Cyclic Solvent Injection Process for Heavy Oil Recovery a report by Jeannine Chang1 and John Ivory2 1. Devon Energy, Calgary; 2. Alberta Innovates – Technology Futures, Edmonton
Cold heavy oil production with sand (CHOPS) has been applied in vertical wells for many years in Cold Lake and Lloydminster heavy oil reservoirs (Alberta and Saskatchewan in Canada) to increase oil production rates. As a result of sand production, high permeability ‘wormholes’ are created that enhance oil production. When 5–10 % of the original oil in place has been recovered, CHOPS becomes uneconomical due to reservoir pressure depletion and/or water encroachment in the production well. Heavy oil production is expected to decrease significantly in Western Canada unless new technologies are developed as a follow-up to CHOPS. Following cold production, the pay zone has become a network of wormholes that extend radially outward from production wells. These wormholes provide reservoir access for a post-CHOPS process in which a fluid, such as solvent or steam, can be injected.
Cyclic Solvent Injection
The concept of cyclic solvent injection (CSI) was borne from the need to develop a non-thermal process for thin reservoirs with wormholes. Of course, CSI can also be applied in other reservoirs where injectivity is sufficiently high. In CSI, solvent (typically a mixture of propane or butane with either methane or carbon dioxide) is injected into the reservoir through a vertical well (see Figure 1) until the pressure approaches the initial reservoir pressure. The solvent mixture is selected so that this pressure is close to the dew point of the mixture. Thus, the solvent has high solubility in the oil but, being in the gas phase, can pressurise the reservoir without an unacceptable amount of solvent being used, as would be the case if a liquid solvent was injected. Following injection, the solvent is allowed to soak into the reservoir for a specified period of time. During production (see Figure 2), the pressure is drawn down to about 200–500 kPa.a before the injection period of the next cycle begins. The injection–soak–production cycle is repeated a number of times. Dissolution of solvent in the heavy oil reduces its viscosity and can provide a solution gas drive when the reservoir pressure is reduced during production. The solvent is selected for a specific reservoir and the injection production strategy will be based on: how well the reservoir is confined following CHOPS; whether there are water inflow concerns; pay thickness; reservoir quality; and many other conditions.
An example of the CSI-operating strategy is shown in Figure 3. The initial reservoir pressure is 4,300 kPa.a and the temperature is 5 ºC. An 80 % methane–20 % propane mixture was selected in this example because its dew point pressure at 5ºC is 4,300 kPa.a. The more volatile methane is added to the propane to increase the dew point of the solvent, thereby minimising solvent hold-up in the reservoir. The economics of CSI is strongly dependent on the solvent retained in the reservoir and the oil production rate. A rule of thumb is that the net propane-to-oil ratio should be less than 0.2 liquid m3/m3 for the process to have any economic potential.
© TOUCH BRIEFINGS 2011
Net solvent is considered to be the solvent injected minus the solvent recovered, i.e. the solvent left in the reservoir. Depending on the surface separation facilities, some solvent may remain in the liquid phase and be transported with the oil to the refinery. Solvent injection processes significantly reduce greenhouse gas emissions and water usage compared with steam-based processes. They have the potential to store carbon dioxide if it is used as a solvent component. Although the process has been under development at Alberta Innovates – Technology Futures (AITF) for many years and is currently being tested at the field pilot scale, it is still considered to be in its infancy in field applications.
The AACI Research Program
CSI was initially developed in the AACI Research Program through experiments and numerical simulation. This research programme is managed by AITF and currently has 21 member companies. The goal of the programme is: “To develop significantly improved, economically viable, and environmentally sustainable in situ recovery technologies for heavy oil and bitumen through research evaluation and technology partnerships.”
Joint Implementation of the Vapour Extraction Project The CAN$40 million Joint Implementation of Vapour Extraction (JIVE) project that was run from 2006–2010 was an initiative that aimed to evaluate and develop solvent injection processes to recover heavy oil in Western Canada. The partners in JIVE were the Sustainable Development Technology Canada, the Government of Saskatchewan, TEAM, Husky Energy, Canadian Natural Resources Limited (CNRL) and Nexen. The research providers were AITF and
Jeannine Chang is a Reservoir Simulation Specialist at Devon Energy Corporation and before that was at AITF. Her work has focused on reservoir simulation of enhanced oil recovery (EOR) technologies including cyclic injection processes (solvent, steam and steam- solvent), vapour extraction (VAPEX), steam-assisted gravity drainage (SAGD) and primary production. Before joining AITF, Ms Chang was an environmental consultant focusing on environmental assessments and petroleum contaminant remediation and investigated EOR processes at AITF based on reservoir stimulation and laboratory experiments.
John Ivory is the Subsurface Portfolio Manager at Alberta Innovates – Technology Futures (AITF) in the areas of enhanced oil recovery (primarily solvent, steam, steam-solvent and in situ combustion processes) and gas separation/purification using membranes, adsorption or absorption technologies, and leader of AITF’s Reservoir Simulation Group. Dr Ivory has extensive expertise in both designing experiments and performing numerical simulations related to enhanced heavy oil and bitumen recovery processes.
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Heavy Oil
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