TY - JOUR
T1 - Modelling the impact of Alkaline-surfactant and Alkaline-surfactant-polymer flooding processes on scale precipitation and management
AU - Al Kalbani, Munther
AU - Jordan, Myles
AU - Mackay, Eric
AU - Sorbie, Ken
AU - Nghiem, Long
N1 - Funding Information:
Petroleum Development Oman (PDO) is acknowledged for funding the PhD student scholarship for Munther Al Kalbani. Acknowledgement also go to Energi Simulation Chair in Heriot-Watt University held by Prof. Eric Mackay for their support and for Computer Modelling Group (CMG) Ltd . for providing the CMG GME simulator with chemical EOR functionalities.
Publisher Copyright:
© 2021 Elsevier B.V.
PY - 2021/10
Y1 - 2021/10
N2 - Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results: show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3−) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)2 scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
AB - Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results: show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3−) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)2 scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
KW - Alkaline-surfactant-polymer
KW - Chemical EOR
KW - Geochemical reactions
KW - Inorganic scale precipitation
KW - Squeeze modelling
UR - http://www.scopus.com/inward/record.url?scp=85105456838&partnerID=8YFLogxK
U2 - 10.1016/j.petrol.2021.108777
DO - 10.1016/j.petrol.2021.108777
M3 - Article
AN - SCOPUS:85105456838
SN - 0920-4105
VL - 205
JO - Journal of Petroleum Science and Engineering
JF - Journal of Petroleum Science and Engineering
M1 - 108777
ER -