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Collaborating Authors
Abstract Guyana's oil and gas production commenced in December 2019 with the Liza Destiny floating production, storage, and offloading (FPSO) vessel for the first phase development of the Liza Field located in the south-eastern portion of Stabroek Block, offshore Guyana. Esso Exploration and Production Guyana Limited (EEPGL) achieved first oil on Liza Unity, the second FPSO in Guyana, in February 2022. A robust process of implementing lessons learned from Liza Destiny commissioning and start-up were adapted by the Liza Unity team. The Liza Unity FPSO is moored approximately 190 km offshore Guyana in 1600-1700 m of water depth. The FPSO is designed to develop the remaining portions of the Liza field, that were not targeted in first phase of development. The subsea system includes eight subsea manifolds (four production and four injection) tied back directly to the FPSO through ten flowlines, ten risers and two dynamic umbilicals to provide power, control and subsea chemicals. Personnel safety, process safety, and environmental performance were prioritized during start-up. Liza Unity achieved background flare within 60 days of start-up with operations continuing to bring new wells online and achieve the initial investment basis oil production capacity of 232 kbd in six months. This paper will present: The strategy and integrated approach to achieve first oil, ramp up to the initial investment basis oil production capacity, and production optimization, while maintaining focus on personnel safety, process safety and the environment Well start-up strategy, reservoir data gathering, and reservoir management of a complex reservoir with wide range of fluid properties Start-up challenges and mitigations First Water-Alternating-Gas (WAG) conversion in Guyana Reliability performance The overall journey from first oil to achieving the initial investment basis oil production capacity was carried out by the Liza Unity team within its first year of operations. This is a result of an integrated approach demonstrated by all the technical and operations disciplines. This paper will elaborate on the challenges tackled by Liza Unity while generating value for all the stakeholders and the people of Guyana.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.32)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Stabroek Block > Liza Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Overall Field (0.99)
Application of Key Deepwater Lessons Learned in Marginal Deepwater Development, Offshore Malaysia
Khalid, Aizuddin (PETRONAS Carigali Sdn Bhd) | Hamza, Norashikin (PETRONAS Carigali Sdn Bhd) | A Rahim, Mas Rizal (PETRONAS) | A Rahman, Amir Ridzwan (PETRONAS Carigali Sdn Bhd) | Patma Nesan, Thanavathy (PETRONAS Carigali Sdn Bhd) | M Sahid, Norhayati (PETRONAS Carigali Sdn Bhd)
Abstract L & B fields offshore Sabah, Malaysia will be the next deepwater development in Malaysia after Kikeh, Siakap North-Petai, Gumusut-Kakap & Malikai. However, in comparison, L & B are considered marginal in terms of recoverable volumes and size of project, making it crucial to design and execute the project sharply to ensure value delivery. 5 key deepwater lessons learned areas are discussed in this paper as applied to L & B Field Development Plan (FDP) to ensure technical robustness based on experience of surrounding deepwater fields. The first key area is subsea production stability and flow assurance. Among critical evaluations conducted were techno-commercial comparison of dual-loop pipe-in-pipe against heated pipe-in-pipe, upfront artificial lift plans, and water injectors design to avoid hydrates formation as observed in another field. The second critical area is in drilling where key lessons were to conduct thorough geohazard analysis for hazard identification and avoid wellhead subsidence. Thorough geomechanics and fracture gradient were also assessed to identify requirements for managed-pressure drilling and for backup designs. The third key area is well integrity, productivity and injectivity where sand production and fines migration risks need to be addressed through well completion strategy. The reservoir management plan must also reflect realistic production and injection plans and data crucial for monitoring. The fourth key issue is with regards to subsurface complexity in deepwater turbidite environment with risks to production attainability vis-ร -vis reservoir connectivity and compartmentalization issues. A no-stones-unturned approach was taken integrating available static and dynamic data to estimate a robust recoverable volume. The fifth critical area is well startup and unloading procedures, which is important for well productivity. Model iterations were needed to conduct methodical well bean-up to eliminate risk of fines movement. Application of lessons learned in these 5 key areas led to robust development plans with mitigations for risks common to deepwater developments offshore north Borneo. For flow assurance strategy, the evaluation led to dual-loop design, proactive artificial lift strategy and optimum water injector locations. Drilling requirements are identified for MPD and backup slim-hole designs. To ensure productivity and injectivity, long highly deviated wells, with downhole sand mitigations, are designed for maximum contact and reduced required drawdown. Skin factors were applied in subsurface modeling as observed in other fields to risk the production targets. The model was also calibrated with dynamic data gained from well tests and pressure points to provide realistic production estimates, with a well sequence plan to observe actual performance and optimize next well locations if necessary. For well startup procedures, model iterations guided by analogue fieldsโ experiences led to optimum startup designs for L & B. These 5 key lessons learned areas are critical in deepwater development plans to ensure technical robustness during development stage to protect high investment value.
- Asia > Malaysia > Sabah > South China Sea (0.34)
- North America > United States > Texas (0.28)
- Asia > Malaysia > Sabah > South China Sea > Sarawak Basin > Baram Delta Province > Block G Production Sharing Contract > Block G > Malikai Field (0.99)
- Asia > Malaysia > Sabah > South China Sea > Sarawak Basin > Baram Delta Province > Block K > Kikeh Field (0.93)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
Formation Damage History In The Mature Fields of Campos Basin Offshore Brazil
Rodrigues, Valdo Ferreira (Petroleos Brasileiro S.A.) | Neumann, Luis Fernando (Petrobras S.A.) | Miura, Kazuo (Petrobras) | Tinoco, Francisco (Petroleo Brasileiro S.A.) | Netto, J. (Petroleo Brasileiro S.A.) | Daher, Jose Sergio
Abstract The Campos Basin mature fields, offshore Brazil, including the Marlim Field, are usually referred to as the World's deepwater field laboratory. The development of these fields was driven by the Brazilian state energy needs throughout the seventies and eighties, which induced a strategy of accelerating the projects implementation and anticipating their first oil. This sense of urgency is still dominant in Brazilian oil politics and has recently enabled the country to reach its oil self-sufficiency. That scenario throughout the last two decades encouraged risk assumption as well as the implementation of a considerable number of new technologies. Fifteen years after the first oil production from Marlim it seems that more engineered solutions are replacing the daring initiatives and the concise studies carried out in the beginning. Those years also testified an outstanding evolution of the drilling and completion technologies. The development advance to deeper and deeper waters brought up unpredicted problems such as wax deposition and hydrate formation. Thus, the history of the mature deepwater fields of Campos Basin offers great opportunities for learning, in a wide perspective. This paper summarizes the history of the damage and main completion troubles associated to Campos Basin deepwater mature fields. The aspects of prediction, prevention and remediation of the formation damage associated to drilling, sand control, stimulation, fines migration, organic deposition, scale, souring and other minor issues are addressed. The paper also presents some statistical data, predicted and unpredicted problems, and the ways they have and are currently handled. The technologies evolution and the most recent challenges are also shown. It is our belief that other deepwater mature fields to be developed and the new systems to be designed will certainly benefit from the experiences and lessons learned in the deepwater mature fields of Campos Basin.
Introduction This paper presents a case study based on internal information and previous published papers.
Damage can be anything that hinders the regular flow of fluids from the formation until the production export lines. Formation damage, or skin effect, specially refers to any obstacles occurring in the near-wellbore region of the rock matrix1. Damage can be classified in pseudodamage, natural damage, and induced damage. Positive pseudodamage is a result of the well completion configuration, caused by limited entry to flow, off-centered wells, poor perforation design, mechanical flow restrictions, inadequate fluid-lift systems, laminated reservoirs, and rate and phase effects1. The pseudodamage or pseudo skin can be negative as in the case of deviated wells, where it is related to the deviation angle and the formation thickness2. Natural damage includes fines migration, swelling clays, water-formed scales, organic deposits (paraffin or asphaltenes), mixed organic/inorganic deposits, and emulsions. Induced damage is caused by plugging from entrained particles, wettability changes, acid reactions, acid by-products, sludge, bacteria, water blocks, and incompatibility with either drilling or completion fluids1. This work covers the natural and induced damages that mostly impacted oil production in Campos Basin (CB).
This paper focuses on mature fields as those that have achieved their peak production as estimated in the original development study. Mature fields are associated with water production, pressure depletion, as well as wells installations ageing. These can either start or aggravate several damage mechanisms, not mentioning solids production and water management issues. The typical mature field in CB shallow waters considered in this study is the Namorado field. On the other hand the typical deepwater mature field is the Marlim field, usually referred to as the World's deepwater field laboratory. A general description of both fields is presented later in the scale history section. Deep and ultra-deep water fields are emphasized because they have been responsible for the major production losses due to damage in CB.
Water depth range is a dynamic concept related to the technologies required by the challenges imposed by drilling deeper and deeper. Currently the Brazilian state owned operator (BSOO) classifies water depth (WD) as: shallow water (WD<300 m), deep water (300 m
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (1.00)
- North America > United States > Texas (1.00)
- Research Report > New Finding (0.66)
- Overview > Innovation (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- South America > Brazil > Sergipe > South Atlantic Ocean > Sergipe-Alagoas Basin > Guaricema Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlin Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Macae Formation (0.99)
- (7 more...)
Abstract Riser Base Gas Lift is one of several methods successfully deployed that can enhance production and suppress severe slugging. With few moving parts, it is a solution that can be accommodated into existing infrastructure with minimal upgrades on existing facilities while not being as maintenance intensive as other solutions. The flow assurance design is critical to successful implementation and this paper details this process through the means of a case study. The case study in question is a three well, deep water subsea tie-back. The subsea system consists of an 8" ร 12" pipe-in-pipe round-trip piggable flowline loop which will experience severe terrain slugging. Riser base gas lift had been implemented with success on adjacent fields at this facility; therefore it was again selected for deployment. From a Flow Assurance perspective, design considerations discussed are: Flowrate requirements that will effectively mitigate slugging and will not violate any operating constraints. Design against brittle material failure. Assessment of droplet erosion. Design to prevent formation of hydrates/asphaltenes in the production system due to injection of gas. Since system design is heavily dependent on the accuracy of simulation modelling, details of equipment flow tests to validate performance are discussed. Development of standard operating practices associated with gas lift. Detailing design adaptations to system changes during installation etc. Review of actual operational performance against design intent. For this field, a novel technological solution of a gas-lift umbilical riser was selected. This configuration provides the best balance of operability, reliability and cost. The operating philosophy uses a fixed subsea orifice /topside choke to control the gas flow (rather than the conventional variable subsea choke). The orifice will regulate the injection rate even as the system pressure varies due to slugging, allowing the umbilical to act as an accumulator that dampens the pressure variations and allows for a larger bandwidth and smoother operation. Ultimately this configuration is envisioned to be less dependent on operator interaction.
- Research Report (0.46)
- Financial News (0.34)
Frontiering Ultra-Deep Water Gas Field Development, Offshore Black Sea - Turkey: Solutions to Complex Well Testing Challenges and Proving Production Potential
Ayan, C. (Turkish Petroleum) | Aktepe, S. (Turkish Petroleum) | Cig, K. (Turkish Petroleum) | Gokmen, M. (Turkish Petroleum) | Ceyhan, A. (Turkish Petroleum) | Tugan, M. (Turkish Petroleum) | Shumakov, Y. (SLB) | Dolu, A. (SLB) | Theuveny, B. (SLB)
Abstract Increasing demand on reliable energy resources have led to an increased exploration activity for untapped hydrocarbon resources in deep-water. The recently discovered, but fast-tracked Turkey's Sakarya offshore natural gas field development is also a result of the country's commitment to energy independence. This paper describes the dynamic reservoir characterization considerations, challenges, and engineering solutions to de-risk field development decisions, confirmed by a well test campaign in a complex setting, with no tolerance to failure. In Sakarya field, a live field development planning approach was applied, where the development plans were updated rapidly, in parallel with the dynamic reservoir characterization process. Therefore, a strong link between static modelling, advanced logging and dynamic well behavior analysis had to be established. In addition, proof of concept for the well completion design had to be validated. Following an unprecedented, detailed formation evaluation, fine-scale reservoir and transient wellbore simulations, five well tests were designed and executed. The design considerations and execution challenges included the completion type, big fluid losses and high risk of hydrate formation in the deep-water environment. Five successful well tests were completed in ultra-deep water and led to the initiation of the first ultra-deep water natural gas field development in Turkey. The detailed formation testing campaign played a key role in selecting production intervals and optimizing well completion. In light of the high-resolution vertical formation evaluation, well tests were designed to prove reservoir extent, connectivity and long-term production potential of the field. Completion design and the actual conditions observed during the execution were compiled and simulated using fine-scale reservoir modeling and transient wellbore simulations to assess all potential risks during well test. The tests were executed successfully, revealing critical well deliverability and reservoir characterization information. Completion brine losses into the formation, hydrate formation risks at low subsea and surface temperatures, completion and formation differential pressure considerations were evaluated with real-time data analysis. Well test execution plan was updated real-time to achieve critical reservoir information. This closely integrated characterization and field development planning approach led to keeping the tested wells as production wells, thus improved efficiency, minimized cost, minimized environmental impact and accelerated time to first production. Many technical challenges and time limitations were overcome during this work. Application of detailed formation testing practices, cased hole gravel pack completion in an offshore environment with hydrate risks and closely integrating the observations with the well test design by a multi-skilled team led to accurate well test simulations, correct test design and successful execution with excellent quality information. This paper allows readers to experience technical considerations in the design and execution steps for successful well test.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-43-L > Pyrenees Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-42-L > Pyrenees Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-12-R > Pyrenees Field (0.99)
- (20 more...)