Unlocking stranded assets with the iEPCI Satellite concept

Increased focus on marginal fields and ‘stranded’ assets, close to existing subsea infrastructure, has led to rethinking the way that smaller assets are developed. Cost and delivery time reduction, combined with an integrated Subsea Production System (SPS) and Subsea Umbilicals Riser Flowline (SURF) delivery, is one way to improve the project economics of these assets.

For the past two years, TechnipFMC has developed a concept leveraging the integrated EPCI (iEPCI) execution model for smaller tie-back developments. Integration, optimization, simplification, cost and delivery time have all been leading factors in developing this solution, based on pre-engineered designs and building blocks. 

Fig. 1. The subsea market is considerably different from what it was three years ago, with many projects delayed significantly, as operators have grappled with escalating costs for subsea development and maintenance.

FUNDAMENTAL SUBSEA MARKET CHANGES

The subsea market has undergone a considerable downturn during the past couple of years. The market has seen many projects delayed significantly, caused by the escalating cost of subsea developments and the new oil price level, Fig. 1. Larger greenfield projects are being reassessed and reevaluated through all parts of the value chain. One key driver to mitigate the reduced attractiveness of the greenfield projects is to change the focus toward lower risk, less capital-intensity, and quicker pay-back projects like discoveries tied back to existing infrastructure. 

According to analysts, as many as 180 undeveloped pockets of different sizes have been discovered on the Norwegian Continental Shelf. This is also a typical pattern in other subsea basins around the world. It represents a significant potential to oil companies, to compensate for production depletion ratios and enable continued utilization of existing infrastructure. So far, the alternatives presented to extract these oil pockets have either been deviation drilling from existing templates or traditional subsea tie-backs. 

The risk, with complicated deviation drilling, is hard to predict prior to commencing the operation, and it may involve well collapse and other wellbore challenges that could be costly. Traditional subsea tie-backs have involved smaller bespoke subsea deliveries, based on design specifications and the project execution methods of larger projects. Combined with the anticipated lower recovery rate and longer payback times of such investments, these traditional subsea tie-backs have not been a viable alternative. 

Fig. 2. Changes in break-even prices, 2014–2017, per selected operators.

As oil prices have fallen, and projects have been moved to the right, the oil service and equipment suppliers have looked at other ways of reducing the cost of these marginal developments. Integration between larger companies is emerging, both in the horizontal (subsea production system + subsea, umbilical, risers and flowline) and vertical (subsea production system + well services) axis. This, combined with the increased surplus capacity and cost reduction within the supply chains, has led to dramatic cost reductions for deepwater developments, Fig. 2. Optimism is starting to return to the industry, and some of the major oil companies are now launching large deepwater projects.           

However, to enable profitability for smaller and marginal satellite tie-backs, the challenge is still there. This is related to limited reserves with high production risk, presumed high cost of development, and the short production lifecycle. Market forecasts show there are many of these dormant projects around the world. As such, there is a need to address this market with suitable development solutions. 

TARGETING THE SWEET SPOT TIE-BACK MARKET

One of the main strategic reasons for the TechnipFMC merger was the need to rethink the way that subsea projects are being designed, delivered and operated. For decades, the standard scope split between SPS (Subsea Production System) and SURF (Subsea, Umbilical, Risers and Flowline) has led to sub-optimal project execution and installation campaigns. This has been driven by the nature of the business model for SPS versus SURF. 

Fig. 3. Trade-offs between recoverable reserves and distance from infrastructure and type of offshore developments.

While SPS is driven more by engineering and equipment manufacturing, SURF has covered these elements while also ensuring compatibility between products and installation vessel capacities and availability. These inefficiencies have been recognized within TechnipFMC for some time, particularly for smaller tie-back developments. Through the joint-venture company Forsys Subsea (June 2015 to January 2017), work began to look at how the execution of smaller tie-back projects could be optimized and streamlined. 

The goal has been to present a quick, cost-efficient and pre-engineered solution to the market for developing smaller fields close to existing infrastructure. However, there was an ambition to challenge the way the industry works and combine the expertise of suppliers and oil companies to profitably unlock these reserves. To do this, clear boundaries have been defined for the sweet spot for this integrated subsea delivery. The sweet spot is (but not limited to):

• No more than three wells 
• Less than 10 km step-out from existing infrastructure
• Less than 30 MMboe recoverable reserves
• No high pressure, high temperature (HPHT) 

With this market segment, it is easier to start scoping and outlining the requirements of the necessary equipment and installation campaigns. On one hand (Fig. 3), our solution may compete against extended deviation drilling, while on the other hand, it could compete against a more traditional subsea field development scenario. To allow oil companies to evaluate profitable projects in the satellite segment, we started a development program, with the aim of designing a system that could unlock potential satellite tie-back projects previously considered too risky and/or with profitability that is too marginal. 

iEPCI EXECUTION MODEL

By introducing the integrated Engineering, Procurement, Construction and Installation project execution model (iEPCI) to the industry, TechnipFMC has demonstrated that there are considerable benefits, in terms of shorter delivery time, de-risked execution model, and cost reduction, compared to the traditional execution model. Particularly for smaller tie-back developments, this could be an enabling factor to make these projects profitable. 

Fig. 4. The value of early involvement.

First, there is no barrier to establishing a lean, efficient execution team across SPS and SURF, from contract award to delivery at the seabed. This means that schedule risks are both significantly reduced and mitigated by early identification of critical interfaces and long lead items through early and timely planning of the entire system. This will safeguard the entire schedule. 

Second, as the complete subsea infrastructure is delivered ready for production at the seabed, “make-good” liability during installation, and one single warranty period for both the SPS and SURF equipment, are included as part of the modified contractual terms. Finally, by taking the installation vessel limitations and possibilities into account early in the design of the subsea equipment (design for installation), the marine scope can be made much more efficient and streamlined, contributing to a lower overall schedule and cost reduction of the development, Fig. 4. It is important to select the construction vessel early, and to work in a fully integrated way with the vessel provider, to identify the most efficient vessel spread available.    

Through early engagement with the oil companies, it is possible to discuss the applicability of vendor-based solutions and plan for the most efficient installation campaigns.

THE iEPCI SATELLITE SOLUTION

To be able to deliver on the value proposition, a thorough methodology of designing the iEPCI system has been developed—“design to market price.” In the process of validating the iEPCI Satellite concept, three different case studies have been developed across different subsea regions: the Gulf of Mexico, North Sea and Asia-Pacific. Despite different customer drivers across different regions, some common drivers and prerequisites have been identified. These have been focused on achieving a basis for design for each region.

Commonly, and not surprisingly, all clients have a limit as to the cost of a system that will make a profitable tie-back. To establish the target cost for different locations, two methods have been used. In the Gulf of Mexico, we asked selected clients to name a target price and delivery time for a typical marginal tie-back project. Then, we developed a subsea system accordingly, excluding assumed drilling, completion and topside modification costs for the development.

Fig. 5. Pre-engineered “satellite in a box” building blocks.

In the other regions, a more conceptual approach was taken. By identifying a selection of projects within the tie-back sweet spot, an oil price assumption of $40/bbl, and by excluding the mentioned drilling-completion and topside modification costs, we developed a maximum subsea cost that would make the satellite tie-back economical. Based on this maximum subsea cost, the development project was given the task to design a complete, installed system.

By using pre-engineered subsea building blocks and installation plans, developed from the combined SPS and SURF experiences of TechnipFMC, the iEPCI Satellite solution will be a vendor-based solution that challenges some of the oil company specifications. While this could be difficult for some oil companies to accept, the attractive cost and delivery time offered are only possible, if industry/vendor-based solutions are adopted as the fundamental premises for the delivery. This also enables stocking of long lead items and makes it possible to achieve time to first oil within 12 to 15 months from contract award. 

The main elements of this “designed-to-cost” system can be summarized as follows, Fig. 5:

• Pre-engineered, vendor-based, configurable subsea tree, and associated equipment and tools
• Multi-plexed electro-hydraulic control system
• Umbilical and flexible flowline, with standard key components
• Pre-engineered installation plans
• Possible well opening from vessel 
• Decoupling of rig and vessel schedule
• Integrated SPS and SURF project execution
• Stocking of long lead items.

Several prerequisites have been identified that must be satisfied, if the common goal of developing marginal fields is to be achieved. Early involvement (Fig. 4); selection of vendor-based pre-engineered equipment and installation plan; early identification of key drivers for both parties; and trust and transparency between the supplier and the oil company are all key elements to achieve common success. 

A CASE STUDY

Recently, TechnipFMC was approached by an oil company with a challenging case. The client had a stranded asset close to existing infrastructure, and wanted to perform a long-term, early
production test of the reservoir. If significant production potential was proven, the field would  justify a subsequent stand-alone development. The overall challenge was time to first oil. 

Fig. 6. Integrated working model between operator and contractor.

Normally, this type of development would have taken 18 to 24 months from contract award to first oil, depending on the process selected. In this case, the client wanted the field to go live much quicker. TechnipFMC’s Front End team was introduced to the challenge. Scope of delivery included the complete subsea infrastructure: flowline, umbilical and distribution, subsea tree, and tie-in jumpers. Battery limits were given by the customer, and based on this, a small integrated team (SPS and SURF) was established. It consisted of personnel from front-end, project execution and services teams. 

The cross-functional team worked in close cooperation with the client for some weeks, with a constant exchange of information, Fig. 6. Identification of all critical items and issues was performed early, and mitigation plans were established. In-house inventories, both in the client’s and TechnipFMC’s facilities, were made available, and it was decided to use a vendor-based standard. A solution was presented to the client, and an agreement was reached. The project was awarded and kicked off with the same team on the vendor side that had participated in the FEED (Front End Engineering Design) study. The most suitable vessel was selected early, and the project is now executing under a letter of intent to deliver the equipment at seabed within 12 months. 

The key to achieving the fast FEED and shortened delivery time was that both the vendor and client had some of the needed equipment in inventory. More importantly, a trusting and open relationship existed between the client and vendor, which contributed to the success. In this case, a “one-team spirit” was established early, with all members of the integrated contractor-client team working toward the same goal: a cost-efficient solution on the seabed and reduced time to first oil. The design was based on existing inventory, plus an optimized system solution for efficient installation. Early involvement and planning led to the identification of critical schedule risks, assignment of responsibilities and clearly defined project milestones. 

SUMMARY

The integrated iEPCI Satellite solution offers a competitive solution for marginal fields and stranded assets by applying vendor-based standard building blocks and technologies designed for installation, in combination with a lean execution model. By using the integrated model across SPS and SURF, new and previously limited possibilities of streamlining and efficient project execution are emerging. The additional benefits of reduced contractual risk, leaner project teams and integrated design across SPS and SURF, including optimization for installation, are extracted. Optimized logistics and mobilization, including the use of legacy rental tooling, provide the ability to perform efficient offshore campaigns. 

By involving all stakeholders early, there are also possibilities to reduce the FEED process (Fig. 6) and move directly into project execution, in parallel with the discussion of contractual terms and conditions. The concept, however, is linked to some clear unconditional prerequisites. A vendor-based solution needs to be accepted to meet promised delivery times and leverage the stocked long lead items. Early involvement and transparency between subsea, reservoir management discipline, and drilling is necessary to fully realize efficiency. Vessel selection and installation method need to be performed early, to leverage the benefits from pre-engineered installation plans. “Design-to-market” price methodology is encouraged, to evaluate the full value chain of the subsea tie-back delivery. 

If the industry is open to, and willing to accept this framework, considerable cost and efficiency savings can be achieved. The application of this type of thinking could potentially unlock assets that are currently considered unprofitable or stranded. This article has outlined the approach employed for selection of fit-for-purpose, vendor-based standards and building blocks, and the “design for installation” philosophy used to save time and costs during subsea operations. The cost-efficient iEPCI project execution model highlights the benefits of early identification of critical interfaces and stocking of long lead items, leading to more efficient project execution and schedule assurance.

In summary, it will lead to:

• Simplified and optimized subsea architecture across SPS and SURF
• Equipment designed for installation
• Reduced cost and delivery time
• More efficient marine operations
• Less project risk and modified contractual terms.