Feasible to define reservoir fluid flow under steady-state conditions?
If a well is drilled in a petroleum reservoir – that penetrates the entire thickness of the reservoir (pay-zone thickness), then, whether the influence of the oil production would extend radially outwards from the production well with time?
And, under such circumstances, whether the oil is produced 'entirely' from the 'elastic storage' within the reservoir? If so, then, since the produced oil must come from a reduction of storage within the reservoir, could steady-state flow ever exist (of course, transient flow can exist)?
On the other hand, if the change in ‘drawdown’ (piezometric surface after commencing production) remains significantly small (negligible) with time, then, the oil flow towards the production well can be considered to be under steady-state conditions. But, in such cases, would it remain feasible to ensure that the drawdown remains insignificant in a real field scenario?
During a field test, how do we ensure that the piezometric surface remains horizontal (or nearly so) over the drainage area of interest that will be influenced by the field test? If the well (that has been drilled) does not penetrate the entire thickness of the reservoir, then, obviously, oil flow may not remain horizontal. In such cases, won’t the streamlines become 'curvilinear' in the vicinity of production well?
If so, what would be the normal threshold length – from the production well, over which, this curvilinear profile would become a linear horizontal profile (so that Darcy’s law could be applied comfortably)?
When the oil removed from reservoir storage remains discharged @ a constant rate, then, can we also ensure that the stored oil from the reservoir gets released ‘instantaneously’; while, it also remains directly proportional to the rate of decline of pressure head (in a transient fluid flow condition)?
In a real field scenario, won’t there be a ‘time lag’ between the pressure decline and the release of the stored oil?
And also, generally, how long will a well take – for the well discharge to remain as a constant (following the pump getting adjusted itself to the changing head)?
Or,
Can it be ignored as the production time is very large?
Can we ensure both (a) drawdown differences with time remaining significant; and (b) hydraulic gradient varying with time – for a transient oil production – in a real field scenario?
How do we ensure in a real field scenario that the late-time production data remains not getting influenced by any input from adjacent reservoir compartment (leakage)?
Defining reservoir fluid flow under steady-state conditions is feasible, but it requires certain assumptions and conditions to be met. In a steady-state condition, the pressure distribution within the reservoir remains constant over time, and the production rate from the well remains constant as well. Under these assumptions, the flow of oil from the reservoir towards the production well would extend radially outwards from the well with time.
However, in reality, achieving true steady-state flow in petroleum reservoirs is difficult. As oil is produced from the reservoir, there is a reduction in the storage within the reservoir. This reduction in storage leads to a decline in pressure, which affects the flow behavior. Therefore, steady-state flow can only be approximated for short periods or if the drawdown (the change in pressure head) remains significantly small and negligible with time.
Ensuring that the drawdown remains insignificant in a real field scenario is challenging. Factors such as reservoir heterogeneity, fluid properties, and production rates can influence the drawdown. Engineers try to manage production rates and reservoir pressures to minimize drawdown, but it is not always possible to eliminate it entirely.
To ensure that the piezometric surface (pressure distribution) remains horizontal or nearly so over the drainage area of interest during a field test, careful management of production rates and reservoir pressure is necessary. This can involve adjusting production rates, using artificial lift techniques, and implementing reservoir management strategies to maintain pressure support.
If the well does not penetrate the entire thickness of the reservoir, the streamlines of oil flow near the wellbore may become curvilinear due to the influence of vertical pressure gradients. The transition from curvilinear to a linear horizontal profile, where Darcy's law can be comfortably applied, depends on the specific reservoir characteristics and fluid properties. There is no fixed threshold length, and it varies from case to case.
In a transient fluid flow condition, the release of stored oil from the reservoir may not be instantaneous. There can be a time lag between the decline in pressure and the release of oil due to various factors such as fluid compressibility, rock compressibility, and flow resistance within the reservoir. The rate of pressure decline is directly proportional to the rate of oil release, but the response may not be instantaneous.
The time it takes for a well to reach a constant discharge rate, following adjustments to the changing head, depends on several factors such as reservoir properties, wellbore conditions, and production system design. It can range from days to months. The production time being large does not necessarily imply that the discharge rate will remain constant. Transient effects can persist over extended periods, and production rates may continue to change over time.
In a real field scenario, it is challenging to ensure that late-time production data remains unaffected by inputs from adjacent reservoir compartments or leakage. Reservoir compartmentalization, fluid communication, and reservoir heterogeneity can influence the flow behavior and cause interference between different parts of the reservoir. Various techniques such as pressure transient analysis, tracer tests, and reservoir simulation are used to evaluate and mitigate the effects of compartmentalization and leakage, but it can still be a complex issue to address completely.
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