Wells equipped with Electric Submersible Pumps (ESPs) are ubiquitous. Methodologies for either long-term (on the order of years) or short-term (months or weeks) well control are common in literature and practice. However, techniques for long-term management and optimization very often ignore devices such as ESPs in their modeling assumptions and procedures for short-term control that incorporate ESP analysis introduce important simplifications regarding fluid flow in the reservoir and well interaction. Lack of reconciliation between these long-term and short-term approaches frequently yields in practice undesired well responses and, in turn, inefficient field production.
In this paper we introduce a methodology that translates controls usually considered in long-term optimization and not directly implementable in ESPs (namely, well bottomhole pressure and rate) into others that are adjustable for these devices (pump frequency and valve aperture). Fluid-flow simulation is used for reservoir modeling and ESP analysis includes viscosity correction and coupling with fluid-flow equations. The methodology allows calibration of the underlying reservoir models so that long-term and short-term reconciliation is possible. Well-control man¬ agement relies on joint optimization of drilling location and control. Calibration is formulated as an optimization problem where the discrepancy between measurements and model output is minimized through changes in reservoir parameters.
The methodology is illustrated by means of a field-development and control problem constructed upon a synthetic reservoir model that has been matched with respect to 2,100 days of production. In this problem the drilling location of a new producer with an ESP and the corresponding controls for the next 1,080 days, a sequence of bottomhole pressure (BHP) values, are optimized jointly. The BHP values are then translated into ESP controls, i.e., pump frequency and valve aperture, for the following 60 days as a sequence of eight intervals, each with duration of around one week. When the ESP controls associated with the first of these intervals are simulated for the true model, the oil (water) rate at the new producer is only around 14% (40%) of the rate predicted by the matched model. Calibration of the matched model in the vicinity of the new producer results in equal rates for the true and calibrated models for the first interval. The discrepancy is relatively small for the second interval and is expected to decrease further if the (local) calibration process is repeated in future intervals.
Current practice for well-control management rarely integrates joint modeling of wells systems such as ESPs and of reservoir fluid-flow dynamics. This may originate unwanted inefficiencies and losses in profitability. The comprehensive methodology for well-control management and optimization presented here aims at alleviating these modeling issues and consequently at improving production. Although described only for ESPs, the methodology is general and can be extended to other production systems.