Masalmeh, Shehadeh K. (Shell Technology Oman) | Blom, Carl P.A. (Shell Intl E&P) | Vermolen, Esther C.M. (Shell International Ltd.) | Bychkov, Andrey (Shell International Ltd.) | Wassing, L. Bart M. (Shell Intl E&P Co)
A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100.
The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs.
Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process.
Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study.
In the past few years, we have been working on understanding waterflooding performance in heterogeneous oil-wet carbonate reservoirs (Masalmeh et. el., 2004, 2007b, 2008) with a focus on the impact of geological heterogeneity, imbibition capillary pressure and relative permeability models. In these earlier publications we have focused on parameters affecting cross flow between reservoir layers and hence sweep efficiency and field-wide remaining oil saturation distribution.
Brooks, David (Shell Intl. E&P Co.) | De Zwart, Albert Hendrik (Shell Intl. E&P Co.) | Bychkov, Andrey (Shell) | Azri, Nasser (Shell International EP) | Hern, Carolinne (Shell) | Al Ajmi, Widad (Petroleum Development Oman) | Mukmin, Mukmin (Petroleum Development Oman)
Conventional displacement methods such as waterflooding do not work effectively in densely fractured reservoirs. The high fracture permeability prevents significant pressure differentials across oil bearing matrix blocks leading to negligible oil drive. In such reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix rock. In Middle East fractured carbonates, the matrix rock is commonly oil-wet or mixed wet and only gravity drainage remains a feasible process. However, permeabilities are usually low, <10 mD, resulting in low gravity drainage production rates with high remaining oil saturation and/or capillary holdup.
Thermal EOR methods have the potential to improve the gas oil gravity drainage (GOGD) rate and ultimate recovery. For shallow fractured reservoirs, it is feasible to inject steam into the fracture system, in the process known as Thermally Assisted GOGD (TAGOGD). Steam will condense as it contacts cooler matrix rock, resulting in a steam front that develops in a stable way through the fractures. Conductive heating of the matrix will result in oil expansion, viscosity reduction, solution gas drive and stripping effects. No viscous pressures are building up, and steam drive does not occur. For reservoirs containing viscous oil, the viscosity reduction effects are most important. When steam is injected in light oil reservoirs, solution gas drive and stripping effects potentially become dominant.
In this paper we analyse the effect of the different recovery mechanisms. We discuss the results of stack simulations for light oils and for a range of fracture spacings with reference to our previous results on viscous oils. We compare single-porosity simulations of a fracture-matrix stack system with dual-permeability simulations. The dual-permeability modeling requires special techniques to capture transient effects.