Kinetics of CaCO3 Scale Formation During Core Flooding

Abstract

Many oil fields in operation today have major scale control problems, and new insight and know-how in this area are important in order to maximize production at minimal operational costs. The models on mineral precipitation available today are based mainly on thermodynamic data found in the literature. The impact of scale precipitation on well performance, however, is not being accurately modeled due to lack of data on precipitation kinetics. It is therefore important to gain a proper understanding of the kinetics of scale formation and its detrimental effects on porosity and permeability in the near well bore region. A series of core flooding experiments were conducted at 80ºC to investigate CaCO3 scale formation. This paper focuses mainly on the CaCO3 precipitation kinetics data obtained at various flow rates, supersaturation ratios (SR) and substrates. However, permeability and porosity alteration due to precipitation during flow are also presented and discussed. Kinetic data were derived from both continuous pH measurements and determination of the remaining calcium concentration in the effluent. The precipitation rate was very dependent on the amount of CaCO3 already precipitated. The combination of residence time and duration of the experiment determined the effluent SR. After a steady state precipitation rate was reached in a Lochaline sandstone, the SR of the effluent changed from the initial 3.00 to ~1.55 and ~1.15 for core residence times of 1 and 4.5 minutes, respectively. With initial SR = 2.00 the corresponding SRs were ~1.25 and ~1.13 for residence times of 1 and 4 minutes, respectively. A permeability-porosity profile was determined showing that the permeability changed rapidly early in the experiment and was followed by a long period with relatively little change as a function of porosity decrease. Towards the end of the experiment a dramatic decrease in permeability, typical to tube blocking test behavior, was observed. Visualization experiments using two dimensional glass porous medium models showed that when crystals had been formed by nucleation, further precipitation occurred preferably on existing crystals. Introduction International oil and gas industry is facing higher water production as fields mature. Many oil fields in operation today have major scale control problems, and new insight and know-how in this important area will help the industry to maximize production at minimal operational costs. Interventions during scale cleanup in subsea completed wells are expensive and difficult. The demand for better scale control for subsea wells is therefore pressing. Databases on mineral precipitation available today are based mainly on thermodynamic data found in the literature. Although the problem of oilfield scale formation has been studied extensively in the past, the mechanisms of scale precipitation are not fully understood, mainly due to complex precipitation kinetics in the CaCO3 system. The cause of scaling can be difficult to identify before damage has occurred in real oil and gas wells. It is well known that pressure and temperature changes are the primary reasons for the formation of carbonate scales. Carbonate scaling may take place in the formation around the well bore and in the tubing itself, as well as in topside equipment. The CaCO3 scaling tendency increases with increasing temperature and decreasing pressure. The rate of CaCO3 nucleation and precipitation is very dependent on the supersaturation ratio (SR), temperature and the substrates available for crystal nucleation. When precipitation occurs in the near wellbore area, the porosity (f) and permeability (k) will decrease. Even if a field measured relationship between f and k is available, this relationship is probably not valid after scale has formed. It is therefore important to gain a proper understanding of the kinetics of scale formation and its detrimental effects on the relationship between f and k at varying degrees of scale damage porosity in the near well bore region

Geochemical modelling of petroleum well data from the Perth Basin. Implications for potential scaling during low enthalpy geothermal exploration from a hot sedimentary aquifer

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