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
Surfactant Based Enhanced Oil Recovery and Foam Mobility Control
Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactants makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. Also, the addition of an alkali such as sodium carbonate makes possible in situ generation of surfactant and significant reduction of surfactant adsorption. In addition to reduction of interfacial tension to ultra-low values, surfactants and alkali can be designed to alter wettability to enhance oil recovery. An alkaline surfactant process is designed to enhance spontaneous imbibition in fractured, oil-wet, carbonate formations. It is able to recover oil from dolomite core samples from which there was no oil recovery when placed in formation brine. Mobility control is essential for surfactant EOR. Foam is evaluted to improve the sweep efficiency of surfactant injected into fractured reservoirs. UTCHEM is a reservoir simulator specially designed for surfactant EOR. A dual-porosity version is demonstrated as a potential scale-up tool for fractured reservoirs.
Concentration of amino acids in wine after the end of fermentation by Saccharomyces cerevisiae strains
Both quantitative and qualitative differences in the utilization and release of assimilable nitrogen by two wine strains of Saccharomyces cerevisiae (cerevisiae and capensis) under different conditions of oxygen were observed. These differences were influenced by the presence of oxygen at the beginning of the fermentation, and by the strain of S cerevisiae. The release of some amino acids post-fermentation may be the result of reoxidation of NAD(P)H in order to maintain a normal redox balance. Copyright © 2003 Society of Chemical Industry