An international Energy Company & independent engineering company have performed preliminary studies for an In-Line Robot (ILR) Project including: feasibility study, turbine design (with CFD calculations and flow assurance) and Energy Balance Assessments. This Robot will be a tetherless autonomous device capable of travelling with/against production flow to accomplish pigging and inspection missions inside pipelines with minimum production impacts. This is particularly adapted for single line long tiebacks, thanks to regenerative power management but the complexity of subsea architecture, flow conditions & fluids services raises some challenges. The ILR development is programmed over five phases (Feasibility study, Preliminary Systems design & Energy Balance Assessment, Flow Loop Bench Testing, Prototype Testing and Commercialisation). Phase 2 utilised Computational Fluid Dynamics (CFD) simulation models to assess power extraction levels from production flow across various scenarios whilst minimising pressure drop. The results obtained included the turbine CFD models that were coupled to power conversion and storage modules in order to ensure that system drive and power managementwere captured in a closed loop. An operational envelope was established considering the preliminary turbine design simulations as well as the associated energy balance. This paper will present the results to date along with the key design features of the ILR and how the data will be used to verify the operational envelope during the next phase, Flow Loop Bench Testing which is due to start in late 2019. This will provide data to configure and predict operational envelopes of the robot for different flow patterns and fluid types.
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.
Presently, drilling riser joints are inspected every five years. This is usually accomplished by rotating 20% onshore every year to be dis-assembled and inspected. This requires extensive boat trips from a mobile operating drilling unit (MODU) to onshore and trucking of the riser to the inspection facility. Typically, 20 riser joints from each riser system are transported on a boat and one riser per truck to an inspection facility each year, making the logistics of performing a drilling inspection complex and costly.
A laser-based measurement for inspection together with monitoring of riser systems has been implemented with a new standard process for collecting critical riser data that is ABS approved. The aim is to mitigate the costs and time associated with essential MODU drilling riser inspections, by empowering operators to reliably determine the condition of drilling riser joints, consistently predict when vital components will require service and accurately assess remaining component life.
The approach utilizes a life cycle condition based monitoring, maintenance and inspection system that can be deployed on a MODU, enabling resources to be deployed only when necessary, instead of on a calendar interval. The solution consists of: Performing a baseline inspection on the riser joints to assess their present state, Collecting the environmental and operating data when the rig is on site drilling, Feeding the environmental and operating data into a digital twin. The tuned digital twin can be used to predict future damage.
The approach removes uncertainties surrounding damage of riser joints and will allow the owner to determine whether riser should be redeployed or replaced. This is the only process that is ABS approved for condition based monitoring of drilling riser systems. The system is compatible with all present owners’ maintenance programs and ensures that maintenance requirements are supported with robust engineering.
As part of an effort to evaluate existing riser systems, an operator launched an inspection and testing program to investigate risers retrieved following well abandonment after a service life of nearly 10 years in the Gulf of Mexico. This paper describes a novel method of chemical dosage based on time-resolved fluorescence (TRF) that allows a simple, accurate, and efficient quantification of chemicals below parts-per-million ranges, even for double (scale/scale, scale/corrosion) quantification.
A project spearheaded by ExxonMobil, Shell, Chevron, and the Southwest Research Institute (SwRI) has been established to advance separation technology through improved testing methods and collaboration between users and suppliers. The simplest way to measure return on investment for an offshore water treatment system is to determine whether using the system actually reduces the risk of paying a fine for violating water pollution laws.
The BC-10 asset, located in deep water offshore Brazil, produces heavy oil in the range of 16 to 24 °API. In this article, two examples of production optimization for this field will be provided (further examples are available in the complete paper). This paper evaluates the feasibility of a number of production- and export-riser configurations for ultradeepwater applications.
As part of an effort to evaluate existing riser systems, an operator launched an inspection and testing program to investigate risers retrieved following well abandonment after a service life of nearly 10 years in the Gulf of Mexico. New long-term contracts between offshore drillers and equipment makers reduce downtime and risks associated with key components, from blowout preventers to risers. This paper evaluates the feasibility of a number of production- and export-riser configurations for ultradeepwater applications. This paper presents results from full-scale testing of a flexible riser equipped with embedded sensors for distributed-temperature sensing (DTS).
A study using a dynamic multiphase-flow software simulated a rapid-unloading event and determined the gas fraction in the riser annulus and the effect on riser fluid levels. The Troll field is one of the largest gas producers discovered off Norway, but ensuring its long-term future required finding ways to drill wells in an increasingly fragile formation to develop its rich oil reserves. The list of wells drilled using dual gradient includes one drilled in the “eastern Gulf of Mexico,” which could be more precisely described as offshore Cuba. A previous attempt to drill an exploration well in ultradeep water in the Gulf of Mexico (GOM) did not reach its objective.
A case study in the deepwater Gulf of Mexico in which pressure transient analysis, fractional flow, and production logging tools were integrated to identify correctly the cause of, and execute an effective remedy for, a well’s productivity deterioration. As part of an effort to evaluate existing riser systems, an operator launched an inspection and testing program to investigate risers retrieved following well abandonment after a service life of nearly 10 years in the Gulf of Mexico. The largest lease sale in the history of the area attracts $139 million in total bids, a $2 million increase over the previous lease sale held last August. Integrated surveillance is critical for understanding reservoir dynamics and improving field management.