Oil & Gas - Maximising Recovery Programme (formerly SHARP) IOR Views

Background

The issue of production below the bubble point is of increasing importance in the UKCS as smaller fields are being developed which may not warrant water injection and mature fields are approaching COP, when operators may wish to reduce operating costs.  This study updates a previous study performed by Maggie Thompson in 1996 (Reference 1)

Production below the bubble point generally refers to a field process where the pressure is lowered with the intention of increasing the oil rate. Production below the bubble point locally around a well gives the benefit of increased pressure drawdown. If the region below the bubble point is maintained within the Gas Production Envelope (GPE) around the well (within which horizontal transit times for gas exceed vertical transit times) (Reference 2) then the risk of reservoir damage due to excessive gas production is low.  More extensive production below the bubble point can also have benefits in displacing oil from low permeability regions for instance and may be used where field economics do not warrant drilling injection wells. In this case high GORs may be produced.

Figure 1: Gas Production Envelope and Oil Isobars for a Horizontal Well

Review of UK Operations

The project investigated how operators have been producing below the bubble point, the success of monitoring techniques and how well fields have behaved compared with the GPE methodology. UKCS operators contributed data for 12 fields. Five fields were studied in detail.

Figure 2: Diagnostic Cumulative Gas v. Cumulative Oil Plot

In general diagnosis of potential problems has been made difficult due to poor levels of pressure and GOR monitoring in most fields with many of the pressure gauges in wells having failed.  Data uncertainties have also played a part it making it difficult to accurately use prediction methods.

Conclusions

The study concluded that in general local production below the bubble point appears to be working successfully. Serious reservoir damage, possibly due to gas blocking, in which the well was lost was observed in only one field. In one other field there was evidence of excess gas production and degassing of the oil over a short period. Both these fields produced with flowing bottom hole pressures of around 1500 psi below the bubble point, equivalent to a flowing bottom hole pressure of about 50% of the bubble point pressure. This compares with minimum flowing bottom hole pressures of around 75% - 80% of the bubble point pressure in most other fields. This suggests that in the absence of further evidence it would be wise to avoid producing with bottom holes pressures less than 75% of the bubble point pressure.

Figure 3: Diagnostic GOR v. Time Plot

PI reductions during production below the bubble point are quite common. The reasons are diverse including well bore collapse, scaling, asphaltenes and water blocking. Three phase relative permeability effects do not appear to be a large problem. 

Assessing the GPE methodology in the light of field experience it was concluded that the methodology may be too conservative if the region available to flow is significantly less than the formation thickness or horizontal well length. This can be corrected for if the length of the well contributing to flow is known and there is a good understanding of the number of compartments intersected by the well.

In heterogeneous fields, the GPE is calculated using average field properties. The methodology has been found to be of less use where there are lateral heterogeneities than in the presence of vertical heterogeneity.

References

1. Maggie A Thompson. “Decision Parameters for Below Bubble Point Production” Feb 1996.
2. M A Thompson, SG Goodyear, T Fishlock and P Jones. “Risk Management for Production below the Bubble Point” IOR 10th European Symposium. Aug 99.