From Operation to Cessation of Production: Creating a Smooth Transition
Celeste Pastorini
Production Engineer - Energy Lloyd's Register

From Operation to Cessation of Production: Creating a Smooth Transition

The global oil and gas industry is in unchartered waters, with challenges including low oil price, high operating costs and ageing assets rivalling its pioneering production days half a century ago. There is no denying the sheer scale of the issue. The challenge on the horizon is significant: decommissioning will be expensive and span several decades.

More than half of the assets in Malaysian waters are more than 20 years old. Operators in this region have faced a decommissioning backlog. Only an estimated 95 platforms having been decommissioned since 1975, attributed to a lack of clear and specific regulations from national authorities. In comparison, The Gulf of Mexico dominates global decommissioning activity, with an estimated 4,600 offshore facilities decommissioned to date. So what is the solution from operation to cessation of production and how do you best go about it?

The global oil and gas industry is in unchartered waters, with challenges including low oil price, high operating costs and ageing assets rivalling its pioneering production days half a century ago.

Decommissioning is never far from the headlines. Across the UK Continental Shelf (UKCS) for example, the industry is now plugging and abandoning more wells than it is drilling for exploration and appraisal. According to McKinsey & Company, 27 UK fields ceased production over the past five years to 2015, with a third of them approaching the regulator for approval to decommission. The number of wells plugged and abandoned in the UK more than tripled in the past three years.

Based on current crude oil prices, analytics' consultancy Wood Mackenzie sees a ramp up of decommissioning activities up to the early 2020s that is perhaps greater than ever previously forecast.

Estimates are exactly that, but there is no denying the sheer scale of the issue. The challenge on the horizon is significant: decommissioning will be expensive and span several decades. And, added to this is a significant factor where infrastructure integrated and shared between installations can increase the complexity of decommissioning.

Internationally, new rules are being introduced to accelerate decommissioning activity. More than half of the assets in Malaysian waters are more than 20 years old. Operators in this region have faced a decommissioning backlog. Only an estimated 95 platforms having been decommissioned since 1975, attributed to a lack of clear and specific regulations from national authorities. In comparison, The Gulf of Mexico dominates global decommissioning activity, with an estimated 4,600 offshore facilities decommissioned to date.

Life before decommissioning

What to do in late-field life is equally as pressing as decommissioning, and as worthy of the headlines. Following on from the key recommendations in the UKCS Maximising Recovery Review, led by Sir Ian Wood for national government, the OGA has set out its strategy to collaborate with industry to Maximise Economic Recovery (MER). Moving to late-field life is a tough decision to take for any operator, but it can mean more than entering 'lighthouse mode' to delay decommissioning liabilities. Radically leaner models of working, coupled with rigorous asset management, will help at a stage that demands a relentless focus on production optimisation, operational efficiency and cost reduction.Getting these factors right are fundamental if the industry is to unlock the remaining potential, safely and profitably. Production gains of assets at late life are potentially considerable. The Wood Review estimates there are between 12 and 24 billion barrels of oil yet to be recovered from the North Sea. The opportunity to generate significant value is echoed by McKinsey & Company, particularly over the next two decades. The firm puts the case for excellence in this transformative phase, highlighting that few companies as yet have truly positioned themselves to capture this value.

If the industry is able to exploit the most optimum ways to increase the level of hydrocarbons that are economically recoverable, it can concentrate on value generating activities. Few would argue that spending capital unnecessarily on decommissioning is better.

Reassessing what is required in late-field life

Given the challenging market conditions, the need to improve operational efficiency and performance escalates in later life, to a point where every possible advantage matters. Activities that fail to deliver commercially or ensure safety standards are met, have to be eliminated.

The challenges are complex during this phase, but the equation is simple: the leaner operations can become, the longer the length of profitable production. Reassessing requirements in late-field life shows where costs can be drastically reduced to remain profitable. What is important at the beginning of a field's life changes as it reaches maturity.

Initial efforts focus on maximising hydrocarbon recovery through long -term development plans. There are numerous technical tasks to perform. Dedicated technical specialists undertake studies in areas that include seismic interpretation, geological modelling, petrophysical evaluation, reservoir modelling, well modelling, system modelling, and production optimisation.

At the end of a field's life, particularly when approaching CoP, the management of day-to-day production and operations takes precedence. With remaining opportunities available, but perhaps not economically feasible to execute, many of the geoscience and reservoir engineering tasks become less valuable or simply not required.

Outsourcing to lighten the burden

The approach to outsource the full running of late-life assets offers a number of advantages, without detracting from the operator's responsibilities for the assets approaching CoP. Fields can be optimised until abandonment, with minimum capital expenditure. Operating costs can be reduced significantly, with personnel redeployed to greater use elsewhere. At the same time, data can be gathered that is required for CoP and, in turn , decommissioning. Such an outsourcing approach is relatively novel and a bold strategic step for an operator and their joint venture partners. Getting the handover right for a smooth transition is critical, ensuring operations are safe while maximising profitability. How is this best achieved? And what competitive edge is possible when pushing the potential of such a model?

Setting the agenda

A late-field outsourcing approach should focus on six core objectives:
  • Zero accidents and no harm to the environment
  • A cash flow positive position in the current marketplace
  • A competitive unit operating cost
  • Extended field life where possible, deferring CoP and delaying decommissioning liabilities
  • Preparing for CoP, while managing late-life assets
  • Optimising well and reservoir performance.
Running it down: a period of continuous improvement

For as long as there is life in a field, the goal must be operations excellence. An outsourcing approach should be able to move quickly and efficiently from providing the essential service an operator requires to managing the assets through continual improvement. Superior asset performance and technically excellent subsurface operations pre CoP can start to be realised once the significant risks are identified and mitigated and the operator's basic requirements, including compliance demands, are being met.

Getting the framework right

Handover of late-field life management should involve five main stages or sets of activities:
  • 1. Project framing and review Close collaboration with the client's asset and operations teams is critical, gaining a total understanding of the planned scope of work, overall objectives during the transition period and the operator’s way of working, with special emphasis on aligned HSE cultures. Governance structure, accountabilities, reporting interfaces, deliverables, timelines and IT requirements should all be covered off.
  • 2. Access to data and systems Effective transition is only possible with the operator's systems to hand. IT solutions are readily available to provide the specialist contractor with remote access to key information. This includes real -time production and injection well data, process and operations data, as well as the operator's systems such as loss management, dashboards and intranet document management.
  • 3. Knowledge transfer Prior to handover, the full range of petroleum and reservoir engineering activities needs to be discussed through visits, meetings and in-depth reviews. Close cooperation is required on a daily, weekly, monthly, quarterly, annual and ad hoc basis to cover the range of requirements and responsibilities.
  • 4. Management of meetings It is important to agree, refine and schedule the full inventory of meetings, with appropriate terms of reference. Meetings should involve both internal and external stakeholders, including joint venture partners and regulatory bodies, where applicable .
  • 5. Quality control, peer review and project management In this final step, the transition plan is completed and agreed . Details on the peer reviews and quality control of the contracted service should be finalised. As a guide to timeframes, full management can be handed over by the operator to a specialist external team within a four-month, fully collaborative transition period.
Rethinking the headcount; redeploying personnel

With fields no longer delivering at peak capacity, outsourcing enables redeployment of subsurface teams, and expensive technical and scientific equipment, to more valuable and strategic assets. Concerns about losing valuable resources - hired directly as the project approaches CoP, but also with an eye to the next opportunity - are also negated. Subsurface and production management can be successfully achieved with a pre-CoP team comprising a dedicated project manager, reservoir engineer and production and operations engineer. These specialists will be supported by other subsurface discipline experts on an ad hoc basis.

Being productive, while preparing for CoP

While the outsourcing approach represents around a 50% reduction in traditional levels of personnel, a range of activities can be performed by this small resource, including gathering data for the final well and reservoir status. Indeed, amidst a lot of industry uncertainty, one point is clear: late-life asset management should form part of the roadmap to CoP. A specialist team is both focused and in the ideal position to collate all the information required for decommissioning plans and the CoP documents required by the regulatory authorities. This also applies to preparing the CoP Application Document itself. In addition, the key tasks can be transferred, such as reserves' booking, short and long-term forecasts, revisiting opportunities for final close-out and other forms of reporting, which are unique to each project. Field optimisation may also lead to further operating savings, enabling the pre-CoP team to be reduced , while still delivering the necessary level of specialist services.

Teasing out additional value

Choosing the right specialist provider enables an operator to tap into a spectrum of skills required in the process of managing mature fields, up to and including CoP, particularly field optimisation. An understanding of the full subsurface and production management requirements, together with expertise in areas such as the management of wells and facilities, can give an operator, as well as the regulator, a valuable view. This will help assure that Maximum Economic Recovery (MER) is being delivered.

    Each field is unique. Below are some examples of the results possible:
  • Streamlining the management of reservoir and subsea pipeline network by reviewing the efficiency of water injection and ‘back-out’ in the subsea pipeline network.
  • Using all the available data - recent seismic, well-test, inter-well connectivity and seawater composition data – to minimise deferred production .
  • Exploring a range of options for improving oil rate and recovery by performing water shut-off using either thermally- or chemically-activated polymers at either or both injector or production wells. Considering both treatments for deployment via the subsea manifolds, rather than by direct well intervention, can reduce cost and risk.
  • Using a cement assurance assessment for safe, cost-effective well abandonment not just for an interval above a main reservoir, but for the entire wellbore.
  • Maintaining stable operations by addressing the effect caused by slugging and gas deficiency to wells and process facilities that were designed for higher production rates.
  • Tackling the common problem in late life of unreliable rate measurements, especially of water and oil that are crucial to optimising production. Here, traditional modelling tools become less effective. Greater outcomes can be achieved through closely monitoring the performance of wells and process facilities, running optimisation exercises, maintaining updated well and network models and educating all personnel to operate in a dynamic scenario, where process settings may have to be adjusted daily.