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AN EXPERIMENTAL MODEL TO PREDICT AND CONTROL OILFIELD EMULSION TIGHTNESS: A NOVEL APPROACH

ABSTRACT

Formation of water-in-oil emulsions are among the major challenges encountered by production and surface facilities engineers during the recovery of crude oil, especially in a large multi-wells system in both onshore and offshore oilfields. The development of systematic approaches to handle emulsion problem has been very slow. Several important aspects of emulsion that have not being studied extensively to date include mechanism, kinetics and energy levels associated with emulsion formation. Such information is needed to understand the emulsification process, model it and hence solve lots of operational and economical emulsion issues. This study presents a novel experimental approach to model the process of water-in-oil emulsion formation and also study the shearing energy levels associated with its formation. Oilfield emulsions were simulated using agitator rated between 0 to 1000 RPM. Mixture of crude oil, formation water, asphaltene, inorganic solid, scale precipitates and reservoir fines were agitated at various revolutions to form the emulsion. The emulsions that result were stabilized using re-solubilized asphaltene precipitated out of the crude oil. A demulsifier chemical sample was used to properly treat over 300 bottle samples, and the rate of separation of their emulsified water was used to determine their tightness. Relationship between shearing energy at the wellhead chokes, pressure drop across it, and its size was first developed. This equation relates the production rate, type of the crude oil produced and the nature of the choke during production to shearing energy. The results from the experiments show that increase in the fraction of the dispersed water phase in an oil-water mixture, leads to formation of tight emulsions. This relationship existed until the point of inversion from water/oil emulsion to oil/water emulsion is reached at 60% watercut, and loose emulsions will start forming. Also asphaltene was seen to contribute tremendously to the formation of tight emulsions. At 2.9% concentration of asphaltene the emulsion becomes more difficult to treat, with a tightness of 18 %. Inorganic solids-sodium bentonite and calcite demonstrated little effects on emulsion stability. Further studies were carried out to study the wettability effect of asphaltene on the inorganic solids and consequently their stabilizing effect on emulsion. Result shows that these solids behaved as very strong emulsifiers when coated with asphaltene. Results from the second set of experiment shows that shearing energy, asphaltene concentration and water-oil-ratio are major factor that determines the formation of tight emulsion. A particular shearing energy threshold (SET) value is needed to form emulsion for a specific water oil ratio, regardless of the concentration of asphaltene present. Lots of interesting trends relating watercut, asphaltene content and shearing energy are seen from the results in this study, and hence could be used to predict and rank emulsion samples according to their tightness. The emulsion diagnostic plots (EDP) produced were digitized and best line of fit for each of the data series plotted was gotten and their corresponding equations generated. These equations were then developed into a java executable application, EMULS-K. This application was used to analyse the emulsion problem in an oilfield of a major operator in Niger Delta. EMULS-K program generated values of emulsion tightness (ET) for all the 21 wells in this field and hence spotted out the problematic ones. The result obtained from this analysis correlates perfectly well with those gotten by a service company using the old bottle test approach.

CHAPTER ONE

INTRODUCTION

1.1  Background to the study

Crude oil is seldom produced alone from reservoirs. It is always produced as a complex mixture of hydrocarbons and formation water.1 These mixtures undergo extreme agitation under high shear rate and turbulence as they flow from the reservoir pores through perforated casing into the wellbore, to the tubing and finally through the surface production facilities. This occurrence causes the water phase to be dispersed and stabilized as fine droplets in the bulk oil phase and hence forms emulsion. Emulsion is among the many problems encountered in the production, transport, and refining of crude oil and dealing with this complex structural arrangements account for much of the expenses incurred by oil companies in their daily operations.2 Their control and resolution is among the major challenges encountered both onshore and offshore by production engineers, production chemists and facilities engineers during production, especially in a complex multi-wells system. Emulsion problems are usually more problematic in fields where heavy crude oils are produced.3

Emulsions are stabilised by rigid interfacial films that forms a ‘’skin’’ on the water droplets and prevents them from coalescing.4 The stability of these interfacial films, and hence the tightness of the emulsions, depend on a number factors, including the heavy materials present in the crude oil (e.g. asphaltenes, resins, waxes), inorganic solids (e.g. clays, scales and corrosion products), temperature, droplet size and droplet size distribution, pH and brine composition.5 As the producing field depletes, the nature of petroleum emulsion changes continuously due to changes in some of these factors and production methods.5 Produced oilfield emulsions can be water-in-oil (W/O), oil-in-water (O/W) or multiple water and oil in water (W/O/W), but most produced oilfield emulsions are of the W/O type.1 This depends on several conditions, which include but not limited to: fraction of each liquid phase, hydrophilic-Lypophylic balance (HLB) etc. From a purely thermodynamic point of view, a W/O emulsion is an unstable system. This is because there is a natural tendency for a liquid/liquid system to separate and reduce its interfacial area and hence, its interfacial energy. However, most oilfield emulsions are stable over a period of time (i.e. they possess kinetic stability).1,4 Produced oilfield emulsions have been classified on the basis of their degree of kinetic stability.5 According to this, oilfield emulsions have been classified as loose, medium and tight emulsions. Loose emulsions separate in a few minutes, medium emulsions separate in ten minutes or more, while tight emulsions will separate in a matter of hours or even days.5

Emulsions from several production headers in the oilfield are usually commingled at the manifolds and then transported to the central processing facilities for treatment. They are usually very difficult to treat and cause a number of operational problems, such as overloading of surface separation equipments with water, increased cost of pumping wet crude, increased heating cost, tripping of separation equipments, high pressure drop in lowliness increase in cost of demulsifiers, production of off-specification crude oil, thick sludge in stock tank bottom, corrosion in export and subsea pipelines, catalyst poisoning at refineries and sometimes force the shutdown of processing equipments in the Wet Crude Handling Facility (WCHF).7 The overall effect of this is a significant loss in production and loss of revenue to the operators.

Different treating methods thus exist in the petroleum industry for demulsification of crude oil. They include thermal methods, mechanical methods, electrical methods and chemical treatment.8 In general, these methods are interrelated. Applying heat to the emulsion reduces the viscosity of the oil and increases the water settling rates. It also results in the destabilisation of the rigid films caused by interfacial viscosity. Application of heat for emulsion breaking should be based on an overall economic analysis of the treatment facility. Furthermore, some of the mechanical equipment available in the breaking of oilfield emulsions include free-water knockout drums, phase separators etc. High voltage electricity is also often used for breaking emulsion.6 It is generally theorized that water droplets move more rapidly when induced with an electric field, and hence collide with each other, and coalesce. The distance between the electrodes in some designs- is adjustable so that the voltage can be varied to meet the requirement of the emulsion being treated.1 By far; the most common method of emulsion treatment is adding chemicals. Demulsifier chemicals account for approximately 40% (in value) of the world oilfield production chemical markets.9 They are deployed at virtually every crude oil processing station worldwide. Chemical additives, recognised as the second ‘‘aid’’, are special surface active agents that migrates to the water – oil interface once added to the emulsion.