Introduction

The Brent Field is located 186 km northeast of the Shetlands Islands in the U.K. North Sea and has a STOIIP of 3.8 Bstb and a GIIP of 7.5 Tscf.  The field was discovered in 1971 and was brought on production in 1976, with annual oil production peaking in 1984 at 410 Mstb/d.

Figure1: Location of Brent Field and Schematic of Infrastructure

Since the mid 1980s, oil production has been declining, but because of the high solution GOR substantial gas volumes remained, dissolved in the residual and bypassed oil. In 1992 the decision was taken to depressurise the Brent Field in order to release solution gas from the bypassed (unswept) and remaining (swept) oil, and to produce the gas, once it has migrated to the crest of the structure. Brent depressurisation was planned to recover an additional 1.5 Tscf of gas and 34 MMstb of oil, extending the life of the field by 5-10 years. Three of the four Brent platforms were redeveloped at a total cost of £1.3 billion to install process facilities for low-pressure operations, to reduce operating costs, to implement safety upgrades, and to refurbish facilities. The fourth platform was also upgraded but no low-pressure facilities were installed. Preparation of the platforms for long-term field development was completed at the end of 1997.

Figure 2: Schematic of Depressurisation Process

On 1st January 1998, 450 Mbbl/d water injection was switched off. Seven years after ceasing West Flank pressure maintenance, reservoir performance is broadly in line with the 1992 plan, which formed the basis for project sanction. West Flank reservoir pressures are declining in line with this plan and forecast oil ultimate recovery is virtually unchanged. Forecast gas ultimate recovery has been increased, due to a lower than expected critical gas saturation, which has been revised from an initial conservative estimate of 15% to around 10%, prompted by material balance reconciliation and verified by simulation results.

As the reservoir pressure declines, rates from gas lifted wells will reduce and a number of high rate ESPs have now been installed to enhance voidage: the so-called Enhanced Voidage project. This will play a role in sustaining depressurisation, and help to further depressurise the reservoir.

Figure 3: Brent Reservoir Pressure – Actual Compared to Plan (at 8700 ft TVDSSDatum)

Reservoir Management

Such a complex recovery mechanism requires a detailed set of reservoir management processes and tools. The criteria to be managed include:

• gas production and availability
• liquids production
• oil production
• reservoir pressure and gas cap size

The Brent depressurisation has been managed and monitored with two parallel and complementary methods: analytical techniques (Figure 4) and dynamic reservoir simulation (Figure 5).

The first key element of depressurisation reservoir management lies in systematic and regular monitoring and mapping of gas-oil and oil-water contacts, both areally and by layer, followed by reconciliation of the changes by material balance. Every year, the estimation of fluid contacts and free gas cap size is updated. The observed reservoir response enables us to determine the fundamental parameters in depressurisation: the critical gas saturation and aquifer strength. This has been enabled by the intensive surveillance programme and the data management systems which had to be set up to handle the wealth of data required to cover all units and areas of the field.

Figure 4: Surveillance Cross-Section

At the same time, dynamic reservoir simulation has been at the forefront of Brent field management, providing a long-term view of the depressurisation process to complement the short and medium term capabilities of the surveillance and mapping work. Dynamic modelling of the Brent field has recently reached a major milestone with the completion of the third generation dynamic model, which incorporates all the latest well information in a 3D geological model with a realistic fault representation of the structurally challenging slumps region at the eastern edge of the field.  Dynamic simulation has been invaluable for evaluation of complex processes such as the additional gas recovery generated by the EV wells, where classical techniques are difficult to apply.

Figure 5: Full Field Simulation Model

Progress

In the last three years, depressurisation has continued apace. The field reached a peak in gas production of some 1000 MMscf/d during 2001 (Figure 6), and since then has entered decline mode. The reservoir development strategy now centres around managing this decline and sustaining the depressurisation process for as long as possible before finally depleting the remaining gas caps in the endgame.

In 2003 an incident on the Bravo platform led to two platforms being shut in for three months, and a third platform being shut in for a total of five months. During this time reservoir pressure was observed to stabilise and even start to rise in some areas of the field, giving evidence that aquifer influx is a powerful force countering the depressurisation process.

To maximise the recovery in the decline phase, two projects are important: The “Enhanced Voidage” ESP wells will continue to play a role in extracting additional liquids voidage to further drop the reservoir pressure and sustain lift in the crestal wells by reducing their liquid/gas ratio (LGR). Secondly, reduction of topsides pressure will enable gas wells to flow to a lower abandonment pressure for a given LGR.

Since the original field refurbishment in the 1990s, which dropped the topsides pressure from 75 bar to 30 bar on three out of the four platforms, the compressors on these platforms have been rewheeled to operate at 20 bar, and the Alpha platform has been tied back to benefit from Bravo’s lower operating pressure. The next stage in the lowering of topsides pressure is to replace the HP compressors with new high head units, designed to operate at a suction pressure as low as 8bar. This will take place in 2005/6 and give a substantial boost to ultimate recovery.

The track record of depressurisation to date has been good, with careful field management enabling successive increases of the gas nomination until the end of the plateau period. Delivering the planned depressurisation and recovery in the final stages remains a challenge against a backdrop of ageing facilities and wells, with associated issues such as sand, scale and well integrity.

Figure 6: Gas Production Compared with 1992 Plan

Conclusion

The world's largest offshore oil field depressurisation project is entering its final phase in the Brent field. The depressurisation process is well on track, is performing as initially planned and gas production has been higher than forecasted during the depressurisation design phase.