A new type of partnership between an oilfield operator and supplier is helping extend the life of fields in the UK North Sea, according to Baker Hughes’ David McKendrick
The UK Oil & Gas Authority estimates that 30 new offshore oil and gas fields have come onstream in the United Kingdom Continental Shelf (UKCS) since 2015. Under the UK industry’s Vision 2035 strategy, the aim is for the North Sea to still be producing more than 1M barrel of oil equivalents per day (boed) in 2035. That would certainly be good news for the entire oil and gas supply chain, including OSV owners and specialised vessel operators.
Although this could be considered a slightly intangible figure, it highlights the significance of field life extension. The need to manage the UKCS resources efficiently and prolong the life of oil and gas developments for as long as possible has created a search for enhanced technology and process efficiencies within the offshore oil and gas industry.
Commercial models, creativity and collaboration are not terms traditionally associated with upstream oil and gas, until now that is. Customary oilfield operator-supplier models are being turned on their head in order to meet the demands of this new environment, with significant success.
A new perspective
This change has been encouraged by a number of critical factors which have emerged over the past decade. Operators have found that overall capital expenditure can be decreased by utilising the processing capacity on existing offshore oil platforms, rather than building new structures for every field. To that end, much smaller reservoirs can be developed more economically than ever before.
For example, extraction via subsea tiebacks require significantly lower initial investments, compared with developments using fixed installations or floating production, storage and offloading vessels (FPSOs), and operators can achieve first production in a much quicker time, significantly improving net present value (NPV), cash flows and overall project economics.
Significant, too, is the number of independent oil operators working in this region today. The market for single wells has expanded as they take over mature assets from oil majors and international oil companies (IOCs), increasing the opportunities for tiebacks, infill wells, intervention and well stimulation.
Technological innovation is also allowing the exploitation of these new and complex discoveries, the majority of which are smaller and more remote than ever. As a result, advances in tieback technology are more in demand than ever before within this modern-day context. Marginal pools and infill projects in UKCS require more collaboration across the value chain and often a completely new approach to project economics is required.
As such, a huge market with unforeseen potential is emerging, one that is centred on applying new project management models and innovative production systems, designed to achieve significant cost savings and early production delivery.
Baker Hughes has undergone significant review and reconfiguration of internal processes and procedures to ensure it is a step ahead of this new market environment. The result has been demonstrable success over several recent projects, innovation in its tieback technology, and a new approach to commercial partnerships.
Increasing production at Solan field
Located about 135 km south west of the Shetland mainland, the Solan field in the UKCS was discovered in 1991 and has an estimated 20 years’ field life. The field development plan was approved in 2012 and it has been in operation since early 2016 by independent UK oil company Premier Oil. Premier Oil has oil and gas interests in the North Sea, Southeast Asia, the Falkland Islands, Mexico and Brazil.
Oil produced at the Solan field is temporarily stored in a specially designed steel subsea oil storage tank that is located near the platform. The subsea tank has a capacity of 300,000 barrels of oil. Oil is then transferred from the subsea oil storage tank to shuttle tankers.
In its annual report for 2018, Premier Oil reported production from Solan field averaged 4.6 kboepd, ahead of forecast, driven by high operating efficiency of over 90%. Premier said it expected to drill P3 in 2020 targeted at increasing production from the Central Northern part of the field. Separately, Premier continues to review the potential for third-party volumes over the Solan infrastructure.
Initially, there were two producing wells at the Solan field. Well three, P3, is required to be brought on efficiently.
In this case the oilfield operator approached US-based Baker Hughes at an early stage to assess how this could be made possible.
Leveraging teams across the Oilfield Services and Oilfield Equipment departments, and by applying North Sea-developed best practices, including Baker Hughes’ ongoing work on the Johan Sverdrup project in Norway, an approach to the well was developed in collaboration with Premier Oil.
Collaboration has been the oil industry’s watchword since 2014’s Wood Report, but despite progress, action has not quite caught up with the rhetoric. At the outset of this phase of work, joint workshops were held between Baker Hughes and Premier Oil, the aim of which was to forge a joint approach towards unpicking and rebuilding the necessary project specifications, rather than simply doing what had been done before.
The result was a jointly defined scope of work that eradicated features and processes which may have legitimately been included if the project had followed the normal methodology, but instead were found to be surplus to this context on closer interrogation.
Baker Hughes invited Premier Oil to visit development facilities that carry out audits and inspections of the equipment manufacturing, assembly and preparations. Timelines were fine tuned between the two companies in terms of equipment order placing, critical path optimisation and execution plans.
Dedicated senior account managers were assigned as the communications lynchpins, not only between the two companies but also to provide an integrated overview of the services Baker Hughes supplied from project outset to contract execution. The simplification of communications structures yielded benefits in terms of efficiencies and streamlining operations.
The collaboration also went a step further than practical delivery. It marked one of the first instances of innovative fiscal project modelling beyond that of a traditional buyer-seller process. As part of the commercial structure, Premier Oil and Baker Hughes reached an agreement to align payment with milestone dates, reducing the operator’s cash outlay prior to the completion of the well.
By rigorously reviewing the customary approach to project development, including the specifications, working relationships and fiscal management in partnership, Baker Hughes was able to assist in lowering the economic development point of Solan P3 for Premier Oil.
This is the first example of how the life of fields can be extended, commercially and practically, in the UKCS and beyond. Perhaps the industry is about to become known for its creativity, as much as its ingenuity.
David McKendrick is senior commercial manager at Baker Hughes Oilfield Equipment