Studies of Some Physical Properties of Sudanese crude
oil
By
Hiba Abdalla Mahgoub Ahmed
A thesis submitted in fulfilment for the requirements of the degree of Master of Science
(Chemistry)
Department of Chemistry
Faculty of Science
University of Khartoum
2003
Central Petroleum Laboratories
Ministry of Energy & Mining
Khartoum
Contents
Page
Acknowledgement
i
Abstract
ii
Abstract in Arabic
iii
Chapter one: Introduction
1
1.1 Origin of petroleum
1
1.1.1 Classification of petroleum
1
1.2 Types of wax
5
1.2.1 Natural wax
6
1.2.2 Synthetic wax
6
1.2.3 Petroleum wax
7
1.3 Industrial uses of petroleum waxes
11
1.4 Wax problems in crude oils
11
1.4.1 Wax production problems
13
1.4.2 Wax transportation problems
14
1.5 Wax problems in Sudanese crude oil
17
1.6 Control of paraffin deposition
17
1.6.1 Mechanical
18
1.6.2 Solvent
19
1.6.3 Heat
21
1.6.4 Chemicals
22
1.6.5 Bacteria treatement
27
1.7 Some properties of waxy crudes affecting wax deposition
28
1.7.1 Pour point and cloud point
28
1.7.2 Viscosity
30
1.7.3 Wax content and wax fractions
32
Chapter two: Experimental
36
2.1 Measurement of wax content
36
2.1.1 UOP method 46-64
36
2.1.2 UOP method 46-85
38
2.1.3 Acetone precipitation technique
40
2.2 Wax fractions
41
2.3 Gas chromatography analysis
43
2.4 Oil content of petroleum wax
46
2.5 Pour point
51
2.6 Viscosity measurement
55
Chapter three: Discussion
57
References
78
Appendix (A)
Appendix (B)
Appendix (C)
Acknowledgments
I would like to express my thanks to my supervisor Dr. Hisham G. A. Lutfi for
his advice and guidance during the execution of this work. Thanks are also to
Professor Mustafa H. Ishaq, my co-supervisor for his support and helpful
suggestion.
Special thanks and gratitude are due to Mustafa Kamal Eldeen (senior analyst,
Heglig laboratory) for supplying the fluid samples from Heglig region and for
advice in experiments and data collection.
My thanks are also extended to the Central Petroleum Laboratories (CPL),
Ministry of Energy and Mining for permission to perform all experimental work
in their laboratories. Also I wish to extend my deep thanks to the CPL staff for
their help and assistance during the fulfillment of this work.
Thanks are also expressed to the faculties of Science (chemistry department),
and Engineering and Architecture (mechanical engineering department) of the
University of Khartoum.
I would like to thank the following personnel for their contributions and
generous support, Mubark Mahi Eldeen, Marwa Mohammed Adam, Faisal
Abood, Mazen Mohammed, Dr Ibrahim I.A Yousif, Dr Taj Elser Ahmed,
Abdalla Mohammed and A. Subai.
CHAPTER ONE
INTRODUCTION
1.1 Origin of petroleum
The word petroleum is derived from the Latin petra (rock) and oleum (oil), and
by modern definition includes hydrocarbons found in the ground in various
forms from the solid bitumen, through the normal liquids, to gases. The origin of
petroleum has been the subject of many postulations in the past. However, it is
generally accepted that it is derived from organic material, such as marine
animal organisms and plant life, which have been buried in the earth by the
deposition of sediments. Among the theories advanced to account for the
transformation of organic materials to crude petroleum are the effects of heat,
pressure, time, combinations of these, bacterial action, low temperature
catalysis, or of radio-activity.
Crude oils vary from country to country and from field to field. In colour they
range from brownish-yellow to black, some are viscous others are limpid, while
a few carry paraffin wax in suspension. However, whatever their appearance and
origin, crude oils consist almost of compounds of carbon and hydrogen with
varying small amounts of organic sulphur, nitrogen and oxygen compounds, and
ash (George Sell, 1963).
1.1.1 Classification of petroleum
Petroleum is the world's major source of energy and is a key factor in the
continued development of world economies. It is essential for future planning
that governments and industry have a clear assessment of the quantities of
petroleum available for production and quantities which are anticipated to
become available within a practical time frame through additional field
development, technological advances, or exploration. To achieve such an
assessment, it is imperative that the industry adopt a consistent nomenclature for
assessing the current and future quantities of petroleum expected to be recovered
from naturally occurring underground accumulations. The terminology used in
classifying petroleum substances and the various categories of reserves have
been the subject of much study and discussion for many years. Attempts to
standardize reserves terminology began in the mid 1930s when the American
Petroleum Institute (API) considered classification for petroleum and definitions
of various reserves categories. Since then, the evolution of technology has
yielded more precise engineering methods to determine reserves and has
intensified the need for an improved nomenclature to achieve consistency
among professionals working with reserves terminology. Two density related
properties of oils are often used: specific gravity and API gravity. specific
gravity (or relative density) is the ratio, at a specified temperature, of the oil
density to the density of pure water. The API gravity scale arbitrarily assigns an
API gravity of 10o to pure water. The API gravity is calculated as:
API gravity
141.5
= ----------------------------------Specific gravity at 60/60 oF
-
131.5
It is necessary to classify crude oils according to their physical properties
because these properties indicate what yields may be obtained for specific
boiling point fractions. Also, the physical properties such as average boiling
point, specific gravity, and viscosity indicate concentrations of impurities like
sulfur, nitrogen, and oxygen compounds. Concentrations of impurities, ability
to flow, and average boiling points govern the value of a crude oil.
Usually petroleums are classified according to their density and the density of
key fractions. According to their density they are classified as light, mediumheavy and heavy as shown in table 1. The density is measured at 15.56 ºC.
Table 1. Classification of petroleum according to density
Density ºAPI
Classification
> 34
Light
34-20
Medium-heavy
< 20
Heavy
The higher the API gravity, the lighter is the crude and the
greater is the yield of light and middle distillate fractions, which
are more valuable, and the lower is the yield of atmospheric
residue, which is less valuable.
Petroleums can be classified according to the group. Petroleums contain four
groups of hydrocarbons: alkanes (paraffins), cycloalkanes (naphthenes),
aromatics and naphthenoaromatics (complex hydrocarbons). There is another
class of hydrocarbons which needs to be considered, namely the olefins. These
are rarely found in crude oils, and only in traces, but they are prepared by
various refinery processes to satisfy the requirements of the expanding
petroleum – chemical industry. There are six classes or sub-classifications that a
crude may fall under depending on its composition (Hans-Joachim et al, 1981):
1. Pariffinic crudes those have paraffins + naphthenes > 50%, Paraffins
> naphthenes, or paraffins > 40%.
2. Naphthenic crudes have paraffins + naphthenes > 50% or naphthens >
paraffins, or naphthenes > 40%.
3. Paraffinic-naphthenic crudes have aromatics < 50%, paraffins < 40%
and naphthens < 40%.
4. Aromatic napthenic crudes have aromatics > 50%, naphthenes > 25%
and paraffins < 10%.
5. Aromatic intermediate crudes have aromatics > 50% and paraffins >
10%.
6. Aromatic asphaltic crudes have naphthenes > 25% and paraffins <
10%.
The downstream oil industry in Sudan is an important sector in the country's
economy. The completion of Al Gaily refinery has made Sudan largely self
sufficient and able to export crude and refined products including jet fuel. The
industry is regulated by the Ministry of Energy and Mining. The Ministry of
Finance and Planning is also involved in the energy sector. Its representatives
are members of the Petroleum Affairs Board which is responsible for final
approval of petroleum contracts. The Sudanese crude oil is sweet, waxy in
character, has an average API degree of 34.1 and 0.07 W/W sulphur. The
paraffinic nature of the crude makes it a good feedstock for lubricating oils. The
differences of crude oil prices are based upon: their API gravity differentials,
their freight rate differentials and other disparities, e.g., sulphur content, wax
content and metal content, etc. The higher the API gravity, the higher is the
price of the crude. The difference of price per degree difference of API gravity
is approximately 6 cents per barrel.
The presence of substantial quantities of wax and high molecular weight
materials in Sudanese crude oil has prompted the undertaking of the present
studies with a view of overcoming the problems that such components have in
production, transportation, handling, storage and refining.
Paraffin was first produced commercially in 1867 as a refined petroleum
product composed of a mixture of saturated straight chain hydrocarbons.
Production involved separation by distillation followed by chemical treatment
and decolorization. In 1954 the German society for fat technology stated that:
‘wax is the collective term for a series of natural or synthetically produced
substances that normally possess the following properties: kneadable at 20 ˚C,
brittle to solid, coarse to finely crystalline, translucent to opaque but not glass
like, melting above 40 ˚C without decomposition, of relatively low viscosity
even slightly above melting point, not tending to stringiness, consistency and
solubility depending on temperature, capable of being polished by slight
pressure’. In 1970, wax had been defined as ‘an organic substance of medium
molecular weight and contains molecules which crystallize easily and have
sufficient Van der Waal’s attractive forces to form crystals with a melting point
between 40 and 120 ˚C, if a mixture, the component must be capable of mixed
crystallization and homogenous solubility in one another in the melt’ (Kirk O.,
1970). In 1975, Bennett H., mentioned that, wax compositions containing
different waxes and/or other substances are often employed for special effect,
paraffin wax is extremely slow setting, when employed alone, it is rather greasy
and adheres to glass. James G. Speight, 1980 defined paraffin wax as solid
crystalline mixture of straight chain (normal) hydrocarbons ranging from C20 to
C30 and possibly higher i.e. CH3.(CH2)n.CH3 where n > 18. and it is
distinguished by its solid state at ordinary temperatures and low viscosity when
melted.
Generally, the term “wax” is applied to a large number of chemically
different materials natural or synthetic products. The chemical composition of
waxes is complex; all of the products have wide molecular weight profile, with
the functionality ranging from products, which contain mainly normal alkanes
(to those which are mixtures of hydrocarbons) and reactive functional species
(Christie W.W., 2002). Today different companies have an increasing number
of commercially available substances of various chemical composition and
properties, which have acquired the name “wax”.
1.2 Types of wax
Waxes can be categorized by origin into three main categories as follows:
1.2.1 Natural waxes:
The natural waxes category includes those waxes obtained from plants
and animals, these include waxes such as:
a\ carnauba wax:
A natural vegetable wax derived from the fronds of Barazilian palm trees,
it is relatively hard, anti blocking and can be used in the film coating industry.
Melting point ranges between 83 ˚C to 86 ˚C.
b\ Montan wax:
Is a mineral wax which, in its crude form, is extracted from lignite formed
by decomposition of vegetable substances. Melting point range is between 79 ˚C
to 89 ˚C.
c\ Bees wax:
It is a light to golden yellow wax, naturally produced by honeybees and it
has a slight honey-like smell. It is used in cosmetics and candle as well as wood
polishes and various other applications, melting point around 146 ˚C.
d\ Palm wax:
Derived from palm. It has a high melting point (140 ˚C) and is known to
produce a crystalline look, also it can be used directly or as an additive to other
natural or synthetic waxes.
There are many types of natural wax such as: soybean wax, bayberry wax,
and candelilla wax, etc. It is often necessary to combine several waxes with
various properties in order to create a new wax with specific properties for a
specific use.
1.2.2 Synthetic wax:
These include waxes manufactured or synthesized from raw materials
such as coal, natural gas, etc. There is a variety of synthetic waxes such as:
a\ Polyethylene waxes:
These are made from ethylene produced from natural gas or by cracking
petroleum naphtha. Ethylene is polymerized to produce waxes with various
properties.
b\ Fischer – Tropsch waxes:
These types of waxes are produced in South Africa by coal gasification;
they have molecular weights of 300 – 1400 gms/mole and melting points of
about 99 ˚C.
1.2.3 Petroleum wax:
The petroleum wax category includes all of the waxes obtained from the
refining of crude oil that is formed by bacteria, heat and pressure on ancient
plant and animal usually found in layers of porous rock. Crude oil is composed
of various products, complex, naturally occurring, fluid mixture of hydrocarbon
and also containing a small amount of undesired compounds that contain sulfur,
oxygen and nitrogen. Crude oil can be divided according to the groups either as
paraffinic base, naphthenic base or aromatic.
There are three general categories of petroleum wax include: a\ paraffin wax b\
microcrystalline wax c\ petrolatum.
a\ Paraffin wax:
A white odorless hydrocarbon wax that is chemically inert and derived
from light lube oil distillates consisting mostly of straight chain hydrocarbons
(80 – 90 % n-paraffin), branched paraffin (iso-paraffin) and cycloparaffin and
very low percentage of aromatic material.
These waxes are non-reactive, non-toxic, good water barrier and colorless.
Paraffin waxes are characterized by a clearly defined crystal structure and have
the tendency to be hard, the melting point of paraffin waxes generally falls
between 43 and 71 ˚C (100 -160 ˚F), molecular weights are usually less than 450
and the viscosity at 98.9 ˚C (210 ˚F) normally will be less than 6 cSt (George V.
D, 1993).
n = Paraffin
iso = Paraffin
Cycloparaffin
b\ Microcrystalline waxes:
A high molecular weight hydrocarbon wax produced from a combination
of heavy lube distillates and residual oils. Microcrystalline waxes are the
remaining fraction of paraffin wax after the lower molecular weight waxes are
removed. These types of waxes are high molecular weight hydrocarbons with
linear chains, few branches might be present and have smaller crystals, they
differ from refined paraffin wax in that the carbon chains are longer and have
greater affinity for oil than paraffin waxes (typical oil content by weight is
between 0.5% and 2%). These waxes have darker color, more adhesive, higher
viscosity (10 – 20 cSt at 98.9 ˚C), molecular weights (500 - 675) and melting
point (65.6 – 104.4 ˚C, 150 – 220 ˚F) than paraffin wax components.
c\ Petrolatum (petroleum jelly):
Petrolatum is a low molecular weight hydrocarbon wax. It consists of a
mixture of microcrystalline wax and oil. It is derived from heavy residue of nonasphaltic crude oils by a centrifugal dewaxing of heavy viscous vacuum
distillate, and sometimes by blending highly refined white oils with wax.
Petrolatum are semi – solid material at room temperature and varies in colour
from white to dark brown, when fully refined, becomes microcrystalline wax.
Other terms are also used to refer to petroleum wax. In general these
terms refer to the amount of oil contained in the product. Scale wax refer to the
wax containing 1 to 3 % oil content, soft and semi-refined wax usually derived
from slack wax by extracting the oil. Slack wax refer to the wax containing 3 to
50% oil content, distinguished from scale wax by having higher oil content.
Fully refined paraffin (FRP) wax that has had nearly all of the oil removed out
of it (have less than 0.5 oil content).
A number of waxes are produced commercially in large amounts for
different uses in industry, those waxes are typically quality controlled with
regard to the physical properties as shown in table 2.
Table 2: Physical properties of waxes*
Property
Test
Description
Method
Provides information on temperature at which most of
Melt Point
ASTM D87 a given wax change from a solid to a liquid. Widely used
for paraffin waxes.
Congealing
Point
Drop Melt
Point
ASTM D938 Measures when a wax ceases to flow.
ASTM D127
Generally used on waxes that don’t show a melting plateau
e.g. petrolatums and microcrystalline waxes.
Typical Values
100-160°F (43-71°C)
for paraffin waxes
Varies widely
140-200°F (60-93°C)
for microcrystalline
waxes
Needle
ASTM
Measures the hardness of wax. Usually determined at 77°F
9-20 (0.1dmm) for
Penetration
D1321
(25°C) or 100°F (40°C). Higher values indicate softer wax. paraffin @ 77°F (25°C)
Fully Refined <0.5%,
Oil Content
ASTM D721
The amount of oil in wax. Indicates degree of refining.
Semi-refined 0.5-1.0%,
Scale 1.0-3.0%
Kinematic
Viscosity
Saybolt
Viscosity
ASTM D445
Saybolt to
Kinematic and
temperature. Results in centistokes (cSt).
ASTM D88 temperature. Results in Saybolt Universal Seconds (SUS),
This practice covers the conversion tables and equations for
ASTM
converting kinematic viscosity in centistokes (cSt) at any
D2161
temperature to Saybolt Universal viscosity in Saybolt
Universal seconds (SUS) at the same temperature.
The deviation of molten wax from colorless. The Saybolt
Saybolt Color ASTM D156 color scale ranges from +30 (colorless) to -16 (medium
yellow/brown)
Odor Test
36-50 for paraffin
usually at 210°F (100°C).
vice versa
ASTM Color
2.9-7.5 for paraffin
The resistance to flow of a molten wax at the test
Viscosity
Conversion of
The resistance to flow of a molten wax at the test
ASTM
D1500
Visual comparison of wax color (molten) against glass
color standards. Used for light amber and darker waxes and
blends.
Lightest color is highest,
+30 is maximum
Darkest color is highest,
8 is black
ASTM
Procedure for rating the odor intensity of waxes derived
A value of 1 or less is
D1833
from petroleum.
acceptable for paraffin
*ASTM Web Site
1.3 Industrial uses of petroleum waxes:
The petroleum wax has a high market value and by no means to be
regarded as a waste product. Due to their relatively low cost, good consistency
and reliable supply, petroleum waxes were introduced in different fields of
industry. Both paraffin and microcrystalline waxes have wide uses in food
packing, paper coating, textile, moisture proofing, candle-making and cosmetics.
Scale wax is used in candle manufacture, coating of carbon paper and rubber
compounds to prevent surface cracking from sunlight exposure. Slack waxes
with higher oil content are used in the manufacture of building materials such as
particleboard. Paraffin wax enters into shoe, floor, furniture, motorcar polishes
and leather dressings, but for these purposes it is mixed with natural wax such as
carnauba or bees wax. Petrolatum or petroleum jelly is used as an ointment,
lubricant, water-repellent, release agent and temporary adhesive. The highly
refined white varieties are used in medicinal preparations.
Wax blending – product performance and economics are usually the
controlling factors in developing a specific wax blend. Physical properties such
as melting point, viscosity, color, hardness, flexibility, tack and surface texture
are a few of the many characteristics that will affect the product performance.
The quality standards of final wax products are determined by the users, and are
laid down in test methods according to DIN, ISO and ASTM respectively (Alan
G. Lucas, 2000).
1.4 Wax problems in crude oils:
Although waxes are very useful raw materials in industry, they present
serious problems in production, transportation, handling, storage and refinery in
the oil business.
The chemical definition of paraffins is that they are saturated hydrocarbon
with straight or branched chains structures, but without any ring structure. This
definition points to the alkanes as the true paraffin. At one time the alkanes were
called the paraffin series of chemicals, but this terminology has been lost, so we
have no link between the words alkanes and paraffin. The paraffin or alkanes
that give us problems in the oilfield are those alkanes of C20H42 chain length and
higher (Baker K.M et al, 2001). The n-alkanes (straight chain) up to chain
lengths of C36H74 give the majority of pour point problems. Above this carbon
number they are joined by the linear and branched paraffins that become
insoluble in the oil at high temperature. The alkanes above C40H82 are primarily
responsible for deposition problems in the oilfield. The longest chain length
alkane observed by (Barker K.M et al, 2001) from an oilfield deposit was
C103H208 from a tank bottom sample.
Reistle C.E. (1932) listed the following as the most significant reasons for
separation of paraffin from crude oil:
1. The cooling produced by the gas in expanding through an orifice or
restriction.
2. Cooling produced as a result of the gas expanding, forcing the oil through the
formation to the well and lifting it to the surface.
3. Cooling produced by radiation of heat from the oil and gas to the surrounding
formations as it flows from the bottom of the well to the surface.
4. Cooling produced by dissolved gas being liberated from solution.
5. Change in temperature produced by intrusion of water.
6. Loss in volume and change in temperature due to the evaporation or
vaporization of the lighter constituents.
The liquid hydrocarbons produced from many oil and gas reservoirs
become unstable soon after leaving the formation due to changing conditions,
including decrease in temperature and pressure. Temperature decrease can lead
to solid hydrocarbons crystallizing and depositing on the walls of the tubing,
flow lines and surface equipment (Becker J.R. 1997, Burger 1988, Joao A.P et al
2002, Julian Y et al 2000). These deposits are mainly constituted by n-paraffins
and small amounts of branched paraffins and aromatic compounds. Naphthenic
(cyclic) and long chain paraffins also have marked contribution to
microcrystalline waxes and influence the growing of macrocrystalline wax.
Several deposition problems were discussed in the literature (Sivaraman A. et al
2000, Cazaux G et al 1998, Matlach W.J et al 1983, Hamouda A.A et al 1993).
1.4.1 Wax production problems
Wax deposition causes diverse production problems in many of the
world’s oil – producing regions (Misra et al, 1994). The production problems
started when the concentration of heavy wax fragments was increased in deeper
reservoirs. These depositions in the producing reservoirs is a difficult problem to
resolve once it begins and it almost involves the cessation of natural drive
production from these reservoirs (Becker J.R., 1997). It was mentioned that, the
wax molecules are soluble constituents of crude oil under most reservoir
conditions and when the equilibrium between the crude oil and paraffin
molecules is disturbed, paraffin precipitation will occur. The disturbance of this
equilibrium occurs due to a reduction in temperature and pressure of the flowing
fluid stream (Jim Svetgoff, 1984). Paraffin precipitation may also occur as a
result of evaporation of volatile light ends, which would act as naturally
occuring solvents (Meclaflin G.G., and Whitfill D.L., 1984, Maria del, et al
2001). Paraffin deposition was also defined as a linear hydrocarbon chain (C20 to
C60 and above) in a mixture with branched hydrocarbons, oil, organics (such as
asphaltene), water and assorted inorganics (sand, rust, iron sulphide, etc) (Mike
Primeaux, 1989). The hardness of the deposit depends mostly on the amount of
oil in the mixture and carbon chains length. The different carbon length chains
vary in percentage and melting point, and precipitate out of the solution at
different temperatures, the longer chains length precipitate first and are difficult
to put back into solution (Nguyen, X.T., et al 1999). On the other hand the point
of deposition in a well’s producing system is normally determined by how close
the crude is to its solubility saturation point and the amount of wax in the crude.
Loss of wax solubility does not necessarily cause deposition, wax crystals
normally have a needle-like shape and if they remain as single crystals, they
tend to disperse in the crude instead of deposition on a surface. A nucleating
material is usually present that gathers wax crystals into a bushy particle that is
much larger than single crystals, these agglomerates may then separate from the
crude and form deposits in the well producing system (Thomas, O.A. and Alan,
P.R., 1982). Certain signs can indicate the start of paraffin deposition, a change
in crude appearance such as cloudiness indicates that paraffin is coming out of
solution. Accumulation of paraffin in stock tanks indicates that paraffin
deposition may be expected in the flow line, tubing and well bore. Paraffin
buildup in the tubing can lead to overload of rod-pumps and cause rod breaks.
Consequently, production decreases in wells producing paraffinic oil caused by
paraffin deposition.
1.4.2 Wax transportation problems
Many papers were published on waxy crude oil pipeline problems. Crude oil is
pumped through a circular pipeline. As the temperature falls, wax deposits on
the pipe walls which decrease the pipe flow diameter. Sifferman and Thomas,
S.R., 1979 discussed transporting waxy crude oil by using emulsifiers and wax
crystal modifiers and special thermal treatment. The use of water to transport
waxy crude oils has been used to allow a low viscosity fluid to contact the pipe
walls. Part of the difficulty with emulsions is their unstable nature for start-up.
Emulsifiers have allowed formation of oil-in-water emulsions with low
viscosities in waxy (and heavy) crude oils. The problems caused by paraffin
deposition are related to restricted flow, which leads to increased flow line
pressure, decreased production and mechanical problems (Meclaflin G.G. and
Whitfill D.L., 1984). The solid deposit increases the surface roughness of the
pipe wall, this causes an increase in the pressure drop at high flow rates, which
can result in higher pumping costs or reduced throughput (Groffe D. et al,
2001). Newberry and Michael, E., 1984, mentioned that, paraffin deposition
takes place by three mechanisms that transport both dissolved and precipitated
waxy crystals laterally. When the oil is cooled, a concentration gradient leads to
the transport, precipitation and deposition of wax at the wall by molecular
diffusion; small particles of previously precipitated wax can be transported
laterally by Brownian and Shear dispersion. From the technical standpoint, two
main problems have to be solved: restart of the oil after a shut down and control
of wax deposition (Carniani, C., and Merlini, M., 1996). When a waxy crude
pipeline operating below the crude’s pour point is shut down for any reason, the
resulting gel led state will require, upon restart, substantially more pressure to
put in motion. This additional restart pressure will be less than if the pipeline
wax operating above the crude’s pour point. Shut downs will occur due to
operational reasons (Uhde A., and Kopp, G., 1971):
1. The oil storage in the terminal will be below the minimum required or
allowable level.
2. There are no delivery requirements by the refineries to be supplied.
3. A pressure test for leakage control of the pipeline has to be performed.
4. During construction, repair or maintenance work at the pipeline or the
supervisory control and safety installations, the flow has to be stopped.
5. The pipeline might be shut down automatically by exceeding the
operational safety limits.
The most important criterion in designing pipelines transporting waxy
crude is whether the line can be restarted easily after a shut down (Bomba, J.G.,
1986, Cazaux, G., et al 1998). Waxy crude oils has three important flow
properties which are necessary to characterize the oil, these include viscosity,
gel strength (yield value) and pour point. Low ambient temperature properties
are necessary to characterize the oil, but for waxy oil it will cause start-up
problems. Pipeline temperature, flow rate, flow velocity and the presence of gas
and water are important parameters which influence the crude congealing since
the mechanics of flow ceasure is also influenced by dynamics of flow, presence
of gas phase and water in the crude oil (Rai R et al 1996, Henaut I. et al 1999).
Michael, Z., 2000 study 18 flow improvers used in transporting highly paraffinic
crude oil in Kazakhstan, only a handful proved to be suitable for this specific
crude. The pour point was lowered from +17 ˚C to –5 ˚C and viscosity at 10 ˚C
was reduced from several thousand mPa*S to about 14 mPa*S. In spite of
significant flow improvement, yield stress remained high (60 Pa), even for
properly inhibited oil whenever the crude was cooled down statically, whereas,
after dynamic cooling yield stress was nearly negligible. Thus special
precautions had to be developed for potential phases of export stocks. On the
other hand paraffinic crude oil in Kumkol area has been transported to the oil
field through a double string pipeline, this crude was diluted in a certain ratio
depending on temperature conditions and the mixture could easily be transported
to the refinery.
1.5 Wax problems in Sudanese crude oil
The Greater Nile petroleum operating company is a consortium of
international oil companies in partnership with Sudapet formed in 1997. Its
production facilities are located in Heglig and Unity. The main fields are Heglig,
Unity, El Nar, Toma South, El Toor, Bamboo and Munga beside other fields
under development. A 1610-Km pipeline from Heglig fields to Port Sudan has
been constructed. The pipeline passes via Elobayid and Khartoum refineries to
the marine terminal at Port Sudan.
The Sudanese crude oil (Nile Blend) which is a waxy one, causes
different problems especially in its handling due to its high wax content (in
some fields) which raises the pour point of the oil. The wax concentration
increases in the heavy products even further (up to 30%) which constitutes
special problems in product transport and handling. The wax concentration in
Sudanese furnace has the adverse effect of raising the pour point to 48 ˚C
(Mohammed, T., et al, 1998). Other problems observed in evacuates of the
crude, need temperature between 70 to 80 ˚C to be in liquid form. On the other
hand, the temperature of the oil (treated) when pumped from the Central
Processing Facilities (CPF) was 70 ˚C. At pump station 2 (PS2) located in ElDalang (239 Km from CPF) the temperature of the oil reaches (52-48 ˚C) and
the yield stress value becomes high. The yield stress is the most important
parameter to calculate the re-start pressure. Yield stress is defined as the stress
below which a material will not exhibit flow behavior. The same problem was
obtained at pump station 3 (PS3) located in Aumsayala where the temperature of
the oil was 38 to 36 ˚C (high yield stress) till it reached Port Sudan. No
shutdown problems were occurring but it is expected.
1.6 Control of paraffin deposition:
There are many different methods for flow improvement of paraffinic
crudes, the most imoprtant of which are mechanical methods, thermal methods,
application of chemicals, application of solvents
(dilution with other
hydrocarbons), magnetic and electromagnetic methods and application of
microbes.
1.6.1 Mechanical
Scrapers and cutters are used to remove paraffin from tubing. These
techniques are economical, but scrapers can cause perforation plugging if it is
necessary to circulate scraped paraffin down the tubing and out of the casing. If
cleanout is required, mechanical cleaning becomes more costly (value of
production + cleanout costs). A scraper attached to a wire line is also used for
removal of paraffin flowing or gas lift wells. Wire line units are operated
manually and some scraper units are controlled automatically by a timing
device. Other systems require shutting in the well long enough for scraper to fall
to the bottom of the tubing; when production is resumed, the scraper opens up or
expands and scrapes the paraffin from the tubing as the scraper moves to the
surface. To operate this tool, wells must be shut and opened manually or
controlled with a timing device (Thomas, O.A., and Alan, P.R., 1982). Coiledtubing technology is also used in well clean-up procedure. It involves the
redirection of well production to fluid collection facilities or flaring operations
while the coiled tubing is in the well. Heavy coiled tubing reels are placed at the
well head by large trucks, the well fluids are diverted and high-pressure nozzles
on the end of the coiled tubing are placed in the well. Tanker trucks filled with
solvent provide the high pressure pumps with fluid that are used to clean the
well tubing as the coiled tubing is lowered into the well (Becker J.R., 1997).
Other mechanical method such as line pigging have been used successfully. This
practice requires that launching and capture sites be engineered into the transfer
facility’s design. A unique test facility was designed and constructed to
invistigate the pigging mechanics of wax removal in pipelines (Qian, W., et al,
2001), a series of experimental studies were performed to better understand the
mechanisms of wax removal in pipelines using different types of commercial
pigs (cup, disc and polly) and to evaluate the performance of each pig as a
function of wax hardness and thickness. The experiment showed that, the thicker
the wax was, the more force was needed to breakup the wax, and the more wax
was accumulated in front of the pig. Hardness (or oil content) of the wax is
expected to have a significant effect on the required force to remove the wax
from the pipelines. During the test of 35% oil content, the pig failed at a distance
10 feet from the inlet. Therefore, only limited data were obtained for 35% oil
content case. Moreover, transportation of the removed or dislodged wax requires
more force as the oil content of the wax decreased. Both the shape and material
of the pig had a pronounced effect on the total force and the pigging efficiency,
for the pigs used in this study the disc pig was most efficient, while the foam
polly pig offered the poorest wax removal efficiency. The wax removal
performance of the cup pig was very similar to that of the disc pig. However, the
cup pig could withstand higher load without mechanical damages than the disc
pig. Pigging operations are conducted with and without incorporation of
solvents and chemicals, and the retrieved material blockages are most often
directed to waste streams. The variety and degree of sophistication of pigging
devices is staggering, ranging from simple projectiles to devices with onboard
telemetry, but a common denominator to each is that they are employed after
damage has been detected (Becker J.R., 1997).
1.6.2 Solvents
Solvents have been one of the primary methods of controlling paraffin
deposition. A number of factors can affect the removal of paraffin from a
production system. Some of the most important of these are type of solvent
used, type and quantity of paraffin, temperature and contact time. All of these
can help determine success or failure of a paraffin removal treatment. As
described by (Barker K.M. et al, 2001) the best paraffin solvent applied to a
long chain paraffin at low temperature for too short a time will fail to give a
clean system. A poor solvent applied to a short chain paraffin at high
temperature in large quantities will clean the system every time. Different
solvents have different abilities to dissolve paraffin. The amount of wax
dissolved by any solvent decreases as the carbon chain length increases. Two
general classes of solvent used in the oilfield to dissolve paraffin are aliphatic
and aromatic. Aliphatic solvents such as diesel, kerosene and condensate.
Aromatic solvents used are xylene and toluene. Chlorinated hydrocarbons such
as carbon tetrachloride are excellent paraffin solvents but they are not generally
used because they have adverse effect on refinery and catalyst. Carbon
disulphide has been called the universal paraffin solvent. Kerosene and diesel oil
are commonly used in wells in which the asphaltene content of deposit is very
low because asphaltenes are not soluble in straight chain hydrocarbons, however
some condensates contain aromatic components that enable them to dissolve
asphaltene. The study carried out by Barker K.M. et al, 2001 shows that the
order of solvency determined was xylene> n-heptane> artic diesel for all three
waxes studied (C29H60- C37H76- C42H86). Application of heating of the solvents
will aid in removal of deposit but care should be taken during warming because
of the relatively low flash points of solvents. Choosing of solvents is based on
cost effectiveness in dissolving a specific organic deposit. Numerous companies
produce different solvents, but the lack of standarized testing techniques makes
comparison difficult (Barker K.M. et al 2001, Becker J.R., 1997).
1.6.3 Heat
Several field experiments were conducted to evaluate the effect of hot
oiling for either the removal or redeposition of paraffin downhole. Hot solvents
have the greatest potential benefit. In many producing areas, particularly in rod
pumps systems, it is common practice to periodically treat with heated crudes
(sometimes together with paraffin treating chemicals) to melt and solubilize
paraffin wax deposits. The most common method is to pump the heated crude
down the tubing casing annulus, which transmits heat through the tubing string
to melt wax deposits on the tubing wall and rods (Thomas, O.A., and Alan, P.R.,
1982). It has been found that the practice of hot oiling to remove paraffin wax
deposits on downhole equipment and tubulars could lead to chronic nearwellbore formation damage with the redepositing of waxes removed uphole and
those waxes originally contained in the load oil (Straub T.J et al, 1989). Field
experiments have suggested that, normal hot oiling treatments performed to
improve production in paraffin choked wells do not produce long term benefits
when the paraffin damage is deep in the well. In one study this process actually
reduced the bottomhole temperature to levels below the paraffin cloud point.
The resultant near-wellbore damage is chronic in nature due to periodic
treatments and may be incorrectly attributed to depletion. Laboratory
experiments indicate that toluene or xylene consistently dissolves paraffin faster
than other commercial organic solvents. Applying these solvents at temperatures
lower than 40 °C had little or no effect in these tests. Increasing temperature of
these solvents increases the rate at which paraffin is removed (Straub T.J et al,
1989). Formation damage may also occur if the reservoir temperature is less
than the cloud point of the oil or below the melting point of paraffin. Steam has
been used to melt paraffin but in downhole care must be taken because melted
paraffin forced into the formation may congeal before it can be produced with
formation. Donald, F. et al, 1989 described the simplest and most efficient
heating of the arctic transport pipe with its own heat tube which called skin
effect pipe heating and was found to be more economical. Finally the
application of heat to remove paraffin should be carried out before large deposits
have accumulated, if accumulation happened the use of mechanical removal of
some paraffin might be advisable.
1.6.4 Chemicals
Chemicals (inhibitors and dispersants) are used to inhibit wax crystal
growth or inhibit its adherence to the tubing wall (Jim Svetgoff, 1984).
Chemical dispersants are a selected group of surface-active agents that work in
the presence of water by water-wetting the paraffin particles to prevent the
particles from uniting and depositing on the tubing wall and flowline. Chemical
dispersants are used to remove paraffin that has already been deposited;
dispersants do not dissolve paraffin. These chemicals disperse large deposits of
paraffin into very small particles, which are then carried through the system by
the production steam. Inhibitors (crystal modifiers, crystal distorters) are
polymers that inhibit or alter wax crystal growth (prevent paraffin crystals from
forming massive, crystal lattice structures). They appear to work best in waterfree or low water content crude; they are selective and often require tailoring to
the individual crude oil. Chemical inhibitors will not dissolve, disperse or
remove paraffin that has already been deposited. They are applied in either
continuous or squeeze-type treatments to restrict crystal size of precipitated
paraffin and help prevent re-agglomeration of paraffin crystals. The temperature
at which paraffin precipitates from the oil phase of crude is called the cloud
point, this cloud point cannot be altered by chemicals means. The successful
paraffin inhibition is getting the chemical into the produced fluid before the
cloud point of the crude oil reached (squeeze treatment) (Jim, S., 1984,
Meclaflin, G.G., and Whitfill, D.L., 1984). A pour point test should be run to
determine the best inhibitor for a particular paraffin problem. Locations of
paraffin deposition and recommended points for inhibitor treatment have been
described (Jim, S., 1984).
Pour point depressants are polymers with pendant hydrocarbon chains that
interact with paraffin in the crude and thus inhibit the formation of large wax
crystal matrices. This interaction retards wax crystal formation and growth, alter
the paraffin’s heat of crystallization and subsequently depresses the crude’s pour
point (John, S. et al, 2001). Examples of the types of chemistries used as crude
oil pour point depressants (PPDs) include ethylene vinyl acetate copolymers,
vinyl acetate olefin copolymers, alkyl esters of styrene maleic anhydride
copolymers, alkylesters of unsaturated carboxylic acids, polyalkylacrylates,
polyalkylmethacrylates, alkyl phenols and alpha olefin copolymers. A literature
review of the types of chemicals that hinder or inhibit wax deposition was
carried out. Several authors have reported studies where the use of wax
modifiers and pour point depressants have shown enhanced flow improvement
properties for waxy crudes (Heinz G 1985, Koshel, K.C. 1999, Michael, Z.,
2000). Newberry M.E et al 1986, studied the chemical additive that was found
to be particularly active on the Niagaran crude, paraffin deposition was reduced
by over 93% with this additive. Lijian, D., et al 2001 studied paraffin inhibitors
that are complex produts by mixing macromolecules, surfactants or polycyclic
hydrocarbons or polar organic compounds. It has been found in the research
experiment that, for the paraffin inhibition efficiency, the traditionaly used
macromolecule type’s inhibitors are not as good as mixing products. Groffe, D.
et al, 2001 studied the chemicals that appear to be able to interfere with the wax
crystal growth mechanism by preventing the formation of 3-dimensional
network. This particular chemical was found to reduce the pour point and
improve the flow characteristics of the particular crude. Becker, J.R., 1999
mentioned that chemicals that interact with the growing waxes require a
relatively high melting point or crystallization temperature and for this reason,
these chemicals often freeze during the winter months. The study deals with the
winterization of these chemicals and the change in their physical behavior in
cold seasons. The crystal modifier solutions that might otherwise be solid under
field conditions can be compared to the experimental suspension versions of the
same modifier chemical. This screening was performed with solution and
suspension versions of each of the various chemicals. The results indicate that,
the build up of wax appeared to be minimal indicating that the modifier product
was performing effectively. The improved products were found to be successful
during critical times of the year (cold months). Barker, K.M., et al, 2001
discussed the laboratory testing and field test results of various application
methods by which these products can be introduced into the system requiring
treatment since not all wells are equipped with capillary injection strings or have
back side access to chemical injection. Other authors reported on how high
molecular weight fractions from crude oil affect the activity of a crystal modifier
(John. S.M and Kim, L.Z., 2001, Carcia M.C et al 1998).
Maria, D., et al 2001, studied the effect of light and heavy alkanes on the
activity of a crystal modifier. Type I crudes display monomodal molecular
weight distributions, with abundant (C24+) components when doped with (C13C20) concentrates, no improvements were found when the crystal modifier was
added. On the other hand, type II crudes which show multimodal molecular
weight distributions and large proportions of (C24+) alkane, when doped with
large paraffins (C20-C44) drastically lost their response to the additive.
Significant proportions of heavy paraffins are found to be responsible for the
inefficiency of crystal inhibitors. The results also indicate a slight decrease in
the inhibitor activity up to 41% Wt of cyclo/isoparaffins. Beyond this point, the
inhibitor activity starts to improve up to a value of four degrees. The improved
inhibitor activity is probably due to a structural disorder introduced in the wax
crystals when the concentration of cyclo/isoparaffins is greater than 50 wt%.
Matlach W.J and Newberry, M.E., 1983 studied the crude of Altamont area
which had high wax content (37.7%), the pour point reaches 49.9 °C. High
chemical concentrations (1500 ppm) were necessary for pour point reduction,
copolymers of olefin/maleic anhydride esters were the most effective on all
three crudes under test. This additive reduces the quantity of wax deposited and
shifts the molecular weight range and configuration (reduce the quantity of C4050 at all chemical concentrations).
As mentioned before there are different factors affecting the performance of
crude oil wax control additives. John, S. et al 2001, studied these factors in
details. The polymers have three variable characteristics that may affect their
performance: the polymer backbone, the length of the pendant chains and the
polymer molecular weight. The backbone and pendant chain length can be
changed by using different monomers. The polymer molecular weight can be
changed by adjusting reaction conditions, amount of initiator used, etc.
Effect of polymer backbone: the data show that, the polymer backbone has a
slight but statistically significant effect on the performance of the wax control
additives.
Effect of the length of the pendant chains: The interaction between the wax
control additives work best when they are matched to the paraffin distribution in
the crude. The results show that as the average carbon number of the pendant
chain on the pour point depressant increases, the pour point of the additized
crude drops until it reaches a minimum and then decreases again. The minimum
in the data show that PPD’s average pendant chain length is most closely
matched with the paraffin distribution in the crude and the greatest pour point
depression results.
Effect of polymer molecular weight: The molecular weight of the wax control
polymer may affect the interaction of the polymer with the paraffins. A very
short, low molecular weight polymer may not have the molecular volume to
disrupt the paraffin crystals as it co-crystallizes within the paraffin matrix. A
very long, high molecular weight polymer may be so large that it interacts with
itself instead of the crude oil paraffins or the polymer’s solubility in the crude oil
may be limited and acually initiate paraffin crystallization and thus raise the
pour point of the crude oil.
Data show that, over the molecular weight range tested neither weight average
molecular weight, number average molecular weight nor peak molecular weight
affects the pour point performance of the wax control additives. The monomer
has no pour point depression activity as one would expect. Although the
monomer may interact with the paraffins, the monomer’s molecular volume is
apparently too small to disrupt paraffin crystal formation.
Effect of solvent and dilution: Undiluted pour point depressants are waxy
materials that are often solids at ambient temperature. To pump these products
in the field, they usually need to be drastically diluted with solvent. Therefore,
solvents comprise a very large portion of these finished formulations to make a
handlable product. Very few studies have examined the role that solvent plays
on the performance of the cold flow polymer.
The result show that the solvent has no effect on pour point performance
because the solvation from the solvent used in the package is immediately lost
upon addition to the crude. Upon additization the wax control polymer is
solvated exclusively by the crude. Subsequently the identity of the solvent used
in the package is not important to ultimate pour point performance.
Effect of polymer dilution: The concentration of a polymer in a solvent has a
large effect on the physical properties of the polymer. The concentration of the
polymer in the solvent will affect extent of interaction of the polymer with itself.
At high concentrations the polymer may interact with other polymer molecules
and become entangled. This entanglement may impact the accessibility of the
polymer to the paraffin in the crude and, thus, may impact the performance of
the cold flow modifier package. At low concentrations, the polymer is fully
solvated and should not interact with other polymer molecules and should be
very accessible to the paraffin in the crude oil. The results show that, dilution
also had no effect on the performance of wax control package.
Effect of mixing: Effective mixing of the additive into the crude oil has a great
effect on the performance of pour point depressants.
1.6.5 Bacteria treatement:
Microbial culture products (MCPs) were first used in 1986 in the Austin Chalk
formation in Texas to control paraffin deposition. The theory behind these
products was that microorganisms can be isolated and combined in novel
mixtures which will produce biochemicals that will mimic the action of classic
oil field chemicals such as pour point depressants, crystal modifiers and wax
dispersants. The advantage of using such biological products is the fact that
microorganisms will produce these biochemicals continuously and attach to
surfaces where paraffin deposition is occuring and act directly at the site of
deposition.
Development of (MCPs) represents a successful alternative technology to
remove paraffin deposits without causing lasting formation damage. Long term
use of MCPs showed no damage to the oil field production system (Bailey, S.A.
et al, 2001).
Natural, non-pathogenic and faculative anaerobic bacteria are claimed to be
effective against wax and waxy emulsion which are problematic downhole.
Main application is by batch treatment to shallow, cool wells in which the
bacteria slowly metabolise producing surfactants, acids and alcohols, for
example, which then disperse and dissolve waxes and resolve emulsions. Soak
periods are usually 3-7 days. Periodic re-treatment is required to maintain an
adequate bacterial colony. Santamaria, M.M., and George, R.E., 1991 selected
five wells with a history of paraffin related problems for treatement with a
commercially avilable bacteria product. It was found that paraffin related
treating costs for the wells was reduced by the use of bacteria. The use of
bacteria cause no obvious alteration to the oil properties and no increase in
sulfate reducing bacteria populations that could contribute to corrosion related
problems.
It is claimed that differing strains of bacteria may be selected to be effective on
paraffins of specific molecular weight bands. There is currently very little
reliable supportive literature for this technology. The technology could see
further developments on account of it’s very friendly health, safety and
environmental profile.
1.7 Some properties of waxy crudes affecting wax deposition
1.7.1 Pour point and cloud point
As defined by ASTM the pour point of an oil is lowest temperature at
which the oil will just flow under standard test conditions. The failure to flow at
the pour point is usually attributed to the separation of waxes from the oil, but
can also be due to the effect of viscosity in the case of very viscous oils. A cloud
point is the temperature at which wax begins to precipitate. At this cloud point
the clouding of an oil begins because of the elimination of n-alkane crystals. The
cloud point can only be determined for mineral oils, which are transparent in a
layer up to 40 mm thick. This usually does not apply to crude oils. For those
dark samples the pour point is determined and for the lighter fractions the cloud
point is described (Hans, J.N., et al, 1981). The measurement of cloud point
depends on a number of factors including oil composition, thermal history,
pressure, shear environment, measurement technique and cooling rate.
Nowadays, more sophisticated techniques of differing measurement principles
and varying degrees of sensitivity have been developed to measure cloud points
of petroleum fluids including opaque hydrocarbon systems (dark oils). Several
experimental techniques are used in the laboratory to measure the cloud point,
the cross polar microscopy (CPM) has been found to be more sensetive than
other techniques for detecting crystalline wax deposits (Ahmed, H., et al, 2003).
In pour point test (ASTM D5853-95) after preliminary heating, the crude is
cooled at specific rate and examined at intervals for movement, the lowest
temperature at which movement of the specimen is observed is recorded as the
pour point. When the crude reaches its pour point, the sample is not frozen solid.
What actually happens is that the paraffins in the crude crystallize and form a
matrix of wax crystals. The wax crystal matrix holds the bulk of the liquid
portion of the crude within it. By trapping the liquid portion within the wax
crystal matrix, the wax crystals prevent the liquid in the crude from flowing and
the sample no longer moves. Any thing that disrupts the formation or the
properties of the wax crystal matrix such as pour point depressants, will affect
the pour point of the crude (John S. et al 2001).
Numerous workers (Nguyen X.T., et al 2001, Barker, K.M et al, 2001) have
shown that wax content and the molecular weight distribution of waxes are
primary factors determining whether crude oils have a high or low pour point.
The additives used to reduce crude oil pour point must have the ability to change
the crystalline state of wax during the crude oil cooling process. The pour point
depends on the shape and size of the crystal, any pretreatment which affects size
and shape also will affect the pour point reduction. Preheat treatment of the
crude, thermal history and loss of light end may significantly affect the crude
pour point (Russel R.J. and Chapman E.D., 1971, Bucaram S.M., 1967).
1.7.2 Viscosity
Viscosity is the measure of the internal friction of a fluid. This friction
becomes apparent when a layer of fluid is made to move in relation to another
layer. The greater the friction the greater the amount of force required to cause
this movement, which is called (shear). Shearing occurs whenever the fluid is
physically moved or distributed as in pouring, spreading, spraying, mixing, etc.
Highly viscous fluids therefore require more force to move than less viscous
materials. Fluids have different rheological characteristics that can be described
by viscometer measurements. There are two categories of fluids:
Newtonian: These fluids have the same viscosity at different shear rate and are
called Newtonian over the shear rate range they are measured.
Non-Newtonian: These fluids have different viscosities at different shear rates.
There are several types of non-Newtonian flow behavior, characterized by the
way a fluid’s viscosity changes in response to variations in shear rate. The most
common types of non-Newtonian fluids include:
Pseudoplastic (shear-thinning): This type of fluid will display a decreasing
viscosity with an increasing shear rate, such as paints, emulsions.
Dilatant (shear thickening): This type of fluid will display increasing viscosity
with an increasing shear rate, such as clay slurries, candy compounds, corn
starch in water and sand water mixtures.
Plastic: This type of fluid will behave as a solid under static conditions. A
certain amount of force must be applied to the fluid before any flow is induced;
this force is called the (yield value), once the yield value is exceeded and flow
begins. Plastic fluids may display Newtonian, pseudoplastic, or dilatant flow
characteristics.
Thixotropic: A thixotropic fluid undergoes a decrease in viscosity with time,
while it is subjected to constant shearing. The time dependency is the time they
are held at a given shear rate. Thixotropic crude oils are paraffinic-based crude
oils that build viscous gel structure as they are cooled. Paraffinic crude oils
behave as Newtonian fluids at temperature above their cloud point. Thixotropic
characteristics begin to appear at just below the cloud point of the crude because
of precipitated wax crystals.
The Brookfield programmable DV-II+ viscometer measures fluid viscosity at
given shear rates. The principal of operation is to drive a spindle (which is
immersed in the test fluid) through a calibrated spring. The viscous drag of the
fluid against the spindle is measured by the spring deflection. Spring deflection
is measured with a rotary transducer. The measurement range of a DV-II+ (in
centipoise or milliPascal second) is determined by the rotational speed of the
spindle, the size and shape of the spindle, the container the spindle is rotating in,
and the full scale torque of the calibrated spring (Brookfield programmable DVII+, operating instructions).
Viscosity measurements should be conducted in combination with the pour point
test to determine the magnitude of a chemically induced physical change. The
shear imparted by the pour point technique is extremely low, and can represent
very small changes in viscosity. Therefore, viscosity measurements avoid the
ambiguity introduced by pour point test. Additional information that is of value
in determining the behavior of waxy crude oils under various conditions is also
obtainable by the use of viscometry (shear stress vs. temperature, and shear
stress vs. viscosity) (Barker K.M, et al 2001).
Crystallisation of waxes in crude oil produces non-Newtonian flow
characteristics including very high yield stress that are time dependent
(thixotropic) upon the shear and temperature histories of crude in question. Wax
crystallisation depends on the degree of under cooling and cooling rate. Wax
crystallisation may cause high viscosity leading to pressure losses and high yield
stress for restarting the flow (Misra et al, 1994). Michael Z., 2000, mentioned
that a yield stress of about 60 Pa for example would lead to restart pressure of
more than 600 bar in a 60 km 8-pipeline and more than 500 bar in a 10-pipeline.
In other words in the case of sudden interuption of pipeline flow, on the
assumption that all the pipeline contents would be cooled down from 30 ˚C or
more to 10 ˚C or less, there would be a severe risk of a pipeline loss due to
excessive restart pressure. So it was decided to build a double – string pipeline.
1.7.3 Wax content and wax fractions:
Determination of wax precipitated at different condition depends on the
method of measurement. The UOP 46-64 method is a standardized technique for
determining paraffin content of petroleum oils. The method involves dissolving
2 g of the crude sample in petroleum ether, and the solution is clarified using
fuller’s earth. The petroleum ether is evaporated and the clarified oil redissolved in an acetone-petroleum ether mixture. This solution is then chilled to
–17.8 °C (0 °F) and filtered through a cold filter funnel, the wax being collected
on an asbestos mat in the funnel, the wax is washed from the mat into a weighed
flask using hot petroleum ether, the petroleum ether is evaporated and the
precipitated wax weighed. Several methods have been presented in the literature
for amount of wax. Elsharkawy A.M., et al (2000) measured the wax content of
eight different stock-tank crude oils from the Middle East by using modified
UOP method 46-64 and thermodynamic model, the two different methods were
in a good agreement for four samples out of the eight samples considered in the
paper, this might be due to entrapment of liquid in solid residue. Several
thermodynamic models for representing wax precipitation have been published
such as Julian Z.Y. and Dan D.Z., et al (2000), Sivaraman A. et al (2000) and
Coutinho J.A.P. and Daridon J.L., (2001). Weingarten, J.S. and Euchner, J.A.,
1988 presented methods for predicting wax precipitation and deposition, the oil
used in this study was saturated with gas under reservoir conditions, as it flows
up the wellbore, its pressure drops and gas is liberated. When the temperature at
some point in the wellbore is lower than the crystallization temperature of the
fluid at that location, wax will begin to come of solution and become available
for deposition on the wellbore walls. A study by Adel M. E., et al (1999) to
determine and predict wax deposition from Kuwaiti crude oils, the wax contents
measured by modified UOP method 46-64 are not in good agreement with that
predicted by the thermodynamic model. Ahmed H. and Mike R., et al, 1997
evaluated the characteristics of four reservoir fluid sample (stock tank oil) and
their propensities towards paraffin deposition, in this study wax content was
measured by UOP 46-64 method. Models accounting for molecular diffusion
and shear dispersion were also presented to predict wax formation under
dynamic conditions in the Trans Alaska pipeline system (Burger et al, 1981), in
this study wax content was not measured by using UOP 46-64 standard method
because it contain a fuller’s earth clarification step which removes certain
portions of the waxy materials that are potentially depositable in a pipeline, a
modified procedure has been developed (acetone precipitation technique) which
determine the total amount of these waxy crystals in an oil sample. Nguyen X.T.
et al, 1999 described a method for wax – free asphaltene fractions which
provides a quantitative subdivision of the wax fraction into pentane soluble and
insoluble waxes which, when correlated with physical properties of crude oil
such as viscosity, pour point and cloud point may help explain causes of wax
deposition during production, transportation and storage of petroleum. Recent
developments in chromatographic techniques for the separation and quantitative
characterization of petroleum and related products are highlighted (Bhajendra N.
B, 1996), applicability of individual techniques such as gas chromatography,
liquid chromatography and thin layer chromatography are discussed in some
detail. Different methodologies based on thin–layer chromatography
(TLC)/densitometry were used to separate and quantitate hydrocarbon types
(Vicente L.C et al, 1999). Maria D.C et al, 2001 used high performance liquid
chromatography (HPLC) for the isolation of the (cyclo+branched) paraffin
fraction. High temperature gas chromatography has been used to characterize
the high molecular weight hydrocarbons. A number of papers have already been
published on this topic including those by Nguyen X.T et al (1999), Del Rio, J.C
and Phlip R.P (1992) and Wavrek D.A and Dahdah, N.F (1995). High
temperature gas chromatography has been used to establish the ubiquitous
presence of high molecular weight hydrocarbons extending as high as C120 in
crude oils (Michael, H and Paul, P.R, 2001), in this study high molecular weight
hydrocarbons (>C40) have been observed in crude oils derived from terrigenous,
lacustrine and marine source materials.
As mentioned before, the Sudanese crude oil (Nile blend) causes difficult
problems due to the high pour point and viscosity (in some fields). Presence of
high molecular weight hydrocarbons and asphaltene are important constituents
of petroleum and can raise the pour point and viscosity of the oil. Because the
Nile blend is a new discovered crude, more investigation is needed in order to
explain causes of wax deposition during production, transportation, handling
and storage. The objectives of the present study is:
1. Isolation of wax from crude oil samples of different fields (El Toor, El
Nar, Munga, Bamboo, Toma South, Unity, Heglig) consisting the Nile
blend by using appropriate method to determine the wax content.
2. Characterization of isolated wax (carbon chain distribution) by using
high temperature column chromatography.
3. Quantitative subdivision of the wax fraction into pentane soluble
(macrocrystalline wax) and insoluble (microcrystalline wax) which may
explain the high pour point and viscosity of the crude and hence the
causes of wax deposition during production, transportation and storage of
petroleum.
4. Measurement of oil content of petroleum wax, which affect key
properties such as strength, hardness, melting point, etc.
5. Effect of two types of chemical additives on crude pour point and
viscosity, the effect of high molecular weight hydrocarbon (> C40) on
the efficiency of the chemical additives.
CHAPTER TWO
EXPERIMENTAL
Experimental work was carried out at Central Petroleum
Laboratories (CPL), Ministry of Energy and Mining.
Viscosity measurements were carried out at the Mechanical
Engineering laboratories (University of Khartoum).
2.1 Measurement of Wax Content
Wax content was measured for the Nile blend sample taken from Khartoum
refinery. This blend contains Heglig, Unity, El Nar, El Toor, Toma South,
Bamboo fields with the ratio shown in table 3. Other crude samples of different
fields were taken from well bores in Heglig region; those included Heglig,
Unity, El Nar, El Toor, Toma South, Bamboo and Munga. Munga is a new field
component of Nile blend and is expected to start producing at a latter stage.
Table 3: Ratio of fields in Nile blend sample
Field Heglig Unity El Nar El Toor Toma South Bamboo
13.1
16.7
12.1
19.6
9.9
Ratio 25.3
2.1.1 UOP Method 46 – 64:
Apparatus:
Balance, goach filter Buchner funnel, Erlenmeyer flask 500 ml,
round bottom flask 500 ml, rotatory evaporator, water suction
pump, desiccator, magnetic stirrer, cryostat.
Materials:
Acetone (BDH Prod No.270236T, purity: 99%), petroleum spirit boiling range
40-60 ˚C (EEC No. 232-453-7 LabPack ltd, code: PE 4530), fuller’s earth,
laboratory reagent for adsorption (Hopkin & Williams, 433950).
Procedure:
1. Crude oil sample (2g) was taken into a 500ml Erlenmeyer flask.
2. The sample was dissolved in 300 ml of petroleum spirit (boiling range
40 – 60˚C) by agitation.
3. 15g of fuller’s earth was added to the sample and stirred by using
magnetic stirrer for 15 minutes.
4. The mixture was filtered under vacuum suction through a goach filter
Buchner funnel, the filtrate was transferred into 1-liter round bottom
flask.
5. The petroleum spirit was evaporated in a rotatory evaporator; water bath
temperature was increased slowly to 95˚C where the last traces of
petroleum spirit have been removed.
6. 200 ml of a solvent mixture (acetone / petroleum spirit 3:1 v/v) was
added to the wax-oil mixture in a round bottom flask.
7. The mixture was then transferred into a 500 ml Erlenmeyer flask, the
round bottom flask was washed with petroleum spirit (5 X15 ml) and
the washing was added to the wax-oil mixture.
8. The flask content was warmed in a water bath to dissolve the wax
crystals. The solution and solvent mixture were chilled to –17.8˚C for 10
minutes.
9. The goach filter funnel was cooled in a propanol/acetone -cooling bath
maintained the temperature of –20˚C by addition of dry ice.
10. The wax-oil mixture was filtered under vacuum suction through a goach
filter maintained at temperature of –20˚C.
11. The wax particles remained in the flask were washed with solvent
mixture (5 X 30 ml) chilled to –17.8˚C.
12. The flask containing the filtrate was removed and replaced with a new
100 ml filter flask. The wax on the goach was dissolved by using 40 ml
of hot petroleum spirit (40˚C) and filtered under vacuum.
13. The filtrate was transferred into a weighed 250 ml round bottom flask;
the filter flask was washed with 20 ml of petroleum spirit.
14. The petroleum spirit was evaporated under vacuum in a rotatory
evaporator; water bath temperature was increased slowly to 95˚C.
15. The round bottom flask was placed in a dessicator for 15 minutes and
weighed.
16. Step 14-15 was repeated until constant weight was obtained.
17. The wax content was calculated as follows:
Wax, wt% = W2 – W1/ S X 100
Where: W1 = weight of round bottom flask.
W2 = weight of round bottom flask + wax.
S = weight of sample.
The results of wax content by using UOP 46-64 were shown in table 4.
Table 4: Measurement of wax content by using UOP 46-64 method:
Field
Wax content Wt %
El Nar
29.604
Heglig
Toma South
Munga
Unity
Nile blend
El Toor
Bamboo
26.172
25.851
16.957
16.192
15.414
12.198
11.284
2.1.2 UOP Method 46 – 85
Apparatus:
Balance, goach filter Buchner funnel, Erlenmeyer flask 500 ml,
round bottom flask 500 ml – liter, rotatory evaporator, water
suction pump, desiccator, magnetic stirrer, cryostat.
Materials:
Hexane (EINECS No.2037776-Fisher Scientific UK), ammonia solution
(AnalaR Prod No. 2344200), sulfuric acid (AnalaR Prod No. 102761),
methylene chloride (LabPack, code No. 0166746), distilled water.
Procedure:
1. Crude oil sample (2g) was heated to aid in dissolution
and mixed with n-hexane (50 ml).
2. Concentrated sulfuric acid (4 ml) was added to remove
asphaltene, the mixture was heated gently on an electric hot plate
and swirled until the acid tar was formed.
3. The sample was left overnight and then transferred into
separatory funnel, warm water (40 ˚C – 50 ml) was added to wash
the hexane solution, the water layer was then removed.
4. Ammonium hydroxide solution (0.1 M – 15 ml) was added to
neutralize the remaining acid, the aqueous layer was then
removed.
5. The hexane solution was washed several times with warm water
(5 X 50 ml, 40 ˚C), water layer was removed
6. The hexane solution was transferred to a dried flask (250 ml)
and mixed with warm methylene chloride (35 ˚C, 20 ml).
7. Sample was cooled to – 30 ˚C for 30 min and transferred into a
cooled fritted glass (– 30 ˚C) and filtered under vacuum suction.
8. The wax on the filter was washed with methylene chloride
chilled to – 30 ˚C (3 X 5 ml), left to reach the room temperature
and was then dissolved with hot hexane (60 ˚C) to a weighed 100
ml flask.
9. The hexane was evaporated under vacuum in a rotatory
evaporator; water bath temperature was increased slowly to 95˚C.
The flask was rewighed and the wax content was calculated. The
result is shown in table 5.
2.1.3 Acetone precipitation technique (Burger et al, 1981)
Apparatus:
Balance, Buchner porcelain filtering funnel, glass fiber filters
(Whatman Cat No. 1823090), Erlenmeyer flask 500 ml, round
bottom flask 250 ml, rotatory evaporator, water suction pump,
desiccator, forceps, cryostat.
Materials:
Acetone (BDH Prod No.270236T, purity: 99%), petroleum sprit boiling range
40-60 ˚C (EEC No. 232-453-7 LabPack ltd, code: PE 4530), toluene (BDH Prod
No. 304526N, purity: 99%).
Procedure:
1. Crude oil sample (5g) was taken into a 500ml Erlenmeyer flask.
2. Petroleum spirit (35 ml) was added and stirred well until the sample was
dissolved.
3. Acetone (110 ml) was added and stirred.
4. The sample was placed into a cryostat maintained at –20˚C and allowed
to come to temperature (about 2 hours).
5. The following items were precooled to –20˚C: Buchner porcelain
filtering funnel, glass fiber filters, vacuum flask and a solvent mixture
(acetone / petroleum spirit 3:1 v/v).
6. Before filtering, the fiber filter was seated in the filter funnel and wetted
with the cold solvent mixture, the sample was filtered by pouring it into
the funnel, the filter cake was washed well with the cold solvent
mixture.
7. The filter was then removed with a forceps and placed in its original
flask.
8. The wax crystal on the filter funnel was washed into a round bottom
flask 250 ml (previously weighed) with toluene.
9. Toluene was evaporated under vacuum in a rotatory evaporator; water
bath temperature was increased slowly to 95 ˚C.
10. The round bottom flask was reweighed, the difference between the tare
and the final round bottom flask weight, less the weight of the filter
used, is the weight of the wax crystal contained in the original 5 g
sample. The results were shown in table 6.
Table 5. Wax content of Nile blend (three methods):
Sample: Nile blend
Wax content (Wt%)
UOP46-64 UOP46-85
15.414
37.51
Acetone precipitation
technique
18.216
Table 6: Measurement of wax content by using acetone precipitation
technique:
Field
El Nar
Wax content Wt %
38.651
Heglig
35.579
Toma South
Munga
Unity
Nile blend
El Toor
Bamboo
34.128
19.921
19.126
18.216
14.809
13.623
2.2 Wax fractions (Nguyen X et al, 1999)
Apparatus:
Balance, Buchner porcelain filtering funnel, glass fiber filters,
Erlenmeyer flask 500 ml, round bottom flask 250 ml, rotatory
evaporator, water suction pump, desiccator, forceps, soxhlet
extraction apparatus, cryostat.
Materials:
Acetone (BDH Prod No.270236T, purity: 99%), petroleum spirit boiling range
40-60 ˚C (EEC No. 232-453-7 LabPack ltd, code: PE 4530), toluene (BDH Prod
No. 304526N, purity: 99%), p-xylene (BDH Prod No. 305786M, purity 99%),
alumina.
Procedure:
1. Crude oil sample (1 g) was dissolved in 10 ml of hot pxylene (80 ˚C) to ensure complete dissolution of any wax
crystals.
2. The dissolved oil was adsorbed on alumina, the alumina
was extracted (soxhlet extraction) with p-xylene for 48 h.
3. Following the extraction, the p-xylene extract was
concentrated under vacuum in a rotatory evaporator.
4. Wax was precipitated with acetone at – 20 ˚C (Burger et al,
1981).
5. Cold n-pentane (– 20 ˚C) was added to the precipitate to a
concentration of about 2 mg/ml and the solution allowed to
stand overnight.
6. The flask contents were centrifuged for 10 min (speed =
1040 RPM, bath temperature 20 ˚C) with cold n- pentane (–
20 ˚C). Two fractions were obtained: macrocrystalline
waxes (<C40) being in solution and microcrystalline waxes
(>C40) with predominance of high molecular weight
hydrocarbon being present as precipitate. The two
fractions were separated by decantation, weighed and the
weight percent for every fraction was calculated. The
results of macro and microcrystalline wax Wt% are shown
in table 7.
Table 7: Macro and microcrystalline wax (Wt%) in different fields.
Field
Heglig
Unity
El Toor
El Nar
Toma South
Munga
Bamboo
Macro wax (Wt%)
97.5859
98.952
14.809
53.554
34.258
37.990
97.806
Micro wax (Wt%)
2.3165
0.547
84.462
46.009
64.244
61.370
1.822
2.3 Gas chromatography (GC) analysis UOP 915-92 method
Apparatus:
1. Balance, readability 0.1 mg
2. Chromatographic column, high temperature column (HT5
aluminum clad column, 5% phenyl polycarborane –
siloxane) and a 25 m X 0.22 mm i.d., temperature limits 10
to 460/480 ˚C, film thickness 0.10 µm, P/N: 054636
3. Gas chromatograph (Varian Chrompack – 9001 model),
temperature programmable, built for capillary column
chromatography, utilizing a split injection system, packed
glass injection port insert and equipped with a flame
ionization detector.
4. Hydrogen generator (Parker model: 75-32-220, serial No:
01244003, minimum operating temperature 10 ˚C, max 40
˚C).
5. Nitrogen generator (Parker model: 76-94-220, serial No:
080360d, minimum operating temperature 16 ˚C, max 38
˚C).
6. Regulator, air, high purity single stage regulator with 0-200
PSIG output, part: AL 81892.
7. Sample injector, syringe SGE, P/N 002200, 10 µL, model 10
F-GT.
Materials
Air, 99.99% purity, hydrogen, 99.99% purity, nitrogen, 99.99%
purity, n-paraffin standard, dichloromethane (LabPack product
no 0166746, purity: 99.5%).
Procedure:
1. The operating conditions (listed in table 8) were
established.
2. 1 µL of the sample dissolved in dichloromethane to be
analysed was injected, the recorder, integrator and column
temperature programming sequence were started.
3. From the resultant chromatogram, normal paraffins were
identified by comparing the chromatogram to the nparaffin standard chromatogram analyzed under identical
conditions.
Calculation:
The mass-% of each normal paraffin in the sample was
calculated by normalized composition to the nearest 0.01 mass-%
using the following formula:
C = 100 A / F
Where:
C = concentration of the specific normal paraffin, mass-%
A = peak area of the specific normal paraffin.
F = sum of all peak areas including n-paraffins and non-normal.
100 = factor to convert to mass-%
Figures 6-12 shows the high temperature gas chromatography
chromatogram (HTGC) of total wax fractions isolated from 7
fields. Figures 13 and 14 shows the chromatograms for the macro
and micro-crystalline waxes isolated from Eltoor field respectively
by using the method described by (Nguyen, X. et al, 1999).
Table 8: The operating conditions for GLC.
Column limit temperature
Detector temperature
Injection temperature
Oven initial temperature
Oven final temperature
Oven rise temperature
Time initial
Time final
Stabilization time
Column initial temperature
Column flow
Split ratio
Carrier gas (N2) pressure
Velocity of carrier gas
H2 pressure
Air pressure
450 ˚C
380 ˚C
280 ˚C
50 ˚C
430 ˚C
3 ˚C/min
2 min
40 min
1 min
50 ˚C
2.11 ml/min
48.39
300 kpa
51.51
150 kpa
150 kpa
2.4 Oil Content of Petroleum Wax ASTM D 721-97
Oil content in wax can affect key properties such as strength,
hardness, melting point, etc.
Apparatus:
Filter Stick and Assembly, consisting of a 10-mm diameter
sintered glass filter stick of 10 to 15 µm maximum pore diameter,
provided with an air pressure inlet tube and delivery nozzle. It is
provided with a ground-glass joint to fit a 25 by 170-mm test tube.
The dimensions for a suitable filtration assembly are shown in
Fig. 1.
Cooling Bath, consisting of an insulated box with 25.4 mm (1-in.) holes in the
center to accommodate any desired number of test tubes. The bath was filled
with a kerosine, and cooled by using solid carbon dioxide. A suitable cooling
bath to accommodate three test tubes is shown in Fig. 2.
Pipet, or equivalent dispensing device capable of delivering 1 ± 0.05 g of molten
wax.
Transfer Pipet, or equivalent volume dispensing device, capable of delivering 15
± 0.06 mL.
Air Pressure Regulator, designed to supply air to the filtration assembly at the
volume and pressure required to give an even flow of filtrate. Either the
conventional pressure reducing valve or a mercury bubbler-type regulator has
been found satisfactory. The latter type, illustrated in Fig. 3, consists of a 250mL glass cylinder and a T-tube held in the cylinder by means of a rubber stopper
grooved at the sides to permit the escape of excess air. The volume and pressure
of the air supplied to the filtration assembly is regulated by the depth to which
the T-tube is immersed in mercury at the bottom of the cylinder. Absorbent
cotton placed in the spaced above the mercury prevents the loss of mercury by
spattering. The air pressure regulatory is connected to the filter stick and
assembly by means of rubber tubing.
Thermometer, having a range as shown below and or in the Specification for IP
Standard Thermometers.
Thermometer Number
Temperature Range
ASTM
IP
–37 to +21°C
...
72C
–35 to +70°F
71F
72F
Weighing Bottles, conical in shape and glass-stoppered, having a capacity of 15
ml.
Evaporation Assembly, consisting of an evaporating cabinet and connections,
essentially as illustrated in Fig. 4, and capable of maintaining a temperature of
35 ± 1°C around the evaporation flask. Construct the jets with an inside
diameter of 4 ± 0.2 mm for delivering a stream of clean, dry air vertically
downward into the weighing bottle. Support each jet so that the tip is 15 ± 5 mm
above the surface of the liquid at the start of the evaporation. Supply air at the
rate of 2 to 3 L/min per jet, purified by passage through a tube of 10-mm bore
packed loosely to a height of 200 mm with absorbent cotton. Periodically the
cleanliness of the air was checked by evaporating 4 ml of methyl ethyl ketone.
When the residue does not exceed 0.1 mg, the evaporation equipment is
operating satisfactorily.
Analytical Balance, capable of reproducing weights to 0.1 mg.
Reagents:
Methyl Ethyl Ketone.
Procedure:
1. The sample of wax (1.0 ± 0.05g) was dissolved in 15 ml of methyl
ethyl ketone and placed in a hot water bath (50 ˚C), the solvent wax
mixture was heated and stirred with wire stirrer until homogenous
solution was obtained.
2. The test tube containing wax solvent mixture was placed in 800 ml
beaker of ice water and stirred until the contents were cold, the
weigh of test tube and its contents was recorded.
3. The test tube was then placed in a cooling bath which, was
maintained at (-34.5 ˚C) and the contents were stirred continuously
by means of the thermometer to avoid crystallization of wax.
4. The thermometer was removed at the temperature of (-31.5˚C) and
replaced by clean dry filter stick which was previously been cooled
to (-34.5˚C) for 15 min, the ground glass joint of the filter was
seated to make an air tight seal.
5. Unstoppered weighing bottle was placed under the delivery nozzle
of the filter.
6. Air pressure was applied to the filter and about 4 ml of the filtrate
were collected in the weighing bottle and immediately weighed.
7. The weighing bottle was then placed under one of the jets in the
evaporation assembly maintained at 35 ˚C, with the air jet centered
inside the neck, and the tip 15 mm above the surface of the liquid.
8. After the solvent was evaporated (18 min) the bottle and stopper
were removed and allowed to stand for 10 min and weighed.
9. The evaporation procedure was repeated three times using a 5 min
evaporation period until constant weight was obtained.
10. The amount of oil in wax was calculated as follows:
Oil in wax, weight % = (100 AC/BD) – 0.15
Where:
A = weight of oil residue = 26.5447-26.5272= 0.0175.
B = weight of wax sample = 51.5401-50.6322 = 0.9079.
C = weight of solvent = 63.1817-51.5401 = 11.6416.
D = weight of solvent evaporated = 31.0396-26.5447 = 4.4949.
0.15 = average factor correcting for the solubility of wax in the solvent at – 32
˚C
Oil in wax, weight % (Nile blend) =
(100 × 0.0175 × 11.6416/0.9079 × 4.4949) – 0.15 = 4.8422
2.5 Pour point test ASTM D 5853-95
Apparatus
Pour Point Test Apparatus Assembly (Fig. 5): Test Jar, cylindrical, of clear
glass, flat bottomed, outside diameter 33.2 to 34.8 mm, and height 115 to 25
mm. The inside diameter of the jar can range from 30.0 to 32.4 mm, within the
constraint that the wall thickness not greater than 1.6 mm. The jar had a line to
indicate a sample height 54
±
3 mm above the inside bottom. The inside of the
test jar (up to the mark) was visibly cleaned and free of scratches.
Thermometers, (ASTM 5C) High cloud and pour having ranges from -38 to +
50°C.
Cork, to fit the test jar, center bored for the test thermometer.
Jacket, watertight, cylindrical, metal, flat bottomed, 115
±
3 mm depth, with
inside diameter of 44.2 to 45.8 mm. supported in a vertical position in the
cooling bath so that no more than 25 mm projects out of the cooling medium.
The jacket was capable of being cleaned.
Disk, cork or felt, 6 mm thick to fit loosely inside the jacket.
Gasket, to fit snugly around the outside of the test jar and loosely inside the
jacket. The gasket was made a material that is sufficiently elastic to cling to the
test jar and hard enough to hold its shape. Its purpose is to prevent the test jar
from touching the jacket.
Cooling Bath, of a type suitable for obtaining the required temperatures. The
size and shape of the bath were supported to hold the jacket firmly in a vertical
position. The bath temperature was monitored by means of the appropriate
thermometer capable of measuring and displaying the designated temperature
with the required precision and accuracy.
Preparation of Test Samples: The pour point of crude oils was very sensitive to
trace amounts of high melting waxes. Exercise meticulous care to ensure
homogeneity of the sample.
Procedure: (for Maximum (Upper) Pour Point)
1. The test sample was poured into the test jar to the level mark. The sample was
preheated to a temperature of about 20°C above the expected pour point but not
higher than a temperature of 60°C (The vapor pressure of crude oils at
temperatures higher than 60°C will usually exceed 100 kPa. Under these
circumstances the sample container may rupture. Opening of the container may
induce foaming with resultant loss of sample and possible injury to personnel).
2. Immediately the test jar was closed with the cork carrying the high cloud and
pour thermometer. The position of the cork and thermometer were Adjusted so
the cork fits tightly, the thermometer and the jar are coaxial, and the
thermometer bulb is immersed to a depth that places the beginning of the
capillary 3 mm below the surface of the test specimen.
3. Because the expected pour point is greater than 36°C, the sample was heated
to 9°C above the expected pour point.
4. As soon as the test specimen had reached the required temperature, the cork
carrying the thermometer was removed and the test specimen was stirred gently
with a spatula. The cork carrying the thermometer was put back in place
5. The disk was placed in the bottom of the jacket. The disk and jacket were
placed in the cooling medium a minimum of 10 min before the test jar is
inserted. The test jar was removed from the water bath and dried with a tissue.
The gasket was placed around the test jar, 25 mm from the bottom. The test jar
was inserted into the jacket in the first bath maintained at 21°C and commence
observations for pour point. A test jar was never placed directly into the cooling
medium.
6. Care was taken not to disturb the mass of test specimen nor permit the
thermometer to shift in the test specimen; any disturbance of the spongy network
of wax crystals will lead to a lower pour point and erroneous results.
7. Pour points were expressed in temperatures which are positive or negative
multiples of 3°C. Examination of the appearance of the test specimen started
when the temperature of the test specimen was 9°C above the expected pour
point (estimated as a multiple of 3°C). At each test thermometer reading, which
is a multiple of 3°C below the starting temperature, the test jar was removed
from the jacket. Then the jar was tilted just enough to ascertain whether there is
movement of the test specimen in the jar. When movement is observed,
immediately return the test jar into the jacket. The complete operation of
removal and replacement shall require not more than 3 s.
8. When the test specimen has not ceased to flow when its temperature had
reached 30°C, the test jar was transferred to the next lower temperature bath per
the following schedule:
(a) The test specimen at + 30°C, moved to 0°C bath;
(b) The test specimen at + 9°C, moved to - 18°C bath;
(c) The test specimen at - 9°C, moved to - 33°C bath; and
(d) The test specimen at - 24°C, moved to - 51°C bath.
9. As soon as the test specimen in the jar does not flow when tilted, the jar was
held in a horizontal position for 5 s. If the test specimen showed any movement,
the test jar was replaced immediately in the jacket and a test repeated for flow at
the next temperature, 3°C lower.
10. This manner was continued until a point was reached at which the test
specimen showed no movement when the test jar was held in a horizontal
position for 5 s. The observed reading was recorded of the test temperature.
Calculation and report
3°C were added to the temperature recorded and reported as maximum pour
point. The results of untreated crude oil samples were shown in table 9.
Fig 5 Apparatus for pour point test
Table 9: pour point for untreated samples.
Field
Toma South
Munga
El Toor
El Nar
Nile blend
Pour point ˚C
45
45
45
39
33
27
Unity
Heglig
Bamboo
24
6
2.6 Viscosity measurement
Apparatus:
Brookfield DV-II+ programmable viscometer.
Temperature – control bath, for work at other than ambient
temperature, and large enough to hold the sample container.
Procedure (untreated sample):
1. The crude oil sample was heated to 60 °C.
2. The viscometer cell was heated to 60 °C.
4. The crude oil sample was placed in a viscometer cell.
5. Spindle (SC4-21) was inserted into the sample cell up to the reference
mark.
6. Spindle speed was selected (10 rpm), the sample viscosity in cP (mPa.s)
at 9.3 shear rate (1/sec).
7. The test was started after the temperature of water bath was decreased
into required one (28 °C).
Procedure (treated sample):
1. Different dosage of PPD (100, 150, 200, 250, 300 and 500 ppm) was
injected in crude oil sample (100 ml) to optimize the appropriate dosage.
2. The sample was placed in a water bath, preheated to 98 °C for 35 min
(agitate each 5 min).
3. The sample was cooled down to 65 °C.
4. The viscosity was measured using Brookfeild viscometer DV II+.
Viscosity was measured for the seven fields and a blend made by
the ratio shown in table 10.
Viscosity of untreated crude samples (blend and seven different
fields) and treated (blend, Munga, El Toor and Toma South)
measured by Brookfield DV-II viscometer were shown in
Appendix (A) and (B) respectively. Viscosity Vs temperature
profile for treated and untreated crude samples were shown in
Appendix (C).
Table 10: Ratio of fields in the blend sample
Field
Ratio
Heglig
25
Unity
22
El Nar
9
El Toor
8
Toma South
16
Munga
7
Bamboo
13
CHAPTER THREE
DISCUSSION
The Crude oil sample (Nile blend) was taken from Khartoum refinery, other
crude samples of different fields were taken from wells bore in Heglig region,
those included Heglig, Unity, El Nar, El Toor, Toma South, Bamboo and
Munga.
Different methods were used to determine the wax content of crude oil samples
including Nile blend. The UOP 46-64 is standard method for measuring wax
content, but it contains a fuller’s earth as a clarification step which adsorb some
portions of wax. The results of this method were shown in table 4. The
adsorption of wax on fuller’s earth had been checked by washing it with 400 ml
petroleum spirit. The UOP 46-85 method involves addition of sulfuric acid to
remove asphaltene; the acid tar formed was difficult to remove. This tar was
then washed with warm water and ammonium hydroxide solution. Water forms
a stable emulsion layer with the crude sample which was difficult to remove
(unless by breaking the emulsion layer by using a demulsifier), the resultant wax
content was found to be high because wax contained some water which could
not be removed just by heating to 105 ˚C as described by the method or even by
addition of a drying agent such as sodium sulphate anhydrous. A modified
procedure has been developed (Burger et al, 1981) which determined the total
amount of wax crystal in an oil sample. This acetone precipitation technique
does not involve removal of asphaltene and other solid deposits since the study
was not to investigate the chemistry of deposited wax, but to quantify the rate at
which the wax would deposit in a pipeline. In this work asphaltene was removed
by adsorbing the crude samples (dissolved in p-xylene) on alumina followed by
extraction with p-xylene (48 hrs) which dissolves only the wax adsorbed on
alumina. This procedure was found to be more suitable for isolation of wax free
of asphaltene. Table 5 shows wax content of Nile blend by using three different
methods. Table 6 shows wax content by using acetone precipitation technique.
Table 4: Measurement of wax content by using UOP 46-64 method:
Field
Wax content Wt %
El Nar
29.604
Heglig
Toma South
Munga
Unity
Nile blend
El Toor
Bamboo
26.172
25.851
16.957
16.192
15.414
12.198
11.284
Table 5. Wax content of Nile blend (three methods):
Sample: Nile blend
Wax content (Wt%)
UOP46-64 UOP46-85
15.414
37.51
Acetone precipitation
technique
18.216
Table 6: Measurement of wax content by using acetone precipitation
technique:
Field
El Nar
Heglig
Toma South
Munga
Unity
Nile blend
El Toor
Bamboo
Wax content Wt %
38.651
35.579
34.128
19.921
19.126
18.216
14.809
13.623
Table 7 shows weight % of macro and microcrystalline wax in the crude oil
samples of different fields by using the method described by Nguyen et al 1999.
Table 7: Macro and microcrystalline wax (Wt%) in different fields.
Field
Heglig
Unity
El Toor
El Nar
Toma South
Munga
Bamboo
Macro wax (Wt%)
97.5859
98.952
Micro wax (Wt%)
2.3165
0.547
14.809
53.554
34.258
37.990
97.806
84.462
46.009
64.244
61.370
1.822
El Toor field has the highest weight percentage of microcrystalline wax
(84.462), the carbon chain distribution of this field obtained by GC extend to
nC59 (fig. 11). Toma South field has (64.244%) weight of microcrystalline wax
and carbon chain extend to nC60 (fig. 12). Toma South and Eltoor fields has
same pour point (45˚C) although the former has less weight of microcrystalline
wax, and this can be explained by the presence of nC60 in Toma South field and
its high wax content.
Munga and El Nar fields has (61.370 and 46.009) weight of microcrystalline
wax, the carbon chain extend to nC57, nC52 (fig. 10 and 9) and pour point of (45,
39˚C) respectively. Heglieg, Bamboo and unity fields have lowest weight of
microcrystalline wax (2.3165, 1.822 and 0.547%) respectively and hence low
pour point (24, 6 and 24 ˚C) in comparison with other fields. Bamboo field has a
lowest wax content (13.623%) and very low concentration (small peak area) of
the nC27-nC48 region (fig. 6).
The pentane soluble waxes contain n-alkanes (< C40) and the insoluble waxes
contain microcrystalline waxes (> C40) whose extremely poor solubility may
potentially cause wax deposition problems especially in storage tanks. The
quantitations of these higher carbon number components were correlated with
other physical properties (pour point and viscosity) different correlations were
obtained.
Figures 6–12 shows the high temperature gas chromatography chromatograms
(HTGC) of total wax fractions isolated from 7 fields. Figures 13 and 14 shows
the chromatograms for the macro and micro-crystalline waxes isolated from
Eltoor field respectively by using the method described by (Nguyen, X. et al,
1999). HTGC for Bamboo field (fig 6) indicate that this field contains high
concentration of nC26 and small quantity of C27-C48 wax fraction, (Wt% of
macro wax 97.806 and micro wax 1.822). Fig. 7 show HTGC for Heglig field
which extent to nC47, the pour point of this field was 24 and micro wax Wt%
2.3165 (total wax content 38.579). In comparison with Unity field (pour point
27˚C, Wt% of micro 0.547, total wax content 19.126), Heglig field has lower
pour point although it has higher wax content than Unity field and this due to the
abundance of high molecular weight hydrocarbon extended to nC53 in Unity
field as indicated in fig. 8. The HTGC for waxes isolated from El Nar (fig. 9),
Munga (fig. 10), El Toor (fig. 11), Toma South (fig. 12) indicate the similarities
of these waxes in composition and they are predominantly micro- crystalline.
The whole oil GC for these fields appear to contain a significantly higher
proportion of the high molecular weight hydrocarbon in the region above C20.
The pour point and viscosity were measured for treated and untreated crude oil
samples. Two different chemicals Champion Enhanced and Deva Flow 009
were injected at different dosages to the crude samples to improve the pour point
and viscosity. Crude samples selected are those, which have high weight of
microcrystalline wax, high pour point and long carbon chain (blend, Munga, El
Toor and Toma South). Table 11 shows the pour point for untreated and treated
samples.
Table 11: Pour point for treated and untreated oils:
Field
Pour point ˚C
(untreated)
Pour point ˚C
(treated with Champion
enhanced 300 ppm)
Munga
El Toor
Toma South
Nile blend
45
45
45
33
30
30
36
27
Viscosity of untreated crude samples (blend and seven different fields) and treated (blend, Munga, El Toor and Toma South) measured by
Brookfield DV-II viscometer is shown in Appendix (A) and (B) respectively. Viscosity Vs temperature profile for treated and untreated
crude samples are shown in Appendix (C). Paraffinic crude oils behave as Newtonian fluids at temperature above their cloud point.
Thixotropic characteristics begin to appear at just below the cloud point of the crude because of precipitated wax crystals.
The data of wax content, carbon number, viscosity and pour point of the seven
fields (table 12) was analyzed by using SPSS program (Statistical Package of
Social Science).
Table 12: Wax content, carbon number, Viscosity cp. @ 40 ˚C and pour
point for seven different fields.
Field
Wax Content
Wt%
Heglig
35.579
19.126
Unity
14.809
El Toor
38.651
El Nar
34.128
Toma South
19.921
Munga
13.623
Bamboo
Carbon Number
Cx
Viscosity
cp. @ 40 ˚C
Pour point
˚C
47
53
59
52
60
57
48
90
75
2175
185
1075
1470
605
24
27
45
39
45
45
6
The correlation was significant when P < 0.05 and not significant when P > 0.05
(P = probability factor). The results show no correlation between wax content
and pour point (0.619), also no correlation between wax content and viscosity
(0.260) of the oil, whereas correlation was obtained between carbon number and
viscosity (0.05) and pour point (0.017). Viscosity and pour point were increased
with increasing carbon number of wax in crude oil. This correlation was not
found in Bamboo field (wax content 13.623 Wt%), which has high viscosity and
low pour point. Crude assay of this field reported asphaltene content as (11%)
and HTGC start from C10. The heaviness of this oil can be explained as a result
of a relatively high proportion of a mixed bag of complex, high molecular
weight (fig 1), non-paraffinic compounds and a low proportion of volatile, low
molecular weight compounds. Paraffins actually tend to act as solvent molecules
for the mixed bag of high molecular weight compounds and tend to improve the
overall flow characteristics of the oil.
The pour point and viscosity were also affected by the weight of macro and
microcrystalline wax present in individual crude oil. Toma South (fig 7), Eltoor
(fig 6) and Munga (fig 5) fields have the highest carbon number (60, 59 and 57
respectively) and high weight of microcrystalline wax fraction (64.244, 84.462
and 61.370 respectively) were found to have higher viscosity (1075, 2175 and
1470 @ 40 ˚C respectively) and pour point (45 ˚C). These three fields have high
pour point and this can be explained by the presence of high molecular weight
hydrocarbon (> C40) (table 12). The two chemicals (Champion Enhanced and
Deva Flow 009) were added to the blend made with the ratio shown in table 10.
Table 10: Ratio of fields in the blend sample
El Nar
El Toor Toma South Munga Bamboo
Field Heglig Unity
25
22
9
8
16
7
13
Ratio
Tables 13 and 14 show the viscosity of the blend at different temperature when
treated with Champion Enhanced and Deva Flow respectively. Champion
Enhanced (optimum dosage 300 ppm, table 13) was found to be slightly better
than Deva flow 009 (table 14) in decreasing viscosity of blend oil to 130 cp @
28 ˚C. Table 15 shows the comparison between the two chemicals in decreasing
the viscosity and pour point of the blend sample. It was observed that, the two
chemicals decrease the pour point of the blend from 33 to 27 ˚C. The Nile blend
was found to have high viscosity at high temperature when treated with Deva
flow 009 (300 ppm), viscosity was 40 cp @ 59.9 ˚C and 70 cp @ 56.7 ˚C (fig
15, appendix C).
Table 13: Nile blend treated with different dosage of champion Enhanced
chemical:
Dosage
Temperature
˚C
60
55
50
45
40
35
30
28
25
0 ppm
viscosity
(cp) @
9.3 s-1
75
75
90
120
205
620
3535
Gelled
200 ppm
viscosity
(cp) @
9.3 s-1
45
55
60
75
100
125
215
260
360
250 ppm
viscosity
(cp) @
9.3 s-1
45
50
65
70
90
110
145
185
235
300 ppm
viscosity
(cp) @
9.3 s-1
35
35
50
55
65
90
115
130
225
500 ppm
viscosity
(cp) @
9.3 s-1
35
35
40
55
65
85
115
130
220
Table 14: Nile blend treated with different dosage of Deva Flow 009
chemical:
Dosage
Temperature
˚C
60
55
50
45
40
35
30
28
25
0 ppm 200 ppm
viscosity viscosity
(cp) @ (cp) @
9.3 s-1
9.3 s-1
75
55
75
60
90
60
120
70
205
80
620
90
3535
140
Gelled
170
195
250 ppm
viscosity
(cp) @
9.3 s-1
55
55
60
75
85
125
200
240
275
300 ppm
viscosity
(cp) @
9.3 s-1
40
55
60
60
75
95
115
140
170
Table 15: Comparison of viscosity and pour point for Nile blend using two
different chemicals:
Temperature ˚C
Champion enhanced
300 ppm viscosity
(cp) @ 9.3 s-1
Deva flow 009 – 300
ppm viscosity (cp) @
9.3 s-1
Blank oil viscosity
(cp) @ 9.3 s-1
50
45
40
35
30
28
Pour point ˚C
50
55
65
90
115
130
27
60
60
75
95
115
140
27
90
120
205
620
3535 Gelled
33
Champion chemical when added to the highest pour point field (El Toor, Toma
South and Munga), no improvement in the pour point was observed, the three
fields still had high pour point (table 11). Table 16 shows the viscosity of
untreated and treated (Champion Enhanced chemical 300 ppm) crude oil
samples of El Toor, Toma South and Munga. Viscosity of El Toor field
(untreated) (wax content 14.809, wt% of micro wax fraction 84.462) was > 3285
cp @ 35 ˚C (gel @ 28 ˚C). The treated sample the viscosity decreased to 3205
cp @ 28 ˚C, so no improvement in viscosity was observed. For Toma South
field where wax content (34.128 Wt%) and wt% of micro wax fraction (64.244),
the chemical decreased the viscosity from > 3500 to 2085 cp @ 28 ˚C (still
viscous). For Munga the chemical improved the viscosity from > 3795 to 415 cp
@ 28 ˚C (untreated was gel at this temperature).
From this observation we note that, the Champion Enhanced chemical does not
improve the viscosity of El Toor and Toma South fields in comparison with
Munga field, and this can be explained by the presence of nC59 – nC60 fractions
in the former fields. So the efficiency of this chemical decreases by increasing
the carbon chain length and this is shown in table 17.
Table 16: Comparison of viscosity at different temperatures for untreated –
treated (champion enhanced 300 ppm chemical) fields (El Toor, Toma
South and Munga)
1. El Toor field:
Temperature ˚C
60
55
50
45
40
35
30
28
viscosity (cp) @ 9.3 s-1
(untreated)
130
145
320
880
2175
> 3285
-
viscosity (cp) @ 9.3 s-1
(treated)
40
35
35
50
60
195
1230
3205
viscosity (cp) @ 9.3 s-1
(untreated)
viscosity (cp) @ 9.3 s-1
(treated)
2. Toma South field:
Temperature ˚C
60
55
50
45
40
35
30
28
60
60
90
400
1075
3500
-
35
30
40
50
70
200
1365
2085
viscosity (cp) @ 9.3 s-1
(untreated)
50
55
175
535
1820
3795
-
viscosity (cp) @ 9.3 s-1
(treated)
30
30
35
45
55
65
230
415
3. Munga field:
Temperature ˚C
60
55
50
45
40
37
30
28
Table 17: effect of carbon chain length on the efficiency of Champion
Enhanced chemical
Field
Munga
Toma South
El Toor
Carbon chain length
Viscosity (cp) @ 28˚C
nC57
415
nC60
nC59
2085
3205
The additives used in this study (Champion enhanced and Deva Flow) loose its effectiveness to depress the pour point after a few days.
Conclusion:
1.
The measurement of wax content depends on the method used. Acetone precipitation technique was found to be better
in determining wax content than UOP 46-64 and UOP 46-85.
2.
Wax types had significant effect on the viscosity and pour point of the oil. The higher the weight of microcrystalline
waxes, the higher viscosity and pour point of the oil.
3.
The pour point and viscosity increase by increasing the carbon chain distribution in the crude oil.
4.
The heaviness of the oil could be explained as a result of a relatively high proportion of a mixed bag of complex, high
molecular weight (Bamboo field), non-paraffinic compounds and a low proportion of volatile, low molecular weight
compounds.
5.
6.
No correlation was obtained between wax content, pour point and viscosity of the oil.
There was significant (P<0.05) positive correlation between wax composition (distribution of carbon chain), viscosity
and pour point of the oil.
7.
The rapid rise in viscosity near the pour point of the crudes was a commonly observed trait for high paraffin content
systems.
8.
Nile blend crude oil behaves as Newtonian fluids at temperature above their cloud point. Thixotropic characteristics
begin to appear at just below the cloud point of the crude because of precipitated wax crystals.
9.
The efficiency of chemical additives (Champion Enhanced) used to decrease the pour point and viscosity of the oil was
significantly affected by the weight of microcrystalline wax fraction and carbon chain distribution present in the crude
(the efficiency of the additive decreases by increasing the weight of microcrystalline wax fraction).
10.
The additives used in this study (Champion enhanced and Deva Flow) lost their effectiveness to decrease the pour
point after a few days.
Recommendation:
Despite the results obtained in this study further investigation could be useful to determine the following points:
1.
Paraffin deposition test by using the rotating disc apparatus should be done for blank and treated oil, the wax deposit
2.
There are different factors affecting the performance of crude oil wax control additives such as polymer backbone,
3.
The pour point and viscosity do not completely indicate a crude oil’s flow properties. Yield stress and gel strength
4.
Microbial culture products (MCPs) have been proven to be safe and effective solution for treating many common
should be weighed and then separated by GC to predict the effectiveness of paraffin deposition inhibitors.
length of the pendant chain length, polymer molecular weight and polymer dilution. These factors should be tested.
should also be considered.
problems in oil production. This new technology should be tested in our paraffinic crude oil and compared with the
traditional chemicals used.
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