Why Scale Forms in the Oil Field and Methods To Predict It

Abstract

Summary Predicting potential scaling problems can be difficult, and numerous saturation indices and computer algorithms have been developed to determine if, when, and where scaling will occur. The Langelier, Stiff-Davis, and the Oddo-Tomson saturation indices, all widely used in the oil field, are compared and contrasted relative to calcium carbonate scale. New saturation indices for barium, strontium, and calcium sulfate scale formation are introduced and discussed, along with an updated version of the Oddo-Tomson calcium carbonate index. An updated version of the CaC03 saturation index is presented that includes correction terms for fugacity effects and changes in the solubility of CO2 in oil and gas wells as functions of temperature, pressure, water cut, and hydrocarbons present. The CaC03 saturation index does not require a measured pH and can accommodate the presence of weak acids, such as H2S, and weak organic acids in the system. The sulfate scale prediction methods (for gypsum, hemihydrate, and anhydrite) are easy to use, reliable, and designed for field use by an operator who may be untrained in chemistry. The prediction methods can be applied to any production well where calcium carbonate, calcium sulfate, strontium sulfate, or barium sulfate scale occurs. Introduction and Need for Improvements As the petroleum industry produces more water to recover hydrocarbons more efficiently from existing fields, scale formation and corrosion will become increasingly difficult problems. Calcium carbonate and sulfate scale problems are incipient to some fields but also occur where incompatible waters are introduced to the production scheme during waterfloods or workovers. A general discussion of saturation indices and sulfate and carbonate predictive equations are given later. The sulfate scales of Ca, Sr, and Ba are well described. However, the chemistry of the individual scale formers is described briefly, along with supporting field application to lend credibility to the predictive equations developed here.

Experimental and Theoretical Study of Calcium Sulphate Precipitation in Porous Media Using Glass Micromodel

“…Inorganic scaling is a process of deposition of scales from aqueous solutions of minerals, referred to as brines, when they become supersaturated as a result of alteration of their thermodynamic state and chemical equilibria [13,14]. In the following section, some key terms regarding the process of calcium sulphate deposition are given.…”

“…The variations of permeability versus pore volumes of injected fluid were measured by applying Darcy's law for single phase flow: (13) Solving Equation (13) for K yields: (14) Bu and Damsleth [20] introduced the uncertainties in permeability measurements as follows: (15) Δμ, ΔL, ΔA, ΔQ, ΔP represent the errors or uncertainties associated with these quantities. The accuracies and errors associated with the experimental equipment are given in Table 4.…”

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

“…Oddo et al (1991); Oddo and Tomson (1994) showed that the formation of calcium sulfate scale depends on temperature and does not depend on pH and can precipitate at low as well as high pH values. In the case where water injection (seawater, river, aquifer, or produced water) is used for pressure maintenance and sweep, the mixing of incompatible aqueous solutions can lead to the formation of sulfate scales when the injection water contains sulfate ions (Mackay and Jordan 2005).…”

Rational Development of New Cooling Water Chemical Treatment Programs for Scale and Microbial Control

“…[8][9][10][11] Initial electrostatic interaction of dissolved anions and cations is the genesis of ion pairs that sequentially act as "building blocks". They later assemble to form larger aggregates.…”