Profile improvement during CO_2 flooding in ultra-low permeability reservoirs

Gas flooding such as CO2 flooding may be effectively applied to ultra-low permeability reservoirs, but gas channeling is inevitable due to low viscosity and high mobility of gas and formation heterogeneity. In order to mitigate or prevent gas channeling, ethylenediamine is chosen for permeability profile control. The reaction mechanism of ethylenediamine with CO2, injection performance, swept volume, and enhanced oil recovery were systematically evaluated. The reaction product of ethylenediamine and CO2 was a white solid or a light yellow viscous liquid, which would mitigate or prevent gas channeling. Also, ethylenediamine could be easily injected into ultra-low permeability cores at high temperature with protective ethanol slugs. The core was swept by injection of 0.3 PV ethylenediamine. Oil displacement tests performed on heterogeneous models with closed fractures, oil recovery was significantly enhanced with injection of ethylenediamine. Experimental results showed that using ethylenediamine to plug high permeability layers would provide a new research idea for the gas injection in fractured, heterogeneous and ultra-low permeability reservoirs. This technology has the potential to be widely applied in oilfields.

Three-dimensional physical simulation and optimization of water injection of a multi-well fractured-vuggy unit

With complex fractured-vuggy heterogeneous structures, water has to be injected to facilitate oil pro- duction. However, the effect of different water injection modes on oil recovery varies. The limitation of existing numerical simulation methods in representing fractured- vuggy carbonate reservoirs makes numerical simulation difficult to characterize the fluid flow in these reservoirs. In this paper, based on a geological example unit in the Tahe Oilfield, a three-dimensional physical model was designed and constructed to simulate fluid flow in a fractured-vuggy reservoir according to similarity criteria. The model was validated by simulating a bottom water drive reservoir, and then subsequent water injection modes were optimized. These were continuous （constant rate）, intermittent, and pulsed injection of water. Experimental results reveal that due to the unbalanced formation pressure caused by pulsed water injection, the swept volume was expanded and consequently the highest oil recovery increment was achieved. Similar to continuous water injection, intermit- tent injection was influenced by factors including the connectivity of the fractured-vuggy reservoir, well depth, and the injection-production relationship, which led to a relative low oil recovery. This study may provide a constructive guide to field production and for the devel- opment of the commercial numerical models specialized for fractured-vuggy carbonate reservoirs.

Surface wettability control of reservoir rocks by brine

Based on adhesion models between rock surface groups and organic molecules,the interactions between the chemical groups on the rock surface and the components of crude oil and the interactions of the electrical double layers at the rock surface and oil-water interface were analyzed to investigate the abilities and microscopic mechanisms of wettability control by H^+,OH^- and inorganic salt ions in brine,and a new method of wettability control for reservoir rocks was built.The results show that the interaction forces between rock surface groups and oil molecules are van der Waals forces,Coulomb forces,hydrogen bonds,and surface forces.By changing these forces,the control mechanisms of surface wettability of reservoir rocks by brine are:transformation of chemical groups,change of interfacial potential,pH variation of injected water,multicomponent ionic exchange,and salting-in or salting-out effect.For sandstone reservoirs,with the decrease of concentration and valence state of positive ions in brine or the increase of pH(increasing pH has a negligible impact on the brine salinity),the interaction between rock surface and oil becomes weak,thus resulting in increase of water wettability of rock surface.For carbonate reservoirs,CaSO_4 or MgSO_4 brine with high concentration is beneficial to increase water wettability of rock surface.Therefore,it is feasible to control rock wettability and improve oil recovery by adjusting the ion components of injected water.

Experimental investigation on continuous N_(2) injection to improve light oil recovery in multi-wells fractured-cavity unit

The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N_(2) injection in a multi-well fractured-cavity reservoir.In this study,the similar criterion of physical simulation was firstly discussed.In order to reveal the mechanism of remaining oil startup and production performance characteristic by continuous N_(2) injection,a visualized twodimensional fractured-cavity model and a three-dimensional pressure resistant model were designed and fabricated respectively based on the similar theory.And the 2D visualized physical experiments and 3D physical experiments were performed with the simulated oil and brine reservoir samples in Tahe oilfield.Four groups of experiments in 2D and 3D model were performed,each of which included bottom water depletion driving,water injection and N_(2) injection.The 2D visualized experiments indicated the main mechanism of N_(2) developing remaining oil was to occupy the high position and replace the attic oil due to gravitational differentiation.Furthermore,both the 2D and 3D experiments demonstrated that higher oil recovery factor could be achieved if N_(2) was injected through high positional wells.The 3D physical model is closer to the real reservoir condition,so the production performance can reflect the real field production process.This paper confirmed the efficiency of continuous N2 flooding in the light oil saturated fractured-cavity reservoir.

On the application of artificial bee colony (ABC) algorithm for optimization of well placements in fractured reservoirs;efficiency comparison with the particle swarm optimization (PSO) methodology

The application of a recent optimization technique,the artificial bee colony(ABC),was investigated in the context of finding the optimal well locations.The ABC performance was compared with the corresponding results from the particle swarm optimization(PSO)algorithm,under essentially similar conditions.Treatment of out-of-boundary solution vectors was accomplished via the Periodic boundary condition(PBC),which presumably accelerates convergence towards the global optimum.Stochastic searches were initiated from several random staring points,to minimize starting-point dependency in the established results.The optimizations were aimed at maximizing the Net Present Value(NPV)objective function over the considered oilfield production durations.To deal with the issue of reservoir heterogeneity,random permeability was applied via normal/uniform distribution functions.In addition,the issue of increased number of optimization parameters was address,by considering scenarios with multiple injector and producer wells,and cases with deviated wells in a real reservoir model.The typical results prove ABC to excel PSO(in the cases studied)after relatively short optimization cycles,indicating the great premise of ABC methodology to be used for well-optimization purposes.