Successful Field Trial of a Novel, Reservoir-Triggered Polymer: Results, Interpretation and Simulation

Abstract

This paper describes the interpretation of a successful inter-well field trial of a novel reservoir-triggered polymer technology, making use of pressure transient analysis and numerical simulation. The polymer has been engineered to improve sweep in oil-bearing formations whilst reducing the impact of two of the key operational and economic challenges facing polymer enhanced oil recovery (EOR). The polymer employs a chemical strategy to render it resistant to shear during injection and in the high flux region at the sand face. In addition, the injection solution has a viscosity similar to that of water until triggered in the reservoir, which sustains injectivity. We demonstrate the use of laboratory kinetics, rheology data, high-resolution surveillance of the injector, and comprehensive analysis of produced fluids to constrain the simulation of the in-situ viscosification of this polymer. Numerical models using commercial and in-house R&D codes were calibrated to tracer effluent data, pressure fall-off tests, and injection pressures, to interpret the size and mobility of the polymer bank and its response to water injection. The field trial has qualified the polymer to be considered for deployment. A comprehensive surveillance programme and downhole sampling was used to successfully demonstrate that the polymer was protected from shear degradation upon injection and propagation, and it viscosified under flow at the designed location in the reservoir. Kinetic and rheology data from laboratory testing, combined with reservoir-scale simulations and field trial surveillance, enabled the reaction and adsorption characteristics of the polymer to be estimated. Simulations of the injection pressure demonstrate that this polymer has significantly better injectivity under matrix conditions than would be obtained with a conventional polymer of an equivalent deep-reservoir viscosity.

Evaluating Factors Impacting Polymer Flooding in Hydrocarbon Reservoirs: Laboratory and Field-Scale Applications

“…This corresponds to an increase in the fluid’s permeability and/or a decrease in its viscosity. Therefore, it is always preferable to increase the mobility of oil to increase the overall recovery [ 36 ].…”

“…A common method to compare the two mobility values is the use of the mobility ratio. This is defined as the ratio between the mobility of the displacing phase and that of the displaced phase [ 33 , 34 , 35 , 36 , 37 , 38 , 39 , 40 ]. In all secondary and tertiary recovery applications, the displaced phase is the oil, whereas the displacing phase is the injected fluid that is being used to displace the oil.…”

“…First, it has a low viscosity value, which is comparable to or sometimes even less than that of oil. This can result in the water having a lower resistance to flow compared to oil, which, in turn, creates channels through the oil zone—a phenomenon referred to as viscous fingering [ 18 , 19 , 20 , 21 , 22 , 23 , 24 , 25 , 26 , 27 , 28 , 29 , 30 , 31 , 32 , 33 , 34 , 35 , 36 , 37 , 38 , 39 , 40 , 41 ]. Secondly, depending on the water saturation and the wettability, the water can have a higher permeability than the oil.…”

“…Li [ 35 ] modeled fluid–particle interactions using computational fluid dynamics and the discrete element method in order to predict polymer injectivity in porous media while taking into consideration fluid-induced fractures, water quality, and polymer rheology. Rashid [ 36 ] conducted a simulation study of a novel model using data from laboratory kinetics, rheology data, high resolution surveillance of the injector, and a comprehensive analysis of the produced fluid. Anand [ 37 ] evaluated the use of water-alternating polymer to enhance polymer pattern performance and optimize polymer utilization through reservoir simulation.…”

Assessment of Polymer-Induced Formation Damage Using Microfluidics

“…The results from a biopolymer injection pilot test in Germany also showed a decrease in injectivity with time, which was attributed to sand-face plugging (Behr & Rafiee, 2017). Complex functional polymers have been used recently for an inter-well field trial showing good injectivity behavior since the injection viscosity is similar to that of water (Rashid et al, 2018). The increase in injection pressure showed to be beneficial in inducing fractures in the near-wellbore region, which translates into a higher effective wellbore area that allows for an improved injectivity profile (Song et al, 2018).…”