Offshore Production Platforms Research Articles

Introduction of a carbon footprint assessment in the oil and gas facility life extension decision-making process

In large oil and gas producing countries, extraction and processing activities, including upstream activities, can represent a large share of domestic emissions. As oil fields approach their expected service life and reach depletion, energy use and GHG emissions increase per unit of produced oil, shifting operations away from their optimal point. Thus, it is paramount that oil field life extension decisions account for energy use and GHG emissions. However, many facilities are having their service life extended without considering this energy inefficiency and previous life extension decision making studies have neglected GHG emissions. Addressing this issue, this paper proposes the inclusion of a carbon footprint assessment within the evaluation of oil and gas offshore production facility life extension. The carbon footprint assessment adds an environmental lens to the evaluation of ageing, formerly evaluated according to material degradation, obsolescence and organizational issues. An eleven-stage framework is proposed to systematize the ageing related carbon footprint assessment and support life extension decision-making: (1) Objective definition, (2) Scope definition, (3) Field conditions description, (4) Scope breakdown into manageable portions, (5) Detailed data collection for each process and subsystem, (6) Input and output definition for each process and subsystem, (7) Process modelling, (8) Methodology definition for energy demand and inefficiency estimate, (9) Monitoring indicator definition, (10) Performance evaluation, and (11) Interpretation of results. The proposed framework is applied to a hypothetical case study, developed with data from a typical oil and gas offshore production platform operated in Brazil. Two LE improvement strategies were simulated, i.e. reducing the number of gas turbines, and increasing the export of natural gas. Both alter the modus operandi of the compression system and do not require additional equipment installation. These strategies resulted in a combined reduction of 922,000 tCO2 during the extended 10-year operation. This outcome demonstrates that by applying the framework opportunities for reducing energy use and GHG emissions during life extension can be identified and quantified, facilitating life extension decision-making.

Whale detection and microseismic monitoring via DAS using submarine telecommunications cables – a case study from the NWS, Western Australia

A monitoring trial of subsea distributed acoustic sensing (DAS) conducted in the marine waters of Australia is presented. This trial explores the concept of repurposing existing submarine telecommunications cables for remote monitoring of the environment and geophysical phenomena. The data were collected from a pre-existing fibre-optic cable, 50 km in length, that links two offshore hydrocarbon production platforms off the northwest coast of Australia. Initial data analyses confirmed the ability to detect underwater sounds from various sources, including marine animals (such as baleen whales), anthropogenic activities (such as vessels), and natural geophysical phenomena (such as earthquakes). The study underscores the efficacy of DAS for capturing and locating marine mammal vocalisations, specifically highlighting signals from pygmy blue whales – a species granted the highest protection status in Australia – and Omura’s whales, both of which migrate biannually through the offshore waters of Western Australia. These findings indicate the potential of subsea DAS for detecting and tracking marine fauna regionally. Moreover, they suggest its applicability for future monitoring in support of environmental impact assessments and the development of adaptive management strategies to prevent or minimise impacts on migratory whale species from offshore industries.

Application of Bayesian networks based on Sequential Monte Carlo simulation and physical model in fault diagnosis of horizontal three-phase separator system

In offshore production platforms, horizontal three-phase separator is common process equipment. Its main function is to complete the dehydration and degassing of crude oil. Separator system is more complex, and its failure may cause significant economic losses and disastrous consequences. Therefore, it is critical to accurately and quickly identify where and why faults occur in the separator system. In this study, separator fault diagnosis model based on Bayesian networks is developed. Moreover, Sequential Monte Carlo simulation and physical model are introduced to overcome field problems such as missing separator failure data and the inability of experts to provide accurate empirical knowledge. Using this model, 13 faults in a separator in an offshore crude oil processing system are successfully diagnosed. Meanwhile, the proposed model is compared with deep neural network, convolutional neural network, and deep residual network, with accuracy rates of 100%, 91.34%, 87.99%, and 94.62%, respectively. Then, the diagnostic accuracy of each model for different faults is also compared in this paper under various signal-to-noise ratios. The results show that the method proposed in this paper has better noise immunity compared to the other three models. Therefore, the accuracy and robustness of the proposed model is further demonstrated. Finally, to analyze the fault-tolerance of the proposed model, 2–3 error evidence is randomly entered. The results show that the proposed model has better fault tolerance compared to data-driven Bayesian networks.

A ReLU-based linearization approach for maximizing oil production in subsea platforms: An application to flow splitting

Oil and gas extraction from subsea reservoirs is a complex process that is highly reliant on accurate mathematical modeling for optimization. A key challenge is identifying control settings to maximize oil production while accounting for the nonlinear behavior and constraints of the underlying physical systems. This paper introduces a new method using Rectified Linear Units (ReLU) neural networks to model these complexities. We focus on a subsea system connecting multiple oil wells to a manifold with multiple headers, explicitly modeling flow splitting to optimize oil yield. Our approach employs mixed-integer reformulations of ReLU neural networks to approximate pressure-drop functions in risers, allowing efficient optimization of production platforms considering routing possibility and flow-splitting operations. Computational analysis employing a branch-and-cut approach and p-split partitioning (for the ReLU model) shows that our ReLU-based methodology converges faster than standard piecewise-linear (PWL) approaches while delivering comparably effective results. Notably, ReLU found solutions in scenarios where PWL failed to find an incumbent solution within the time limit. These results underscore a significant advancement in the optimization of offshore production platforms by using ReLU-based models.

Reactive power capacity allocation technology of shore‐based power supply system of offshore oil production platform under different network topology reliability measures

AbstractTo improve the economy of offshore oil production platform shore‐based power transmission mode, the reactive power capacity allocation technology of offshore oil production platform shore‐based power supply system based on different network topology reliability measures was proposed. The optimization model of power supply system network topology and the structure model of voltage source converter high voltage direct current transmission system were established, the start and stop control scheme of flexible direct current (DC) transmission system was designed, and the operation parameters of converter station and DC line were monitored in real time. The topological structure of offshore oil production platform shore‐based power supply system is constructed, the mathematical model of flexible DC transmission system is established when the alternating current side voltage is balanced, the reactive power capacity configuration of offshore oil production platform shore‐based power supply system is optimized, and the life cycle cost results are calculated. The experimental results show that the algorithm proposed in this paper can obtain the optimal solution only after 26 calculations, with high optimization efficiency and good convergence effect. Reactive capacity configuration of shore‐based power supply system for offshore production platform can reduce failure rate and life cycle cost.

Big Players Pivot in Response to Regulatory Pressures

_ Early January brought with it significant changes in the environmental side of the oil and gas industry. ExxonMobil and Chevron, the two largest US oil producers, announced they will exit California, and the Biden administration froze LNG export approvals. After 50 years of producing oil in California, ExxonMobil will take a $2.5 billion writedown of the value of some of its California properties to be recorded in its fourth-quarter earnings. The company said the decision is primarily related to its Santa Ynez operations off the coast of Santa Barbara. Its US Securities and Exchange Commission (SEC) filing said, “While the Corporation is progressing efforts to enable a restart of production, continuing challenges in the state regulatory environment have impeded progress in restoring operations.” After the Refugio oil spill in May 2015 (approximately 100,000 gal), resulting from a leak from a pipeline owned by Plains All American Pipeline, ExxonMobil acquired the damaged asset in October 2015. Just a few months before the purchase, the Santa Barbara County Board denied ExxonMobil’s request to truck its oil produced off the coast of Gaviota to its Las Flores Canyon processing facility and on to refiners located in Pentland, California. Seeking an alternative, ExxonMobil planned to replace two stretches of the 112-mile corroded pipeline for transit of its oil. Met with opposition to replace the damaged pipeline and denied permission to repair and restart production at the site (halted since 2015), ExxonMobil is now selling the Santa Ynez operation to Sable Offshore, a blank-check company created in 2020. The company will loan Sable the money for the purchase of its three offshore production platforms, pipeline, and onshore processing facility. Sable’s agreement with ExxonMobil requires production to be started by early 2026 or the assets and liabilities revert to ExxonMobil. Chevron, headquartered in San Ramon, California, will write down $3.5 billion to $4 billion in assets, citing its home state’s regulations that “have resulted in lower anticipated future investment levels.” The company intends to continue operating its oil fields and related assets. In the SEC filing, Chevron wrote it also will incur fourth-quarter charges related to decommissioning of US Gulf of Mexico assets that have reached the end of their productive lives. The company sold some of those assets, but US law stipulates that previous owners may be responsible for those costs if the current owner declares bankruptcy. Chevron wrote it’s “probable” that it may see such costs. January closed with another unexpected announcement on 26 January. The Biden administration paused decisions on permits to export LNG to non-free trade agreement countries to review current projects seeking approvals. US Energy Secretary Jennifer Granholm stated, “We must review export applications using the most comprehensive, up-to-date analysis of the economic, environmental, and national security considerations.” She added that this was not a ban on exports and would not affect already authorized exports, which when combined with existing plants, total 48 Bcf/D. “Within this decade another 12 Bcf/D of US export capacity already authorized and under construction will come online,” Granholm said. While environmental impact (greenhouse gas emissions including CO2 and methane) was one of the reasons for the decision, along with market, economic, national security, and energy security, Granholm pointed out that facilities totaling 22 Bcf/D of capacity have been approved but have not yet started construction. This capacity, combined with existing infrastructure, is “more than enough to make the US a ‘behemoth’ in the LNG field,” according to Holland & Knight in an analysis dated 29 January. The international law firm said this raises the question of whether further development of LNG facilities could hurt US citizens as higher percentages of produced gas are exported. “This line of thinking follows the historical rhetoric on this issue as domestic users of natural gas want to ensure their feedstock price is stable. To support those claims, recent studies have concluded that ‘higher LNG exports create a tighter domestic natural gas market (all else held equal), increasing domestic natural gas prices.’” Could unintended consequences of these recent announcements rear up in the future? And could they be a behemoth for the US or global markets? For Further Reading Growth in 2022 US LNG Liquefaction Capacity Hits Top of the Charts by Pat Davis Szymczak, SPE Oil and Gas Facilities.

A Modular System Architecture for an Offshore Off-grid Platform for Climate-neutral Power-to-X Production in H2Mare

Power-to-X (PtX) products constitute a promising solution component in the defossilisation of hard-to-abate sectors. Where direct electrification is not possible, they can find application as chemical feedstock, easy to transport energy carriers and storage. In this contribution, a modular system architecture for a highly automated operation of an offshore off-grid PtX production platform consisting of five layers (asset, control, communication, digital, application) is presented. The assumed advantage of such an off-grid platform is the good scalability worldwide as well as easy exploitation of renewable potentials in any location. Using the example of a power-to-methanol process, a simplified prototype is outlined.

Stochastic optimal dispatch of offshore-onshore regional integrated energy system based on improved state-space approximate dynamic programming

The offshore-onshore regional integrated energy system (OORIES), which includes offshore gas production platforms and wind farms, along with the onshore gas-fired combined cooling, heating, and power supply campus, can effectively improve economic and environmental benefits by the complementary and coupling operation of multiple energies. In this paper, multi-energy coupling elements and multiple energy networks in the OORIES are modeled in detail. Considering the stochastic fluctuation of the offshore gas source and wind power output, a stochastic optimal dispatch (SOD) model of OORIES with multiple energy storages, including associated gas storage, hydrogen and heat storage tanks is proposed. Furthermore, a carbon trading mechanism is introduced to ensure the environmental benefits. An improved state-space approximate dynamic programming (SSADP) algorithm is proposed to solve the SOD model. By using the approximate value functions, the multi-period SOD model is decoupled into a series of single-period optimization models which are recursively solved period by period. The approximate analytical expression of the value function concerning states of each period is obtained based on the polynomial approximation, and combined with the transition probability matrices of stochastic quantities, an accurate and efficient solution for each single-period optimization model is obtained. A case study on an OORIES, and compared with the scenario-based algorithm, chance-constrained programming algorithm and traditional SSADP algorithm, demonstrates the effectiveness and high efficiency of the proposed method.

Optimization of Offshore Wind Power Generation in Response to the 2022 Extreme Drought in Portugal

Portugal, in line with the European Union, is aiming for carbon neutrality by 2050 (Net Zero), which implies a transition to sustainable energy sources. Climate change is all too evident, as extreme weather periods are occurring in a cyclical manner with greater brevity to such an extent that the grid operator must deal with production scenarios where it can no longer rely on hydroelectric production given the recurring drought situation. This situation increases dependence on thermal production using natural gas and imports. This has significant economic implications. Portugal has exploited its onshore wind potential, reaching an installed capacity of 5.671 MW by 2022. However, the expansion of onshore wind energy is limited to reinforcing the existing infrastructure. To overcome these challenges, it is necessary to expand the exploitation of the offshore wind potential that is already underway. This article proposes the location of offshore wind production platforms along the Portuguese coast. This allows for an analysis of offshore production and its optimization according to the minimum cost per MWh in the face of extreme scenarios, i.e., in periods of extreme drought where the hydroelectric production capacity is practically non-existent. The model is fed by using market price indications and the amount of energy needed for the following day. Using forecast data, the model adapts offshore wind production for the following day according to the minimization of the average market price. This study presents an optimization model adapted to combat the unpredictability of extreme weather conditions. This strategic framework significantly increases the resilience and reliability of offshore wind energy production, marking a significant advance in the management of renewable energy under the pressure of climate variability. The results of the simulations allow us to conclude that despite the high cost of offshore technology (in deep waters), in extreme climate scenarios, it enables cost reduction and a clear decrease in imports.

Improved multi-search strategy A* algorithm to solve three-dimensional pipe routing design

Pipe routing design (PRD) has a significant impact on the safety and operational efficiency of the system. PRD is involved in multi-disciplinary knowledge such as mechanical engineering, computer graphics and mathematical geometry, and it can be abstracted as a complex combined optimization problem. A* algorithm is one of the most commonly employed approaches to solve two-dimensional (2-D) path planning. However, due to the central idea of A* algorithm is all-traversal search, the search process considers all possibilities and requires a blind search one by one, it is difficult to solve PRD problems in complex three-dimensional (3-D) space environment. In this study, an improved multi-search strategy A* algorithm (MSSA*) is presented to overcome the disadvantages of the traditional A* algorithm in solving 3-D PRD problems. The MSSA* algorithm contains four novel mechanisms which are the node directional discrimination rule, the double-layer domain extension search strategy, the multi-factor heuristic evaluation function, and the dynamic adaptive weighting strategy. Then, a range of experiments are conducted to prove the validity of the presented mechanisms. Subsequently, the MSSA* is compared with several existing algorithms for solving 3-D PRD to further verify the superiority of MSSA* in terms of high-efficiency and practicality. Finally, the MSSA* is applied to solve the 3-D PRD problems for offshore production platforms in oil and gas treatment system.

Developing a spatially explicit global oil and gas infrastructure database for characterizing methane emission sources at high resolution

Abstract. Reducing oil and gas methane emissions is crucially important for limiting the rate of human-induced climate warming. As the capacity of multi-scale measurements of global oil and gas methane emissions has advanced in recent years, including the emerging ecosystem of satellite and airborne remote sensing platforms, a clear need for an openly accessible and regularly updated global inventory of oil and gas infrastructure has emerged as an important tool for characterizing and tracking methane emission sources. In this study, we develop a spatially explicit database of global oil and gas infrastructure, focusing on the acquisition, curation, and integration of public-domain geospatial datasets reported by official government sources and by industry, academic research institutions, and other non-government entities. We focus on the major oil and gas facility types that are key sources of measured methane emissions, including production wells, offshore production platforms, natural gas compressor stations, processing facilities, liquefied natural gas facilities, crude oil refineries, and pipelines. The first version of this global geospatial database (Oil and Gas Infrastructure Mapping database, OGIM_v1) contains a total of ∼ 6 million features, including 2.6 million point locations of major oil and gas facility types and over 2.6×106 km of pipelines globally. For each facility record, we include key attributes – such as facility type, operational status, oil and gas production and capacity information, operator names, and installation dates – which enable detailed methane source assessment and attribution analytics. Using the OGIM database, we demonstrate facility-level source attribution for multiple airborne remote-sensing-detected methane point sources from the Permian Basin, which is the largest oil-producing basin in the United States. In addition to source attribution, we present other major applications of this oil and gas infrastructure database in relation to methane emission assessment, including the development of an improved bottom-up methane emission inventory at high resolution (1 km × 1 km). We also discuss the tracking of changes in basin-level oil and gas activity and the development of policy-relevant analytics and insights for targeted methane mitigation. This work and the OGIM database, which we anticipate updating on a regular cadence, help fulfill a crucial oil and gas geospatial data need, in support of the assessment, attribution, and mitigation of global oil and gas methane emissions at high resolution. OGIM_v1 is publicly available at https://doi.org/10.5281/zenodo.7466757 (Omara et al., 2022a).

Optimizing Operations Sequencing and Demulsifier Injection in Offshore Oil Production Platforms

Short-term production optimization of oil assets concerns routing decisions and equipment control settings that induce optimal steady-state operations. Typically, the decisions are made on the scale of hours to days with the aim of maximizing short-term economic and oil gains. Still an evolving field, this paper contributes by presenting a model and solution strategy for sequencing operations over time to drive the system towards an optimal state, while accounting for constraints that ensure smooth transitions until settling at the terminal steady-state. The constraints include the maximum number of wells that undergo a change in the control settings, maximum number and variation on the input signals for each well, and maximum number of changes in each time period, among others. Additionally, the proposed strategy can optimize the rate of injection of demulsifiers into wells considering the limits and impacts on fluid processing capacity. The paper reports simulated results for a real-world offshore production platform, demonstrating the effectiveness of the optimization strategy to cope with the failure and recovery of compression capacity, and manage the injection of demulsifiers.

Analyzing non-technical skills in the sharp end of facilities/utilities operations in onshore and offshore O&G process plants

It is on the sharp end of the O&G operations where the real work happens, but also where the highest risks and system demands are placed. Understanding the skills—technical and non-technical—necessary to perform efficiently and safely is not only needed to maintain the business and assets, but also to ensure the safety of lives and the environment. Accidents such as Piper Alpha (1988), P-36 (2001) and Deepwater Horizon (2010) highlight the importance of understanding the real role of the human element in these events, from the highest hierarchical levels to the sharp end, where the work as done takes place. This article presents a non-technical skills analysis focused on the sharp end of O&G operations, specifically in the facilities/utilities operations, onshore (refineries) and offshore (production platforms). The findings show the importance and presence of certain non-technical skills, as well as the need for improvement of others in the daily routine and in emergencies.

Geoscience Poster G4: A time series analysis of exploration in the North West Shelf

Poster G4 The North West Shelf (NWS) of Australia has seen a stellar increase in oil and gas discoveries, from less than 30 just 50 years ago to more than 180 today. It also hosts the ‘NWS Project’, Australia’s largest resource development project involving petroleum extraction, offshore production platforms, LNG processing plant, and LNG export hub, contributing to over 50% of Australia’s LNG export in 2020. In the last decade, discoveries have slowed down, with only four discoveries since 2010. Here, we undertook a data-driven analysis of which factors contributed to this ‘NWS boom and bust’. We noted numerous factors, the most important ones being technology and economic drivers. We arrived at this conclusion by building a time series and correlating key exploration activities to the number of discoveries and oil price. We found that (a) exploration steadily increased from the late 1960s due to 2D seismic, which coincided with oil price surge, (b) improved computational capacity spurred 3D seismic acquisition in 1981, boosting discoveries, and (c) 3D seismic acquisition in frontier areas began in the late 2000s, with the rate of discoveries flattening in 2010 as drilling became more challenging. We observed large areas of undrilled acreage covered by 3D seismic with plans for future seismic acquisition despite some of these areas equating to expensive wells and higher risks. With further work on existing 3D seismic coupled with insights from upcoming acquisitions, we would be able to develop a better subsurface understanding of these frontier basins and apply the knowledge to petroleum exploration as well as emerging energy economies like geothermal and carbon capture and storage (CCS). To access the poster click the link on the right. To read the full paper click here

A time series analysis of exploration in the North West Shelf

The North West Shelf (NWS) of Australia has seen a stellar increase in oil and gas discoveries, from less than 30 just 50 years ago to more than 180 today. It also hosts the ‘NWS Project’, Australia’s largest resource development project involving petroleum extraction, offshore production platforms, LNG processing plant, and LNG export hub, contributing to over 50% of Australia’s LNG export in 2020. In the last decade, discoveries have slowed down, with only four discoveries since 2010. Here, we undertook a data-driven analysis of which factors contributed to this ‘NWS boom and bust’. We noted numerous factors, the most important ones being technology and economic drivers. We arrived at this conclusion by building a time series and correlating key exploration activities to the number of discoveries and oil price. We found that (a) exploration steadily increased from the late 1960s due to 2D seismic, which coincided with oil price surge, (b) improved computational capacity spurred 3D seismic acquisition in 1981, boosting discoveries, and (c) 3D seismic acquisition in frontier areas began in the late 2000s, with the rate of discoveries flattening in 2010 as drilling became more challenging. We observed large areas of undrilled acreage covered by 3D seismic with plans for future seismic acquisition despite some of these areas equating to expensive wells and higher risks. With further work on existing 3D seismic coupled with insights from upcoming acquisitions, we would be able to develop a better subsurface understanding of these frontier basins and apply the knowledge to petroleum exploration as well as emerging energy economies like geothermal and carbon capture and storage (CCS).

Безопасность морских газопроводов

Due to the nature of the development of gas transmission network, the problem of ensuring reliability and safety of the underwater gas pipelines was practically exhausted by the calculation of underwater crossings through the rivers, lakes, and other water barriers. However, in recent years in connection with the development of oil and gas fields on the shelf, and the globalization of the gas transmission network, the question came up related to designing, building, and subsequently ensuring the stable operation of the offshore deep-water pipelines. Individual information about the accident rate of the offshore pipelines is given. They mainly concern the coastal pipelines transporting raw materials from the offshore production platforms to the onshore terminal. The largest number of accidents is typical for the pipelines of small diameters (2–6 inches) — 59 % of their total number. A group of medium-diameter pipelines (8–16 inches) accounts for 32 % of accidents. Pipelines of large diameter (18–36 inches) are the least susceptible to damage — about 3 % of accidents. In recent decades, the offshore main gas pipelines were widely used and are considered as the most promising way of transporting gas due to higher reliability, safety, and environmental friendliness, as well as the advantages of direct Analysis is presented in the article concerning the accident rate and features of failures of the offshore gas pipelines. The criteria of limit states and the algorithm for calculating the stress-strain state of the offshore pipeline, which are the main part of the safety assessment, are given. Methodology for the safety of the offshore gas pipelines was developed, based on which the example of the safety assessment of the Blue Stream gas pipeline is given. The materials of the article were used in the development of the projects for the offshore gas pipelines and are also included in the industry regulatory document.

Analysis of alternatives for the selection of offshore production platforms. Application in the Colombian Caribbean

El desarrollo de este artículo consiste en la aplicación de una secuencia de análisis para seleccionar las plataformas de producción de hidrocarburos, la cual consta de cuatro criterios que se requiere tener en cuenta al momento de desarrollar un campo petrolífero costa afuera. Primero, se hace un estudio detallado de los diferentes tipos de plataformas que se pueden llegar a emplear para la producción de hidrocarburos en aguas profundas y ultra profundas, seguidamente se desarrollan los criterios de selección para cada tipo de plataforma dependiendo de factores como las características del yacimiento, los requerimientos técnicos y las condiciones metaoceánicas del sitio, posteriormente se buscan identificar las facilidades básicas que deben tener las instalaciones en alta mar y se plantea una serie de escenarios para la producción de los campos tomando como referencia con las experiencias del campo Liwan 3-1 ubicado en aguas profundas del mar del sur de China. Se sugiere la aplicación de un escenario para el desarrollo del campo Orca, teniendo en cuenta necesidades de infraestructura, sistemas de producción y facilidades, además se analizan las variables influenciadas por las condiciones metaoceánicas de la zona; para lograr así analizar las variables que pueden llegar a influir en la selección de una plataforma de producción, específicamente en el mar caribe colombiano, donde en los últimos años se han realizado exploraciones con descubrimientos en gas.

Cybersecurity of Offshore Oil and Gas Production Assets Under Trending Asset Digitalization Contexts: A Specific Review of Issues and Challenges in Safety Instrumented Systems

Due to the rapid digitalization of offshore oil fields and production platforms, diverse technological solutions, products, and application software have begun to appear both in upstream and midstream processes raising new organizational and operational challenges. The potential effects of these digital technologies driven developments have also been generating concerns, particularly in safety, security, and regulatory terms. Both hardware and software related changes and challenges in sensitive systems such as safety instrumented systems (SIS) can expose a production asset to new forms of risks. Hence, diverse aspects of cybersecurity have gained serious attention from authorities, operators, and service providers, particularly due to increasing general tendencies of major cyber-attacks on high-risk industrial assets, as well as their significant impact on safety, production, and asset economics terms. A SIS in an offshore oil and gas production asset has a critical role towards its safety integrity level (SIL). In general, a SIS consists of specific safety assurance instruments and pre-defined safety functions that are tightly coupled to detect, prevent, or mitigate hazardous situations ensuring process safety. Under the current industrial contexts of major changes within the offshore oil and gas production sector, partly due to unavoidable commercial changes and partly due to rapid technological developments, a better understanding of the cybersecurity exposure potentials of SIS is quite important to mitigate unwanted events and incidents. Under such circumstances, this paper explores critical issues and challenges related to cybersecurity of SIS as an extended step of a research study done in collaboration with industrial partners. It assesses the current actual status, requirements in governing standards and guidelines, and identifies some dangerous failure modes of SISs that need due security-oriented attention in a continuous asset digitalisation process. Towards the end, the paper defines and elaborates in-depth on specific issues and challenges relating to cybersecurity of SIS. Moreover, it identifies and reflects on generic initial steps that can be taken for assurance of cybersecurity of SIS within offshore oil and gas production assets to ensure necessary safety and security integrity levels under rapidly changing industrial contexts.

Field application of a modular multiple thermal fluid generator for heavy oil recovery

A modular multiple thermal fluid generator is introduced to enhance heavy oil production, which consists of water treatment system, fuel injection system, air compressor, central burning and heat exchanging system, and measuring and controlling system. All the components are mounted in three separated light shelters, which are easy to be lifted and installed, especially on the offshore production platform. It could be operated under 350 ℃ and 20 MPa, and the temperature and GWR (ratio of the volume of gas to the equivalent water volume of steam under standard conditions) could be adjusted by the water injection rate under the given heating capability of the central burning chamber. The temperature of the generated fluid is usually 200–300 ℃ with GWR of 200–300 m3/m3. Compared to conventional steam generator, such compact multiple thermal fluid generator is easy to be installed on the offshore oil production platform, and the generated multiple thermal fluid is potential to enhance heavy oil production in mechanisms of reducing heavy oil viscosity by both heating and injected gas, enlarging the heating reservoir chamber, and pressure by injected gas. In the past 10 years, the multiple thermal fluid generator has been applied to more than 40 wells in Bohai Offshore Oilfield and Xinjiang Oilfield in cyclic multiple thermal fluid stimulation (CMTFS in short) process. As a result, the multiple thermal fluid generators were operated soundly, and the heavy oil production of these wells was enhanced remarkably. (The oil production rate was 2–3 times more than cold production.)

A Diode-MMC AC/DC Hub for Connecting Offshore Wind Farm and Offshore Production Platform

A diode rectifier-modular multilevel converter AC/DC hub (DR-MMC Hub) is proposed to integrate offshore wind power to the onshore DC network and offshore production platforms (e.g., oil/gas and hydrogen production plants) with different DC voltage levels. The DR and MMCs are connected in parallel at the offshore AC collection network to integrate offshore wind power, and in series at the DC terminals of the offshore production platform and the onshore DC network. Compared with conventional parallel-connected DR-MMC HVDC systems, the proposed DR-MMC hub reduces the required MMC converter rating, leading to lower investment cost and power loss. System control of the DR-MMC AC/DC hub is designed based on the operation requirements of the offshore production platform, considering different control modes (power control or DC voltage control). System behaviors and requirements during AC and DC faults are investigated, and hybrid MMCs with half-bridge and full-bridge sub-modules (HBSMs and FBSMs) are used for safe operation during DC faults. Simulation results based on PSCAD/EMTDC validate the operation of the DR-MMC hub.