Pilot Testing Issues of Chemical EOR in Large Fractured Carbonate Reservoirs
Many world class large carbonate reservoirs leave behind at least half of the initial oil in place. Typically water injection is used to improve oil recovery while gas injection is used to maintain pressure or to promote oil gravity drainage. Immiscible gas injection, including injection of CO2, has been considered but not implemented on a large scale for economic reasons. Furthermore, interest in using surfactants in large carbonate reservoirs has recently flourished. As a result, we began to investigate the viability of designing and conducting a manageable pilot test program in a large fractured carbonate reservoir using a single-well, dual-completion system to evaluate the efficacy of the surfactant oil mobilization and oil capture. However, pilot testing in large reservoirs is very expensive and requires a long time to complete. These issues are less problematic in pilot testing of small and thin reservoirs in onshore field. In this paper we will present the results of a conceptual model to simulate the performance of surfactant flooding in the above-mentioned pilot test configuration. Three different model formulations, having different approaches to gridding and grid-refinement, were used. These include conventional dual-porosity, dual-permeability, and single-porosity models with variable porosity and permeability to simulate fracture-matrix interactions. Simulation of pilot tests using dual-porosity models shows that gravity is most effective during waterflood but not as effective during the surfactant injection while in the dual-permeability models, the surfactant oil recovery is greater because both gravity and viscous displacement contribute. We will explain the reasons and will indicate which model is more reliable. In general the results of this study give an insight into the viability of using surfactant injection in thick carbonate reservoirs both in the pilot and production stage. Introduction In the U.S, typically about a third of the original oil in place (OOIP) is recovered by primary and secondary recovery processes, leaving two-thirds of the oil behind as remaining oil (NPC, 1984). About 60% of world‟s discovered oil reserves are in carbonate reservoirs, and many of these reservoirs are naturally fractured (Rohel and Choquette, 1985). According to a recent review of 100 fractured reservoirs (Allan and Sun, 2003), fractured carbonate reservoirs with high matrix porosity and low matrix permeability could be good candidates for enhanced oil recovery (EOR) processes. The oil recovery from these reservoirs is typically very low because about 80% of fractured carbonate reservoirs are either oil-wet or mixed-wet. Injected water will not penetrate easily into the oil-wet porous matrix to displace oil. Wettability of carbonate reservoirs probably is the most important oil recovery controlling parameter (Morrow and Mason, 2001; Tong et al., 2002; Hirasaki and Zhang, 2006). Typically water injection is used to improve oil recovery, while gas injection is used to maintain pressure or to promote oil gravity drainage as an IOR process. If gas injection is miscible or near-miscible, oil recovery is enhanced because a fraction of the conventional residual oil is mobilized by miscibility or near-miscibility conditions. Water and gas injection have been used to produce oil from the matrix in naturally fractured reservoirs (NFR) mainly by gravity drainage. Viscous displacement in fracture-dominated NFR generally plays a minor role except for chemical flooding, where surfactants might enter the matrix from fractures with assistance from viscous displacement to mobilize oil. Even this effect appears to be small because of the lack of deep surfactant penetration. In water-wet NFR, water imbibes strongly into the matrix and produces a lot of oil. However, in oil-wet reservoirs, water-flooding is relatively inefficient. This is characterized by the early water breakthrough and rapidly increasing water-oil ratio. The reason is that, for an oil-wet reservoir, the injected water tends to travel only through the fractures and not enter the
Low salinity polymer flooding: Lower polymer retention and improved injectivity
Abstract Delayed arrival of the oil bank and reduced injectivity are risks which are commonly associated with low salinity polymer (LSP) flooding. In this study, experimental work was carried out to address these risks; the polymer retention and the cationic exchange in the presence of polymer were the main subjects of investigation. Single phase coreflood experiments were performed, where low and high salinity polymer (HSP) solutions, i.e., conventional polymer flood using formation brine, were injected in reservoir core plugs. The performance of the two polymer solutions were analyzed for polymer retention, injectivity and polymer acceleration. Compared to the HSP coreflood, the LSP coreflood showed considerably lower polymer retention and better long-term injectivity. There was no delay in polymer breakthrough, and the polymer acceleration was comparable to HSP floods. Analysis of produced effluent of the LSP coreflood detected divalent ion concentrations higher than the injected solution, and the solution which was already in equilibrium with the rock. This suggested that the divalent ions were released from the rock into the solution because of cation exchange in the presence of the LSP solution. Such increase in divalent ion concentration increased the polymer solution salinity and resulted in a viscosity loss. The results of the experimental study indicated that LSP flooding can be an attractive alternative to conventional polymer flooding, although viscosity loss due to cation exchange is a subject for further de-risking work. A numerical model which couples the cation exchange in presence of polymer with flow dynamics in core scale has also been developed. The flow field was used to advect the polymer which influenced the equilibrium condition between the rock surface and the solution. We present preliminary results obtained using the model which can be used to gain insights and study sensitivities around different geochemistry coupled flow processes.
Slaughter Estate Unit Tertiary Miscible Gas Pilot Reservoir Description
A reservoir description for the Slaughter Estate Unit tertiary pilot and surrounding area and the procedure that we used to obtain it are discussed in this paper. The procedure is based on matching waterflood performance prior to pilot miscible gas injection with a black oil reservoir simulator. An initial estimate of the reservoir description is obtained from petrophysical data and single-well pressure transient tests. The initial estimate is then modified by a trial and error procedure until a good match between the actual and calculated waterflood performance is obtained. It was determined that the Slaughter Estate Unit tertiary pilot had an original oil in place (OOIP) of 642,400 STB (102 133 stock-tank m/sup 3/). A waterflood prediction derived from the reservoir description in this paper indicates that a primary-plus-secondary recovery through Sept. 30, 1983, of 49.6% OOIP would have been obtained from the pilot if waterflood operations had been continued. On the basis of this prediction, it was established that the tertiary oil recovery resulting from the miscible gas process was 18.5% OOIP as of Sept. 30, 1983.