FIELD MANAGEMENT PLAN (FMP)

The objective of the FMP is to manage and develop the individual reservoirs so as to maximise the economic ultimate recovery factor. To achieve this objective, this project will try to improve and maintain the overall company and working performance by following

‘Field development best practice’. Moreover, the environment will be conserved and protected during all the activities.

In order to ensure that the development plan will be successful, the plan will be updated and reviewed annually. Moreover, by using multidiscipline integration such as geology, reservoir simulation and well testing, the plan will be improved to ensure the optimum development. In addition, the flexibility of the development plan makes it prepared for further opportunities of new technology and development.

4.3.1. UNCERTAINTY MANAGEMENT.

The uncertainties for Z-field which are addressed by the Field Management plan are:

1. Reservoir heterogeneity

2. Faults and reservoir compartmentalisation 3. Deposition of the turbidites

4. Reservoir fluid properties 5. Size of the lower reservoir

4.3.1.1. Reservoir Heterogeneity

As it is mentioned previously, one of the reservoir main uncertainties lies in its vertical permeability: the core images display zones highly cemented by calcite. However, what is not known is the size of these zones: are they just boulders or are they spread out in large sheets (see figure G3 below)? The vertical permeability will be highly affected by these zones and by their layout: normal vertical permeability if the cemented zones are boulders, small one if

the cemented zones are continuous sheets. Since the reservoir will be drained by two long deviated wells, the risk of early water breakthrough can be reduced by completing the wells in the crestal part of the reservoir (as shown in figure DVP1). In addition, the full shut-off of the branch or wells can be used if required.

Figure G3: Effects of cemented zones on vertical permeability

4.3.1.2. Faults and reservoir compartmentalisation

According to the seismic shot interpretation (and precision), it is possible to determine several faults within the reservoir. The smaller faults are almost impossible to detect with seismic because of the resolution scale. How the presence of faults in the reservoir will affect its quality in terms of permeability? Well testing results give us a more precise idea of their distance to the well. However, it does not give any clue on the size or the direction of these faults (see well testing section). In order to reduce this uncertainty, the producers and injectors are put in the center and West side of field instead of only at the edge of the oil water contact.

Thus, it can be ensured that the reservoir will have enough pressure support even if some faults are effectively present in the field.

4.3.1.3. Deposition of the turbidites

It is possible to infer the distribution of the different properties according to how the turbidite has been deposited. Furthermore, the distance from the source of deposition is an indication of the sorting of the rocks: bigger boulders will tend to stay near the source of

deposition whereas smaller grains (sand, silt, mud) will be distributed further. The uncertainty here is how it is possible to relate this sorting with the quality of the reservoir. Based on this uncertainty, the multidiscipline integration will be required such as well test and reservoir simulation, in order to select the most appropriate well position to achieve the ultimate recovery.

4.3.1.4. Reservoir fluid properties

As mentioned in the reservoir fluid section, the uncertainties of the fluid properties come from the heterogeneity of reservoir and lack of information. For example, the SCAL which showed the relative permeability and capillary pressure curves come from only one well which could not use correctly as representative for the whole reservoir. To reduce this uncertainty, more data from the other wells need to be gathered and analyzed. Moreover, the simulation model is required to update the fluid properties by data from the other wells and history matching.

4.3.1.5. Size of the lower reservoir

Well test analysis from well Z-7 (western part of the field) and log analysis indicated that there is the another reservoir situated below the main one at 10260-10400 ft (MD). From the DST analysis, there seems to be faults or no flow boundaries situated in a U-shape around well Z-7. This well has been test by DST and clearly showed a clean sand with higher permeability and porosity than the upper reservoir. However, the volume of oil in place could not be identified neither by well testing nor by geological structure map because of the lack of data. Regarding the above reason, it appeared to be difficult to consider the lower reservoir in the simulation model and it will be treated as the uncertainty. Therefore, it has been suggested that another well test should be conducted in this area (Z-7) to confirm the reservoir drainage area before development. Furthermore it would be suggested to drill the new wells deeper and

conduct the test to gain the information from this area. Reservoir fluid analysis showed that it would be possible to produce fluids from two zones at the same time as commingled which should increase the production rate of the field.

4.3.2. Workover, Re-entry and sidetrack potential

The main uncertainty in re-entering the old wells is the well path of the appraisal wells because the drilling surveying has not been conducted for all the appraisal wells. This may lead to drilling through the casing and thus going out of the track. Therefore, it is essential to monitor the ROP all the time during the drilling phase.

4.3.3. Artificial Lift

If the production performance of the Z-field indicates that there is no aquifer support or very small aquifer. It is possible to use the artificial lift i.e. gas lift or ESPs in the wells located within high PI area. After investigation, both gas lift and ESP were not required in the base case. Because water flooding can support the pressure in the reservoir and keep it above bubble point pressure. However, these artificial lift can be used to extend the production period when the field water cut exceeds 70% but this will have to be justified by economic evaluation.