Russell Giesbrecht - Academia.edu (original) (raw)
Papers by Russell Giesbrecht
IOR 2019 – 20th European Symposium on Improved Oil Recovery, 2019
Alkali-surfactant-polymer (ASP) flooding is a common chemical enhanced oil recovery (EOR) method.... more Alkali-surfactant-polymer (ASP) flooding is a common chemical enhanced oil recovery (EOR) method. Large full-field applications are limited, but there are numerous pilot trials reported. One reason for the lack of full-field implementations might be the comparatively high chemical cost of the ASP formulations. Hence, there is a continuous need for improving the cost and/or performance of the system. In this regard, new ASP formulations based on hydrophobically modified polyacrylamides, also known as associative polymers, were developed and the best performing candidate was evaluated in a pilot in a heavy oil field in Canada. The major motivation to use an associative polymer was to make use of its superior in-situ viscosifying performance compared to regular polyacrylamide polymer (HPAM). As a high in-situ viscosity was targeted to prevent influx from the aquifer in the reservoir. Altogether, more than ten different ASP formulations were investigated in sandpacks with cleaned and crushed rock material from the field. A high tertiary oil recovery of almost 69% was observed for an ASP formulation including chelating agent, sodium hydroxide, an alkylether sulfate surfactant and a novel hydrophobically modified polymer. The field application of this formulation commenced at the start of 2017 into three horizontal injection wells and concluded in Q2 of 2018. Injectivity was proven to be very good. It even did improve if compared to the alkali-polymer injection with a different polymer which was conducted in advance to the ASP pilot. Despite an increase of the injection rate from around 50 m3/d to approx. 70 m3/d, the wellhead pressure dropped from initially 1500-1600 psi down to approx. 1200 psi. This can be possibly explained by the good dissolution characteristics of the polymer, as also confirmed by the less frequent filter changes. Polymer effluent was detected in several production wells, which indicates a good propagation of the polymer through the reservoir. In August 2017 the oil-cut in several producers increased. However, this increase was not sustainable and it was concluded that the dilution effect of the aquifer was too strong to continue the chemical flooding operation. Altogether, it was shown that the combination of an alkylether sulfate surfactant and a hydrophobically modified polymer revealed excellent injectivity and good propagation through the reservoir. However, a drawback was the strong aquifer effect, which made the additional oil recovery only moderate. This effect needs to be managed more carefully for future chemical EOR program plans.
Die vorliegende Erfindung betrifft ein Verfahren zum Fordern von Erdol aus unterirdischen Formati... more Die vorliegende Erfindung betrifft ein Verfahren zum Fordern von Erdol aus unterirdischen Formationen, wobei in einem Verfahrensschritt permeable Bereich der unterirdischen Formation durch Injizieren wassriger Formulierungen hydrophob assoziierender Copolymere in die Formation blockiert werden.
L'invention concerne un procede pour l'exploitation de petrole a partir de formations sou... more L'invention concerne un procede pour l'exploitation de petrole a partir de formations souterraines. Dans une etape de procede, des zones permeables de la formation souterraine sont bloquees grâce a l'injection de formulations aqueuses de copolymeres associatifs de maniere hydrophobe dans la formation.
Journal of Surfactants and Detergents, 2019
Many reservoir formation brines are characterized by high salinity and contain high concentration... more Many reservoir formation brines are characterized by high salinity and contain high concentrations of divalent ions such as calcium, magnesium, and potassium. These challenging conditions can render the surfactants ineffective during chemical flooding for enhanced heavy oil recovery. Various brine types can have an impact on the stability of emulsions generated with chemicals as chemicals have various resistant levels toward hard divalent ions and salinities. To investigate the impact of brine hardness on heavy oil-in-water emulsion stability, glass tube experiments, microscopic visualization and sandpack flooding experiments, and Hele-Shaw visualization experiments were conducted in this study under lowsalinity/hard-brine, high-salinity/hard-brine conditions using commercial chemicals, which are designed for specific reservoir brine conditions. Recovery results demonstrated that complex colloidal solution introduced in the previous study with silica and Dodecyltrimethylammonium bromide (DTAB) along with screened chemicals from glass tube tests in this study can enhance heavy oil recovery significantly with an addition of low concentration of xanthan gum (Lee and Babadagli 2018). The results confirmed the robustness of the complex colloidal solution formula to enhance oil recovery with low concentration of polymer under any reservoir brine conditions. The study also demonstrates the potential of polymer as an emulsion stabilization additive for enhanced heavy oil recovery by in situ emulsion generation. Polymer effects seemed to be particularly dominant under the low-salinity conditions than highsalinity conditions.
IOR 2019 – 20th European Symposium on Improved Oil Recovery, 2019
Alkali-surfactant-polymer (ASP) flooding is a common chemical enhanced oil recovery (EOR) method.... more Alkali-surfactant-polymer (ASP) flooding is a common chemical enhanced oil recovery (EOR) method. Large full-field applications are limited, but there are numerous pilot trials reported. One reason for the lack of full-field implementations might be the comparatively high chemical cost of the ASP formulations. Hence, there is a continuous need for improving the cost and/or performance of the system. In this regard, new ASP formulations based on hydrophobically modified polyacrylamides, also known as associative polymers, were developed and the best performing candidate was evaluated in a pilot in a heavy oil field in Canada. The major motivation to use an associative polymer was to make use of its superior in-situ viscosifying performance compared to regular polyacrylamide polymer (HPAM). As a high in-situ viscosity was targeted to prevent influx from the aquifer in the reservoir. Altogether, more than ten different ASP formulations were investigated in sandpacks with cleaned and crushed rock material from the field. A high tertiary oil recovery of almost 69% was observed for an ASP formulation including chelating agent, sodium hydroxide, an alkylether sulfate surfactant and a novel hydrophobically modified polymer. The field application of this formulation commenced at the start of 2017 into three horizontal injection wells and concluded in Q2 of 2018. Injectivity was proven to be very good. It even did improve if compared to the alkali-polymer injection with a different polymer which was conducted in advance to the ASP pilot. Despite an increase of the injection rate from around 50 m3/d to approx. 70 m3/d, the wellhead pressure dropped from initially 1500-1600 psi down to approx. 1200 psi. This can be possibly explained by the good dissolution characteristics of the polymer, as also confirmed by the less frequent filter changes. Polymer effluent was detected in several production wells, which indicates a good propagation of the polymer through the reservoir. In August 2017 the oil-cut in several producers increased. However, this increase was not sustainable and it was concluded that the dilution effect of the aquifer was too strong to continue the chemical flooding operation. Altogether, it was shown that the combination of an alkylether sulfate surfactant and a hydrophobically modified polymer revealed excellent injectivity and good propagation through the reservoir. However, a drawback was the strong aquifer effect, which made the additional oil recovery only moderate. This effect needs to be managed more carefully for future chemical EOR program plans.
Die vorliegende Erfindung betrifft ein Verfahren zum Fordern von Erdol aus unterirdischen Formati... more Die vorliegende Erfindung betrifft ein Verfahren zum Fordern von Erdol aus unterirdischen Formationen, wobei in einem Verfahrensschritt permeable Bereich der unterirdischen Formation durch Injizieren wassriger Formulierungen hydrophob assoziierender Copolymere in die Formation blockiert werden.
L'invention concerne un procede pour l'exploitation de petrole a partir de formations sou... more L'invention concerne un procede pour l'exploitation de petrole a partir de formations souterraines. Dans une etape de procede, des zones permeables de la formation souterraine sont bloquees grâce a l'injection de formulations aqueuses de copolymeres associatifs de maniere hydrophobe dans la formation.
Journal of Surfactants and Detergents, 2019
Many reservoir formation brines are characterized by high salinity and contain high concentration... more Many reservoir formation brines are characterized by high salinity and contain high concentrations of divalent ions such as calcium, magnesium, and potassium. These challenging conditions can render the surfactants ineffective during chemical flooding for enhanced heavy oil recovery. Various brine types can have an impact on the stability of emulsions generated with chemicals as chemicals have various resistant levels toward hard divalent ions and salinities. To investigate the impact of brine hardness on heavy oil-in-water emulsion stability, glass tube experiments, microscopic visualization and sandpack flooding experiments, and Hele-Shaw visualization experiments were conducted in this study under lowsalinity/hard-brine, high-salinity/hard-brine conditions using commercial chemicals, which are designed for specific reservoir brine conditions. Recovery results demonstrated that complex colloidal solution introduced in the previous study with silica and Dodecyltrimethylammonium bromide (DTAB) along with screened chemicals from glass tube tests in this study can enhance heavy oil recovery significantly with an addition of low concentration of xanthan gum (Lee and Babadagli 2018). The results confirmed the robustness of the complex colloidal solution formula to enhance oil recovery with low concentration of polymer under any reservoir brine conditions. The study also demonstrates the potential of polymer as an emulsion stabilization additive for enhanced heavy oil recovery by in situ emulsion generation. Polymer effects seemed to be particularly dominant under the low-salinity conditions than highsalinity conditions.