There are many examples of dry oil production from portions of reservoirs where the local water saturation is high. When relative permeability data are available, predictions of the expected water cut are not zero, but typically 30–60%. This lack of agreement means that reservoir management using simulation models is questionable because such models can only mimic the observed reservoir production using data that bear little resemblance to measurements.
The first focus of this paper is to examine the uncertainties in the data that are used for the predictions. This then provides a numerically structured approach to adjustments that need to be made to data so that history matching of simulation models can be achieved. The relative permeabilities, rather than saturations and fluid properties, are shown to be the least certain of the relevant data.
The second focus is to explore the reasons why the relative permeability data are so uncertain. The evidence points to the fact that oil emplacement and subsequent geological history of the reservoirs have not been considered sufficiently in preparing core samples and making measurements. Greater reliance on drill-stem and early production tests is therefore crucial for deriving reservoir relative permeabilities until laboratories are able to mimic, within rock samples, oil emplacement as experienced in the reservoir.
The main source of data is from the abandoned UK North Sea reservoir (Maureen, block 16/29a).
There are many examples of dry oil production from portions of reservoirs where the local water saturation is high1. When relative permeability data are available, predicted water cuts are not zero, but typically 30–60%. This lack of agreement means that effective reservoir management is questionable, because simulation models only reproduce the observed early reservoir production using data that may bear little resemblance to measurements.
The first focus of this paper is to examine the uncertainties in the data that are used for the predictions. The UK North Sea Maureen reservoir2 (block 16/29a) whose data were placed in the public domain for research and training purposes by Phillips after it was abandoned3, provides the main source of information. The data examined are viscosities, saturations and relative permeabilities.
Having established which of the data are the most uncertain, the paper then includes a brief discussion of the transition zone and oil emplacement, in order to understand the nature of the relative permeabilities that the reservoir reveals. Simplifying recommendations are then made.
Maureen is an anticlinal sandstone reservoir discovered in 1972 and appraised in 1974. Production from 1984 to 1999 yielded over 200 mmstb. The reservoir was then abandoned.
A map of the reservoir top structure, and positions of relevant wells2 are shown in Fig. 1. The oil is light and sweet. There was an extensive natural aquifer, although water injection was needed to supplement pressure support from the aquifer. Shales were present within the main body of the reservoir sandstone, but these did not correlate across the reservoir. The sandstone was judged to be slightly water-wet. (Amott-Harvey index 0.14.) Faulting was present, but had only a limited effect on pressure communication across the reservoir.
Dry oil production occurs in portions of many reservoirs even when the water saturations are high1. Three Maureen wells showed this behaviour (2X, A14 and A18).
Using electric logs, the oil-water contact (zero oil saturation) is 8682 feet sub-sea in well 2X (Fig. 2). Forty feet above this contact a drill-stem test (DST 5) was carried out over a two-foot interval, and dry oil was produced, apart from a trace of water. The local water saturation was 64 su. The section was clean sand.