Investigation of the Potential Application of Smart Wells in Compartmentalised Reservoirs

Graham Paterson (graham.paterson@ecltechnology.com) of ECL Technology Ltd (http://www.ecltechnology.com) summarises the results of a simulation study investigating the potential benefits of using smart wells in compartmentalised reservoirs.  The work was undertaken as part of the DTI's SHARP programme.  A more detailed account of the study can be obtained from the author.

Compartmentalisation is a major issue in many UKCS reservoirs. It is estimated that over 4000 MMstb of oil and over 12000 BCF gas reserves (associated, condensate and dry gas) could be apportioned to compartmentalised reservoirs. About 3500 MMstb oil and 6400 BCF gas have been produced to end 2001 leaving about 500 MMstb oil and 5600 BCF gas remaining under the current development plans.

The use of smart wells has been identified as a possible means of increasing oil reserves from compartmentalised reservoirs. This study involved the use of a simulation model to identify the circumstances in which the implementation of smart wells may be appropriate. The overall conclusion is that a smart well can increase reserves and bring forward oil production in certain circumstances.

A three-compartment Eclipse model has been set up with different permeabilities to represent isolated regions. An areal representation of the model is given in Figure 1. The model STOIIP is about 39 MMstb oil, with a STOIIP of about 8, 15 and16 MMstb in Regions 1 (mid permeability), 2 (low permeability) and 3 (high permeability) respectively. Two permeability scenarios were considered, one in which the permeabilities differed by a factor of two (using values of 50 mD, 100 mD and 200 mD) and another in which the permeabilities varied by an order of magnitude (using values of 10 mD, 100 mD and 1000 mD). A horizontal production well is included to represent a smart well and has completions in each compartment. A water injector is included to provide pressure support and the production well is controlled on liquid production rate (with a secondary bottom hole pressure control). It is worth noting that if wellbore hydraulics were modelled, the incremental oil recoveries could be greater, as a lower column density would be expected in cases where water production is minimised.

Cases were also considered in which water injection was increased to double the original rate. This can be thought of as a sensitivity representing a case with significant aquifer influx.

Figure 1: Areal representation of grid showing permeability regions (Click image for larger view)

Several scenarios were set up which essentially involved shutting in particular completions after water breakthrough (or when a pre-determined watercut limit is reached) mimicking a possible smart well operation. The results are compared with a base case in which the well is completed across the whole interval for all of the simulation period. In the cases described here, all of the well completions are open at the start of the simulation period. The worst offending completions (i.e. those in the highest permeability region) are shut-in when a particular watercut limit is reached. Once all the completions have been shut-in, the well is re-opened for the rest of the simulation. We have considered watercut limits of 0.1, 0.6, 0.7 and 0.8.

It was found that a smart well can increase reserves and bring forward oil production in compartmentalised reservoirs. This is particularly the case in circumstances where there is a large difference in permeability contrast between the various regions and water production is a potential problem. For example, in cases with a permeability contrast of two, there is an increase in reserves of up to 2% of model STOIIP (1 MMstb oil) over the base case (in our high water injection rate scenario with a 0.6 watercut limit prior to recompletion). In the equivalent case with a permeability contrast of ten, this increase can be up to 13% of model STOIIP (5 MMstb oil). Oil production can be brought forward by, for example, an incremental oil recovery of about 3.5% STOIIP at around 9 years in the case in which a 0.6 watercut limit is imposed (for a permeability contrast of two).

Typical oil production profiles are shown in Figures 2 and 3. Figure 2 shows an example of a case with a permeability contrast of two, in which production is balanced by water injection. Figure 3 shows a case in which a permeability contrast of ten is used with double the original water injection (to represent a case with an active aquifer).

Figure 2: Typical oil production profiles (permeability contrast of two) (Click image for larger view)

Figure 3: Typical oil production profiles (permeability contrast of ten, double water injection) (Click image for larger view)

It was also found that, unless a smart well is used, in cases with a large permeability contrast, the oil recovery from the low permeability region can be negligible (e.g. only 0.03% of region STOIIP in some cases). The recovery from the higher permeability region may be slightly reduced when the smart well is used, but this is more than compensated for by increased production from the low permeability region.

A simple economic analysis was also carried out and indicated that the incremental NPV for a smart well project can run into tens of millions of dollars. Most incremental NPVs were positive for the cases considered.

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