Flow Assurance - Scale Basics
Introduction
Scale deposits can vary from mild scaling tendencies to extreme. In general, the scale deposit will reduce productivity and eventually blockage of the wellbore and hence unexpected downtime if it is allowed to persevere. Scale occurs when concentration of salts that are dissolved in formation waters exceeds their saturation points. Pressure, temperature, and pH also play a vital role in scale severity. Scale formation involves four phases, which are aggregation, nucleation, crystal growth, and agglomeration. Aggregation occurs after being super-saturated with salts. Then, aggregates develop into nucleation centers for crystallization while eventually they fuse into macro crystals as agglomerates.
In oil and gas systems, scaling cations usually deposit as Calcium carbonate/sulfate, Barium sulfate, and Strontium sulfate. Sulfates usually occur due to mixing of different incompatible waters such as seawater injection in offshore wells. On the other hand, carbonates are attributed to loss of carbon dioxide from water to HC phase as pressure falls, which is also referred to as self-scaling.
The cost of scale has been estimated at more than USD $1.5 billion per year (Frenier and Ziauddin, 2008). ?In order to mitigate scale formation, different chemicals (naturally occurring and synthetic) are tested in labs and used in oilfields. Chemicals are usually introduced in systems where scale is expected through continuous injection, squeeze techniques or batch treatment. Scale inhibitors are chemical compounds that retard or prevent mineral scale formation. For cost effective treatment, threshold scale inhibitors are preferred. Liu et al. (2012) defined them as ones which inhibit at a concentration below equimolar amounts permitting inhibitors to avoid scale growth at concentration of 1000 times less than a balanced stoichiometric ratio of scaling cations.
Scale Inhibitors
A) Threshold Synthetic Inhibitors (TSIs)
Mpelwa and Tang (2019) reviewed synthetic threshold scale inhibitors (TSIs) and showed that unlike Chelants, which function by sequestration or binding cations to form stable water-soluble complexes, they interact chemically with crystal nucleation and reduce crystal growth rate. The most used TSIs are phosphorous-containing compounds, polycarboxylates or sulfonated compounds. They can be classified into three groups; inorganic phosphates, organophosphorus, and organic polymers. Inorganic phosphates are very effective with both scale and corrosion, however they are limited to high temperatures. Alternatively, organic phosphonates could tolerate high temperatures up to 250 F and could be used for corrosion inhibition as well yet they are more expensive. On the other hand, organic polymers have the advantage of being “green” scale inhibitors as they have the lowest non-desired effect on environment.
B) Scale and Corrosion Inhibitors
Sanders et. al. (2014) discussed that most common techniques focus on assessing ?surface scaling problems solely despite the fact that scaling rarely occurs in environments where no corrosion exists. Alternatively, corrosion inhibitors are usually evaluated independently in systems that do not account for bulk scaling. This could lead to undesired effects since potential antagonistic effects between both chemicals could go unrecognized. Hence, they conducted an experiment to assess the ability of four combined inhibitors to control both calcium carbonates scale and corrosion in environments where both occur simultaneously. ?They mentioned that inhibitors could increase induction time in bulk solutions while they do not prevent scale formation and that proportion of scale depends on the chemicals used. Additionally, they concluded that it was difficult to determine performance of the combined inhibitors on each phenomenon separately since they are sometimes more efficient with scale and sometimes more efficient with corrosion.
C) Effect of Inhibitors on Formation Damage
Amro (2004) studied the possible formation damage of scale and corrosion inhibitors injection into systems where the reservoir contains asphaltenes. The investigation concluded that presence of scale inhibitors does not alter wettability and has no effect on oil/water relative permeability, surface tension, or interfacial tension. Oppositely, corrosion inhibitors showed significant undesired decrease for relative permeability and alters wettability into oil-wet. On the other hand, results showed that corrosion inhibitors mixed with scale inhibitors does not affect relative permeability or wettability of reservoirs containing asphaltene. Thereafter, they recommended the utility of mixed chemicals if corrosion inhibition is desired. They also showed the necessity of lab investigations prior to using any kind of chemicals so as not to reduce well productivity.
References: