Offshore Production Research Articles

Site Selection for an Offshore Wind Power Station Under a Fuzzy Environment

The Malaysian government’s support for offshore wind power production has led to an increase in a few proposals. An important factor in the overall efficiency of any offshore wind farm is the site selection process, which is a multi-criteria decision-making (MCDM) task. However, classical MCDM techniques often fail to choose a suitable site because of three main challenges. First, compensation is regarded as a problem in the processing of information. Second, data usage and data leakage are often ignored in the decision-making process. Third, interaction difficulty in fuzzy environments is easily ignored. This study provides a framework for making site selection decisions for offshore wind farms while addressing the constraints. Fuzzy VIKOR is used in the second stage of the AHP process to analyze the site’s results with respect to evaluation criteria for offshore wind farms. A comprehensive index system, which incorporates the veto criteria and evaluation criteria for selecting offshore wind power station sites, is devised. Then, the system is used to transmit imprecise information to decision makers by using a triangular fuzzy set. Likelihood-based valued comparisons indicate that imprecise choice information can be correctly used, and issues of information loss can be logically avoided. A case study of Malaysia is used to demonstrate the validity and practicality of the site selection technique. This research offers a theoretical basis for accurate offshore wind power evaluation in Malaysia.

Isothermal and non-isothermal multiphase flow steady-state simulation of offshore production systems using ALFAsim

Isothermal and non-isothermal multiphase flow steady-state simulation of offshore production systems using ALFAsim

Isothermal and non-isothermal multiphase flow steady-state simulation of offshore production systems using ALFAsim

Isothermal and non-isothermal multiphase flow steady-state simulation of offshore production systems using ALFAsim

Assessment of an Isolated Offshore Power Grid Based on the Power Hub Concept for Pre-Salt Oil and Gas Production

Towards a future with more renewable energy, oil and gas (O&G) will still play a major role in the energy and mobility sectors. Therefore, scientists must also investigate ways to mitigate carbon emissions in O&G production. In this sense, a power hub with local generation can be employed in offshore production sites to allow the adoption of more efficient power generation technologies without the weight and space constraints that exist in usual Floating Production, Storage and Offloading (FPSO) platforms. This power hub can be connected to the FPSOs forming an isolated offshore power grid that requires further study. This work investigates stability issues of such offshore power networks. Simulations of a system composed by the power hub and three identical FPSO units were performed in PSCAD, and the stability of the system was validated according to the IEC 61892-1 standard. Results demonstrate that it is possible to operate such system with a stable and secure supply. The main contributions of this work are the electrical modeling of the power hub and of the resulting isolated offshore electrical grid, and a detailed discussion of the rising challenges and the required models for dynamic electrical studies.

Optimizing hybrid offshore wind farms for cost-competitive hydrogen production in Germany

Nearly 96% of the world's current hydrogen production comes from fossil-fuel-based sources, contributing to global greenhouse gas emissions. Hydrogen is often discussed as a critical lever in decarbonizing future power systems. Producing hydrogen using unsold offshore wind electricity may offer a low-carbon production pathway and emerging business model. This study investigates whether participating in an ancillary service market is cost competitive for offshore wind-based hydrogen production. It also determines the optimal size of a hydrogen electrolyser relative to an offshore wind farm. Two flexibility strategies for offshore wind farms are developed in this study: an optimal bidding strategy into ancillary service markets for offshore wind farms that build hydrogen production facilities and optimal sizing of Power-to-Hydrogen (PtH) facilities at wind farms. Using empirical European power market and wind generation data, the study finds that offshore-wind based hydrogen must participate in ancillary service markets to generate net positive revenues at current levels of wind generation to become cost competitive in Germany. The estimated carbon abatement cost of “green” hydrogen ranges between 187 EUR/tonCO2e and 265 EUR/tonCO2e. Allowing hydrogen producers to receive similar subsidies as offshore wind farms that produce only electricity could facilitate further cost reduction. Utilizing excess and intermittent offshore wind highlights one possible pathway that could achieve increasing returns on greenhouse gas emission reductions due to technological learning in hydrogen production, even under conditions where low power prices make offshore wind less competitive in the European electricity market.

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.

Applying systems engineering to roadmapping for digital transformation in the offshore exploration and production supply chain operations

AbstractThis article presents the results of the third cycle of an Action Research (AR) study conducted in an offshore exploration and production (E&P) operator on the Norwegian Continental Shelf (NCS) that investigated a digital transformation (DT) in offshore E&P supply chain operations, with a focus on drilling operations. This study provides the results of a brief investigation of the main factors that contribute the success of DT and demonstrates the value of using technology roadmapping alongside systems engineering (SE) practices to create a path between identified “AS‐IS” and “TO‐BE” operational states. Applying SE methods to the adoption of the “T‐Plan” roadmapping process resulted in a strategic communication tool that can be used among stakeholders to support them with the integration of business planning and technology adoption, and to help assess the impact that new technologies may have on their organizations in their journey toward a successful DT. In addition to the roadmap itself, which benefits the case company, this study contributes to building and enriching academic literature by providing insight from the oil and gas industry and demonstrating the use of technology roadmapping to create a strategic plan for DT in a well‐established industrial domain.

Comparison of the Vertical Gas-Hydrate Production Profile with the Simulation Results Obtained Using Geophysical Log-Based Reservoir Characteristics and Reasons for Their Discrepancies in the Nankai Trough

In this study, we analyzed the temperature and pressure measurement data obtained from the production test of methane hydrates in the second offshore production wells of Nankai Trough (2017). Based on the analysis, we derived time-series information on the vertical profile and the gas and water influxes in the wells via an optimization process. The time-series information revealed variations in the vertical production profiles and behavior between two production wells. Some discrepancies were observed in the petrophysical characteristics, particularly in the permeability between the wells, while comparing the measurement-based profile and simulation results based on geophysical log-based reservoir models. The discrepancies are attributed to the water-producing layers and some near-wellbore phenomena, which also inhibit stable and increasing gas production in the well. Current studies on gas hydrate by the Japanese national gas-hydrate resource development project focus on identifying the causes of these problems and possible countermeasures.

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.)

Integrating spherical fuzzy Delphi and TOPSIS technique to identify indicators for sustainable maintenance management in the oil and gas industry

This study offers an investigation into the degree of importance of indicators affecting the sustainable maintenance management of the oil and gas industry. Four dimensions and 12 strategic indicators for sustainable performance are identified, based on literature review and expert opinion on sustainable offshore production. The survey was conducted as a pioneer attempt to evaluate the significance of each indicator, particularly for the Malaysian and Turkmenistan oil and gas industry. In this study, the spherical fuzzy sets modified-Delphi Method was implemented to address the uncertainty and subjectivity in expert judgment. Then, the spherical fuzzy technique in order of preference by similarity to ideal solution integrated approach was proposed to prioritize strategic indicators for assistance in administrating sustainable practices within two developing countries. The study culminated with a set of conceptual indicators intended to promote the implementation of performance benchmarking of sustainable operations in the oil and gas industry offshore.

Emulsions in porous media from the perspective of produced water re-injection – A review

During offshore production, it is typical to discharge produced water into the sea after treating it to a level that meets environmental regulations. A growth in the volumes of produced water and increasingly stringent requirements have drawn attention to re-injection of produced water as a more viable disposal method. Produced water re-injection is regarded as an environmentally friendly and cost-efficient approach that allows integration of produced water with reservoir management. However, loss of injectivity, due to the plugging of pores by oil droplets and particles present in produced water, limits implementation of re-injection. This review discusses engineering challenges during re-injection and summarizes the knowledge and the gaps in the literature on the permeability reduction due to the flow of dilute oil-in-water emulsions. First, a short introduction into the origins of produced water, its composition, and the treatment techniques employed offshore are provided. An overview of the water injection strategies as well as a discussion of the past field experience of produced water re-injection is given. This is followed by a detailed review of the flow of diluted oil-in-water emulsions through porous media from the permeability reduction perspective. An overview of models for predicting permeability reduction during the flow of emulsions is provided. The physical parameters affecting the droplet retention and physicochemical interactions between droplets and pore walls are discussed. The studies that investigated co-injection of oil droplets and solid particles are included as well. The review identified that the effect of droplet stability, oil viscosity, wettability, and particles on droplet retention is not sufficiently examined. It was found that drop-to-pore size ratio is a crucial factor for droplet retention, but it is often omitted in the industry. An outlook on the gaps and suggestions to address them was provided. Microfluidics was pointed out as a complementary technique to coreflooding.

Technology Focus: Flow Assurance (November 2021)

I sincerely hope that all JPT readers and your families, peers, and employers remain safe and healthy and have work as they read this year’s Flow Assurance feature. Flow-assurance effects from slug-flow engineering, design, maintenance, and operations technical concerns still create and sustain challenging technical issues requiring safe, economical solutions for both onshore unconventional and offshore conventional production facilities. The recurring long-term mitigation of slugging and various flow-assurance phenomena—along with the prevention of wax, erosion, asphaltenes, corrosion, and salt deposition—and gas hydrate prediction and handling still demand attention and considerable project technical effort. Slug-flow assessments present opportunities for significant optimization in work flows to target governing operating scenarios. Paper OTC 30172 describes an integrated iterative approach between the flow-assurance and pipeline-engineering disciplines to streamline the work flow based on the value or cost associated with changes in input parameters that affect pipeline fatigue-assessment outcomes. Case studies on two multiphase pipelines are presented to illustrate this design approach. The results show that early identification of the key pipeline profile features and dominating spans for pipeline slugging fatigue assessments facilitated the optimization of slug-flow modeling and reduced computational time. The second paper, SPE 203448, presents decision trees that are considered as nonparametric machine-learning models. The data sets used in training and testing the predictive model are experimental and were collected from literature. Air/kerosene and air/water mixtures were used in obtaining the experimental data points. Results show that the proposed boosted decision tree regression (BDTR) model outperforms the best empirical correlations and the fuzzy-logic model used in estimating liquid holdup in gas/liquid multiphase flows. For the built model, the most important input feature in estimating liquid holdup is the superficial gas velocity. The empirical correlations developed in the past for identifying liquid holdup in multiphase flow can be applied only under the flow conditions by which they were originally developed. However, this machine-learning model does not suffer from this limitation. The third paper, OTC 31298, describes a slugging-control solution that was rejected because of the use of a pseudovariable as the principal control point. A novel control scheme, therefore, was developed and tested on simulations for both hydrodynamic slugging and severe riser-induced slugging in an Angolan field. The project implemented the novel active slugging control using a topsides control valve and topsides instrumentation. While a pseudovariable, a pseudoflow controller, was used, it was part of a cascade scheme such that the principal control variable was a real top-side pressure measurement. Upon com-missioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug-control scheme was effective in controlling incoming slugs. The desire to understand better how to describe and improve flow assurance and multiphase flow for both offshore and onshore facilities drives new production technology research, applications, and approaches. The three papers listed for additional reading focus on developing further new analytical tools while providing safe, cost-effective, and reliable operations for flow assurance. I hope you find them as interesting as I did. In addition, I invite you to join the Flow Assurance Technical Section to augment your learning. Recommended additional reading at OnePetro: www.onepetro.org. OTC 30177 - Real-Time Online Hydrate Monitoring and Prevention in Offshore Fields by Syahida Husna Azman, Petronas, et al. SPE 201316 - Modeling Dynamic Loads Induced by Slug Flows Considering Gas Expansion Caused by the Pressure Gradient in a Free Span Horizontal Hanging Pipeline by Gabriel Meneses Santos, Universidade Estadual de Campinas, et al. OTC 31238 - Taylor Bubbles of Viscous Slug Flow in Inclined Pipes by Longtong Abednego Dafyak, University of Nottingham, et al.

Integrated computer digital decision for Offshore production automated management

Rising requirements for the hydrocarbons production management system state are based on the industrial situation control necessity according to the environmental conditions. Development of the system construction and complexity indicates the integrative approach implementation reasonability for the producing capacity main indexes estimation and regularity of pace parameters evaluation as well as the layer productiveness level identification. Data processing and management tasks are the waymarks for the industrial multilevel structures models creation. Computer integrated model includes the estimated analytical tool for the extended operational functional support for the production parameters evaluation and technological process state diagnostics in changeable conditions and productive region origin and features traceability. Based on the well observations it is possible to apply the systematic approach for the trends occurrence and dynamics evaluation of the reservoir development time series data. And integrated decision includes the information value degree identification tool for the hydrocarbons production digital model updating.

Assessment of offshore liquid hydrogen production from wind power for ship refueling

Green hydrogen from electrolysis has become the most attractive energy carrier for making the transition from fossil fuels to carbon-free energy sources possible. Especially in the naval sector, hydrogen has the potential to address environmental targets due to the lack of low-carbon fuel options. This study aims at investigating an offshore liquefied green hydrogen production plant for ship refueling. The plant comprises a wind farm for renewable electricity generation, an electrolyzer stack for hydrogen production, a water treatment unit for demineralized water production, and a hydrogen liquefaction plant for hydrogen storage and distribution to ships. A pre-feasibility study is addressed to find the optimal capacities of the plant that minimize the payback time. The model results show that the electrolyzer capacity shall be set equal to a value between 80% and 90% of the wind farm capacity to achieve the minimum payback times. Additionally, the wind farm capacity shall be higher than about 150 MW to limit the payback time to values lower than 11 years for a fixed hydrogen price of 6 €/kg. The Levelized Cost of Hydrogen results to be below 4 €/kg for a wide range of plant capacities for a lifetime of the plant of 25 years. Thus, the model shows that this plant is economically feasible and can be reproduced similarly for different locations by rescaling the different selected technologies. In this way, the naval sector can be decarbonized thanks to a new infrastructure for the production and refueling of liquified green hydrogen directly provided on the sea.

Review of Energy Efficiency of the Gas Production Technologies From Gas Hydrate-Bearing Sediments

Even in the carbon-neutral age, natural gas will be valuable as environment-friendly fuel that can fulfill the gap between the energy demand and supply from the renewable energies. Marine gas hydrates are a potential natural gas source, but gas production from deposits requires additional heat input owing to the endothermic nature of their dissociation. The amount of fuel needed to produce a unit of energy is important to evaluate energy from economic and environmental perspectives. Using the depressurization method, the value of the energy return on investment or invested (EROI) can be increased to more than 100 for the dissociation process and to approximately 10 or more for the project life cycle that is comparable to liquefied natural gas (LNG) import. Gas transportation through an offshore pipeline from the offshore production facility can give higher EROI than floating LNG; however, the latter has an advantage of market accessibility. If the energy conversion from methane to hydrogen or ammonia at the offshore facility and carbon capture and storage (CCS) can be done at the production site, problems of carbon dioxide emission and market accessibility can be solved, and energy consumption for energy conversion and CCS should be counted to estimate the value of the hydrate resources.

Передовые практики нефтегазовых компаний по освоению газовых месторождений на арктическом шельфе

The development of the hydrocarbon potential of the Arctic shelf is one of the priority tasks for Russia, forming the conditions for its strategic presence in the region. Russia's official energy documents stipulate the need to increase oil and gas production in the Arctic, including offshore production, to ensure the stable operation of the country's oil and gas complex in the long term. However, the development of hydrocarbon fields on the Arctic shelf is a serious technological challenge for the domestic oil and gas in-dustry. While offshore oil production in the Russian Arctic is already underway, natural gas production remains a promising future target. The article analyses the current gas projects on the Arctic shelf in terms of their technological complexity and unique solutions, and the strategies of operators to attract foreign participants to the project. We consider these in the contexts of technological issues, organizational features, securing foreign investment. The author believes that the provisions and conclusions of this study will help add to the comprehensive picture of the foreign oil and gas companies experience engaged in natural gas production on the Arctic shelf, which will minimise the errors and risks in the development of hydrocarbon resources on the Russian Arctic seas shelf.

Impact of ocean waves on offshore wind farm power production

Offshore wind energy has seen a steady increase in the latest years as it serves as an ideal alternative energy source to meet our renewable energy goals. Due to this increase in interest and in installations of offshore wind farms a better understanding of the impact of waves on the power production of wind farms in necessary. This wave-wind farm power production interaction has scarcely been examined, however, some exceptions of small scale large-eddy-simulations exist. Unfortunately, these studies are not able to take multiple wind farms under real weather conditions into account. Here, we show the power production and wake lengths of 1250 offshore wind turbines located in the German Bight simulated by a stand-alone atmospheric (WRF) model and a coupled atmosphere-wave (WRF-SWAN) model. The coupled atmosphere-wave model estimates larger (smaller) power production in case of waves and wind traveling in the same (opposed) direction compared to the stand-alone atmospheric model. The relative difference between the two models can be as much as 20% for the two-week averaged grid power production, while the difference in total power over this two-week period is equal to 9%. Moreover, the wind farm wake lengths of waves and wind traveling in the same (opposed) direction are longer (shorter) for the coupled atmosphere-wave model compared to the stand-alone atmospheric model. Here, the relative difference of the mean wake length between the two models can be up to 25%. This shows the importance of waves as a part of the offshore wind environment and can be an important factor in future wind assessment or power production estimation studies.

Technology Focus: Offshore Facilities (September 2021)

For this feature, I have had the pleasure of reviewing 122 papers submitted to SPE in the field of offshore facilities over the past year. Brent crude oil price finally has reached $75/bbl at the time of writing. So far, this oil price is the highest since before the COVID-19 pandemic, which is a good sign that demand is picking up. Oil and gas offshore projects also seem to be picking up; most offshore greenfield projects are dictated by economics and the price of oil. As predicted by some analysts, global oil consumption will continue to increase as the world’s economy recovers from the pandemic. A new trend has arisen, however, where, in addition to traditional economic screening, oil and gas investors look to environment, social, and governance considerations to value the prospects of a project and minimize financial risk from environmental and social issues. The oil price being around $75/bbl has not necessarily led to more-attractive offshore exploration and production (E&P) projects, even though the typical offshore breakeven price is in the range of $40–55/bbl. We must acknowledge the energy transition, while also acknowledging that oil and natural gas will continue to be essential to meeting the world’s energy needs for many years. At least five European oil and gas E&P companies have announced net-zero 2050 ambitions so far. According to Rystad Energy, continuous major investments in E&P still are needed to meet growing global oil and gas demand. For the past 2 years, the global investment in E&P project spending is limited to $200 billion, including offshore, so a situation might arise with reserve replacement becoming challenging while demand accelerates rapidly. Because of well productivity, operability challenges, and uncertainty, however, opening the choke valve or pipeline tap is not as easy as the public thinks, especially on aging facilities. On another note, the technology landscape is moving to emerging areas such as net-zero; decarbonization; carbon capture, use, and storage; renewables; hydrogen; novel geothermal solutions; and a circular carbon economy. Historically, however, the Offshore Technology Conference began proactively discussing renewables technology—such as wave, tidal, ocean thermal, and solar—in 1980. The remaining question, then, is how to balance the lack of capital expenditure spending during the pandemic and, to some extent, what the role of offshore is in the energy transition. Maximizing offshore oil and gas recovery is not enough anymore. In the short term, engaging the low-carbon energy transition as early as possible and leading efforts in decarbonization will become a strategic move. Leveraging our expertise in offshore infrastructure, supply chains, sea transportation, storage, and oil and gas market development to support low-carbon energy deployment in the energy transition will become vital. We have plenty of technical knowledge and skill to offer for offshore wind projects, for instance. The Hywind wind farm offshore Scotland is one example of a project that is using the same spar technology as typical offshore oil and gas infrastructure. Innovation, optimization, effective use of capital and operational expenditures, more-affordable offshore technology, and excellent project management, no doubt, also will become a new normal offshore. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202911 - Harnessing Benefits of Integrated Asset Modeling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field by Yukito Nomura, ADNOC, et al. OTC 30970 - Optimizing Deepwater Rig Operations With Advanced Remotely Operated Vehicle Technology by Bernard McCoy Jr., TechnipFMC, et al. OTC 31089 - From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil by Paulino Bruno Santos, Petrobras, et al.

Debottlenecking Approach Revitalizes Aging Platform by Increasing Production 30%

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203321, “Integrated Debottlenecking Approach Revitalizes Aging Platform by Increasing Production 30% in Gulf of Mexico,” by Ankur Gandhi, Sara L. McConkey, and Jeremy Kimbrough, SPE, Occidental, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Successful identification, evaluation, and management of bottlenecks in a complex offshore production processing system is challenging but can increase daily production significantly. The Constitution platform in the Green Canyon area of the Gulf of Mexico, which was commissioned in 2006 with a nameplate capacity of 70,000 BOPD, is a complex system with four fields in varying stages of development. The complete paper focuses on a multidisciplinary process developed to identify, evaluate, and eliminate interdependent bottlenecks on the platform and its flowline network during a 16-month period; this synopsis details some of these findings. Integrated Process A study and field trial during 2016–17 demonstrated the ability to separate fluids above the design capacity, but the team faced challenges in terms of flow reliability even at lower production rates. Therefore, in 2017, an effort was launched to understand and mitigate this issue. The underlying process used for the effort stemmed from principles of Six Sigma and Gemba walks. The steps of the process, detailed in the complete paper, are as follows: 1. Define 2. Measure and analyze 3. Design 4. Verify and execute 5. Review The process allows the team to see the variance between perception and reality. The results-driven, continuous-improvement approach also increases visibility among leaders, giving them a chance to interact with subject-matter experts (SMEs) and to understand key bottlenecks. Platform Bottlenecks and Responses Reservoir and Subsea Network Deliverability. The rate uplift from the debottlenecking efforts was estimated using a reservoir simulation model that included a fully integrated subsea flow net-work model, which solved the reservoir and flow network equations in the same Newtonian iteration. This type of simulation model particularly is suited for the problem at hand, provided that the reservoir model adequately matches historical well performance and the network model matches historical friction pressure losses as a function of rate. The simulation model predicted that the reservoir should be able to deliver a rate uplift of 30% above the production rate before debottlenecking. Topsides Fluids Processing Debottlenecking: General. The late-life debottlenecking of the platform posed many process engineering challenges, some of which stemmed from the inherent flexibility for which the platform was designed. The multitude of gas paths available led to many viable operating alignments of sources to separators and then separators to compressor stages. One initial exercise for debottlenecking was to develop a matrix of potential future operating modes, which would account for the required operator flexibility, as well as to address compressor downtime and the resulting temporary rerouting of sources. Once this matrix was developed, topsides process simulations were developed for each to identify capacity requirements for each equipment item. As detailed in the complete paper, topsides fluids processes involving the oil-cooling system and oil-system hydraulics were also debottlenecked.