Investigation of geochemical interactions of carbon dioxide and carbonate formation in the Northwest McGregor oil field after enhanced oil recovery and CO2 storage

Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.

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Technology Focus: EOR Operations (November 2021)

Journal of Petroleum Technology ◽

10.2118/1121-0057-jpt ◽

2021 ◽

Vol 73 (11) ◽

pp. 57-57

Author(s):

Reza Fassihi

Keyword(s):

Enhanced Oil Recovery ◽

Carbon Footprint ◽

Oil Recovery ◽

Saline Water ◽

Co2 Storage ◽

Oil Field ◽

Unconventional Reservoirs ◽

Alternative Methods ◽

Water Sustainability ◽

Waterless Fracturing

As the discovery rate of new hydrocarbon resources decreases, the need for more-efficient enhanced-oil-recovery (EOR) processes increases. Unlike in the past, however, when the efficiency was defined in terms of maximizing the recovery factor (RF), the new interpretation of efficiency is based on optimizing the balance between RF and the reduction of carbon footprint. This is done through an integrated approach in which both surface and subsurface elements of the oil-production systems are used to determine energy efficiency and carbon footprint of a unit volume of oil produced by EOR methods. When choosing traditional EOR methods, new innovations may be needed to arrive at new injectant composition to reduce emissions or make the process more efficient. Adding chemicals to the injectant gas to improve the mobility ratio and increase the sweep efficiency is desirable. One example is the use of hydrogels. These are hydrophilic structures that swell when hydrated. Hydrogels are of interest in EOR because of their ability to respond to stimuli such as pH, temperature, light, and ionic strength. EOR methods that involve use of fresh water are also switching to alternative methods that reduce or remove its usage as part of water sustainability. The produced water could be treated properly to make it suitable for injection. Alternatively, polymers that are effective under high salinity or temperature could be used to deal with injecting saline water. For unconventional reservoirs, waterless fracturing techniques are progressing. Paper SPE 201609 discusses the application of a reversible hydrogel that can be added to the injected carbon dioxide (CO2) stream in order to make it a more-efficient injectant for EOR and, hence, create more opportunity for CO2 storage. Paper SPE 202809 deals with utility of new polymers that are suitable for injection into carbonate reservoirs under high-temperature and ultrahigh-salinity conditions. Finally, paper OTC 30437 discusses ways of mitigating safety risks associated with CO2 waterless fracturing in unconventional reservoirs as part of water sustainability as well as prevention of environmental pollution. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200357 - Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and Its Pertinence for Low-Salinity EOR by Duboué Jennifer, TotalEnergies, et al. SPE 205118 - Experimental Design and Evaluation of Surfactant Polymer for a Heavy-Oil Field in South of Sultanate of Oman by Ali Reham Al-Jabri, Petroleum Development of Oman, et al. SPE 200256 - Chemical Enhanced Oil Recovery and the Dilemma of More and Cleaner Energy by Rouhi Farajzadeh, Delft University of Technology, et al.

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Mobility Investigation of Nanoparticle-Stabilized Carbon Dioxide Foam for Enhanced Oil Recovery (EOR)

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.1119.90 ◽

2015 ◽

Vol 1119 ◽

pp. 90-95 ◽

Cited By ~ 3

Author(s):

T.A.T. Mohd ◽

N. Alias ◽

N.A. Ghazali ◽

E. Yahya ◽

A. Sauki ◽

...

Keyword(s):

Carbon Dioxide ◽

Porous Medium ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Viscous Fingering ◽

Oil Field ◽

Nanoparticle Concentration ◽

Good Potential ◽

Foam Flooding ◽

Brine Salinity

Enhanced oil recovery (EOR) can extend the life of an oil field by providing additional drive mechanism to the crude oil. The use of carbon dioxide (CO2) in EOR application has shown a good potential, but it has some weaknesses such as viscous fingering. Viscous fingering problem can be solved by reducing the CO2gas mobility, which can be achieved by transforming the CO2gas into surfactant-stabilized foam. However, surfactant-stabilized foam is not very stable under harsh reservoir condition, which could be handled by introducing nanoparticle-stabilized CO2foam. Thus, this paper aims to investigate the mobility of nanoparticle-stabilized CO2foam at varying brine salinity (1 - 4 wt%), concentration of AOS surfactant (0.01 - 1 wt%) and concentration of nanoparticle (0.05 - 1 wt%). The volumetric phase ratio was fixed at 8 CO2/aqueous. The sand pack foam flooding test was conducted to measure the effectiveness of the formulated foam to displace the oil inside the porous medium through mobility and oil recovery measurement. It was found that foam mobility is inversely proportional to oil recovery. Mobility decreased when increase of brine salinity, surfactant and nanoparticle concentration, which has increased the oil recovery. Thus, it is important to reduce the foam mobility for efficient displacement process, which could minimize viscous fingering and enhance the oil recovery. This could be achieved by increasing the viscosity of displacing fluid (foam) for more stable displacement in EOR application.

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