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Australian explorer Woodside Energy has returned its TTDAA 5 block, which it held in joint venture with Shell, back to the government following an appraisal of the Victoria discovery could not prove up positive economics for a potential development. Woodside cited the high costs associated with a deepwater project as one reason for the move. Woodside held a 65% working interest in the block. Shell held the remaining 35%. Woodside got into the Trinidad and Tobago offshore oil patch in 2013 and in 2018 encountered gas with its Victoria-1 well.
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (0.77)
- Management > Asset and Portfolio Management (0.69)
BP Trinidad & Tobago (BPTT) confirmed the safe delivery of first gas from its Cassia C development. Cassia C is BPTT's first offshore compression platform and its largest offshore facility, according to the company. The platform enables BPTT to access and produce low-pressure gas resources from the Greater Cassia Area. It is the company's 16th offshore facility and is connected to the existing Cassia hub located about 35 miles off Trinidad's southeast coast. "First gas from Cassia C is an important milestone for BP in Trinidad and Tobago," said BPTT President David Campbell.
The Subsea Integration Alliance (SIA), a OneSubsea and Subsea 7 joint venture, was awarded a contract by BP Trinidad and Tobago to support the development of the Cypre gas project offshore Trinidad and Tobago. Subsea 7 will handle the concept and design and the engineering, procurement, construction, and installation of a two-phase liquid natural gas tieback to the Juniper platform through dual flexible flowlines and a manifold gathering system, along with topside upgrades. OneSubsea will provide the subsea production system. "We have been working closely with BP and our suppliers at the earliest possible stage to help develop and deliver an integrated SPS [subsea production systems] and SURF [subsea umbilicals, risers, and flowlines] solution that optimizes cost and efficiency to accelerate first gas," said Craig Broussard, vice president for Subsea 7. Work on the design, engineering, and project management scope of the project has started at Subsea 7's US offices. Offshore installation is planned for 2024, the contractor said in a release on 18 November.
Abstract It is an unpalatable truth that all engineering and construction works, either onshore or offshore will have an environmental impact, during all the design, fabrication, and operational phases. Balancing the worldwide need for hydrocarbons with the desire to maximise the ESG benefits of an offshore development require a change in the way we approach both platform design and project implementation. In this paper we highlight the main points in this approach to platform design, and the direct and indirect benefits gained. A case study is presented, where sustainability was at the core of both the clients desires but also in the design philosophy used. The outcome of this project and the benefits gained are also outlined. The next steps to be considered in this philosophy are also discussed, where additional benefits gained from the use of Digital Twins can be leveraged to provide further potential reductions in the overall carbon footprint.
- North America > Trinidad and Tobago (0.29)
- Asia (0.28)
BP Trinidad and Tobago (BPTT) announced that it is moving forward with the development of its Cypre offshore gas project. It includes seven wells and subsea trees tied back into BPTT's existing Juniper platform via two new 14-km flexible flowlines. The company operates in 745,000 acres off Trinidad's east coast and has 16 offshore platforms and two onshore processing facilities. Drilling at the Cypre gas field, located 78 km off the southeast coast of Trinidad at a water depth of 80 m, is to begin in 2023. First gas from the facility is expected in 2025.
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (0.59)
- Facilities Design, Construction and Operation > Facilities and Construction Project Management > Offshore projects planning and execution (0.40)
DeNovo Energy has started gas production from the offshore Zandolie field in Trinidad & Tobago. The field, located in the Gulf of Paria off the west coast of Trinidad, is DeNovo's second offshore development following the Iguana field development in the same Block 1(a). The $52-million investment by the Trinidad-based DeNovo demonstrates the company's commitment to increasing Trinidad's natural gas supply by developing stranded and marginal gas reserves, it said in a statement. Gas from the field is produced through a single well, conductor-supported platform with a nameplate capacity of 40 MMcf/D of gas. This unmanned facilities platform, designed by UK-based offshore engineering firm Aquaterra Energy, is installed in 20 m of water, and tied back to the Iguana platform.
- North America > Trinidad and Tobago > Gulf of Paria > Block1a > Zandolie Field (0.99)
- North America > Trinidad and Tobago > Gulf of Paria > Block1a > Iguana Field (0.99)
- North America > Trinidad and Tobago > Gulf of Paria > Block 1(a) > Zandolie Field (0.99)
- North America > Trinidad and Tobago > Gulf of Paria > Block 1(a) > Iguana Field (0.99)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.80)
- Management > Asset and Portfolio Management (0.78)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Platform design (0.58)
- Health, Safety, Environment & Sustainability > Environment > Climate change (0.56)
The new Juniper offshore platform has begun its journey toward the southeast coast of Trinidad where it will be installed as BP Trinidad and Tobago LLC's (bpTT)'s 14th offshore installation. The Juniper project is a USD 2-billion investment in Trinidad and Tobago and one of BP's largest start-up projects in 2017. It comprises a platform made up of jacket, piles, and topsides, and corresponding subsea infrastructure, which will be installed 50 miles offshore in 360 ft of water. It is the sixth platform that bpTT fabricated in T&T. As bpTT's first subsea field development, Juniper will have a production capacity of approximately 590 MMscf/D, which will flow to the Mahogany B offshore hub via a 10-km in-field flowline, which was installed in 2016.
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.61)
Abstract This case study describes the successful outcomes and learnings from a brownfield tie-back project in offshore Trinidad. The greater Angostura Asset consists of multiple Oligocene-age turbidite sandstone reservoirs with complex geology and compartmentalization. The Asset has produced oil since 2005 from thin oil rims overlaid by large gas caps. This has been supported by significant gas reinjection and constrained by gas coning. Commencement of gas sales added value but also increased gas cap blowdown in the oilfields. The Angostura Phase 3 project was conceptualized to enable gas production from an adjacent gas discovery and extend the overall productive life of the existing oil fields. Key subsurface uncertainties and operational constraints were identified early in the project. Historically, drilling in the Angostura field has been challenging due to the complex geology and compartmentalization. Poor seismic data in the Phase 3 area added complexity to optimal well placement. Ensuring high deliverability was another critical project requirement. The main reservoir management challenge in the existing fields was optimizing both oil and gas sales while managing voidage and coning. Limited topside facilities and space constrained addition of new gas at flowing at higher pressures. To address these challenges, a multi-disciplinary project team was formed to plan and execute the project. Material balance, detailed geological modeling and numerical simulation were used to understand the impact of key uncertainties on recovery. The integrated evaluation resulted in an optimized development plan with three subsea gas wells tied back to existing facilities. Production performance of existing wells helped highlight critical performance drivers for Phase 3 wells. Modified completion designs along with a flow back and stimulation program during completion helped to maximize productivity. Phase 3 wells have performed at the high levels expected during project design and sanction. Detailed surveillance (including pressure transient analysis (PTA) and interference testing during completion, start-up and production phases) has continuously helped to optimize production. Oil production in the existing fields has also been improved by better balancing gas sales and injection. The project added significant value from the increased gas sales and oil production. This paper discusses the planning, successful execution and impact on the overall value of the Angostura Asset from the Phase 3 project. Optimized completions along with an improved approach for evaluating stimulation options during completion (detailed near well-bore modelling, real-time PTA and simulation) enabled strong well performance. We highlight some of the critical factors for achieving success in brownfield tie-back projects including having (right from project inception): multi-disciplinary project teams, tight coordination with existing operations and a focus on key uncertainties and constraints. Building optionality and flexibility into development plans and being prepared for contingencies have been the other critical learnings from this project
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean (1.00)
- North America > Mexico > Veracruz (0.89)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.60)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin (0.99)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Venzuela Basin > Darien Ridge > Block 2c > Greater Angostura Field > Angostura Field > Aripo-1 Well (0.98)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Venzuela Basin > Darien Ridge > Block 2c > Greater Angostura Field > Angostura Field > Angostura-1 Well (0.98)
- (4 more...)
Abstract Trinidad and Tobago is exploring 9 frontier blocks in water depths 1800 to 2200m. 3D seismic was completed in 2015 and the first well is to be spudded by mid-2016. As per the contracts, a minimum of 8 exploration wells are to be drilled. This paper aims to determine how small an oil or gas field could be and still generate economic rent. The taxation system and contractual obligations for two blocks were used to model oil fields of reserves 150 and 300 mmbbl and gas fields of reserves 2400 and 4800 Bcf. The production rates and oil/gas prices were varied to determine their impacts on investment criteria like NPV, IRR, payback time and government take. The models were used to project the minimum field sizes at different oil and gas prices that would be commercial. At $60/bbl, the minimum economic size for a standalone oil field is approximately 300 mmbbl reserves. Economic means that the field must attain a positive after tax NPV @10%. None of the gas models were economic at $3/mcf. It was projected that at this price, a single field with at least 12 Tcf reserves must be discovered to be commercially viable. Further, the minimum obligatory spend on the 9 blocks is approximately $765M in 2012 dollars. To breakeven with this expenditure, (that is, post-tax NPV = $765M) the largest field modelled (300 mmbbl) requires an oil price of $100/bbl. First tax revenues are forecasted as 2026 for oil and 2029 for gas. The first PSCs were executed in 2012, so first production is modelled 14 to 17 years later. Government take ranges 55 โ 60%. While the PSC mechanism of taking taxes out of the governmentโs share reflects long term stability from the investorโs point of view, changing individual tax rates may be irrelevant as the full taxes owed are never paid over the field life. These models are dependent on a myriad of assumptions. Variations in reservoir characteristics, new technology, market availability and global prices can have dramatic effects on the results. The deepwater is widely considered to be the last frontier for T&Tโs hydrocarbon industry. Therefore, it is critical that we understand how the contracts and taxation regime affect the commerciality of any potential fields, and make any necessary changes.
- North America > United States (1.00)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean (0.93)
- North America > Canada > Alberta > Lane Field > Barr Lane 5-32-65-7 Well (0.98)
- North America > United States > Texas > Permian Basin > Central Basin > Nelson Field > Ellenburger Formation (0.93)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Management > Asset and Portfolio Management (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
- (3 more...)
Abstract Deep-water has long been proclaimed as the hydrocarbon frontier with huge potential of resources. The offshore basins of West Africa, Gulf of Mexico and Brazil are particularly known for deep-water campaigns. Trinidad and Tobago is no stranger to deep-water activity having drilled eight deep water wells in the last decade. After a period of dormancy, it may soon rejoin its global counterparts as it prepares to dive into the deep yet again. In 2011 and 2012, two deep water bid rounds were held and ten companies/consortia dared to venture into the deep but only three won the opportunity. Eleven thousand, six hundred and fifty seven square kilometres (11, 657 km) was awarded out of a total acreage of twelve thousand, eight hundred and six square kilometres (12, 806 km) for the past two bid rounds. With such potential activity, Trinidad and Tobago's commercial success in the deep may seem to be imminent but this is far from certain as exploration and development costs are substantially higher than those in our shallower areas. While commercial success is dependent on government share, hydrocarbon volumes and project costs, this paper focuses only on the latter. This paper compares and analyses Trinidad and Tobago's proposed Deep-water development project costs with other global deep-water field development costs, by investigating scenarios in terms of estimated development capital and operational expenditure and associated volumes. Capex and Opex of USD 12-14 Bn was required for developments between 500-750 mmbbl and the average global sample estimated for this volume range was USD 13 Bn. The paper concludes that Trinidad and Tobago's proposed project costs are indeed in line with other global developments. Undoubtedly, deep water exploration and development demands huge investments. Trinidad and Tobago's deep-water venture will soon commence and understanding these proposed costs would shed some light on its position in the deep and help prepare for what lies ahead.
- North America > Trinidad and Tobago (1.00)
- North America > United States > Texas (0.15)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Albacora Field > Albacora Leste Field (0.99)
- South America > Brazil > Campos Basin (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.98)
- Management > Strategic Planning and Management > Project management (1.00)
- Management > Asset and Portfolio Management (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (0.73)