Summary
Relative permeabilities are fundamental to any assessment of reserves and reservoir management. When measurements on core samples are available, however, they often predict initial water production that is not experienced by individual wells. For example, dry oil production occurs from portions of reservoirs where the local water saturation is relatively high, even though the relative permeability data would predict a water cut in the range of 30 to 60%. This lack of agreement means that effective reservoir management is hampered because it is difficult for simulation models to mimic the observed reservoir production without use of data that may bear little resemblance to measurements.
After a brief discussion of relative permeability, the focus of this paper is first 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 in the paper is to explore the reasons why the relative permeability data are so uncertain. The evidence points to the fact that oil emplacement and the subsequent geological history of the reservoirs have not been considered sufficiently in preparing core samples before making measurements. Greater reliance on drillstem and early production tests is, therefore, crucial for deriving reservoir relative permeabilities until laboratories are able to mimic oil emplacement within rock samples as experienced in the reservoir.
The main source of data is the abandoned UK North Sea reservoir Maureen (Block 16/29a). Inevitably, during the 36 years since discovery, some data have been misplaced. Nevertheless, sufficient data exist to highlight the potential need for a paradigm shift in understanding how relative permeabilities should be obtained for reservoir simulation.
Introduction
There are many examples of dry oil production from portions of reservoirs where the local water saturation is relatively high (Matthews 2004). On the occasions when relative permeability data are available, predictions of the expected water cut are not zero but typically in the range of 30 to 60%. A particular example is that of the abandoned UK North Sea reservoir Maureen (Cutts 1991). This lack of agreement means that effective reservoir management is hampered because it is difficult for simulation models to mimic the observed early reservoir production without use of data that may bear little resemblance to measurements.
The focus of this paper is first to examine the uncertainties in the data that are used for the predictions. The Maureen reservoir--its data were placed in the public domain for research and training purposes by Phillips after it was abandoned (Gringarten et al. 2000)--provides the main source of information. The data examined are viscosity, saturation, and relative permeability.
Having established which data are the most uncertain, the paper then includes a brief discussion of the transition zone and oil emplacement to understand the nature of the uncertainties in relative permeability measurements and, in particular, measurements of the irreducible water saturation. From this, a new avenue of research related to oil emplacement can be identified that, if pursued, may lead ultimately to better reservoir-management models.