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 1
INTRODUCTION
1.1 Overview
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.