Subido por andres yrigoyen

SPE-03649-Impact of Oil Field Chemical on Refineries

Paper No.
Sergio Kapusta
Shell Global Solutions U.S., Inc.
P.O.Box 1380
Houston, TX 77251
Frans van den Berg, Rinus Daane
Shell Global Solutions International B.V.
P.O.Box 38000
1030 BN Amsterdam, The Netherlands
Morris C. Place
Champion Technologies Inc.
P.O. Box 450499
Fresno, TX 77245-0499
Chemical additives play an important role in oil production. Chemicals are used to enhance oil
production, control corrosion, prevent wax or paraffin deposition, enhance the flow characteristics
of the crude oils, aid in water separation, etc. However, oil field chemicals are often suspected of
causing diverse problems in refining operations, including corrosion, fouling, desalting upsets,
and loss of catalyst activity. One recent example is the appearance of "rogue chlorides" in certain
crudes, which has led to severe corrosion problems in crude distillation units and naphtha
hydrotreaters. This paper presents a review of the nature and function of chemical additives that
are commonly used in oil production, and discusses examples of the type of problems
encountered in refining that are caused by some of these chemicals. A clear understanding of the
impact of oil field chemicals on refinery operations is critical to both refiners and producers, to
avoid these problems and prevent the erosion of value of the crude. Better communications
between producers and refiners is a first step to resolve these problems.
Keywords: corrosion, corrosion control, oil field, chemicals, refining, inhibitors, paraffin, hydrate,
Oil Field Chemicals (OFC) are used for various purposes in oil production, including
corrosion control, management of hydrate formation, prevention of wax or paraffin deposition,
enhancement of the flow characteristics of heavy crudes, oil dehydration, water de-oiling and well
stimulation. In particular, economic oil production from ever deeper offshore reservoirs depends
heavily on the use of chemicals to maintain adequate flow from the well bore to the separation
facilities, by preventing mineral scales and wax deposits from plugging the connecting flowlines.
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Other chemicals are used to assist in the various techniques that renew the flow of crude oil from
older fields (steam, carbon dioxide, polymer flooding, etc.). Many different chemicals are used in
the oil field, and their volume seems to be increasing with production from more challenging
environments, as shown in Figure 1 (1). The world market for OFC reached 5 billion $ in 2000
and is expected to grow further (2).
Chemical usage [kTONs]
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FIGURE 1 - Trend in the use of production chemicals in fields operated by a major European oil
company (1)
However, some of these chemicals may also cause processing problems in refineries. The most
common problems that are often associated with the presence of OFC in the crude are: desalting
upsets, corrosion in the overhead system of crude distillation units and in hydrotreaters, fouling of
catalysts, foaming of amine treating units, and fouling of heat exchangers. In many cases the
actual relationship between OFC and refinery upsets is hard to prove, as other operational or
crude oil factors may account for the observed problems. But the perception that a crude oil is
"troublesome" can nevertheless have a negative effect on its value. An understanding of the
impact of OFC on refining operations is therefore of critical importance not only to refiners, but
also to producers since both are interested in minimizing any negative effect of these chemicals
on the operation of the refinery.
The impact of OFC on refinery operations, particularly corrosion, has been studied on previous
occasions. However, an update of this topic seems timely because a series of incidents related
in part to the presence of organic chlorides in the crude has resulted in a renewed awareness in
the refining industry that some otherwise "unexplained" processing problems may be caused by
OFC. Whether this awareness reflects an actual increase in the severity or frequency of these
problems is more difficult to assess, because a systematic evaluation of these issues has not
been undertaken, and most of the evidence is anecdotal. It is likely that the overall crude oil pool
now contains more additives than in the past, as production from deepwater reservoirs, which is
more dependent on these additives, becomes an increasing proportion of the total crude oil
supply. It is also true that more strict environmental regulations designed to reduce the amount of
chemicals and oil that are released into the water have prompted the producers to use more deoiling chemicals, and in general more chemicals that partition preferably to the oil phase.
The fate of OFC once they enter a refinery is not fully understood, and this in itself is a problem.
The intention of this paper is to bridge this knowledge gap between producers and refiners by
presenting an update of the nature and function of chemical additives commonly used in oil
production, and some examples of the processing problems that can be attributed to these
chemicals. Suggestions to improve the existing situation will also be presented.
Table 1 summarizes the generic chemical composition and the estimated partition to the
water phase of the most common chemicals used in the oil field, with the exception of corrosion
inhibitors, which are discussed separately. It should be noted that water partitioning is a function
of several variables (especially water cut, but also temperature, pH, salinity, etc,) and the
numbers quoted below are only a first estimate.
Generic Description
Paraffin Inhibitors
Ethylene/vinyl acetate copolymers
Olefin/ester copolymers
Ester/vinyl acetate copolymers
Alkyl phenol resins
Amine oxides
Nonionic surfactants
Aliphatic (i.e., heptane)
Aromatic (i.e., xylene, toluene)
Pinene/Terpene Derivatives
Polyolefin copolymers
Alkyl phenol resins
Amine oxides
Quaternary Amines
Sulfated ether alcohols
Polyether alcohols
Fatty acid ethoxylate
Silicone fluids/Fluorosilicones
Alkyl benzyl ammonium quats
Polyphosphinocarboxylic acids
Phosphate Esters
Polyvinylpyrollidone (PVP)
Polyvinylcaprolactam (PVCAP)
VP/VC copolymers
Alkyl phenol ethoxylates
Alkyl phenyl phosphonium quats and
Paraffin Dispersants
Paraffin/Asphaltene solvents
Asphaltene Inhibitors
Asphaltene Dispersants
Scale Inhibitors
Partition to water, %
Table 1 shows that many chemicals end up in the oil phase, although they are not expected to
produce any problems in refining. The increasing emphasis on water quality and water reinjection, and the zero-discharge policies in many offshore production regions has put increasing
pressure on the suppliers and users of chemicals to develop oil-soluble additives for many
Corrosion inhibitors
The typical oil field corrosion inhibitors are based on film forming amines, amides, imidazolines or
quaternary ammonium compounds, or phosphate esters of long chain alcohols. The molecular
weight is relatively high to provide high temperature stability under downhole conditions. Table 2
summarizes the chemical nature and physical properties of some of the most common corrosion
Generic name
Fatty amides
Quaternary ammonium
Phosphate esters
stability °C
Solubility in oil
200- 300
60- 70
The partitioning of the above molecules in brine depends on the size and shape of the molecules
and on temperature, the salinity of the brine, the gravity of hydrocarbons and the ratio of oil to
The commercial inhibitor formulations contain, in addition to the active film-forming component,
other components to optimize the physical properties (viscosity, low temperature stability,
compatibility with the produced fluids, oil and water solubility or dispersibility) of the package that
is actually used. These compounds include emulsifiers, demulsifiers, stabilizers, solvents, etc.
The active components can be either water or oil soluble; water dispersible products are also
used. The inhibitor concentrations are usually estimated on the basis of the full formulation, and
can range from 10 to 200 ppmw in crude oil. The active component can represent between 20
and 80 % of the total package.
The active inhibitor components tend to be effective emulsifiers. This characteristic creates
problems related to the formation of stable oil/water emulsions not only for oil/water separation at
the production facilities, but also during dewatering of the crudes (removal of decanted water) in
the separation/storage tanks, and desalting of the oil at the refinery. The desalted crude may
contain higher levels of water and of hydrolysable salts, which result in higher chloride levels and
higher corrosion rates in the overhead system of the crude distillation unit.
These problems have been observed in several refineries receiving crudes from fields where oil
soluble/water dispersible inhibitors had been used. Water-soluble inhibitors are less likely to
cause this type of problem. In the past, this type of inhibitors did not have the high performance
required in very severe (hot and sour) environments. But their performance has continuously
improved, and they are now used also in very hostile environments containing H2S and CO2 at
temperatures up to 150 to 170 °C (300 to 350 °F).
The presence of corrosion inhibitors has also been associated with worsening quality of desalter
effluent water, also due to the formation of more stable emulsions.
Table 3 is a compilation of some of the refining problems that have been attributed to the
presence of OFC in the crude oil. The table also shows that in some cases alternative
explanations for the observed problems could not be positively excluded.
Poor tank farm
Desalter upsets,
High salt content of
desalted crude
Corrosion of pre-heat
Corrosion of furnace
CDU overhead
fouling and corrosion
by HCI and NH4CI
Catalysts poisoning,
fouling of catalyst
Catalyst bed
High water content of
hydrotreated naphtha
Poor bitumen quality
Foaming of amine
Corrosion of amine
Type of chemical presumed to
be responsible
Surfactants, corrosion inhibitors
Alternative causes
Higher Ca and Mg content of the
crude due to acidizing of wells
Presence of acidizing fluids
Improper desalter operation
Improper desalter operation
Presence of acidizing fluids,
particularly organic acids
Formation of H2S by high
temperature decomposition of the
Improper desalter operation
Presence of acidizing fluids, Ca/Mg
content due to acidizing of wells,
NH4CI used for post-flush,
decomposition of corrosion
inhibitors with formation of NH4CI
Organic chlorides from well bore
clean-up operations
Presence of slops
Inorganic chlorides
Iron sulphide in the crude, silt from
charge tank bottoms
Corrosion inhibitors
Silicon containing antifoaming
Glycol or glycol amines used for pH
Si-containing antifoaming agents
Corrosion inhibitors
High level of NHs due to
decomposition of amines used as
corrosion inhibitors or for pH
Inadequate separation of water in
the CDU overhead accumulator
Amine degradation, high HSS
content, hydrocarbon carry-over
NH3 in water used for desalting, for
example process water from
conversion units
The desalting process
Table 1 summarizes the type and generic oil/water partition tendency of chemicals used in oil
production. The partition tendency is important as an indication of the relative ease of removal of
these chemicals by desalting. However, water solubility is not a guarantee that the chemicals will
be fully removed by desalting or that they will not cause corrosion in the refinery, for several
(1) Some OFC are emulsifiers and have a negative effect on oil/water separation, causing
water soluble chemicals to end up in the oil phase as emulsions or entrained in water
(2) Thermodynamic equilibrium is not achieved during desalting. This means that even
chemicals that are fully water soluble partition to some extent to the oil phase.
(3) Although one can expect inorganic acids and low molecular weight organic acids, such
as HCI and acetic acid, to fully partition into the water phase, some heavier molecular
weight acids, such as phosphonic acid, will partition partly into the oil phase.
(4) Desalters may operate under non-optimal conditions, especially if they were designed for
processing crudes having different properties.
(5) The desalter operation cannot be changed fast enough to handle OFC which are used
intermittently, and which arrive unexpectedly at the refinery.
(6) Many refineries do not have desalters ahead of the crude distillation units.
Impact of OFC on refinery operations
The impact of OFC on refinery operations is diverse. While the majority of OFC travels through
the refining system without major effects, others may have harmful consequences in the following
hardware: increased corrosion, fouling of heat exchangers, plugging of pumps and lines
operational: formation of emulsions in storage tanks and desalters, foaming in flash
vessels and amine units, plugging of catalyst beds, increasing amount of waste streams
product quality: off spec jet fuels, poor bitumen, fuel oil or coke quality,
environmental: poor effluent water quality, increased emissions
The situation is further complicated by the fact that some OFC are applied continuously where
others are used only incidentally or in cyclical fashion. It has also been found that the effects can
be either direct or indirect. Producers may assume, sometimes incorrectly, that OFC will be
removed by the desalting process in the refinery. By way of examples the effect of hydrate
control, well acidising and well bore cleaning chemicals will be discussed.
Continuous vs. discontinuous use. Some oil field chemicals are applied at a more or less
continuous level, for example corrosion or wax deposition inhibitors. Other chemicals are used
more infrequently or on a cyclical basis. Examples of these are hydrate control inhibitors, which
may be used only during start-up or shutdown operations, and well bore cleaning solvents and
well stimulation acids, which are used as needed to maintain or enhance production. To a large
extent, the impact of continuously injected chemicals is easier to predict and counteract. On the
other hand, intermittently used chemicals can have a more detrimental impact because refineries
are neither aware nor prepared to deal with their effects. Their impact is also more difficult to
identify, because by the time that the refineries realize that something is wrong, the chemicals
may no longer be present.
Direct and Indirect Effects. The impact of oil field chemicals on corrosion in downstream
processing units can be direct or indirect. For example, acids used for well stimulation (HCI, HF,
formic) can be carried with the crude and directly cause corrosion in the pre-heat train of the
crude distillation unit. Emulsifying agents, on the other hand, are not corrosive. However, they
can indirectly cause corrosion of the overhead system by increasing the content of water and
hydrolysable salts in the crude, which lead to the formation of HCI during the distillation process.
Some oil field operations that are not intended to change the properties of the crude oil can
nevertheless have indirect consequences on the composition and behavior of the oil. For
example, water injection is a commonly used method for maintaining reservoir pressure and oil
production. Depending on the quality and treatment of the water, and other not fully understood
factors (presence of sulfate reducing bacteria in the reservoir, availability of nutrients), one
unintended consequence may be souring of the reservoir. This can effectively increase the
existent H2S content of the crude with potentially severe consequences not only due to enhanced
corrosivity but also because of increased health and safety risks. Although well stimulation is not
expected to affect the properties of the oil, there is circumstantial evidence of an increase in both
the existent and the potential H2Scontent of crudes after repeated acidizing treatments.
Hydrate Control. Hydrocarbon hydrates are clatrate-type compounds of water and
methane, ethane, propane, etc., that are formed at low temperatures and high pressures. They
tend to form ice-like clusters that can block production lines. Hydrate problems are particularly
difficult in deepwater production, because of the low temperatures of the seabed. For lines
operating in the stable hydrate region, two main types of hydrate control compounds are used:
(1) thermodynamic control chemicals that reduce the potential for hydrate formation, such as
methanol and glycol.
Both methanol and glycol are water soluble and should be extracted by wash water during
desalting, and therefore are not expected to cause any corrosion problems. However, some
instances of glycol contamination of naphtha have occurred. The presence of glycol can create
corrosion problems by enhancing the solubility of water in the hydrocarbon phase. This in turn
may contribute to corrosion problems in downstream units, such as naphtha hydrotreaters, that
are designed to operate essentially dry.
(2) kinetic control chemicals, or hydrate growth inhibitors, such as quaternary ammonium
compounds, that either prevent the growth of hydrate crystals capable of plugging the production
lines, or maintain the crystals dispersed and allow them to be removed by the flow in the lines.
These products are used at concentrations of several thousand ppm's, based on the water
content in the production lines. They are partially water soluble, which means that they are
separated from the oil in the production facilities or during desalting. However, some of the salts
are known to remain with the oil, for example by formation of water emulsions.
(3) Anti Agglomerate (AA) hydrate inhibitors prevent hydrate plugs by dispersing the hydrate
crystals rather than preventing the nucleation of hydrate crystals. This hydrate alleviation
technique requires the presence of a liquid hydrocarbon phase. The AA has a hydroratephilic
head that is incorporated into the hydrate crystals and a hydratephobic tail that disperses the
hydrate crystals into the liquid hydrocarbon phase. The advantage of AA hydrate inhibitors is that
they are effective at much lower sub-cooling temperatures than kinetic hydrate inhibitors. They
may be organic quaternary ammonium and phosphonium salts with long oleophillic tails (3).
The quaternary ammonium salts tend to decompose at the high temperatures of the distillation
process, with the formation of ammonium chloride and heavy hydrocarbons. The ammonium
chloride that is formed in this way can make a very significant contribution to raising the
desublimation temperature of this salt in the overhead system. As a result, salt deposition can
occur upstream of the water dew point.
Acidizing Treatments. Acidizing fluids include both strong mineral acids such as HCI and
HF, and weaker organic acids such as formic and acetic. They are used to dissolve the salts
(silicates and calcium or magnesium carbonates) from around the well bore and for some
distance into the formation, and sometimes to dissolve scales that form in the production tubulars.
The acids are not fully consumed during the process, and may be carried as contaminants in the
crude. These acids can cause severe corrosion problems in the storage tanks and also in the preheat train of the crude distillation unit. They are removed by water washing, and should not cause
problems downstream of the desalters.
As mentioned above, one of the purposes of acidizing is to dissolve calcium and magnesium
carbonates. The relative concentration of calcium and magnesium chlorides in the crude
increases for some time after acidizing of the producing wells. These salts are harder to remove
during desalting. As a result, both the content of hydrolizable chlorides and production of HCI by
hydrolysis of the salts increase, causing more severe corrosion in the overhead systems.
It has also been reported that acid stimulation may result in the formation of emulsions which are
very difficult to break and can cause considerable problems downstream (4).
Well bore cleaninq: Production of waxy or asphaltene crudes may result in the formation
of deposits in the well bore, that reduce its diameter and decrease the production rates. The well
bore can be washed with chemicals that dissolve and remove these deposits. In the past,
chlorinated solvents such as trichloroethane were commonly used for this purpose. After the
1994 Montreal Protocol that limited the production and use of chlorinated solvents, hot xylene
washes became the norm. However, this treatment is often not as effective as the previous
method and there seem to be instances in which chlorinated solvents are still used.
Organic chlorides are not removed from the crude by desalting; hence, they are also called
"non-desaltable chlorides". They are normally stable at the conditions of the crude distiller, which
means that they will mostly (95 to 99 %) pass through the distiller to the naphtha fraction.
However, even a small degree of decomposition in the CDU (Crude Distillation Unit) can result in
low pH corrosion of the overhead condensers if the concentration of organic chlorides in the
crude is above normal crude acceptance criteria.
Organic chlorides in the naphtha are converted to Hydrogen Chloride (HCI) in the NHT (Naphtha
Hydrotreater), where they combine with ammonia (NH3) to form ammonium chloride (NH4CI). The
amount and rate of NH4CI formation is controlled by the HCI level because of the over-abundance
of NH3 in the NHT effluent coming from the conversion of nitrogen in the feed. Depending on the
chloride level in the feed, the location of NH4CI deposition can shift. Solid NH4CI tends to deposit
at temperatures as high as 150 to 170 °C. This temperature range often corresponds to the
coldest effluent exchangers.
The dry NH4CI salt is not corrosive, but can cause fouling and plugging of heat exchanger tubes.
The salt is very hygroscopic, which means it will pull water out of the vapor phase. The wet salt
can be extremely corrosive. Most corrosion problems in hydrotreaters result from the deposition
of wet NH4CI.
Occasions of NHT corrosion and fouling due to organic acids occurred regularly in the 70's and
early 80's until the problem was recognized and pipeline companies and refineries, especially in
the US, developed a test method (ASTM D4929) and defined upper limits to the allowable
amount of organic chloride in crudes (5). However, the problem has not completely disappeared.
In January 2000, a refinery in the US experienced a sudden and catastrophic rupture of a heat
exchanger shell in their naphtha hydrotreating unit. One operator was severely burned, the NHT
was heavily damaged and the refinery suffered a serious loss due to the unavailability of the unit
for three months. Several European refineries recently detected varying levels of organic
chlorides in Ural crude and measured high corrosion rates, necessitating hardware modifications.
It was found that the crudes contained 1 to 5 ppmw organic chlorides, which were subsequently
identified as mainly tri-chloroethane, a light molecular weight solvent. It is usually difficult to
positively determine the root source of organic chlorides in a crude. However, some clear
indications can be derived from the chemical nature of the chloride-compounds and from their
seasonal variations.
This discussion will be primarily directed toward oil and condensate production, although
the same issues are also important for gas production.
Everyone involved in producing and refining oil is interested in maintaining or enhancing the value
of the oil. Historically oil producers and refiners have independently tried to maximize the value
of their resources. Within specifications imposed by common carriers, oil producers maximize
production and minimize expense without a lot of knowledge of the effect of their operations on
refining. Likewise, refiners do not always like the quality of the crude of the crude that they
receive as a result of oil field operations, but they do are not fully aware of the consequences, in
terms of production volume and prices, of changing oil field practices to eliminate undesirable
It is clear that a co-operative effort is the most effective way to resolve the problems caused by oil
field chemicals on refinery operations. This discussion is an effort to increase awareness and
open the technical communication between oil producers and oil refiners.
Actions to reduce the impact of OFC
Technically, decreasing the effect of OFC on the refineries appears to be feasible. An example of
the type of changes that are possible when providers and users of chemicals work together is the
development of more environmentally friendly chemicals. Major oil companies are committed to
make continuous improvements in the environmental consequences of their operations.
Producing companies already require chemical vendors to supply detailed information on their
chemicals and could include the potential impact of OFC on downstream refineries in their
chemical selection process. In several parts of the world, E&P companies already prepare
Environmental Impact Assessment reports for the local government and discuss ways of further
reducing their impact on the environment. A full EIA requires a detailed survey of all chemicals in
use, including SMDS sheets, toxicity evaluation, oil-water partitioning behavior etc. It would be
relatively easy to expand this assessment with a module evaluating the impact of OFC on the
In the absence of such data, crude buyers will become increasingly more demanding with regards
to crude composition requirements. Future crude contracts may require the supplier to disclose
information on OFC or guarantee the absence of the most harmful OFC's.
Improvements in OFC
Additive suppliers are actively working on providing better alternatives for harmful or
environmentally undesirable chemicals. Scale inhibitors are mainly water soluble, and are
expected to be removed from the oil during field processing.
Corrosion inhibitors: Historically, oil soluble inhibitors were the best in controlling the most
difficult corrosion problems. These "Best" corrosion inhibitors also caused severe emulsions,
both in the production facilities and at the front end of the refineries. Today, more effective
corrosion inhibitors have been developed that do not cause the same type of emulsion problems.
In a recent case of a very corrosive sour environment, a proven effective emulsion forming oil
soluble inhibitor was replaced by an equally effective oil soluble inhibitor which did not have the
same severe emulsion-forming tendency. In addition to solving downstream processing
problems, the need for a field demulsifier was reduced by 75%, with considerable cost savings for
the producer.
More effective water-soluble inhibitors are continuously being developed for increasingly hostile
environments (higher temperatures, higher H2S and CO2 partial pressures, higher velocities,
higher salinities). These corrosion inhibitors largely partition to the water phase and thus their
concentration in the oil is lower. Water soluble corrosion inhibitors are gradually replacing oil
soluble corrosion inhibitors in many offshore applications as a result of environmental
Hydrate control: The new anti-agglomerate hydrate inhibitors that have recently been
introduced into deepwater provinces are not yet widely used. They have some oil solubility and
residuals will remain in the crude oil. As the use of these products increases, and if the residuals
in crude oils cause problems in downstream processing, this is an area where refiners and
producers cooperatively minimize the impact on the crude oil value.
Acid stimulation: Acidification of well bores with organic and mineral acids usually results
in emulsion problems for the oil producer. Often the acids are present in the crude oil in tightly
held emulsions. The solution to corrosion of storage tanks and refinery pre-heat train and
desalters is good water removal by the producer, and perhaps the addition of a water-soluble
corrosion inhibitor when warranted. The increase in the concentration of hydrolizable chlorides in
the crude following acidizing operations is more difficult to manage. It requires refiners to be on
the look-out for possible spikes in the overhead chloride level, and be prepared to handle these
upsets by caustic injection, water washing, or the use of chemical additives.
Paraffin and asphaltene solvents: Domestically in the U.S., oil field chemicals with
chlorine have been prohibited for over 40 years, and throughout the world since the Montreal
protocol of 1994. Their presence in crude oil should be considered an aberration and not a
normal practice of the oil field.
Defoamers: These silicon defoamers, sometimes with added fluorine are essential to
maintaining the high volume offshore production, particularly deepwater production. As their use
increases, their affect on refineries will have to be evaluated. To date, non-silicon defoamers
have not been economically effective.
Industry wide efforts to deal with these issues
Fortunately, efforts to deal with the problem are already underway in some parts of the world (6):
The CCQTA (Canadian Crude Quality Technical Association), founded in 1996, is an example of
producers, pipeline companies and refiners working together on the subject of crude oil quality.
Their stated objective is:
"To facilitate the resolution of common crude quality issues by establishing a direct line of
communication between all sectors of the oil industry including producers, service companies,
chemical companies, pipeliners and refiners"
According to the CCQTA website (http://www.¢, there is a committee on additives
which for example distributed a note regarding fouling incidents in several distillation columns
caused by the presence of ppm levels of phosphate-ester based chemicals used to gel
hydrocarbons for hydraulic fracturing.
Similarly, the US based Crude Oil Quality Group (COQG) has started an Additives Subcommittee
which is starting to investigate this problem (see for details.).
Although the beginnings are modest and there are many uncertainties facing those active at the
interface between oil producers and oil refiners, there is no doubt that improved industry
cooperation is the way forward.
This paper is intended to bridge the knowledge gap between oil producers, oil refiners,
and suppliers of oil field production chemicals regarding the impact of these chemicals on refining
processes, and indirectly on the value of crudes. This is a first step to try to find a joint solution to
refining processing problems which originate in chemicals added for oil production. In the past, a
similar cooperation has yielded excellent results, for example in the development of more
environmentally friendly products. Some industry-wide groups are already taking further steps in
formalizing this cooperation.
The authors are grateful for the stimulating ideas and discussions with numerous
colleagues in Shell Global Solutions in Amsterdam and in Houston, and Ann Davis and Ali
Naraghi of Champion Technologies, Inc. for their help in preparing the chemical tables. We also
thank Shell Global Solutions International B.V. and Champion Technologies Inc. for permission to
publish this paper.
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