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.

This paper describes the successful execution of an inter-well field trial to test a novel reservoir-triggered polymer technology (the Polymer) which has been proven to mitigate two of the major operational and economic challenges facing polymer injection for enhanced oil recovery (EOR), particularly in the offshore environment. The challenges of shear degradation and reduced injectivity are overcome by delaying the development of viscosity until the Polymer is in the reservoir. The field trial was conducted in an onshore sandstone oil field in Texas. The 1,000 ppm Polymer solution was injected at rates of 500 to 900 bbl/d into a 10-ft interval of low water permeability (50-100 mD) under matrix conditions. To demonstrate development of its expected viscosity in the reservoir, the growing Polymer bank was sampled from an existing producer. Pressure Transient Analysis (PTA) was used to confirm the deep-reservoir behaviour of the Polymer. Field data demonstrates that the Polymer behaves as intended. The viscosity of the produced Polymer samples corresponds to the target viscosity as determined from surface activation of the Polymer at the same concentration. This confirms the shear-stability of the Polymer in its un-triggered form. In addition, the injection pressures were no greater than expected and significantly lower than the expected injection pressures, under matrix conditions, for an equivalent partially-hydrolysed polyacrylamide (HPAM). PTA indicates a bank of fluid of increased viscosity some distance from the injector, as designed.

Single-well chemical tracer tests (SWCTT) have proven to be a valuable technique for evaluating Enhanced Oil Recovery (EOR) responses in clastic reservoirs. Development of carbonate waterflood EOR technologies are relatively immature in comparison, but the use of SWCTT for providing evidential basis in the field promises to be quick and relatively inexpensive compared with inter-well trials. SWCTTs measure the remaining oil saturation (Sor) to waterflood at a 15-20 feet distance from the wellbore. The technique indirectly measures the Sor by analysing back-produced fluids for partitioning tracers in a well which is producing at 100% water cut. Completing the test pre- and post-EOR treatment quantifies the EOR benefit, at least in that near-well region. Laboratory studies suggest that the use of ionically designed waters for EOR in carbonate reservoirs is temperature sensitive. This makes the design of a single-well test complex as it is essential to understand the thermal behavior of the well and the near-wellbore reservoir during any sequence of SWCTTs. Commercial simulators were used to investigate the thermal characteristics of the well and the near-wellbore reservoir respectively. These simulation results were also benchmarked against a water injection trial in another analogous well. The results showed that to ensure the temperature in the near-well region is kept sufficiently high to trigger an EOR response, it is necessary to pre-heat the injection water to >100°C. This is a complex operation especially offshore where the technical and HSE considerations need to be integrated into a sufficiently-sized heating system where space may be limited. Artificial lifting of produced fluids from a well which is producing at 100% water is also problematic offshore. Benefits and drawbacks of various lift options will be reviewed. The effect that delays during the production phase can have on the quality of data from the SWCTT will be shown as well as the options considered to reduce the likelihood of such problems occurring. The need to test this EOR technique in a controlled manner places stringent requirements on the surface facilities to deliver a test within the design specification. The need for low salinity water injection led to the selection of an integrated water treatment system able to produce desalinated water on-demand. This paper is the first of a series of papers aimed at describing the development of an ionically designed waterflood EOR technology for a giant carbonate oil field.