Tertiary Miscible Gas Injection (MGI) in the Alwyn North Brent Reservoirs

Lucy Burns (lucy.burns@tfeeuk.co.uk) Reservoir Engineer with TotalFinaElf Exploration UK PLC discusses the design, implementation and early results from a tertiary hydrocarbon gas injection scheme in Alwyn North.

Introduction

The Alwyn North complex is located in Block 3/9a of the Northern North Sea, UK sector. The Alwyn North Area consists of three main reservoir units, Brent, Statfjord and Triassic. The reservoirs are tilted fault blocks, tilting to the west. The Brent comprises of a sequence of sands/silts and shales deposited in deltaic and shoreface environments compartmentalised by two principal fault trends (Figure 1). In Alwyn North Brent it is the Tarbert (massive sand underlain by poorer quality channel sands) and Ness channel sands that are within the oil bearing leg, representing an oil column of just over 100m. The Brent oil composition and OWC varies between the panels, an undersaturated oil in Brent East (39°API) progressively getting lighter in Brent West, with a volatile oil encountered in Brent South West.

Production commenced in 1987 from the Middle Jurassic Brent Group, and was supported by water injection from early 1988. The MGI project was sanctioned in 1997 with incremental reserves for three panels, estimated at 33 million boe. This figure includes a waterflood phase post MGI and field depressurisation, and was evaluated against a continued waterflood scenario. Depressurisation after waterflood, even with artificial lift was not attractive.

Figure 1: Alwyn North Brent map (click image for larger view)

A downdip gas injection strategy is employed for the MGI project with cumulative planned injection of 4.5Gsm³. Gas injection in each panel is to be followed by water injection until field depressurisation to produce the injected gas. Pressure maintenance is critical with Minimum Miscibility Pressure (MMP) ranging from 375bar for BE to 330-350bar for BW. Currently, and throughout the MGI project to date, the field pressure in the MGI panels is just above MMP. To help avoid premature gas cycling the high permeability massive Tarbert 3 sands were isolated in the main part of the BE panel. This should allow better sweep into the lower Tarbert and Ness channel sands and allow a gas bank to form in the Tarbert 3 improving the sweep where gravity override is a concern. The Tarbert 3 in BE will be re-perforated after the gas injection project has finished. The Tarbert 3 was kept open in BW as it is the main producing zone as the OWC is stratigraphically higher up the sequence relative to BE.

Intensive reservoir monitoring (permanent downhole gauges, wellhead pressure and temperature data, tracers, production logging, fluid sampling and regular well tests) has been carried out to ensure that MMP is maintained and to identify performance changes and to react quickly to them. This has been fundamental to improving the understanding of field performance. The information has been regularly integrated into full field geological and compositional simulation models to optimise the near term performance of the panels and to plan the future strategy.  

Gas injection commenced in late 1999. The early part of the project was interrupted by facilities difficulties; however, by end 2002 1.9 Gsm³ of gas had been injected. This represents 73% efficiency compared to planned injection.

In the three years since first injection, incremental oil has been observed in four wells showing between a two to ten fold increase in oil potential. Associated gas breakthroughs have been experienced in two of these wells and can be related to zones of high permeability. The first gas breakthrough was earlier than expected through a high permeability Ness channel sand to the BE-S producer, N10, located ~0.75 km from the injector N9. This occurred only six months into the project. By one and a half years into the project incremental oil was detected at three other wells (Figure 2 shows an example of change in oil potential in well N36). Associated with this has been a 5-10% reduction in water cut in each of the wells. With the exception of the first gas breakthrough the results have been as prognosed.

Figure 2: Well N36: Oil potential normalised to 40 bar WHFP (Click image for larger view)

A positive correlation has been noted between the gas injection rate and the oil production potential and by three years into the project around 1.7 million bbl of incremental oil had been recovered. This was calculated by plotting the voidage constrained well potential against decline curves. Good reservoir management ensuring voidage replacement is maintained, is key to the success of this project with average reservoir pressures only marginally higher than MMP. To date (January 2003) 6% of the injected gas in Brent East has been backproduced suggesting good sweep and no apparent gas cycling problems. Well N10 which experienced the early gas breakthrough was shut-in to stop gas cycling problems.

The geological and reservoir models were re-built just prior to the start of gas injection in 1999. Detailed simulation studies have been carried out to optimise both the near term performance and the long term strategy, without having a detrimental impact on the ultimate recovery. For the near term other scenarios such as zonal gas injection (injecting in the lower zones for a period of time, then switching to the upper zones), conversion of selected producers to injectors to help with the voidage constraints and WAG (Water Alternate Gas) were examined. For the longer term the length of water injection phase after gas injection and the depressurisation timing were all examined and the model optimised to maximise reserves. WAG, although not initially encouraging during earlier studies, will be re-visited.

Microscopic and macroscopic mechanisms have been examined with the full field model. The macroscopic mechanisms encompass the vertical effects of gravity override in the massive Tarbert 3 sands (Figure 3) and the lateral effects such as gas conduit in the channel sands (Figure 4). The microscopic mechanisms have been examined on the cell scale with emphasis on the evolution of the phase saturations, particularly the residual oil saturation, and the evolution of the density of the different phases.

Figure 3: Reservoir model: Gravity override effects (Click image for larger view)

Figure 4: Reservoir model: Channelling effect (Click image for larger view)

The reservoir model has been used to respond quickly to changes in field performance and to anticipate likely changes in well behaviour. Use of the model as a tool for near term as well as long term performance of the field requires the model to be regularly updated. The latest full field models show that 30 million boe of incremental reserves could be recovered with 4.5Gsm³ of injected gas. This assumes that MGI is followed by water injection then field depressurisation (depressurisation currently planned for mid 2006 for BW and 2008 for BE). This is slightly less than the figure quoted at the time of sanction and the latest number represents more gas recovery and less oil recovery. This is a result of more geological heterogeneity, which has lead to poorer sweep (less recovery of residual oil), and a greater reliance on the depressurisation process. The timing of the depressurisation is seen to influence the oil versus gas recovery.

The first three years of gas injection have revealed some surprises and a lot of learning. Despite some deviations from the detailed scope of the original project, the incremental reserves are still expected to be similar to the estimate at the time of sanction thanks to the knowledge acquired during the early phase with a quick response to changes and continuous optimisation of the process.

More information on the project can be found in:

• Chaussumier, D., and Sakthikumar, S. 1997. “Alwyn North IOR Gas Injection Potential – A Case Study.” Society of Petroleum Engineers Middle East Oil Show, Bahrain, SPE paper 37755.
• L.J Burns et al., 2002. “Tertiary Miscible Gas Injection in the Alwyn North Brent Reservoirs”, Society of Petroleum Engineers Europec 2002 Conference, Aberdeen, SPE paper 78349.

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