Evaluation and Optimisation of Relative Permeability Modifiers for Water Control in Mature Wells

Abstract

Water production from oil and gas wells increases lift costs and produces production problems such as effluent discharge limits, separation difficulties, fouling and corrosion. This is becoming more of a challenge in these times where the Carbon footprint of new oil and gas installations is under tighter environmental scrutiny. Therefore, prolonging the life of existing wells in an environmentally friendly and economic way is becoming increasingly important. As water production increases the profitability of a well typically decreases due to the costs incurred in dealing with the problems mentioned above. While several engineering solutions for curbing excessive water production exist, the cost of such solutions typically outweigh the benefits, hence favouring the use of chemicals. For chemicals to be successful, case by case evaluation is required. This paper examines the successful screening and evaluation of relative permeability modifiers for water control in the field. Two relative permeability modifier chemicals (RPM A and RPM B) were selected for evaluation under simulated reservoir conditions. Prior to core flood testing, both chemicals were examined for stability and compatibility with formation fluids. While RPM B showed some signs of instability, ultimately, both chemicals were assessed under simulated reservoir conditions using core flood testing apparatus. A series of core flood tests were conducted to examine the effectiveness and any formation damage of both relative permeability modifier chemistries at various concentrations under different saturation conditions. The RPM was applied into a brine saturated core – to assess its water "shut-off" properties and into an oil saturated core – to assess its formation damage potential. The effectiveness was assessed from comparing recovery permeability to water and oil. The data presented in this paper suggest that RPM B did not reduce the permeability to brine after application under the conditions and concentrations examined. RPM A on the other hand showed a clear potential to impair water permeability upon application, causing a dramatic rise in differential pressure and reduced brine permeability. At a concentration of ~ 5% for RPM A, the flow of brine was completely shut-off when applied to a water saturated core at residual oil and when applied to an oil saturated core at Swr, although the permeability to oil is reduced, oil production was still achievable. Reducing the concentration of the RPM A to 1% resulted in less shut-off than at 5%, indicating that the level of water control in the field can be optimised by altering the products concentration. This laboratory work indicates the effect of the chemicals on core samples, it does not address the placement of the chemicals in the field. This is critical to success once a suitably performing chemical has been identified in the laboratory. Placement design and suitability of treatment should therefore be considered for each individual well location, the placement method may be bull head, coiled tubing, or straddle packer, depending on location and proximity to other oil producing zones. For example, it would not be useful in a zone producing oil and brine at different locations as once placed at the brine location area the oil /water ratio may increase for a short period, but water will find a way around the shut off location and again enter production. This paper highlights potential for reduced water production in the field when using relative permeability modifiers. Further highlighted is the utility of well-designed laboratory core tests for selection and optimization of relative permeability modifiers for field application. This work shows that with careful selection and optimization, problematic water producing zones can be treated with chemicals like those examined in this paper thus improving overall well productivity.