Previous results from a new laboratory test rig designed to mimic calcium naphthenate deposition under Blake field conditions were presented in 2006.1  This paper demonstrated that the equipment and test protocols adopted were able to replicate field conditions and allow selection and optimisation of calcium naphthenate inhibitor treatments prior to field trials.

Since this paper, further work has been conducted, both to further optimise field treatments using different naphthenate inhibitors and also to examine the interplay between different acids, inhibitors and demulsifiers in tackling these complex, and often field specific, problems. In summary the use of appropriate selected and optimised calcium naphthenate inhibitors in conjunction with acid treatments (pH 6.1) has led to efficient naphthenate control in the field over the past 2 years with minimal production upsets. Important considerations with respect to the selection of different, less volatile, organic acids primarily to minimise the risk of corrosion in the gas phase process lines has indicated significant differences in the performance of the naphthenate inhibitors and the stability of the emulsion when changing the nature of the acids used to control the in-situ pH. The work has also shown that different naphthenate inhibitors work via different mechanisms. The work then illustrates, under field representative conditions, the close interplay between acids, calcium naphthenate inhibitors and demulsifiers, and sheds further light on the mechanisms by which different calcium naphthenate inhibitors perform.

The work continues to support field treatments on the Blake field and direct comparisons between the laboratory and field results will be described.

The formation of calcium naphthenate precipitates and emulsions during oil production is becoming an increasing problem to the global oil industry. They have been identified in many highly productive fields across the world, particularly in fields in West Africa, the North Sea and Venezuela. Controlling the formation of naphthenate deposits involves the use of high volumes of acid and other treatment chemicals. Due to the nature of the problem, treatments are usually field specific, and re-optimisation is often required throughout the production lifetime of a field, as conditions (for example, water cut) change.

Naphthenic acids, R-CO2H are present in many crude oils, normally owing to in-situ biodegradation of oils under appropriate reservoir conditions. They are common in heavy, high TAN crudes, but are also found in light crudes with relatively low TAN values. It is the nature of the naphthenic acids present in the oil phase, and the brine composition in the field, along with the associated production conditions, that determine whether or not naphthenates will occur. Calcium naphthenate deposition is often associated with fields producing heavy, high TAN crudes, but the problem is not restricted to these fields. The solution to a naphthenate problem is often required urgently and most work to date has focussed on specific fields and the problems encountered in these fields. Over recent years work has progressed in a more generic way to rationalise the relative importance of the various factors involved in the formation of calcium naphthenate solids and stabilised emulsions (e.g. amount and type of naphthenic acids present in the oil phase, emulsion stability, interface activity, metal cations (particularly Ca and Na), bicarbonate concentration and pH in the brine phase, water cut and system temperature etc.).2-6 

Naphthenic acids have the typical structure R-CO2-H, where R is may be a saturated cyclic structure,7, 8, 9-13  or a long-chain aliphatic compound.14  Robbins13  states that naphthenic acids are C10-C50 compounds with between 0 and 6 fused, saturated rings with carboxylic acid group(s) attached to a ring with a short side chain. However, negative ion electron spray mass spectrometry (ESMS) has indicated the presence of naphthenic acids as small as C7 in various calcium naphthenate samples. On the other hand, Baugh et al15  have identified the ARN acid as the dominant constituent in calcium naphthenate deposits from oilfields offshore Norway, Britain, China and West Africa. The ARN acid is a family of 4-protic carboxylic acids containing 4-8 rings in the hydrocarbon skeleton with molecular weights in the region 1227 – 1335g/mol. Goldszal et al.7  have proposed some theoretically determined structures of naphthenic acids and it is considered that the carboxylic acid groups are attached to an alkyl chain (both straight chain and branched) rather than directly onto the ring structures. In general naphthenic acids can be considered as organic carboxylic acids present primarily (at least initially) in the oil phase.

When crude oils are in contact with formation water the naphthenic acids tend to congregate at the oil-water interface due to the hydrophilic nature of the carboxylic acid group. The pH of the brine affects the level of dissociation of the naphthenic acids. As the pressure drops during production and carbon dioxide is lost from solution, the pH of the brine increases. The dissociated naphthenic acids can then complex with the sodium and calcium ions in the formation water. Low molecular weight sodium soaps (NaRCO2) tend to pass into the water phase, although large amounts can form a sodium-rich soap sludge, which is hard to remove without treatment16, 17 . As calcium is a divalent ion it will complex with two naphthenate ions. Calcium naphthenates will therefore be more lipophilic and preferentially go to the oil phase or the oil/water interface. When the calcium naphthenate concentration exceeds the solubility, precipitation of solid or formation of emulsion will occur.

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