Three speakers gave the benefit of their experiences of how to increase productivity and profitability at a panel discussion held earlier this summer in London.

Certain death
In the second half of 1993, faced with a low and falling oil price, BP undertook a review of its UK portfolio. 'We identified four assets which were not contributing a great deal to the bottom line but were costing a lot of money to keep going,' said John Gregory of the BP mature assets team. 'A new, radical approach was required to avoid certain death!'

The contribution from the four fields in question - Buchan, Beatrice, Clyde and Thistle - amounted to just four per cent of BP's UKCS production, yet accounted for some 13 per cent of the staff and more than 17 per cent of the overhead spend. Added John: 'We effectively had a $90 million business generating only $5 million profit.'

The organisation was characterised by complexity, with many interfaces and unclear accountabilities. More than 1000 individual service contracts were in place, involving some 50,000 invoices each year. Additionally, BP was dealing with no fewer than 14 partners.

Technically, all four fields were in various stages of maturity, and generally characterised by high water cut, large numbers of wells and ageing facilities. There were no operational synergies between the assets, with Thistle being a huge first generation structure located in the east Shetland basin, Beatrice being in the environmentally-sensitive inner Moray Firth, Buchan being an ageing floating production facility close to Forties, and Clyde being a more modern central North Sea facility.

In January 1994, the four fields were brought together into a single mature asset - MAST - and a small team of 20 people was challenged to achieve top quartile operating costs by the end of 1995 and to deliver $16 million net cash flow at $14 per barrel oil price. And all while improving an already excellent health, safety and environmental record, maximising cash generation, deferring abandonment, and creating a means for BP to experiment with a new way of doing business.

According to John, the team rose admirably to the challenge. 'With a clear strategic focus, the small team was completely �delivery� driven. We would only do something if it contributed to delivering our performance targets.' Their main responsibilities included:

• Performance contracting and setting of business targets;
• The performance measurement and review process;
• Safety management and protecting BP�s licence to operate (LTO);
• The generation of investment choices and decision -making on them.

Certain processes were outsourced, such as accounting, production reporting, operations support, IT and computer systems, and reservoir, well and facilities engineering. Out-sourcing of the reservoir management function was a new departure for BP. Added John: 'Having business pro-cesses carried out in the marketplace enables the setting of tough performance indicators, the driving of continuous improvements, and sometimes, step changes in delivery. It also allows extraordinary reward for extraordinary performance.' $21 million delivered

And the results so far? MAST delivered $21 million net cash flow to BP by the end of 1994 (taking oil price movements aside), the additional $5 million arising from increased productivity and further reductions in cost. 'The impact of the improvements in productivity and reductions in operating costs, when coupled with the deferral of non value-adding abandonment expen-diture, has added some $100 million to BP�s net cash flow over the period 1994-97,' John concluded.

An example of a new field deve-loped with a view to boosting productivity and profitability was presented by Graham Walker of ARCO. He described how a combination of FPSO technology and a win-win contracting strategy made it possible to bring the small Blenheim field on stream only ten months after obtaining development approval from the government.

Discovered in 1990, the Blenheim field has estimated reserves of 23 million barrels. A horizontal appraisal well drilled in 1993 confirmed that the reservoir could produce at the rates required to support a floating facility - the well tested at 13,700 barrels a day. The development plan was approved in May 1994 and first oil was celebrated ten months later on 13 March 1995. The project scope remained unchanged from sanction to first oil.

A floating production, storage and offloading (FPSO) facility concept was selected for Blenheim on the grounds of its average uptime of over 95 per cent. The on-board storage within the vessel hull and the internal turret mooring arrangement enable production to continue in severe weather conditions. The FPSO concept also eliminated the cost of a separate storage facility. Oil is offloaded directly to a shuttle tanker for onward transportation to the market. The selection of the existing Petrojarl 1 meant that minimal facility modifications were needed to meet the requirements of the Blenheim development.

'Technology allowed us to reduce the facility requirement, reduce the development time, and increase the production uptime,' Graham noted. All three exploration and appraisal wells were converted to production wells, and existing subsea trees were also re-used - a first for ARCO. The field is produced via three wells, two horizontal and one vertical.

Added Graham: 'We also benefited from the contracting strategy adopted. For an oil field with an expected four-year life, it seemed pointless to purchase facilities which would probably last for 20 years. We chose to lease a vessel, and we considered various contracting methods which included a fixed day rate, a per barrel fee or a combination of both. We went for the latter option, with a view to aligning our income profile with that of Golar Nor, the FPSO owner.'

Performance targets
Golar Nor has responsibility for the installation and day-to-day operation of the Petrojarl I facility for the entire life of the field and has a contract requirement to meet specified facility performance targets. ARCO retains responsibility for reservoir management, oil trading, etc. With all parties working towards a common objective, this is a true win-win scenario.

Rob Kewley of Baker Hughes INTEQ gave a perspective from the service company viewpoint, focusing on the subject of well planning and engineering. The move towards alliancing in the industry is a way of reducing costs from the entire system while increasing productivity and profitability for all involved, he said.

'It is essential that the operator and contractors working together in a well engineering alliance maintain a life of field perspective and, through common objectives, are focused on those elements of the development that control its ultimate value,' Rob continued. 'Establishing a shared well planning process founded on continuous improvement and teamwork is key and this must be underpinned by effective systems which ensure technical integrity and retain knowledge as the organisation learns.'

Typically, key success factors might include well performance, the first oil/gas date, the reduction of capex and opex, and health, safety and environmental performance.

As illustrated in the diagram above, well construction requires the skills of many disciplines and teams must be developed and organised to focus on key business deliverables. Added Rob: 'It is important to get the performance measurement right too. The teams must understand the performance measures and how the rest of the industry performs against these. Each well must be evaluated and plans revised accordingly as part of the continuous improvement process. Good teamwork is critical for success, with individual behaviour also playing an important role.'

Rob considered how the construction of a well impacts on value over the entire life of a field and how important it is to get a well right first time. A poorly placed well may result in costly intervention to control premature water or gas breakthrough. A damaged well can lead to reduced well management flexibility, more wells being needed to sustain plateau production rates, stimulation and deferred, or even lost, production.

Significant benefits accrue from a fully integrated alliance approach to well construction/well management, all of which contribute to increasing the NPV of the project:

• Focus on adding value. The operator can focus its resources on value-adding core activities such as reservoir evaluation/management, quality assurance for well engineering rather than operations management, etc.
• Cost reduction through removing waste and duplication, simplifying the admin- istration and logistics, multi-skilling, the reduction of interfaces and continuous improvement.
• 'Value engineering', where the contractor and operator work together to deliver the best business solution using the most appropriate technology and benefiting from their combined worldwide experiences. A team environment is established which promotes innovation and delivers a step change in performance.
• Commitment is won with common objectives, alignment through risk/reward and a shared culture of continuous improvement. Risk is reduced via a win-win/lose-lose scenario.