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Naphthenate scales and carboxylate soap emulsions have become increasingly evident issues as more marginal crudes are sourced and through greater awareness. These issues are not new but the potential severity and increased occurrence highlights the need for successful management and the importance to field development and expansion. This paper provides a comprehensive and up-to-date resource for successful management of naphthenate/carboxylate issues. The paper is aimed at development projects, during flow assurance assessments as well as existing operations trying to manage naphthenate/carboxylate issues, and attempts to bring together all available information to provide a holistic approach to management.
There is a number of different control approaches published in the literature and in the author's experience. No definitive solution has been identified but this paper provides a review of varying strategies for mitigation that if appreciated early or even later in production life, can result in successful management. Previously, operational problems caused by naphthenate/carboxylate have occurred in production facilities, which then require remedial efforts and significant chemical treatment. As more knowledge is available, effort has been applied to the development stage through new innovative system designs. These combine identification and understanding with process design, operational practices, chemical treatment and remedial efforts. No particular approach is more effective but should be tailored to the development and how the problem manifests itself. Equally there is no ‘magic-bullet' currently to these problems but nevertheless, with good understanding and considered application of different approaches, these naphthenate/carboxylate problems can be successfully managed.
Nichols, D.A. (Scaled Solutions Ltd.) | Rosário, F.F. (Petrobras) | Bezerra, M.C.M. (Petrobras) | Gorringe, S.E. (Scaled Solutions Ltd.) | Williams, H.L. (Scaled Solutions Ltd.) | Graham, G.M. (Scaled Solutions Ltd.)
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 CO2 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.
Graham, Gordon M. (Scaled Solutions Limited) | Melvin, Keith Buchan (Talisman Energy UK Limited) | Gabb, Alexander Emil (British Gas Intl.) | Haider, Faheem (BG Group plc) | Williams, Helen (Scaled Solutions Limited) | Dyer, Sarah (Scaled Solutions Limited) | cummine, Craig (Talisman Oil)
A laboratory methodology has been developed to better simulate calcium naphthenate formation and evaluate chemical inhibition measures. Detailed ongoing field experience data and related samples have been used in support of the lab rig design and protocols. Calcium Naphthenates are becoming more recognized as a major flow assurance issue. When occurring in the field operation, significant quantities (typically in tonnes per day) can be formed and the process operation, chemical controls and monitoring procedures are far from straightforward. The ability to accurately predict calcium naphthenate formation and/or replicate field production conditions in the laboratory has been fraught with difficulties. For example conventional "bottle?? or "jar?? test procedures suffer from severe limitations relating to poor pH control, inefficient mixing, non representative residence times coupled with relatively indirect assessments often indicating fluid compatibility issues rather than identification of naphthenate deposits.
Recent work examining both current calcium naphthenate problems in existing facilities and the technical requirement to predict the potential for naphthenate deposits in new fields has led to the design and validation of more appropriate laboratory test equipment. This includes new designs of novel dynamic flow systems and modified autoclave approaches which allow the formation of naphthenate deposits, stable emulsions and soap scales to be assessed directly under laboratory conditions using relatively small volumes of reservoir fluids. The designed equipment is shown to overcome the challenges previously associated with the assessment of calcium naphthenate issues, their mitigation and chemical treatment under laboratory conditions.
The ability to simulate naphthenate deposition represents a major step forward in our ability to understand the controlling parameters associated with these complex scales. This paper will describe the novel aspects associated with the laboratory flow rig and other test methods adopted, it will illustrate how the equipment design overcomes the limitations associated with more conventional tests and describe how the results are being used directly to assess the changing naphthenate challenge and its treatment which may be expected throughout a field's lifetime. The composition of solids collected from naphthenate formation tests in the flow rig under different conditions is also presented, thus further validating the effectiveness of the rig design. The paper therefore illustrates how improved equipment design and test protocols can reduce the risks associated with field trials, which have previously been required for optimising treatments against naphthenate deposits.
Although the presence of naphthenic acids in crude oil and their impact on emulsion stability and the formation of sludges, soaps, stabilised emulsions and other production problems have been known for many decades, little direct evidence of calcium naphthenate deposits has been reported until relatively recently. Over the last 10 years the problem of calcium naphthenate deposits has become an increasing problem, especially for fields producing oils which have been subject to biodegradation resulting in relatively low wax contents and high dissolved naphthenic acids. An increasing number of fields especially in areas such as West Africa, the North Sea and Venezuela[1,2,3] have therefore reported problems leading to several literature references over recent years as their formation represents a significant flow assurance issue for several major field developments. Sodium naphthenate sludges have also been observed in Indonesian fields[4-6] in addition to bicarbonate and metal ion stabilised naphthenate sludges.  As the solution to a naphthenate problem is often required urgently and as this is a relatively novel area of research, most work to date has focussed on specific fields and the problems encountered in these fields, although some work has progressed over recent years to consider the generic problem and to rationalise and unravel the relative importance of the various factors involved in this complex reaction system (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.).[7-9,19]
Soap deposits, which can manifest as emulsion soaps (carboxylates) or hard deposits (naphthenates), are an increasingly recognized cause of some unique flow assurance and crude marketing problems in oilfield processes.This paper illustrates the physical and chemical drivers for the generation of soap scales in a number of differing and challenging production system environments.Mitigation options for the successful treatment of soap scales are also discussed. Where possible, data presented in this paper are taken from field trials in order to illustrate these drivers and the impact of successful mitigation strategies.
An understanding of the key fluid characteristics allows pre-screening of fluids from new field developments that are likely to develop naphthenate/soap deposits and allows diagnosis ofthe likely soap scaling problems. The critical fluid characteristics required for the generation of naphthenate soaps are different from those required for generation of carboxylate soaps.An empirical approach to predicting the degree of risk for soap generation, based on oil and produced water properties, can be adopted, although there are knowledge and data gaps that increase the uncertainty of this approach.
Physical parameters, such as pressure, are known to influence soap generation. However, other physical parameters that are key in the design and operation of an oil-field process can also influence the soap severity. These parameters include temperature, shear, electrostatic fields, water cut and fluid-fluid incompatibility; examples of each are discussed. This information can be used in the design stages of an oil-field process where engineers must think beyond the conventional process designs.
Despite the fact that the impact of a soap problem can be considerably reduced by adjustment of physical design and operating parameters, chemicals are usually required to provide complete mitigation of soap. Chemical mitigation (acid and non-acid) guidelines are discussed with field examples and the need for a chemical management and monitoring programme.
The formation of calcium naphthenate solids and stabilised emulsions continues to be a major flow assurance issue. The ability to replicate the conditions under which naphthenates form in the laboratory has, until recently, been an unresolved challenge. Recent work by the authors has resulted in improved test methodologies, utilising a novel flow rig. The rig enables the study of the formation and control of naphthenate solids and stabilised emulsions under field-representative conditions, and allows the prediction and control of their occurrence in the varying production conditions that may be experienced over a field's lifetime.
This paper describes the use of the flow rig to test a number of crude systems, some of which have known calcium naphthenate problems, and some of which are known to have no calcium naphthenate issues. The results from the flow rig have been compared with field observations and show excellent correlation. Data is then presented which more directly assess the influence of a number of variables, such as water-cut, brine composition, bicarbonate level, and pH, on emulsion stability and naphthenate formation than has previously been possible under conventional laboratory test methodology. This work therefore extends our understanding of "practical?? naphthenate formation.