ABSTRACT
The ambitious five-year strategic business plan for Petrobras presented a challenge for its Surface Installation Engineering Department. This paper explores the business case behind the strategy, initiatives and identified issues that enabled Petrobras to design, plan, contract, build and deliver more than fifteen new O&G production systems. The company transformation relied on strategic parallel initiatives. Four areas concentrated the efforts: Corporate Integration, Surface Installations, Subsea Systems and Reservoir Wells. This article focuses on the analysis of the technical actions in the Surface Installation department. Nonetheless, it summarizes the related essential efforts, as well. The optimization process started with high level assumptions, for instance to reinforce one company value. That is, to keep and develop a strong in-house technical knowledge. This allowed to continue a previous development initiative to create internal Concept and Basic Design Engineering for Standard FPSO Design. The major challenge occurred during the COVID-19 pandemic. Petrobras mobilized its longest and largest Organizational Response Structure (EOR) team in its history. It involved all company departments with direct contribution of more than a thousand employees assigned for two years. With deep respect to the lives impacted and lost, there were lessons learned in this process, although Petrobras managed to continue its essential operations. From Corporate Integration perspective, Petrobras actively managed its asset portfolio to reduce the company's debt. Combined with favorable commodity prices, it allowed the company to restore and increase its financial situation to invest in oil production development despite observed volatility in the macroeconomic scenario. Regarding Reservoir and Wells, innovative technology created conditions to reduce the overall completion time. Subsea Systems layout optimizations and a more efficient resource management like the PLSV assigned fleet present significant contribution to the results. standardization process to evolve. Optimization in system machinery design templates saved time while respecting each project unique input design conditions. One of the results was a new series of FPSOs with All Electric concept design. It consequently tends to increase efficiency and overall reduction of greenhouse gas emissions. Another key point identified was the interface among Petrobras, its supply partners, and shipyards. Through a permanent FPSO market monitoring committee, the process of procuring technical qualification was updated and stimulated early engagement of critical equipment suppliers. Furthermore, Petrobras have been continuously improving the drafting of contract terms for each FPSO project to stimulate shared interest. Finally, there were also improvements during FPSO construction and commissioning phase. The above mentioned efforts are expected to increase the chances of Petrobras delivering its strategic plan and sustainable growth. There are lessons learned to undertake fifteen O&G production systems in a synchronous manner. This is a considerable number of offshore projects for any operator company. © 2023, Offshore Technology Conference.
ABSTRACT
The oil industry is experiencing a critical situation as the Covid-19 pandemic outbreak. There are several challenges that facing the industry specially the investors as the global decline in demand for Energy merchandises, the future exploration and development drilling in new assets that require massive investments is still uncertain based on the current market price and conditions. The much-reported fall in oil prices and the acute pressure on IOCs to survive in this environment led the companies to stop many ongoing projects and shrink work profile that affected the oil production all over the world. The situation in Egypt is quite challenging for the investors as Egypt is a big consumer, along with the political stability that kept the economy running directed the big IOCs to embrace innovative approaches to lower the operating costs that has the direct impact on the cost per barrel to support maintaining the country growth and secure current energy demand. Dragon Oil company as newly introduced to Egypt's market after acquiring the market shares of one of the major joint ventures in Egypt (Gulf of Suez Petroleum Company- GUPCO) in October 2019 has faced the same dilemma of exerted pressure on the expenditures (Capex and Opex) in order to cope with the global market circumstances. However that didn't deter the company to embrace an innovative way of thinking and handling for the situation. Dragon Oil/GUPCO multi-disciplinary teams achieved successfully a production incremental increase of 10,000 barrels per day through the past six month by adapting a strategic management innovative plans, alternative lower cost technical solutions, production optimization and introducing new proved technologies to the 50 years old assets. This paper will highlight the complete workflow adopted by GUPCO/Dragon Oil teams covering the whole process aspects;appraise, select, define and execution phases to achieve the company goals. The work done was including restoring production from Shut-in offshore platforms or wells via fixing the surface network using neoteric solutions, widely applying rigless interventions using several new techniques in the current producers to maximize their production and optimizing the production cycle across the four production chokes In Summary, Dragon Oil/GUPCO teams managed to increase GUPCO's production despite of the restricted budget and the negative impact of COVID-19 pandemic on the oil price and reach an outstanding performance in operation excellence and safety aspects that results in arresting the natural decline and increase the growth production by about 15% from the 2019 Average production. Copyright © 2023, Society of Petroleum Engineers.
ABSTRACT
The second phase of Johan Sverdrup came on stream in December 2022. This paper focuses on the execution of Johan Sverdrup phase 2 and describes the assessments and investments for improved oil recovery (IOR) from one of the largest oil fields in Norway. The Johan Sverdrup field development has been called Equinor's ‘digital flagship', and this paper includes the proof of concept for the digital initiatives after more than three years of operation. Despite the Covid-19 pandemic Johan Sverdrup phase 2 has been able to deliver on schedule, under budget, and with an excellent safety record. The paper includes experiences from the concept development and engineering phase to the global contracting strategy, through the construction on multiple building sites in Norway and globally, and until the end of the completion phase offshore Norway. Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS), and with recoverable reserves estimated at 2.7 billion barrels of oil equivalents, has the resources to be a North Sea Giant. Start-up of the Johan Sverdrup phase 2 extends and accelerates oil and gas production from the NCS for another five decades. This paper aims to highlight what it took to make Johan Sverdrup a true North Sea Giant, fit for the 21st century: a safe and successful execution of a mega-project, with next-generation facilities adapted to a more digital way of working, with an ambition to profitably recover more than 70% of the resources, while limiting carbon emissions from production to a minimum. In many ways the Johan Sverdrup development has set a new standard for project execution in Equinor. The impact of different variables made during the execution of the project, such as the Covid-19 pandemic, market effects, procurement strategies, value improvement initiatives, execution performance and reservoir characteristics is addressed, as well as describing assessments and investments for improved oil recovery (IOR). Data acquisition, Permanent Reservoir Monitoring (PRM), fibre-optic monitoring of wells, innovative technologies, and digitalization, as well as new ways of working are included. Equinor ´s digital strategy was established in 2017, and Johan Sverdrup was highlighted as a digital flagship at that time and a frontrunner in applying digital solutions to improve safety and efficiency from the development to the operational phase. What has been implemented so far together with experiences will be shared. © 2023, Offshore Technology Conference.
ABSTRACT
In a modern era of unprecedented events, such as the COVID-19 pandemic, energy matters now more than ever. What was previously impossible is now a challenge that should be met with measured risk and a mitigation plan. In early 2020, a service company pursued a solution to provide a compact surface well test (SWT) package for an extended well test (EWT) on an offshore production platform in the Zafaraana field with extremely high concentrations of H2S. The solution involved proper treatment and safe delivery of well effluent within acceptable H2S limits to a floating production storage and offloading (FPSO) facility. The EWT was to be installed for a long period to allow production from the reservoir, treatment of the effluent using H2S scavenger, and delivery to the FPSO facility by means of electric transfer pumps. This was the only way to produce because the FPSO facility could not accommodate the high H2S concentrations from the reservoir. A further challenge was that it was a simultaneous operation (SIMOPs) wherein the rig was engaged in drilling and completion activities of other wells on the same offshore platform;operational conflicts were identified during the HAZOP/HAZID meeting to help mitigate potential issues. Copyright © 2023, Society of Petroleum Engineers.
ABSTRACT
Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign. The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions. This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects. Copyright © 2022, Offshore Technology Conference.
ABSTRACT
In line with the losses brought about by the recent pandemic of the new coronavirus, the oil market, as well as other segments, has been facing economic difficulties to recover. Seeking to bring a practical and efficient strategy to the corporate environment, in this area, this study demonstrates a new multi-criteria method based on multi-objectives, capable of calculating the importance of each criterion, to encourage more assertive and objective decision-making to evaluate different situations in the oil industry, such as the application of resources, investments and other strategies. As a case study, a group of AHTS (Anchor Handling Tug Supply) vessels was used to supply offshore platforms and application of the CRITIC-MOORA-3N method, which allows a logical analysis of the relevant criteria and presents an objective solution, as result for the scenario that applies. © 2022 The Authors. Published by Elsevier B.V.
ABSTRACT
Low oil prices, coupled with operational challenges in offshore environment due to COVID-19 restrictions, have driven oil and gas operators to implement low-cost technological solutions to optimize fields' production. For mature oil fields in offshore East Malaysia, sand production has become one of the onerous challenges that requires this approach. Sand production is known to adversely affect the well deliverability and it also contributes to safety concerns due to surface flowline leak and equipment failure. Hence, it is of upmost importance for operators to address the sand production downhole. To achieve this, through-tubing sand screens (TTSS) installation is opted due to its ease of installation and low-cost slickline operation. Although there have been many TTSS installations to date, there is still limited understanding of the factors that affect TTSS lifespan, and this has led to frequent TTSS changeout. Based on the operator's experience, TTSS lifespan can vary significantly across different wells ranging from just a few days to years of production. To improve the understanding of TTSS performance with the aim to increase TTSS longevity, a comprehensive study on potential contributing factors has been conducted by analyzing the past TTSS installations. Over the years, there were more than 75 TTSS installations performed in oil fields offshore East Malaysia. Lookback analysis was conducted to evaluate the effectiveness of TTSS as remedial downhole sand control and investigate the factors affecting TTSS performance such as TTSS type, well production rates, TTSS deployment method, installation depth relative to perforation interval and well interruption frequency. Several criteria identified as the key performance indicators have been investigated to evaluate the performance of each TTSS installation, including the well flowing parameters, production uptime and sand production trend. Thorough study across different TTSS installations has concluded that TTSS lifespan varies according to well properties and well operating parameters. This paper presents best practices and lessons learnt from past installations to predict and improve the mean time between failures (MTBF) for TTSS. Case studies for several wells have been scrutinized to highlight the learnings for further enhancement of TTSS lifespan. Additionally, recommendations for further research and development of erosion resistant TTSS technology are also discussed. Copyright © 2022, Society of Petroleum Engineers.
ABSTRACT
During the early stages of the Covid pandemic, the oil and gas industry was faced with significant challenges in executing inspections for ageing offshore oil and gas infrastructure together with the management of various operational integrity threats. These challenges were addressed through the collaborative development of remote, digital techniques to minimise inspector time offshore and maximise efficiency. This initially involved a review and challenge of our existing operational integrity management lifecycle, comprising systems data, risk-based strategy development, inspection planning, inspection execution, data management, anomaly management (including fabric maintenance and engineering repairs) and closeout. Working with our partner, GDi, we sought to drive a step change into digital integrity management, combined with streamlined workflows, activities, and administrative tasks. The pilot development involved comprehensive laser scanning of a floating production storage and offloading (FPSO) facility to generate a dimensionally accurate digital twin, overlayed with 360° HD photogrammetry to provide a thorough baseline for subsequent general visual inspections of pressure equipment, piping systems and structural elements. General visual inspections can now be executed remotely, without the requirement for an offshore inspector. The digital twin environment also supported transformation of inspector-led activities, through optimisation of processes, digital inspection workflows via tablets and seamless integration with the integrity management platform. The pilot development also involved enhancing the anomaly risk management process, including management of mitigations (such as temporary repairs) and actions required to resolve and close anomalies. For the anomaly actions, the digital twin environment enables the accurate estimation of fabric maintenance scopes and dimensionally accurate repairs for corrective work orders. The system also facilitates a unique overview of cumulative risk via the plotting of anomalies in the digital twin space. The digitally enhanced operational integrity management system has substantially reduced direct costs and personnel safety risks, enabled substantial improvements in productivity (up to 200% for inspections), and improved the quality of integrity management outcomes. Copyright © 2022, Society of Petroleum Engineers.
ABSTRACT
For an upstream oil and gas company, avoiding an offshore COVID-19 outbreak while executing four different offshore projects poses a huge challenge, particularly in a country experiencing a daily COVID-19 test positivity rate over 20%. Even minor mismanagement of the quarantine process can lead to an offshore COVID-19 outbreak, with the risk of shutting down campaigns and severely impacting business objectives. The challenge is therefore to avoid an offshore COVID-19 outbreak, ensuring well-being of personnel during the quarantine period and managing quarantine related costs, including COVID-19 test costs. To ensure effective quarantine management, a new approach was created that applied a combination of medical assessments, Health & Safety (H&S) and security measures. Quarantine management was led by a special task force responsible for ensuring the readiness of transportations, rooms, PCR tests, as well as overall compliance to quarantine rules. In compliance with government regulations and WHO recommendations, another complimentary approach was applied that sequestered personnel who tested positive in an isolation room. Effective quarantine management was established with the assistance of the company Business Continuity Management Team (BCMT). The company was able to complete four different major offshore projects with no offshore COVID-19 outbreaks. During these operations, over 1,000 personnel were quarantined and tested with a 5.37% positivity rate at the pre-work quarantine site. Confirmed cases were managed in full compliance with government regulations. The result of this effective quarantine management system, has allowed the company to achieve scorecard performance goals while delivering all four of the major offshore work-scopes, as per the original business plan. This paper discusses quarantine management as part of business continuity management covering medical assessment, H&S and security measures amidst a national COVID-19 pandemic. These programs were applied in an adaptive method-based risk assessment, which based on evidence base approaches, during frequently changing government regulations. Copyright © 2022, Society of Petroleum Engineers.
ABSTRACT
PETRONAS completed Well H16 in BS field, East Malaysia with a Digital Intelligent Artificial Lift (DIAL) - an improvement to the current applied gas lift system in the field for production optimization system. This DIAL installation represents the first ever successful installation of the technology in an Offshore oil well for Dual String production. This paper provides the details of the installation planning, designing stages, operational process, well unloading and production undertaken to achieve this milestone. DIAL is a unique technology that enhances the efficiency of gas lift production. Downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention which will be challenging in high deviation well (more than 60-degree deviation). With remotely operated, non-pressure dependent multi-valve units, the technology removes the challenges normally associated with gas-injected production operation in a dual completion well i.e., gas robbing and multi-pointing. DIAL introduces a paradigm shift in design, installation and operation of gas lifted wells. This paper will briefly highlight the justifications of this digital technology in comparison with conventional gas lift techniques. It will consider value added from the design stage, through installation operations, to production optimization. Digitization and automation have become the new concepts in managing the operations in order to boost efficiency that reflected in long-term cost savings especially in Operating Expenditure (OPEX). This paper focusses on a well completed in November 2020, the fourth well to be installed with the DIAL technology across PETRONAS Assets. The authors will provide details of the well strategy, installation process and production phases: system design, pre-job preparations, improvements implementation, run in hole and surface hook-up. The results of well unloading while utilizing the DIAL system to start up the well and lifting the completion brine will be explained in detail in this paper. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits. Despite the additional operational & planning complications due to COVID-19 restrictions, the well was completed with zero Non-Productive Time (NPT) and Loss Time Injury (LTI). Once brought online, this DIAL-assisted production well can be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS' upstream digitization strategic vision. © 2022, Society of Petroleum Engineers.
ABSTRACT
Operator's Wells Abandonment & Decommissioning campaign consists of 15 Deepwater subsea wells in Field "C" offshore West Africa. Discovered in 2001, the field is located approximately 80 km west of coastline and about 90 km from Nouakchott, capital of Mauritania. Field "C" is a deepwater field in water depth ranging from 730m to 830m. The field was developed using subsea wells, Hinged Over Subsea Templates (HOST), manifolds, flexible flowlines, umbilicals, and risers tied back to a permanently moored FPSO. In total, the field consists of nine (9) oil producer wells and five (5) water injection wells. During the development stage, one (1) gas injection well was drilled and completed at adjacent Field "B" about 17 km Northeast of Field "C". The water depth at this gas injection well location is approximately 280m. Field "C" reached maturity in 2016. Due to high operating costs, declining production coupled with declining oil prices, the decision was made to cease production, plug and abandon (P&A) and decommission the field. Two phases strategy was engaged by the Operator in order to complete the decommissioning and abandonment of Field "C". In Phase 1, which was executed back in the year of 2017-2018, all the 15 deep water subsea wells were temporarily suspended with two (2) barriers in place. The Floating, Production, Storage and Offloading (FPSO) unit was decommissioned and disconnected. In line with the strategy of dividing the project into two phases, the information on well integrity and conditions acquired during the Phase 1 Temporary Wells Suspension (TWS) was used by the Operator in planning for Phase 2 - Wells Plug and Abandonment (P&A). The operator made full use of temporary well suspension period between Phase 1 and Phase 2 for engineering, procurement, and operations preparation. The same drillship was utilized for the project in both phases. Multiple optimizations and modifications were done on the drillship based on lessons learned in Phase 1 and to cater for the subsea Xmas Tree and subsea structures retrieval in Phase 2. Due to the nature of the remote location and no existing oil & gas operations support base, all equipment required in this project was sent to Mauritania early. Equipment inspection and acceptance were carried out in Mauritania as part of the strategy in ensuring the availability of good quality equipment for offshore operations. The operations on Wells Plug & Abandonment commenced in December 2019. In March 2020, upon declaration of the COVID-19 pandemic, operator was faced with difficulty of continuing operation as the Host Country activated border lockdown. The operator managed to continue operations for remaining well and demobilized drillship and personnel safely. Operator has successfully retrieved three (3) subsea Xmas Trees, P&A three (3) wells and intervened six (6) other wells for tubing cutting before operations was suspended due to COVID-19 pandemic. Operator used the suspension phase to devise a methodology to resume operation in the prevailing COVID-19 pandemic situation. The challenges faced during the COVID-19 pandemic as well as the steps taken for resumption are highlighted in this paper. It is expected that this paper will serve as guidance in highlighting challenges and efforts taken to resume operation in the event of unforeseen suspension due to any reasons. It is also hoped that the details shared in this paper can assist other Operators in better operation planning for remote locations. Copyright © 2021, Society of Petroleum Engineers
ABSTRACT
In 2020, PCSB implemented the first permanent Plug & Abandonment (P&A) campaign for three Subsea wells in a gas field offshore Malaysia. The main objective of the campaign was to establish two (2) barriers for every movable hydrocarbon or overpressure bearing sand by placing laterally extended cement plug across impermeable formation with enough formation strength to handle the pressure of the formation to be isolated. The unique case of this operation was the challenges to execute PCSB's first subsea P&A operation in gas field Malaysia during pandemic situation. In March 2020, the Malaysian government imposed Movement Control Order (MCO) to curb the spread of the COVID-19. A semi-submersible rig was on-hired a week after government initiated the MCO, resulted in the rig preparation being badly hampered due to manpower management and material fabrication and delivery. PCSB was exposed to expensive rig daily rate that had to be managed. Four (4) main challenges were encountered during operation: safe protection for workers, expensive standby cost, manpower management and material fabrication and delivery. This paper, from the 'project management' point of view, describes the journey of managing rig operation during PCSB's first subsea wells P&A in Malaysia efficiently amidst the pandemic by reducing the impact of COVID-19 on project cost. With the experience of managing rig for subsea well operation, a complex operation in Malaysia, amidst pandemic, PCSB sharing on the experience is beneficial to provide context setting and benchmark on maintaining the efficiency of operation. Wells successfully met the objective of operation with no incident occurred, negotiated reduction on standby cost and managed to bring critical manpower on time during operation. Copyright © 2021, Society of Petroleum Engineers
ABSTRACT
Avoiding an offshore COVID-19 outbreak while executing an urgent and intricate pipeline repair campaign is a significant challenge, especially in a country that is experiencing a COVID-19 positivity rate of more than 20% on daily basis. Any minor mismanagement of health management on the DSV (diving support vessel) may lead to a COVID-19 outbreak with the risk of shutting down the campaign and significantly impacting the business continuity objectives. Therefore, the major health management challenge is to avoid a COVID-19 outbreak on the DSV to ensure the well-being of personnel during campaign and to achieve the necessary pipeline repair. The approach taken was to deploy the DSV with team and tools/equipment as soon as possible to avoid a prolonged platform shutdown due to the pipeline leak event. In order to carry out the project, a detailed risk assessment taking account of medical, logistics and security considerations was undertaken in order avoid a COVID-19 outbreak on the vessel. The risk assessment enabled an adjustment to the quarantine requirements for the pipeline repair team before departure to the work location. A contingency plan was also developed to manage a scenario in which a member of the offshore team was infected with COVID-19, and in order to comply with applicable government regulation. Through the effective implementation of a detailed risk assessment, the company was able to complete the pipeline repair campaign without any offshore COVID-19 outbreaks. On the DSV there were 65 personnel working on multiple activities to execute the pipeline repair works on time and on budget. The site team made a diligent effort to follow the mitigations identified in the risk assessment, under the direction of company Business Continuity Management Team (BCMT). As a result of this effort, the company was able to resume production from the offshore platform in a timely manner. This paper discusses the effective implementation of detailed risk assessment on a DSV as part of company business continuity management amid COVID-19 pandemic in the country, including medical, logistics and security considerations. This project was implemented in a year-end period, beyond normal conditions and in a tight schedule. © Copyright 2021, Society of Petroleum Engineers