Complexity arises when trying to maximize oil productions from fields using Electrical Submersible Pumps (ESP). The complexity increases with the increase in the number of reservoirs and wells in a particular field. I...Complexity arises when trying to maximize oil productions from fields using Electrical Submersible Pumps (ESP). The complexity increases with the increase in the number of reservoirs and wells in a particular field. Individual well’s ESP frequencies have to be constantly updated to ensure optimum oil productions from the field. The choice of the ESP frequency to be used must come from sound engineering decisions which do not come from mere intuition but must be backed up by mathematical models and computer simulations. This study proposes to evaluate field production network optimization on ESP lifted wells using quadratic sequential programming techniques. The optimization approach seeks to determine the ESP frequency for each well that will lead to the maximum field oil production while honouring the field operational constraints. Two reservoirs and five wells were considered. The non-linear optimization problem for the ESP lifted wells in the field was formulated with their boundary conditions. The simulations were performed in Prosper and GAP software. Prosper software was used in building the individual well’s ESP models for the five wells in the field. Individual well’s model in Prosper was exported to GAP and simulations were run in GAP for the field network system. GAP simulations were run in two cases: case 1 comprises ESP simulation without optimization while case 2 comprises ESP simulation with optimization. For case 1, fixed values of ESP frequency were selected for each well and the GAP software calculates the production rates from the wells in the network accruing from the ESP frequencies inputted. For case 2, there was no input ESP frequency as the GAP software was allowed to calculate based on optimization algorithms, the best suitable ESP frequencies for each well in the field that will lead to the maximum total oil production in the field network while honouring the operational constraint imposed on the systems in the field. From the results, it was realized that at the basis of well, the higher the ESP frequency, the higher the well’s production rates. Sensitivities on the effects of separator pressure on production rates show that separator pressures affect the well’s productions rates. A reduction in separator pressure from 200 psig to 80 psig led to a 1.69% increase in field oil rate. Comparison of results for case 1 and case 2 showed that ESP field network simulation with optimization yields had a higher field production rate than ESP field network simulations without optimization. There was an increase in oil rate of 1.16% and 2.66% for constraints 1 and 2 when ESP simulation was done with optimization rather than without optimization. Also, simulation with optimization comes with higher pump efficiency than simulation without optimization.展开更多
文摘Complexity arises when trying to maximize oil productions from fields using Electrical Submersible Pumps (ESP). The complexity increases with the increase in the number of reservoirs and wells in a particular field. Individual well’s ESP frequencies have to be constantly updated to ensure optimum oil productions from the field. The choice of the ESP frequency to be used must come from sound engineering decisions which do not come from mere intuition but must be backed up by mathematical models and computer simulations. This study proposes to evaluate field production network optimization on ESP lifted wells using quadratic sequential programming techniques. The optimization approach seeks to determine the ESP frequency for each well that will lead to the maximum field oil production while honouring the field operational constraints. Two reservoirs and five wells were considered. The non-linear optimization problem for the ESP lifted wells in the field was formulated with their boundary conditions. The simulations were performed in Prosper and GAP software. Prosper software was used in building the individual well’s ESP models for the five wells in the field. Individual well’s model in Prosper was exported to GAP and simulations were run in GAP for the field network system. GAP simulations were run in two cases: case 1 comprises ESP simulation without optimization while case 2 comprises ESP simulation with optimization. For case 1, fixed values of ESP frequency were selected for each well and the GAP software calculates the production rates from the wells in the network accruing from the ESP frequencies inputted. For case 2, there was no input ESP frequency as the GAP software was allowed to calculate based on optimization algorithms, the best suitable ESP frequencies for each well in the field that will lead to the maximum total oil production in the field network while honouring the operational constraint imposed on the systems in the field. From the results, it was realized that at the basis of well, the higher the ESP frequency, the higher the well’s production rates. Sensitivities on the effects of separator pressure on production rates show that separator pressures affect the well’s productions rates. A reduction in separator pressure from 200 psig to 80 psig led to a 1.69% increase in field oil rate. Comparison of results for case 1 and case 2 showed that ESP field network simulation with optimization yields had a higher field production rate than ESP field network simulations without optimization. There was an increase in oil rate of 1.16% and 2.66% for constraints 1 and 2 when ESP simulation was done with optimization rather than without optimization. Also, simulation with optimization comes with higher pump efficiency than simulation without optimization.
