Experimental PVT Property Analyses for Athabasca Bitumen

Torsæter

2012

EER

Self Cite

There have been a number of somehow contradictory reports in the literature on the effect of temperature on oil and water relative permeabilities. Although some authors have reported the dependence of relative permeability curves on temperature, others have attributed these dependencies to artifacts inherent in unsteady-state method of relative permeability measurement. In order to further investigate the impact of temperature changes on the relative permeability data, we have conducted laboratory core flooding experiments on heavy oil systems. The porous media used was glass bead packs, and the Athabasca type bitumen with varying viscosities was displaced by hot water. The history matching technique was conducted on production and pressure differential data to get the relative permeability curves.Results indicated that generally the increase in initial water saturation and the decrease in residual oil saturation are expected by increasing temperature. However, viscous instabilities can rule out the above mentioned trends. No temperature dependency of either oil or water relative permeability can be justified in our tests. The changes in relative permeabilities by temperature are probably related to experimental artifacts, viscous fingering and changes in oil to water viscosity ratio and not fundamental flow properties.

Section: Oil Preparation and Viscosity Measurementmentioning

confidence: 99%

Section: Oil Preparation and Viscosity Measurementmentioning

confidence: 99%

Section: Oil Preparation and Viscosity Measurementmentioning

confidence: 99%

See 1 more Smart Citation

Effect of Temperature on Athabasca Type Heavy Oil – Water Relative Permeability Curves in Glass Bead Packs

Ashrafi

Torsæter

2012

EER

Self Cite

“…There is no gas cap or aquifer in this model which has 34% porosity and homogeneous horizontal and vertical permeabilities of 7.0 and 2.1 Darcy respectively. Ashrafi et al (2011d) measured the properties of Athabasca bitumen such as viscosity, density, molecular weight and its interfacial tension (IFT) with steam at different temperatures and pressures. These measured properties were used in this model.…”

Section: Description Of Numerical 2-d Modelmentioning

confidence: 99%

Field Scale Simulation Study, Investigating the Effect of Geological and Operational Parameters on Solvent Co-Injection Process in Athabasca Bitumen Reservoir

SPE Western Regional Meeting

Ashrafi

Ghahfarokhi

et al. 2015

Considerable proportions of the hydrocarbon resources in the world are in the shape of heavy oil and bitumen. In an environment of low economic returns for heavy oil operations, Steam Assisted Gravity Drainage (SAGD) process appears very promising from a technical point of view. However, it has two significant deficiencies, namely high energy and water requirements and environmental issues of green house gas (GHG) emissions. Recently, hybrid processes have attracted attentions, since they benefit from advantages of steam and solvents together. The vaporized solvents dissolve into the viscous oil and help the steam to reduce bitumen viscosity dramatically. Moreover, hybrid processes alleviate the high consumption of water and energy while improving the GHG emissions.The goal of this paper is to evaluate and compare the efficiency of SAGD and solvent co-injection (SCI) using experimental PVT properties of the Athabasca bitumen and a thermal numerical reservoir simulator. Steam trap control was applied in this study to hamper the steam production. Sensitivity analysis was performed to find out the effects of various geological parameters such as reservoir thickness, horizontal and vertical permeability, horizontal and vertical shale barriers and reservoir pressure, as well as operational parameters like injector location, solvent diffusivity, different solvent types and different concentrations of injected solvent. Three different crude oils from Cold Lake, Athabasca and Lloydminster reservoirs were selected to investigate the effect of viscosity.Results divulged great recovery of bitumen and reasonable amount of steam-oil ratio (SOR) for both processes. Applying solvent co-injection with steam reduced the amount of steam required and consequently decreased SOR, while higher recovery factors (R.F.) were obtained. Butane, pentane, hexane, heptane and dodecane were tested solvents in this study. Among them, hexane was used to investigate the effect of solvent concentration. Using higher concentration of injected solvent resulted in higher R.F. and lower SOR, however, economy of the process regarding the use of highly valuable solvents should also be considered.Higher vertical, horizontal permeability and reservoir pressure had positive effect on oil production. In addition, thicker reservoir showed better and more economical results in terms of oil production and SOR.Presence of shale barrier has a negative effect on oil production. This negative effect is more pronounced in case of horizontal than vertical shale layers. Applying solvent diffusivity coefficients revealed that very fine grid system in three directions is needed to evaluate the effect of diffusion precisely.

“…There is no gas cap or aquifer in this model which has 38% porosity and homogeneous horizontal and vertical permeabilities of 7.0 and 2.1 Darcies respectively. Ashrafi et al (2011b) measured the properties of Athabasca bitumen such as molecular weight, density, viscosity and its interfacial tension (IFT) with steam at different temperatures and pressures. These measured properties were used in this model.…”

Section: Description Of Numerical 2-d Modelmentioning

confidence: 99%

Application of Solvent Alternating SAGD Process to Improve SAGD Performance in Athabasca Bitumen Reservoir

SPE Western Regional &Amp; AAPG Pacific Section Meeting 2013 Joint Technical Conference

Torsater

Ghahfarokhi

et al. 2013

Canada, Venezuela and United States contain the largest portions of heavy oil and bitumen resources throughout the world. The problem associated with this type of resource is very viscous fluid flow. The EOR methods applied to heavy oil reservoirs are mainly based on viscosity reduction processes such as heating the reservoir and solvent injection. Heating, in the form of hot water flooding, steam injection and in-situ combustion dramatically reduces the viscosity of heavy oil and bitumen, but it has green house gas (GHG) emission problems. Diffusion of solvents in heavy oil makes it lighter and therefore mobile and producible via production well. Diffusion of solvent is a very tardy process while time is very important in oil industry and any delay results in extra costs. Recently, hybrid methods like solvent and steam co-injection, steam alternating solvent injection (SAS) have been introduced to solve the mentioned problems, while benefiting from the advantages of heat and solvent.Several simulation studies were performed to evaluate and compare the performance of steam assisted gravity drainage (SAGD) and steam alternating solvent (SAS) processes. Athabasca bitumen reservoir properties were used. Effects of some reservoir and fluid parameters such as thickness, porosity, vertical to horizontal permeability ratio and viscosity were assessed and compared for both processes. Experimental viscosity data of Athabasca and Cold lake bitumen were applied to evaluate the viscosity effect. In addition, sensitivity analysis was carried out on injection time intervals of solvent, solvent type and concentration.Results revealed high recovery of bitumen and appropriate steam-oil ratio (SOR) for both processes. However, SAS showed better performance using hexane as a solvent. Lower porosity, vertical to horizontal permeability ratio and thickness resulted in higher SOR for SAGD process while they had no major effect on SAS. Higher concentration of injected solvent resulted in faster recovery performance and lower SOR. Pentane and heptane were used as alternatives for hexane to investigate the impact of the selected solvent. They divulged almost the same results as hexane. Different injection intervals of 3, 6, 9 months and a year were also studied and the analogous results were obtained.