Sam Huang

A comparison of CO2 minimum miscibility pressure determinations for Weyburn crude oil

Abstract Minimum miscibility pressure (MMP) is often used as a key criterion for screening and selecting suitable solvents for enhanced oil recovery projects. This paper compares the pure and impure CO2 MMP values determined for a medium oil from Weyburn reservoir located in southeast Saskatchewan, Canada. Three different methods were employed for determining MMP, namely, slim tube experiments, rising bubble apparatus (RBA) tests, and correlations. The contaminants in the impure CO2 streams considered were nitrogen (from flue gas) and methane (from recycled CO2). Results of the study indicated that the MMP values measured by the RBA technique agreed well with those measured using the slim tube tests and those predicted using a published correlation. For the Weyburn oil–CO2 system, a distinct bubble behaviour—tail formation—was observed when the pressure reached or was higher than MMP. These results provide additional experimental experience of using the RBA as an efficient tool of determining the MMP for some solvent gas–medium oil systems. This study also demonstrated that, for the Weyburn reservoir, promising EOR agents (having an MMP below 80% of the reservoir fracture pressure) are pure CO2 and blended CO2 containing up to about 12 mol% CH4 or 5 mol% N2.

Asphaltene Deposition During CO2 Flooding: A Laboratory Assessment

In a CO 2 miscible displacement process, the injected CO 2 solvent can induce flocculation and deposition of asphaltenes and other heavy organic particles. This can cause numerous production problems with a detrimental effect on oil recovery. Therefore, it is important to understand the behavior of this organic matter under reservoir operating conditions. This paper presents results of dynamic and static precipitation tests conducted at reservoir temperature and pressure conditions to investigate the likelihood of asphaltene deposition problems in the Weyburn reservoir (in southeast Saskatchewan). A laboratory study using a high-pressure PVT cell was undertaken to determine the effect on asphaltene flocculation/precipitation of operating pressure, CO 2 concentration, gas contaminants in CO 2 , and presence of formation brine for three different oil samples collected from the reservoir. The extent of asphaltene deposition was also assessed through coreflood experiments using preserved and restored reservoir core material collected from different reservoir zones of increasing permeability (Marly, Vuggy, and high-grain-size Vuggy) and through a suitably designed X-ray CAT-scanning visualization experiment. Static tests indicated the most important factor on which the asphaltene precipitation depended was the CO 2 concentration. For oils belonging to the same pool, the increase in asphaltene precipitation with solvent concentration was proportional to the initial asphaltene contents of the oil. Coreflood experiments showed a considerable increase in asphaltene deposition in the core matrix following CO 2 injection. Pore topography of the core matrix played an important role in the extent of CO 2 -induced asphaltene deposition. The deposition appeared to be higher in a high-grain-size Vuggy matrix than in the normal Vuggy matrix, and lowest in the Marly matrix. X-ray CAT-scanning tests depicted localized areas of asphaltene deposition along the length of the core, with significant deposition suspected to be occurring near the inlet of the core. The CAT-scan tests also identified sites of suspected formation damage to the core matrix associated with CO 2 injection.

Prediction of fluid phase behaviors in a CO2-EOR process in Weyburn field, Saskatchewan, Canada

Publisher Summary The objective of the multidisciplinary “Weyburn CO2 Miscible Flooding Project” is to develop a Pressure-Volume-Temperature (PVT) model for the CO2-Weyburn oil system that can be coupled with compositional reservoir models for the short- and long-term field-scale reservoir simulations. This project is operated by Encana Corporation in southeastern Saskatchewan, Canada, provides a unique opportunity for the “lEA GHG Weyburn CO2 Monitoring and Storage Project” to add to the knowledge and understanding of the process mechanisms of enhanced oil recovery (EOR) and CO2, a greenhouse gas (GHG), storage in oil depleted reservoir. The model is continuously modified as the field process proceeds to capture the dynamic change in fluid properties, including minimum miscibility pressure (MMP) and the effect of contaminates in the injecting CO2. Accurate prediction of the CO2 distribution in different phases (that is, aqueous, oleic, and gaseous) in the reservoir after the CO2-EOR process is essential for long-term risk assessment that is relied on the understanding of the fluid phase behaviors. For example, estimations of mineral trapping, ionic trapping, and solubility trapping of CO2 are based on the amount of CO2 stored in the aqueous phase. On the other hand, the amount of CO2 stored in the gaseous phase, which is the most mobile phase of CO2 in the reservoir, is essential in the estimation of CO2 leakage.