Magnus Miscible WAG EOR Project

Magnus had long been considered as a technically ideal candidate for miscible gas injection. In 1998 a unique opportunity to implement EOR in Magnus using distress gas from the west of Shetlands was recognised. Following the successful negotiation of a supply agreement, the project went ahead in 2002. Phil Trussell ( Trussep@bp.com ), Reservoir Engineer working on Magnus at BP presents an overview of the field and the EOR project together with some of the latest results. The current partners in the Magnus field are BP (operator), Nippon Oil, Eni and Enterprise Oil.

Background

Magnus (located in blocks UKCS 211/12A and 211/7A) is the most northerly of the presently producing fields in the UKCS.

Discovered in 1974, the reservoir is an Upper Jurassic turbidite reservoir, comprising a high net to gross (0.8-0.9) upper reservoir (Magnus Sandstone Member - MSM) and a low net to gross (0.3-0.4) lower reservoir (Lower Kimmeridge Clay Formation - LKCF), both averaging approximately 100mTVT. STOIIP is in the order of 1500 MMstb with recoverable reserves (excluding EOR recovery) of 797 MMstb of 39o API light sweet crude. The MSM contains the majority of the STOIIP (1208 MMstb) and also has a higher expected recovery factor than the LKCF. Initial reservoir pressure was 6653 psia at datum depth of 3050mTVDSS with a bubble point pressure of 2600 psia (solution GOR of 725 scf/stb).

The field has a single steel jacket platform with 20 well slots, 14 of which are used for production wells and 6 for injection wells. Subsea wells have also been used over field life to provide additional well capacity. There are currently five active subsea water injection wells supporting Magnus field production.

The original field development plan was approved by the UK Department of Energy in 1978. The original plan was to waterflood the field, maintaining average reservoir pressure above bubble point to maximise recovery. Platform construction began in 1979; and first oil was produced in 1983 through pre-drilled subsea production wells. The first platform producer came on line in April 1984 and water injection commenced in July 1984. Production climbed rapidly to a plateau rate of 150 Mstb/d in 1985 and was sustained for 10 years. Since 1996 the field has been on decline associated with increasing water production. In late 2002 the field was producing around 50 Mstb/d oil at a water cut of 70%. Cumulative production in October 2002 was in the order of 750 MMstb of oil.

The EOR Opportunity

The opportunity to enhance oil recovery above the volume achievable through optimal waterflood has been reviewed at various times through field history. Multiple EOR schemes have been considered, including miscible and immiscible gas injection, polymer flooding, surfactant flooding, caustic flooding and microbial EOR. Miscible hydrocarbon gas injection was identified as the best option for EOR on Magnus reservoirs based on technical and commercial viability. By implementing EOR in a large part of the field additional reserves in the range of 30 MMstb to 90 MMstb are considered recoverable. This figure includes volumes associated with extension of field life as a result of the EOR project.

Despite the Magnus reservoir being considered technically an ideal candidate for EOR, previous studies had shown gas injection EOR to be uneconomic. The fundamental issue was sourcing a supply of suitable gas to provide sufficient injection volumes in the earlier stages of the project. Existing levels of associated gas produced by Magnus itself were insufficient and there was no readily available local gas accumulation that could be developed from the Magnus platform.

In 1998 a unique opportunity to implement EOR at Magnus was recognised. A number of fields had come on production to the west of the Shetland Isles. These fields had no commercial gas export route; produced gas was injected into disposal wells. The potential to use these fields as the supplier of gas was recognised and the successful negotiation of a supply agreement with the West of Shetlands field partners allowed the project to proceed.

The gas supply pipeline is routed via the Sullom Voe Terminal. This routing also enables gas to replace diesel as the fuel for terminal power generation, a substantial environmental benefit. The planned routing also provides the opportunity to purchase LPG to enrich the lean gas from West of Shetlands fields.

The Magnus EOR project thus includes supply fields west of Shetlands, the Sullom Voe terminal and the Magnus field itself.

In summary the benefits of the overall project are:

• Additional oil reserves at Magnus
• A commercial gas outlet for West of Shetlands fields
• Reduction in fuel costs at Sullom Voe Terminal
• Environmental benefits due to fuel change at Sullom Voe Terminal and reduced flaring West of Shetlands

It was this unique set of parameters and benefits which enabled the project to become a commercial reality.

EOR Project Scheme

Magnus oil has abundant light intermediate components. Injection of hydrocarbon gas leads, through a multi-contact process, to a vaporizing dominated miscible gas flood. Misciblility is achieved for a range of light injection gases at pressure below the average operating pressure for the field; miscible performance was confirmed by laboratory slimtube tests. In addition to the improvement in unit displacement efficiency due to miscibility, the injected gas also benefits recovery by sweeping oil from locations bypassed by the waterflood, such as oil below shales and in the attic areas of the field. The presence of bypassed oil has been indicated in openhole logs from sidetracked wells such as the one in the composite log shown in Figure 1.

Figure 1: Openhole Logs Showing Bypassed Oil

The Magnus EOR project was designed for a water alternating gas (WAG) flood, which helps reduce the injected gas mobility and increases volumetric sweep. In the Magnus scheme the gas is injected downdip to enable existing injection wells to be used where appropriate. A provisional ratio of 1:1 for reservoir volumes of gas and water is planned.

Incremental EOR reserves come from the following sources:

• lowering of residual oil saturation to waterflood
• accessing oil that is by-passed by waterflood
• improved pressure maintenance through better voidage replacement in low permeability, low connectivity areas of the field
• increased drawdown through natural gas lift of production wells
• extension of field life

Project Construction Scope

The project involved a large construction effort. The scope included facilities for gas supply from West of Shetlands fields, for gas transportation via Sullom Voe Terminal through to the Magnus platform and for gas injection at Magnus. The project was sanctioned in 2000 and completed in 2002. Figure 2 shows an outline of the fields and pipelines involved.

Figure 2: Schematic of Fields and Pipelines

At the West of Shetland fields, Foinaven and Schiehallion, modifications were required to deliver gas to the newly laid evacuation pipeline. Gas is taken for export from subsea tie-ins into the existing gas injection/lift systems; no changes were required to the gas compression facilities on the FPSOs.

A major investment for the project was the 400 km, 20 inch pipeline laid from WoS to Magnus via Sullom Voe Terminal. The pipe was laid in two sections - one from SVT to WoS, and one from SVT to Magnus. The pipe was continuously welded, and concrete coated for protection and negative buoyancy. At Sullom Voe Terminal facilities were added to take the pipeline to a new H2S treatment unit, and for provision of LPG injection from the existing storage tanks.

At Magnus itself a new gas riser and gas compressor was installed on the platform, six water injector wells have been or will be converted for water alternating gas injection service.

This substantial level of construction is reflected in a total cost of facilities in the order of $500 million.

Current Project Status

West of Shetland gas was first brought onto Magnus in summer 2002 and small volumes of gas were crossed over into the export line. Gas injection commenced into the reservoir in October 2002.

The planned gas injection programme was designed to cover the majority of the field area. All the six platform injection wells were to be worked over or sidetracked to allow them to be used for both gas and water service. Equipment rating of the current subsea injection wells means they cannot be used for gas injection.

Figure 3: Schematic Layout Showing Location of WAG Injection Wells

The planned scheme was to use sets of three wells for gas injection on two six-month cycles. The first wells on gas injection were to be M45:C5 a sidetracked MSM injector in the southern area of the field, M34:C3 an MSM injector in the central area, and M42Y:B3 in the MSM western extension. Second cycle wells were to be M48:C4 in the MSM central area, a sidetrack of M4:C2 in the MSM north and a sidetrack of M38:C6 in the LKCF.

The well preparation programme was begun in 2002. Well M45:C5 was drilled, M34:C3 worked over, and a tree replacement completed on M42Y:B3. Additional technical work resulted in a planned sidetrack of M4:C2 being reduced to a workover at the current location. This work also resulted in a decision to delay injection into the LKCF, deferring the sidetrack of the M38:C6 well.

In practice higher than anticipated injection rates have been achieved in all wells to date. Well M34:C3, the initial injection well, has recorded rates as high as 100 MMscf/d, compared to a forecasted 60 MMscf/d. This high injectivity has resulted in a decision to focus gas injection on four wells rather than six in the near term.

The first cycle was changed to the two wells M34:C3 and M48:C5, and lasted from October 2002 through to April 2003. In April, C3 and C5 were put back on water injection and M42Y:B3 and M38:C4 put onto gas injection. It is planned to work over M4:C2 later this year and sidetrack M38:C6 in 2004 or 2005.

Well M42Y:B3 is in a relatively isolated fault block with a single associated producer M47:A3. This area has been closely studied by the team and will be used as a test bed for EOR operations. The M47:A3 well is a sidetrack of M1Y:A3 away from the injection well. When M42Y:B3 was originally put onto water injection the M41Y:A3 well saw very early water breakthrough. The same rapid breakthrough of water occurred with the current M47:A3; switching M42Y:B3 to gas has reduced the watercut, and increased oil rate. There has been no breakthrough of gas in M42Y:B3 to date. Figure 4, for M47:A3, shows predicted waterflood performance versus well production tests and indicates the benefits achieved to date due to gas injection.

Figure 4: Well M47:A3 Performance

A response has been seen in other wells as well as M47:A3, notably M24:B4 and M39Z:B6, in these wells an increase in gross rate was noted with M48:C4 on gas injection without a discernable watercut reduction. The increase in rate is believed to be a result of improved pressure maintenance on gas injection and the improved sidetrack location.

With respect to the equipment installed for gas injection the compressor performance at Magnus has generally been excellent. There have been a number of issues typical of early operations, for example blockage of a suction strainer. To date compressor run time has been 83%, while 95% going forward appears to be achievable.

Associated with the start of EOR operations a number of additions have been made to surveillance activities. Injection logs have been run to assess gas injection profiles in M34:C3 and M45:C5 and are planned on M42Y:B3 and M48:C4. A programme of gas tracer injection jobs has begun with injection of tracers into M34:C3 and M45:C5. Pressurised samples are being taken from associated producers to provide the baseline for EOR recognition.

Future Success

The future success of the Magnus EOR scheme will require a high level of planning and integration of efforts both onshore and offshore for the Magnus team and the West of Shetland and Sullom Voe terminal teams.

One of the key factors that will contribute to success is maximising the volumes of gas injected and optimum placement of gas injectors. It may be necessary to sidetrack from the current bottomhole locations in order to optimise the sweep in the reservoir. To assist with decision making a rebuild of the current full field reservoir simulation model is in progress based on a fine scale geologic model developed from new seismic data acquired in 2001.

Other factors in the future success of the EOR scheme include a commitment to a high level of surveillance and constant monitoring of performance.

Disclaimer: The material available on this website is designed to provide general information only. Whilst every effort has been made to ensure that the information provided is accurate, it does not constitute legal or other professional advice.
Please note: The Department of Trade and Industry cannot be held responsible for the contents of any pages referenced by an external link.