Calcium Naphthenates in Complex Production Systems - Evaluation and Chemical Inhibition Challenges

Abstract

Over the last 15 years, much research and many field application studies have led to considerable improvement in our understanding of the formation and mitigation of calcium naphthenate deposits.In this field example, calcium naphthenates and stable emulsions are formed following mixing of fluids from different reservoir formations on a single FPSO. High TAN crudes containing low levels of ARN produce with low calcium formation waters whereas low TAN crudes are associated with high calcium formation waters. Mixing of these two systems has led to calcium naphthenate deposition and associated problems with its removal.This paper outlines the challenges in this complex deepwater subsea production system and the interpretation of the cause of the deposit. A series of laboratory tests using a specialised flow rig were conducted to illustrate the effects of mixing different fluids and identify those mixtures with the largest naphthenate potential.The work further illustrates the effect of bicarbonate ions on the system. Laboratory tests at low levels of bicarbonate (to prevent carbonate scaling at separator conditions) do not result in calcium naphthenate formation when mixing the high TAN crude with the current produced brine (moderate calcium). Naphthenates only formed when mixing with the high calcium brine. When bicarbonate is included at full field levels (in the presence of a scale inhibitor) significant calcium naphthenate formation is recorded with the lower calcium brines. The effect of CO 2 within the produced fluids has also been evaluated.The paper describes how several variables contribute to the likelihood of calcium naphthenate deposition and presents results from several naphthenate formation and inhibition tests covering a range of fluid compositions and mixtures. Chemical qualification in the lab using the worst case fluid mixtures has been conducted to select a calcium naphthenate inhibitor for field deployment. Field trials demonstrate both the effectiveness of the treatments and also the qualification exercise conducted for this field.The results further indicate the complexity of accurately predicting a calcium naphthenate risk while illustrating that, even under challenging conditions, chemical inhibitors are effective in this system.

Oilfield metal naphthenate formation and mitigation measures: a review

“…A class of C 80 -C 82 tetraprotic naphthenic acids having molecular weight between 1227 and 1235 g/mol have been identified (Smith et al 2007;Baugh et al 2005). Also known as C 80 -tetraacids (C 80 -TA) or ARN acid (an allusion to their unique structural and molecular properties), they occur in low concentration (0.6-3.6 ppm) in oil but are the predominant acids in calcium naphthenate deposits (Juyal et al 2015;Nichols et al 2014). ARN acids have 4 to 8 rings in their structure.…”

“…Naphthenic acids are sparingly soluble in water except the very low molecular weight members (Havre et al 2002). The extent to which naphthenic acid dissociates depends on the pKa and partitioning coefficient of the individual acids (Nichols et al 2014). The partition coefficient is a function of the pH, concentration and structure of the acid (Havre et al 2002).…”

“…Apart from emulsion stabilization, the most notable flow assurance problem associated with sodium carboxylate soaps is the formation of sludge. Sludge formation begins when the amount of the fairly hydrophilic carboxylate soap exceeds its solubility limit (Nichols et al 2014;Junior et al 2013). Sludge is a highly viscous, paste-like carboxylate/bicarbonate-stabilized emulsion containing entrained solids such as sand, mineral scale and corrosion products.…”

“…This effect is related to the emulsion stabilization ability of bicarbonate. In a field simulation test, it was observed that despite relatively low pH, CaN formation increased due to the increase in bicarbonate concentration (Nichols et al 2014). This means that calcium naphthenate may precipitate at untypically low pH values if bicarbonate content (and calcium content) of the brine is high.…”

“…The low-level dissociation of tetraacid at low pH is sufficient to produce calcium naphthenate deposition due to the emulsion stabilizing effect of bicarbonate. Bicarbonate content of oil may increase by commingling of fluid or can be contributed by residual CO 2 in the separator (Nichols et al 2014).…”