The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.
A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.
The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.
A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.
In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements.
In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls Allow a design robust enough to tackle geosciences uncertainties Optimize subsea design margins
Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system
Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls
Allow a design robust enough to tackle geosciences uncertainties
Optimize subsea design margins
This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields.
This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance Temperature No hydrates risk during preservation No severe slugging effect Production below the flowline design flowrate Velocity below the erosional velocity
Arrival temperature above the Wax Appearance Temperature
No hydrates risk during preservation
No severe slugging effect
Production below the flowline design flowrate
Velocity below the erosional velocity
In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells.
By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate.
Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000m water depth, including subsea production wells more than 25km away from the production facility.
During the project phase, measures have been taken in order to standardize the subsea design overall including the thermal requirements. By necessity the insulation design of the subsea component is driven by the most stringent part of the development which is then applied throughout the complete system on Kaombo. This inevitably infers that certain parts of the system operate with a built-in margin regarding thermal performance. With an overall objective to optimize the OPEX the use of this margin on some assets generates added-value in the operational phase by reducing production shortfalls through reducing the number of preservations undertaken during life of field.
In order to improve the overall preservation sequence, crude abilities to delay hydrates formation and/or to transport hydrates have been studied on the coldest fields. It was found that studied crudes present interesting properties to delay hydrates formation. These tests have been performed with crude samples in lab conditions in order to assess the temperature and pressure when hydrates start to form. The results indicate that it is possible to extend the waiting period (i.e. time before launching preservation) well inside the hydrate thermodynamic zone and operating "safety" zones have been defined depending of the actual temperature and pressure.
An optimized preservation sequence postponing the decision point to restart or preserve was finally implemented thanks to:
An accurate knowledge of the full system thermal performance especially including the weak links The study of crude properties for the most penalizing fields vs. hydrates plug risk
An accurate knowledge of the full system thermal performance especially including the weak links
The study of crude properties for the most penalizing fields vs. hydrates plug risk
The methodology implemented is today already field proven and application of the extended waiting period was performed allowing reduction of shortfalls and smooth restart. A significant impact is expected for the full life of the field.
At nearly 3,000 tonnes, the company said its lift of an FPSO module was one of the heaviest land-based crane lifts ever performed. ALE was contracted to lift six modules for Total’s FPSO module integration project in Nigeria. The $635-million deal sees Oman-based Petrogas and Norwegian private equity company HitecVision acquire a package of non-core North Sea assets, including 100% ownership stake in four fields. The gas agreement clears the way for the FEED phase; FID expected in 2020. The 15-year deal calls for 1 million tons of LNG to be shipped each year to the Iberian Peninsula.
Phase 1 production from the deepwater US Gulf of Mexico field is expected to reach 30,000 BOPD. The field contains an estimated 5 billion bbl of oil in place. After suffering major setbacks, Chevron’s massive Big Foot project finally achieved first oil last November in the US Gulf of Mexico. With the setbacks in the rear-view mirror, project personnel spoke about the challenges. BP and partners have sanctioned the Azeri Central East project, the next stage of development of the giant Azeri-Chirag-Deepwater Gunashli oilfield complex in the Azerbaijan sector of the Caspian Sea.
The facility will serve as a hub to support customers and projects in the Angola and Southern Africa region. The startup of a second FPSO will add 115,000 BOPD to the deepwater project offshore Angola, bringing overall production capacity to 230,000 BOPD. Sanctioned in 2014, the project is the largest deepwater offshore development in Angola. It will produce an estimated 230,000 BOPD from six different fields at peak. Production from an offshore Angola field has been decreasing because of subsea pressure declines amid water-cut increases and limited gas compressor capacity.
In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel. The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates.
The Italian operator reported positive appraisal and exploration results from wells drilled some 10,000 km apart. The five discoveries combined hold an estimated 1.8 billion bbl of light oil in place. Conventional oil and gas discovered resources in 2019 are on pace to rise 30% from last year and reach their highest level since the beginning of the industry downturn. Here, a recap of the first quarter's 15 biggest oil and gas discoveries, which altogether are propelling the increase. The startup of the 1300-m water depth field is Eni’s fifth new field since 2014 in its West End development offshore Angola.
One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September. Lundin reports that the hookup and commissioning of installed facilities at the large North Sea field is progressing as planned.
Total’s Egina floating production, storage, and offloading vessel is its largest ever, weighing 220,000 tonnes and measuring 330-m-long by 60-m-wide. It's equipped to produce up to 200,000 B/D and hold up to 2.3 million bbl of oil. Total advanced its global deepwater campaign 29 December with the launch of production from the Egina Field 150 km offshore Nigeria. The Egina floating production, storage, and offloading vessel, which Total says is its largest ever, will be connected to 44 subsea wells and produce up to 200,000 B/D of oil. The field lies in 1600 m of water on Oil Mining Lease (OML) 130.