Inhibition of CaCO3 Precipitation From Brine Solutions: A New Flow System for High-Temperature and -Pressure Studies
Authors: Oddo John E. , Sloan Katherine M. , Tomson Mason R. 
Published: December 2007

The study of calcium carbonate (CaCO3) scale inhibition in geopressured energy systems has led to the development of a flow system with high-temperature and -pressure capability. A high-pressure (performance) liquid chromatograph (HPLC) was modified by the addition of a backpressure valve and by bypassing the HPLC packed column. Solution mixing and temperature are computer-controlled, and CaCO3 precipitation is monitored by in-line pH measurement. Simulated and real brine samples were used to evaluate scale inhibitors, and CaCO3 precipitation was related to the saturation index, Is. The inhibitors that were evaluated and the brine Is with respect to CaCO3 were as follows.

Inhibitor Is ppm Hydroxyethylidenediphosphonic acid (HEDP) 1.87 0.6 Polymaleic acid (PMA) 1.87 0.6 Polyacryic acid (PPA) 1.87 1.0

Introduction

Geopressured energy wells along the U.S. gulf coast region are potentially a major source of natural gas and mechanical and thermal energy for the U.S. These wells are designed to produce approximately 40,000 B/D (6359 m3/d) of high-temperature and -pressure brine saturated with methane and CO2 gases. In operation, the gases are removed from the brine in a separator, and the mechanical and thermal energy may be removed with a turbine and heat exchanger, respectively. Downhole, these brines are generally at thermodynamic equilibrium with CaCO3 in the producing aquifer. As pressure is decreased and gases evolve from solution, pH rises and the brine can become saturated or supersaturated with respect to CaCO3, producing scale in the recovery equipment. To prevent CaCO3 scale formation, either the thermodynamic driving force must be lowered by addition of acids, chelates, etc. or the reaction kinetics must be delayed by various types of inhibitors (for a literature review of scale prevention see Ref. 2). Because of the volume of brine produced per standard cubic foot (2.8 std m3) of natural gas recovered [30 scf/bbl (0.85 std m3/m3)], it is important to minimize the inhibitor dose while maintaining effectiveness. To study the problem of CaCO3 scale inhibition in geopressured energy wells, the parameters of brine flow, temperature, and pressure should be duplicated in the experiments to produce a similar scaling regime. A brief description of the flow parameters in geopressured energy wells considered in the design of the experimental procedure follows. Geopressured systems vary in pressure from more than 13,000 psi (89.6 MPa) in the producing aquifer to less than 1,000 psi (6.9 MPa) in surface equipment. Temperatures vary from over 300 degrees F (149 degrees C) downhole to sometimes less than 212 degrees F (100 degrees C) at the surface. Projected flow rates for geopressured systems are about 40,000 B/D (6359 m3/d) but may be much lower in test wells. The systems consist of a well completed usually between 10,000 and 15,000 ft (3048 and 4572 m) in a sand aquifer large enough to produce at economic flow rates [about 40,000 B/D (6359 m3/d)] for a number of years. Natural gas at depth is essentially totally dissolved in brine solutions. The brine flows to the surface, where the pressure is 4,000 to 6,000 psi (27.6 to 41.4 MPa), trough a choke or series of chokes that reduce the pressure to about 1,000 psi (6.9 MPa), to a gas separator where the gas is recovered. The brine solution continues to a disposal well, usually at a depth of 3,000 to 5,000 ft (914 to 1524 m) (Fig. 1). The temperature varies in the system typically only about 10 to 60 degrees F (22 to 33 degrees C) at full flow because of the high flow rate and the insulation of the surrounding sediment.

JPT

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