Operators’ co-operative approach boosts production performance on Erskine field

Effective teamwork between operators and suppliers has resulted in the completion of a highly efficient maintenance programme on Erskine, one of Chevron Upstream Europe’s (CUE) offshore installations, which has significantly boosted production performance.

Erskine is a gas condensate field that was discovered in 1981 in Block 23/26 in the Central North Sea. It was the first high-pressure, high-temperature field to be developed in the U.K. Continental Shelf, achieving first production in December 1997. It comprises a normally unmanned installation (NUI) which is remotely controlled from BG Group’s Lomond platform. An 18.6 mile (30 km) pipeline links the two facilities.

Processing of hydrocarbons takes place in a dedicated module on the Lomond platform. Gas and condensate are exported separately to BG Group’s North Everest platform before gas is finally exported via the Central Area Transmission System, while condensate is exported through the Forties Pipeline System.

BG Group and CUE have been working together on a large scale maintenance campaign to upgrade the Lomond hub to improve the efficiency of Erskine production, part of which comprises the cleaning and inspection of the 30 kilometre pipeline using a practice called ‘pigging’ with devices known as ‘pigs’.

Andy Brooks, Erskine Asset manager, explained: “Pigging involves inserting a pig into an oversized section in the pipeline known as a ‘pig launcher’ located on the Erskine Platform.  The launcher is then closed and the pressure-driven flow of the product in the pipeline is used to push it along the pipe until it reaches the receiving trap called the ‘pig catcher’ located at Lomond.  Carrying out this process enables us to clean and inspect the pipeline.

“By developing a joint vision for the campaign with BG Group and securing committed integrated input from the Erskine Asset and Intervention Team, Facilities Engineering Pipelines Group including pigging vendor companies, Logistics, BG onshore and Lomond offshore teams, we ran a total of 14 pigs, including an intelligent pig, which was essential for proving the long term integrity of the pipeline.”

The work took place over three mobilisations spanning a period of three months and, along with BG’s major refurbishment and maintenance programme on Lomond to improve long-term reliability, has resulted in all five Erskine wells coming online for the first time in two years. The daily production rate is now the highest it’s been in two years, at approximately 27,000 barrels of oil equivalent per day, and the combined production from Erskine and Lomond is at its highest since changing to a single train operation.  Daily production efficiency is currently sitting at more than 90 per cent.

Steve Cox, BG’s Vice President UK Operated Assets said:  “The recent pigging campaign is a great example of the ongoing success of the collaboration between the two companies,” a sentiment echoed by Dave Dillard, General Manager of CUE’s UK Operated Assets, who added: “With Erskine back on line, the teams are on course to deliver against their performance metrics for 2015 – a position Erskine hasn’t been in for a number of years.  These results highlight the impact of exceptional teamwork and reinforce how a collaborative approach can add real value to the business.”

The Erskine Field is operated by Chevron North Sea Limited (50 percent) with BG International Limited (29.30 percent), BG North Sea Holdings Limited (2.70 percent) and Serica Energy (UK) Limited (18 percent) holding non-operated interests in the field.

Chevron- Enhancing collaboration to drive future success

Submitted by Chevron


The focus on improving the collaborative approach had a major impact on the long term sustainability of both the Erskine and Lomond assets. The short term impact has been the delivery of a number of key milestones and significant achievements that have added real value to the business, including:

  • All five Erskine wells online for the first time in two years;
  • Erskine daily production rate is the highest it’s been in two years (approximately 27,000 barrels of oil equivalent per day);
  • Erskine production efficiency is currently above 90% (highest since 2012); and
  • Combined production from Erskine and Lomond is the highest it’s been since changing to a single train operation.


Description of Best Practice

In September 2014, Chevron Upstream Europe (CUE) created a new Erskine Asset team. At the same time, BG Group were about to embark on a large scale six month floatel maintenance campaign and associated turnaround (TAR) on their Lomond facility, which remotely controls CUE’s normally unattended Erskine  installation and processes and exports the field’s hydrocarbons.

With new employees (both Chevron and BG Group) came new ideas and opportunities to improve collaboration were quickly identified. The teams started small, with regular meetings to address ways in which collective action could enhance operations.

These meetings became a foundation on which to build and the two parties quickly decided that greater collaboration was key to performance improvement and sustainability. Both groups began working together through key TAR meetings, morning calls, flow assurance work groups, engineering studies and management engagements.
An example of where this new approach has added real value to the business is the safe and successful completion of the recent large-scale maintenance campaign at Erskine.

A key element of the campaign involved a practice called ‘pigging’, which used devices known as ‘pigs’ to perform various maintenance operations, including cleaning and inspection, on the 30 kilometre pipeline that ties Erskine back to BG’s Lomond platform. The campaign involved running a total of 14 pigs, including an intelligent pig, which was essential for proving the long term integrity of the pipeline – a significant achievement considering the last pigging campaign took place in 2009.
Having created a joint vision and developed a trusting, accountable, fit-for-purpose and collaborative relationship, the three-month campaign was executed on schedule. A testament to the efforts of all onshore and offshore personnel involved and the commitment shown to planning, peer reviews, offshore representation and daily progress meetings.

Contact: Andy Brooks, Chevron Upstream Europe

Chevron- Evolution of the Britannia Operating model: A case history in business efficiency

Submitted by Chevron


The change in Operatorship will

  •  Deliver simplified governance and efficient and effective decision making;
  •  Provide streamlined access to specialist support within an optimized organizational structure;
  •  Drive improved focus on production efficiency and safety; and
  •  Maximise shared resource synergies which will result in operating and capital cost savings over time [10% opex reduction in 2016].

Description of Best Practice

In 1994, Chevron and Conoco formed Britannia Operator Limited (BOL), a company that owned no assets, did not make a profit and existed solely to develop and operate the Britannia field on behalf of the fields’ co-venturers.

The setting-up of a 50:50 joint operating company for the Britannia development was an innovative approach in the UK North Sea. It expedited the development of the field by simplifying the process of reaching agreement between Chevron and Conoco. It was an operating company that looked and functioned like a traditional one-company operator with the ability to utilize the technical strengths of both – with Chevron providing seconded employees primarily responsible for subsurface activities (geology, reservoir engineering, drilling) and Conoco seconded personnel responsible for conceptual engineering, safety and the environment, operations and commercial activity.

This Operatorship model proved to be an outstanding success, providing safe, cost-effective and objective management of the Britannia asset to the benefit of all co-venturers.

Twenty one years on and [47] production wells later, Britannia is a very different asset. Development of the subsurface is still important but the focus is now on safely, efficiently and cost-effectively managing a mature asset. In addition, a large part of the throughput is now derived from satellite developments tied back to the field, which requires a different approach to management.

Both ConocoPhillips and Chevron recognized that the change in the nature of the business might be better managed under a different business model. Early in 2015, a joint review was launched to consider whether a greater value with tangible results could be delivered to co-venturers if the company was to become a 100% owned entity. It was coincidental that this review took place against a back-drop of falling oil prices. However, both companies concluded that there was an opportunity to reduce operating expense without impacting safety and efficiency.

Formal agreement was subsequently reached to transition the organisation to become a 100% ConocoPhillips-owned entity. By integrating the operation into the broader ConocoPhillips UK company, efficiencies can be enabled. The focus on reliability and maintenance will become more challenging as the demands of fabric maintenance and asset integrity compete with the need to maintain high levels of production efficiency for all fields using the Britannia facility.

There is an additional level of complexity that needs to be factored in, namely the process of decommissioning certain Britannia assets which will begin over the next several years. Both parties agreed that the increased depth and breadth of technical and operational resources required during this phase would be better handled within a larger organisation having more direct access to specialist support. In addition, ConocoPhillips has recently established a dedicated decommissioning team whose expertise and growing experience can be more easily and efficiently accessed in-house.

However, the spirit of BOL lives on and the contribution of Chevron to development of the subsurface has been recognized with the decision to second [7] subject matter experts to ConocoPhillips to continue working on the Greater Britannia Areas.

Contact: Andy Clitheroe / Chevron Upstream Europe

Chevron – Joint venture collaboration reduces clair turnaround (TAR) duration

Submitted by Chevron


The shortened duration of the TAR has added approximately 1 million barrels of oil equivalent to Clair’s production and the production efficiency challenges addressed in the work scope of the TAR plan have so far resulted in the longest run time without a full production shutdown since 2012.

Description of Best Practice

In the summer of 2015, the Clair Joint Venture team undertook a TAR of the Clair Field to address a number of maintenance and production efficiency improvements. With an expected duration of 108 days, a collaborative approach saw this substantially reduced and the TAR safely and successfully completed in 58 days.

The successful delivery of the reduced duration TAR was achieved through:

  1. A drive to achieve superior results by identifying that opportunities to optimise the scope, efficiency and duration of the TAR
  2. A series of meetings and workshops to promote collaboration and focus on detailed reviews of the TAR plan
  3. An ability to leverage and build on Best  Practices and key Lessons Learned from Joint Venture subject matter experts experienced in TAR planning and execution
  4. A collective approach to supporting the Operator in the delivery of the optimised plan with excellence

With a robust TAR plan and an agile Joint Venture Team, the group were react effectively and efficiency to any emerging workscopes to ensure delivery ahead of schedule.

 Contact: Justin Thomas, Chevron Upstream Europe

Centrica – Chestnut scale squeeze journey

Submitted by Centrica


By collaborating with the service community and adopting a ‘One Team’ approach novel solutions to challenges were identified and successful projects delivered at a significantly reduced cost.

Overall a cost saving of 79% was realised. These savings were subsequently used to fund other projects across different areas of the business.  Production from one of the well assets increased by 25% helping to extend the life of that asset offsetting the low commodity price.

Had an industry standard approach been adopted, projected costs would have resulted in the activities being sub-economic in the low commodity environment.

As well as allowing us to source new ways of working the ‘One Team’ approach has helped to break down recent barriers along the supply chain and created a spirit of greater collaboration with and between our vendors emphasising that if we all work together we can all benefit.

Description of Best Practice

As a result of irregular sampling and delayed sample analysis on a CNNS oil asset, Barium Sulphate scale started to form in one of the subsea wells tied back to an FPSO.

Flow monitoring in the comingled flow system eventually identified a problem with the wells flow performance.  Discrete flow testing and sampling confirmed 90% loss in a single wells production as a result of scale formation in the wellbore.

Initial opinion was that a drilling unit or intervention vessel would be required to re-enter the subsea well and mechanically remove scale returning the well to production.  This was the industry standard method of addressing the problem.

Focused on delivering value in a low commodity price environment, Centrica presented the scale removal challenge to a team of internal engineers and external experts from the service community.  A series of open forums were held to identify all potential solutions.  After a peer review of options identified, chemical removal via the FPSO was sanctioned as the preferred option for execution.

A number of challenges had been identified with the preferred solution:

  •          Deck space on the FPSO
  •          Volume of chemical required
  •          Placement of chemical in the wellbore
  •          Materials compatibility
  •          Effectiveness of the chemical treatment
  •          Conflicting priorities on the FPSO
  •          Weather limitations in the time period identified for execution

A ‘One Team’ approach was adopted and key accountable people from the Centrica project team, FPSO owner, field Operator, chemical vendor, pumping vendor and marine vendor were identified.  The team was tasked with ensuring the project received the priority required for returning the well to production without impacting existing safety critical activities planned during the same period.

On schedule a PSV (production support vessel) modified as a chemical heating and pumping vessel sailed to the FPSO location and deployed heated scale dissolving chemical to the wellbore via the FPSO through the existing subsea flow system.  After a period of back production and well clean-up, managed by the field Operator, the PSV pumped scale protection chemicals to the wellbore returning the well to production.  Subsequent flow testing confirmed not only a return to pre scale production rates but an increase in the PI (productivity index) of the well and a production increase of approximately 24% over original rates.

The lessons taken from the successful PSV scale dissolver and treatment operation were further applied when a second well was identified as requiring a scale protection chemical treatment.  Unlike previous treatments where chemical was injected with support from a DSV, the same ‘One Team’ approach identified a different method of chemical deployment to the wellbore via the FPSO through existing subsea pipework.

The new method was planned mobilized and executed in a shorter timeframe to the DSV method and delivered at a 79% cost reduction over the previous solution.

Contact: Alan Quirke, Centrica E&P

ConocoPhillips – Collaboration is key for marine logistics

Submitted by ConocoPhillips


Tracy Morrison, UK Logistics Manager explains:

“Our efforts are clearly showing results and we have successfully achieved an improvement in vessel productive time, have improved deck utilisation and seen a reduction in the cost per tonne for material shipped.

“We are now building upon this success and as a result of changing work activity offshore, we have now amended our logistics operating model and removed the use of dedicated platform supply vessels to our Central North Sea business.

“We are also continuing to work collaboratively with other operators as part of a shared pool model with neighbouring installations.”

For ConocoPhillips, seeking opportunities to improve efficiencies in our marine logistics by empowering the team to think creatively out with the box has enabled us to focus and reduce costs.

Whilst our work processes within marine logistics have been improved and streamlined, we are now in a position where we are seeing other tangible results. Vessel non-productive time -32%; Cost GBP tonne shipped -7%; Deck utilisation +/-80%.

Description of Best Practice

Marine logistics, or the delivery of necessary plant, equipment and materials from suppliers to offshore installations is a huge cost to oil and gas operators across the North Sea. In the current economic climate, it is essential that new ways of working are developed to reduce these costs, but yet an efficient, safe and reliable service must be maintained to support the ongoing work of the offshore platforms. With this in mind, the marine logistics team from ConocoPhillips, the largest independent exploration and production company based on production and proved reserves, were challenged with looking at how these costs could be managed more effectively across the company’s UK operations.

The first step was to co-locate the marine logistics team with aviation logistics and the integrated planning and materials front-line support group at Rubislaw House as part of the company’s new cutting-edge Integrated Operations Centre. With this came the efficiencies of collaboration, new technology and improved communications.

 A new VHF communications system was introduced from onshore direct to the vessels on contract to us and an alarmed collision avoidance radar early warning system installed in the logistics hub to monitor offshore marine traffic. With this increased focus on communications, co-operation and performance measures, the team were able to trend the non-performance time of vessels offshore. They demonstrated to internal stakeholders that the service could continue to be delivered and maintained adequately using one platform supply vessel less. A shared marine pool model was subsequently introduced. This change also necessitated improvements in the way deck space was managed onboard the remaining vessels and more effective utilisation of these boats so their productive (or in use) time was improved or in other words ‘increased’.

contact: Sandra Duncan

BP – Teaming up with fellow operator to unlock UKCS resources

Submitted by BP


Shared exploration costs by cooperating on main wellbore and side-track locations, saving XYZ %

Description of Best Practice

BP has worked cooperatively with fellow operator, GDF SUEZ E&P UK Ltd (part of the ENGIE Group), to increase exploration activity and help maximise economic recovery from untapped oil and gas resources in a mature play in the Central North Sea. Using advanced seismic data enhancement techniques and careful analysis of preexisting well data, BP’s exploration team identified a prospect named ‘Vorlich’ in the central North Sea. The challenge was to see if they could drill and test this cost-effectively and expeditiously. In the UKCS, the days of simple quick finds are behind us. Finds are now in small and complex structures, which are challenging, requiring a large amount of time and forensic effort to properly understand. The high drilling costs in the basin can also quickly erode the value of smaller opportunities, making new discoveries increasingly rare.

Ronnie Parr, BP Geophysical Advisor, said: “We identified that drilling the main wellbore into the BP acreage was the optimum exploration location, but a side-track into GDF SUEZ E&P UK Ltd’s neighbouring licence block would allow us to confirm the scale of the resource and its extent, so BP and GDF SUEZ E&P UK Ltd jointly designed the well to test and appraise Vorlich across both blocks. GDF SUEZ E&P UK Ltd operated the well in 2014 in partnership with BP which allowed both companies to share exploration costs, resulting in a successful, potentially commercial, oil discovery”. “At a time when exploration in the UKCS is facing severe investment and cost pressures, we believe the Vorlich project has demonstrated that two UK operators can work together to apply their expertise, expedite a project efficiently and maximise recovery of the considerable remaining resource. We believe there is great potential for other operators on the UKCS to find new ways to work together to ensure that oil and gas is not left stranded and undeveloped.”

Other partners in Marconi / Vorlichare: DEA UK SNSLimited, Maersk Oil North Sea UK Limited and Total E&PUK Limited.