R.W. Paige, L.R. Murray, J.P. Martins,* and S.M. Marsh, BP Exploration Op. Co. Ltd.; BP Exploration (Alaska) Inc.
In recent years, major advances have been made in understanding injection well performance. In particular, the impact of fracturing, thermal stress effects and water quality are far better understood, as a result of both improved theoretical understanding and from detailed analyses of field data.
This paper reviews our current understanding of the processes which control the performance of injection wells, including the effects of produced water quality, taking examples mainly from the Prudhoe Bay and Forties oil fields. Techniques for predicting and optimising injector performance under a variety of circumstances are discussed, together with the implications for waterflood management.
It is clear that water is injected at above fracturing pressures in a large proportion of injection wells. This may occur deliberately, or inadvertently, particularly in circumstances where the reservoir stresses have been substantially reduced by thermal stress effects associated with injecting water that is colder than the reservoir.
The primary advantages of injection at above fracturing pressures are dramatically improved injectivities (highly negative skins may be achieved) and a fundamentally greater tolerance to poor water quality.
The potential disadvantages of fractured injectors relate to fracture growth, both laterally and vertically. Where the fracture lengths approach the inter-well spacings, sweep efficiency may be adversely impacted, depending on the well configuration. Where water is injected into an interval at an excessive rate for that formation, unwanted fracture height growth may result in water being injected into other zones, possibly to the detriment of the main waterflood. Maximising oil production and recovery from waterflooded oil fields requires that the desired volumes of water are injected into the appropriate regions of the reservoirs in a cost efficient manner.
Two oil fields are used to provide the majority of the observations given in this paper: Prudhoe Bay and Forties. The main Prudhoe Bay field is a sandstone reservoir located at a depth of Ca. 8800ft on the North Slope of Alaska. Recoverable reserves are estimated at about 12 billion barrels, of which 8 billion have been produced to date. In contrast, the North Sea Forties field is a poorly consolidated sandstone reservoir at a depth of about 7000ft. 90% of the estimated 2.5 billion barrels of reserves have been produced.
A formation can be fractured either by purely hydraulic means, as in conventional hydraulic fracturing, or by a combination of applied pressure and thermal in-situ stress reduction.
During water injection, cold water may be injected into a warm reservoir. This establishes a zone of reduced temperature around the well, principally due to convection. The reduction in reservoir temperature causes a decrease in rock stress which is proportional to the rock's elastic modulus. For consolidated sandstones, this stress reduction is typically in the range 10 to 15 psi/ F [0.13 to 0.2 MPa/ C]. The reduction in stress may be sufficiently high that fractures are formed. In most oil reservoirs, the minimum stress component acts horizontally, so the fractures are vertical.
An example of the impact of injection water temperature is shown in Figure 1, which indicates the change in bottomhole temperature and pressure measured during the start-up of a North Sea injector. The well was deliberately fractured initially.