Karen Boman assesses the market for West African oil and gas projects, and profiles Total’s Moho Nord development offshore Congo.
The tension leg platform and Likouf FPU at the Moho Nord field. Photo from Total.
Around 15 offshore West Africa projects are forecast to come online between now and 2020, with another 15 estimated for 2020-2025. There are a few tiebacks/additional phases planned in major production areas, such Usan in Nigeria, Zinia and Ochigufu in Angola, and Nene Marine in Congo. However, most will involve new infrastructure, as the fields are spread out across a much larger area than the North Sea or Gulf of Mexico.
“Given that less fixed infrastructure, such as pipelines and platforms, is available off West Africa, most of the production is developed using floating vessels and exported via tankers,” Jonathan Markham, GlobalData upstream analyst, told OE.
Billions of barrels of oil remain offshore West Africa, and recent discoveries in Senegal have opened new plays in frontier areas of North West Africa, Markham says. Operators also are increasing their focus on natural gas projects, which have typically been overlooked due to lack of local markets, as new technology such as floating LNG is being implemented.
“Much of the remaining hydrocarbons offshore West Africa are in deepwater and ultra-deepwater fields, and this is similar to challenges faced in many parts of the world,” Markham explains. “Operators now focus more effort on optimizing well locations and drilling trajectories to ensure maximum productivity per well to reduce drilling costs.”
More equipment is being installed on the seafloor, such as subsea multiphase pumps, to reduce the pressure differentials between the surface and the wellhead and maintain flowrates. Operators also are using electrical heating technologies, such as trace wires and composite materials, to maintain the temperature in the flowlines, or chemical additives to prevent the hydrocarbons congealing in the extreme conditions of ultra-deepwater, Markham says.
To cope with the downturn, operators are trimming capex budgets by opting for simpler solutions with greater equipment standardization, instead of bespoke designs. Project breakevens are currently around US$50-60/bbl for deepwater fields in West Africa.
“Overall though, companies are simply delaying sanctioning new projects and reducing the amount of investment in the area,” Markham says. A steady price above $60/bbl is necessary before widespread investment starts picking up again.
Fortunately for West Africa, a significant number of massive projects such as Moho Nord had already been sanctioned prior to the oil price downturn, Mark Adeosun, analyst with Douglas-Westwood, told OE. Since the downturn, however, regional activity has been quiet, with only one floating production, storage and offloading vessel ordered. That order was placed in 2005. In recent months, operators have been looking at extending existing fields with brownfield drilling to maintain a certain level of production, Adeosun says.
Political tensions present another challenge for operators working offshore West Africa. Such tension between countries can often be an impediment to developments, as maritime borders are often disputed, Markham adds.
Adeosun says that he believes that political instability and local content issues are the real challenges for offshore West Africa projects.
“Local content rules are making it more difficult for some of these projects to be completed in a timely and effective manner,” Adeosun says. One of the issues delaying the Bonga SW project has been the Nigerian government trying to negotiate local content requirements for the construction of components for the Bonga SW’s floating production storage and offloading vessel.
Adeosun has seen an improvement in this area over the past two years. Companies such as TechnipFMC are setting up factories in West Africa, allowing operators to meet local content requirements for manufacturing.
Some companies also have been collaborating with local firms to train local workers. Developing the local workforce will take time. Workers will gain significant experience as they work on projects, creating a situation that is more of a win-win for international oil companies and local companies, Adeosun says.
Over the next two years, Douglas-Westwood anticipates a significant oil production increase due to massive projects coming online. After that, a decline is expected due to lack of project sanctioning before another uptick when more offshore projects come onstream.
Moho Nord raises stakes
Moho Nord, which started production in March, confirms Total as the largest oil and gas operator in the Congo, and establishes Congo as a deepwater producer, Andre Goffart, senior vice president development and support to operations for Total, told attendees at this year’s Offshore Technology Conference in Houston.
Moho Nord, which came on stream four years after Total made a final investment decision on the project, is the French major’s latest project on the 450-1200m water depth Moho Bilondo license offshore Congo. The first Moho Bilondo project came onstream in 2008, with 12 wells to two manifolds producing to via the Alima floating production unit (FPU). In 2015, Total then brought the Moho Bilondo Phase 1bis development online, in the southern portion of the license, which involved an upgrade to the Alima and the subsea system, including new subsea multiphase pumps. Moho Nord, the latest project, is in the northern portion of the license, 75km offshore Pointe-Noire, Congo.
Moho Nord was developed using 34 wells, 17 (including six water injection) tied back to a new 14,600-tonne minimal facility tension leg platform (TLP) – a first for Total in Africa – and 17 were tied back to the new 62,000-tonne Likouf FPU. Moho Nord has a 100,000 b/d capacity (40,000 b/d from the TLP and 60,000 b/d from the FPU). Combined with Phase 1bis (which had 11 additional wells come online), the Moho Bilondo license has the capacity to produce 140,000 b/d.
Engineers on the Moho Nord faced a challenge due to the different oil types within the different reservoirs the project aims to tap. Moho Nord comprises two sub-projects over three reservoirs, Goffart says. The northern portion contains both shallower Miocene and deeper Albian reservoirs; the southern portion contains a Miocene reservoir. In the north, unconsolidated Miocene sand is buried 1000m below the seabed, in 1200m water depth. The Albian carbonates reservoir is buried 3000m below the surface, but lies in 800m water depth.
Because the Miocene and Albian produced waters are incompatible, Total would have to produce the resources separately. To address this challenge, Total opted to use both a FPU and a TLP, Goffart says. For the northern Miocene reservoir, Total deployed a conventional subsea network, with 17 subsea wells tied in to the Likouf FPU and the existing Alima FPU. Oil started producing from this Miocene reservoir in March this year.
Due to the shallower water depths of the Albian reservoir, the company decided to use a TLP with surface wellheads connected to 17 wells, Goffart says. This reservoir was scheduled to come onstream in May. The TLP will be used to drill deeper, longer wells, and allows for frequent well interventions using coil tubing. Production from the TLP is routed to the Likouf FPU for processing, then sent to the Djeno terminal onshore. The two oils are processed separately via the FPU, which was built by Hyundai Heavy Industries in South Korea, as was the TLP.
The downturn posed another challenge for Total in developing Moho Nord. “We signed the contracts before oil prices fell,” Goffart told the OTC audience. To cope with lower oil prices, Total pre-installed the anchor tendons on the TLP and fast-tracked subsea production system deliveries.
Speaking at the Underwater Technology Conference in Bergen, Joel Cazaux, SPS manager for Total, said in total some 10,000-tonne of subsea equipment was delivered for the project. Cazeux outlined some lessons learned on the project, including the need to streamline documentation packages, but also issues with the project’s subsea control modules, having large (65-tonne) Xmas trees, and delivery schedules.
New technology is also playing a role. A new multipurpose workover system, with an interface for dual intervention mode systems, had by mid-late June already been used on 15 wells successfully, and is being developed to be able to work in tubing hangar mode, by Q4 this year, Cazeuz said.
Technip was contracted for project management, engineering, supply, fabrication and installation of pipelines, umbilicals and other subsea structures for the project, in addition to installing the manifolds, control system components and multiphase jumpers. Aker Solutions was chosen to supply 28 vertical subsea trees including wellhead systems, two installation and workover control systems, seven manifold structures, subsea control and tie-in systems for the project.
Ocean Installer was selected to install and pre-commission an umbilical, multiphase pump, flying leads and spools. Fugro was selected to provide remote operated vehicle services and remote subsea tooling for the field. Dockwise, owned by Boskalis, was tasked with transporting the FPU from South Korea to the Congo.
Total operates Moho Nord with 53.5% interest. Its partners include Chevron (31.5%) and Société Nationale des Pétroles du Congo (15%).