A new hydrocarbon discovery elicits a chain of questions to determine its viability. How big is the reservoir and how much is recoverable? What are the realistic recovery rates? What are the field development options, and how much capital expenditure (CAPEX) will be required to implement them? These questions become more difficult as untapped reservoir sizes decrease and economic conditions tighten, placing operators under increased pressure to find more efficient and cost-effective ways to develop so called “marginal” oil fields.
What constitutes a marginal field varies greatly, depending on geological, financial, and regulatory factors. Extended time periods of low oil prices can cause even the largest reservoirs to go from commercially viable to marginal, for example. At its core, however, a marginal field is one that is “economically unattractive to develop and produce.” Such a field can be discovered but untapped or it can be already producing but at reduced rates.
Developing these new or existing reservoirs in such a way so as to maintain their economic viability is a tricky but increasingly necessary process. Producers have a wide range of intelligent development solutions to choose from, but each comes with its own benefits and drawbacks. Selecting a field development option requires analyses of technical, environmental, and economic feasibility. It also requires a sound management plan in regards to how the development technologies are used.
In the offshore environment, for example, subsea tiebacks can add value to an existing production facility and reduce CAPEX. However, considerations such as a reservoir’s distance from an existing installation, water depth, complexity, recoverable volume, and recovery rates must be taken into account. Freestanding hybrid risers (vertical deepwater pipe structures that transfer fluids to surface units) and normally unintended installations (a partially or fully automated platform scaled down for lean, mostly unmanned operation; occasionally “not permanently attended installation,” mainly in the U.K.) are other examples of lower-cost alternatives to traditional offshore oil production. Drilling techniques such as multilateral completion — which provide access to two or more reservoirs at varying depths — or horizontal drilling provide additional tools for those seeking profitability from marginal fields.
Finally, how governments, operators, and contractors incentivize marginal field development shape the success of these types of projects. The U.K.’s tax incentives for special field types offer a governmental model that could be applied to other marginal fields around the world. Governments can also adopt rigorous standards at a regional or national level, reducing development costs. Operators must also work with contractors, who may be financially affected by the cost-saving initiatives associated with marginal field development. Operators can incentivize these types of developments to contractors by rewarding them for creative ways of streamlining and standardizing the developments. Contractor incentives may come in the form of a project bonus or guaranteed follow-up work, while operators benefit from the contractor-driven time and cost savings on marginal field projects.