Many basins throughout the world, including those in Asia-Pacific, are experiencing declines in hydrocarbon production with fields maturing and approaching abandonment. Growth in production is coming either from unconventional reservoirs or from relatively immature and emerging basins.
In Asia-Pacific, the scale and cost of offshore decommissioning is likely to involve hundreds of platforms, thousands of wells and tens of billions of dollars. Other mature basins such as the North Sea face similar challenges. Throughout the region, processes have been underway (in some cases for many years) to allocate, clarify, and properly fund abandonment obligations. Some jurisdictions have carried out wide-ranging consultation processes to gather stakeholder views. Others have strengthened regulations in successive licence contracts. Such clarity is essential to allow governments and operators to estimate the net revenues from oil and gas operations and the liabilities associated with decommissioning and abandonment.
Other regulatory developments have recognised the challenges of mature field economics and offered improved fiscal or contract terms to incentivise Improved Oil Recovery, Enhanced Oil Recovery, asset rejuvenation, or field redevelopment.
Keeping Productive
Oil and gas fields can have lives much longer than initially envisioned. Fields may be relinquished or proposed for abandonment when the operator’s perspective does not allow the full potential of the field to be exploited. Organisational barriers, regulatory or commercial issues, capital or manpower allocation constraints, technology limitations, cost structures, and other factors may exist that, if resolved, can extend the productive life of a field or production area.
An excellent regional example is seen in Thailand, where the nation has been producing oil and gas at a Proved Reserves/Production (R/P) ratio of 10 years (or less) for the past 14 years, and an R/P ratio of 4 years (or less) for the past 5 years (source: BP Statistical Review of World Energy) – with only small new field developments coming on stream in that period. This means that every year Operators are finding or maturing new volumes from existing fields to extend field life.
Several classes of activity can be considered to extend field life while maintaining safe and profitable operations. These include cost management, incremental production, operational improvements and fiscal and commercial improvements.
Cost Management
A detailed understanding of operating costs, and where and why they are incurred in a production system, allows uneconomic elements of the production system to be abandoned, improving the economics of the remaining system. This can take place at the well level (high-water-cut wells) or the satellite-production-system level by consolidating production streams into a single processing facility. The overall objective is to reduce costs by ceasing uneconomic activities. This approach also may require decommissioning activities to be carried out to remove redundant infrastructure (e.g., wellhead platforms) where the continued existence of these facilities would incur costs to maintain a minimum level of structural integrity and safety. The unit costs of essential activities or services can be reduced by contract renegotiation; furthermore, alternative and lower-cost approaches to deliver the same production service may exist.
Figure 1: Oil field example with three life stages. Source: Optimized Field Development of Mature Assets”, Li & Agrawal. Reservoir Management and Surveillance Summit, 2017.
Cost-reduction opportunities also may be found in rethinking contract strategy and moving activities from in-house to contracting out (or vice versa) to take advantage of lower-cost structures for shared services. Similarly, contracting strategies can be used to move costs from capital expenditure to operating expense (or vice versa) through equipment leasing or sale and leaseback, where such steps offer fiscal or cost advantages.
An operator of mature fields often will start with a detailed review of all available field subsurface and operational data to identify ways of generating early cash flow to finance further development. A range of incremental production opportunities can be generated and ranked for implementation, including surface facilities debottlenecking, review of existing wells to identify behind-pipe opportunities and development of new infill wells that take advantage of new technologies to exploit by-passed pay, attic, field-flank, or tight zones previously considered unproducible. These incremental volumes can extend economic life, allowing a previously sub-economic ‘tail’ of the legacy field to be economically produced.
Figure 1 shows an example from a field which has been through three distinct life stages. The field was initially operated by an IOC under a Production Sharing Contract. The National Oil Company then took over, maintained production but with minimal investment. Later, an alliance with a service company resulted in a detailed study, significant investment and increased production.
Fields like this will inevitably decline if neglected and treated as ‘cash cows’. It may be necessary to invest time and money to achieve production improvements and extensions to field life. Many mature fields are just waiting for such attention.
Operational and Commercial Improvements
Field economic performance may be improved and extended by attention to operations. Additional gas sales can be achieved through constrained facilities by attention to planned and unplanned downtime. Attention to metering accuracy, and sometimes to system-reallocation algorithms, may offer marginal improvements in metered (and sold) volumes at minimal or no cost. Delaying field shutdown and abandonment by renegotiating commercial or fiscal terms may be in the best interests of off-takers (e.g., gas buyers) and host governments.
Gas prices, netted back to the producer, can be improved by addressing gas price, indexing terms, delivery specifications, embedded transport costs, capacity charges, or swing factors. Value may exist in a gas stream from its potential to mix away other below specification gas. Attention to the calibration of fiscal and calorific value meters can offer small but worthwhile improvements.
Oil prices generally are linked to a regional reference crude and, therefore, to Brent; however, the producer can improve net price by addressing the transport and quality offsets that are applied to the benchmark price. Attention to oil marketing and meeting with a range of buyers and traders can help a producer materially improve net prices.
Government take, over and above the rates of general corporate taxation, also may be negotiable where the alternative is field abandonment.
Reserves Extensions
Assessment and management of Reserves in mature fields is a key aspect of late life field planning. The economic limit is defined within the Petroleum Resources Management System (PRMS) as the time when the maximum cumulative net cash flow occurs for a project. The entity’s entitlement production share, and thus net entitlement resources, includes those produced quantities up to the earliest truncation occurrence of technical, licence, or economic limit. The economic limit is an undiscounted operating net-cash-flow calculation, the inputs of which are production and cost profiles together with relevant fiscal terms.
The PRMS allows for interim periods of negative cash flow to be accommodated. This allows for periods of development capital spending, low product prices, or major operational problems, provided that the longer-term cumulative cash flow becomes positive and that the negative cash flow is more than offset by the positive. There may be situations where production is continued beyond the economic limit e.g., delaying abandonment expenditure, keeping shared facilities running, strategic reasons; however, any such sub-economic production cannot be classified as Reserves under PRMS.
Figure 2: Example of field extension activities. © GaffneyCline
Figure 2 shows field extension from two activities. The field is declining and the No Further Activity (NFA) case shows the field reaching its economic limit in Year 5. However, the Operator commits additional Capex in Year 5 (A) to increase production, perhaps through infill drilling, resulting in an extension of the economic field life until Year 10. In Year 10, an Opex reduction programme (B) improves cash flow (but not production) and results in another extension of economic limit until Year 15. The field finally reaches its economic limit in Year 15 (C), but production continues beyond that with negative cash flow until the field is abandoned in Year 21. The production associated with this period cannot be classified as Reserves, even though there may be good reasons to continue production as noted earlier.
A recent study on a field cluster in South East Asia evaluated combining several of the elements described above. Elements evaluated included: IOC exit from block and Operatorship taken over by small independent with lower cost structure, reduction in Opex, additional development (which did not meet investment hurdles under previous Operator), operational and fiscal improvements. As a result, there was potential to extend economic field life by 10–15 years with a large increase in asset value.
Other options available include reducing carbon intensity of oil and gas production. In South East Asia, gas flaring is a major component of high carbon intensity in some fields. Projects which involve monetising gas can reduce carbon intensity and provide economic returns, especially as carbon pricing is expected to increase in coming years and decades.
Rebirth or a Second Career?
Depleted hydrocarbon reservoirs can be used as sites for carbon capture and storage. Deep saline aquifers nearby existing fields and facilities can also be used as potential carbon capture sites. Old facilities can have a wide range of potential uses. Suggestions include transition of offshore platforms into aquafarming hubs or recreational use such as offshore hotels and diving resorts; such reutilised platforms already exist in South East Asia. Nexstep, a joint venture between the Dutch state and the oil and gas industry, envisions various potential repurposing options including: transformer locations for wind farms, power to gas and other renewable or geothermal energy activities. Some examples are shown in Figure 3.
Figure 3: Offshore oil and gas facility repurposing options. © Nexstep.
Oil industry professionals, from geologists with subsurface knowledge to facilities engineers with offshore construction and operations experience, will be an important part of the transition. Who understands the storage capacity, surface risks and potential for CO2 leakage better than subsurface professionals who assess and develop oil and gas fields?
Subsurface technical assessments, such as those that assess seal capacity and hydrocarbon trapping mechanisms are useful for exploration and production, but can also be vital for carbon capture. Geological Society Memoir 52 records not only the extraordinary 50+ year journey that led to development of oil and gas fields, but is also useful for potential CO2 sequestration projects.
These opportunities also come with several challenges. Regulatory issues related to decommissioning are already a concern in many parts of the world, including South East Asia. Providing a regulatory pathway to re-use of facilities is an additional challenge.
Timing may also be a key concern. With a large wave of decommissioning expected, providing a regulatory framework, technical capability and economic incentives may come too late to be of use for many fields and facilities. Lessons can likely be learned from basins such as the North Sea and the US Gulf of Mexico which may be more mature in the life cycle.
Prolonging economic field life until an appropriate second life can be identified may be an ideal solution to multiple problems.
The Last Economic Barrel
Imagine the conditions under which the ’last economic barrel’ would be produced from a field – for maximum benefit to both the host government and to the licence holder. That barrel (or gas boe) would be produced when the marginal cost of production equals sales revenue, with no excess government take (beyond normal corporate tax), and all production services are provided by 100% local businesses. At cessation of production, a properly funded general arbitration provision is available to cover decommissioning and restoration.
Managing mature oil and gas fields is both a challenge and an opportunity. The challenge is how to manage transition to that last economic barrel, while maintaining equitable returns to business and society throughout the field life cycle.
There are a range of approaches and technologies available to extend economic operations, and a new group of operators and commercial structures emerging to implement these. The challenge to host governments and to the existing Operators is to carefully manage the fiscal, regulatory, and commercial framework of field management to allow these activities to take place, while assuring responsible field decommissioning.
Opportunities for repurposing, and a second life, should be investigated and screened. The last barrel may not be the end, but a chance of a new beginning.
