Abstract
Reservoir fluid estimation for exploration prospects can be random and of large uncertainties. Typically, the reservoir fluid estimation in a prospect can be derived from a geochemical basin model or seismic data interpretation with regional knowledge. An analog reservoir fluid sample will often be selected for reservoir fluid estimation. Such analog samples can come from a neighboring field at some distance. The best approach for accurate reservoir fluid estimation is based on the reservoir fluid data from nearby wells when available. This paper demonstrates that mud gas data from wells inside or near the exploration prospect provides a much-improved reservoir fluid estimation.
In our previous work, we developed novel methods to estimate reservoir fluid properties from advanced and standard mud gas data. This paper uses three field cases to illustrate how mud gas data can be translated into reliable reservoir fluid estimations for prospect evaluation for potential developments. We have standard mud gas data available for the three field cases. The first two cases are examples of gas and oil prospect evaluations based on legacy wells without reservoir fluid samples. The last example is a prospect evaluation of overburden for potential production.
For the first prospect, reservoir gas has been produced from high permeable formations for many years, and the field is in its late life. To extend the gas production, the low permeable formation with a large reserve becomes the new target for evaluation. Due to the poor quality of the target reservoir zone and the need to stimulate production, it is important to confirm the reservoir gas in the formation. The reservoir fluid estimation is crucial for the decision of an appraisal well and the potential development of the prospect. We utilized the mud gas data from the legacy well to improve the reservoir fluid estimation. The new reservoir fluid estimation is gas-prone with leaner gas than the reservoir gas under production. The second prospect locates an area with multiple oil fields but various oil qualities. The well from the prospect has no PVT samples, making the prospect evaluation highly uncertain. We used mud gas data to estimate the oil quality of the prospect and the reservoir oil gradient in the reservoir zones. The last prospect is the overburden of a large oil field. Due to the good experiences from near fields on production from overburden, the reservoir fluid estimation is required to distinguish if the reservoir fluids in the overburden are similar to those in reservoir zones or have an independent fluid system. We used mud gas data from a new production well crossing the overburden formation. The results show the reservoir fluids in the overburden are close to those in reservoir zones.
The new mud gas data method provides accurate reservoir fluid estimations for three prospect evaluations with significantly reduced uncertainty. The implementation of the new method for prospect evaluation has not been reported previously. Due to the wide availability of standard mud gas data, the new method can be broadly implemented for prospect evaluations and generates large business impacts.
