Making MODUs into FPUs

Mobile offshore drilling units could be a FPU conversion alternative. Karen Boman sets out the details.

InterMoor tows the ATP Innovator FPU from the Gomez field in the Gulf of Mexico.Photo from InterMoor’s Flickr.

In a cash-constrained environment, finding alternative concepts could help make offshore developments float. One such alternative, discussed at this year’s Offshore Technology Conference (OTC) in Houston, would see mobile offshore drilling units (MODUs) converted into floating production units (FPUs).

The conversion of tankers for floating production, storage and offloading (FPSOs) vessels has been a common practice, accounting for almost two-thirds of operating units, due to the relative economic attractiveness of a tanker hull versus a newbuild FPSO hull, according to Anders Martin Moe, project development manager for floating production, and Manuel Laranjinha, project manager floaters and drilling, Wood Group, in their OTC paper, Design Methodology for Converting a MODU into a FPU. Converting MODUs into FPUs has been less common over the past 15 years, but there are examples, including the P-40 at the Marlim Sul field off Brazil and the ATP Innovator at the Gomez field in the Gulf of Mexico.

As operators look to reduce deepwater project costs, conversion of MODUs to FPUs might provide the oil and gas industry an answer, the paper authors say. A decline in drilling activity and the subsequent halt or delay of development plans means many MODUs are available that could be candidates for conversion into early production facilities, long-term well-testing facilities, minimum processing facilities and even full processing facilities in oil fields in benign areas, Moe and Laranjinha say.

For its base case, Wood Group used its own MODU design to determine feasibility for converting a MODU to an FPU. The exercise conducted on the basis of the design focused mainly on weights and hydrostatics stability to determine the maximum topsides payload that could be accommodated without making significant changes to the hull. Wood Group then considered two other cases: conversion of a MODU to an FPU capable of full production without drilling, the other an FPU that had full production with drilling capacity.

A study of the cases shows the conversion of a MODU into a combined production and drilling facility represents the highest risk and possibly the highest cost. The conversion of a MODU into a facility with reduced topsides processing and drilling capability appearing to offer a reasonable balance between risk and cost, Moe and Laranjinha say.

Before undertaking a conversion, several technical and commercial factors must be considered, the authors say. Even if no hull modification is needed, operators will need to verify the hull’s remaining design life of the fatigue-sensitive areas such as bracing connections. A MODUs global structure may need to be strengthened when the payload becomes significantly higher than the design values. Such issues are well-known and frequently encountered in the modification, upgrade and life extension of drilling rigs.

Removing existing drilling facilities and integrating a new topsides processing facility present relatively low-risk challenges. But, operators will have to pay close attention during conversion to the riser and mooring system arrangement. For example, only having two pontoons for hanging off and routing risers to topsides will limit field layout.

Commercial feasibility issues include finding a MODU unit with sufficient payload capacity and in good enough condition to limit the needed conversion/modification workscope for the hull. Finding a field with the environmental conditions, reservoir characteristics, and production requirements suitable for a converted MODU, as well as necessary infrastructure, is also crucial. The cost of acquiring topsides and their integration must be included in decision-making.

Semisubmersible MODUs and FPUs differ not only in their intended purposes, but in their equipment and structure. For example, semisubmersible FPUs do not dry dock for inspections at regular intervals like those for MODUs, which means additional requirements for structural design regarding fatigue are needed. Unlike MODUs, semisubmersible FPUs are very rarely equipped with propulsion equipment, and are typically installed at a field onto pre-laid permanent mooring lines. The two do share similarities in their primary design driver – the weight and footprint of the topsides, though the definition of payload does differ somewhat for both.

The Wood Group authors conclude, saying that the conversion of MODUs into FPUs could potentially open new opportunities for additional lease and operate models within the semisubmersible market.

“Potential commercial gains are very much related to reduced investment and low risk. In the end, one must prove the modification is not only a feasible solution, but also commercially interesting when compared to a traditional newbuild project, proving the modification will have such a reduction on overall capex that it eventually will impact the traditional oil and gas players’ medium- to long-term strategies.”