APSYS- Sparing optimisation of a network of compression stations

/in , , , /by

Submitted by APSYS

Impact

The customer was provided with the following results:

  • Reduction of sparing at 23 out of 24 compression stations; at one location savings of €1.2M were identified;
  • Availability risk identified at one location resulting in a requirement to increase sparing;
  • A 35 per cent increase in sparing at the central warehouse to provide better network support; and
  • An overall stockholding cost reduction from the M€9.6 to M€2.4 i.e. a reduction by 75 per cent.

Description of Best Practice

Context: A multi-national Oil & Gas service provider into the energy industry operates a network of pipelines and gas compression stations. The customer had requirements to optimise sparing from a cost point of view whilst preserving current levels of availability for this network which comprises 25 sites (gas compression stations, supported by a centralised warehouse facility).

Approach: The study has been carried out in a two-stage approach.First we assessed the logistical readiness for both localised and centralised sparing, using existing data.

The availability was determined by creating a model based of the system and supplied information, along with a snapshot of the inventories at all 25 locations. In the second stage, the model was run to identify opportunities for cost and stockholding optimisation across the entire network, whilst maintaining or improving the existing availability levels. SIMLOG is a software tool which helps to optimize type, quantity, and location of Logistics Elements for one or more repairable systems. This tool has been applied in other industries (Aerospace, Defence, Railway) and tested /validated in the UK by the MOD. It can also be linked to the CMMS (SAP, Maximo) for real time availability analysis.

Contact: Pierre Secher
pierre.secher@apsys.eads.net

Proserv provides asset life extension for major North Sea operator

/in , , , /by

Impact

The proposal provided by the controls system supplier was to sell a new electro-hydraulic SSIV to the Operator  which would not have been compatible with the installed controls system. The Operator would have to replace a 400m umbilical and upgrade the existing controls system to operate the new electro-hydraulic SSIV. As a rapid-response engineering solutions provider, Proserv were contacted to determine whether there was a solution to work around the controls supplier’s negative response of having to replace the entire SSIV and controls system. The solution offered by Proserv saved the client from spending many millions to replace the existing subsea system and the cost of lost production. Furthermore, Proserv was able to offer a future-proof component obsolescence management  plan.

The SSIV was transported down to our Subsea Control Centre of Excellence in Great Yarmouth, UK, for testing on a base plate. The filter and filter block were removed and dismantled, and the existing filter element removed and discarded, along with the filter block seals. The unit was then re-assembled with new seals and a new filter element. The same was then done with the DCV Shuttle Valve which went on to achieve an acceptable shutdown time which was acceptable to the Operator. A full FAT was carried out by the Proserv team in Great Yarmouth which was witnessed and accepted by the  Client representatives.

Description of Best Practice

In the early 1990s, a major North Sea Operator purchased a subsea controls system which included pipeline subsea safety isolation valves (SSIV). A field ready spare was also purchased and stored, to provide contingency. As the units in place were more than 20 years old, the decision was taken to re-FAT the spare SSIV to check its serviceability. The unit was stripped down and the incumbent controls supplier was contacted to establish whether they could support the main valve on the SSIV, with a view to ordering parts or replace the valve if required. The OEM controls supplier was unable to support this valve, or offer a replacement  for the obsolete parts.

Contact: Scott Lourie, Proserv
Scott.Lourie@Proserv.com

 

Maersk Oil – Optimising to remove risk

/in , , , /by
Submitted by Maersk Oil

Impact

The Maersk Oil team adapted an existing inspection technique forecast to produce cost savings in excess of 80% over the next five years as well as a considerable reduction in the duration of the activity.

Description of Best Practice

In order to scan the flexible hoses on the Gryphon Alpha’s turret, Maersk Oil previously used radiography, a technique which uses gamma radiation to capture an image onto a film. This technique is widely used throughout the industry but isn’t without issue:

  • Radiography could not be carried out in the direction of the asset’s nucleonic detectors as this will trip the vessel’s High Integrity Pressure Protection System (HIPPS), causing an unplanned production outage.
  • The entire turret area has to be shut off to personnel during scanning as radiography poses a significant danger to health. This prevents routine operations from taking place in the vicinity.
  • Radiography was carried out over nine months of the year but this only achieved around 50% of the required work.

Maersk Oil engaged with Innospection, innovative inspection specialists, to investigate alternative inspection techniques, with a goal to reduce personnel exposure to ionising radiations, spurious plant upsets and identify possible cost reduction.

It was discovered that Innospection already used Saturation Low Frequency Eddy Current (SLOFEC), an electromagnetic technique, on subsea risers. The current method was employed on a much larger scale than required, so teams worked to figure out how the technique could be adapted for topsides. A bespoke tool (MEC-P7), small enough to work successfully with the flexible hoses on Gryphon, was developed and tested onshore; an old section of a flexible hose was intentionally damaged to see if the tool picked up the discrepancy. It did. Overall, around six months was spent developing the tool and validating the technique.

The MEC tool was then trialled offshore on the Gryphon Alpha FPSO where it scanned all of the 6” flexible hoses, around 40% of the turret system in just two weeks, providing better coverage whilst delivering required image quality.

It’s estimated that the use of the MEC technique will deliver cost savings in excess of 80% over the next five years as just two fortnightly trips per year are now required. The tool has also eradicated the risk radiation posed to personnel and the risk of unplanned outages.

Contact: Danielle O’Donnell
danielle.odonnell@maerskoil.com

Maersk Oil – Engineering a unique solution

/in , , , /by

Submitted by Maersk Oil

Impact

Replacing the buoyancy modules on a live riser system has never successfully been completed before. The Maersk Oil team met this challenge head on and developed an innovative solution, avoiding the need to replace the riser completely. The project only took around two and a half weeks and cost around 16% of the average fee of replacing a riser. Throughout, there was no production loss and no need for diving personnel, reducing the risk to human life.

Description of Best Practice

Replacing the buoyancy modules on a live riser system has never successfully been completed before. The Maersk Oil team met this challenge head on.

Rather than replacing the whole riser, an extremely time consuming, expensive and risky operation, the team sought an alternative way to correct the slippage. A rough concept was put to the supply chain: we wanted to fix the problem in a targeted manner using an ROV, allowing us to move away from conducting saturation diving operations for repair or replacement. This also allowed the team to engineer a solution which could be implemented whilst in operation.

In collaboration with SubC Partner, inventor and owner of the technical solution, a bespoke tool was created over six months which connected to a ROV. As EPCI contractor, SUBC Partner’s was responsible for: conceptual/detailed engineering; construction of subsea and support tools; supply of vessel/ROV; supply of manpower and project management.

The tool had to be specially developed for the task because there were a number of specific requirements: it had to work underwater whilst connected to the ROV, dock onto the riser and remove the old buoyancy module and inner clamp from the riser. Then bring the old parts to the surface, pick up the new clamp and module and go back down to the riser to install the new parts. Furthermore, the new clamp was installed with rubber compliant pads to stop future slippage; a technique already effectively used by Maersk Oil.

In the end, the team found an innovative solution to a complex issue, avoiding the need to replace the whole riser, the only other viable option: the project only took around 2 and a half weeks and cost around 16% of the average fee of replacing a riser. Throughout, there was no production loss and no need for diving personnel, reducing risk to human life.

Contact: Danielle O’Donnell
danielle.odonnell@maerskoil.com

Performance Improvement People- Cost efficiency through behavioural readiness

/in , , , /by

Submitted by Performance Improvement People

Impact

Outcome: On commencement of project execution there was an immediately high productivity ratio, and better-than-planned productive day.  These efficiencies have allowed for increased scope liquidation and therefore increased value for the same spend.

Learning: We believe this was the first time this approach has been tried within an oil & gas execution environment, and as such some approaches brought greater success than others.

The best value activities appeared to be:

  • Team profiling resulted in objective identification of weak points and the early opportunity to manage them.
  • Scenario-based workshops flushed out areas of misalignment and misunderstanding; meaning gaps could be plugged prior to entering the high cost execution environment.
  • Small, diverse, group workshops allowed a free flow of discussion between representatives of different groups.  This was an unplanned side effect of the original strategy and the relationships made during these sessions have underpinned a great deal of problem solving in execution.
  • Meeting audits gave objective feedback as to how data and decision making flowed through the project.  This gave a very clear identification of bottlenecks.

Description of Best Practice

Challenge: An operator was running a life extension project for a major North Sea asset.  The project team consisted of representatives of a number of different organisations, including Operator, Tier 1 Contractor and the extended supply chain.

Performance Improvement People were asked to address the challenge of bringing together these different organisations into a single, cohesive team to ensure high efficiency and productivity in the execution environment.

Action: Performance Improvement People used various behavioural analysis techniques to measure and understand the behavioural norms present in the combined team.  These norms could then be used as a basis for identifying hot spots and weak points, which in turn provided a practical understanding of inefficiencies in execution.

Many of the tools used are widely available, and primarily used within the context of recruitment, assessment and personal development.  We chose to apply them within the context of project delivery, using the data to develop the project execution model rather than for individual development.
The diagnostic tools included work-related activities such as psychometric analysis, creating and delivering practice scenario discussions, carrying out meeting audits, work-process analysis, team workshops sessions and site-based fabrication maintenance ‘mock-up’ exercises.
The overall impact was to allow the leadership team to truly understand the norms in their business and how they may impact on future work, especially joint project delivery, as well as giving key team members the opportunity to understand the impact of their own behaviours on others around them. In turn this lead to greater efficiency through improved communication, reduction in duplication of work, clearer processes, more effective meetings and reduced overall meeting footprint.

Contact: Morna Ronnie (morna.ronnie@pi-people.co.uk)

Chevron- Enhancing collaboration to drive future success

/in , , , /by

Submitted by Chevron

Impact

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

/in , , , /by

Submitted by Chevron

Impact

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

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

/in , , , /by

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 – Joint venture collaboration reduces clair turnaround (TAR) duration

/in , , , /by

Submitted by Chevron

Impact

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

/in , , , /by

Submitted by Centrica

Impact

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