Downhole Steam Generation for Green Heavy Oil Recovery

The ultimate target of heavy oil recovery is to enhance oil mobility by transferring steam's thermal energy to the oil phase, incrementing its temperature, and reducing heavy oil's viscosity. While the various types of steam floods such as Cyclic Steam Injection (CSI) and Steam-Assisted Gravity Drainage (SAGD) are widely used worldwide, they have certain limitations that need further improvements. Notably, in surface steam generation systems, downhole steam quality is around 70% which means that 30% of latent heat is lost while steam travels from the surface to the pre-determined downhole location. Downhole steam generation (DHSG) can be a viable alternative for the surface steam injection in which steam will be generated downhole instead of on the surface. The asserted method presents significant benefits such as preventing steam quality loss, decreasing the environmental effects, and enhancing the heavy oil recovery by co-injecting the flue gas products such as CO2, and consequently, the economic outcomes will be increased. In this research, a comprehensive techno-economic case study has been conducted on a heavy oil reservoir to evaluate the economic and technical advantages of DHSG compared to surface steam generation. Various technical expenses and revenues such as investment costs, operating costs, royalties, and taxes have been considered in a simulation model in MATLAB. This DHSG feasibility assessment has been performed using data of a heavy oil reserve currently under steam flood. Results showed that DHSG could increase up to 50% economic and technical interest than conventional steam injection projects. One of the outstanding benefits of DHSG is the reduction of heat loss. Since steam is produced in-situ, either downhole or in the reservoir, no waste of heat occurs. Typically, most heat losses happen on surface lines and wellbore during steam injection from the surface, which accounts for approximately 32%. Thus, this issue is excluded using the DHSG method. The results of the recent effort fit well into the current industry's requirements. DHSG can (1) increase the rate of heavy oil production, (2) decrease the extra expenses, and (3) dwindle the environmental side effects of CO2 emission of surface steam generation. Compared with conventional thermal methods, in DHSG, the steam to oil ratio remains constant with depth change while the desired steam quality can be achieved at any location. The asserted benefits can ultimately optimize the steam injection with a significant reduction in UTC, hence, improved profitability.

Semi-Analytical Method for Accurate Calculation of Well Injectivity During Hot Water Injection for Heavy Oil Recovery

Representation of wells in numerical simulation of petroleum reservoirs is a challenging task due to large difference in typical scales of grid blocks (tens to hundreds meters) and wells (~0.1 m), with high pressure and saturation gradients around wells. Although a variety of grid refinement techniques can be used for local simulations, they have limited application in field-scale problems due to huge model dimensions. Thus, auxiliary quasi-stationary local solutions (so-called inflow performance relations) are used to relate well flow rate with well and grid block pressures. These auxiliary solutions are strictly derived for linear cases and generalized to non-linear problems by using grid-block averaged values of fluid and reservoir properties. In the case of hot water injection for heavy oil recovery, this results in significant errors in well injectivity calculations due to large temperature and saturation gradients dynamically influencing viscosity and relative permeability distributions around the well. In this paper we propose a method which combines a semi-analytical solution of the hyperbolic Entov-Zazovsky problem for non-isothermal oil displacement with integration for pressure distribution taking into account nonlinear dependencies of fluid viscosities and relative permeabilities on temperature and saturations. Both constant injection rate and constant well pressure cases are considered. Example calculations demonstrate that the method helps to avoid underestimation of well injectivity in non-isothermal problems caused by grid-block averaging of fluid and reservoir properties in conventional inflow performance relations.