of large Arctic LNGC equipped with 3 × 15 000 kW azimuth thruster units. These propulsion devices help ship owners to access opportunities in the Arctic areas by providing safe and reliable operation in the region. Paper will highlight some of the key findings from the ship machinery data collected with RDS (Remote Diagnostic system) and further analyzed by engineer specialist in view of ice loading on machinery system and components. Podded propulsion solution has played major role on Arctic ship projects, making these challenging projects technically and economically feasible. We will present latest findings and unique results from Arctic LNG carriers, which is valuable information in development of future Arctic oil and gas transportation in the Northern hemisphere.

Reel-lay installation is one of the most effective methods for subsea pipeline installation. Pipes subject to reeling installation experience cyclic plastic deformations and tight control of the yield strength range, yield strength to ultimate tensile strength ratio (YS/UTS) and uniform elongation values is required on the delivered pipe. Double Submerged-Arc Weld (DSAW) pipes formed from Thermo-Mechanically Controlled Process (TMCP) plates do not normally exhibit the minimum requirements for plastic strain requirements such as minimum YS/UTS ratio or uniform elongation values. This paper describes a process for increasing the reelability of DSAW pipes. This has been achieved by induction heating of DSAW pipe ends to normalise the mechanical properties at pipe joints. The mechanical properties of the treated section have been measured and verified against design rules for reeling, based on industry standards such as DNVGL-ST-F101 [Ref. 1 ] and TechnipFMC supplementary requirements. The improvement in mechanical properties is measured by comparison with the as-manufactured properties of adjacent sections. A commercial study demonstrates that the locally heat-treated DSAW pipe is a cost-effective alternative to seamless pipes for reel-lay installation.

This paper is a companion paper to OTC 28671, titled "Experience with Interface Shear Box Testing for Axial Pipe-Soil Interaction Assessment on Soft Clay", and presents a similar range of experience and best practice recommendations for geotechnical laboratory testing to determine soil properties relevant to pipeline-seabed friction on sandy seabeds. The paper is underpinned by a new database that demonstrates the driving parameters that influence interface friction in granular materials. By accurately quantifying shear resistance along the pipe-soil interface under low normal stresses imposed by subsea pipelines, design ranges in friction can be narrowed and/or tailored to specific pipeline conditions. These improved geotechnical inputs to pipe-soil interaction can alleviate unnecessary axial expansion mitigation and lateral stabilization measures, unlocking cost savings otherwise unavailable through conventional testing. A large database is presented, compiled from both previously published research and unpublished recent industry experience with low normal stress interface shear testing using various modified direct shear box devices. The test database comprises several coarse-grained soil types of both silica and carbonate minerology tested against pipeline coatings of various material, hardness and roughness. The database populates a framework for assessing frictional pipe-soil interaction response, illuminating key trends from normal stress, interface roughness and hardness, and particle angularity, which otherwise remain elusive when examined through individual test datasets. This database and the populated framework provides guidance to pipeline and geotechnical engineers in the form of a basis for initial estimates of axial and lateral friction of pipelines on sand and an approach for improving these estimates via focused site-specific testing. The test database includes previously unreleased project data collected over the past few years for offshore oil and gas projects. Similar to its predecessor paper on soft clays (OTC 28671), this paper shares the authors’ collective experience providing guidance on the planning, execution and interpretation of low stress interface shear tests in sands. The combined databases across both papers provide a significant improvement in early stage guidance for characterization of geotechnical soil properties for subsea pipeline design.

Gas developments are required to facilitate energy transition from carbon intensive energy to a sustainable balance of green and blue energy. The next decade will focus on exploiting gas fields globally to support this. A significant number of these fields are located in deepwater and /or are long distances from existing gas processing / LNG plants. Transporting large volumes of gas from remote gas fields over longer distances and in deeper waters remains technologically and economically challenging. Conventional and near-term development options include subsea compression, floating vessels with topside compression and pipeline tie-back to shore, or floating liquefied natural gas vessels. This paper and study are supported by The Oil & Gas Technology Centre (OGTC) and UK Oil and Gas Authority. It examines development options for a 200 km long 1700 m water depth tie back using integrated production modeling linked to power demands, along with installed steel tonnages. The Scope 1 and 2 emissions per unit of gas produced are analysed via a life cycle assessment using ISO 14044 as guidance for a long-distance gas tieback to the point of sale (inclusive of processing to sales specification). The major power intensive equipment used to develop these fields will be presented showing their proportion of the power consumption compared with the total; these include compression either onshore, offshore or subsea as well as the efficiency of the power generation devices in these environments. The paper will highlight the economics of each option and how varying the carbon price changes the commercial position of each option. The paper will show that by understanding what drives emissions, and how emissions relate to the amount of gas produced, that concept selection can drive upwards of 50% reduction in life cycle carbon emissions whilst improving project economic performance. This paper examines multiple innovative technologies, providing technology readiness of new concepts based on the benchmarked study focusing both economic and carbon emission aspects. Finally, the paper will show that better economic outcomes with the decarbonisation of gas gathering systems is technically possible and can be deployed subsea to help meet the energy transition and allow the development of remote and deeper gas fields.

Using Computed Tomography (CT) for 3D spatial analysis is a well-established technique primarily used in the fields of medical imaging and precision defect analysis of materials such as aircraft CT technology is gradually evolving for asset integrity within the Oil and Gas sector for two main applications: in-line inspection (ILI) verification and non-intrusive inspection (NII) of coated subsea pipelines. The CT scanning philosophy for both types of inspection challenges varies significantly and in this paper is considered in terms of alignment of inspection deliverables with scan definition. This paper explores the redesign of the traditional CT approach to optimize scanning for high-density target volumes by implementing a ground-up approach to all hardware and mathematics. The advanced algorithms used in the InspeCT TM technology enables a novel technique for image reconstruction; allowing for cleaner images than are possible using traditional CT whilst using less data and hence smaller radioactive sources. In addition, this paper demonstrates a selection of important findings from the InspeCT TM system qualification to API Standard 1163. To maximize the effectiveness of the subsea campaign, use of automated analysis is demonstrated to provide consistency in interpretation and reduce the considerable time demands of high-volume data analysis enabling any remediation decisions or change to inspection strategy to be actioned at the time of inspection rather on a future campaign.

A major pipeline company was tasked with decommissioning the Morpeth tension leg platform (TLP) in the Gulf of Mexico (GoM) and needed to abandon a 22-year-old, 8-in gas export steel catenary riser (SCR). The conventional approach to decommissioning an SCR is to mobilize a topside winch package, which sometimes requires the removal of platform equipment. The next step is to carry out structural engineering checks on the platform, determine the wire's various drop point routes through the platform, and provide the engineering analysis necessary to handshake the load from the winch to a heavy lift vessel for abandonment. This was the original plan for the Morpeth TLP SCR decommissioning program. Instead of employing this traditional approach to remove the riser using a topside winch package and heavy lift vessel, the pipeline owner requested an alternative method that had been used previously for an international operator. This novel method employed ROVs and divers to install a series of clamps to grip and secure the riser prior to cutting and used a Multiservice Vessel (MSV) to manage the disconnected riser for abandonment on the seafloor. The appeal of this integrated solution is that it does not interfere with the platform's topside operations or equipment layout and can provide potential cost savings. This methodology was used for the first time in the GoM to remove a riser to make space for a new one to be installed. For this installation, a clamp was designed by the operator to sit on the J-lay collar and to support the weight of the riser being removed. The project was modeled in OrcaFlex to determine safety requirements and the service company carried out the riser removal. Following adaptations to accommodate the differences presented by the Morpeth TLP SCR, a similar approach was used in the SCR decommissioning project, with the service company's engineering team designing a combination of a friction and through-pin box clamp, determining their placement, mapping out the role of divers, and defining the necessary vessel movements for each phase of the operation. Following an initial survey to determine the profile of the SCR, the service company created an OrcaFlex model and decommissioning plan that would allow the vessel to safely execute the program. The model allowed the team to incorporate safety factors to ensure that the load of the riser could be managed and that the riser could be handled without jeopardizing the safety of the vessel or creating riser clashing during the process of cutting and swinging the riser away from the TLP. It was determined that a winch wire could be cantilevered off the stern of the vessel to provide overhead access to the riser and clamp connection point. With the clamps properly connected, the riser was severed in a controlled manner by ROVs and then abandoned within the right-of-way (along the pre-approved area) of the pipeline prior to the ends being plugged and covered. In comparing the actual dynamic loads monitored during the operation with a line rider, it was confirmed that the model was within 5% of the expected loads, estimated at 54 metric tons. This paper explains how an unconventional method of SCR decommissioning allowed execution entirely from the MSV without impeding the operator's decommissioning schedule or conflicting with the work of other contractors on the platform to provide substantial cost savings. The solution also can be used to replace existing risers, whether the useful life of the platform exceeds the useful life of the riser and/or in the case where new field development requires a new tie-in. Other deepwater, vessel-based decommissioning solutions include the abandonment and/or recovery of flushed umbilicals and potentially the abandonment of flexible catenary risers. Following successful execution of the SCR decommissioning project, the pipeline company requested a FEED for using this integrated decommissioning solution for additional offshore assets. It was also requested that the clamp design be ROV installable. The study is for a three-year program to abandon five export SCRs on multiple TLPs in the GoM with loads upwards of 350 metric tons. The abandonment method to be employed for the upcoming SCR decommissioning program is the same as the one described in this paper, with execution from a single, standalone MSV.

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.

Pipelines are coated with insulating material that minimizes heat losses to the environment. Reeled pipe can experience nominal bending strain in the order of 1% to 2%. Thick coating on the pipe is inherently more highly strained, because of concentrations that occur at the interface between parent coating and field joint coating. Occasionally, contractors who specialize in pipe-lay using the reeling method have experienced difficulties relating to unexpected disbondment and cracks in coating at these interfaces. Any disbonded coating is routinely identified and repaired, but it is important to understand the influential factors that could lead to this type of coating disbondment. It is known in the industry that parameters such as temperature, reeling speed and pipe tension are influential but the relative influence of the factors is not well understood. In addition, there is currently no industry code or recommended practice that proposes the strain levels that the coating could safely withstand prior to cracking. This paper addresses thermo-mechanical aspects of coating design and presents a novel approach to quantify which parameters have the largest influence. In the presented assessments, coating strain was assessed using finite element analysis. Material input was selected from a combination of typical values and specific laboratory test results for polypropylene (PP) and injection molded polypropylene (IMPP). An essential aspect was that the mechanical and thermal properties of the PP were related to temperature and strain rate. Strain rates in the coating during reeling operations were obtained from global FE models. Detailed local FE models incorporated all the material and load inputs and temperature conditions that are necessary to determine peak strain values in the coating; the peak strain values would indicate the locations of potential coating disbondment. The study is purely a strain assessment and excludes any potential for defects or delamination in the coating that could result from its manufacturing process. This strain-based study revealed that coating temperature during reeling is the most influential factor on strain level in the coating. Reeling speed and pipe tension are parameters providing secondary influences.

Objective / Scope LNG has proven its worth, to meet energy demands throughout the globe at scale, whilst providing the cleanest fossil fuel. To complement the emerging trend of energy transition all over the globe, LNG provides a robust solution for a potential future. This paper will describe the current state and outlook of the LNG market, rethinking of LNG contracts and the major drivers that could favor a Floating LNG facility as a market driver compared to land-based facilities. Methods, Procedures, Process With recent events which include the oil price slump, LNG supply glut and the ongoing COVID 19 pandemic, the imbalance in the LNG market is predicted to run with low market price that could last up to four more years. On one hand, low market price is putting a lot of pressure on suppliers but on the flip side, this can be a game changer for the consumers. Consumers can potentially exploit buyers' market by making the investments much stronger to strive towards a clean future. Conventionally LNG producers have been land-based until facilities like Golar LNG made historical success. The focus of the Floating LNG industry is now directed towards small and mid-scale production. With a constant demand from stakeholders to get facilities up and running in a short development schedule, Floating LNG can provide some compelling benefits when combined with the concept of an economic time chartering investment rather than a CAPEX investment. This leads to a shortened execution time from discovery to market and avoids the extensive and time-consuming permitting and land use issues that are typical of onshore projects. The main drivers / challenges for a Floating LNG Facility investment are · Location, associated country regulatory restrictions · Source of gas · Market demand · Technology based on capacity · Project financing Floating LNG can not only provide economic benefits for first use but could also provide a commercial route to easy re-deployment to new gas sources, wherever necessary and possible. The paper will include: · Reflection on the LNG market of the recent past · Impact of COVID 19 on LNG market globally and the projected trends by various analysts · Overview of LNG contract types · Technical and commercial Drivers of Floating LNG which will potentially influence the market Results, Observations, Conclusions The take-away from this paper is a deeper understanding of the following: · Current LNG market and outlook · Reimagine LNG Contracts · Re-explore Floating LNG drivers Novel / Additive Information While the COVID 19 has created one of the reasons for the major impact on the market, this paper will present more interesting facts on many other contributing reasons for the present market downturn. This will in turn give an in-depth understanding for reimagining the major three drivers of Floating LNG, potentially leading to a WIN-WIN solution. This will help to sustain a constant cash flow amongst both sellers and buyers.

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.

Objectives/Scope In recent years, there has exceptional expansion of the liquefied natural gas industry (LNG), which is largely attributed to rising demands in various parts of the world and triggered the emergence of Floating LNG (FLNG) as a faster and more cost-effective strategy for exploitation of gas resources with a huge competitive advantage in the business activities. However, the introduction of new technologies comes with new requirements for tax related issues. Methods, Procedures, Process It is a testament to the resilience and adaptableness of the LNG business to check the hypothesis that FLNG provides a method by that stranded gas discoveries will be monetized and essentially within a shorter time, lower fabrication execution risk and the entrepreneurial vibrancy that comes from competitive suppliers and approaches on FLNG. On FLNG plant cost, Brian Songhurst gives a review review of the state of the performance of FLNG after commissioning. The need for the FLNG industry to address both cost base and contractual price formation mechanisms as a viable channel for the delivery of gas is key. Results, Observations, Conclusions The impact of Independent Power Projects (IPP) in the third World nations act as game-changer in the monetization, new gas markets discoveries and increasing impact on the global gas economy. FLNG has potentials to transform the phase transition business from technical and business stand points within the economic development of remote offshore oil fields. The opportunity provided by the contractors to lease the FLNG vessel enables the smaller independent energy companies to avoid arranging project finance and carrying the asset on their balance sheet. However, it could also assist the major energy companies where current low oil prices are restricting capital investment to lease their FLNGs. Given the high level of interest in the researcher's two previous papers, this update will prove equally interesting and useful to analysts and participants in the gas sector, as floating technology continues to open new opportunities. Cost Comparison of the FLNG offerings are following a more industry standard design approach based on functional specifications and vendor standard equipment rather than client standards and design methods as used by the energy companies. The reason for the quality style approach is to position the FLNG facilities to be hired and reused by energy company. Novel/Additive Information The price of producing LNG from offshore gas reserves through the FLNG ought to be less than from onshore plants thanks to the lower CAPEX, albeit this will be somewhat offset by higher OPEX. This paper provides an update on the floating LNG sector (both floating liquefaction and regas terminals) over the past few years looking into some of the publication of the floating liquefaction (FLNG) contribution from the Oxford Institute for Energy Studies.

Proper design of LNG loading lines and verification of emergency shutdown (ESD) interlock systems are critical in ensuring overall safety of the LNG facility. During an emergency, ESD interlock is activated with ESD valves closure initiated simultaneously with all loading pumps trip and the kickback valves open. During the ESD valves closure, the pipeline can be exposed to a risk of high surge pressures exerted onto the wall. A pressure surge or liquid hammering phenomenon in piping systems can be caused by a fluid in motion forced to stop or change direction suddenly (rapid momentum change) and also due to cavitation effect. Cavitation is caused by the formation and instantaneous collapse of vapour bubbles. The collapsing bubbles exert severe localized impact forces that can result in pressure surges. This paper discusses the methodology used to evaluate any potential occurrence of surge and the peak pressure associated with it, using several case studies for analysis. This paper also shares best practice identified from the study to facilitate with safe operations at an LNG loading facility.

Objective / Scope With renewable energy sources not currently able to move energy around the globe and forming small portions of the total global energy supply, it has fallen upon hydrocarbon sources to form the backbone of global energy movements. Hence, the recent energy demand decline, along with policy, have disproportionately impacted world-wide petroleum and LNG pricing. The impact on Floating LNG has been a heightened demand for capital efficiency, required to achieve final investment decision. A business case specific means of reducing FLNG CAPEX, has been repurposing marginal assets. Starting with a breakdown of the cost components of an FLNG facility, this paper will provide examples of the inclusion of preexisting assets into FLNG projects to reduce capital cost. The paper will wrap up with other opportunities for cost savings, to stimulate thought. Methods, Procedures, Process Floating LNG (FLNG) technologies have been deployed to monetize mid-sized offshore gas reservoirs, avoiding constructing a sub-sea gas pipeline to a land-based LNG facility and export jetty. Containing the processing to an oceanic environment also reduces the impact on indigenous peoples as well as terrestrial flora and fauna. FLNG facilities also have the potential of serving multiple offshore fields over the life of the facility, thereby reducing the minimum size field that can be economically monetized. Interest in FLNG continues, despite the current slump in energy prices, however these challenging times are refocusing efforts on reducing the capital cost of FLNG. This paper will explore recent capital cost trends in LNG, with a focus on floating LNG, examples of realized opportunities to reduce CAPEX, and further scope for reductions. Results, Observations, Conclusions The readers will take-away from this paper a deeper understanding of: Recent trends in CAPEX for LNG, and specifically FLNG Where significant opportunities lie for cost reduction Examples of the reuse and repurposing of marginal assets to reduce cost of FLNG facilities Areas to be explored for future capital reduction Novel / Additive Information This paper pulls together disparate threads into a coherent whole, providing visualization of the trends and examples of realized opportunities.

Rock berms are used for many different offshore pipeline applications such as protection from anchors and trawlers, mitigation against pipeline global buckling and improvement of pipelines on-bottom stability. Understanding the lateral resistance provided by rock berms to pipelines is essential for all the above applications. This paper presents insights into lateral resistance of rock berms restraining pipelines by finite element analyses. Pipelines of various diameters (0.2 m-1.5 m) within typical rock berm geometries were modelled in PLAXIS 2D to evaluate the peak lateral resistance provided by the rock berm to the pipe. The finite element model was validated against available full-scale test data. The results of the numerical analyses demonstrate that the peak lateral resistance of a pipeline in rock berm depends mainly on the unit weight and the frictional properties of the rock, while the mobilization to reach the peak resistance is dependent on the rock berm stiffness. Based on the results from this study, a simplified design chart is presented which provides the lower bound peak lateral resistance for a given pipe diameter under typical rock berm with cover to top of pipe in the range of 0.3 m to 1 m. This design chart could be used by engineers undertaking preliminary design assessment of pipelines in rock berms.

This work foucs on the safety transportation and risk evaluation of LNG accidental release and vapor cloud flame. The experimental was conducted in water tank with dimension of 1×0.5×0.5 in height × long × width and placed in a wind tunnel. The LNG released from a storage tank which connected by a flexible insulation tube. A stainless steel pipeline placed through the plexiglass tank with three orifice sizes and 0.6 m water depth. The leakage pressure and volume flow rate was measured by a pressure gauge and liquid flow meter with online monitoring. The dynamic behavior of LNG jet release was recorded by a high speed camera from a full and micro view. The flammable vapor was immediately ignited on the water surface under different crosswinds. In addition, a new correlation of the radio between flame height to width with mass loss rate and wind speed has been proposed. The flame temperature was employed by an array of K-type thermalcaplous in vertical and horizontal directions. An infrared camera was used to compare the thermal distribution for quantitative.

The interest of achieving zero flaring during Liquefied Natural Gas (LNG) offloading operation is governed by the following factors, i.e. safe operation with zero Loss of Primary Containment (LOPC), green environmental impact with lower greenhouse gas emission, maximizing the profit value of LNG, increasing the asset reliability and bringing good reputation to the company. The proper fuel gas and Boiled Off Gas (BOG) balance management between Floating LNG (FLNG) facility and LNG Carrier (LNGC) is critical during offloading operating to ensure the system reaches equilibrium and lead to zero flaring. This paper is to demonstrate the process study of identifying the potential causes of flaring during LNG offtake and the corrective measures to accomplish zero flaring without any plant capital modification. The gas flaring minimization study was based on the actual offloading operations data with multiple enhancements throughout the study. The intent is to identify the most optimum conditions that bring in the highest efficiency with the least amount of gas flaring. The outcome of the study suggests two methods which involve procedural changes during offloading operations as follows: Alteration of Boiled-of-Gas (BOG) compressor suction pressure controller set point to a higher value to accommodate additional BOG vapor accumulation in the storage tanks as temporary buffer, preventing sudden fuel gas flow surge to the fuel gas system which lead to excess flaring. Application of new offloading pattern by balancing BOG/ fuel gas flow to avoid pressure spike due to large amount of ship vapor return flow at certain LNGC tanks level. The flaring gas minimization techniques were applied in actual LNG offloading operation in June 2019 and successfully achieved zero flaring through the collaborative effort between FLNG and LNGC. This optimization methodology is proven to provide advantages by bringing in cost recovery and maximizing the profit values of LNG production. The methodology does not involve additional capital modification and the achievement during the actual implementation can serve as benchmark study for other FLNG facilities. This paper also provides insight on the potential area of improvement opportunity to the FLNG facilities that are currently under detailed design or construction phase.