2 Field Development strategy
2.1 General
Different strategies have been developed by the Oil & Gas Industry in order to minimise as far as possible the cost of field development. Indeed, the stunning fall in oil prices, from a peak of $115 per barrel in June 2014 to under $35 at the end of February 2016, has been one of the most important crisis in the oil & gas industry. This drastically changed the operators’ approach and strategy in terms of projects development (large-scale development put in stand-by; increased number of projects related to marginal fields and long subsea tie-backs), and led to consider the selection of a field architecture which would minimize both CAPEX and OPEX as a key driver for the development of a project.
This section aims at describing the most recent approaches in terms of alternative project development strategies. Most of the track records are related to projects which had been developed before the sharp price drops. However, these approaches were developed to accommodate a rising cost of deepwater developments due to limited resources, e.g. steel material, shipyard, qualified personnel. At that time, they were therefore already developed to improve the subsea development cost-effectiveness, which remains more important than ever in current context.
These factors led to a change of view on the development scenarios: new technologies were applied (e.g. the development of subsea processing, Ref. and other floaters [9] and risers [1] technologies) while alternative field development strategies were adopted on some projects:
Early Production System (EPS) and the “Design One and Build Multiple” approach.
2.2 Early Production System
An Early Production System (EPS) consists in partly developing a field in a fast track phase, with the purposes of (1) producing very rapidly (cash flow issue) and (2) gathering information on the field conditions (e.g. reservoirs characteristics, effluent properties) in order to optimise a cost-effective Full Development phase. The EPS strategy is based on low cost early production phase, which allows reducing the field development risk in cases of reservoirs uncertainties.
The duration of an EPS is typically within 5-8 years, comparing with the 20 years (and up to 30years) design life of a permanent or ‘full field’ development scenario.
The EPS philosophy has been used on different projects around the world, e.g. by Petrobras offshore Brazil for the Jubarte field development or Mero in the Brazilian pre-salt, or Exxon Mobil in West of Africa for the Xikomba field, offshore Angola.
2.2.1 Mero Field Development Scheme
The Mero field is an ultra-deepwater oilfield, situated approximatively 200 km offshore Rio de Janeiro, between 1950 and 2400 m water depth. It is located in the pre-salt area of the Santos basin.
The field features 28° API oil, with a reservoir pressure of 650 bar, and a GOR of 400 vol/vol. Due to the uncertainties on the well productivity and on the development scenario, Petrobras decided to develop the field in a stepwise manner. The field is hence developed in three distinct steps:
The Phase I EPS features an FPSO (Pioneiro de Libra, 50,000 bopd capacity) and 1 production well + 1 gas injection well. This phase allows in particular:
To calibrate the risk of gas breakthrough
To validate the drainage mechanism as well as the appropriate well spacing for the full field development.
The main objective of the Mero EPS is hence to gather valuable information for the definitive (Phase II) development.
2.2.2 Xikomba
The ExxonMobil Xikomba EPS is based on a FPSO development in combination with four production and four injection subsea wells located at 1480m water depth. The design life is 7 years and the first oil was achieved in November 2003.
A particularity of the Xikomba project is to be based on both the EPS and “Design One and Build Multiple” principles. The FPSO is the third (and last) of the Kizomba series (see Section Section 2.3, “"Design One and Build Multiple"”).
The following principles were applied and seen as key factors to the success of the Xikomba EPS:
The FPSO is to be owned and operated by a Contractor. The floater is leased for the short EPS duration and can be then re-employed for other development. The main goal is to amortise the investment cost beyond the sole EPS phase.
The subsea equipment is to be owned and operated by the Company and is to remain and be re-used for the full development phase.
2.3 "Design One and Build Multiple"
The development strategy consists in applying a system design (e.g. production floater) to different developments with only minor modifications. This allows to:
Develop challenging deepwater fields with a single (multi-)project team, i.e. to avoid project delay due to lack of staff.
Minimise the risk by applying "standard" solutions (as much as possible) to different projects.
Make cost and time savings on these multi-project developments.
However, this approach would be impacted by some drawbacks related to a slowdown of innovation, which would limit new technology developments and provide the possibility for future "obsolescence" of the systems.
The "Design One and Build Multiple" strategy requires continuity between the projects to guaranty the performance of the second (or further) project and hence the success of the scenario. According to ExxonMobil, a key lesson learned of the Kizomba project is that the fewer modifications shall be made to leadership teams, management systems, contractors and suppliers.
ExxonMobil was the first to group projects together and repeat designs with the Kizomba (A, B & C) complex (Angola). Cost and time saving took precedence over technically optimised concepts. In particular, the Kizomba B FPSO completion schedule was five months ahead the Kizomba A FPSO. Cost savings of around 10% were made on the FPSO package.
Total also applied this approach for Kaombo project, for which two of Total’s Very Large Crude Carriers (VLCCs) named VLCC Olympia and VLCC Antarctica were converted to create the FPSOs. Each FPSO has an individual oil treatment capacity of 115,000 bpd, a water injection capacity of 200,000bpd, a gas compression capacity of 100 Mmscf/d, and an oil storage capacity of 1.7 million barrels.
2.4 Field Architecture Decision Tree
The following Figure 2.2, “Field Architecture Decision Tree” summarises the main steps of a field architecture definition process. Each item is then further described in the following sections of the document as indicated.
