AKZO Oilfield Brochure 2011 Compact (2)

AkzoNobel Surface Chemistry in the oil industry

A broad product range for a wide spectrum of oilfield applicationsAkzoNobel Surface Chemistry has the global experience, expertise and sustainable solutions to help the oilfield industry enhance its production, drilling and stimulation processes. Our portfolio of products with advanced functionalities allows our customers to select the solution that best fits their specific needs in any particular oilfield application.

In this brochure, you will find our innovative offerings developed specifically for production and drilling applications. You can quickly scan and select the best products based on your needs.

AkzoNobel Surface Chemistry in the Oil Industry 3

R&D CentersBridgewater, USACroton River, USAChattanooga, USAHouston, USAFt. Worth, USAMexico City, MexicoDeventer, the NetherlandsItupeva, BrazilMumbai, IndiaSingaporeOsaka, JapanShanghai, ChinaStenungsund, Sweden

Surface Chemistry is a business unit of AkzoNobel, the largest global paints and coatings company and a major producer of specialty chemicals. Based in Chicago, USA, our business unit operates in 50 countries, employing over 1500

people. With regional marketing centers and R&D facilities worldwide, we are a leading supplier of specialty surfactants and synthetic and bio-polymer additives.

ManufacturingChattanooga, USAHouston, USAFt. Worth, USAItupeva, BrazilMons, BelgiumMorris, USASaskatoon, CanadaSalisbury, USA

SingaporeStenungsund, SwedenStockvik, SwedenYokkaichi, JapanOsaka, JapanShanghai/Zhangjiagang, China

We have dedicated oilfield technical teams working tirelessly to understand the performance characteristics of our existing product portfolio so that we can recommend the best possible candidates to address our customers technical needs. We also have dedicated research and development scientists developing the next generation of products for application in the uniquely challenging oilfield environment. Our strategic intent is to provide best-in-class performance while reducing the environmental impact of oilfield operations. Specifically, we aim to replace toxic chemistries used in the market today with more benign materials or to find more environmentally friendly versions of products from our own porftolio.

Our commitment to innovation for the oil industry

HeadquartersChicago, USABridgewater, USAStenungsund, SwedenSempach, SwitzerlandShanghai, ChinaSingapore

Sustainability is at the heart of everything we do at AkzoNobel. Were committed to reducing our impact on the planet by delivering more sustainable products and solutions to our customers.

Thats why we have integrated sustainability into every area of our business for the benefit of our customers, our shareholders, our employees, our communities, and the world around us. As a result, we have been ranked in the top two on the Dow Jones Sustainability Index for five years running.

For a sustainable future:


AkzoNobel Surface Chemistry also offers a variety of technologies that can be used in oilfield stimulation activities including cementing, fracturing and acidizing. Some of the technologies mentioned in this brochure can be applied to stimulation, but certainly not all. Stimulation application conditions have their own unique requirements and challenges. Especially when it comes to controlling the rheology of the applied fluids, water-based or oil-based.

Viscoelastic surfactant (VES) technologies are another essential class of chemistries produced by AkzoNobel Surface Chemistry. These products form worm-like micelles in concentrated acids and saline brines which viscosify the various water-based fluids required for fracturing and acidizing.

These materials, sold under the Aromox and Armovis trade names, provide significant performance benefits over conventional non-surfactant-based systems.

Additionally, we have secondary additives to help formulate fracturing and/or acidizing systems including foamers, corrosion inhibitors, organic viscosifiers and spacer additives. We also produce products that can be used in other oilfield applications, including enhanced oil recovery, shale-gas, pipeline and refinery.

Contact our sales representative in your region for in-depth technical data sheets (TDS) that are available for all these products, with descriptions of their performance characteristics and end-use properties.

Solutions for stimulation

Solutions for production applications

The production, separation and purification of crude oil and gas constitute a complex task that needs to be achieved not only safely but also quickly, economically, and in compliance with the regulatory restrictions of the operator's environment. Advances in understanding the characteristics of produced fluids, improvements in engineering design and materials science, as well as a greater appreciation of the mechanisms and conditions that promote production problems have all led to immense strides forward in the scale and speed of production. However, the task remains complex, and there is a continuing need in the industry for specialty chemical products to help meet productivity targets.

AkzoNobel Surface Chemistry has worked for many years to develop an extensive range of products that can address most of the compelling issues that the production engineer and service provider face on a daily basis.

Our product line for production applications includes demulsifiers, corrosion inhibitors, scale inhibitors, paraffin control, biocides, water clarifiers and deoilers, asphaltene inhibitors, and foamers.


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Demulsifiers


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Due to the high throughput requirement of most oilfield separation systems, gravity separation of the emulsions is insufficient, particularly if the relative gravitational difference between hydrocarbon and water is negligible e.g., steam-assisted gravity drainage (SAG-D). Therefore, assistance is required to achieve satisfactory throughput.

To achieve optimized demulsification, natural gas needs to be removed from the fluids to encourage quiescent coalescence of the emulsion. This is physically aided through heating of the oil and/or the emulsion pad. This helps melt waxes and reduces the crude oils viscosity, allowing the water droplets to settle out more quickly.

During the production of crude oil, a single hydrocarbon phase is rarely produced. Co-produced with the oil are natural gas and an amount of water, usually saline, which as the reservoir is depleted, can be present in quite large proportions. During the production process, the fluids experience significant shearing in different locations, including the perforated zone, the downhole pump and the wellhead. Emulsifying agents naturally present in the crude oil, such as asphaltenes and the soaps of linear and aromatic organic acids, along with solids such as clays, sand and scale, stabilize the crude oil/water interface and make the emulsions difficult or slow to separate. In most oilfield applications, the initial crude is an oil-continuous emulsion that, upon treatment, can invert to become water-continuous, requiring the use of deoilers, which are covered separately.

However, by far the most common treatment to help break the emulsion is the addition of formulated chemical demulsifiers. These chemical additives are usually injected at the wellhead to achieve adequate mixing prior to the separator so that the demulsifier can reach the target interface and function effectively. To reach the surface of the emulsified water droplets, the demulsifier blend must have the right solubility. The chemical demulsifier is attracted to the emulsifying agent through differences in polarity. Once at the target, it neutralizes the effect of the emulsifying agent, allowing the finely dispersed water droplets to coalesce upon contact. As the water droplets increase in size, they tend to settle, separating the water from the oil.

The stability of an emulsion is unique to each reservoir, and may vary from well to well. As such, it is necessary to develop demulsifier blends specifically targeted at fluids produced. Witbreak demulsifier products should be considered as concentrated raw materials, or intermediates, for the preparation and/or formulation of oilfield demulsifiers and dehydrating chemicals. Field demulsifiers are usually blends of two or more intermediates, selected on the basis of their performance in bottle tests and centrifuge tests, the methods of which can be found in separate publications.

These tests help identify the products that produce the maximum amount of water and the cleanest oil. The samples should be examined for fastest water drop, sludging, quality of the interface, and quality of the water. The best-performing candidates should have bottle tests repeated using different combinations and concentrations until eventually the best performance blend is found.

Relative solubility number

Another useful guide in formulation is the Relative Solubility Number (RSN), which helps eliminate some of the trial-and-error involved in formulating demulsifier blends. The value assigned to each product indicates its relative solubility in water. As the numerical value increases, water solubility increases. Generally, products with a solubility number below 13 are insoluble in water. Products with solubility between 13 and 17 are dispersible in water at low concentrations and form gels at high concentrations. Products with values of 17 and above are completely water-soluble.

The following are general guidelines for the RSN system:

For crude oil emulsions, a demulsifier formulation should have an RSN between 8 and 15. The RSN values combine algebraically. For example, a 50-50 blend of a product with an RSN of 10 and a product with an RSN of 20 will yield a blend RSN of 15.

In general, synergistic action between intermediates makes demulsifier blends better than single-component formulations.

Demulsifiers with either very low or very high RSN values are seldom used individually; their properties can be best utilized by blending.

Due to synergism, blends of intermediates from different chemical groups make better demulsifiers than blends using intermediates from the same family of compounds.

Some demulsifier bases have special properties that give them very good blending characteristics. This is the case with highly oil-soluble (low RSN) polglycols. When blended with oxyalkylated resins, some


excellent demulsifier formulations have been developed for the oil industry. Other effective combinations include oxyalkylated resins blended with polyols, diepoxides or polyacrylate-based intermediates.

To dehydrate crude oil to a sufficient level to achieve export quality, a combination of water droppers and oil dryers need to be used in the final demulsifier blend. While the droppers may work very quickly due to flocculation of large droplets, usually the base sediment and water (BS+W) will be greater than 1 percent - not sufficient to complete the job. Drying demulsifiers help

reduce the water content further via coalescence of the fine emulsion droplets, but this function usually takes longer. A balanced formulation of droppers and driers is usually required to achieve target. Typical dropper/drying characteristics of individual demulsifiers are given.

Desalting

Another important demulsifier application occurs at the refinery and is referred to as desalting. The imported crude oil arriving at the refinery contains up to 1 percent water, which will contain significant amounts of dissolved salts. The refining process relies heavily on catalysts

that will be poisoned if they are contacted by such salts, so the import crude is mixed with freshwater to remove these salts. The coalescence of the resulting emulsion is encouraged using an electrostatic grid and specialty desalting demulsifiers that yield crude suitable for refining.

the following product lists (tables 1 & 2) present AkzoNobel Surface Chemistry's porfolio of solutions for demulsifier applications.

Table 1: Demulsifiers

General information Solubility (as 10% product) Function Application

product Description type RSN Isopropanol Kerosene Water Aromatic 150 Water Dryer Wetting Water-in-oil Waste oil Desalter dropper demulsifier dmeulsifier

Witbreak DGE-169 Glycol Ester Nonionic 8.2 S D I S Witbreak DPG-40 Poly Glycol Nonionic 32 S I S S * Witbreak DPG-481 Poly Glycol Nonionic 18.4 S D S S * Witbreak DPG-482 Poly Glycol Nonionic 17 S I S S * Witbreak DRA-21 Resin Oxyalkylate Nonionic 14.9 S D D S Witbreak DRA-22 Resin Oxyalkylate Nonionic 20.2 S I S S Witbreak DRA-50 Resin Oxyalkylate Nonionic 8.4 S D I S Witbreak DRB-11 Resin Oxyalkylate Nonionic 11.5 S I I S Witbreak DRB-127 Resin Oxyalkylate Nonionic 8.9 S D I S Witbreak DRB-271 Resin Oxyalkylate Nonionic 9.6 S I I S Witbreak DRC-163 Resin Oxyalkylate Nonionic 14.9 S I I S Witbreak DRC-168 Resin Oxyalkylate Nonionic 20.5 S S I S BESTWitbreak DRC-232 Resin Oxyalkylate Nonionic 14.3 S D I S Witbreak DRE-8164 Resin Ester Nonionic 7.5 D I D S Witbreak DRI-9010 Diepoxide Nonionic 5 S S D I Witbreak DRI-9026 Diepoxide Nonionic 5.7 S S I S Witbreak DRI-9030 Polyacrylate Nonionic 7.5 D I I S Witbreak DRI-9037 Polyacrylate Nonionic 7.8 S I I S Witbreak DRI-9045 Amine Oxyalkylate Nonionic 16 S D S S Witbreak DRL-3124 Resin Oxyalkylate Nonionic 12.5 S D I D Witbreak DRL-3134 Resin Oxyalkylate Nonionic 13.5 D D I D Witbreak DRM-9510 Polyacrylate Nonionic 7.9 S I D S Witbreak DTG-62 Polyoxyalkylene Glycol Nonionic 23.4 D I D S * Witbreak GBG-3172 Resin Oxyalkylate Nonionic 10.6 S I I S

* - secondary function, but when so, very effective.

Products may be not be immediately available in all region Contact our local offices for more information.

Table 2: Secondary demulsifier additives

product Description type Slug treater Wetting agent

Witconol NP-100 Nonylphenol Ethopxylate Nonionic Witconate 708 Alkylaryl Sulfonate Anionic Witconic AN Acid Alkylaryl Sulfonate Anionic Petro IPSA Alkylaryl Sulfonate Anionic Witconic 1298H Branched DDBSA Anionic Witconic 1298S Linear DDBSA Anionic


continue. Sweet corrosion is characterized by the presence of closely grouped, smooth-edged pits. Rates of metal loss are usually lower than with sour corrosion.

Sour corrosion

Sour corrosion is more aggressive than sweet corrosion. Hydrogen sulfide (H2S) reacts directly with the iron surface. A protective film of ferrous sulfide (FeS) can form at the corrosion site; however, even low fluid flow rates are sufficient to abrade the surface, enabling severe corrosion to continue.

A further issue with sour corrosion is the poisoning of the hydrogen diatomization process. The hydrogen atoms diffuse into the metal where they can cause blistering, embrittlement and cracking in weak steels. Hydrogen sulfide can also be generated locally by sulfate-reducing bacteria (SRB). These SRBs are often most active under scale deposits in the production system, which can lead to severe localized pitting corrosion.


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Corrosion inhibitorsUnlike typical iron corrosion, oilfield corrosion generally does not occur as a result of a metal's reacting with oxygen to produce rust. Produced multiphase fluids are usually oxygen-free reductive environments. But due to the predominant use of mild steel in the construction of production pipework, acid gases dissolved in the produced water when in contact with the steel can lead to corrosion.

For corrosion to occur, a galvanic cell must be established. Small variations within the body of the pipework or across weld sections create an electric potential. The galvanic circuit can be completed if water touches the iron surface, which itself is reduced as the iron is oxidized. Under acidic conditions typical of oilfield production, the cathodic reaction leads to the addition of electrons to aqueous protons producing hydrogen atoms. At the anode, iron is oxidized to ferrous (II) ions, leading to iron dissolution.

Two types of corrosion occur in the oilfield:

Carbon dioxide (CO2)-induced - called "sweet corrosion" - which is ubiquitous

Hydrogen sulfide-induced corrosion - called "sour corrosion" - which is less common but more damaging.

Sweet corrosion

The severity of sweet corrosion will depend upon the conditions of production, but is usually worse at high pressures, due to the presence of higher concentrations of dissolved CO2 in the water (present as carbonic acid), and at higher temperatures (increased rate of reaction). Carbonic acid can continue to react directly with the iron surfaces, but under the right conditions can form a protective iron hydroxide film. However, if this is displaced, corrosion will

Various methods of corrosion control are employed in the field, but continuous-dose, film-forming corrosion inhibitors are one of the most commonly employed. The mechanism of action is disruption of the galvanic cell. The film-forming surfactants have a delta-positive charge that attracts them to the delta-negative pipe surface. The hydrophobic tails of the surfactants pack together to create a hydrophobic layer, minimizing contact between the water and pipe and reducing the corrosion potential. The schematic illustrates film formation and the protective nature of the film.

AkzoNobel Surface Chemistry has developed a broad range of products that can be used to tackle oilfield corrosion (see Table 3). They can provide corrosion inhibition in a variety of forms, including oil- soluble, oil-soluble/water-dispersible and water-soluble. Guidance regarding formulation and inhibitor selection can be found in separate documentation.

Figure 1: Film-Forming Corrosion Inhibitor


table 3: Corrosion Inhibitors

General information Solubility (c,f)

product Chemistry Molecular % primary % total Appearance Minimum pour point (C) Isopropanol Kerosene Water Aromatic Hlb weight amine active amine 150 Davis number scale (mgKOH/g)

Armac C Acetate salt of cocoalkylamines 200 ND 98 Paste 165 S S S S 21

Armac HT Prills Acetate salt of hydrogenated 263 ND 98 Solid 202 70 S P P P 6.8 tallow alkylamines

Armeen C Coco alkylamines 200 95 99.5 Liquid 275 18 S S P S 10.3

Armeen CD Coco alkylamines, distilled 200 98 99.5 Liquid 281 18 S S P S 10.3

Armeen HT Hydrogenated 263 97 99.5 Solid 207 43 S I P I 8.2 tallow alkylamines

Armeen OLD Oleylalkylamine, distilled 265 98 99.5 Liquid 207 18 S S P S 8

Armeen S Soyaalkylamines 264 97 99.5 Liquid/paste 206 24 ND ND ND ND 8

Armeen TD Hydrogenated tallow 262 98 99.5 Solid 210 35 S S P S 8.2 alkylamines, distilled

Armohib CI-28 (d) Proprietary surfactant blend 750-800 (a) ND ND Liquid NA 11 ND ND ND ND ND

Armohib CI-31 (e) Proprietary surfactant blend ND ND ND Liquid NA 0 ND ND ND ND ND

Armohib CI-41 mixed polyamine + ND ND ND Liquid NA


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Scale inhibitorsDuring the production of crude hydrocarbons, water is co-produced with oil and gas. It needs to be separated from the oil and gas to meet the refinery specifications for export or sale. As well as being a waste product, the produced water usually tends to precipitate inorganic salts during production, due to modification of environmental conditions encountered as the fluids are extracted. This occurs due to the physical changes experienced by the water as it is produced into the well, is mixed with other fluids and passed through the separation train. The severity and type of scale(s) that occur depend upon the unique chemistry of the formation water and the physical processes of temperature and pressure change experienced during production and separation of the produced fluids.

The two most prevalent oilfield scales are calcium carbonate and barium sulfate. Most formation brines are saturated with respect to calcium carbonate due to the presence of an excess of the mineral in almost all reservoirs. Barium sulfate is commonly encountered when highly sulfated seawater or surface waters are injected into a reservoir to maintain pressure. Mixing with high- barium formation waters can lead to rapid scaling due to the very low solubility of barium sulfate in water.

Unlike remedial treatment of calcium carbonate with acid, barium sulfate dissolver treatments are difficult to perform and seldom successful. Other common scales include strontium sulfate, iron (II) carbonate and calcium sulfate. Other less common, or exotic, scales include calcium phosphate, sodium chloride and the sulfides of zinc, iron and lead.

Supersaturation of brine to any particular inorganic salt creates the potential for precipitation, and if precipitation occurs, this scale can lead to problems with the well, either through impairment of reservoir productivity by restricting the fluid pathways in the near well bore or by restricting fluid flow in the production tubulars and/or separators. In addition to restricted production, safety and operational concerns arise due to scaling of critical monitoring and safety equipment as well as the potential accumulation of low specific activity scales due to co-precipitation of radium sulfate.

A number of different approaches to tackling the problem of scale formation are employed in the field - preventative and remedial. One of

the most widely used preventative options is the continuous injection or squeeze treatment of chemical threshold scale inhibitors into the production and/or water injection system.

Scale inhibitors are typically either phosphorous-containing molecules or water-soluble polymers. The method of action of scale inhibitors depends on type. It is thought that the phosphorous-containing molecules bind to the crystal growth sites preventing further growth, allowing microfine crystallites to be flushed from the system. For the polymers, molecular adsorption onto the meta-stable crystallites destabilizes them back into solution and prevents the initial formation of scale. The performance and action of all scale inhibitors depend greatly upon the conditions of application, and it is suggested that scale inhibitors be screened under representative field conditions.

AkzoNobel Surface Chemistry has developed a wide range of specialized scale inhibitors that allow the treatment of all common scales in a range of production conditions (see table 4). We have assessed the performance of these products under a series of standard conditions to give indicative performance, as well as providing indicative physical property characteristics for these materials. the product portfolio includes green products made using our patented hybrid technology platform.

Accurate residual scale inhibitor detection methods for our scale inhibitor products are available. These methods use either ICP-AES or wet chemistry methods and have detection limits to a few parts per million.


table 4: Scale Inhibitors

General information typical properties

product Description physical form Approximate typical pH typical Calcium barium Other brine Methanol ethylene molecular solids (%) carbonate sulfate scales tolerance 3 tolerance (%) 4 glycol weight perfomance 1 performance 2 compatibility (%) 5

Alcoflow 100 Polyacrylic acid Aqueous solution 3,000 2.5 50 CaSO4 100 100Alcoflow 225 Polytartaric acid Aqueous solution 600 13 33 Iron scales 0 100Alcoflow 250 Polycarboxylate Aqueous solution 800 3.5 40 - 50 100Alcoflow 260 Multipolymer Aqueous solution 7,500 4.3 44 CaSO4 20 50Alcoflow 270 Multipolymer Aqueous solution 5,000 4.5 40 CaSO4 20 50Alcoflow 275 Polcarboxylate Aqueous solution 600 260C/500F

Versa-TL 4 Unique ultra high temperature stable inhibitor/dispersant - >260C/500F.

1 Standard NACE test method. = MIC 6ppm or less, = MIC 7-9ppm, = MIC 10-15ppm, = MIC>16ppm, MIC based on finished product. 2 50:50 Forties FW:SW, 80C (176F), 2 hours. = MIC 25-50ppm, = MIC 50-100ppm, = MIC 100-150ppm, = MIC>150ppm, MIC based on finished product. 3 Polymer stable in the following brines overnight at 95C (203F). = North Sea seawater, = 2500ppm Ca, 25000ppm Na, = 25000ppm Ca, 50000ppm Na. 4 Neat polymer stable upon addition of x% methanol

5 Neat polymer stable upon addition of x% ethylene glycol



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Paraffin controlParaffins are naturally occurring >C18-saturated linear and branched-alkane molecules that are found in most liquid crude hydrocarbons. These components are completely soluble in the hydrocarbon under virgin reservoir conditions. The paraffinic components are not discreet molecules, but rather occur as a mixture of n-alkane-saturated hydrocarbons in the order of C18-C40, and even higher carbon chain lengths when branched. The presence of paraffins does not indicate the potential for a paraffin problem, and most paraffinic crudes are produced without precipitation or the need for chemical or physical treatment.

Paraffins can become problematic when the fluids are subjected to various physical changes required to produce and separate the crude oil or condensate. Three physical processes in particular encourage precipitation of paraffinic fluids:

pressure change - this causes the light ends of the crude oil to vaporize, reducing the overall solubility of the high MW paraffins in the remaining liquid hydrocarbon, which can lead to precipitation. Strong pressure changes occur at the formation face, chokes/valves, the wellhead and separators

temperature change - cooling of the crude oil reduces the solubility of the paraffins, which start to associate with themselves and crystallize from solution, observed as a cloud point. Particularly problematic locations can be oil storage vessels and flow lines, especially long-distance sub-sea tiebacks.

turbulence - perhaps due to temporary degassing of fluids and impingement of wax crystallites on pipe walls, high turbulence flow areas are also known to be problem areas for paraffin deposits. Typical examples can be downhole pumps, treatment vessels, wellheads and chokes.

Paraffin begins by forming needle-like or plate-like structures, and is initially observed as a cloud-point in the produced fluid. These deposits can be very different in nature once deposited in a system. Some form mushy, readily dispersed deposits, others hard waxy deposits - the latter being more problematic from a remediation perspective. In general, the latter waxy-type forms from the higher C-chain length ends - typically >C25 n-alkanes. These problem high-molecular-weight paraffins are more prevalent in crude oil than condensates.

The principal concern with paraffin deposits is the restriction of fluid production rates. This may be due to paraffin deposition in the near-wellbore, restricting flow of hydrocarbon into the well, or more often deposition in production pipe work leading to restriction of diameter and therefore flow rate. The paraffinic crystallites, if precipitated in the bulk hydrocarbon, can increase the viscosity of the fluids, reducing pipeline throughput. At worst, if the paraffin crystal network is allowed to continue to grow and fuse, such as during a shut-in, wax gelling can occur and it may be impossible to re-initiate fluid flow, causing the pipe to be abandoned.

Paraffin control regimes can be either remediative or pre-emptive. Modern reservoir developments design the production system to minimize the

physical factors that can induce paraffin formation. However, paraffin formation may still be an issue. Paraffin remediation techniques include soaking the deposits with an appropriate solvent, often including a dispersant. Remediation involves the continuous injection of dispersants, inhibitors, pour-point depressants, or combinations thereof.

AkzoNobel Surface Chemistry has developed high-performance chemical additives to help tackle even the most challenging paraffinic crudes and condensates either in paraffin remediation or continuous treatment regimes. these products fall into three categories:

Paraffin dispersants - surfactants used either in solvent treatments of pre-existing deposits or in continuous application to keep paraffin crystallites suspended in the solvent/crude and flushed out of the system without depositing

Paraffin inhibitors - oil-soluble polymers that reduce the temperature of appearance of the cloud-point, inhibiting the formation of paraffinic deposits

pour-point depressants - used to limit wax gelling, usually induced by cold temperature exposure, by interfering with the crystallization process and keeping the bulk fluid mobile.

Table 5: Paraffin control

General information Paraffin dispersant Paraffin inhibitor Pour-point depressant

product Description

Armohib PC-105 Copolymer inhibitor/crystal modifier Armohib PC-150 Proprietary blend Armohib PC-205 Amine alkylarylsulfonate Armohib PC-308 Copolymer inhibitor/crystal modifier Witconate 93S Amine alkylarylsulfonate Witconate P10-95 Amine alkylarylsulfonate



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biocides

Due to the relatively harsh environment downhole, only a limited number of organisms are able to survive and adapt if they make it that far down. But once in place, these organisms will find an environment free of competition, with all the nutrients they need to grow and multiply.

The biggest risk factors for contamination during the production process occur when surface fluids are injected directly into the reservoir, typical examples of which are produced water re-injection (PWRI), scale squeeze and other remediation or stimulation treatments of the wellbore. It is under these circumstances that extreme care should be taken to decontaminate the fluids, which is usually achieved by using a suitable chemical biocide.

Downhole colonization of the reservoir has a number of negative impacts. Slime-forming sessile bacteria can block pore throats and reduce the injectivity of water injection wells. Most damaging, however, is contamination with sulfate reducing bacteria (SRB) such as desulfovibrio. These bacteria metabolize the sulfate from surface injection waters into hydrogen sulfide gas. This acid gas level builds over time and causes enhanced corrosion, increased production costs (due to necessary H2S scavenging) and health and safety concerns. These bacteria are extremeophiles and are able to survive in the high-salinity, high-pressure, elevated temperatures and moderate pH levels typical of many reservoirs.

Once bacterial colonies are established, it is practically impossible to disinfect a reservoir. The only true method to control the downhole environment is to ensure adequate biocide use topside.

AkzoNobel's biocides: Highly effective

Due to the toxicity of many biocides to both the environment and to those handling the products, regulatory restrictions on biocides and their use have become more stringent in recent years.

the following listing of AkzoNobel Surface Chemistry biocides is specific to the regulatory body that approves the biocide for use. In countries where a similar regulatory structure is not in place, the adoption of the best practices of foreign regulators may be suitable.

The biocides offered by AkzoNobel Surface Chemistry are non-oxidizing surface-active organic types. They disrupt the typical function of the cell by their adsorption onto cell walls. While this kill mechanism may not be as fast as

A virgin hydrocarbon reservoir is free of biological life before it is drilled or produced. However, as soon as contact is made with the surface, the potential for biological contamination exists.

with oxidizing biocides, these biocides are less corrosive to production pipework, and can in fact act as corrosion inhibitors, particularly the quaternary ammonium compounds.

Selecting the right biocide depends upon the target organisms to be treated, the regulatory approvals applicable and the type of treatment regime proposed. Many of the biocide chemistries mentioned become inactive once they reach the surface environment and are readily biodegraded to benign metabolic products.

table 6: biocides

product Description physical form 25C biocide registering authority

Aquatreat DNM30 Dithiocarbamate Aqueous solution US EPA / Canada DSL

Aquatreat KM Dithiocarbamate Aqueous solution US EPA

Arquad 2.10 Didecylmethylquat Liquid EU Biocidal Product Directive

Arquad MCB Methylbenzylcocoquat Liquid EU Biocidal Product Directive

Armohib B101 Cocodiamine diacetate Liquid US EPA / Canada DSL

Armohib B654 Cocodiamine diacetate Liquid Canada DSL

Duomeen C (intermediate) Cocodiamine Liquid US EPA / Canada DSLRegistrations and permitted use scenarios for biocides are complex. Please contact your sales representative.


Water clarifiers / deoilers


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Typically, a separation system will have equipment for treating the waste water to encourage the further separation of the oil droplets from the water. This equipment includes hydrocyclones, flotation tanks, filtration units, and centrifuges. The performance of these devices can be significantly improved through the use of chemical flocculating agents. The flocculants are referred to interchangeably as deoilers (due to the removal of the oil) or water clarifiers (due to improvement in water quality).

The emulsion droplets that have not been removed by the primary separating system will be significantly stabilized from further coalescence due to two mechanisms. The first is mutual charge repulsion of emulsion droplets. As fluids are processed, the decreasing pressure allows the pH of the water to rise, resulting in the deprotonation of naturally occurring fatty and naphthenic acids present in the crude. These

salts provide a negative charge to the emulsion surface and actually repel other oil droplets that would otherwise approach and coalesce.

In high TDS brines, calcium soaps of fatty/naphthenic acids can form, creating a solid phase at the water interface, making coalescence even slower. This is similar to the second stabilizing mechanism whereby organic and/or inorganic solids adsorb to the emulsion oil/water interface, effectively sealing it from exposure to other emulsion droplets and impeding the coalescence mechanism. If the emulsion droplets are sufficiently small, Brownian motion will keep the emulsion stable indefinitely.

Effective deoiling can be achieved using polyelectrolytes that encourage flocculation of the emulsion droplets into larger collections, which are then more readily acted upon by the physical

Demulsification and separation of the hydrocarbon phase during primary separation of produced fluids does not usually leave an aqueous phase sufficiently free of hydrocarbons to meet the discharge limits required for water disposal. Depending on the geographic location, these limits can be from 40ppm residual oil in water, to as low as 10ppm. Environmental regulations will continue to press for reduction of these discharge limits, particularly in marine environments.

separation equipment in the water treatment process. The preferred polymers neutralize the repulsive charges developed on the emulsion droplets, and if of sufficient size, can also bridge between the droplets collecting then together into flocculated groups where coalescence may occur due to close proximity. Flocculants are designed to function in the high salinity brines common in produced waters.

AkzoNobel Surface Chemistry's products include a range of natural and synthetic materials to meet the performance and environmental needs of the market. We also manufacture dithiocarbamate products, which are also known to form temporary in-situ, iron-linked pseudo-polymer complexes that function as effective oilfield deoilers.

Table 7: Water clarifiers / deoilers


product Description physical form pH Solids (%) MW

Alcoclear CCP-II Polycationic aqueous solution 4.5 6.2 1,000,000

Flocaid 19 Polyamphiphile aqueous solution 4 27.5 100,000

Flocaid 34 Polyamphiphile aqueous solution 4.8 27.5 100,000

Witbreak RTC-330 Polycationic aqueous solution 4.5 70 ND

Nsight A1 Anionically modified starch aqueous solution 12 30 5,000,000

Nsight C1 Cationically modified starch aqueous solution 12 30 5,000,000

Nsight H1 Hydrophobically modified starch aqueous solution 6 27 5,000,000Products may be not be immediately available in all region Contact our local offices for more information.


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Asphaltene inhibitorsAsphaltenes are some of the highest-molecular-weight organic fractions to be found in crude oil. They consist of heteroatom-containing polycyclic aromatic groups with aliphatic arms. The specific structure of asphaltenes varies from crude to crude, but where present, can be the source of major fouling and disruption to production. Asphaltenes can be a problem downhole as well as topside.

Asphaltenes are widely defined as those hydrocarbon materials that are soluble in aromatic solvents such as benzene, but not soluble in aliphatic solvents such as n-pentane. The presence of such asphaltenic components in a crude oil need not necessarily lead to asphaltene problems. However, precipitation of asphaltenes, when it occurs, is usually the result of the solubility of these high-molecular-weight components destabilizing in the oil. The sources of destabilization are typical of production conditions e,g., pressure decline, pH change, crude mixing, etc.

If non-chemical techniques cannot be employed to eliminate an asphaltene problem, then chemical inhibitors are required.

AkzoNobel Surface Chemistry has recently developed Armohib AI-100, a specialty inhibitor product to help with this specific production problem.

table 8: Asphaltene inhibitors


product Description physical form pourpopint Solubility (25% or more)

Armohib AI-1000 Ampoteric surfactant Liquid/paste 35C Isopropanol, benzene, mineral oilProducts may be not be immediately available in all region Contact our local offices for more information.


FOA

Me

RS

FoamersIn the production of crude oil and gas, foamers have a number of important applications. These include the deliquification of low-pressure gas wells by creating a stable foam that can slowly lift those heavy liquids from the wellbore that would otherwise slowly choke off the flow of the well, eventually killing it. Foamers are also used in enhanced oil recovery (EOR) either as blocking and diverting agents to restrict unwanted flow or by improving the sweep characteristics of the mobile phase by reducing its mobility. Many of the products described here are also used in foamed drilling and stimulation applications (including fracturing, cementing and acidizing) where the use of foam can reduce the total chemical cost and/or improve the performance of the operation.

Foamers work by preferentially adsorbing at the air/water interface, resulting in incorporation of significant volumes of air into the fluid. The fraction or percentage of air that is incorporated into the foam is referred to as the foam quality and is usually in the range of 75-90 percent, but can be as high as 97 percent. Foam quality will vary as a function of pressure and temperature and the chemistry of the water in the aqueous phase.

Foamers need only be dosed at low concentrations to give significant results. During the unloading of gas wells, foamers can reduce the overall SG of the fluid column in the well, allowing the reservoir to eject the water blockage. Treatments may be done by slug injections of liquid surfactant to the wellbore, or continuously through the use of a slowly dissolving foam stick.

In EOR applications, it is the rheological characteristics of the foam flowing in a porous

media that provide the desired mobility modification and fluid diversion. Foams are more resistant to flow than either the aqueous phase or the gaseous phase in such a medium, and this can be advantageous so long as the bubble size is designed properly.

A wide range of anionic surfactant chemistries is available from AkzoNobel Surface Chemistry. Selection will require consideration of the conditions of application and the environmental requirements. Laboratory evaluation of performance is recommended.

Of the families of products available, the most environmentally friendly materials are the ether sulfates. These materials are somewhat brine tolerant, but are prone to hydrolysis in strongly acidic or alkaline conditions or at high temperature. As with many surfactant applications, synergism is observed with foamers, and we recommend

blending ether sulfates with sulfonate products to boost performance.

The sulfonates and naphthalene sulfonate products are more robust than the ether sulfates. They have higher foaming performance and are more temperature-, brine- and pH-stable. But they can also be more environmentally persistent. Certain products can be made to be solvent and oil dispersible, and in a specific case can be used to foam non-aqueous media. Linear alpha-olephin sulfonates seem to offer particularly desirable properties as foamers in oilfield applications.

On the next page, you will find AkzoNobel Surface Chemistry core products for foamers applications.

Contact our local sales representative for more information on products and regional availability.


table 9: Foamers


product Description Appearance Activity pH Freshwater brine Gas well Soap Foamed eOR Foam booster Non-aqueous (%) Foamer Foamer unloading stick and stimulation by blending foamer applications

Witcolate 1247H Ammonium C6-C10 Liquid 39 7-8.5 (a) Alcohol Ether Sulfate (3EO)

Witcolate 1259 C6-C10 Alcohol Ether Sulfate Liquid 80 7-8 (a) (3EO), IPA salt

Witcolate 1259FS C6-C10 Alcohol Ether Sulfate Liquid 88.5 7-8.5 (a) (3EO), IPA salt

Witcolate 1276 Ammonium C10-C12 Alcohol Liquid 53 7-8 (a) Ether Sulfate (3EO)

Witcolate 3220 Surfactant blend Liquid 32 8.8 (a) Wirconate 708 Cyclohexylamine Salt of Diisopropyl Liquid 53 6 (b) Naphthalene Sulfonic Acid in Naphthalene

Witconate 79S TEA-Dodecylbenzene Liquid 52 6.5-8 (c) Sulfonate Linear

Wirconate 90 Flake Sodium Dodecylbenzene Solid flake 90 6.5-8.7 (d) Sulfonate Linear

Witconate 93S Isopropylamine Linear Liquid 92 4-5 (e) Dodecylbenzene Sulfonate

Witconate 96A Sodium C14-16 Alpha Liquid 39 6.8-8.5 (d) Olephin Sulfonate

Witconate AOK Sodium C14-16 Alpha Solid flake 90 7-10 (d) Olephin Sulfonate

Witconate AOS Sodium C14-16 Alpha Liquid 39 8-10 (f) Olephin Sulfonate

Witconate AOS-12 Sodium C12 Alpha Liquid 40 (g) 8-10 (a) Olephin Sulfonate

Petro BAF Sodium Alkyl Napthalene Liquid 50 ND Sulfonate

Petro P Sodium Alkyl Napthalene Liquid 50 7.5-10 Sulfonate

(a) 5% aqueous solution

(b) 5% in 75% IPA solution

(c) 5% in 25% IPA solution

(d) 10% aq solution

(e) 20% aq solution

(f) 12.8% aq solution

(g) % solid



Solutions for drilling applications

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A critical component of the success of a drilling operation is the use of drilling fluids. The most obvious need is for the fluid to carry the rock cuttings to the surface and out of the well to prevent them from clogging the drill bit and hindering further drilling progress. To do so, clean drilling fluids are injected into the hollow drill string. The fluid emerges from nozzles on the drill bit and flushes the cutting head and rock-face, lifting the ground rock away and sweeping the cuttings toward the surface through the annulus.

Control of the viscosity of the mud and the fluid flow rates ensure adequate cuttings removal. The density of the mud also helps to create buoyancy for the cuttings. At the surface, the cuttings are physically separated using screens, and the cleaned fluids are returned to the well for pumping.

Lifting the cuttings out of the well is not the only function that a drilling fluid must complete. Further critical functions include:

Controlling formation pressure. Balancing the pressure of fluids in the drilled zones will ensure that either no fluids or a controlled flow of fluids will enter the well during drilling, thus enabling effective rheological control of the drilling fluid to be maintained.

Sealing permeable formations. Many of the rock strata penetrated by the drill are permeable and will accept liquid from the mud. If allowed to continue, this will cause unacceptable mud thickening. The drilling mud is designed to develop a thin, low- permeability filter cake from the solids it contains. This seals the permeable zones from further fluid loss and allows drilling to continue.

Suspending cuttings. While the drilling fluids rheology is important in dynamic conditions, it

To access the hydrocarbons contained in an oil or gas reservoir, a well must be drilled to connect the reservoir with the surface. This will allow the crude fluids to be conveyed via the well to the topside for initial separation and purification. Rotary drilling techniques are used to create the well. A drill bit is mounted on a tubular drill string, which is turned by rotary action. The weight of the drill string on the rotating drill bit is sufficient to grind the rock and allow penetration toward target.

is also important during periods of low annular velocity, such as a shut-in or the addition of a new pipe to the drill string. Drilling fluids are designed to be thixotropic, developing high low-shear viscosity that maintains suspension of the cuttings and the weighting agents, thus minimizing any sedimentation or sag that might occur. The fluid should require minimal energy input to return to dynamic flow conditions.

Maintaining wellbore stability. Erosion of the wellbore due to dynamic abrasion or an osmotic expansion of in-situ shales can be problematic. Brine chemistry and effective mud design can limit these issues.

Allowing effective removal of cuttings. Shale shakers are used to mechanically remove cuttings. However, if the mud thixotropy is insufficient, solids can be left in the mud. Upon reinjection, these particles break down further and can impact the rheology (of shales especially) and many other design characteristics of the mud. Lowering solids and plastic viscosity through the use of dispersants and deflocculants will help in this regard.

Cooling and lubricating the drill bit. Due to the abrasive forces at play during drilling, the drill bit temperature can rise significantly. The drilling fluid helps reduce this. Water-based systems cool most efficiently although oil-based muds lubricate the most.

Minimizing formation damage. The penetration of either mud fines or brine into the near-wellbore can permanently reduce the productivity of the reservoir. Remediation is possible, but avoidance through mud-design is preferred.

Minimizing environmental impact. Lower-toxicity products have been developed to reduce the environmental burden of the drilling fluids in case of exposure or spill.


Drilling muds are required to perform an extensive list of tasks. In addition, as regulatory and drilling performance requirements become increasingly challenging, these fluids are becoming increasingly complex and sophisticated, utilizing a variety of specialty chemical products to push performance boundaries. Satisfying all requirements can be a challenge, especially when the fluid selected provides a compromise of performance, cost and the specifications of the reservoir being drilled.

To help achieve the optimum balance of properties to meet drilling engineers specific requirements, many different mud types have been developed, all of which fall into two fundamental drilling mud types: water-continuous fluids, also known as water-based muds (WBMs), and oil-continuous fluids, often referred to as oil-based muds (OBMs).

WBMs use water as the continuous phase. They are thickened using bentonite or polymers and are usually weighted by dissolving salt into the water and/or dispersing sized inorganic minerals such as barium sulfate to counter the pressure from fluids in the formation and eliminate mud contamination. Due to the cheapness of the fluid base, WBMs are often preferred where their use is permitted by performance requirements. Water-based systems have until recently been limited to lower-temperature applications due to the poor rheological stability and high fluid loss characteristics at high temperatures. However, the development of high-temperature stable additives have allowed WBMs to be utilized in the most extreme drilling environments. From an environmental perspective, WBMs are also

preferred because they contain lower-toxicity components.

OBMs use either crude oil or a refined hydrocarbon (diesel) as the continuous phase. They too are thickened using bentonite - hydrophobically-modified, in this case. Their lubricating and fluid loss characteristics are much preferred over WBMs, but the toxicity of the base fluid can be a concern.

Recently, "green" synthetic hydrocarbons have been developed, and are referred to as synthetic-based muds (SBMs). These materials, which are non-aromatic, usually contain a sacrificial chemical link to encourage biodegradation and have been used in environmentally sensitive areas. These mimic the characteristics of conventional hydrocarbon OBM bases in many ways, but the chemical additives used to complete the fluid may need to be adapted due to the aliphatic nature of the base.

While this family of oil-continuous fluids (OBMs and SBMs) may be referred to as oil-based muds, in most cases these fluids are invert emulsions containing a high proportion of water in the internal phase. The emulsion provides viscosity to the fluid, and the internal phase is usually weighted with highly salinity brine (CaCl2 is most common) to increase the fluid density.

To maintain the stability of the invert emulsion, high-performance emulsifiers are required. These materials are usually a formulation of various components to optimize performance. One of the key benefits of using OBMs is the ability to maintain an oil-wet surface to the reservoir,

which inhibits shales, improves fluid loss and minimizes formation damage. To ensure the oil-wet character is maintained, wetting agents are also incorporated into the formulation. Other chemical additives utilized are dispersants, lubricants and foamers.

AkzoNobel Surface Chemistry has a full range of surfactant- and polymer-based additives to help our customers develop both high-performance and basic oil-based and water-based drilling mud formulations. Our research staff continue to develop novel products that address some of the key challenges facing the drilling market today, including products for high-temperature applications and materials to reduce the environmental impact of drilling.

On the following tables (10 & 11) you will find our core products for oil-based and water-based muds.

Advice and guidance on the chemistry can be provided through interaction with our sales and technical staff.


Oil-based mud additivestable 10: Oil-based mud additives

General Information typical properties Solubility

Product Desciption Type Physical pH Brookfield Pour Point F Isopropanol form at Rt Viscosity at Rt

Amadol 511 Alkanolamide Nonionic Liquid 8.6 850


General Information typical Function

product Kerosene Water Aromatic Drilling mud Drilling emulsion Drilling Mud Stuck pipe Surfactant Drilling mud Wetting Dispersant Foaming 150 primary Mud Secondary Stabilizer lubricant additive detergent agent agent emulsifier Emulsifier

Amadol 511 S D I Amadol 1017 S S I Witcomul 1844 I S I Witcomul 3020 S D S Witcomul 3158 ND ND ND Witcomul 3241 I S S Amadol CDA I S I Armohib 209 D D S Witconate 605A S I S Witconate AOS D S D Witcolate 1247-H I S I Arquad 2HT-75 I S I Arquad 2C-75 D S S Arquad HTL8-MS S I D Ethoquad 18/25 S I I Ethylan 1008 S S S Berol 840 I S S Witconol NP-40 I S S Witconol NP-100 S I S


Water-based mud additives

(a) 5% in 3:1 IPA/H20 (b) 5% in 1:1 2propanol:H20 (c ) Polymers as % total solids, surfactants as % actives (d) 5% aqueous solution (e) 10% aqueous solution (f) 1% in 62.5% IPA (g) 20% aqueous solution (h) 5% in 75%IPA (i) 1% in water (j) 2% in water


table 11: Water-based mud additives

General Information typical properties

product Desciption Charge physical form pH typical typical polymer Solids % (c ) Molecular Weight

Alcodrill HPDL Sulfonated Polycarboxylate Anionic Aqueous liquid 6.5 45 3,500

Alcodrill HPDS Sulfonated Polycarboxylate Anionic Water soluble powder 6.5 95 3,500

Alcodrill SPDL Polycarboxylate Anionic Aqueous liquid 8 40 3,000

Alcodrill SPDS Polycarboxylate Anionic Water soluble powder 8 95 3,000

Alcoflow 300D Sulfonated multipolymer Anionic Water soluble powder 7 95 15,000

Narlex D72 Sulfonated Styrene Maleic Acid Copolymer Anionic Water soluble powder 7 95 15,000

VersaTL 3 Sulfonated Styrene Maleic Acid Copolymer Anionic Water soluble powder 7 95 20,000

VersaTL4 Sulfonated Styrene Maleic Acid Copolymer Anionic Aqueous liquid 7 25 20,000

VersaTL 70 Sulfonated Polystyrene Anionic Water soluble powder 7 95 75,000

VersaTL130 Sulfonated Polystyrene Anionic Aqueous liquid 6 30 200,000

VersaTL 501 Sulfonated Polystyrene Anionic Aqueous liquid 7 25 1,000,000

VersaTL 502 Sulfonated Polystyrene Anionic Water soluble powder 7 95 1,000,000

Aquatreat DNM30 Sodium Dithiocarbamate Blend Anionic Aqueous liquid 11.5 30

Aquatreat KM Potassium Dimethyldithiocarbamate Anionic Aqueous liquid 13 50

Arquad S50 Soyaalkyltrimethyl Ammonium Chloride Cationic Liquid in propylene glycol 7 51

Armohib 209 Tall Oil Imidazoline Cationic Liquid 11 (a) 99

Arquad 2.1070 HPF Didecylmethylquat Cationic Aqueous liquid 7 (b) 70

Witcolate 1247 H Ammonium C6C10 Alcohol Ether Sulfate (3EO) Anionic Aqueous liquid 7.8 (d) 65

Witcolate 1259 FS C6C10 Alcohol Ether Sulfate (3EO), IPA salt Anionic Aqueous liquid 7.5 (d) 80

Witcolate 1276 Ammonium C10C12 Alcohol Ether Sulfate (3EO) Anionic Aqueous liquid 7.5 (d) 53

Witconate 3203 Specialty Sulfonate Anionic Aqueous liquid 7.5 50

Witconate AOK Sodium C1416 Alpha Olephin Sulfonate Anionic Flake 8.5 (e) 90

Witconate AOS Sodium C1416 Alpha Olephin Sulfonate Anionic Aqueous liquid 8.5 (e) 39

Witconol NP100 Nonyl Phenol (10 EO) Ethoxylate Nonionic Liquid 6.5 (f) 99

Witconol NP120 Nonyl Phenol (12 EO) Ethoxylate Nonionic Liquid 6.5 (f) 99

Witconate 93S Isopropylamine Linear Dodecylbenzene Sulfonate Anionic Liquid 4.5 (g) 93

Amadol 1017 Modified Alkanolamide Nonionic Liquid 9.5 (a) 99

Witconate 605A Calcium Alkylaryl Sulfonate Anionic Organic liquid 6 (h) 60

AG 6202 Alkyl glucoside Nonionic Aqueous liquid/paste 7 (i) 65

AG 6206 Alkyl glucoside Nonionic Aqueous liquid 7 (j) 75

AG 6210 Alkyl glucoside Nonionic Aqueous solution 6 (i) 61


(a) 5% in 3:1 IPA/H20 (b) 5% in 1:1 2propanol:H20 (c ) Polymers as % total solids, surfactants as % actives (d) 5% aqueous solution (e) 10% aqueous solution (f) 1% in 62.5% IPA (g) 20% aqueous solution (h) 5% in 75%IPA (i) 1% in water (j) 2% in water


General Information typical Function

Product Deflocculant Fluid loss Rheoloogy Biocide Corrosion Foamer Emulsifiers Lubricant Dispersant/ Wetting Saltwater/ High temperature Additive stabilizer inhibitor detergent agent Freshwater stable

Alcodrill HPDL SW Alcodrill HPDS SW Alcodrill SPDL FW YesAlcodrill SPDS FW YesAlcoflow 300D SW YesNarlex D72 SW YesVersaTL 3 SW YesVersaTL 4 SW YesVersaTL 70 SW YesVersaTL 130 SW YesVersaTL 501 SW YesVersaTL 502 SW YesAquatreat DNM30 SW/FW Aquatreat KM SW/FW Arquad S50 SW/FW Armohib 209 SW/FW Arquad 2.1070 HPF SW/FW Witcolate 1247 H SW Witcolate 1259 FS SW Witcolate 1276 FW Witconate 3203 SW YesWitconate AOK FW YesWitconate AOS FW YesWitconol NP100 SW/FW Witconol NP120 SW/FW Witconate 93S SW/FW Amadol 1017 SW/FW Witconate 605A SW/FW AG 6202 SW AG 6206 SW AG 6210 SW

USAHead Office AkzoNobel Surface Chemistry LLC 525 West Van Buren Street Chicago, IL 60607-3835, USA Telephone: +1 312 544 7000 Fax: +1 312 544 7320

Customer ServiceTelephone: +1 800 906 9977

Technical ServiceAkzoNobel Surface Chemistry LLC 281 Fields Lane Brewster, NY 10509 Telephone: +1 845 276 8200 Fax: +1 845-277-1423

CanadaAkzoNobel Chemicals Ltd 1, City Center Drive Suite 318 Mississauga, Ontario, L5B M2 Telephone: +1 905 273 5959 Fax: +1 905 273 7339

South AmericaAkzoNobel Surface Chemistry LLC Rodovia Akzo Nobel 707 Bairro So Roque da Chave P.O.Box 32 Cep 13295-000 Itupeva S.P. Telephone: +55 11 45918938 Fax: +55 11 45911744

Mexico, Central America and CaribbeanAkzoNobel Chemicals SA de CV Av, Morelos No. 49 Col. Tecamachalco CP 56500 Los Reyes la Paz, Edo. de Mexico Telephone: +52 (55) 5858-0756 Fax: +52 (55) 5858 0703

www.akzonobel.com/surface

AkzoNobel is the largest global paints and coatings company and a major producer of specialty chemicals. We supply industries and consumers worldwide with innovative products and are passionate about developing sustainable answers for our customers. Our portfolio includes well known brands such as Dulux, Sikkens, International and Eka. Headquartered in Amsterdam, the Netherlands, we are a Global Fortune 500 company and are consistently ranked as one of the leaders in the area of sustainability. With operations in more than 80 countries, our 55,000 people around the world are committed to excellence and delivering Tomorrow's Answers Today.

2011 AkzoNobel N.V. All rights reserved.Tomorrows Answers Today is a trademark of AkzoNobel N.V.

Products mentioned may not be available in all countries. AG, Alcoclear, Alcodrill, Alcoflow, Amadol, Armac, Armeen, Armohib, Arquad, Berol, Duomeen, Ethoduomeen, Ethomeen, Ethoquad, Ethylan, Floc aid, Narlex, Nsight, Petro, Versa-TL, Witbreak, Witcolate, Witcomul, Witconate, Witconic and Witconol are registered trademarks in the USA.2011 AkzoNobel Surface Chemistry LLC, all rights reserved

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