HEAVY OIL A comparison of steady-state and unsteady-state relative permeabilities of viscous oil and water in Ottawa sand BRIJ MAINI, ABSTRACT Relative permeabilities have a central role in numerical simula-tion of oil recovery processes. Reliable relative permeability data for heavy oil reservoirs are scarce because of the experimental dif-ficulties involved in working with heavy oil systems at reservoir . r conditions. Often, in computer simulation studies, the laboratory measured relative permeabilities fail to provide satisfactory history-match of field operations. While there are several reasons for such failures, including the difficulties in obtaining a representative sam-ple of the reservoir material and differences between hydrodyna-mic conditions used in the laboratory measurements and the actual reservoir con&tions, the experimental errors in relative permea-bility measurements may be a principal cause.There appears to be lack of consensus among different labora-toties on how relative permeabilities should be measured in heavy oil systenn. The measurement techniques currently being used were developed for light oil systems and fail to address experimental problems which are peculiar to heavy oil systems. For example, viscous fingering is rarely a concern in light oil systems but becomes extremely difficult to eliminate when heavy oils are involved. Because of its speed and convenience, the unsteady-state techni-que is favoured by most laboratories. In light oil systems there appears to be good agreement between relative permeabilities measured by the steady-state method and those obtained by the unsteady-state technique. However, the equivalence of steady-state and unsteady-state measurements has not been confirmed in vis-cous oil systems.Steady-state measurements of relative permeability are generally free from viscous fingering effects. Therefore relatively high flow rates can be used to eliminate capillary end effects. The unsteady-state technique, in viscous oil systems, is likely to suffer from capil-lary end effects at low rates and from viscous fingering at high flow rates. Keywords: Relative permeabibty, Steady-state, Unsteady-state, Ottawa sand, Viscous oil.The objective of this work was to compare steady-state and unsteady-state relative permeabilities in a viscous oil-water-Ottawa sand system. Both types of measurements were obtained at two temperature-5 (room temperature and IOO'C). Displacement tests were carried out at several differentflood velocities to determine the effect of flow rate. The results show that in this system the two techniques provide different results. Moreover, the unsteady-state relative permeability was found to vary with flood velocity. The results appear to show that the unsteady-state technique may not be reliable when very adverse viscosity ratios are involved. Introduction Production of oil and gas from petroleum reservoirs usually in-volves flow of two or more immiscible fluids through a porous rock. Multi-phase flow in porous media is a complex process that de...

The recovery of 1,600,000 cp bitumen from very heterogeneous carbonate reservoirs in the Grosmont unit in Albert is a great challenge. Steam injection alone may not be efficient due to the heterogeneous nature of the reservoir caused by natural fractures at different scales. Recent cold solvent studies showed limited recovery because of low diffusion coefficient and by-passing matrix oil. The hybrid use of steam and solvent could be an option to overcome some of these challenges. We adapted the previously introduced SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) method and conducted twelve experiments using preserved core samples from the Grosmont formation. The temperature used can be qualified as hot water injection thereby reducing the cost of heating the reservoir.The method applied in this study is based on soaking rather than continuous injection. The samples were immersed in hot water (90 o C) first to mimic low temperature pre-steaming to condition the reservoir for solvent injection. This was followed by a solvent soaking period under varying conditions (duration, solvent type, etc.). Heptane and the distillate obtained from a heavy oil upgrading facility were used as solvents. Finally, the core samples were soaked in hot water again. Oil recoveries varied between 40% and 90% OOIP with a mean value of 68%. Asphaltene precipitation as a percentage of OOIP was measured between 6.5wt% and 33wt%. The oil recovery and asphaltene precipitation depended on the solvent type, the solvent exposure duration, the position of matrix rock (horizontal or vertical), and the duration and number of solvent/hot water cycles. Most importantly, the last phase (hot water immersion) yielded substantial recovery of solvent diffused into matrix oil by applying a temperature value close to the boiling point of the solvent. The solvent retrieval was extremely fast and varied between 62% and 82% of the solvent diffused into the core during solvent exposure. Experimental observations look promising for further applications as indicated by the high recovery values. The important aspects are that the solvent from readily available distillates used for transportation of heavy oil are very responsive and the temperature requirement for final hot water injection applied to retrieve solvent was less than 100 o C. Solvent retrieval was extremely quick and reasonably high which is more likely to make the process economic.

We adapted the previously introduced SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) method and conducted 12 experiments using preserved core samples from the Grosmont formation. The method applied in this study is based on soaking rather than continuous injection. The samples were immersed in hot water (90 °C), first to mimic low-temperature presteaming to condition the reservoir for solvent injection. This was followed by a solvent soaking period under varying conditions (duration, solvent type, etc.). Heptane and the distillate obtained from a heavy oil upgrading facility were used as solvents. Finally, the core samples were soaked in hot water again. Oil recoveries varied between 40% and 90% OOIP, with a mean value of 68%. Asphaltene precipitation, as a percentage of original oil in place (OOIP), was measured between 6.5 wt % and 33 wt %. The oil recovery and asphaltene precipitation depended on the solvent type, the solvent exposure duration, the position of matrix rock (horizontal or vertical), and the duration and number of solvent/hot water cycles. Most importantly, the last phase (hot water immersion) yielded substantial recovery of solvent diffused into matrix oil by applying a temperature value close to the boiling point of the solvent. The solvent retrieval was extremely fast and varied between 62% and 82% of the solvent diffused into the core during solvent exposure. Experimental observations look promising for further applications, as indicated by the high recovery values. The important aspects are that the solvent from readily available distillates used for transportation of heavy oil are very responsive and the temperature requirement for final hot water injection applied to retrieve solvent was <100 °C. Solvent retrieval was extremely quick and reasonably high, which is more likely to make the process economical.

A new thermal recovery scheme is proposed that utilizes Steam-Assisted Gravity Drainage (SAGD) well pairs as well as Cyclic Steam Stimulation (CSS) wells placed in between the SAGD well pairs. The wells are operated in CSS mode until the steam chambers are in contact with each other and then switched to SAGD operation. It is shown that the new process recovers greater amounts of bitumen with lower injected steam in shorter operation time than is achieved with SAGD, Fast-SAGD and CSS.Sproule is a diversified, worldwide petroleum consulting firm.We have been in business for over 50 years and have experience in all aspects of the energy sector throughout North America and the world.

Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required.Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and under burden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent. This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky's Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent.It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.