Globally large volumes of heavy oil are currently locked in shallow low permeability reservoirs. If they contain sufficient natural fractures then one of the most viable recovery processes is thermally assisted gas oil gravity drainage. In this process steam is injected into the fracture system from where it heats the oil in the matrix which reduces the oil viscosity and accelerates gravity drainage. The economic viability of this process is largely determined by the spacing of the fractures. Large blocks take longer to heat than small blocks, and the correct description and thermal simulation of these across the reservoir is critical to decision making.
Arriving at the appropriate reservoir description of the fractures for full field simulation modelling requires input of the geological matrix and fracture model scenarios, a spacing averaging method per grid block and the geometric shape factor term per grid block. Each of these contains its own uncertainties. The objective of this paper is to access each parameter and their impact on recovery.
For a given heterogeneous geological description, determination of the appropriate average spacing per simulation grid block is a non standard operation. A number of techniques have been assessed including arithmetic and square weighted averages. In addition a number of thermal shape factors used in dual permeability/porosity simulators are tested against single porosity results. Impact on recovery and produced fluid temperatures of the above parameters was investigated through multiple reservoir simulation models.
A history matching approach was proposed and used in matching a pilot steam injection scheme. This included matching the measured temperatures, oil rim position, and production data gathered during a pilot. Conclusions are made regarding the importance and relative impact of the fracture characterisation, fracture spacing averaging and shape factors on recovery.
In naturally fractured carbonate reservoirs, the matrix which contains most of the oil is surrounded by a system of fractures of very little volume but with permeabilities that are several orders of magnitude higher than that of the matrix. In such a reservoir it is difficult to apply any pressure differential to the oil in the matrix to cause the oil to flow out by a conventional displacement process between injectors and producers. The injected fluid simply flows through the fracture system bypassing the oil in the matrix. If however gas is introduced into the fracture system such that the gas-oil contact (GOC) in the fracture system is deeper than the GOC in the matrix, then a hydrostatic imbalance is created. The oil in the matrix above the fracture GOC is surrounded by gas and is forced to drain down wards by virtue of its higher density ultimately into the fracture oil rim much the same way as in a U tube. As the oil drains from the matrix it is replaced by gas and the oil collecting in the fracture system can then be produced. This process is called gas-oil gravity drainage (GOGD). From Darcy's law the drainage rate can be derived as 1,2,3
kv is the matrix vertical permeability, kro is the oil relative permeability in presence of gas in the matrix, A is the reservoir area, µo is the oil viscosity, is the gas-oil density difference, g is the acceleration due to gravity, pc is the gas-oil capillary pressure in the matrix and z is distance upwards.