This paper addresses a critical step on the road to having in-situ reservoir agents. It targets the limiting size of these devices and endeavors to model their transport mechanisms in the rock matrix. It also details an experimental study on nanofluid coreflood experiments in the ARAB-D formation of the giant Ghawar field in Saudi Arabia. The study aims to test the feasibility and future reality for displacing molecular nanoagents in the reservoir. The testing objectives, process, and results are further detailed herein. Introduction The initiative for deploying nanoagents in the reservoir is part of an umbrella initiative for in-situ sensing and intervention (ISSI) at Saudi Aramco. The ISSI focus area works at identifying and developing enabling micro-nano-technologies (MNT) in support of the company's upstream E&P (i.e. exploration, drilling, production, and reservoir) operations. Logically, having in-reservoir nanodevices will require first and foremost determining the maximum usable size of these devices before attempting to develop interrogatable (passive) nanosensors or steerable (active) nanomachines. And this critical step has its own roadmap that involves [1]:making an assessment of the rock's pore throat size distribution to establish a first rough estimate on a usable size or size range for these agents,acquire or formulate stable, uniform, and inert nanoparticle suspensions with narrow distributions of different particle sizes, andconduct coreflood experiments to validate the particles stability and their transport continuity under realistic conditions. The paper is concerned with the coreflood testing that intends to identify and understand the needs to implement the idea in the field. Conceptually, nanofluid coreflooding is rather simple. It involves injecting a slug (about one tenth of a pore volume or 1 cc) of a well characterized nanofluid solution at one end of a core sample and follow this with continuous injection of ultra-filtered particle-free water. The effluent fluid at the other end of the core is then monitored and characterized for its content in nanoparticles. As such, it is hoped to formulate an idea on the transport potential of these particles within the rock matrix. In the particle concentration versus injected volume plot, the influent response is a Heaviside type function and the effluent response is generally a skewed bell-shaped function.
Carbon dioxide (CO 2) flooding is one of the most globally used EOR processes to enhance oil recovery. However, the low gas viscosity and density result in gas channeling and gravity override which lead to poor sweep efficiency. Foam application for mobility control is a promising technology to increase the gas viscosity, lower the mobility and improve the sweep efficiency in the reservoir. Foam is generated in the reservoir by co-injection of surfactant solutions and gas. Although there are many surfactants that can be used for such purpose, their performance with supercritical CO 2 (ScCO 2) is weak causing poor or loss of mobility control. This experimental study evaluates a newly developed surfactant (CNF) that was introduced for ScCO 2 mobility control in comparison with a common foaming agent, anionic alpha olefin sulfonate (AOS) surfactant. Experimental work was divided into three stages: foam static tests, interfacial tension measurements, and foam dynamic tests. Both surfactants were investigated at different conditions. In general, results show that both surfactants are good foaming agents to reduce the mobility of ScCO 2 with better performance of CNF surfactant. Shaking tests in the presence of crude oil show that the foam life for CNF extends to more than 24 h but less than that for AOS. Moreover, CNF features lower critical micelle concentration (CMC), higher adsorption, and smaller area/molecule at the liquid-air interface. Furthermore, entering, spreading, and bridging coefficients indicate that CNF surfactant produces very stable foam with light crude oil in both deionized and saline water, whereas AOS was stable only in deionized water. At all conditions for mobility reduction evaluation, CNF exhibits stronger flow resistance, higher foam viscosity, and higher mobility reduction factor than that of AOS surfactant. In addition, CNF and ScCO 2 simultaneous injection produced 8.83% higher oil recovery than that of the baseline experiment and 7.87% higher than that of AOS. Pressure drop profiles for foam flooding using CNF was slightly higher than that of AOS indicating that CNF is better in terms of foam-oil tolerance which resulted in higher oil recovery.
Foamed acidic fluids have been utilized in the industry for enhanced oil recovery and fracturing applications due to their various advantages. Flowback enhancement, recovery of treatment fluids, and reduction of overall water consumption per operation are examples of these advantages. This study examines the utilization of a chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA) in N2 and CO2 foamed fluids, which enhances the stability of foamed acidic fluids, lowers corrosion tendency, and is environmentally friendly. A modified high pressure and high temperature (HPHT) foam rheometer, and foam analyzer at ambient conditions, are used to test the acidic foamed fluids prepared in produced water using N2 and CO2. A screened out Alkyl diamine derivative surfactant has been tested at 212-300 °F and 1000 psi with and without GLDA. The effect of corrosion inhibitor addition on viscosity and foam quality is also investigated. Viscosity and foam quality measurements were done at increasing shear rates from 500 1/s up to 2000 1/s. Results showed that GLDA enhances the foamed fluid viscosity and stability. Resulted viscosities were in the range of 5 cP at higher shear rates to 25 cP in the lower shear rates region. Viscosity, in general, is lowered by higher shear rates, but foam quality is not affected. Fluid systems with a corrosion inhibitor also resulted in lower viscosities. The most stable and relatively higher viscosity values resulted from the 1 wt.% surfactant concentration with the addition of 15 wt.% GLDA and no corrosion inhibitor. Ambient conditions foam analyzer results showed higher foam height and half-life values of 182.8 mm and 16.5 minutes respectively when foaimg using N2 compared to 77.4 mm and 2.16 minutes when foamed with CO2. The addition of corrosion inhibitor showed significant negative impact in all cases, but least on the half-life of the CO2 foamed fluid. The rheology study provided did not consider the addition of thickeners which could be further investigated. This study covers the novel utilization of a chelating agent as an additive in CO2 and N2 acidic foamed fluids at harsh conditions. Furthermore, the fluid systems tested can be investigated and utilized as reliable stimulation fluid systems at temperatures up to 300 °F.
Summary This research fills the gap in understanding the impact of corrosion inhibitors (CIs) and a chelating agent on the rheology and stability of foam under harsh conditions. In this regard, a modified high-pressure, high-temperature (HPHT) foam rheometer and HPHT foam analyzer were used to investigate foam rheology and stability at 1,000 psi and 120 to 150°C with carbon dioxide (CO2) in the gas phase. Surfactant screening showed that Duomeen TTM and Armovis are thermally stable at high temperature and high water salinity and thus were used in this study. The liquid phase generally contained produced water (PW) (total dissolved solids ~ 24,611 ppm), 15 wt% chelating agent [L-glutamic acid-N, N-diacetic acid (GLDA)], and 1 wt% surfactant with and without a CI. First, we screened the viscosity and stability of Duomeen TTM and Armovis; the results showed that Duomeen TTM has a higher viscosity (at least by 82%) at a low shear rate, but both have similar viscosity at a higher shear rate. However, Armovis produced more stable foam. Once the GLDA was added to the Duomeen TTM solution, the viscosity increased significantly by 135% at a high shear rate (1,000–1,500). For the Armovis system, the viscosity improved by 77% and 68% at the low and high shear rates by adding GLDA. Additionally, foam stability was improved remarkably in both systems; half-life time almost doubled. Finally, we reported the effect of CI on the fluid systems, showing it considerably reduced the foam viscosity and stability. It reduced the half-life of the Armovis system by 79.4% and hindered the generation of foam for the Duomeen TTM system. A detailed discussion of foam properties, such as foamability, bubble count, and bubble radius, is provided. This study provides a wide-ranging understanding of additives’ impact on stimulating foam stability at HPHT.
Injecting carbon dioxide (CO2) into oil reservoirs has the potential to enhance oil recovery (EOR) and sequester CO2 underground. While CO2 injection has been successful, a major challenge facing this technique is enhancing volumetric sweep efficiency. Some of the factors that contribute to this challenge are the low density and viscosity of injected gas relative to reservoir fluids. The use of foam is one of the most promising techniques to increase the CO2 apparent viscosity, thereby improving volumetric sweep efficiency. Increasing the CO2 viscosity by using surfactants has the potential to mitigate some of the challenges associated with CO2 injection projects. The objective of this work is to investigate the effect of various surfactants on CO2-foam viscosity. Four surfactants were used to evaluate the foam generation and rheological properties of CO2-foams at high pressure and temperature. Dynamic foam viscosity measurements were conducted in a special foam rheology apparatus with supercritical (sc-CO2) under high pressure (3200 psi), temperature (210°F) and salinity conditions. The foam was generated by injecting sc-CO2 and surfactant at different concentrations (0.20, 0.50 and 1.00 wt %), shear rates (10-600 s-1) and qualities (70, 85 and 90%). The results indicate that all surfactants were able to generate good quality foam at high pressure and temperature. The foam viscosity increases with surfactant concentration. All foams exhibited shear thinning behavior, with foam viscosity decreasing with increasing shear rates. In general, the highest viscosity for each surfactant was reported at the lowest shear rates. The results also showed that the foam quality has an impact on foam viscosity for some cases. The highest foam viscosities for surfactant 2 were achieved at 85% quality. However, the quality had no significant impact on foam viscosity for surfactant 3.
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