Experimental Study of Chemical Enhanced Oil Recovery (EOR) Methods in Sandstone Core Samples: Effect of Salinity and Divalent Cations.

PhD Thesis


Centeno, M. (2019). Experimental Study of Chemical Enhanced Oil Recovery (EOR) Methods in Sandstone Core Samples: Effect of Salinity and Divalent Cations. PhD Thesis London South Bank University School Of Engineering https://doi.org/10.18744/lsbu.8qv7w
AuthorsCenteno, M.
TypePhD Thesis
Abstract

Chemical Enhanced Oil Recovery (CEOR) is defined as the injection of chemical slugs into the reservoir with the object to increase the oil recovery factor (RF). Optimal combinations of chemicals, alkali (A), surfactant (S) and polymer (P) for an ASP CEOR have shown being an effective recovery method. However, due to high salinity and hardness (defined as the concentration of divalent cations Ca2+ and Mg2+) existing in the brine of some reservoirs, numerous and complicated physicochemical interactions such as adsorption, retention, and formation of emulsions are triggered.
This research project frames problems associated with the design of ASP CEOR for sandstone reservoirs under high salinity and hard brine. The fluid-fluid and fluid-rock interactions for the brine/oil, surfactant-brine/oil, alkali-surfactant-brine-oil, surfactant-polymer/oil, and alkali-surfactant-polymer/oil systems were evaluated at laboratory scale using Bentheimer sandstone core samples. Results from the study were aiming to understand the various mechanisms that favour the oil displacement efficiency of the ASP CEOR processes in sandstone.
A sample of crude oil from the North Sea was used in this research and synthetic brines were prepared to reproduce the original brine composition. The first part of the research consisted of the study of the effect of brine salinity and hardness on the fluid-fluid and fluid-rock interactions for the brine/oil system. Further studies were required on the microemulsion formation using different surfactant formulations with alcohol alkoxy -sulfate (APS), alcohol ethoxy sulfate (AES), and internal olefin sulfonate (IOS) surfactants for the system surfactant-brine/oil. The effect of sodium hydroxide and sodium metaborate on the microemulsion formation for alkali-surfactant-brine-oil system and interactions with polyacrylamide based polymers in surfactant-polymer/oil and alkali-surfactant-polymer/oil systems were also investigated.
Polymer viscosity exhibited shear thinning and Newtonian behaviour as a function of shear rate. The rheological behaviour was also associated with salinity, divalent cations, and the polymer size and structure in aqueous solution. These interactions were modelled adjusting experimental results to correlations proposed in the literature.
A comparative study of the displacement efficiency of waterflooding, P, AS, SP and ASP CEOR methods under a salinity gradient was completed to understand the different chemicals
interactions. It was found that the brine salinity and hardness affected the brine surface tension (ST) and the brine/oil interfacial tension (IFT). The brine ST and brine/oil IFT showed three well defined regions at different salinities. At low salinity (< 5,000 ppm TDS), the surface tension decreases with the salinity; between 5,000 ppm and 30,000 ppm TDS the ST and IFT slightly increase with salinity. In a third region the ST and IFT do not change with salinity exhibiting a plateau behaviour. Results from core-flooding tests showed that by creating a multicomponent salinity gradient that promotes the cationic exchange between divalent (Ca2+ and Mg2+) and monovalent (Na+) ions, an additional 5% of oil recovery was obtained. Alcohol alkoxy sulfate C13-14—7APS surfactant promotes microemulsion formation and tolerate divalent cations Ca2+ and Mg2+ at salinity higher than 28,000 ppm and lower than 48,000 ppm. Alcohol ethoxy sulfate C06-10-AES as co-surfactant moves the range of salinity for micoremulsion formation towards higher salinity (34,000 to 52,000 ppm) and enhance the stability of C13-14—7APS surfactant. While salinity restricts the use of surfactant alcohol ethoxylated (AEO) due to instability and precipitation formation, the combination of this surfactant with surfactant alcohol alkoxy sulfate (C13-14—7APS) increases its solubility and alsopromotes the microemulsion formation at salinity from 20,000 to 38,000 ppm.
Surfactants reduce the surfactant-brine/oil IFT to ultra-low values and increase the oil displacement efficiency by 15% compared with waterflooding. Surfactant absorption increases
with its concentration and with salinity; this effect is increased for brine with divalent ions. Co-surfactant alcohol ethoxy sulfate C06-10-AES reduces the adsorption of surfactant alcohol alkoxy sulfate C13-14—7APS. Divalent cations Ca2+ and Mg2+ react with alkali to form insoluble divalent hydroxides (Ca(OH)2 and Mg(OH)2); this effect limits the application of alkali for brines with divalent cations. However, the use of ethylene-diamine-tetracetic acid (EDTA) at controlled pH ≤ 9 prevents the precipitation of hydroxides by forming a complex between EDTA and divalent cations. The concentration of alkali should be controlled to reach a pH ≤ 9 in the formulation of alkali-surfactant slugs to prevent that a displacement reaction between the alkali in excess and divalent cations complexed with EDTA initiates. However, at pH ≤ 9 the formation of natural
naphthenic surfactant from the oil is not favourable. The use of alkali-surfactant-brine increases the oil displacement efficiency by 12% compared with the use of surfactant. High salinity also affects the interactions between polymers molecules in aqueous solution and reduces the viscosity of polymers; the effect is more marked by the presence of divalent
cations. Polymers reduce the mobility of the displacing fluid and mobility ratio by permeability reduction and viscosity augmentation. The effect is reflected in an increment of the
displacement efficiency ED. Polymer CEOR increases the recovery factor by 25% for PHPA-6 and 16% for PHPAM-3. The addition of surfactants for SP CEOR adds 19% oil recovery in comparison with water flooding, whereas ASP CEOR adds 31% for blend of surfactant with sodium metaborate, and 33% for the blend of surfactant with sodium hydroxide/EDTA. The polymer HMPAM-3 is more effective in increasing the oil displacement efficiency than PHPA-6 polymer in formulations for SP and ASP CEOR.
The advantages of the synergy of ASP CEOR were demonstrated on the displacement efficiency with an increase up to 33% for ASP using NaOH and EDTA. Stoichiometry calculations are required to complete desired equilibrium reactions involved in the process
and avoid hydroxide precipitation. While the mechanism of polymer flooding is associated with mobility ratio, it was demonstrated that the predominant effect of IFT on the displacement efficiency of SP and ASP systems for CEOR, which indicates the mechanism is dominated by the changes in the capillary number Nc. It was found that the stability of chemicals is affected in a larger extent by the concentration of
divalent ions Ca2+ and Mg2+ than by the total salinity. The surfactant stability in solution determines the optimal conditions for the microemulsion formation. Therefore, the selection of the surfactant formulation and controlling its stability are the main steps on the design of a successful ASP CEOR process.
This research presents a detailed study of the fluid-fluid and fluid-rock interactions that affect the design of SP and ASP CEOR at a microscopic scale. The results from the study provide
a systematic analysis of standalone methods and the synergy of combined methods on a fluid-fluid–rock system. Henceforward, the range of applicability and conditions of CEOR at laboratory scale for oilfield applications can be established.

Year2019
PublisherLondon South Bank University
Digital Object Identifier (DOI)https://doi.org/10.18744/lsbu.8qv7w
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