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.
Experimental and numerical heat-transfer analysis was conducted on a T-shaped acrylic-glass pipe, representing a production header in a subsea production system with a vertical deadleg. The header was insulated, while the deadleg was not insulated and carried a cold spot on the top. The experimental conditions were set to mimic those of steady-state production, followed by a 3-hr shutdown (cooldown). The internal fluid temperature and the wall temperature were measured by use of resistance temperature detectors and thermocouples, respectively, while particle image velocimetry was used to measure the velocities in the deadleg. It was shown that the mean velocity field during both steady state and cooldown was periodic, with a clockwise and counterclockwise rotation along the deadleg wall.
Experimental and numerical heat-transfer analysis was conducted on a T-shaped acrylic-glass pipe, representing a production header in a subsea production system with a vertical deadleg. The header was insulated, while the deadleg was not insulated and carried a cold spot on the top. It was shown that the mean velocity field during both steady state and cooldown was periodic, with a clockwise and counterclockwise rotation along the deadleg wall. By use of a k–ω shear-stress transport Reynolds-averaged Navier-Stokes (RANS) model in ANSYS CFX, the thermal field was correctly predicted for 3 hr of cooldown by modeling the cold spot as an isothermal wall. The RANS model was unable to recreate the periodic velocity field observed in the experiment.
Experimental and numerical heat-transfer analysis was conducted on a T-shaped acrylic-glass pipe, representing a production header in a subsea production system with a vertical deadleg. The header was insulated, while the deadleg was not insulated and carried a cold spot on the top. The experimental conditions were set to mimic those of steady-state production, followed by a 3-hour shutdown (cooldown). The internal fluid temperature and the wall temperature were measured by use of resistance temperature detectors (RTDs) and thermocouples, respectively, while particle image velocimetry (PIV) was used to measure the velocities in the deadleg. It was shown that the mean velocity field during both steady state and cooldown was periodic, with a clockwise and counterclockwise rotation along the deadleg wall. By use of a k-ω shear-stress transport (SST) Reynolds-averaged Navier-Stokes (RANS) model in ANSYS CFX (2013a, b), the thermal field was correctly predicted for 3 hours of cooldown by modeling the cold spot as an isothermal wall. The RANS model was unable to recreate the periodic velocity field observed in the experiment.
In recent years, it has become even more challenging to qualify acid systems that satisfy stringent corrosion acceptance criteria. This paper describes a unique approach of combining the effect of cooldown and effective treatment design to perform scale removal treatments in high-temperature (HT) wells in the Norwegian sector of the North Sea. The method helps minimize the use of corrosion control additives and its associated cost without compromising the integrity of the well components.
Controlling corrosion is a key consideration in designing acid recipes for HT wells. Achieving sufficient cooldown can further help ensure that inhibition lasts for the entire treatment duration. In this work, temperature modelling software was used to determine the volume required to cool down the well from 135°C to a specific temperature. Static weight loss corrosion testing was used to design the inhibition chemistry on 13Cr-L80 alloy. A corrosion loss of = 0.02 lbm/ft2 for the time tested with no pitting observed at 40x magnification was considered acceptable.
The corrosion tests were performed in both organic and inorganic acid mixtures with varying acid concentrations over a temperature range of 40 to 135°C for a period of 3 to 9 hours. This paper discusses the acid recipe composition, results of corrosion testing, and microscopic analysis to determine pitting. The simulation results of the temperature modelling show that wells can be easily cooled down to as low as 40°C by pumping a sufficient volume of preflush at a certain rate, and examples of such treatment designs are presented in this paper. The qualified acid system was used for carbonate scale removal in the Norwegian sector of the North Sea. The treatment post-job analysis showcases an improvement as a result of the acid treatment.
The approach presented serves as a cost-effective guide toward designing scale removal or acid stimulation treatments for HT wells. The details shared in this paper are aligned with the drive of the oil and gas industry toward using cost-effective solutions and environmentally acceptable chemicals.
Gharaibah, Emad (GE Oil & Gas – Subsea Systems / Flow Assurance) | Antel, Bill (GE Oil & Gas – Subsea Systems / Flow Assurance) | Sreenivasulu, K (GE Oil & Gas – Subsea Systems / Flow Assurance) | Barri, Mustafa (GE Oil & Gas – Subsea Systems / Flow Assurance)
The thermal management of a subsea hydrocarbon production system is a major task over the entire life cycle of the subsea production system (SPS) development. The thermal studies include heat transfer modeling and temperature-distribution calculations of the production fluid and hardware of the entire SPS stretched between the reservoir and the process facility. The thermal model involves the subsea environment as well as the SPS operating conditions (e.g. reservoirs, seawater, ambient and arrival temperatures and pressures). The major objective of the thermal management process is to aid the design of the SPS as well as to verify the production philosophy. The design includes component temperature qualifications and thermal insulation design, and the production philosophy includes maximum and minimum temperature during steady production and transient flow scenarios.
The thermal study applies analysis and simulation tools that are based on fundamental heat transfer theory. However, limitations of computation resources or project time lines lead to simplifications and assumptions in the thermal modeling approaches. One major assumption comprises the modification of the thermal conductivity of the modeled fluids to account for the transient free convection process in the subsea components (for example for the hydrocarbon fluid flow in the piping system or for the trapped fluids). This assumption reduces the calculation effort associated with the explicit modeling of the transient buoyancy and natural convection flow and heat transfer.
This paper focuses on the validation of this assumption. A combination of experimental and numerical results are presented and are utilized to recommend a robust thermal modelling procedure for subsea components that allows a favorable balance between conservatism and accuracy. The experimental data consists of both steady state and transient results from models of subsea components. Three-dimensional numerical conjugate Computational Fluid Dynamics/Heat Transfer (CFD/CHT) simulations were performed with assumed effective conductivity and with explicitly resolved free convection. Results are compared to the experimental data. The comparison between the experimental and model exit temperatures during steady state flow showed a good match with a 7% offset as a maximum value for the deviation between measured and calculated temperatures. In the transient results, the numerical model using an effective conductivity consistently gave a closer match than did the model explicitly modelling buoyancy. Given the closer match and the advantage of numerical efficiency, it is concluded that it is best to treat a production fluid as a solid with an effective conductivity when modelling transient events. Further test data are utilized to validate thermal modelling using the effective conductivity shows acceptable results accuracy of the cooldown behavior of subsea components. With increased confidence in the numerical model results, there is less of a need to apply over conservative boundary conditions. This in turn leads to a more robust product and decreased cost due to avoidance of over engineered designs.
In Subsea Production System design, the effect of equipment design on flow and vice versa may not be sufficiently considered by the design engineers. Historically, rules-of-thumb and piping design guidelines have been adopted leading to overly conservative design or conversely poor performance. This paper discusses some of common design practices with regard to equipment sizing, sensor placement and thermal design and attempts to promote a better understanding of the impact of flow on equipment design.
Insulation slows down the cooldown of the subsea production system and thus keeps it safe from hydrates for a chosen period of time after shut-in. Thermal FEA or CFD is used to simulate the cooldown of the equipment to design and verify the equipment insulation design. Currently is the insulation design determined manually, which results in a subjective and not the most efficient insulation design. This paper presents FMC's experience with an automatic optimization loop giving optimal insulation designs with respect to its volume/weight/price and safety/performance. Such automated design process clearly brings direct cost/weight savings, but also opens the door to standardization and smarter engineering.
Flexible riser and pipeline systems have been proposed as a promising solution for offshore oil and gas production systems in various harsh and challenging marine environments. They have many advantages compared with traditional rigid riser and pipeline systems, including: relatively low axial bending stiffness; ability to spool on a reel for easy transport and faster installation; and suitability for various floating systems. Flexible riser and pipeline systems typically have buoyancy modules to produce a lazy wave or similar configuration in the riser to decouple the floating vessel motions from the touchdown point. However, the buoyancy modules may move or even drag the riser in the horizontal direction, which may cause the riser shape to change or the riser bottom to move on the seabed. The riser shape/configuration may change, even slightly, with the movement of buoyancy modules or flexible riser, resulting in potentially significant changes in flow assurance design issues related to slugging and system blowdown. Case studies were carried out using transient multiphase simulation software, as reported in this paper, to investigate the slugging issues impacted by slight variations in the riser configuration in flexible pipeline/riser systems, including slight uphill and downhill riser base configurations. These small changes in the riser shape/configuration can also cause significant differences in the resulting residual pressures in the subsea pipeline and riser after blowing down the system. The results from this paper suggest that the riser shape/configuration in flexible pipe systems has a significant impact on flow assurance concerns, especially the impact of slugging and blowdown residual pressures related to hydrate prevention and mitigation. Consequently, the sensitivity of riser shape/ configuration in flexible riser and pipeline systems should be considered in early design phases to understand the impact on key flow assurance strategies.