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Forties CO2 EOR Evaluation Integrating Finite Difference and Streamline Simulation Techniques

Halil Turan

Roger Skinner

Peter Brand
CO2 List:
A CO2 Infrastructure for the North Sea
Future Paths of the European Power-Plant Infrastructure - A Newly Established Project with Emphasis on Carbon Sequestration
CO2 Flooding of UKCS Reservoirs
Forties CO2 EOR Evaluation Integrating Finite Difference and Streamline Simulation Techniques
UK Advanced Power Generation Technology Forum (APGTF) - CO2 Capture and Storage Mission to US and Canada - 27 October - 7 November 2002
 

Halil Turan (turinhi1@bp.com), Roger Skinner (skinnerr@bp.com) and Peter Brand (brandpj@bp.com) of BP in Aberdeen report the detailed reservoir engineering work undertaken to enumerate the additional technical reserves that could be recovered from Forties if a field-wide CO2 injection scheme were introduced in the field. For more information see SPE 78298 presented at EUROPEC 2002

Introduction

The waterflood in Forties is mature with a field average watercut of 80%. In 2000 the Appraise stage of this project concluded that a CO2 injection scheme could add at least 5% incremental recovery over what we would achieve from a water flood alone. This provides additional technical reserves and an extension of field life.

CO2 injection into Forties recovers oil in two main ways.

  • Being lighter than water the CO2 will sweep upper sections of the reservoir displacing any unswept attic oil.
  • CO2/oil mass transfer will occur with both oil evaporation into the CO2 and CO2 condensation into the oil (particularly as it is undersaturated). Continued mass transfer, largely evaporation, leads to the development of miscibility and the mobilisation of waterflood residual oil.
Reservoir Simulation Workflow

The full field EOR response would traditionally be calculated using the familiar Todd and Longstaff approach or a coarse full field compositional simulation. In this work a fine scale finite difference simulation (VIP) was coupled with a streamline full field upscaling methodology (Frontsim).

The upscaling methodology was developed in Plano by Arco and has been successfully applied to Prudhoe Bay and Kuparuk. It has the benefit of being fast and simple to use and capturing the "finite difference physics" through type curves (rate dependency and slug dependency recovery curves). A disadvantage of the tool is the uncertainty of scaling up the results from a single areal model (generally small) to full field. To reduce this uncertainty several recovery curves are generated corresponding to different areas of the reservoir. These curves are then used in the scale up tool to assess the uncertainty. Please contact the authors for further information about pros and cons of different techniques.

The following activities have been performed in the EOR project modelling:

  • Ensure that the fine scale 3-D mechanistic models are representative. This is achieved through checking that the model input is representative of the core data and by obtaining a ‘good match’ to the water flood history.
  • Run the fine scale models a number of times to predict EOR performance with different volumes and rates of CO2. Convert the results into ‘recovery curves’ for Frontsim scale up.
  • Tune the EOR scale up tool by comparing the fine scale mechanistic model to an equivalent 2D Frontsim model.
  • Use the tuned scale up tool to scale the results to the full field and generate production profiles


Figure 1: Reservoir simulation workflow (click image for larger view)

Results

Initially, a 40*5*76 (1km*0.5km) fine scale compositional simulation model was run to generate the first set of recovery curves. Figure 2 shows three EOR targets, attic, intermediate saturations and oil under shale. Figure 3 favourably compares the model permeability data with the core data.


Figure 2: Present day saturations (click image for larger view)


Figure 3: Model and core plugs cumulative permeability distribution (click image for larger view)

The full field CO2 injection scheme leads to ~150 MMstb and ~200 MMstb additional technical reserves for CO2 supplies of 100 MMscf/d and 200 MMscf/d respectively. Figure 4 shows the oil rate and cumulative volumes recovered.


Figure 4: Production profiles and reserves  (click image for larger view)

Reservoir Uncertainty Statement (RUS)

The results presented above were based on one set of recovery curves in which the following assumptions were made:

  • Trapped gas saturation value of 0.3
  • Gas relative permeability curve as supplied.
  • Injection of pure CO2 (i.e. no impurities)
  • An optimised perforation strategy
  • 1km spacing

A reservoir uncertainty study has been conducted to assess the above parameters. Figure 5 shows the sensitivity of each parameter (%) compared to the base case incremental reserves.


Figure 5: Reservoir uncertainty study (click for larger view)

Conclusions

The evaluation of Forties CO2 EOR has been made by integrating finite difference and streamline simulation techniques. The technique allows fast development of EOR models and optimisation of development plans with reasonably thorough incorporation of physics.

The incremental technical reserves are ~150 MMstb and ~200 MMstb for a CO2 supply of 100 MMscf/d and 200 MMscf/d respectively.

The results were found to be sensitive to the reservoir description, perforation strategy, trapped gas and methane dilution.

Acknowledgments

The authors would like to thank Robert Trythall for his effort in developing the geological model and Chris Macdonald for his help in deriving the poro-perm relationship used.
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