Excessive water production impacts the economics of petroleum reservoir and often leads to their premature shut-in. Production of high saline water represents a major corrosion for casing, tubing, flow lines, and production facilities. Polymer solution has been used to control water production and to plug in high-temperature reservoirs. Most of these polymer solutions consist of polyacrylamide-based polymer and an organic or inorganic cross linker. Polyethylene mine has been used as an organic cross-linked for polyacrylamide. Literature reported that polyethylene mine can also form ringing gels with polyacrylamide copolymers in addition to polyacrylamide concentration. In this study, nano-chemical solutions has been prepared and studied in detail for their efficacy at reservoir condition. The compositions of the nano-chemicals mainly consisted of polyacrylamide mixed with nano particles, cement, coated-clay and polyethylene mine as cross-linker. The aim of using nano particles and coated-clay was to control gel performance and strength under the reservoir condition. Moreover, the effect of nano-chemical composition at higher temperature have been studied extensively on the gelation properties, elastic modulus, viscosity, and swelling ratio. Results showed that the elastic modulus and viscosity improve significantly with the increasing nano particle concentration. Coated-clay can control the gelation time as clay swallows and absorbs more formation water in the target zone, when its thin coated film breaks down, lesser water production can be predicted.

As a reservoir reaches depletion stage there will still be a varying amount of residual oil saturation in the reservoir pore volume that is too heavy to be moved and produced. This undesirable phenomenon occurs due to adverse mobility and/or viscosity ratio between displacing phase (water) and displaced phase (residual oil). A solution to that is polymer injection which has been considered as one of the most effective and successful method to improve oil recovery. Moreover polymer flooding also showed limited success when applied in heterogeneous reservoir. This is because single polymer injection cannot sweep entire porous media efficiently, therefore in this research work the effectiveness of sequential polymer injection is studied and compared with conventional single polymer injection. The reservoir property model was developed from the available well data of an example field using stochastic approach. From the base case two more property models were developed to cover the heterogeneity from slightly to very heterogeneous reservoir rock. The degree of heterogeneity was obtained for each property model using DykstraParson technique. The magnitude of Dykstra-Parson coefficient for Slightly, Moderate and Very heterogeneous were 0.24, 0.59 and 0.69, respectively. Our results indicated that injecting polymers sequentially with varying in concentrations is an effective technique for enhanced oil recovery in heterogeneous reservoir rock.

This paper presents the results of laboratory investigation conducted with reservoir rock plugs recovered from the Gas reservoir in the North West Shelf of Western Australia. The experiments were conducted in reservoir conditions (High Pressure (HP = 41.37 MPa) and High Temperature (HT = 433.15 K)). The aim of this study was to determine residual gas saturation and quantify the effect of reservoir conditions (HP/HT) on gas-brine relative permeability. The experimental data have been analysed using relative permeability concept. Both wetting and nonwetting phase relative permeability were generated using explicit methods, i.e, Hasslar and Corey model (Power Model). The power model is then used to match experimental data through modifying the parameters of the Corey correlation. Several core plugs were used by this study representing different reservoir quality rocks in the reservoir. The core plugs were in different dimensions, the short core plugs measured around 5 cm in length while the long core plug measured 19.41 cm. The aim of using longer core plugs was to minimise the effect of capillarity and end-effects on the relative permeability measurements. Since permeability measurement under the test conditions depends on pressure drop across the core plugs.