C. Jossy’s research while affiliated with Alberta Research Council (ARC) and other places

VAPEX and related processes for the recovery of heavy oil and bitumen have potential application to oils containing some methane in solution. A set of experiments has been completed to evaluate the potential for thermal VAPEX operations in heavy oils containing significant dissolved methane content. Three experiments were run to evaluate a VAPEX process operating in a reservoir in which the oil had significant initial methane saturation. The first experiment tested a 3-component mixture (C1-C2-C3) that was used in an earlier non-thermal dead oil VAPEX test. The second experiment used horizontally offset wells and 100% ethane as the working solvent. The production well was heated to reflux the solvent in situ. The third experiment also used horizontally offset wells and 100% ethane, plus steam. The steam was injected into the production well to reflux the solvent. Results indicated that the live oil inhibited solvent absorption, and hence production rates, but that a properly designed solvent system could produce oil at reasonable rates. Oil production from the steam-heated well/ethane experiment was similar to that from the electrically heated well/ethane reflux experiment. The experiments provided a database which can be used for economic comparison of process options, and for developing numerical simulations for field predictions. Introduction Some heavy oil reservoirs cannot be produced by cold production. They may be immobile at reservoir temperature, or they may have some initial oil mobility and some reservoir drive energy, but the sand strength precludes the production of sand or wormholes. These reservoirs may be dead oil, as in the case of Athabasca bitumen, or they may have some dissolved gas, as in the case of Cold Lake reservoirs. The VAPEX process(1) has been considered as a means of mobilizing heavy oil or bitumen. Figure 1 illustrates the concept of the VAPEX process. Heating a horizontal wellbore is a possible means of mobilizing these oils. Heat will reduce viscosity sufficiently to produce a large increase in oil rate. Heat also serves to initiate communication between an injection well and the producer, enabling solvent injection. Heat may also serve to speed the diffusion of the solvent into the oil. Heat may be injected by injecting steam, or by injecting heated Solvent(2). The wellbore may be heated by means of an electrical heater or a steam or glycol loop. Heat vapourizes the injected solvent. Solvent vapour moves to the oil interface at the edge of the vapour chamber and dissolves in the oil. The diluted oil is reduced in viscosity and flows down the edge of the vapour chamber to the production well. The vapourized solvent is driven out of the oil by the heat as it enters the near wellbore region or the production well. The vapourized solvent will return to the vapour chamber, where it will mobilize additional oil. The result is a Thermal Solvent Reflux process(3). The process concept is illustrated in Figure 2. FIGURE 1: VAPEX process (Available In Full Paper) FIGURE 2: The thermal solvent process (Available In Full Paper)

Laboratory experiments at Alberta Research Council (now Alberta Innovates Technology Futures) have indicated the potential for improving the recovery of bitumen and heavy oil, and a substantial reduction of SOR relative to SAGD, by the addition of substantial volumes of light hydrocarbon to steam as an enhancement of SAGD. Many scaled lab model experiments have been completed, some of which have identified solvent/steam ratios that outperformed low pressure SAGD. In order to more reliably scale the results of these experiments, it was desired to measure the rate of oil production and hence solvent front advance rate in field permeability sand. The experiments were isothermal to simplify the numerical simulations. Three experiments were completed, one at 68°C one at 80°C and one at 100°C. The respective butane pressures were 700 kPa, 1020 kPa and 1450 kPa. The respective oil rates were 52.5 g/h, 62.3 g/h and 63.2 g/h. Solvent front advance rates were 7.81 cm/d, 9.0 cm/d and 9.42 cm/d. These rates translate into SAGD-like rates when extrapolated to a field size project.

The experiments and numerical simulations described in this paper were performed to determine the effectiveness of the thermal solvent reflux and steam solvent hybrid processes and to determine the key parameters involved in these two processes. Steam-assisted gravity drainage (SAGD) is the current technology of choice for Athabasca reservoirs. It is commercially proven and delivers high oil rates and high ultimate recoveries. However, it is energy intensive. In addition, steam injection may be limited by lack of water, by regulatory issues or by the fact that some reservoirs are water sensitive. Vapour-assisted petroleum extraction (VAPEX) does not have the energy and water problems associated with SAGD. However, it is inherently slower than SAGD. One solution to the above difficulties is to combine processes by heating the horizontal wellbores. The heat serves to initiate communication between the injector and the producer. In addition, it will increase the rate of diffusion of the solvent into the oil. Heat may be applied by electric heaters, with a closed steam or glycol loop, or by direct injection of steam. In the first three of four experiments described in this report, the wells were electrically heated. In the fourth experiment, steam was co-injected with the solvent. Two experiments using Hillmond oil showed that similar results were obtained whether heating was obtained by electrically heating the wells (thermal solvent reflux process) or by direct steam injection (steam solvent-hybrid process). For these two experiments, the oil rate and recovery were similar. Numerical simulations were used to history match the experiments and effective diffusivity values were estimated. Introduction The objective of the thermal solvent reflux experiments was to develop a solvent-assisted process for recovery of heavy oil from thick, cold reservoirs such as Cold Lake and Athabasca. The thermal solvent process concept (Figure 1) is • Inject solvent and produce oil through horizontal wells • Heat the injection and production wells to reboil the solvent in situ (solvent reflux) (i.e., in-situ recycle of solvent) The advantages of the thermal solvent reflux process are • Requires less heat than SAGD • Less steam plant emissions • Smaller solvent recycle plant on surface • Smaller injection facility needed • Does not inject water into the reservoir • Suitable for reactive reservoirs • No treatment of boiler feed water required • Minimal water disposal • Minimal oil/water separation facilities required • Heat will speed mass transfer over cold VAPEX

Both gravity-based and cyclic processes for heavy oil/bitumen recovery may involve the use of hydrocarbon (n-alkane) solvent at relatively high solvent/oil ratios. Previous work at ARC has shown that at high solvent loadings, the oil/solvent mixture partitions into a solvent-rich oil phase and a heavy-ends-rich (mostly asphaltene) oil phase. The liquid phases have significantly different densities and viscosities. The partitioning phenomenon could have a significant impact on the performance of gravity-based processes such as Vapex involving solvents, where the low-viscosity liquid phase carries the bulk of the oil production, and the heavier liquid phase consisting of mostly asphaltene is essentially immobile. The solvent-rich phase will consist of the upgraded (de-asphalted) oil. Production of upgraded oil thus would not only enhance the production rate, but also have both economic and pipelining advantages. Data on the physical properties (viscosity and density) and the composition of both the partitioned phases are needed to design and optimize solvent-based processes in reservoir engineering calculations. Phase partitioning experiments conducted at the Alberta Research Council Laboratories along with the experimental data are presented in this paper. Introduction Both gravity-based and cyclic processes for heavy oil recovery may involve the use of solvent which dissolves in heavy oil or bitumen at relatively high solvent/oil ratios. Earlier works at ARC, and recent work in the Thermal Gravity Strategic area, have shown that at high loadings the oil/solvent mixture partitions into a solvent- rich oil phase and a heavy-ends-rich oil phase. The two liquid oleic phases have significantly different densities and viscosities. The phase partitioning may have significant impact on the performance of a solvent-based heavy oil recovery process. In particular, VAPEX and other gravity-based processes involving solvents may have their performance enhanced if the low-viscosity phase carries the bulk of the oil production, and the heavy-ends-rich phase contains most of the asphaltene and is essentially immobile.

Solvent-based processes for recovery of heavy oil and bitumen have potential application to a variety of reservoir situations. Potential processes range from steam assisted gravity drainage (SAGD) to VAPEX, with a range of hybrid processes in between. Over 50 laboratory-scale and 80 field-scale simulations were run to determine optimwn operating points for various hybrid processes. The results showed that steam-butane simulations yielded two "sweet spots" where the cost objective function was lower than that for SAGD. Economic analysis was done based on a set of field-scale simulations. This analysis showed that a hybrid solvent process for an Athabasca reservoir was an alternative to SAGD. The analysis may be extended to other reservoir types as needed.

Several partially scaled laboratory model experiments were conducted to evaluate a hybrid solvent-steam process for recovery of heavy oil or bitumen. All experiments used Athabasca UTF bitumen, and modelled a 30-metre-thick formation. The experiments were compared using a common set of economic assumptions. The experiments showed that a hybrid solvent-steam process could recover bitumen at steam-oil ratios much lower than those observed for steam assisted gravity drainage (SAGD), and achieve reasonable ultimate oil recovery (60% IOIP). The economic analysis based on experiments indicated that a hybrid solvent-steam process could be more cost-effective than SAGD for a 30-m Athabasca formation. Introduction Some heavy oil reservoirs are difficult to produce by cold production. The oil may be immobile at reservoir temperature, or there may be some initial oil mobility and some reservoir drive energy, but the sand strength precludes the production of wormholes. These reservoirs may contain dead oil, as in the case of Athabasca bitumen, or they may have some dissolved gas, as in the case of Cold Lake or Burnt Lake reservoirs. SAGD is the main commercial technology used for in-situ recovery of these oils. Because of the increasing costs for energy (natural gas) and the increasing restrictions on fresh water usage, solvent-based processes (VAPEX, Thermal Solvent, Hybrid Solvent, N-Solv, Savex) have been proposed as alternative technologies for heavy oil and bitumen production. Most of these technologies utilize a pair of horizontal wells, similar to those used in SAGD, but use a gaseous solvent, typically propane, alone or in conjunction with steam, to recover the oil. The VAPEX process may be augmented by adding heat. Heating of a horizontal wellbore will reduce bitumen viscosity sufficiently to produce a large increase in oil production rate. The heat also serves to initiate communication between the injector and the producer. The heat also serves to speed the diffusion of solvent into the oil. The combination of heated wellbores and VAPEX is known as the thermal solvent process.

In 1998, Butler and Mokrys proposed a "Closed-Loop Extraction Method for the Recovery of Heavy Oils and Bitumens Underlain by Aquifers." The process has potential application to many Alberta and Saskatchewan heavy oil reservoirs. The objective of our work was to produce an experimental evaluation of solvent-assisted process options for bottom water reservoirs. The current work is entirely experimental, and provides data that may be used to back up a numerical simulation effort. The experimental series modelled a bottom water process in order to determine its feasibility for a field-scale oil recovery scheme. A series of five experiments were run in an acrylic visual model. Pujol and Boberg's scaling criteria(1) were used to produce a lab model scaling a field process by a geometric ratio of 100:1, and compressing field time by a ratio of 10,000:1. The model simulated a slice of a 30 m thick reservoir with a 10 m thick bottom water zone, containing a pair of horizontal wells at the oil-water interface, offset by 25 m. For field prediction, experimental results were scaled up to represent a 30 m thick reservoir (20 m thick oil zone) with 500 m horizontal wells. The experimental rates were negatively impacted by continuous low permeability layers and by oil with an initial gas content. The lower effective diffusion rates required that the surface area exposed to solvents be increased in order to achieve commercial oil recovery rates. The Bottom Water Process described in this report offers the opportunity to do just that, as the large surface area of the oil water interface between the wells will provide contact for solvent by injecting gas at the interface. Given an appropriate well spacing, high production rates should be possible. Introduction The Alberta Research Council (ARC) has done several years of investigative work into solvent-assisted heavy oil recovery processes(2, 3). The present report describes a particular contribution to solvent-assisted oil recovery technology; a comparative scaled physical model study of bottom water process options. The results of this work showed scaled field rates of 25.3 m3/d and a live oil scaled rate of 16.5 m3/d, both at 25 m offset well spacing. Mechanisms of the Bottom Water VAPEX Process The Bottom Water VAPEX Process, illustrated in Figure 1, is a recovery process depending on the interplay of several mechanisms for its success. The solubility of the gas in the oil is controlled by the k-values of the oil/solvent system. Diffusion, hydrodynamic dispersion, and swelling also play a role in the movement of gas into the reservoir oil. The oil flow is enabled by viscosity reduction due to the dissolution of solvent in the oil. Oil-solvent contact is further augmented by capillary pressure moving some oil into the vapour chamber zone, as was observed in Experiment #2. Heterogeneity of the reservoir sand further increased the surface produced by capillary action, but excessive layering can hinder the movement of oil, as was shown by Experiment #3.

SAGD and CSS are the main commercial technologies used for in-situ recovery of bitumen in Alberta. Due to the increasing costs for energy (natural gas) and the increasing restrictions on fresh water usage, VAPEX and other technologies have been proposed as alternative technologies for heavy oil production. VAPEX uses a pair of horizontal wells, similar to SAGD, but uses a gaseous solvent, typically propane, to mobilize the oil. The Thermal Solvent process uses a light hydrocarbon solvent, injected into the upper will of a horizontal well pair. The action of the solvent is augmented by heating the wellbores, possibly by a steam loop. The Hybrid Solvent process injects light hydrocarbon solvent (propane) plus a modest amount of steam, sufficient to vaporize the solvent. Several scaled laboratory model experiments were designed to evaluate VAPEX and other solvent-based processes for recovery of heavy oil or bitumen. One experiment evaluated the VAPEX process in Athabasca UTF bitumen. Two experiments were completed to evaluate the Thermal Solvent Process. Two experiments were completed to evaluate a Hybrid Solvent process. All experiments were compared using a common set of economic assumptions. The economic results indicated that a hybrid process could be cost-competitive with SAGD for a 30 m thick Athabasca formation, and that the Thermal Solvent process could be competitive in certain thick heavy oil situations. Introduction Heavy oil and bitumen reservoirs may be immobile at reservoir temperature, or they may have some initial oil mobility and some reservoir drive energy. These reservoirs may contain dead oil, as in the case of Athabasca bitumen, or they may have some dissolved gas, as in the case of Cold Lake or Burnt Lake reservoirs. SAGD is the main commercial technology used for in-situ recovery for Athabasca reservoirs. Due to the increasing costs for energy and the increasing restrictions on fresh water usage, VAPEX has been proposed as an alternative technology for bitumen production. VAPEX uses a pair of horizontal wells, similar to SAGD, but uses a gaseous solvent, typically propane, to recover the oil. Experimental evaluation of VAPEX and related processes for mobile heavy oil recovery was assessed by Alberta Research Council in Reference 1. The VAPEX process may be augmented by adding heat. Heating of a horizontal wellbore will reduce viscosity sufficiently to produce a large increase in oil rate. The heat will also serve to initiate communication between the injector and the producer. The heat will serve to speed the diffusion of solvent into the oil. The combination of heated wellbores and VAPEX is known as the Thermal Solvent process. Again, a pair of horizontal wells is used, but the wells contain heating strings. This heat vaporizes the injected solvent. Solvent vapour moves to the oil interface at the edge of the vapour chamber and dissolves in the oil. The diluted oil is reduced in viscosity and flows down the edge of the vapour chamber to the production well. The vaporized solvent is driven out of the oil by the heat as it enters the production well.

Many heavy oil reservoirs in Alberta are currently produced by primary production (cold production) or by thermal processes (SAGD or cyclic steam). Not all reservoirs are suitable for these techniques due to bottom water zones or unfavourable mineralogy. The purpose of this work was to develop and evaluate an economically and technically feasible non-thermal process for those reservoirs which are not suitable for primary production or thermal simulation, and as a post-primary process. The focus was on developing processes using solvent mixtures tuned to the specific reservoirs, which would result in good sweep efficiency, reduced solvent costs, and commercially viable production rates. Several partially-scaled physical models were used to model the tuned solvent process being evaluated. Since gravity drainage is the primary process believed to occur in a heavy oil reservoir produced by a top-down displacement, the models represented a two-dimensional slice of the reservoir which intersected a pair of horizontal injection/production wells. The models operated at ambient reservoir conditions, representative of the Burnt Lake field or the Lloydminster region. The solvents used were gaseous or two-phase (vapour-liquid) mixtures of CH4, C2H6, C3H8, and CO2. The oil recovery ranged from 12% IOIP (initial oil in place) to 73% IOIP at 15 years field time. A series of experiments was performed to evaluate the potential for economic non-thermal recovery of heavy oil from a Burnt Lake reservoir, based on solvent assisted gravity drainage to horizontal wells. The experiments performed used carbon dioxide, a single phase hydrocarbon solvent, and two two-phase hydrocarbon solvents. Results of the experiments were extrapolated to the field scale (500 m horizontal well), and economic analyses were performed. Additional field scenarios were developed and their economics were analysed. The results of the economic analyses were used to evaluate the commercial potential of the processes proposed. Oil supply costs ranged from $384/m3 (lean mix experiment) to$41/m3 (the best single well scenario). The experimental results were analysed with a spreadsheet economic model in order to determine the economic potential of a 1,500 m3/d field project. Oil supply costs ranged from $384 Cdn/m3 (pre tax) for the lean mix process to$60.67/m3 Cdn for the rich mix+ process to $44/m3 for the thick Lloydminster process. Additional scenarios were investigated by extrapolating oil production and costs to cover possibilities such as wider well spacing, thicker pay zone, lower solvent cost, and a single well process. The additional scenarios were analysed using our economic model. The economic analysis suggested that a properly selected solvent would allow production of heavy oil from a single well cyclic process in a Burnt Lake reservoir at potentially economic rates. A dual-well gravity drainage process was potentially economic for a thick Lloydminster (> 15 m) reservoir, but not in a thin (< 8 m) Lloydminster reservoir. The most critical factor for economic success was to obtain high rates of bitumen production soon after the startup of the process, in order to rapidly recover the capital cost of the wells. Also critical was the minimizing of the solvent inventory and cost while maintaining solvent effectiveness.