BP- Waste ‘swap’ delivers savings of £9million

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Impact

  • BP has saved approximately £9 million by changing how we manage waste water from well plugging operations on our Valhall oil field.
  • The new, offshore-based approach avoids the need to transport and treat the waste onshore and send to landfill.
  • Well clean up fluids can now also be recovered and reused.

Description of Best Practice

BP has delivered an innovative solution for offshore well waste management on our giant Valhall oil field in thesouthern Norwegian North Sea, where 31 older wells will be permanently plugged over the coming years.

Preparing a well for permanent closure generates thousands of cubic metres of water containing oil based muds, cuttings and cleaning fluids. Due to lack of capacity and/or facilities offshore, this waste water is traditionally shipped onshore to be treated and then disposed of safely at significant cost.

On Valhall, a single waste injector facility was being used to treat and then inject the giant complex’s drainage waste water into the ground. However, this waste water is 98% pure and the project team realised it would be more efficient to use this facility to treat and then inject the higher solids waste water generated from the plug and abandonment operations.

At the same time, a separate cleaning plant was installed on the nearby drilling rig being used for the long-term plug and abandonment programme. The platform’s drainage water is now piped to the rig, where it is treated and purified to the extent it can be discharged to sea.

Planning for the new system took four months and the first lot of waste was transferred in June 2015. The drilling rig has since treated 49,362 barrels of open drain water from the Valhall complex while the platform has received 85,228 barrels of waste from the plugging and abandonment operation, delivering cost savings of approximately £9 million. The new approach also avoids the need to transport and treat the waste onshore and send to landfill

An unplanned benefit has been that the brine water used for clean up of the wells is being reused. Some 3,200 barrels have been recovered during the treatment phase and reused on other well kill operations.

Arnfinn Grøette, Waste and Fluid Operation Specialist, said: “Before the project, a single well abandonment generated approximately 2,000m3 of waste water and cost £950,000 to send back onshore for treatment and disposal. Now, a major part of this is treated to a defined specification before it is sent to the solids handling module on the production platform and then reinjected.”

Jeroen Nijhof, Engineering Team Lead, added: “The Wells team essentially swapped our waste with Operations. It sounds simple but it was vital to have everyone in all functions on board and to believe it was possible before embarking on the project. It demonstrates what is achievable when different functions come together to find a solution to a problem.

Contact: Stephanie McHardy, BP
stephanie.mchardy@gmail.com

BP – New technology and focus on performance management improves efficiency of drilling operations

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Submitted by BP

Impact

Reduced drilling time by 24 days per 10,000 feet drilled compared to previous campaigns

Description of Best Practice

Major oil and gas operator, BP, has achieved a significant reduction in drilling time by focusing on performance management and introducing new technology.

During the appraisal of the possible third phase of development on the Clair field, West of Shetland, the application of new technologies, applying lessons from previous drilling campaigns alongside a rigorous focus on performance management reduced drilling time by 24 days per 10,000 feet drilled compared to previous campaigns.

The continuous improvement from the first well to the last saw productive rig time –the underlying operational time to completethe same tasks –improve from 53 days to 39 days. The implementation of new technology saved an average of four days’ drilling per well. In addition, completing a dual zone well test in a single run instead of two saved two to three weeks of well testing operations.

Russell Morrice, BP Drilling Engineering Manager commented: “Our approach to well operations in the appraisal of Clair reduced drilling time to such an extent that an additional sixth well was drilled within the original five well schedule. This enabled further appraisal of the Greater Clair field in support of both a potential Phase 3 development and ultimately maximising recovery ofthe UK’s oil and gas. The approach will now be used in other drilling campaigns”.

Clearwater Fire Solutions- Embracing new technologies to improve safety critical maintenance procedure efficiencies

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Submitted by Clearwater Fire Solutions

 Key benefits

  • No new corrosion, salt or marine growth will form in deluge pipework and nozzles
  • The system is live throughout the process and the equipment does not impede the flow path of firewater to protected areas.
  • Damaged, blocked and partially blocked nozzles are quickly identified as well as ruptures or damage to pipework.
  • Dry Deluge Testing does not rely on the system being clean or having up-to-date hydraulic calculations and isometric drawings.
  • Testing deluge systems dry brings a more scientific approach to all previously available inspection based routines.
  • Dry deluge testing makes internal borescope inspections more efficient
  • Dry Deluge Testing has been extensively field proven on and offshore and is regularly used in the Dutch and UKCS offshore sectors and also the UK Nuclear industries.

Cost Reduction

  • It is efficient and has no disruption to normal platform activities.
  • Preparation time for Dry Deluge Testing is considerably shorter.
  • Smaller teams required means less bed space required
  • Typical time for single dry deluge test and borescope inspection is less than one working shift
  • Complete platforms can be tested in days rather than weeks.
  • Typical savings of 60% achieved by replacing a 6 Monthly Wet Test regime with Annual Dry Test in line with a Fire System Integrity Assurance (FSIA) plan

Safety

  • No water ingress protection is required over sensitive instrumentation or electrical equipment
  • Pipe wall failures are easier to identify

Description of Best Practice

Many operators are stuck in the cycle of increased wet deluge testing in order to prove that systems are clear of blocked nozzles. Whilst this approach may achieve the end result, any increased frequency of wet testing brings its own problems to the operator.  Not only does testing with seawater exacerbate the corrosion levels within the pipework, the operator has increased risk of an unplanned business loss due to a production shutdown and also the on-going fabric maintenance issues due to water ingress.

Implementation of the unique and patented Siron Dry Deluge Testing will enable the operator to provide proof that the deluge system is in a fit for purpose condition. The system utilises pressurised water based vapour instead of sea water.   Any flow problem in pipes and nozzles will be quickly identified in an easy and cost effective manner within the NFPA guidelines. Whilst not a complete replacement for wet deluge testing, the use of Siron Dry Deluge Testing can potentially extend the periods between wet testing to 5 years or more.

Siron Dry Deluge Testing is the most efficient method of visually identifying blocked and partially blocked pipework, blocked and partially blocked nozzles, and also damaged nozzles to 100% of each system by visually recording the disrupted spray patterns from the affected nozzles without using water.

By using dry deluge testing the operator can ensure operational efficiency whilst improving safety in a cost effective manner.

Contact: Steve Nickerson

steve.nickerson@clearwater-fire.com

Nexen – Electric Line Tractor technology drives savings for Nexen

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Submitted by Nexen Petroleum U.K. Limited

Impact

Nexen has saved nearly £1 million by attempting new methods in the removal of isolation plugs.

Results have also included substantial reductions in heavy lifts offshore, platform services support and operational risk.

Description of Best Practice

Plugs are often used in wells to cut off water producing zones in multi-layered reservoirs.  In early field life the water producing zones are often isolated due to other layers producing plentiful ‘dry’ oil.  However later in the life of field those reserves that were previously isolated start to become more attractive to produce, as water production in the field rises in general.

Removal of the isolation plugs has traditionally been done by Coil Tubing, however Nexen Petroleum U.K. Limited has carried out the removal of isolation plugs by a combination of milling and other devices deployed on Electric Line Tractor technology.

This operation removes the requirement to use coil tubing and results in a substantial saving in operational cost of up to £1 Million.

There have also been many incremental benefits such as the substantial reduction in heavy lifts offshore, platform services support and operational risk.

Contact: Tracey Miller
tracey.miller@nexencnoocltd.com

Nexen – Advancement in tubing cutter methodology drives greater efficiency

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Submitted by Nexen Petroleum U.K. Limited

Impact

Nexen Petroleum U.K. Limited has increased efficiency due to new developments in tubing cutter methodology.

Before, electric line tubing cutters were employed but technological advancements have resulted in tubing string now able to be cut in compression ie without the need to create tension.

The result is that low cost preparation work can be done offline and in advance as part of a wireline intervention, with no requirement for a drilling rig to make the cut.

This efficiency has saved Nexen approximately 7 to 10 days of drilling rig time.

Description of Best Practice

When a well is sidetracked from an existing well bore the completion has to be removed first, which requires the tubing to be cut and released from the packer.  This cut used to be done from a drilling rig, due to the need to create tension in the tubing string in order for the cut to take place.

Electric Line Tubing Cutters have been in existence for a number of years, however a recent development has meant that the tubing string can be cut in compression – i.e. without the need to create tension.  This means that there is not a requirement for a drilling rig and the operation can be performed on a wireline deck.

The use of this technology means that a well can be fully prepared offline as part of a low cost wireline intervention before a drilling rig arrives.  This saves approximately 7 to 10 days critical path rig time.

 Contact: Tracey Miller

tracey.miller@nexencnoocltd.com 

Nexen – Significant savings made by changing to alternative valve in well interventions

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Submitted by Nexen Petroleum U.K. Limited

Impact

Nexen Petroleum U.K Limited:

  • has saved approx. £30,000 per each well intervention as a result of changing to an alternative valve;
  • routinely used Shear Seal Valves in well interventions but the dimensions of the valve actuator caused logistical problems (removal of a major deck hatch) which cost time and manpower; and
  • is now using Slimbore Shear Seal Valve, which uses a different type of valve (ball valve) to create a valve which has tall and slim dimensions.
Description of Best Practice

The growing complexity of well interventions coupled with the reduced oil price environment has increased the cost of well interventions workscopes, which are necessary for maintenance and technical purposes to extend the life of a producing well.

Nexen Petroleum U.K Limited has saved approx. £30,000 per each well intervention as a result of changing to an alternative valve.

A type of valve routinely used in all well intervention operations, Shear Seal valves, have actuators attached that are short in width but long in height.

The dimensions of the valve actuator cause logistical problems (removal of a major deck hatch) which costs time and manpower.

An alternative valve design is now used, the Slimbore Shear Seal Valve, which uses a different type of valve (ball valve) to create a valve which has tall and slim dimensions.

This valve fits through a much smaller aperture and means that a much smaller deck plate can be removed manually.

The valve can also be lifted and placed using the in-situ wireline mast tugger line. This removes the requirement for a platform deck crew, crane driver and scaffolders.

Contact: Tracey Miller
tracey.miller@nexencnoocltd.com 

Lokring – Lessons in pipe connections from the British MOD

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Submitted by Lokring Northern UK

Impact

Lokring provides a safer, faster and cheaper alternative to welding and is code qualified as a permanent method for connecting pipe within Oil and Gas industry.

Lokring is, however, used across a wide variety of industries. One of the most extreme applications being with the British Ministry of Defence. After under-going highly stringent testing including:

  • 1000G Shock Test (to simulate a depth charge or missile strike)
  • Vibration Test with 10 million cycles and 500,000 pressure pulsations

It was found that only Lokring or properly done butt welds were suitable to be used. As a new build project, there were no restrictions to welding. However, the speed of install offered by Lokring and the ability to stack trades saw over 7000 Lokring fittings used on each of the astute class submarines and over 12,500 on both the aircraft carriers (HMS Queen Elizabeth and HMS Prince of Wales).

How does this relate to the Oil and Gas industry?
Recently an Operator in the SNS replaced a diesel ring main on one of its offshore platforms. Initial plans, using pre-fabricated spools to be tied in using flanges, came in over budget. An alternative method was therefore required and, by adopting the techniques used by the MOD, it was proposed that Lokring was used to construct the entire system offshore (site-run).

Description of Best Practice

By changing the mind-set from ‘we always do it this way’ to looking at alternative methods already used in other industries, an operator in the SNS was able to make significant savings in both COST and TIME.

The operator took a product it was already using, Lokring, and adopted a technique used by the British MOD. By doing this they managed to massively reduce offshore construction time by over 1000 hours, freeing up bed space and allowing workers to move onto the next job. The cost of site-running Lokring came in 28.48% cheaper than the pre-fabrication method.

Site-running with Lokring is becoming more and more common in the Oil & Gas industry, helping operators to complete projects efficiently and within budget.

Contact:    Jake Rowley
jrowley@lokring.com

Wood Group – Significant cost reduction with virtual metering

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Submitted by Wood Group 

Impact

Long term reliability of subsea multi-phase meters is an ongoing challenge. These can incur costs of tens of millions of dollars over the life of a field, with maintenance cost reported to be greater than $100,000 per month, and replacement cost greater than $3 million per event. With the range and variety of subsea solutions there can be a number of different subsea, topside and downstream meters in play. Wood Group’s virtual metering system (VMS) makes a robust, low cost backup for physical metering, allowing greater flexibility for maintenance scheduling and frequency.

Description of Best Practice

Virtual metering technology works by using proprietary modelling software to draw from available field instruments and generate online flowrate estimates. Across the whole well system VMS can reconcile flowrates to help customers understand total allocation and mitigate errors in upstream meters.

In one example the VMS was tested for an extended period when all the physical devices failed within six months of installation. After two years of operation the virtually metered flowrates matched the total from export meters with less than 0.5% error margin.

Recent advances in technology have brought greater sensitivity and accuracy to this system and enhanced calibration has maintained a high level of accuracy against real operations. The accuracy of metering is such that some operators are considering the system as a replacement for physical metering rather than backup, or at least reducing physical numbers. This would have a major impact on maintenance and replacement costs.

Contact: Philip Oliver
philip.oliver@woodgroup.com 

 

Wood Group – Enhanced decision making in offshore drilling

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Submitted by Wood Group

Impact

Well specific operating guidelines (WSOG) set out the specific conditions and guidelines for drilling, based on detailed analysis of operational environment parameters. This is highly valuable in time sensitive operations, where there may be a drilling rig on standby awaiting the results from an analysis of a planned operation.

Based on detailed analysis of a considerable number of operational environment parameters, producing a WSOG can be labour intensive. A significant volume of data needs to be analysed and interpreted in order to produce actionable ‘decision-grade’ information. Wood Group tackled this by automating the process, improving the turnaround time for getting valuable information to the customer.

Description of Best Practice

OptiView is an innovative new software solution for efficient generation, presentation and interpretation of key operational guidelines for offshore drilling operations; the tool is set to become an industry standard.

This interactive system can be licensed for the duration of a drilling program. It takes results generated by Wood Group’s drilling riser analysis software and collates them in a user friendly interface so results are quickly and easily filtered, presented and interpreted in an offshore operational environment.

Contact: Philip Oliver
philip.oliver@woodgroup.com

Wood Group – Innovation to improve flange management when decommissioning

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Submitted by Wood Group

Use of Springlynn, a self-tapping saddle for draining and venting, adopted from the water industry.

Impact 

The system is very simple in design, and can be used by someone with no previous training Using a self-tapping saddle for draining and venting systems while decommissioning negates the need to break flanges whilst ensuring that re-energisation of the pipeline cannot occur.

Being simple to install and effective in design, the system removes potential risk of asbestos exposure from old compressed asbestos fibre (CAF) gaskets, and therefore does not require specialist asbestos operators to be present.

Where engineered valves are not installed or are difficult to access, the system may also be used to install vents and drains.

Spill risks are reduced by making it easier to divert potential liquid inventories through to a containment system prior to commencing separation scopes.

Description of Best Practice

From the point of ‘Cessation of Production’ (COP) and the initiation of decommissioning work, the process of engineering down selected systems and pipelines begins.

Systems are physically isolated and de-energised with air gaps, and appropriate vents and drain points installed as further safeguards. Breaking flanges is a routine part of this process to prove it is safe before progressing with module and process separation. Similarly, breaking flanges is necessary when separating topsides for Single Lift Vessel (SLV) removal. All of these flange breaks take time to carry out safely as they may interrupt asbestos present in CAF gaskets of old flanges.

To solve the issue, our decommissioning services contract team proposed using a system adopted from the water industry. The Springlynn system avoids the need to break valves and may also be used to install vents and drains at low/high points if there are no engineered valves installed where required (or if they are difficult to access).

The system is very simple in design, and can be used by someone with no previous training. All components come ready for use, and all that is needed is a common hand drill and a spanner. No fluids escape during installation owing to the specially designed drill head which seals off on the drill bit. Because of the unique system design, once drilling into the ball valve is complete and the ball valve closed, the drilling head may be removed whilst maintaining the integrity of the valve.

Contact: Philip Oliver
philip.oliver@woodgroup.com