While barium stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium, strontium and barium ions, this paper presents evidence for in situ sulphate stripping in a sandstone reservoir. The formation brine composition suggests that a moderate to severe barite scaling tendency will require inhibitor concentrations in the range of 10–50 ppm to control scale, but in practice concentrations < 5 ppm are adequate. Investigation of the produced brine compositions has revealed that this is due to much lower sulphate concentrations in the produced brine mix than would be expected purely from dilution of seawater with the formation brine. The question this paper addresses is what has caused this reduction in sulphate concentration. The formation brine Mg/Ca ratio is < 0.1. Over geological time frames, the reservoir rock and formation brine will come into chemical equilibrium, the Mg/Ca and Na/Ca ratios in the brine being dependent on the respective ratios in the rock matrix. However, when seawater is injected, this equilibrium is disturbed. Since the Mg/Ca ratio for seawater is ∼ 3, to re-equilibrate an ion exchange mechanism causes magnesium to be retained from the brine phase onto the rock, and in return calcium is released from the rock into the brine phase. This is confirmed by lower than expected magnesium concentrations in the produced brine. The impact of the calcium release into seawater as it is displaced through the hot reservoir is to cause precipitation of calcium sulphate, this process resulting in the observed sulphate stripping. This analysis is supported by the field data and by reactive transport calculations. Implications are drawn for scale management in this and similar fields with high formation water calcium concentrations. Introduction The Gyda field lies on the north-eastern margin of the North Sea Central Trough, on the Norwegian Continental Shelf, 270 km (168 miles) southwest of Stavanger and 43 km (27 miles) northeast of Ekofisk Centre. The offshore installation comprises a conventional 6-legged steel jacket which supports integrated production, drilling and living quarters. Peak oil production topped 20,100 m3/day (126,000 stb/day) during 1993. Gyda is currently operated by Talisman-Energy Norge A/S (61 %) on behalf of DONG (34 %) and Norske AEDC A/S (5 %). It was originally operated by BP Norway Ltd., and when it came on stream in July 1990, it was the deepest, hottest and lowest permeability oilfield in the North Sea[1]. Gyda receives limited aquifer support and is developed by waterflood. There are 32 well slots of which currently 15 are for producers with a further 10 wells dedicated to water injection. From the outset it was recognised by BP that the formation water / injection water mix would lead to a severe scaling tendency[1]. The current operator, Talisman, have sought to review the scale management process to ensure that any lessons that can be learned from analysis of the earlier stages of production may be applied to ensuring effective scale control to the end of the field life cycle. It is the results of that review process that are presented in this paper. Reservoir Description and Field Development Gyda hydrocarbon reserves are contained in Upper Jurassic shallow marine sands. Reservoir depth is 3,650 - 4180 m (11,975 - 13,665 ft) subsea, initial temperature was 160 °C at 4,155 m (320 °F at 13,362 ft) and initial pressure was 604.5 bar at 4,155 m (8,768 psia at 13,362 ft). Some areas of the reservoir are heavily faulted, while others are moderately faulted. The sands are bioturbated, and in areas they are interbedded with calcite stringers. The field is divided into three regions, main field, the South-West and Gyda South with different PVT regions. The main field has a dip-closure in the western parts, called the C-sand area. The crest area has closure in the east by the Hidra fault system while it pinches out to the south. The downdip area has closure to the south by a Triassic high, while the southern area (Gyda South) is a tight rollover on the western bounding fault of the horst block. The field is moderately faulted (Fig. 1), and production has demonstrated that communication in some reservoir layers is good. Nevertheless, several distinct field compartments are defined from pressure data, and geochemical data from Gyda South indicate that sealing faults controlled the filling and cementation history[1]

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

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. Introduction 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[1] 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. [20] 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]

No abstract

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.Naphthenic acids are defined as having the structure R-CO 2 -H, where R is often considered to have a saturated TX 75083-3836, U.S.A., fax 01-972-952-9435.