Introduction to Production Chemistry

PRODUCTION CHEMISTRY - DEPOSITS AND EMULSIONS

Process ChemistryProcess Chemistry

COST VOLUME

Maximising Production Potential(with existing facilities)

Russell Hollamby & Guus Nuis The copyright of this document is vested in Shell International Exploration and Production B.V., The Hague, The Netherlands. All rights reserved. Neither the whole nor any part of this document may be reproduced, stored in any retrieval system or transmitted in any form or by any means (electronic, mechanical, reprographic, recording or otherwise) without the prior written consent of the copyright owner.

2000 SHELL INTERNATIONAL EXPLORATION AND PRODUCTION B.V., RESEARCH AND TECHNICAL SERVICES, RIJSWIJK

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Contents Objectives and Introduction

1. Emulsion Treatment 1.1 Dehydration 1.2 Sludge 1.3 Deoiling 2. Organic Deposits 2.1 Gas Hydrates 2.2 Waxy Crude 2.3 Asphaltenes 3. Drag Reducers

4. Inorganic Scales 4.1 Oil Field Water Scales

5. Bacteria and Biocides 6. Corrosion 7. HSE Aspects

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Produced by:

Nuis Exploration & Production Services V.o.F. Zijdelaan 25

2594 BW Den Haag Netherlands

telephone: 0031 70 3850764 facsimile: 0031 70 5851048 email: [email protected]

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Objectives and Introduction

Session ObjectivesSession ObjectivesAt the end of the Session the Participants will be able to:

• List the Main Technical Challenges (Chemistry Specific) forProcessing Produced Hydrocarbons and Effluents.

• List the Main Influencing Factors on the Formation ofEmulsions and Deposits.

• Describe the Process for Formulating, Applying andMonitoring a Chemical Treatment.

• List the Key Elements in Assessing the Economics of aChemical Treatment.

• Identify the main HSE aspects for Process Chemistry.

The objectives of this booklet are that, after reading the various sections and completing the exercises, you will be able to: • name the different types of deposits and emulsions that may form or be present,

in hydrocarbons • explain what makes deposits come out of solution and what makes

emulsions occur • explain the potential problems that may arise in production facilities from deposits

and emulsions • explain how the potential production problems associated with deposits and

emulsions may be prevented and/or resolved • describe the process for formulating, applying and monitoring a chemical

treatment • list the key elements in assessing the economics of a chemical treatment • explain the term drag reduction • name a range of drag reducing agents and explain how they work • explain how and why drag reducers are used in a production environment. • identify the main HSE aspects for Process Chemistry Overview Crude oil and gas are naturally occurring substance which emerge from the well with a considerable range and variation of both physical properties and chemical

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constituents. Some of these emerge as a direct result of the production processes involved in extraction and transportation. Many of these physical properties and chemical constituents do not cause problems in the upstream or refining processes. Others may, however, have a negative impact on costs, quality, safety, the ability of a well to continue to produce and the ability of the refinery to handle the output. It is essential, therefore, that production staff have a clear understanding of the relevant physical properties and chemicals, their potential impact on operations and, of equal if not greater importance, how the associated problems may be avoided and/or overcome.

Process Treatment ChemicalsProcess Treatment ChemicalsProduct Quality• DeHydration (Oil, Gas)• DeOiling• Pour Point Depressants• Sulphide Scavengers• Sludge Disposal

Processing Potential• Wax Inhibitors• Asphaltene Inhibitors• Hydrate Inhibitors• Oxygen Scavengers• Corrosion Inhibitors• Scale Inhibitors• Friction Reducers

• Estimated Group Expenditure on Process ChemicalsDemulsifying US$ 22 MM Scale US$ 8 MMDeposits US$ 20 MM Other US$ 5 MMCorrosion US$ 11 MM HSE Related US$ 5 MM (1994 - WOCANA)

Process Chemicals can be sub-divided over a number of different processes in which these chemicals are being applied. The types of chemicals used in the left column are mainly aimed to improve the quality of the stream to be treated. Dehydration chemicals will assist reducing the water (and salt) content in the crude to the quality level required for export. Pourpoint reducers assist reducing the temperature at which wax deposits from the crude stream, while sulphide scavengers reduce the H2S content in the production stream, etc. In some cases like for deoilers and sludge disposal chemicals, the product quality is more of an environmental quality. In the right hand column, chemicals applied are aimed more at improving the production- or process potential in the field and/or the facilities. A wax inhibitor for instance, could avoid deposition of wax in the production facilities without directly improving the crude quality. Asphaltene and Hydrate inhibitors, allow undisturbed flow of hydrocarbons while producing under normally deposit forming conditions. Their application, however, does not have any impact on the sales aspects of the produced hydrocarbons. The application of chemicals has a number of disadvantages which should be taken into consideration before any process chemical is introduced.

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• chemicals can be rather expensive • applying chemicals can be Labour intensive • chemicals often have a negative impact on the environment when disposed

Chemical Costs - GabonChemical Costs - Gabon

CHEMICALS50%

WELLS11%

STATIONS14%

MANPOWER13%

MISC12%

OPCO - OPEX Breakdown

RABI - OPEX Breakdown

CHEMICALS18%

MATERIALS12%SERVICES

35%

MANPOWER8%

SALARY27%

1994 Data The cost of chemicals as a percentage of total Opex varies between Operating Units. Above Viewgraph shows that for Gabon (1994 data), chemicals take 18% of the total Opex. From the bottom Viewgraph, depicting the split of Opex for the Rabi field in Gabon, clearly shows that the fraction of the total operating expenditure required for process chemistry, can vary widely in and between OU’s. The reason for these differences is often the differences in production streams and conditions, but can also be attributed by the design of the production facilities.

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Chemical Cost - ExproChemical Cost - Expro• Total Expenditure on Treatment Chemicals - US$ 8.3 million.• Unit Cost of Chemical Treatment - US$ 0.051 / BOE.

1994 Data0

500

1000

1500

2000

2500

3000

3500Ex

pend

iture

- U

S$'0

00

Sca le Inh ib itio n (P )Corro sion Inh ib itio nDem uls ifierO xygen ScavengingDehydrationBiocide (P )Hydrate Inh ib itionAnti-Foam (P )Do ilingAnti-Foam (I)H2S ScavengingBiocide (I)Anti-FoulantFreezing D epressionFiltrationScale Inh ib itio n (I)F low Im provem ent

38%

16%

12% 10%9%

6%

91%

<2%

The Viewgraph above demonstrates the variation in chemical cost that can exist in a certain OU. In this case Shell Expro UK in 1994 spent 91% of her chemical cost to only six of the in total 17 different categories of chemicals in use. Scale inhibition ranks first which is caused by scaling as result of sulphate containing sea water injection in a calcium bearing formation. In most OU’s scale inhibition takes only a minor part of the OU Opex, while demulsifier cost is normally higher.

Chemical SelectionChemical Selection• Chemical Treatment is the Third Line of Defense

• Avoid.• Mechanically Treat.• Only Then Use Chemicals!

• Identify the Problem• Ascertain Specific Cause/s (Temp., Press., Energy, Chemistry).• Determine Reason for Cause/s to Occur at that Point in the Process.

• Assess Remedial Action Target• 100% solution or a proportion.

• Identify Candidate Chemicals• Computer Modelling if Available.• Literature, Service Company, RTS/ARC Searches.• Laboratory Screening (OPCO, RTS/ARC, Service Company Laboratories).

• Field Trial & Evaluation• Routine Sampling and Evaluation of Performance.

Application of process chemicals can be costly, operationally manpower intensive, and cause a negative impact on the environment. For these reasons, chemicals should only be applied as the third line of defence.

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Always first try to avoid using chemicals by for instance changing operational conditions. If problems cannot be resolved with these changes, then mechanical treatment may be a solution. Only if above attempts do not result in a sufficient improvement in the production problems, chemicals can be used. In order to select the most effective chemical, first the problem at hand has to be fully identified. Therefore samples and measurements have to be taken and analysed by an experienced process chemist who has a good understanding of the production processes and equipment. Once the cause(s) have been identified, the required minimum improvement has to be established to form the target for the process chemicals to be tested. Candidate chemicals will now have to be identified and, to assist the Process Chemist, use can be made of computer modelling (if available), literature searches, or assistance from research (RTS/ARC) or from chemical companies. After initial screening and testing, a full field trial and evaluation thereof is very important to make sure that the finally selected product will work under the actual production conditions and variations thereof.

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1. Emulsion Treatment

Emulsion treatment can be subdivided into three groups of hydrocarbon water processes. The first process is called dehydration whereby water is removed from oil or gas. The main reasons for dehydration are the following: • Requirement of refineries which demand a specific (maximum) water content in

the crude • High water cut of crude oil require larger pipeline size and pump capacity and thus

higher transport costs • The presence of water in crude enhances the likeliness of corrosion in the

production facilities. Deoiling is the opposite process whereby remaining (dispersed) oil will be removed from the remaining water phase following dehydration. The reasons for removal of the oil are mainly the following: • environmental, where the water is disposed into the sea or other surface waters • where the water is (re-)injected oil removal is often required to reduce formation

damage and reduction of injectivity • For high oil in water contents, the removal of the oil can be economically

attractive. Sludge is an emulsion stabilised by a high solids content and not possible to be broken by normal dehydration techniques. Their removal from the dehydration and deoiling process is important to avoid upsetting these processes. Environmentally acceptable disposal options are sometimes difficult to find and often annular injection is the most acceptable method.

Hydrocarbon-Water ProcessingHydrocarbon-Water Processing• DeHydration.

Water Removal from Oil or Gas.• Refinery Requirements (0.5-1.0%v) or End User Requirements.• Reduced Transportation Cost.• Minimise Corosion Problems.

• DeOiling.Oil or Gas Removal from Water.

• Environmental Impact.• Formation Damage.• Loss of Revenue.

• Sludge.Removal of Residual Emulsion with Entrained Solid Debris.

• Interference with Dehydration.• Environmental Impact.

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1.1. Dehydration

Oil Processing Emulsions• An Emulsion is a Stable System of Two Immiscible Liquids,

with One Phase Finely Dispersed in the Other.

DispersionMechanical

Energy

Water

EmulsificationChemical

StabilisersCalciumStearate

SodiumStearate

Non-Polar Tail

CH3-(CH2)16

CH3-(CH2)16Ca++

C OO-

C O-

OPolar Head Non-Polar Tail

CH3-(CH2)16Na+ C-OO

Polar Head

Oil

In many cases, water is co-produced with oil production and part or all of the water produced may be in the form of an emulsion with the oil phase. An emulsion is a semi-stable dispersion of one liquid (dispersed phase) in another liquid (continuous phase). The formation of an emulsion requires: • the presence of two immiscible liquids • mechanical energy to disperse one liquid as small droplets in the' other” liquid • the presence of compounds to stabilise the emulsion, delaying phase separation. Two types of emulsion can occur: • Water in oil (W/O) emulsion (or normal emulsion) • Oil in water (O/N� emulsion (or reverse emulsion). In the first case the oil is the continuous phase and the water is the dispersed phase, with the opposite being true in the second case. The removal of water from a water in oil emulsion is called dehydration. The removal of oil from an oil in water emulsion is called de-oiling. When one fluid is dispersed in another, the interfacial area is increased. Dispersion, therefore, requires energy. The amount of energy required is a function of the interfacial tension between the liquids and the increase in interfacial area. The presence of surfactants, compounds which are partly attracted by both liquids, reduces the interfacial tension and in doing so facilitates emulsification. A common example of this phenomenon is a soap molecule. This has a polar "head", which will dissolve in water out of preference, and a non-polar "tail", which prefers to

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stay in the oil phase. In crude oil, asphaltenes, naphthenic acids and intermediate wet solids, among others, will act in the same way to stabilise emulsions.

Maximum Stable Droplet Size• The Maximum Stable Droplet Size is a Function of the Mixing

Intensity (ξ = ∆P / tρ).

Dmax = 0.725 1ξ.4

σρc

.6

Dmax = Maximum Droplet Size (µm)ξσρc

= Mixing Intensity (erg/g.sec)= Interfacial Tension (dyne/cm)= S.G. of Continuous Phase

Hinze-Clay Relationship

101

102

103

104

105

100

Dmax(µm)

101 102 103 104 105 106 107 108 109ξ(erg/g.sec)

σ = 1σ = 5σ = 30

• Energy for Dispersion = Interfacial Tension x Interfacial Area. An important parameter for emulsion stability is the size of the emulsion droplets. As can be seen from the above figure the stable size of the emulsion phase droplets decrease at increasing energy levels. The smaller the droplets the more difficult it is to “break” or destabilise the emulsion and separate the water from the oil. This emulsion stability is often further assisted by the presence of stabilising chemicals in the produced crude as was discussed above.

Emulsion Droplet Size• Droplet Size is Dependant Upon System Energy and the

Density and Viscosity of the Continuous Liquid Phase.

0

10

20

30

0

10

20

30

0

10

20

30

1 2 3 4 5 6 7 8 9 10Droplet Size - µm

1 2 3 4 5 6 7 8 9 10Droplet Size - µm

Vol% Vol% Vol%

1 2 3 4 5 6 7 8 9 10Droplet Size - µm

Gas Lift (18% Water) Beam Pump (29% Water) Beam Pump (84% Water)

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Potential Emulsification Areas• Increase in Velocity

or Turbulence.• Typical Mixing

Intensity Values:• Choke - ξ∼109

• Valve - ξ∼107

• Pump - ξ∼106

• Pipeline - ξ∼102

• Sample Point - ξ∼106

1

2

3

4

5

Surface Pumps

Beans, Valves

Artificial Lift

Perforations

Formation

1

2

3

45

Originally in the reservoir, the oil and water phases, having stayed at rest in the formation for millions of years, are fully separated in the formation pore structure. When production starts, the oil and when the water cut exceeds connate water saturation, also the water, starts moving from the formation into the wellbore, up the tubing, across the bean valve into the flow line, etc. Over the total distance of their travel from reservoir to the export tanks, the oil and water is subjected to shear forces and different mixing intensity levels. As result stable emulsions can be formed stabilised by the emulsifiers.

Formation-Perforation Region

Shear Around Wellbore EmulsificationField

SW Ampa(Brunei)Rahab(Oman)

Lab Study@ 30 cm @ 15 cm

0.8 - 4.0 E4 1.3 - 6.5 E4

40 - 120 65-185

>2000

>1100

sec-1sec-1

• The Emulsion Forming Tendancy in the Formation and at thePerforations can be Modelled Using the Shear Rate.

8kθ4V

• Kozeny’s Formula : Shear Rate =

Laboratory modelling can be used to establish the likeliness of emulsion forming conditions in the formation and at the perforations in the wellbore. The so-called dynamic coalescer ( a fan viscosity meter type equipment) has been developed to submit live crude and water mixes to similar shear conditions as

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observed downhole. It is important to note that presence of gas and the actual pressure cannot be simulated. For calculating the actual shear rate at the wellbore Kozeny’s formula can be used. Shear rate = 4v/√(8kf) v = linear velocity (m/s), k = formation permeability (m), f = porosity (fraction). Example: A well produces 100 m3/d ,the total perforation surface area is 1m3, while the permeability is 1Darcy and the porosity is 0,3. What is the average shear rate at the perforations? Velocity 100 m3/d => 100/(24*3600) = 1,1 * 10-3 m/s Shear rate = (4* 1,1 * 10-3) / √ ( 8* 10-10 * 0,3) = 284 s-1

The dynamic coalescer can be used to subject oil and water mixes to the calculated shear in order to find out whether formation of stable emulsions under these conditions are likely. Further the effectiveness of selected demulsifiers can be screened.

Gravity SeparationBuoyant Force: Fb=1/6 * gπd3(ρw-ρo)

Most important parameter is droplet diameter (d)

Drag Force: FD=1/8 * π * CD * d2 *ρw * v2

where v = gd2 * (ρw -ρo) 18 µ

Density difference (ρw-ρo) between oil and water phase Cannot be influenced

Can be influenced

Viscosity of continuous phase also important for separation Oil and water can be separated because of their difference in density. If the density of the droplets of the dispersed phase is lower than the continuous phase, they are rising upwards while in the other case (e.g. water in oil), the droplets are falling. The basic equations describing this motion are the buoyant force: Fb =1/6 g π d3 (ρw - ρo)

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Fb = buoyant force, N g = gravity, m/s2 d = diameter of droplet, m ρw = density of water, kg/m3

ρo = density of oil, kg/m3 and the drag force: FD = π/8 CD d2 ρw v2 FD = drag force, N CD = drag coefficient v = droplet velocity relative to continuous phase, m/s Equating Fb with FD and assuming a Reynolds number “Re = (ρwvd / η)” below one, so that the equation CD= 24/Re is valid, the terminal velocity of a spherical , dispersed phase droplet, will give Stokes Law (next Viewgraph). The only parameter which can be influenced is the droplet size by subjecting the emulsion to more or less mixing energy (shear). This influencing starts already at the plant design phase where high shear conditions are avoided where possible.

• Separation is Primarily by Settling:• Stokes Law

• Variables: Droplet Size (d), Viscosity (µc), Gravity (g), Density(ρ).• Influencing Factors: Turbulence.

Dehydration

δρ.g.d2V= 18µc

Velocity (ft/hr) of a 200 µm Water Droplet in Various Gravity Crudes

Crude API 12 16 3340 oC 0.01 0.1 7

65 oC 0.12 0.18 10

90 oC 0.28 0.45 18

In Stokes Law the variables are the droplet size, the viscosity of the continuous phase, and the density difference between the phases. At static (or very low shear) conditions (i.e. in a dehydration tank) the droplet diameter being squared in the equation, the effect on phase separation velocity (dehydration) is very significant. The example on the view-graph demonstrates the effect of the viscosity on the settling velocity of water droplets in oil at various temperatures. As the temperature rises, the viscosity drops and settling velocity increases.

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The higher the API (or gravity number) of the crude the lower the viscosity of crude oil is. For a similar water droplet of half the above diameter (or 100 µm), these velocities would be a factor four lower. The above table also demonstrates the effects of API gravity and temperature on the dehydration velocity. The higher the API number (or the lighter the crude) the faster the droplet velocity. This is caused by two factors; first the lighter the oil phase, the larger the density difference between the oil and the water phase. The second reason is that the viscosity of lighter crudes (the continuous phase) is lower thus allowing less drag and faster separation. Increasing the temperature during the dehydration process also results in a lower viscosity of the oil and enhances the droplet velocity. For this reason heating is sometimes applied to enhance dewatering of emulsion.

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Sedimenting & Coalescing

Closely Packed & No Coalescing

Good Separation

Interference

Continuous DehydrationThe “Working Layer” Promotes Active Coalescence

Dry Oil

Emulsion

Water

In continuous dehydration tanks the feed stream is entered below the oil water interface. The oil droplets have to move through the (brown) emulsion layer in the middle where they meet other small oil droplets. As demulsifier has been injected upstream the feed emulsion is destabilised and droplets can easily coalesce into larger ones improving the separation velocity. The density of the water droplets mixed with oil is also lighter than pure water and will enter the water rich emulsion layer allowing these droplets to grow in size and fall into the “clean” water layer. In case of “stable” emulsion the interface is very closely packed with a higher apparent viscosity making it more difficult for the oil and water droplets to enter the middle emulsion layer. As result coalescence will be hindered as no free interaction between the droplets will be possible. Stable emulsions can be formed and grow in size as result of the presence of for instance stabilising agents such as emulsifiers, silt, rust particles, etc. For this reason the emulsion layer has to be removed from the tank at regular time intervals and treated with heat and/or chemicals to be broken into clean oil and water.

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DeHydration Demulsifier Action• Rupture the Emulsion Skin

and Coalesce the Dropletsto Increase Size.

• Destabilise the Skin.• Adsorb at the Interface.• Displace the Emulsifier• Alter the Emulsifier

• Promote Coalescence toIncrease the Droplet Size.

• Chemical Must be FullyDispersed in the StreamBefore the MechanicalSeparation Equipment.

0 100 200µTCM 2227/8

The above view-graph shows a microphotograph of water droplets in an oil phase. Emulsifier chemical molecules, present in the production stream, position themselves along the interface between the water and the oil phase, creating a kind of difficult to penetrate skin stabilising the emulsion. Addition of Demulsifier chemicals counteract the effect of the emulsifier and reduces the interfacial tension or the energy required for the droplets to coalesce into larger ones. The results is that the skin (of emulsifying agents) around the droplets is ruptured allowing easier access to the cohesional forces of other droplets. To be able to work optimally, it is important that these chemicals are applied as far upstream in the production stream as possible to allow time for the chemical molecules to place themselves around the water droplets and promote coalescence. This process can be totally upset when excessive shear is applied to the feed stream whereby all liquids and chemicals are mixed up again. It is therefore important to avoid large pressure drops and/or the use of high shear pumping systems before the oil and water phases are separated dehydrated).

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Chemical Application

0102030405060708090

100

0 4 8 12 16 20 24

Free Water, %v

Time, hrs

• Inject Demulsifier at the Earliest Possible Point.• Allow Coalescence Before Entering the Separation Tank

Downhole

Wellhead

None

As discussed above, for optimal application of dehydration chemicals these products have to be injected as far upstream the system as operationally possible. Preventing stable emulsions to be formed is the most important criterion. Downhole injection of the chemical would theoretically be the best option as it could also enhance the production rate of the well because of the lower viscosity of the produced fluids as well as giving more time for the chemical to avoid or destabilise stable emulsions. In practice however, injection downhole may not be practicable as this would require intensive operator attention. In some cases, it may be possible to select one or two notoriously stable emulsion producing wells for downhole injection in stead of injecting at the production manifold of that particular field. A new option currently under development by RTS in Rijswijk is the squeeze injection of demulsifier chemical downhole say once a year in stead of continuous injection and similar to the injection of scale inhibitors. Slow release chemicals are injected in the formation rather than applying continuous injection.

Chemical Selection• Identify the Problem.

• Representative Samples Throughout Process Stream.• Evaluate Mixing Intensity Distribution.

• Eliminate Mitigating Factors Where Possible.• Lengths of Pipeline Instead of Valves to Reduce Pressure.

• Compatibility Testing with other Treatment Chemicals.• Ionic - Cationic Reactions.

• Bottle Test with Chemicals.• Quick Elimination of Non-Candidates.• Due to Complexity of the Process it is Still the Most Effective Method.

• Evaluate Best Candidates for Temperature Sensitivity.• Select on Cost-Performance Basis.• Field Test

• Minimum of 3 Months to Allow System to Stabilise and to Monitor Sensitivities.• Routine, Representative Sampling Throughout the Field Trial.

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Where stable emulsion, hindering the dehydration process are encountered, dehydration chemicals may be required to enhance the separation process. To identify which chemicals will be required and at what location, a comprehensive sampling and analysis programme has to be conducted to find out where the problems do occur. It could also be that somewhere in the system conditions do generate sufficient mixing energy to stabilise emulsions, and could be avoided easily by simple engineering modifications. In these cases, making these modifications and if economically feasible, would always be preferred above using chemicals. If this is not the case and chemicals will be required, an extensive screening of products has to be conducted using the so-called “bottle test”. This test in which a large number of products can be screened will allow for a quick elimination of non-performers. Life crude-water mixes without chemical are used for this screening test. 100 ml bottles are filled with a carefully homogenised mixture to which a certain concentration of one of the demulsifiers under test is added. These bottles are monitored for their oil-water separation performance against time, the so-called “settling profile”. The faster the oil and water separate into clean oil and water phases without sediment or stable interface, the better the performance of the product. Apart from obtaining a “dry” or water free crude, for environmental reasons also the water quality (i.e. oil in water content, etc.) becomes ever more important. Until now it is still not possible to select suitable products based on the chemical composition of the to be treated production stream and physical testing of products will continue to be required. After this first screening, a number of products will have to be tested further for their performance under different operating temperature conditions and variations in production streams. After this second phase screening and economic evaluation, one or two promising products are being selected for a full field trial. During these field trials which typically last three months, all the different parameters such as fluctuations in production rates, temperature, dosing rates, compatibility with other chemicals such as corrosion inhibitors, but also the effect of stimulation activities in the field, etc. can be monitored. Based on the outcome of these trials, during which period an extensive sampling programme has to be followed, the most cost effective product can be selected.

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Demulsifier Chemicals• Anionics• Sulphated Oils, Sulphonated Oils

• Cationics• Quaternary Ammonium Compounds and Amines

• Nonionics

Demulsifier chemicals can be divided into three main groups being the “anionics” which have a negative charge on the molecule, the “cationics” with a positive charge, and the “nonionics” who are neutral. Depending on the emulsion stabilisation chemicals present in the feed stream, chemical mixtures of one of these classes are used to destabilise the oil and water emulsion. Thereby ionic chemicals of the opposite side can never be mixed as they react with each other and negate each others effect. This also applies if a for instance “cationic” chemical is used for corrosion inhibition. In this case no “anionic” chemical can be used as a demulsifier this would result in counteracting the effect of both chemicals and precipitation products. Non-ionic chemicals being neutral in electrical charge however, can be mixed with either anionic or cationic chemicals. Nowadays chemical mixes are rather complex and can exist of a large number of products with varying molecular length. No method has at yet be found to predict with sufficient accuracy, the effectiveness of these chemicals. Trial and error product screening is up to now the only method of selecting an optimal product.

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SAMPLING PROGRAMME

When?• New Developments or Extentions

•De-bottlenecking of Existing Facilities

•Troubleshooting

•Routine

Sampling Aspects•Offshore or Onshore Development

•Is it a Complete New Development?

•Is Crude Light/Heavy/Waxy/Asphaltenic?

Sampling programmes are important tools to prevent or solve dehydration problems. For a new field development, up front information is required of the production stream to anticipate potential emulsion/dehydration problems. During production testing, of exploration wells, only limited information can be collected about the dehydration characteristics of this new stream. The settling profile can be measured on life crude samples which allows early information on potential separation problems. Already a start can then be made in selecting some potential demulsifier products which could be used once the field starts producing. De-bottlenecking of facilities means that somewhere in the production facilities the conditions are such that they are the limiting factor for the maximum throughput of the plant. A careful analysis and investigation of the settling performance at various locations in the facilities is required to find the limiting factor. For trouble-shooting of existing facilities, can be conducted to find the location in the production system normally functioning satisfactorily, now causing the dehydration problem. Changed operating- or other process conditions need to be found. Once identified and understood, the best option for restoring proper functioning can be identified, either technically, or by using/changing chemicals. Routine sampling is conducted to ensure that changes in dehydration performance are readily identified to allow timely action to rectify the changed condition before it results in dehydration upsets. Routine sampling therefore requires regular sampling at all critical locations in the field and the production facilities while maintaining statistical records for analysis.

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Aspects of importance for a sampling programme, include the location of the field, onshore/offshore, the complexity of the operation, the physical properties of the individual crude streams and their compatibility, etc. A complete new development, where no- or very limited data are available, will require another sampling approach compared to a field already in production for many years. The properties of the crude also are important for a good sampling programme, necessitating sometimes different sampling methods to make sure a representative sample is taken.

Sampling for Emulsions• Sample Collection Must Not Alter the Sample Condition.• Typical Mixing Intensity

Values:• Choke - ξ∼109

• Valve - ξ∼107

• Pump - ξ∼106

• Pipeline - ξ∼102

• Sample Point - ξ∼106

1

2

3

4

5

Surface Pumps

Beans, Valves

Artificial Lift

Perforations

Formation

12

3

45

At many locations in the production system the produced fluids are subjected to mixing energy levels as shown above. As result the oil and water are mixed and could form more or less stable emulsions. When sampling to identify potential dehydration problems in the field, it is important that the samples taken reflect the actual situation around the sampling point. Therefore a proper sampling technique and equipment is required.

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Sampling• Sample Collection Must Acquire a Representative Sample.

• The Whole Flow Stream Should be Sampled without Creating extra Shear.• Recommended Sampling System

A crude sample for dehydration performance testing has to be representative of the actual stream in that part of the production process system under investigation. The oil, water and gas phase in the flow line can be segregated and care has to be taken that all these phases are represented in the sample. Above picture shows a sampling system where, via an adjustable insert a sample can be taken across the height of the pipeline. Another option is that the insert is provided with a number of holes to take care of representative samples. To minimise pressure drop and thus mixing energy across the sampling bottle inlet, a large size valve has to be installed and fully opened to minimise the inlet restriction.

Temperature Effect• Temperature can Significantly Affect Dehydration Chemical

Performance.

0

5

10

15

20

25

0 30 60 90 120 150 180 210 2400

5

10

15

20

25

0 30 60 90 120 150 180 210 2400

5

10

15

20

25

0 30 60 90 120 150 180 210 240

Static Time - Minutes

Test Temp: 70oC

Only Product A Gave Separation

Residual Water

%Test Temp: 60oC Test Temp: 80oC

ABC

Demulsifier chemicals, due to their complex chemical mixtures, may be significantly affected in dehydration performance by variations in temperature. Climatic changes in temperature will also affect the temperature at which crude streams are processed

23


and have a significant impact on the “dry crude” quality. In desert locations ambient temperature differences of over 50oC are not uncommon, and result in significant variations of the production stream temperature. When screening for alternative demulsifier products, the temperature sensitivity of these products has to be taken into consideration. Before starting a new screening exercise, the maximum and minimum expected crude stream temperature has to be measured. These minimum and maximum temperatures can then be applied during the static settling performance bottle tests. The above picture shows their performance on a certain crude stream varying in temperature from 60 to 80oC. At 60oC, only product A showed some separation, while no separation was achieved with the other two demulsifiers. At 70oC, all three products gave separation, product A showed an average performance of the three chemical products. At 80oC, the performance of all three products improved but chemical A was the least effective product. Where temperatures fluctuate from 60 to 80oC, product A would be the best choice, whereas with temperatures between 70 and 80oC, product C would be the best product. Where no incompatibilities do exist between the tested chemicals another option may be to change of chemical product to optimise the dehydration for the various seasonal temperatures.

The Ghost Field Problem• The Ghost Field Produces from 50 Wells; Each Delivering

about 160 m3/day• Oil-Water Separation and the Export Crude and Disposal

Water Quality have become an Increasing Problem since theFirst Formation Water Breakthrough.

• Several Remedial Actions have been Implemented but theProblem Persists.

• As a Team Assigned to Investigate the Problem:• Analyse the Treatment Process and Flow of Fluids.• Identify the Potential Problem Areas.• Recommend Changes.

• Consider the Various Change Options : Economics versus Benefits

24


The Ghost Field Schematic

AtmosphericFWKO

Gas

Dehydration Plant

FTHP1650 kPa

FieldManifold50 wells1500 kPa

Field Station

Gas

4” Flowline2000 m

Gaslift

7” Csg3.5” Tbg

1500 m

FBHP25,500 kPa

10 m500 mD20% Por.

SSV

ChemicalInjection

240 m3/dWater

6,400 m3DynamicDehyd.Tank

20m

4800 m3DynamicDehyd.Tank

10m

320 m3/dFreshwater

3200 m3/dWater

800 m3/dWater

12” Flowline1000 m

GasSeparator675 kPa

160 m3/d

4100 m3/dOil

25


1.2. SLUDGE

Sludge• A Substance Left Over from the DeHydration Process.• Irreversible Emulsion with Entrained Solids and Debris.• Appearance is Highly Viscous with the Components Very

Finely Divided.• If Not Removed Results in:

Poorer Dehydration PerformanceTank Dropout SRB Growth

Components:Water, Oil,Sand, Silt, Clay, (Heavy Metals)Wax, Asphaltenes, ScaleCorrosion Products, Bacteria

Together with the oil and water, other components from the reservoir such as clay, silt, sand, but also wax, asphaltenes or scale can be co-produced. Operations such as well acidisation and back production, apart from the spent acid, often also results in large amounts of the above products to be released in the production system. From the well and the production facilities, rust, paint, or bacterial debris, can be transported into the production system. These products often have a stabilising effect on oil and water emulsion systems and hinder the destabilisation process of the demulsifier in a dehydration system. As result, a stable, tight and highly viscous emulsion layer (called sludge) builds up and cause a deterioration of the treated oil and water quality. Also, the use of an ineffective dehydration chemical can result in the build up of tight emulsion in the treatment facilities. Carry-over of some of the sludge into the static dehydration-, export crude-, and water treatment systems will occur and a sludge layer will also build up in the bottom of these tanks. Draining of the static dehydration and export tanks to remove water and stable emulsion is applied to avoid excessive build up and to allow full utilisation of these tanks. Normally the water is drained via a closed drain system to the water treatment facilities while the sludge is often routed back into the incoming feed stream. Due to the stability of these sludges, the amount of this product continues to grow and further burden the dehydration process. To minimise disturbances to dehydration and prevent sludge build-up in the facilities, the stabilised emulsion will have to be removed from the oil-water interface at regular time intervals. In continuous dehydration systems the sludge can be taken from the interface via a separate line, while for batch operated systems sludge can be drained after first draining the free water phase.

26


Heat treatment is often applied to destabilise sludge, sometimes combined with special dehydration chemicals or acid such as acetic acid.

Oily WaterTreatment

ExportCrude

HeatTreatm.

BatchDehydration

FWKO

Sludge

Dehydration System

Sludge Build-up

FeedStream

EmulsionBreak Tank

Above picture shows a (very simplified) typical dehydration facility where sludge is generated at various locations in the system. The feed stream enters the Free Water Knock-Out (FWKO) tank with a relatively short residence time, to remove mainly free water. The inlet is located just below the emulsion layer to take advantage of this “working” or coalescence layer. If this layer grows too much or becomes too tight to optimally function, a part has to be removed and treated via a heater treater. From the FWKO tank, the crude stream is transferred into batch dehydration tanks with a longer residence time, where the oil and water separation will be completed. Also in these tanks stable emulsion can build up which has to be removed at regular intervals to allow continued optimal functioning of these tanks. In the heater treater the unbroken emulsion is heated to enhance the separation into oil and water. Sometimes chemicals can be added. From the heater treater, the emulsion will be transferred into an emulsion break tank to allow full separation. If unbroken emulsion (sludge) remains from this tank, it has to be disposed of to prevent it to recirculate through the treatment facilities and worsen the situation.

27


Disposal•Burial•Road Surfacing

•Direct Application•Injection into Asphalt Plants.

•Solidification with Calcium Silicate (Dresser)•(Re-)Injection into wellbore or reservoir

•(Controlled) Land Farming•Natural Evaporation•Bacterial Degradation

Sludge Disposal

• Spiking in Crude Stream• Mechanical Removal for Biological Degradation or Disposa• Incineration

Sludge can be removed from the dehydration system via direct spiking in the crude stream, mechanical removal or incineration. Spiking into the crude stream can only be allowed if crude quality criteria are not exceeded. Spiking the sludge into the crude results in transferring the disposal problem to the refinery and is therefore not the environmentally preferred way of handling. Another option is incineration where the emulsion can be injected in an incinerator. Often when tanks have to be opened for maintenance sludge and bottom sediments are often removed mechanically and have to be disposed of. Depending on the composition (heavy metals and toxic organic materials) of the sludge and environmental legislation in place, various options are available. These include: • Burial (only allowed where no leaching of chemicals can occur) • Road surfacing (either via direct application or by mixing in asphalt) • Solidification to prevent leaching • Land farming in contained areas where toxic materials evaporate and/or degrade

naturally. Sometimes sludge can be used as addition to the fuel for cement kilns which temperature is high enough to fully decompose the material in an environmentally acceptable manner.

28


1.3. Deoiling

DeOiling Chemicals• Aid Mechanical Separation: Gravitational or Filtration• Increase Droplet Size

• Skin Rupture & Coalescence• Quarternary Ammonium Compounds to Displace Emulsifying Agents• Insensitive to Dehydration Demulsifiers• Relatively Expensive (~$0.01/m3)• Toxic

• Agglomeration• Polyacrylamide• Insensitive to Dehydration Demulsifiers• Relatively Inexpensive (~$0.004/m3)• Sensitive to Overtreatment (maximum 5 ppm)• Generally Non-Toxic (Must Not Have Free Acrylic Acid)

The water separated from the oil in the dehydration process always contains some oil. As the water has to be disposed off either as an effluent into the sea or other surface waters, or will be (re-)injected into a reservoir, the oil content has to be reduced to meet environmental- or technical requirements. Most of this oil can be normally removed from the water using mechanical equipment, such as tilted plate interceptors (TPI), Dispersed or dissolved gas floatation units, hydrocyclones, (ultra) filtration units or centrifuges. The selection of the equipment is mainly based on three criteria namely, final oil concentration, oil droplet size and available space. In particular (ultra- or membrane) filtration units and centrifuges are capable of removing very small oil droplets and reduce the oil content to below 10 ppm. Often, in production facilities equipment is installed which cannot meet the required outlet oil in water content. This can be caused either by having the wrong equipment installed for the particular produced water stream, or as result of tightening of environmental legislation. In these cases, chemicals could be used to enhance the performance of the equipment. It is very important to realise that when chemicals are added, the main part of that chemical will be disposed together with the water. Therefore, in the selection of a deoiler chemical, the environmental acceptability is a very important factor. Typical deoiler chemicals act in a similar way on oil in water emulsion as demulsifiers on water in oil emulsions and in this case rupture the rigid skin around the oil droplets allowing coalescence to take place. They are therefore often called “reverse emulsion breakers”.

29


Quaternary ammonium compounds are cationic or positively charged thereby displacing the emulsifier at the oilskin. These chemicals can only be added in the system after the dehydration process has been completed as they counteract demulsifiers which are mostly anionic. Another later developed group of deoiler chemicals are the so-called agglomeration products, mainly organic polymer products. These products with high molecular weight, have a charge density (positive or negative) independent of the pH of the water. This charge density will neutralise the opposite, often negative charge of the oil droplet and destabilise it. The advantage of the use of polymers is that they are virtually insensitive to dehydration demulsifiers and do not cause incompatibility problems. Also compared to the above reverse emulsifiers they are relatively less expensive, and more importantly virtually non-toxic.

30


2. Organic Deposits In this chapter the organic deposits hydrates, waxes and asphaltenes will be discussed. Hydrates are crystalline compounds of water stabilised by certain guest hydrocarbon molecules including methane, ethane and propane. Their main importance is that these crystals can be formed during the production of water containing gas sometimes at temperatures well above zero degrees centigrade, the normal freezing point of water. Waxes are chemical compounds consisting of long aliphatic (linear) hydrocarbon molecules, which depending on the chemical composition of the oil and the temperature, will form wax crystals. Asphaltenes, are complex mixes of hydrocarbon compounds which are dispersed in crude oils. Once destabilised, also these chemicals can form deposits which is mainly pressure dependent. Destabilisation and subsequent deposition mainly occurs when the (above bubble point) pressure of a compressible crude is reduced resulting in a reduced solubility of the asphaltenes.

Hydrocarbon Processing DepositsHydrocarbon Based Deposits• Hydrates

Crystalline Water and Hydrocarbon Compounds.• Wax

Paraffinic, Alkane, Component of Crude Oils.• Asphaltenes

Natural Compounds Dispersed in Crude Oils.

••• Aqueous Based DepositsAqueous Based DepositsAqueous Based Deposits••• ScaleScaleScale

Inorganic Chemical Deposits.Inorganic Chemical Deposits.Inorganic Chemical Deposits.

31


2.1. Gas Hydrates

Gas Hydrates• Gas Hydrates are (ICE) Crystals Formed by a Framework of

Water Molecules, Reinforced by Guest Molecules.• The Most Common Guest Molecules are:

Methane (.7H20), Ethane (.8H20), Propane (.18H20), CO2, H2S and N2

Carbon Dioxide Hydrogen Sulphide

• Freezing Point Rises with Increased Pressure.

H

GuestMoleculeO

Gas hydrates are crystalline compounds formed by a framework of water molecules, reinforced by guest molecules. Under suitable conditions, water molecules may form structures as a result of hydrogen bonding. These structures are thermodynamically unstable. However, if guest molecules are available to fill the cavities in the water framework, stable compounds will be formed. Suitable guest molecules relevant to the oil industry include small hydrocarbon molecules such as methane, ethane, propane and isobutane, as well as other gases such as carbon dioxide and hydrogen sulphide. The size of the water lattice structure can vary, the final arrangement being dependant on the precise availability of guest molecules. These hydrate lattices when formed in production systems may grow to the extent that they can plug lines or pieces of equipment. They can be found in the liquid as well as the gas phase and, because of their damaging consequences, great care is taken to avoid their formation in production systems. Hydrates can be formed in oil and gas production and transport facilities and may cause severe problems. A (normal) pre-requisite for hydrate formation is the presence of free liquid water. High pressures and low temperatures are also beneficial to the promotion of hydrate formation. Impact of hydrate crystallisation Hydrate ice crystals are generally softer than normal ice and as such will not normally cause damage to tubing, flow line, or vessels. However, in some cases the crystals are harder and cause erosion or destroy sensitive parts in the production facilities. In particular attention has to be given to the damage which can be caused to measuring devices such as orifices and pressure differential membranes.

32


In larger quantities, the crystals tend to lump together and cause blockages in the system, for instance in the wellbore, the tubing or flowlines causing interruption of the gas flow.

Impact of Hydrate Crystallisation• Particles.

• Hard Hydrate Crystals can:• Cause Erosion of Metal Components.• Destroy Inlet ‘Scrubber’ Screens.• Impact on Measuring Device Integrity.

• Blockages.• Hydrate Formation can

• Plug Producing Zone• Block Tubing• Block Flowlines.• Block Measuring Device Inlets.

Hydrate Formation At temperatures well above 0oC, water molecules are moving freely from each other, called the “Brownian” movement of molecules. When temperatures are approaching the normal freezing point of water, these movements are becoming slower and the water molecules tend to group themselves in a more stable structure. This is done via the so-called “Hydrogen Bonding” in which the Hydrogen atoms from the water molecules are forming a loose bond with the Oxygen atom of another water molecule. In this way clusters of water molecules are being formed where the hydrogen bonds move from one molecule to another. During these changes in hydrogen bonding, also the formation of unstable crystal like lattices may occur. In the presence of certain “Guest Molecules” which have a size to nicely fit in the cavity of a lattice of water molecules, the total structure can thereby be stabilised such to form a hydrate crystal. As result hydrate ice crystals can be formed well above the pure water freezing point.

33


Cluster Model of ‘Freezing’ WaterH

OO

O

O

O

O

O

O

O

O

O

HH

H

HH

H

H

HH

H H

HHH

H

H H

HH

H

O HH

HH

H

HH

HH

HH

H

H

H H

HH

H HH

H H

H

H

HHH

H H

H

H

H

H

H H

HH

H H HH

HH

O

OO

OO

OO

O

O

OOO

O

O

O

O

OOO

O

O

Regions of LowThermal Energy

Flickering Clusters due to Hydrogen Bonding

Factors affecting hydrate formation Although solids, like true ice, hydrates have different structural characteristics. Two hydrate structures are often encountered in oil and gas production operations. Firstly, the simplest of all crystalline cavity structures can be formed by a pentagonal dodecahedral of 20 water molecules linked together by hydrogen bonds (see below). This structure has 12 regular pentagonal (five-ring) faces. The almost spherical cavity inside this structure can accommodate small molecules such as methane, ethane and hydrogen sulphide.

A Simple Lattice of Water MoleculesA Simple Lattice of Water Molecules

40 Hydrogen-BondLinkages

20 OxygenAtoms

34


As a result of minor deformations, other structures containing cavities can be formed besides the regular pentagonal-dodecahedron ones. Typical examples, like the fourteen and the sixteen face cavity structure are shown on the figure below left and right of the twelve face structure. The larger the cavity the larger molecules the molecules it can contain, including propane, isobutane and carbon dioxide. The hydrogen bonding structure of the hydrate is weak and will collapse unless it is supported by molecules occupying the cavities. This explains why propane and butane, which only can fill the larger cavities, form very unstable hydrates- as they do not fill enough cavities to support the weak lattice structure. Molecules larger than butane are too big to form hydrates as they cannot fit into the cavities. In fact they tend to inhibit hydrate formation because the crystal tries to form around it. The number of guest molecules that can enter the cavities is dependant upon temperature and pressure (pressure distorts the lattice, and hence the cavity shape). Not all the voids may be filled, and hence hydrate structure tend to be varied.

Typical Gas Hydrate StructuresTypical Gas Hydrate Structures

5 A

14 faces12 Faces

16 Faces

Ethane Methane Propane

The existence of single guest molecule stabilised hydrate crystals would not cause a problem in production facilities are their physical size is very small (+/_ 0.50 nm.) However, like normal ice, the crystal particles do tend to group themselves in typical three dimensional crystal shapes as shown above. As such their size increases to that extend that blockages of the flow system can occur

35


Packing of Hydrate Basic UnitsPacking of Hydrate Basic Units

General conditions for hydrate formation Hydrate formation in natural gas can, as follows from the above, only be formed in the presence of water. Its formation is mainly dependant on pressure and hydrates can be formed both in the gas and liquid phase of the gas (left of the hydrate line in the picture below). At lower pressures, the temperature also has an effect on hydrate formation, but significantly decreases when pressure increases.

General Conditions for Hydrate Forming

Dew PointLine

Bubble PointLine

HydrateCurve

P

T

CriticalPoint

The next picture shows the hydrate forming conditions for pure Propane (C3H8).

36


The line in red indicates the hydrate curve while the blue line is the Propane vapour pressure curve. The pink area indicates the total area where hydrates can be formed. Below the water freezing point of 0oC, both ice and hydrate are present, while above this temperature only hydrate ice can be formed. At temperatures above 0oC, the pressures required for hydrates formation increases steeply, while above the vapour pressure line, hydrate formation becomes virtually independent of pressure.

Hydrate Forming Conditions for Propane

0.05

0.1

0.5

1.0PressureMPa

Temperature oC1050-5-10-15-20

Hydrate+

Water

LiquidPropane

+Water

Vapour+

Water

Vapour+

Ice

Hydrate+

Ice

PropaneVapour Pressure

Curve

The same type of curves do also exist for other low molecular weight natural gas components including Methane (CH4), Ethane (C2H6), Butane (C4H10), Hydrogen Sulphide (H2S) and Carbon Dioxide (CO2) and can be used for hydrate formation prediction modelling. In the earlier models, like the Hercules model developed by KSEPL (former RTS), only simple predictions for gas mixtures could be made based on equilibrium conditions. They however, did not reflect the kinetics of hydrate formation and decomposition.

37


Prediction• Old Hydrate Prediction Software: ‘Hercules’ (EP 51181).

• New Software Package: “STFLASH” (OP97-20206)• More Accurate Over a Wider Operating Window.• Allows Multiple Phases and Tolerant to CO2.

• Sensitive to CO2 and Condensate.

A new software tool, STFLASH developed by Research and Technology Centre Amsterdam (RTCA) however, is a thermodynamic model, capable of obtaining quantitative results for the following categories: • Removal of water from the mixture below the level of saturation (with respect to

hydrate formation) • Control of thermodynamic conditions, i.e., temperature and pressure • Addition of inhibitor (i.e., Glycol or Methanol), shifting the equilibrium.

The addition of a new type of inhibitor, called “growth modifier”, cannot as yet be predicted with the model. The latest version (version 4.0) of the STFLASH software has recently been released with a user manual, report OP97-20206. Further information can be obtained from ORTET/26.

38


Prevention• Freewater is Necessary for Hydrate Formation• Dehydrate the Gas• The Water Must Freeze to Form Hydrates• Depress the Freezing Point.• Anti-Freeze: Methanol or Glycol.

• Glycol, being easily recoverable, is the preferred preventative measure.• Methanol, being faster acting, is the preferred remedial treatment.

• Ammonia and Salts (NaCl, CaCl2).• Salt solutions can be corrosive.

• Heat the Gas / Insulate Pipeline.• Inhibit Crystal Growth• Modify the Crystal Shape.• Negate Crystal-Crystal Bonding.

Hydrate Prevention Prevention is always the preferred option and is also applicable to the formation of gas hydrates. As water is always required in order to form an hydrate, dehydration (or water removal) of the gas could be an attractive option. Dehydration in the oil and gas industry is mostly conducted using glycol contactors and would be no option for downhole application. In most cases hydrates, when present form either downhole or upstream the gas processing facilities.

Anti-FreezesDo Not React with gas hydrates but dilute the liquid water phase thereby shiftingthe hydrate curve to lower temperatures by 0,8 degrees per mole % of particlesdissolved in the Water

H y d r a te M e l t i n g P o i n t

02 04 06 08 0

1 0 01 2 01 4 01 6 0

0 5 1 0 1 5 2 0

T e m p e r a t u r e ( o C )

Pres

sure

(bar

)

N o A n t i f r e e z eA n t i f r e e z e

39


A second option is to depress the freezing point for hydrates. This can be done by the addition of chemicals such as Methanol or Glycol and is used very often when hydrate formation is predicted. These chemicals do not react with the hydrate structure itself but merely function by diluting the water phase thereby shifting the freezing point to lower levels (see figure above). Glycols, due to their higher boiling points compared to water, can more easily be recovered from the gas in gas dehydration systems, and is therefore the preferred product as a preventative measure. Methanol however, due to its lower viscosity, acts faster and is mostly used for remedial applications when hydrates already have been formed. Examples in the figure below show that the selection of the product can also be dependant on other conditions such as the location of the hydrate plug in the production system.

When Hydrates Are Formed

MeOH Glycol +WaterWater

HYDRATE PLUGHEAT HEAT

BACK PRESSURE

SYSTEM PRESSURE

SLOW FAST

Other chemicals which depress the hydrate freezing point are salts such as common kitchen salt (NaCl) or Ammonium Chloride (NH4Cl). Despite of being cheap products, their disadvantages are the relatively large quantities required and their corrosivity to carbon steel. Heating is a third option to prevent hydrate formation. This option is often applied in gas sales systems where the lines around the pressure reduction system are insulated and electrically heated. The last option for hydrate formation prevention is by crystal growth prevention. This can be achieved in two ways namely:

40


• Crystal shape modification in which the crystal is reshaped into a more amorphous appearance. In this case by its non-crystalline shape the hydrate cannot easily adhere to flowlines etc. (see picture of amorphous crystal)

Amorphous Hydrate Growth

• The second type of growth preventers are the so-called “crystal-crystal” bond

negating products. As the word says it does interfere with the growth of crystals by positioning around the single crystal lattice, resulting in only very fine (and harmless) hydrate particles to be formed.

An example of the latter type chemical is the Shell developed product Armoblen 802. This product was successfully tested by Statoil in Norway in 1995. A disadvantage of this product, although being very effective in preventing large hydrate crystals to form, is that it is non-biodegradable. As part of the chemical ends up in the water phase of the production system and has to be disposed of, it is subjected to strict environmental limitations with regards the acceptable disposal option. Particularly in Europe, the only possible solution could be to re-inject the contaminated water into the formation.

Shell Hydrate Inhibitor• Initial Material - Armoblen 802

• Non-biodegradable Prototype• Successfully field trialed by Statoil, May 1995.

• Line operating at 4.5o Subcooling Hydrated up in about 2-3 hours.• With 0.25% Inhibitor Operated for Days Without Problems.• Tested Down to 10o Subcooling without Hydrate Formation.• Tested Down to 13o Subcooling Shutdown/Restart.• Ref. AMGR 96.202

• Limitations• So Far Tested to 20% Water Cut; However Statoil Claim Up To 40% OK.• Non-Biodegradable; However Can be Reclaimed in Glycol Regeneration

Unit or Neutralised in a Simple Sewage Treatment Plant.

• Future Developments• Biodegradable Version Ready for Field Trial.• Test Upper Limits of Operating Range.

As result, a new product has been developed by RTCA recently, which is biodegradable. The product called ACER 96S44, is now available via Akzo/Nobel (at test quantities) and is claimed to be 50% degraded within 28 days while product toxicity is lost in five days. A successful test was conducted by Shell Expro UK in the Sean field with a BS&W of 30%.

41


Another test planned in Norway, was cancelled as no approval from the Norwegian authorities could be obtained for reasons of the short term toxicity of the product. Akzo conducted an environmental risk analysis which showed any effect of the product to disappear within 5 days. Norwegian authorities still reject application as they do not wish to set a precedent for application elsewhere in Europe.

Shell Hydrate Inhibitor

New Biodegradable Product is ACER 96S44 (AKZO/NOBEL)

• 50% Biodegradable in 28 days• Successfully tested by Expro in Sean Field (30% BS&W)• Product Toxicity was Lost in 5 days

• Statoil Trial: No approval from Norway Authorities yet

Advantages of ACER 96S44:

• +/- 8 times Cheaper than Methanol• Safer (Not flammable)• Requires less Storage Space

The figure above shows the advantages of the new type inhibitor compared to the regular glycol and methanol. Testing of Hydrate inhibitor products In order to develop improved hydrate inhibitors, RTCA has developed a Hydrate test loop in which wet gas can be subjected to actual temperature and pressure as encountered in the field. In these tests the conditions under which hydrates are being formed can be established. Another important function if this test loop is to test the effectiveness of hydrate inhibitors. So, before an expensive field trial is to be carried out, first the product can be tested in the laboratory.

Hydrate Test Loop - Amsterdam

Recently, Statoil developed their own test loop for hydrate formation testing. A transparent loop is filled with gas, condensate and water and cooled to the required temperature. During this cooling process the loop is rotated with a velocity of 1 m/s, while a camera is fixed to the loop such that it is level with the gas/condensate interface. While rotating, the liquids are moving and mixing with the gas to enhance contact. The video camera records the movements of the liquids in the loop while rotating. The formation of hydrates and its effect on the flow of the liquids can be followed instantaneously.

42


Also this loop can be used to test the effectiveness of hydrate inhibitors and has the advantages of being more simple and visibly showing the effect of inhibitor products on the onset of hydrate formation.

STATOIL Hydrate Wheel Test Unit1 m/s

Camera

Condensate

Water

Gas

Laboratory Grown Hydrate Crystal

Apart from the Armoblen and the later biodegradable Acer product, other inhibitors are available on the market. One of these, an initial BP product, was proved to be fully ineffective in reducing the onset of hydrate formation. This product was removed from the market by BP and replaced by a former Shell product THI. This product is discarded by Shell as a poor performer but claimed by BP to allow 10o sub cooling. It was tested by Statoil and found to be hydrated up in two hours only. BP conducted a field trial in the Hyde West Sole field with 12 o sub cooling, where over one year they reported only minor hydrate forming problems. Another, more important problem reported was the formation of severe emulsions resulting from incompatibility of the product with demulsifier used in the field. For this reason BP also plan to conduct a trial with the Acer product in the Villages field. For pipelines in marginal hydrate forming conditions THI may be a suitable product as in this case no crystals are formed at all, therefore needing no condensate flushes to disperse crystals.

43


This product has the advantage of already being commercially available and it is currently planned to be used as first fill in the Shell Expro UK ETAP field.

Other Hydrate Inhibitors• Initial BP Inhibitor

• Proven to be Fully Ineffective (i.e. ‘0’ performance) and Dropped by BP.

• Current BP Inhibitor - THI• Previous Shell Development Discarded as a Poor Performer.• Claimed to Perform up to 10o Subcooling.

• Tested By Statoil at Tommeliten• Ineffective, Hydrated Up in 2 hours.

• BP Field Trial in the Hyde West Sole Field (12o Subcooling).• Only Minor Hydrate Problems Reported.• Severe Emulsions Reported.• Want to Field Trial Acer in Villages Field.

44


2.2. Waxy Crude World-wide approximately 1500 different types of crude have been distinguished, although no two crudes are found to have exactly the same composition. Of these, between 10 and 20% are found to be waxy. A strict definition of what constitutes a problematic, waxy, crude is not possible because this is not related to any one single property of the crude. The paraffin waxes present in a crude are the saturated hydrocarbons, with. both straight chain -, CH3-(CH2)n-CH3, and branched-molecules being present. Methane, is the simplest saturated hydrocarbon, and being a gas under all operating conditions, can not be classified as a paraffin wax. In general, the higher molecular weight compounds have higher melting points and so can generally be considered to be more "waxy”, although an increased amount of branching in a molecule reduces this effect. Whether wax is observed to crystallise under field conditions will depend considerably on local circumstances. Production rates, temperature and flow conditions, presence of other hydrocarbons, asphaltenes, resins and water content are all factors which may have a bearing upon this. Thus the paraffin wax which crystallises will vary in composition for each individual case. Operating at low temperatures is likely to induce crystallisation for smaller, lower melting point molecules (although the higher melting molecules will precipitate as well), than operating at higher temperatures.

WaxWax• Wax is the Paraffinic, or Alkane, Part of a Crude.

• Deposits Usually Include Other Heavy Hydrocarbons, Asphaltenes and Resins.

• Crystallisation is Temperature Sensitive.• Pressure has a Much Smaller Effect.

• Crystals can be Either Plate or Needle Like.• These Interact Resulting in a 3-Dimension Structure.

Bubble point-line

Temperature

Pres

sure

The Figure above shows a typical plot for the conditions under which wax will deposit. Wax deposition is mainly temperature dependant, while pressure only has a minor effect.

45


Wax crystals can have different crystal structures depending on the hydrocarbon composition. The structures are three dimensional and can easily adhere to rough metal surfaces.

Impact of Wax Crystallisation• Increase in Crude Viscosity.

• Higher Pressure Drops (Higher Pump Input Energy).• Reduced Throughput.

• Gellation• Very High Restart Pressures.

• Deposition on Metal Components.• Increased Wall Roughness Inducing Turbulence.• Partial Blockage Reducing Flow Area.• Impaired Safety Device Functionality.

• Solidification in Pipelines.• Arrest of Flow ( )

PipeWall

Cool

Cool

Wax deposition can have the following impact on hydrocarbon production. • Increase in Crude viscosity as result from the presence of solid wax particles in

the oil. This increase of viscosity will result in higher pump pressures and reduced throughput through the production system.

• The solid wax particles due to their 3 dimensional structure have the tendency to adhere to each other thereby growing in size. This process, called gelation, proceeds more rapidly in stagnant or low energy flowlines where the initially brittle structures would easily be broken. In case flow has been interrupted for some time, these wax crystal structures are building up in time. At the time of restart, high pump pressures are required to break these gels.

• As at the flow-line walls, under laminar flow conditions the shear rate is lower than in the centre of the flow line. Wax crystals can more easily adhere themselves at the rough metal pipe walls without being sheared into pieces. Over time the wax particles are growing into more strong crystal structures, thereby reducing the flow area and result in increased pump pressure and lower throughput. Another aspect is that devices such as safety relief valves may become blocked and result in safety hazards.

• In extreme cases the total pipeline can become blocked by the deposition of wax. This is the case when the shear stress and yield strength exceed the pump capacity.

46


Wax Deposition The onset of wax deposition depends on the chemical composition of the crude; a high concentration of high molecular weight n-alkanes (e.g. C40+) often is the forebode of wax related problems. This onset is mainly influenced by the crude temperature and in a lesser degree the pressure. The temperature at which the first crystals appear is called the wax Appearance Temperature (WAT).

Wax Deposition

• Drop in temperature below Wax-Appearance Temperature (WAT) Drop in pressure (& temperature)

Beware of high proportion of n-alkanes e.g. C40+ => high WAT

Wax Terminology In its original composition all the constituents of a crude will remain completely dissolved when the temperature is high enough. On cooling, a temperature will eventually be reached at which wax crystals form. The temperature at which the first wax crystals form, and are in equilibrium with the wax that remains dissolved, is defined as The Wax Appearance Temperature (WAT). Above this temperature all the wax will eventually dissolve: below this temperature increasingly quantities of wax will crystallise. The best way to approximate the WAT is through the determination of the cloud point of the crude oil. The cloud point is defined as the temperature at which the first wax crystals are formed. This temperature may be determined by direct microscopic observation of the crude. However, due to the problems inherent in physically observing wax crystals in dark, non-transparent crudes, other means of measuring the cloud point have been developed. For example, the Bondi cloud point is obtained by recording the rate of cooling of a crude, the cloud point being marked by a drop in the rate of cooling induced by the onset of wax crystallisation. Due to the effect of supercooling, whereby crystallisation does not actually begin until below the critical wax solubility temperature, the cloud point in this method is obtained by extrapolating the cooling rate after crystallisation has been initiated, back to the cooling rate before crystallisation. In this way the super-cooling effect is eliminated as an error in the determination. Even so, due to the slow crystallisation rate of wax, this method also has its drawbacks. As a result of these problems the measured cloud point may be significantly (10-20oC) below the actual WAT. Pour Point Another way of characterising a waxy crude is by measuring its pour point, the temperature below which, flow of crude ceases. Paraffin crystals can, after sufficient wax has crystallised, form a three- dimensional structure. This structure may become sufficiently strong to prevent flow of the crude. The strength of this structure will depend on

47


several external factors such as shear effects and thermal history. More than one “type” of pour point can therefore be defined. The minimum pour point of a crude is defined as that obtained when the crude has been heated to 104oC prior to the pour point determination. The maximum pour point is obtained when the crude is heated to at least 46oC, or to 9oC above the expected pour point. The minimum temperature required to obtain the minimum pourpoint is called the “Inversion point”. If a repeat pour point were to be carried out on a sample, it is likely that a higher pour point than originally observed would be recorded the second time. Two factors would contribute to this phenomenon. Firstly some light components may have been lost by evaporation during the initial determination and hence the wax content of the crude may be expected to be higher for the sample for the second determination. Furthermore, when the gelled crude is re-heated the lighter paraffin’s within the crystal structure will dissolve first. The large crystal structure disintegrates leaving a large number of crystal fragments which, if they are not completely dissolved in the heating process, will act as crystallisation nuclei. Thus, it is likely that in the second determination, there will be more crystal nuclei to seed crystal growth, resulting in a higher pour point being obtained. In practice the apparent pour point is sometimes used. This is measured by conducting a pour point test under ambient conditions, without any thermal pre-treatment.

Wax Terminology• Cloud Point (= Wax Appearance Temperature)

• Temperature at which the First Wax Crystal Forms.• Difficult to Determine in an Opaque Medium.• Cooling Rate Dependant.

• Pour Point• Temperature at which Crude will No Longer Flow.• Measured in 3oC Decrements.• Generally 10-40oC Below the Cloud Point.• Strongly Dependant on Thermal History.

•ASTM Minimum Pour Point - Monotonic Cooling from 104oC.•ASTM Maximum Pour Point - Reheated to 46oC then Re-cooled.

• Inversion Point• Temperature at which All Crystals are Re-dissolved.• Some Crudes have an Inversion Point Below 46oC.

The figure below lists a number of crudes where crude density and wax content are related to their pourpoint. This table indicates that at lower wax levels, relative lower pour points are observed. At increased wax content above 10%, the pourpoint

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rapidly increases to temperatures between 20 and 30oC. No direct relation has been observed between the crude density and its pourpoint.

Pour Point - Wax Content

Crude Density Wax Content Pour Pointkg/m3 %wt (Shell) oC ASTMD97

Arabian Light 854 4 -36Kuwait 870 4 -21Basrah 855 4 -12Forties 839 4 0

Low Wax Content Oils

Cabinda 868 10 21Gamba 868 12 33Shengli 908 12 27Sarir 847 16 24Beatrice 832 16 27Bombay High 832 16 33Taching 864 20 33

High Wax Content Oils

• The Pour Point May be Independent of the Wax Content.

The following figure shows the pourpoint behaviour for crudes with different wax content. The crude samples are cooled from reservoir temperature to determine their initial cloud point. Thereafter the crude samples are reheated above their inversion temperature and cooled again to the cloud point. Finally, the samples are reheated to 46oC and re-cooled again, now to obtain the maximum cloud point. The results are listed in the table for these crudes and indicate no significant difference between minimum and maximum cloud point for low wax contents, where higher wax containing crudes show a higher maximum pourpoint.

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Pour Point Behaviour• The Pour Point is Dependant Upon the Thermal History.

Crude Wax Content Pour PointMinimum Maximum

%wt (Shell) oC ASTMD97Boscan 0 18 18Kuwait 4 -21 -21Shengli 12 18 27Gamba 12 18 33Sarir 16 9 24Beatrice 16 9 27Bombay High 16 24 33

X XXXX

X X

X XXXX

X X

X XXXX

X X

- ----

- -

Cloud Point

Min. Pour PointMax. Pour Point

Undissolved CrystalsSeed New Crystals

Inversion Point

ReservoirConditions

Temp

Mixing of crudes is sometimes applied to avoid wax deposition problems. In these cases, a crude with known wax deposition problems is mixed with a low wax crude with a lower pourpoint as shown in the figure below. As result of this mixing the wax content of the waxy stream is diluted and likely to reduce its pourpoint to lower

Mixing Crudes• Mixing Crudes with Different Pour Points Will Not Necessarily

Result in a Pour Point Between the Two.

• Example:Pour Points: Min. Max. Inversion

Crude ‘A’ 12oC & 18oC 31oCCrude ‘B’ 21oC & 54oC 65oCMixed Above 65oC 15oCMixed Below 65oC 30oC

• Tests Must Always be Carried Out, at Operating Conditions,to Determine the Actual Impact.

temperatures. Laboratory testing under actual field conditions is a requirement as there is no linear relation between wax content of a crude mix and its minimum and

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maximum pour point. In these tests the actual temperature at which the crudes are mixed is an important parameter and may have a significant impact on the resulting mix pour point. At temperatures below the inversion point, a significant higher pourpoint will be the result if compared to mixing the two crude streams above this inversion temperature. Waxy Crude Viscosity Behaviour Most pure liquids have a viscosity profile which is independent of the shear rate (i.e. display Newtonian characteristics). The formula to describe Newtonian viscosity behaviour is as follows: Newtonian fluid: t = µay If, however, solids are present which interact with each other, the viscosity profile becomes more complex. A crude which contains wax crystals will have a shear rate which depends upon

viscosity and a residual yield strength (τy ) at zero velocity. This can be understood by the formation of loose wax crystal structures which hold the liquid together. Once the main structure is broken, the fluid can start flowing. By exerting higher shear (energy) to the liquid, also the smaller crystal structures will be broken, resulting in an apparent reduction of the fluid’s viscosity. Several models are available to describe non-Newtonian fluids. The mathematical expressions representing the most common of these non-Newtonian viscosity profiles are shown below: Bingham equation:

τ = τy + µpy Herschel Buckley equation (extended Power Law equation):

τ= τy+kyn where:

τ = shear stress τy = yield strength µp = plastic viscosity µa = apparent viscosity y = shear rate k = consistency index n = flow behaviour index Fluids which have a viscosity behaviour similar to the Bingham equation, virtually Newtonian, apart from the yield strength, which has to be overcome before the fluid will start flowing. In the Herschel Buckley equation, however, in addition to the yield strength, also a further shear thinning effect at increased shear rate is apparent. By increasing the temperature of the waxy crude, where the crystals start melting, it will be clear that the viscosity behaviour will slowly return to a Newtonian pattern.

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Waxy Crude Viscosity• Wax Crystallisation Has a Major Impact on Crude Rheology.• Above the Cloud Point the Crude is Newtonian.• Below the Cloud Point the Rheology of a Waxy Crude

Becomes ‘Shear Rate Dependant with a Yield Strength’.• Generally Waxy Crude Rheology can be Described with the

Herschel Buckley equation.

τ = τy + kyn

τ = shear stress, τy = yield strength, y = shear ratek = consistency index, n = flow behaviour index

• Waxy Crudes Become Increasingly More Thixotropic withFurther Reductions in Temperatures.

Crude RheologyCrude Rheology

0102030405060708090

100

0 200 400 600

Shear rate (sec-1)

Visc

osity

(Mpa

s)

Wax Prediction Over the years a number of wax prediction software tools have been developed to assist, the engineer and the operator in the design and optimal operation of the production facilities with minimal negative impact of the waxy nature of the crude to be produced and processed. Like for all other software prediction tools, the accuracy of the input data are of paramount importance in obtaining reliable prediction results. These data are collected by conducting laboratory tests under as much as possible actual field conditions on fresh crude samples. Proper sampling and analysis is important; two laboratories capable of conducting proper sampling and analysis are

52


Core Laboratories, with laboratories in all major oil production regions, and Oil field Chemical Technology (OCT), which is located in Aberdeen. The first prediction model, “Waxline” , used mainly by process engineers, is a relatively simple software tool, which can predict temperature and pressure drop for waxy crude flow in a pipe line. It is part of the Engineering department Engineering Office System (EOS) software package. A second model developed by Shell Oil is called “Waxdep”, which in addition to Waxline can also predict the pipeline “restart” pressure.

Crude Shear StressCrude Shear Stress

Restart measurement after shut in

0

2

4

6

8

10

0 10 20 30

Time (min)

Line

pre

ssur

e (p

si)

Build up of Wax

The data required as input for these models include the isobaric temperature profile of the crude (at operating pressure). In particular Waxdep also needs test-loop data on wax build-up as function of shear as input to predict the restart pressure for a particular production system. This test loop was build by Oil field Production Analyst (OPA), but is now also used by Nowsco. A third model, “ParaSim”, recently developed by Atomic Energy Association (AEA)., can be used for the prediction of wax deposition in multi-phase lines.

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Wax Prediction

Software Packages: • ‘WAXLINE’ Predicts Temperature and Pressure Drops for Waxy Crude Flow in a Pipeline

• ‘WAXDEP’ (ShellOil)

Can also calculate Pipeline Restart Pressure

Data required: Isobaric Temperature Profile (at Operating Pressure) Testloop data on Wax build-up as function of Shear

Laboratories: Corelab and Oilfield Production Analyst (OPA)

• ‘ParaSim’ from AEA for Multi-Phase Lines

Apart from the above models, use is made of other models and techniques such as Compack and Wellwax, to predict wax deposition inside the well. Compack is a thermodynamic model which uses compositional data to fit equations of state and validate predicted versus actual cloud point. The objective is to predict the well temperature for a wax deposition free operation. For Wellwax, High Temperature Gas Chromatography is used for wax samples extracted from core samples.

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The importance of fresh, live crude samples, is demonstrated in the figure below. It compares the wax appearance temperature of “dead” crude with that of a fresh “live” crude sample. In this case a difference of some 5oC was observed in WAT between the two crude samples (data from mtg. on asphaltenes and wax between Shell Oil and Shell Expro 10-11 June 1997).

LABORATORY MEASUREMENTSWax Appearance

Filte

r pre

ssur

e di

ffere

ntia

l / p

si

Crude temperature /C

Pressurised Crude Samples

02468

10121416

0 10 20 30 40

Live CrudeDead Crude

Wax appearance

When the temperature at the wall of a pipeline is below the cloud point of the crude, wax deposition is likely. A wax layer of increasing thickness, increasing the thermal insulation, will form, until an equilibrium situation will occur. In the equilibrium situation, the rate of erosion of wax as result of shear forces is equal to the deposition rate. In this situation the wall thickness may be reduced considerably. This in turn will reduce the pipe capacity and increase the energy required for pumping.

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0

2

4

6

0 100 200 300 400

Wall Shear rate sec-1

Wax

dep

ositi

on (m

l/litr

e cr

ude)

Wax DepositionMeasured on Live Crude

ApproximateWax

shear strength

LABORATORY MEASUREMENTS

Wax Inhibition Prevention of wax deposition by taking measures is always preferred to tackling the problems after wax has deposited in the production system. Options to design out wax problems by inhibition include the following: • Dilution of the wax content • Operating within optimal conditions • Chemical additives • Magnets? Dilution of the wax content Dilution of the wax content can be conducted in varies ways. One method is by blending the waxy crude with another crude stream with a higher cloud point. Proper sampling and laboratory testing has to be carried out to ensure the mixture to be non-waxing under actual operating conditions. Mixing the crude with solvents such as naphtha or kerosene also has been used in the past. This method requiring large volumes of the solvent is expensive and logistically unattractive.. Sea water has also been used for diluting the wax content and to create an oil in water emulsion. The effects are a significant lower fluid viscosity and due to the system being water wet, no wax deposition. The disadvantages, however, are that the large amount of water has to be removed, biocides and corrosion inhibitors have

56


Wax Inhibition• Inhibition.• Dilution of the Wax Content.• Operate Within Optimal Conditions.

• Keep Temperature Above Cloud Point.• Induce Turbulence to Erode Pipe Wall Deposits.

• Chemical Additives.• Shell’s SWIM (Shell Wax Interaction Modifier).

• Generally Used to Reduce the Pour Point.• Shell SWIM 11-T Can Reduce Wax Deposition for Some Crudes.

• Must be Thoroughly Tested Before Application.• Must be Added to the Crude Stream Before It Cools Below Its Cloud Point.• Shell SWIM Will Not Remove Already Deposited Wax.

• Magnets ?

to be added to control corrosion, and more difficult dehydration of the emulsified crude. It is also important to realise that by mixing the crude with sea water, the temperature of this mix drops resulting in wax depositing inside the oil droplets. Operating within optimal limits Two options are available to control wax deposition in the production system which are: • keeping the temperature above the cloud point of the crude • using turbulence to avoid build up of wax on the pipe walls • coating of pipe walls Temperature above the cloud point This can be achieved in a number of ways including insulation of pipelines or tubing, or applying heat. Where insulation would be sufficient to prevent deposition, this should be the preferred option. Also the use of heat exchange systems where heat is generated somewhere in the production system could be an attractive method to avoid cooling of the pipe wall below the crude’s cloud point. The second option of using turbulence can also be applied to avoid wax building up in the system. The disadvantages of this technique include the following: • Initial wax deposition will always occur along the pipe wall and after for instance a

shut down, severe start up problems may be experienced including a total blocked pipe line.

• To create turbulence in a system, extra pump pressure may be required costing additional energy.

57


• Turbulence in a system of oil and water, may cause a destabilisation of the dehydration system and cause stable emulsions.

Coating of pipe walls Coating of tubing down hole or pipe lines at surface, is sometimes applied to minimise wax build up. The principle thought behind this is that by smoothing the pipe wall, wax crystals have more difficulty to adhere themselves, thereby delaying a wax layer to build up. Chemical additives Like with the use of all other chemicals, using wax inhibitors, should be the last resort in combating wax drop out in the production system. An example of these products is Shell’s “SWIM” which is the abbreviation for Shell Wax Interaction Modifier. The product is generally used to reduce the pour point of a crude system. It has been proved to reduce wax deposition for some crudes, but is not the solution for every waxy crude stream. Therefore, before applying any chemical additive to prevent wax, a thorough testing programme is required to test its (cost)effectiveness and the dosing level of the product. It is important to realise that Shell SWIM will not remove any wax already deposited. The figure below shows how the chemical interacts with wax molecules, preventing unlimited crystal growth and by smoothing the molecular structure such to minimise adherence to the pipe wall. The actual temperature for the onset of wax crystals is not altered, only the growth is affected and the crude viscosity will not increase dramatically.

Wax Modifier Action

PipeWall

Cool Cool

PipeWall

Cool Cool+

• Normal Crystal Growth• Crystals Form Network.• Increase Viscosity• Adhere to Pipe Wall

• Shell Wax Interaction Modifier

• Modified Growth• Crystals Isolated.• Pass Through System

Magnets

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Magnets have been claimed many times in literature, to inhibit the growth of wax crystals. However, scientific proof or a clear definition of how it works has not been given as yet, and often initial promising test results could not be duplicated. Based on this, it is very doubtful whether magnets have a measurable effect on wax deposition. Wax Removal If, in spite of all prediction, prevention and mitigation actions, wax still is depositing on pipe walls or in tanks/vessels, remedial actions have to be taken to remove this material before it causes too large operational problems. A number of techniques/methods are available for the removal of wax from the well bore, pipe lines, etc. These techniques/methods include the following: • Mechanical removal by scraping or pigging • Thermal removal via heating with stream or electrical • Dilution by dissolving in (hot) oil • Chemical dissolvers Mechanical Removal Mechanical removal by scraping is often applied to remove wax from down hole tubing. Even when applying inhibitors like SWIM, it can still be necessary to run scrapers down hole at regular intervals. Often economics related to crude deferral, scraping frequency and scraping is used to find the optimal approach. Pigging is often applied in flow and pipe lines. The selection of the most suitable type of pig is important to remove as much as possible wax without running the chance of getting the line blocked by a stuck pig. Thermal removal Heating is also regularly applied to remove wax deposition in the tubing. Mobile steam generation is used, while also electrical heating can be applied. The importance of this technique is that its frequency is tuned such that it is most cost effective. An alternative way of thermal removal is by utilising in situ heat generating chemicals like NH4NO3 with NaNO2 which forms when mixed in the presence of water, NaNO3+ Heat. Placement problems are the main reason why this technique has not been used recently. Dilution Dilution with hot oil can also be applied to resolve the crystallised wax from the tubing, by heating the deposit well over its cloud point. As in this case a liquid is injected via the wellhead into the well bore, extreme care has to be taken that this wax enriched hot mixture does not enter the formation to re-solidify. If this would occur, a relatively simple problem would be made worse by impairing the well, requiring stimulation or hydraulic fracturing to start production again. Chemical solvents and surfactants

59


Chemicals have been developed which are claimed to dissolve wax deposits. In practice, however, these products do not perform as claimed. Also, often large volumes of these (expensive) products and long soak times are required, resulting in extra production deferral. Testing is always required before deciding on actual treatment with these products.

Wax Removal• Removal.• Mechanical.

• Scraping.• Pigging.

• Thermal.• Steam/Electrical Heating.

• Dilution.• (Hot) Oil Flushing.

• Chemicals.• Mutual Solvents and Surfactants.• Effectiveness is Dubious and Must be Tested Beforehand.

• Shell SWIM Will Not Remove Crystalline Wax.Reference:EP-64010 General Aspects of the Transport of High Pour Point Waxy Crude Through Pipelines.

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New Developments Wax problems in a number of Operating Units such as Shell Gabon, result in very high chemical expenses, still combined with loss of production. These costs and production losses warrant extra research in the development of better tools/products. For this reason, and as part of the initiative by RTS in Rijswijk to improve performance via the Installation of “Jewel” research projects, the idea of “designer” bugs was developed. These designer bugs, in the case of wax deposition should be bio-engineered such that they would decompose-, or eat the wax crystals thereby avoiding serious wax deposition and even remove wax layers already formed. One of such products recently developed is Para-bac which is claimed to perform as described above. This product is currently being evaluated by Thornton Research Centre for its effectiveness. As these bacteria prefer Oxygen free environments, a possible application area may be the under water (anaerobic) storage cells in Draugen, which crude has a WAT of 31 oC. Apart from using these products in storage tanks, etc. their main use will be to prevent wax growth in tubing and flow lines. Therefore these products could be applied by annular injection, or alternatively, by squeeze injection into the formation.

• Designer Bugs

Wax: New Developments

Para-Bac

Can also Remove Wax

Claims: Promotes Wax Degradation

Application Options:• Annular Injection• Reservoir Squeeze

Product evaluation by Thornton

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2.3. Asphaltenes Asphaltenes are usually arbitrarily defined as that fraction of a crude oil which is soluble in toluene, but not in n-heptane. As such the asphaltenes embraces a complex mixture of components. They comprise a peptised dispersion of high and lower molecular weight aromatic molecules (molecular weight usually between 1,000 and 10,000) which are polar (and as such usually contain hetero-atoms such as

Asphaltenes• Asphaltenes are a Complex Natural Component of Crudes.

• They are the Constituents of Crude that are Not Soluble in Heptane/Pentane.

• They Exist as Peptised Micelles Dispersed in the Crude Oil.• Resins and Aromatics Peptise (Disperse) the Micelles in the Aliphatic Oil.• Destabilising the Dispersants will Result in Asphaltene Flocculation.• Dispersion is Pressure Sensitive; Temperature has a Smaller Impact.

Central Part ofthe Asphaltenes

High Molecular Weight& Aromatic Compounds

Low Molecular WeightAromatic Compounds

Mixed AromaticNapthenic Compounds

Mixed NapthenicAliphatic Compounds

PredominantlyAliphatic Compounds

nitrogen, sulphur, etc., for an example, see the figure on the next page ). Once destabilised, these molecules have a tendency to aggregate, a property which produces their insolubility in n-alkanes. However, in crude oil systems they are normally associated with resins, which are molecules similar in nature to the asphaltenes, but they are less polar and have strong solubility in the n-alkanes. The resin’s association with the asphaltenes reduces the aggregation and thus enables the solubility of the asphaltenes. Research into the development of a model to predict the behaviour of asphaltenes in crudes has followed two separate paths. One school of thought considers the asphaltenes as particles present in the crude as a colloidal suspension. The colloids exist as micelles (diameter 3-40 nm ), which are stabilised by large molecules (the resins) adsorbed on their surface. Removal of the resin leads to the deposition of the asphaltene. The theory implies an irreversibility in the process. Under this model the phase behaviour is described by colloidal science techniques, e.g. electro-kinetics and adsorption.

62


Hirschberg has approached the problem by looking at asphaltenes as molecules in the liquid phase, which may or may not form a solid phase, manifested as a deposit or floc, depending on the thermodynamics of the situation. The key difference this model has with the colloidal theory is that it implies that a reversible phase change occurs in the deposition of asphaltenes.

S

CH3S

CH3

CH3

CH3

CH3

N

SN

CH3CH3

CH3

Asphaltene Molecule

The molecular model implies that kinetic effects are extremely important in asphaltene deposition. This is clear because deposition is usually seen to be extremely fast whereas re-dissolution is extremely slow (weeks?). Deposits, once formed, are extremely difficult to remove, and indeed re-dissolution may prove totally impossible. This latter point appears to be better explained by the colloidal theory but overall the evidence either way is inconclusive. The models however are not necessarily mutually exclusive and it may be that both models present elements of the truth.

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Asphaltene concentrations in crude oils vary greatly - from virtual absence up to 50% in some heavy oils. Deposition of these compounds is a problem which has plagued the industry world wide for a great number of years, though occurrence of such problems has not always been seen to be a direct function of the asphaltene content of the crudes in question. In contrast to the conditions which induce wax deposition, temperature is found to have a relatively small effect on asphaltene solubility; pressure and crude composition are much more critical factors.

Major Solubility Fractions of Crude Oil

The occurrence of asphaltene deposition problems in oil fields world wide is found to bear little relation to the asphaltene content of the crudes in question. Crudes containing very high concentrations of asphaltenes may produce trouble free for years, whilst other crudes with asphaltene content as low as 0.2% can give deposition problems from day one. For example Venezuela's Boscan field, whose crude has a 17.2% asphaltene content, was able to produce with no initial deposition. In contrast, the nearby Mata-Acema crudes, which contained from 0.4-9.8% asphaltenes, had a history of deposition problems. In laboratory tests the Boscan crude was shown to be resistant to electro-deposition of asphaltenes, whereas the Mata-Acema crude did show deposition under the same conditions. However, addition of Boscan crude to the Mata-Acema crude resulted in the prevention of deposition in the Mata-Acema crude. It was clear, therefore. that the Boscan crude contained some agent which was able to work against asphaltene deposition. This agent turns out to be the resins. Thus, the asphaltene content of the crude is seen to play a lesser role in the flocculation process than the amount of peptizing agents present, i.e. the resins.

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There is a theory that the two metals nickel and vanadium, which are found to be present in significant concentrations in many crude oils, may also be somehow implicated in the mechanism for asphaltene deposition. These elements are found to be present in asphaltene deposits in much greater concentrations than they are in the crude itself. They do have a tendency to form organometallic complexes with the asphaltene molecules and will tend to impart electrical charge to the molecule; this may have a significant impact on the solubility of the asphaltene in the main body of the crude and hence influence its deposition. Destabilisation and thus asphaltene drop out for a particular crude can occur by a drop in pressure above the bubble point. This pressure drop causes an expansion of the oil leading to oversaturation of the crude with asphaltenes. Temperature plays only a minor role in the deposition of asphaltenes. By mixing of crudes with totally different chemical composition, and the presence of asphaltenes, may cause oversaturation of asphaltenes in the mix and, resultingly, in deposition. Highly compressible oil, a high undersaturation in a gas reservoir and a low asphaltene content, are all possible forebodes for the likeliness of asphaltene deposition tendency.

Causes of Asphaltene Dropout

• Drop in Pressure above Bubble Point

•Some Dependence Upon Temperature

•Mixing Incompatible Crudes or Condensates

Beware of: Light Oil (Compressible) High Undersaturation in (Gas) Reservoir Low Asphaltene Content (< 2%)

As described earlier, deposition of asphaltenes can occur rapidly, in contrary to its dissolution, which, if at all possible, is very slow. Once formed, the deposition of asphaltenes in the near well bore region (e.g. perforation and inflow area, will severely impair the inflow of hydrocarbons into the well. The use of solvents, dispersants, or even hydraulic fracturing, may become necessary to improve inflow.

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Like for wax deposits, asphaltene deposits in the production tubing will restrict inflow and cause operational and safety hazards to operating equipment such as gas lift, and safety valves . In surface facilities, deposit particles due to their polar nature can form the nuclei for emulsion droplets, thereby stabilising these emulsions. Further, plugging of oil/gas processing equipment can result in deterioration of the treatment processes, or even result in safety hazards.

Impact of Asphaltene Deposition• Slowly Reversible Process

• Reservoir• Near Well Bore Drop Out of Asphaltene Flocs Can Severely Impair Inflow

Performance.

• Tubing• Deposits can Restrict Tubing Diameter Reducing Outflow Performance.• Deposits can Foul Operating Equipment; GLV’s, SSSV’s and such.

• Surface Facilities• Can Stabilise Emulsions.• Plugging First Stage Gas Separator; can lead to Pressure Build-up.• Plugging Compressor Inlets; leading to Starving.• Solids Disposal Problem

The figure below thus shows the asphaltene solubility versus applied pressure for a given temperature and GOR. The shape of the plot is generally similar for each type of crude oil, although the asphaltene content will naturally vary for each crude. From the Figure, it can be seen that above the bubble point (Pb), asphaltene solubility decreases with decreasing pressure. This effect is due to the expansion of the oil (compressibility). At a certain critical pressure (Pc, the crude becomes saturated with asphaltenes. Below this pressure, asphaltene: will precipitate until the bubble point Pb is reached, at which point there will be minimum solubility. As the pressure is reduced further below Pb, more of the asphaltenes will go back into solution, the unfavourable effect of compressibility being increasingly compensated for by degassing. However, as stated above, the rate at which re-dissolution occurs may be slow relative to crude residence time in the system. However, for deposits to be formed, the following aspects are of importance: • The asphaltene peptised micelle dispersion must be destabilised to allow

flocculation • The precipitation kinetics should be fast enough to form the deposits in time

66


• Once the flocs are being formed, they should grow into agglomerates to cause plugging.

• Due to the normally soft nature of the deposits and easy erosion, a high velocity in the production system would prevent larger particles to be formed.

• The build up of deposits can only occur when the wetting conditions are favourable for the particles to adhere themselves to the metal walls.

• Asphaltene Dispersion is Pressure Dependant

• Asphaltene Dispersion Must Be Destabilised.• Precipitation Kinetics Must Be Favourable.• Crystals Must Agglomerate.• Velocity of Flowing Stream Must Allow Deposition.• Wetting Conditions Must Allow Adsorption.

Asphaltene Deposition - Production

Dispersion Line

Pb Pc Pr

Asphaltene ContentOf Reservoir Crude

AsphalteneContent

(%w)

Pressure

Precipitated

Dissolved

Dispersed Pb = Bubble Point

Pc = Critical Pressure

Pb = Reservoir Pressure

Asphaltene Deposition - Well Activities Destabilisation of asphaltene micelles can be caused by a number of well activities including: High shear pumps. The asphaltene-resin relationship is seen to be critical to the solubility of asphaltenes. In high shear environments, the micellar structure of the dispersion becomes distorted, whereby the resins can become separated from the asphaltene molecules. Once the destabilised crude enters a low energy zone in the production system asphaltene particles can start dropping out of solution Well Stimulation and EOR Also when applying stimulation, the balance between resin and asphaltene is likely to become distorted and have an impact on asphaltene deposition. The same is also valid for injection of carbon dioxide, water, and steam flooding programmes. They all can initiate asphaltene deposition where no problems had been previously encountered.

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When well stimulation is being applied in a reservoir where asphaltenes are likely to become destabilised, deposition thereof can be prevented by separating the crude from the stimulation chemicals by using a pre-flush of an asphaltene compatible fluid.

Asphaltene Deposition - Well Activities• Asphaltene Micelles Can be Destabilised by:• Shear

• High Shear Pumps Which Have a Lower Pressure Region Downstream.

• Well Stimulation• Changes in pH.• Aromatic Solvents.• Surfactants.

• EOR• CO2 Flooding

•Change the pH and Cause Localised Joules-Thompson Cooling.• Steam Flooding

•Localised Temperature and Pressure Change.

• Prevention• Isolate the Natural Crude from the Treatment with a Pre-flush.

For the prediction of asphaltene deposition, a PVT sample is required of the crude taken under reservoir conditions (above the bubble point). Apart form measuring the

Prediction• Asphaltene Dispersion versus Pressure and Temperature

can be Profiled in the Lab.• Field Test Unit Available Which Detects Asphaltene Dropout.

• Also can Determine Wax Crystallisation Properties and Crude Viscosities.

PUMP A PUMP B

Pressure sensor

Filter unit

Stirred piston reservoir

Temperaturecontrol

Datacapture

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asphaltene content, In a PVT laboratory a pressure and temperature profile can be determined by slowly changing the pressure in a PVT chamber with a see through window where the transparency of the sample can be measured. This test has to be repeated at various temperatures before a full profile can be obtained. Another method is to make use of a special asphaltene field test unit. A crude sample is transferred (at reservoir pressure) in the test unit shown below and pumped though a filter unit equipped with a pressure sensor. The temperature is kept constant while at slowly decreasing pressure. When the pressure has reached where the asphaltene solubility is exceeded, particles will start dropping out of the crude and slowly plug the filter. This plugging will result in an increase in the pressure differential over the filter which can be monitored against the absolute test pressure (see the figure below).

Asphaltene Detection

PrecipitateFormation

Test Direction

Pressure - psi

Diff

eren

tial P

ress

ure

0123456789

10

1500 2000 2500 3000 3500 4000

The same equipment as used to test a crude for its asphaltene deposition tendency, can also be used for wax prediction. In this case, however, the temperature is the variable and the pressure kept constant.

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Wax Detection

WaxAppearance

Test Direction

Temperature - C

Diff

eren

tial P

ress

ure

02468

10121416

15 20 25 30 35 40

Prevention The best option to prevent deposition of asphaltenes, is to operate outside the precipitation window as shown below. In practice, however, this is often not possible. The other options to prevent deposition of asphaltene particles, are mainly based on either preventing the crystals to grow by high erosion velocities of crystal agglomeration inhibition, or by merely avoiding the particles to adhere to the metal surface of the production tubing or facilities. Both for changing the wettability and inhibiting crystal growth, mostly chemicals (dispersants or surfactants) are being used. Over the suitability/effectiveness of (electro) magnets in the production system, no clear proof has been found of these products to be effective.

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• Operate Outside of the Precipitation Window

• Use High Flow Velocities to Erode Deposits.• Change Wetting Conditions to Minimise Adsorption.• Inhibit Crystal Agglomeration

• Chemicals• Electromagnetism

Prevention

Dispersion Line

Pb Pc Pr

Asphaltene ContentOf Reservoir Crude

AsphalteneContent

(%w)

Pressure

Precipitated

DispersedDispersed

Options for Control When operating under asphaltene depositing conditions, control options have to be available to prevent plugging of formation, tubing , valves or other production systems. Two (chemical) options are available; solvent washes and inhibitor injection. Both methods are often not 100% effective and laboratory testing is required. Even when not being 100% effective, in a number of cases they can be used economically to manage asphaltene deposition problems. Both types of chemicals have number of constraints as listed in the figure below. A number of product types for both solvents and dispersants are listed in the last figure on this topic.

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Options for Control

Options:• Solvent Washes to Remove Deposits• Continuous Inhibitor (Dispersant) Injection• Other (e.g. Magnetics)

Constraints:• Solvent Compatibility with Injection Lines• Chem. Inj. via Waswater must Remain in Solution or Stable Dispersion.• Stability to High Temperatures•Compatible with Other Chemicals

Asphaltene Solvents/Dispersants

Solvents:• Most Contain Aromatics (= aquatic toxicity)• New Products under Investigation. e.g. Glycol Ether, Esters Amino-ethanols, etc

Dispersants:• Mainly Surfactant Type Products (Some products tested were found to be able to eliminate formation of asphaltenic flocs.)

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3. Drag Reducers Introduction Vast amounts of crude oil are transported in pipelines all over the world. Due to new discoveries being evacuated along with existing production, and due to improved production techniques for existing fields, several pipelines appear to have insufficient capacity for current needs and have become limiting factors for production rates. Increasing capacity is therefore a key factor for many operations. Drag reducers are high molecular weight polymeric chemicals which are successfully applied in several parts of the world to solve this problem. The best known example of drag reduction is the trans-Alaska pipeline. The capacity of this 1300 km long 48” diameter pipe was increased from 188,000 m3/day to 220,000 m3/day (17% increase) by the addition of 10 gram of polymer per m3 of crude. Drag reducers are also used in hydraulic fracturing where water soluble compounds are added to the fracture fluid to reduce the horse power requirements. Attention must be paid to the solubility of the products used, their compatibility with other chemicals, in particular demulsifiers and their sensitivity to shear degradation.

Drag ReductionDrag Reduction

• Improve Pipeline Capacity• Reduce Horse Power Requirements for Pumping• Shear Sensitive• Expensive• Compatibility with Demulsifiers

Pro’s and Con’s:

Definition:Long chain chemicals which improve the flow of hydrocarbons in pipe/flow lines operating under turbulent flow conditions

Definition of Drag reduction Drag reduction can be defined as “the increase in pumpability caused by the addition of a drag reducer to the crude stream”. For a given flow rate, in a given pipe, this definition is expressed by the following formula:

%dr = (dP - dP1) x 100/dP where;

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%dr = percent drag reduction dP = pressure drop of untreated fluid dP1 = pressure drop of fluid with additive This formula represents the actual performance of a drag reducer. In most practical applications however, the improved pumpability of a fluid is used to increase the capacity of a pipeline rather than to reduce the pumping costs. A formula which represents the increased throughput potential is therefore more applicable. An empirical formula has been proposed which defines the percentage throughput increase (5Ti) as follows:

%Ti = [{0.01(100- %dr)}-0.55-1] x 100 From this formula it can be calculated that a 20% reduction in drag represents a throughput increase of 13%.

Drag ReductionDrag Reduction

Formula’s:% Drag reduction (%dr) = (dP - dP1) x 100 / dP

dP = pressure drop untreated fluiddP1= pressure drop treated fluid

% Throughput increase (%Ti) = [{0.01(100 - %dr)}^-0.55 -1] x 100

Mechanism: Not fully understood but believed to result fromaligning flow in the direction of the principle strain rate inpipe lines under turbulent flow conditions

The exact mechanism of drag reduction is not yet fully understood. However, drag reduction effects seem to depend on the stretching of individual molecules by high strain rates in the flow. As the long drag reducer molecules are elongated they align in the direction of the principle strain rate. It is suggested that “threads” occur in the flow, inhibiting bursts and sweeps in the wall-layer flow, thereby reducing friction under turbulent flow conditions. This explanation is consistent with the fact that the effective application of drag reducers is restricted to turbulent flow conditions only. Drag reducing Chemicals

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Drag reducers are long chain polymeric materials which should have the following properties: • be readily soluble in oil • have a high molecular weight • be inert to chemical (compositional) changes within the crude • be compatible with other additives (e.g. demulsifiers) The best drag reducers are essentially linear, high molecular weight compounds with a maximum length. Several types of such chemical are commercially available and include: • polymetacrylates • polydimethylsiloxanes • polybutadienes • polyisobutylenes • polyisoprene Polyisoprene, a synthetic rubber with a molecular structure almost identical to natural rubber, can be supplied as solids crumbs, suspended in a stable aqueous solution. One advantage of this delivery method is the high concentration of active material in the slurry as most drag reducers are supplied as a 1% solution. A further advantage of the above product is that solid particles suffer less from shear degradation. Shearing can induce break down of polymer chain, an effect which will reduce the effectiveness of the drag reducer. For this reason drag reducers are where possible injected downstream of booster pumps

Drag Reducer ChemicalsDrag Reducer ChemicalsProperties:• be readily soluble in oil• have a high molecular weight• be inert to chemical changes within the crude• be compatible with other chemicals (e.g. demulsifiers)

Commercially available products• poly-metacrylates• poly-dimethylsiloxanes• poly-butadienes• poly-isobutylenes• poly-isoprene

Shell have developed a method whereby solid polymers are injected into the pipeline. These polymers dissolve slowly, thus ensuring that the required amount of

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drag reducer is available along the entire length of the pipeline. Additionally, solid polymer is more likely to pass through pumps, etc. and so continue to dissolve and provide drag reduction downstream. Drag reducers are soluble in oil but not in water. For this reason the effectiveness of these products is found to decrease with increasing water cut. Due to their insolubility in water, sometimes “slimy” products are observed in dehydration tanks. These slimes cause water in oil emulsions to become stabilised resulting in a deterioration of the dehydration process. Testing of compatibility of drag reducers with the demulsifier used in the system is therefore an important requirement.

Drag Reducer ChemicalsDrag Reducer ChemicalsDrag reducers are oil soluble only and their effectivenessdecreases with increased water cut

Types of Products:• solutions with concentrations from 0.5 - 10%• solids which must be dissolved onsite• solids which are injected directly (with some water)

Beware:• Many products break down under high shear conditions and

lose their effectiveness• Often slimey products enter the dehydration facilities and

disturb the oil water separation Economics of drag reducers The economic viability of using drag reducers depend on either or both of the following:

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• reduced energy consumption for pumping • increased pipeline capacity The benefits to be derived from these two factors by the use of the drag reducer must be greater than the cost of the drag reducer itself. These costs also have to be compared with other capacity improvement options such as laying a further pipeline for instance. Although laying a pipeline involves a larger up front investment, especially if production restrains are severe, this option is likely to be more cost effective in the long run. Drag reducers therefore tend to be economically viable where such options are not realistic, or where throughput restrictions are only temporary

Drag ReductionDrag ReductionEconomics depends on:• Reduced energy consumption for pumping• Increade pipeline capacity

Compare with laying (further) pipelineEconomically viable for temporary throughput restrictions

Foaming

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Foaming is the phenomena where due to the low surface tension between liquids and air, and the presence of sufficient mixing energy, the air and liquid become a stabilised mixture called foam. Foam can also be called a gas liquid emulsion where, in comparison with oil/water emulsions, both the gas external as the water external emulsion can exist. The reduction of the surface tension is often caused by the presence of natural surfactants in these liquids or the use of certain process chemicals (e.g. detergents for cleaning, stimulation additives, etc.) Foaming can cause a number of operational problems including the following: • The carry-over of liquids into the gas phase in separators resulting in a less

efficient gas liquid separation process. This is often the case with a liquid in gas foam where gas is the continuous phase.

• Disturbances in separation processes such as dehydration, deoiling, filtration and other water treatment processes such as de-aeration using vacuum de-aerators, etc.

• Pump cavitation caused by the entrainment of gas in the liquid phase • Some tight gas in liquid foams can significantly increase the apparent viscosity of

the liquid phase requiring higher pumping energy. As foaming can cause all the above negative effects, the use of defoamers is often the only option to remediate foaming. For aqueous foams often polyglycols can be used which work on weakening the bubble film by also moving to the water gas interface thereby inactivating the surfactant. Very often a very low concentration of defoamers is required to stop the foaming to occur. The siloxanes is another group of defoamers which can be used to stop foaming. As these products have a low water solubility, they are not recommended to be used for the treatment of injection water as this may result in well impairment. A third group of defoamers are the hydrophobic (=water hating) surfactants which counteract the hydrophilic (=water loving) surfactant(compare with demulsifiers which work on weakening the water droplet film).

Foaming

Occurs in Liquids with Low Surface Tension and Exposedto Turbulence ( e.g. De-airator Towers, O/W, G/O Separators)

Results in:• Liquid Carry-Over and Lower Efficiency Operations• Separation/ Treatment Process Disturbances• Pump Cavitation (Gas Entrainment in Liquid Phase)

Defoamers:• Polyglycols (work on weakening bubble film)• Siloxanes (less suitable in water due to low solubility)• Hydrophobic Surfactants

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4. Inorganic Scales

Hydrocarbon (Water) Processing Deposits• Hydrocarbon Based Deposits• Hydrates

Crystalline Water and Hydrocarbon Compounds.• Wax

Parafinic, Alkane, Component of Crude Oils.• Asphaltenes

Natural Compounds Dispersed in Crude Oils.

• Aqueous Based Deposits• Scale

Inorganic Chemical Deposits.

Water is an excellent solvent for many chemical species including salts. The concentration at which the salts are present in the water, varies significantly from place to place. These salts are dissolved in the water in the form of ions. The positive charged ions are called “cations” while the negatively charged ions are called “anions”. Some examples are: Cations: Na+, Ca2+, Mg2+, Ba2+, Sr2+, Fe3+, etc. Anions: Cl-, NO3-, HCO3-, SO42-, CO32-, PO43- The combination of cations with anions results in the formation of salts. Some salts such as Sodium Chloride (NaCl) have a high solubility which means that large quantities can be dissolved in water before saturation is reached and NaCl precipitation takes place. Other salts such as Barium Sulphate (BaSO4) have a very low solubility of a few milligram per litre only. In an aquifer the salt content of the water is in equilibrium with the salts present in the reservoir rock at reservoir pressure and temperature. In a carbonate reservoir, the Calcium and the Carbonate concentration in the water phase are at their saturation point. By changing pressure, temperature, or another variable, the solubility of a certain salt in the water can be exceeded resulting in precipitation (often in the form of salt crystals) of a certain amount of that salt until saturation is reached for this new situation.

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4.1 Oil Field Water Scales

Scale• Oilfield Waters Contain a Variety of Dissolved Salts.

• Seawater Contains SO42-.• Formation Water Often Contain HCO3-, Divalent and Trivalent Cations.

Ion Concentration (mg/l)Brent Nigeria Marmul Sirikit Champion Venezuela

Sodium 1640 8400Calcium 59 100Magnesium 10 70BariumStrontiumChloride 2167 11000Sulphate 10 50Bicarbonate 841 4000pH (@ 25ºC) 7.6 8.1

• Salts May be Precipitated as Scale by:• Pressure and Temperature Changes.• Ionic Balance and pH Changes.• Mixing of Incompatible Waters.

Range of Water Quality ParametersRange of Water Quality Parameters

P a r a m e t e r s S e a w a t e r F o r m a t i o n W a t e rD i s s o l v e d S o l i d s m g / lT o t a l D i s s o l v e d S o l i d s 3 0 , 0 0 0 - 4 1 , 0 0 0 1 0 0 - 3 3 6 , 0 0 0S o d i u m 1 1 , 0 0 0 - 1 6 , 0 0 0 4 0 - 1 3 5 , 0 0 0P o t a s s i u m 3 0 0 - 5 0 0 0 - 1 , 0 0 0C a l c i u m 3 0 0 - 5 0 0 0 - 5 0 , 0 0 0M a g n e s i u m 1 , 1 0 0 - 1 , 5 0 0 0 - 5 , 0 0 0B a r i u m 0 , 1 - 0 , 5 0 - 2 , 0 0 0S t r o n t i u m 6 - 8 0 - 2 , 0 0 0I r o n 0 0 - 1 0 0C h l o r i d e 1 7 , 0 0 0 - 2 4 , 0 0 0 6 0 - 2 0 0 , 0 0 0S u l p h a t e 2 , 4 0 0 - 3 , 2 0 0 0 - 5 0 , 0 0 0C a r b o n a t e 0 0 - 1 , 0 0 0B i c a r b o n a t e 1 2 0 - 1 5 0 1 0 0 - 3 , 0 0 0A c e t a t e 0 0 - 1 , 5 0 0P r o p i o n a t e 0 0 - 3 0 0B u t y r a t e 0 0 - 5 0

S p e c i f i c G r a v i t y 1 , 0 2 0 - 1 , 0 3 2 1 , 0 0 0 - 1 , 2 5 0D i s s o l v e d O x y g e n 6 - 1 1 0C a r b o n D i o x i d e 0 0 - 2 , 0 0 0H y d r o g e n S u l p h i d e 0 0 - 1 , 0 0 0p H 8 , 0 - 8 , 4 4 - 1 0T e m p e r a t u r e 0 - 3 0 2 0 - 1 5 0T o t a l S u s p e n d e d S o l i d s 0 , 1 - 2 0 1 - 1 0 0

This precipitation of excess salt from a solution is called scaling. The importance of this for the oil industry is that when scaling occurs in the production system, it may restrict flow through injection and flow lines, impair the

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formation around the well bore, etc. Galvanic Cell corrosion can result from scaling, when for instance the tubing is covered with scale but at some places the scale came off. The result is that the bare parts of the tubing are (via the conductive water) in electric contact with other metal parts in the system whereby an electric current will remove iron from the bare tubing parts resulting in pitting corrosion. Apart from loss of production and damage to equipment, in some cases it can also result in an HSE problem. This is the case if together with for instance Barium or Strontium scale, also minute amounts of radio active material are co-precipitated. As result the radio-active material builds up in the production facilities and cause an environmental and/or safety hazard.

Impact of Scale Crystallisation• Reservoir

• Reduces Near Wellbore Permeability; Resulting in High Skin and Lower Inflow.

• Wells• Flow Restriction Resulting in Higher Pressure Losses or Lower Throughput.• Loss of Equipment Functionality (Esp. Pumps and SSSV’s).• ‘Galvanic Cell’ Corrosion.• Restricted Well Entry.

• Flowlines and Surface Facilities• Flow Restriction Resulting in Higher Pressures or Lower Throughput.• Loss of Equipment Functionality (Esp. Pumps and Pressure Relief Valves).• ‘Galvanic Cell’ Corrosion.

• HSE• Sulphate Scales Often Contain ‘NORM’ (Naturally Occurring Radioactive

Materials) - ‘LSA’ (Low Specific Activity) Elements.• Usually Uranium and Thorium Decay Series Products.

The Viewgraph on the next page shows a number of scales which can be encountered in oil field operations. Rock salt (NaCl) can be expected to be formed when producing from an oil reservoir with very high NaCl concentrations (over 300,000 mg/l). In contrary, it can also occur when producing gas from a formation with a low NaCl content. When the gas is produced, due to the pressure drop in the tubing part of the co-produced water will evaporate in the gas thereby increasing the salt content in the water. When this continues, the salt content can eventually reach saturation point and precipitate in the tubing. A number of the scales will be discussed in more detail below.

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Inorganic Oilfield Scales Rocksalt NaCl

Carbonates CaCO3FeCO3BaCO3PbCO32PbCO3.Pb(OH)2

Sulphates CaSO4 .xH2OSrSO4BaSO4PbSO4

Sulphides S8FeSxZnSPbS

Oxides etc. Fe2O3, Fe(OH) 3

Others CaF2CaSiO3Pb metal, Pb(OH)ClFe3(PO4) 2Ca5[(OH)(PO4)] etc.

Carbonate scales are the most common scales encountered in oilfield operations. Calcium is most often the Cation, but also Barium and Strontium Carbonates are possible. The figure below demonstrates the complexity of the equilibrium of the different ions playing a role. From the figure, formation of a carbonate scale can only occur above pH 4, as at this pH the first carbonate ions are formed. It is also clear that apart from the pH, also the CO2 concentration plays an important role. The CO2 content in the water is very pressure and temperature dependent.

Carbonate Scale• Carbonate Deposition is Complex and Dependent on the

Equilibrium between Bicarbonate, Carbonate, and CO2.Total Carbonate = [CO2] + [H2CO3] + [HCO3-] + [CO32-]

• Carboxylic Acids May Affect HCO3- Determination.• Volatile Fatty Acids (VFA) May Be Reactants when Titrating for Bicarbonate .• Gives a False Value Indicating a Higher than Actual Scaling Potential.

Concentration Variation of Depressured Sample

Downhole SurfaceCO2 mg/l 7660 100HCO3- mg/l 202 2850pH 4.7 6.9

Because of the Equilibrium Complexity and theLoss of Gaseous CO2, it is Not Recommendedto Use Corrections of Surface Samples toDownhole Concentrations Without CalibratingUsing an Actual Downhole Pressure Sample.

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It is very important when taking samples for analysis, that the exact CO2 content at reservoir conditions is known as well as the pH. To allow calibration for CO2, a downhole sample has to be taken and analysed. These data are of importance in the prediction of scaling. Apart from the CO2 content (influenced by pressure and temperature), an increase in pH will significantly affect the solubility of calcium carbonate by shifting the equilibrium to the right hand side. Carbonate scale deposits are acid soluble and hydrochloric acid (HCl) is often used for stimulating wells which are scaled up with calcium carbonate. Presence of large quantities of NaCl (or other dissolved solids), however, will increase the solubility of Calcium Carbonate. This is called the “No common ion effect” and is the result of increasing the ionic strength of the water solution. The Stiff and Davis formula can be used for predicting the likelihood of carbonate scale deposition. Scaling may occur when the Scaling Index is positive. The accuracy of this formula is not very high and its use should be as a first indication only.

Carbonate Scale Deposition• Carbonate Deposition is Affected by:

• Pressure Decrease (decreases partial pressure of CO2).• Temperature Increase (decreases solubility of CO2).• pH Increase (Ca2+ + CO2 + 2OH- ==> CaCO3 + H2O).• NaCl up to 20,000 ppm Increases Carbonate Solubility by ~2.5 times.

• Can be Predicted with the Stiff and Davis Stability Index• Scaling Index (S.I) = pH - (K + pCa + pAlk).

•pH = actual water pH.•K = a constant dependent upon temperature and ionic strength.•pCa = negative logarithm of calcium concentration.•pAlk = negative logarithm of total alkalinity.

Calcium Carbonate Scale

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Calcium Sulphate deposition is mainly the result of mixing of incompatible fluids. Typical is the injection of sea water with a Sulphate content of some 2000 - 3000 ppm into a Calcium containing reservoir. The calcium from the reservoir reacts with the sulphate to form calcium sulphate. There are different forms of calcium sulphate which include CaSO4.2H20 (Gypsum), the most common oilfield form at lower temperatures and CaSO4 (Anhydrite). The solubility of calcium sulphate increases to a temperature of 38oC, after which the solubility decreases. Above this temperature the anhydrite form is becoming the more dominant form and is less soluble compared to gypsum. Like all other scales, also calcium sulphate solubility increases at increased pressure. Also the presence of large quantities of dissolved salts other than calcium or sulphate, (i.e. sodium chloride etc.), positively affect the solubility of calcium sulphate. In contrary to carbonate scales, the solubility of sulphate scales is virtually pH independent. These types of scale can therefore also not be dissolved with acid.

Sulphate Scale• Sulphate Scales are Generally a result of Chemical Interaction

between Formation and Injection Fluids.Such as: Ca++ + SO4-- => CaSO4

• Solubility Decreases with Decreasing Pressure.• But not as markedly as for the Carbonate system.

• Solubility is Virtually pH Independent.• Solubility is Mildly Temperature Dependent

• Gypsum Solubility Increases with Temperature to about 40ºC & thenDecreases.

• Dissolved Na+, up to 160,000 ppm, Increases R-SO4 Solubility.• Can be Predicted with Skillman’s Method

• Solubility = 1000 [(X2 + 4K)0.5 - X]•K = Solubility product constant (a function of ionic strength and temperature)•X = Excess common ion concentration (difference between Ca2+.and SO42-)

Calcium Sulphate Scale Apart from calcium, other sulphate scales include barium and strontium. These scales have a very low solubility compared to calcium sulphate. Barium sulphate solubility at ambient temperatures and pressure is only +/- 2 mg/l. In comparison the solubility of calcium sulphate under similar conditions is +/- 2000 mg/l, while the solubility of strontium sulphate is +/- 250 mg/l. The solubility of these salts increase with increased temperatures (up to 100 oC) and pressure. Solubility is unaffected by changes in pH while increased salt content again increases solubility.

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Over the last decade, naturally occurring radioactive materials (NORM), have been found to co-precipitate together with mostly barium and strontium scales.

Barium/Strontium Sulphate Scale• Mostly Caused by Mixing of Incompatible Waters.• Compounds Have Very Low Solubility (Ba less than Sr).• Solubility Increases with Increased Temperature.

• Even so BaSO4 solubility at 90ºC is still only 4 mg/l.

• Solubility Increases with Increased Salt Content.• Solubility is Unaffected by Changes in pH.• Chemically Similar to Radium, may Co-precipitate with

Radioactive Scales.• Not Acid Soluble.

These radio-active materials with a low specific activity, can be present in the producing formation, and leach out via the produced water. Together with normal scale it can become deposited in the well bore, tubing or surface production facilities. The importance is that as the scale layers building up in the system the radio-activity level will increase and could pose health or environmental hazards. At the end of this chapter, some more details on NORM will follow.

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Barium Sulphate Scale

Courtesy of Shell Expro Iron based deposits or scales can be the result of Iron ions present in the water naturally or the result of corrosion or Sulphate Reducing Bacteria (SRB). Formation waters normally contain only a few mg/l of iron and values as high as 100 mg/l are rare. Precipitated iron compounds are a common cause of deposit formation and injection well plugging, and can also be a sign of a serious corrosion problem. Carbon dioxide (CO2), a corrosive gas, reacts with iron to form ferrous carbonate (FeCO3). Presence of hydrogen sulphide (H2S) in the produced water or gas together with iron, will result in the formation of iron sulphides (FeS). The presence of H2S in the production system can, apart from natural reasons, also be caused by SRB bacteria in the presence of sulphate. Oxygen combines with iron to various (corrosion) compounds. Ferric (Fe2O3) and Ferrous Oxide (FeO) are common forms resulting from contact with air or oxygen containing water. Other forms are the hydroxide forms of iron Fe(OH)2 and Fe(OH)3. Iron deposits/scales can normally be removed with acids like HCl. Care has to be taken by back production that depleted acid with iron can again deposit as iron hydroxide. For this reason, often complex forming chemicals like citric acid or ethylene diamine tetra acetic acid (EDTA) are used to avoid this re-precipitation of iron. In case the iron deposit is the result of corrosion, a detailed investigation into the cause(s) and possible remedial actions is required.

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Iron Compounds• Iron Based Deposits May Exist as:

• Ferrous Carbonate FeCO3 Siderite.• Ferrous Sulphide FeS Pyrite.• Ferrous Oxide FeO Hematite• Ferric Oxide Fe2O3.Fe3O4 Magnetite.• Ferrous Hydroxide Fe(OH)2

• Ferric Hydroxide Fe(OH)3

• All Deposits are Insoluble in Water.• Hydroxides are difficult to treat with Acid.

Scale Prediction Prediction of scaling is an important tool when developing new fields and/or water injection projects. The most simple form of prediction is by simple calculations such as the Stiff and Davis (CaCO3) and the Skillman, McDonald and Stiff (CaSO4) indices. The equation for the saturation index (SI) of calcium carbonate according to Stiff and Davis is: SI = pH - (K + pCa + pAlk) pH = actual pH of the water K = A constant which is a function of salinity, temperature and water composition pCa = The negative logarithm of the calcium concentration Palk = The negative logarithm of the total alkalinity (CO32- + HCO3-) The Skillman, McDonald and Stiff equation is: S = 1000 [(X2 + 4K)0.5 -X] S = gypsum solubility (milliequivalent/liter) X = excess common ion concentration/liter. This is the difference between the calcium- and the sulphate concentration. K = solubility product constant ( a function of the ionic strength of the water and temperature) These calculations are a rather coarse method of predicting the likeliness of scale formation and cannot be applied in more complex situations.

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Over the past decade, more sophisticated computer models have been developed, amongst others, the KSEPL (RTS) developed Waters program. This software tool was rather complex to run and did not have sufficient flexibility to predict a wide range of scaling conditions. A later development was Scalechem which, in the beginning also suffered from a user unfriendly approach. However, this program has been improved over the past years resulting in the release of a user friendly Windows 95 version. This latest version is capable of correlating high temperatures and pressures, accounts for flow rates and many other features. The only scale it cannot accurately predict is metallic lead (Pb). As for many other Process Chemistry areas, the accurate prediction of software tools like Scalechem, is fully depending on the accuracy of the data used. In these programs the composition of water at downhole condition is required from where the software can calculate the composition when the sample is produced to surface. Water samples, where possible, have to be analysed for pH, CO2 and HCO3- content at actual downhole conditions (pressure and temperature). This is in particular true where CO2 takes part in the reaction equations. Analytical data of a surface sample cannot be used without accurate calibration tables based on downhole samples.

Prediction of Water Formed Scales• Calculations (Only Rough Indications)

• Stiff and Davis Scaling Index (CaCO3).• Skillman, McDonald and Stiff (CaSO4).

• Computer Programmes• Consider More than One Type of Scale.• Consider Multiple Factors which may Induce Scale.

• Scalechem• Correlates for High Temperatures and Pressures.• Mixes Water and Gas Compositions.• Accounts for Flowrates, Temperatures and Pressures.• Predicts all Scales except for Pb• Currently Under Development for the New PT Computing Portfolio.

• Available Q2-1997 as a User Friendly ‘GUI’ version, under Windows ‘95.

• Accurate Data Entry is Required for Meaningful Results.

Prediction of scaling conditions are an important tool in the development phase of a production or water injection project. Knowledge of the situation to be expected can be used to prevent scaling to occur or to take measures to manage scaling. Different categories of approaches are available for the prevention or control of scaling. These include the following:

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Scale Prevention and ControlCategory Summary of MethodProcess Design Operate Under Less-Scaling

Conditions.

Ion Removal or Exchange Remove Ions to Prevent Them Reacting.

Inhibition Leave Ions in SolutionApply Chemical Treatment to Disperse Precipitates.Modify Crystal Growth Pattern.

Removal Allow Deposits to Accumulate and Remove Periodically by Chemical / Mechanical Means.

Process Design: Taking measures in the design of the injection/production system to minimise or prevent scaling. Removal of the scaling ions: In this case the injection water is pre-treated to remove one of the scaling ingredients to prevent scaling after mixing with the water in the formation. Inhibition The use of chemicals to prevent the scaling ions to precipitate but stay either dissolved or dispersed in the water phase. Removal In cases where scaling takes place at moderate rates, the most cost effective approach sometimes could be to allow deposition, while periodically removing the scale mechanically or chemically. Process Design As described above in the category of process design, options are mainly to take measures in the production process to control scaling. A number of options include the following: pH control. In particular for carbonate scales, the pH plays an important part in the equilibrium. CO3

2- + H+ HCO3- + H+ H2O + CO2

The equilibrium is moved from carbonate via bicarbonate to carbon dioxide by adding acid (H+).

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The control of the pH can be effected by dosing small concentrations of for instance acetic acid which is low in corrosivity. Otherwise where the water and gas phase contain carbon dioxide, maintaining the pressure will keep the CO2 content high, thereby preventing an increase of the pH and consequently scaling. As for carbonates, for iron scales, pH also plays an important role in the solubility of these compounds. pH control is not a measure which is widely applied as it may create increased corrosion problems. Only where minimal adjustments in pH are required this option could be investigated. Temperature control For water compositions where scaling is sensitive to temperature reduction, sometimes the insulation of pipe- and flowlines may be sufficient to prevent or minimise scaling. Incompatible waters In particular for water injection projects, the compatibility of the injection water with that in the formation is very important. For instance, if the injection water contains a large concentration of carbonate, and the formation water calcium, together this could result in the formation of calcium carbonate when these waters are mixed following injection. A typical example is injection of sea water containing sulphate in a reservoir containing either calcium, barium or strontium. The use of software tools such as Scalechem can predict the likelihood of scaling to occur either in the reservoir or in the producing wells. Where possible, mixing of incompatible waters should be avoided. Where this is not possible, two options are available to prevent impairment and scaling in the production facilities. These are: removal of incompatible chemicals from the injection water or the use of scale inhibition chemicals.

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• Operate Under Less Scaling Conditions• pH Control

• Maintaining Low pH May Prevent Carbonate Scaling.

• Temperature Control• Pipeline Insulation May Reduce Temperature Changes.

• Avoid Mixing of Incompatible Waters• Carefully Select Injection Water.• Do Not Use Mixed Sources for Injection Water.

Process Design

Ion removal or exchange In case a water source has to be used which is incompatible with the formation water, one option is to remove or exchange the interfering ions with non-interfering ones. One method is to exchange the scaling ions such as calcium, magnesium, carbonate or sulphate, by non scaling ones such as sodium (Na) and Chloride. This can be done by using ion exchange units which use exchange resins. The method, however, is very expensive and more applied to removing scaling conditions for boiler feed water rather than for large scale water injection projects. In the past scaling ions were removed by precipitating these chemicals and removal of the deposits via filtration. Also this method is not widely applied as the precipitation and filtration processes have to be complete to avoid solids to bypass the filtration units and deposit later in the injector wells. Ion removal, is a process, whereby the injection water is passed via a membrane filtration system with pores allowing only the smaller ions to pass. Larger ions such as sulphate and (bi)carbonate are too large to pass and are concentrated in a reject stream. The additional advantage of this process in addition to removing a scaling ion is that by the removal of the sulphate (the main feed stock for these bacteria) the possibility of corrosion due to sulphate reducing bacteria is diminished.

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Ion Removal or Exchange• Remove One of the Offending Ions to Prevent Reaction.

• Normally Only Applicable for Water Injection Where Early ‘Break-Through’ andIncompatibility is Expected.

• SO4 can be Removed from Seawater.•‘Cross-flow’ Filter Membranes Reject Ions Based Upon Their Hydrated Sizeand Charge.

•Electro-Dialysis Reversal (EDR) or Ion Exchange Systems Replace theOffending Cation with One That is Less Problematic.

The Viewgraph on the following page shows the result of a sulphate removal trial from sea water conducted at the Orkney water test centre. It demonstrates that only the larger ions are selectively removed while the smaller ones, are much less affected. This technology, while sufficiently developed to be applied in the field, is in most water injection projects still too expensive. The preferred way often is to use scale inhibitors at the initial phase of the injection project in the injection water and again in the producers during the period that a scaling mix of injection and formation water is produced.

Sulphate Removal

Determinant Seawater SRM Product

Sodium mg/l 11,120 10,050Potassium mg/l 420 354Calcium mg/l 420 274Magnesium mg/l 1,340 620

Chloride mg/l 20,035 18.110Sulphate mg/l 2,830 25Bicarbonate mg/l 141 20

Orkney Water Test Center Trial

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Scale inhibitors Scale inhibitors are most commonly applied to control the formation of scales. In water injection projects these chemicals are used to prevent impairment in the near well bore region, while for produced water, also the downhole- and production equipment is given protection. Scale inhibitors are chemicals which will delay, reduce or prevent scale formation when added in small amounts to a normally scaling water. One category of inhibitors are the chelating agents. These products work by reacting with the scaling cations (Ca, Mg, Ba, Fe) by forming soluble complexes. Examples of these products are the complexed organic acids such as Ethylene Diamine Acetic Acid (EDTA), Mostly these chemicals are used in the form of a sodium salt (e.g. EDTA-Na2) and are active over a specific pH range depending on the Cation to react with. When applying these chemicals, the dosage used should be sufficient to chemically bind such a portion of the scaling cations that the concentration of free cations is below the maximum solubility threshold for the scale in question. Threshold type inhibitors are chemicals which achieve effectiveness at low concentrations. At these low doses, these products may prevent precipitation of scale by keeping the water supersaturated for a prolonged length of time. The time for which these products keep this supersaturation is dependant on the chemical water composition, the type of product and other factors including temperature, turbulence in the system and the presence of nuclei (solid particles). Their effectiveness at low dosing rates is caused by these chemicals to adsorb onto the crystal growth sites thereby inhibiting their growth as well as settling on pipe walls. Several generic threshold inhibitors are available which all have their specific application limits. Polyphosphates were commonly used in the past but due, to their low temperature tolerance (up to +/- 55 oC), were later replaced by the more stable phosphonates. These products are most effective for the inhibition of carbonate scales, while the phosphates are also effective for barium- and calcium sulphate scale. Another group of threshold inhibitors are the so-called polymers, polyacrylamides and the polyacrylates. These products have a high temperature stability, and are also effective for the inhibition of Barium Sulphate. Very often blends of the above groups of chemicals are being used and tuned to the typical scaling conditions encountered.

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Scale Inhibitors• React One of the Ions to Keep It In Solution or Dispersed.• Chelating Agents.

• Use Active Sites to Chemically Bind (“Chelate”) with Ions which areSusceptible to Scaling.

• Complexed Organic Acids; EDTA, DTPA, NTA.• Organic Salts; Lignins, Tannins, Lignosulphonates.• Must be Applied Stoichiometrically for Effective Treatment.• Complexes may be pH sensitive.

• Threshold Type Inhibitors.• Maintain Precipitates in Dispersed State by Adsorbing onto Crystal Growth

Sites and Inhibiting Crystal Growth.• Inhibit Agglomeration on Pipe Walls.• Effective in Low Concentrations.• Polyacrylamides, Polyacrylates, Polyphosphonates.

• Laboratory Tests Are Essential for Cost Effective Treatment.

When inhibitors are being applied, they always need to be introduced before the scale has been formed as most products do not or only slowly dissolve already precipitated scale. For water injection systems, where the water is self-scaling under system- or reservoir conditions, the inhibitor must be applied continually from the start of the injection at dose rates which are dependent on chemical type and scaling potential but are typically in the range 1-50 mg/l. (see points listed on Viewgraph for continuous injection). If the scaling is the result of incompatibility between injection and formation water, then the selected inhibitor may initially be injected at a higher dosage rate (in the injection water) until a buffer zone of inhibited water is created in the injector wellbore area. Dosage can thereafter be reduced or even be discontinued until the injection water is close to breaking through in the producers whereby mixing with the formation water will cause scaling in producers and/or facilities. At that later stage “squeeze injection” of chemical is often applied rather than adding the inhibitor to the injection water. (see points listed on Viewgraph for squeeze injecting inhibitor). Inhibitor dosing in the injection water will not prevent scaling in the production wells as the product will have long been adsorbed in the reservoir. The frequency of squeeze injecting inhibitors in the scale prone producers can vary dramatically and extremes between a few weeks and a few years have been observed in practice. In most cases a high overdose of chemical will have to be injected in the well where it ideally absorbs in the formation being slowly released when producing the scaling water. In practice however, often around one third of the product is produced back within a few days while another third will never be produced back. This makes the application of squeeze inhibitors relatively expensive.

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Application of Scale Inhibitors• Inhibitors Must Be Introduced Before the Scale is Formed.• Continuous Injection.

• Applicable for Scale in Wells and Surface Facilities.• Apply Upstream of Initial Scaling Point.• Ensure Good Mixing.• Injection Rates 1-50 mg/l.

• Squeeze Treatment.• Applicable for Scale in the Formation (Near Wellbore).• Chemical Squeezed Into Formation.• Adsorbed onto Rock Surface or Precipitated in the Pore Space.• Gradually Released During Production thereby Providing Continual Inhibition.• Life of the Treatment can Cary from 1 Month to Several Years.• Can be Expensive as Generally 1/3 of Treatment is Immediately Back Produced

and 1/3 of Treatment is Often ‘Lost’ in the Formation.

Non-chemical Crystal Growth Inhibition Over the past decades many claims have been made that magnetism could prevent or delay the onset of deposition of scales such as calcium carbonate. In the potable water industry the use of magnets has been reported to minimise carbonate scale in drinking water lines. Also reportedly, in China and Russia many wells have been provided with magnets for the same reason. Apart from preventing scale, also claims have been made that these magnets prevent wax deposition. During the seventies, some experiments have been conducted by KSEPL (now RTS) in Rijswijk, but never any solid proof was obtained. The view graph below describes some of the claims which are being made about the way these magnets inhibit scale formation. So far, no clear evidence has been found that magnets can reduce scaling, but as the technology would be very cheap to be applied and in addition is environmentally inert, a more detailed study of this phenomena could be worth wile. Research in this subject is still underway, and funded by a number of oil companies.

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Non-Chemical Crystal Growth Inhibition• Physiosorption

• Electro-Magnetic Crystal Growth Modification.

• Applying a Strong Magnetic Field at the Time of CrystalFormation May Modify the Crystal Shape and Inhibit Multi-Crystalisation.

• In Some Circumstances May Modify Post Formation CrystalShape Giving Some Deposit Degradation.

• Applicable to All Crystalline Materials.• Have Been Successes and Failures• Evidence is Lacking and Theory is Still Under Discussion.

• ARC Have Yet to Simulate Field Reported Success in Their Test Loop.

• Environmentally Inert.• Relatively Inexpensive.

Even where scale inhibitors are applied, complete prevention of deposition is rarely achieved. Failure of chemical dosing will occur periodically and removal of resultant scale accumulation may be required. Scale can be removed either chemically or mechanically. Calcium carbonate scale can normally easily be removed with Hydrochloric Acid (HCl) unless the scale is covered with oil. In this case a surfactant or solvent has to be added to the acid. When using corrosive acids such as HCl, corrosion protection via inhibitors is often required, in particular with normal carbon steel tubing completions. In contrary to carbonate scales, sulphate scale cannot be dissolved with regular acids. Apart from physical removal, successes have been claimed by using mixes of strong Ethylene Di-Amine Tetra Acetic Acid (EDTA) and other gelating agents which are available via chemical suppliers. Another possible, but more complex method is to pre-treat the sulphate scale with ammonium carbonate in which the calcium sulphate with a relatively high solubility is transformed into the less soluble calcium carbonate. The soluble ammonium sulphate can then be flushed away prior to treating the generated calcium carbonate with HCl. Sulphide deposits like FeS are soluble in strong acids like HCl. Extreme care has to be taken with these treatments as with this chemical reaction the very toxic H2S gas is formed and safety precautions have to be taken. In cases where the scale cannot chemically be removed, mechanical removal is the only remaining option. Physical removal is difficult and may require the use of jack

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hammers, reamers of high pressure water jets. Coiled tubing can be used for internal removal, but more common is to pull the tubing from the well for cleaning.

Chemical Scale Removal• Calcium Carbonate are Best Removed by Acid.

CaCO3 + 2HCl > CaCl2 + CO2 + H2O• Corrosion Inhibitor is Required to Protect the Steel.• Use Less Aggressive Acids for More Frequent Applications.

• Calcium Sulphate Scale can be pretreated with ammoniumcarbonate prior to removal by hydrochloric acidCaSO4 + (NH4)2CO3 > (NH4)2SO4 + CaCO3

• This May Not Always be Effective - Mechanical Removal May be Needed.

• Sulphate Scales May be Removed with EDTA.

• Sulphide Deposits can be Removed with Hydrochloric Acid.2FeS + 6HCl > H2 + 2FeCl3 + 2H2S

• Care Must be Taken Due to Hydrogen Sulphide Production. Radioactive scale Trace quantities of the radioactive elements uranium (238U) and thorium (232Th) have been present in the earth’s crust since its formation. Consequently, these elements are also common in oil/gas bearing geological formations. Both 238U and 232Th are the parent of a complex series of successive decays in which their radioactive daughters are formed. They are called Naturally Occurring Radioactive Materials or NORM. The most common radioactive materials or NORM encountered in E&P operations are 226Ra, 222Rn (Gas), 210Pb, 210Po, 228Ra and 228Th. Some of these daughters may be co-produced with oil/gas well fluids. Normally the natural concentration of these radioactive isotopes is very low and will not cause an HSE problem. However, these materials may concentrate and co-deposit together with Barium and Strontium scales. The deposition of these concentrated radioactive material is called Technologically Enhanced Natural Radioactive (TENR). Its deposition on tubulars, flow lines and in production facilities can cause a serious Health and Environmental hazard and requires the specialist contractors for the removal of the scale and its disposal at safe locations such as nuclear waste repositories. Three different types of radiation can be distinguished: • The first type is called Alpha radiation consists of the emission of Helium Nuclei

from the radioactive element. As these helium particles are relatively large (atomic weight = 4), their penetration depth is very small and are easily stopped in the surface cells of the skin.

• The second type is Beta radiation which consists of emission of electrons. As electrons are relatively much smaller compared to helium nuclei, their penetration depth is higher.

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• The third type of emission is Gamma radiation which is the emission of photons which again are much smaller than electrons. Resultingly, the penetration depth of photons is higher which makes this type of radiation more dangerous.

Another name for the most common oil field radio active scales is LSA or Low Specific Activity scale. This is because the radioactive materials in the scale only make up a very small portion of the scale deposit. Eventhough by building up a layer of scale the total concentration of this material may build up beyond safe levels and special care has to be taken in handling and disposing it.

‘NORM’ & ‘LSA’• Naturally Occurring Radioactive Materials.

• Normally Daughters of Uranium and Thorium Decay Series.•Ra226 and Ra228 are the Most Commonly Occurring Derivatives.

• Co-precipitate with the main Scaling Cations.

• Radiation Types• Alpha Radiation (Helium Nuclei): Easily Stopped, Only Affecting Surface Cells.• Beta Radiation (Electrons): Penetrates Only a Few Millimetres.• Gamma Radiation (Photons): Much More Penetrating.

• Low Specific Activity• ‘Specific Activity’ is the Radioactivity per Gram of Material.• Radium and Thorium Form Only a Very Small Fraction of the Scale Volume.• Therefore Such Scales are Classed as Low w.r.t. their Specific Activity.

•There is a Low Level of External Hazard.•There is Still a High Internal Hazard if Inhaled or Ingested.

• All Exposure Should Be As Low As Reasonably Possible. The final view graph on water borne scales shows the decay series for radium via Alpha and Beta emissions.

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Radium Decay Series

Pa-2341.2 m

2.3 MeV

U-2342.5 x 105 y4.8 MeV

U-2384.5 x 109 y4.2 MeV

Th-23424 d

0.2 MeV

Th-2308.0 x 104y4.7 MeV

Ra-2261620 y

4.8 MeV

Rn-2223.8 d

5.5 MeV

Po-2183.05 m

6.0 MeV

Po-214160 us

7.7 MeV

Po-210138 d

5.3 MeV

Bi-21420 m

43.3 MeV

Bi-2105.0 d

1.2 MeV

Pb-21427 m

1.0 MeV

Pb-21022 y

0.06 MeV

Pb-206Stable

0

α

U-2342.5 x 105y4.8MeV

RadionuclideHalf-lifeRadiation Energy

Mode of Decayα

α αα

α

α

β

β

β

β

β

β

α

α

Uranium Protactinum Thorium Radium Radon Polonium Bismuth Lead

North SeaLSA Scale

10 ppb100-1000 Bq/g

β

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5. Bacteria and Biocides Micro-organisms are currently divided into three major domains: the bacteria, the Archea and the eucarya. Each group has unique characteristics which can have an impact on various oilfield operations. As the group of bacteria covers most of the aspects encountered in E&P operations, only the domain of bacteria is discussed below. The domain of bacteria can be subdivided into four main types: the aerobic-, anaerobic-, the mesophilic- and the thermophilic bacteria. These types indicate the conditions under which different categories of bacteria live and can multiply themselves. A combination of these types is often used to describe the living environment of bacteria (e.g. aerobic, mesophilic). Aerobic Bacteria Aerobic bacteria live only in the presence of oxygen, predominantly in well aerated low salinity water. For this reason aerobic bacteria are mostly encountered in injection water systems where use is made of surface water. Removal of all Oxygen sources will result in these bacteria to die, the reason for the use of oxygen scavengers which remove the oxygen from the water. Examples of aerobic bacteria are iron bacteria, slime formers, sulphur oxidising- and hydrogen oxidising bacteria. Anaerobic Bacteria The word anaerobic means “without air”. Indeed these bacteria can only live in environments without oxygen, which is common for production streams and facilities. An example of anaerobic bacteria are Sulphate Reducing Bacteria (SRB) which are further discussed below. Mesophilic Bacteria Mesophilic Bacteria means that type of bacteria that only live and multiply in moderate temperature environments (20 - 40 oC). At lower temperatures these bacteria can remain dormant which means that they can stay alive but not multiply, but at temperatures well above 40 oC, they will die. Thermophilic Bacteria In contrary to the mesophilic type, thermophilic bacteria can live at (much) higher temperatures. Some SRB, the so-called t-SRB have been found to survive temperatures of at least 120 oC and pressures of 500 bar.

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Types of Bacteria• Aerobic Bacteria

• Live in the presence of oxygen

• Anaerobic Bacteria• Capable of living in the absence of oxygen

• Mesophilic Bacteria• Thriving at moderate temperatures, usually between 20-40oC

• Thermophilic Bacteria• Thriving at relatively high temperatures, above 45oC

Dormant

Active

Death

20 50 ToC

PressureBars

700

Iron Oxidising Bacteria Iron oxidising bacteria are aerobic bacteria forming iron oxide containing slime colonies in water containing large quantities of ferrous oxide. They are commonly observed in water injection systems where these slimes block filtration systems. As these colonies grows denser, their base may become deprived of oxygen under which SRB (with resulting corrosion) can develop. Most of these bacteria either use organic matter or sometimes CO2 as a carbon source.

Iron Oxidising Bacteria• Deposit Iron Oxide and Hydroxide.

• Their Activity Results in the Plugging of Filters with IronOxide or Hydroxide Slime.

• Corrosion Occurs Under the Deposits.

• Detection is Very Difficult.

Sulphate Reducing Bacteria (SRB)

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SRB consist of diverse types of strictly anaerobic bacteria, which can only grow in the absence of oxygen, but can often survive aerobic conditions. They have in common the ability to reduce sulphate, sulphite or thiosulphate to hydrogen sulphide to support their metabolism. The sulphate is not a nutrient, rather is it similar to other organisms using oxygen for their metabolic processes, and producing CO2. SRB can tolerate temperatures from -5 to at least 90 oC and are found in fluids with pH ranges from 5 to 9.5 as well as pressures up to 500 bar. Reservoir souring (and subsequent corrosion of well completions and production systems) following the injection of sulphate and dormant SRB containing sea water is one of the main challenges related to these bacteria. H2S formed during the sulphate reduction process can cause metal failure in two ways. Firstly the H2S can react with steel to form FeS thereby corroding the metal parts. Secondly the hydrogen resulting from the reaction with iron can penetrate the metal thereby making the material more brittle and susceptible to stress cracking. SRB sometimes are enclosed by slimes or debris (=sessile bacteria) under which they can concentrate and cause the so-called “pitting” corrosion. The use of biocides in water injection systems is generally ineffective as a 100% kill is required to prevent live SRB to enter the reservoir. In the reservoir the few remaining live bacteria have sufficient time to multiply until they reach the producing wells. In production systems a 100% kill is not always necessary and reducing their numbers to control their growth is often sufficient. However, if SRB are buried under protective layers as mentioned above, penetration by the chemical is not always achieved. SRB, like many other bacteria, use as food supply the fatty acids normally present in oil/gas reservoirs. Removing this food supply from the bacteria is the preferred method but is in practice not easily achieved. Only where other bacteria provide this feed stock a control may be practicable by killing these food suppliers.

Sulphate Reducing Bacteria (SRB’s)• SRB’s are Strictly Anaerobic - the Presence of Oxygen

Usually Prevents their Growth.

• The Main Characteristic of SRB’s is that they ReduceSulphate to H2S and CO2.

• H2S Can Cause Metal Failure (Stress Cracking).• H2S May Lead to Formation Plugging by Iron Sulphide.

H2S + Fe => FeS + H2

• Biocides are Generally Ineffective as they Have to Kill 100%of the Population.

• Oxygen Will Often Kill SRB But May Cause Other Corrosion• Removing the Food Supply is the Preffered Method.

SO42- + 2H2O + Organic Material + SRB => H2S + 2CO2 + 2OH

-

Sulphide Oxidising Bacteria (SOB)

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In contrary to SRB, SOB only can thrive in oxygen rich environments. They grow in well aerated systems utilising reduced sulphur compounds such as sulphur, sulphite and sulphide, which are converted to sulphuric acid. These bacteria can generate a pH in the range of 1 - 2 which is highly acidic and result in severe localised corrosion of steel and concrete structures. SOB classically grow in close association with SRB, where cycling sulphur compounds and variations in oxygen levels, can lead to sustained corrosion problems.

• SOB’s are Strictly Aerobic - The Lack of Oxygen Will InhibitTheir Growth.

• The Sulphuric Acid Causes Pitting Corrosion.

• Biocide are Generally Ineffective as they Have to Kill 100% ofthe Population.

• Removing the Oxygen Supply is the Preffered Method.

Sulphide Oxidising Bacteria (SOB’s)

O2 + S2- + 2H2O Organic Material + SOB = CO2 + H2SO4

Bacterial Survival and Growth Conditions As we have seen above, bacteria are able to live under extreme conditions and are found in environments such as hot geysers, sulphur springs, and ice. Whether they could also originate in oil reservoirs is still unproved as it would require survival, in dormant conditions, over periods of millions of years at high pressures and temperatures. Limits on conditions for bacterial survival are ill defined. Under certain environmental conditions however, they may be expected to proliferate. These are: 1. Presence of water 2. Carbon source 3. Nitrogen source 4. Inorganic salts - phosphate, iron 5. Electron acceptor (O2 or SO4

2-) 6. Temperature range 7. Maximum pressure 8. pH range 9. Reduction - oxidation potential (Eh) range 10. Salinity range 11. Upper limit on toxic agents (e.g. high H2S inhibits SRB) During growth, bacteria may substantially modify the nearby environment by creating:

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1. Inorganic by-products (e.g. H2S, CO2, H2SO4) 2. Soluble organic by-products (e.g. fatty acids) 3. Insoluble organic by-products (e.g. slimes, polysaccharides) 4. Oxygen depletion, pH and Eh change. Growth of bacteria can be restricted by a lack of any one of their nutritional requirements or unfavourable conditions with restrict their growth. Their growth may be limited by a single factor, small changes in this limiting factor may significantly affect bacterial growth whilst changes on other parameters have no effect. By using these conditions, the growth of bacteria can be controlled. Biocides Where no control options are available to the continued growth of bacteria, bactericides or biocides can be applied. As most of these products have a potential negative impact on the environment or could cause health or safety problems, extra care should be taken by their selection and application in the field. Before applying any of these chemicals, all relevant HSE data have to be requested from the chemical supplier and approval from environmental legislative bodies is often required. Different products are available for the different types of bacteria. Inorganic bactericides Chlorine is widely used to control the growth of aerobic bacteria in surface water injection systems and no evidence of bacteria becoming immune have been reported. It is a cheap product and generally effective at low dosage rates (e.g. 0.2 - 1 mg/l). Chlorine, however, is a corrosive chemical and attacks carbon steel. In addition, when applied in produced water, it could react with the dissolved oil and create persistent toxic chlorinated products. Oxygen free water often contain soluble iron and the use of Chlorine would result in the iron to become oxidised by it and become insoluble. Mostly the Chlorine (or better Hypochlorite) is generated via the electrolysis of Sodium Chloride (from sea water) as follows: NaCl + H2O => NaOCl + H2 Sodium Chloride Sodium Hydrogen Hypochlorite The NaOCl is ionised into Na+ + OCl- the latter being the most active disinfecting compound. The Hydrogen generated if combined with oxygen is very explosive requiring a safe disposal at the process unit by blowing with air below a concentration of 1%. Hypochlorite solutions are very corrosive to carbon- and stainless steel and for chemical injection pumps special alloys such as Hastelloy C or plastics are required. Other effective biocides for the control of aerobic bacteria are chlorinated phenols, but as these products are slow biodegradable, their use in the oil industry is very limited, if at all allowed.

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Organic bactericides Anaerobic bacteria are less sensitive to chlorine as often these bacteria are located underneath deposits or slimes and the chlorine cannot penetrate. In addition, as chlorine is a strong oxidiser, the presence of soluble iron would result in iron deposition. A wide range of organic bactericides have been developed to prevent the accumulation of anaerobic bacteria. Many of these products have practical limitations or are only effective against one specific type of bacteria. A number of these products are discussed below: Aldehydes Among the aldehydes, formaldehyde is a well-known broad spectrum Biocide which is affecting the DNA in the microbial cells. Mutation in the DNA can lead to the development of resistant strains resulting in the Biocide becoming ineffective. Besides formaldehyde, also glutaraldehyde is a commonly used product. The effectiveness of glutaraldehyde against bacteria increases with increasing pH. Both products are effective general anti-microbial agents, but penetration into biofilms is poor. For this reason the aldehydes are often blended with quaternary ammonium compounds to assist in penetration. Another consideration when using these products is their toxicity and suspected carcinogenity, which limits their application in the field. Quaternary Ammonium Compounds (QAC) The quaternary ammonium compounds are considered low toxic and are used in the food industry. This in contrary to aldehydes which are now considered toxic and possibly carcinogenic. At low concentrations these products show high rates of biodegradation and are of low environmental risk if accidentally discharged. A disadvantage of the low toxicity of the products is that their killing rate is low compared to the aldehydes. QAC are very surface active and may remove biofilms without killing all microbes. This can lead to plugging and downstream contamination effects after Biocide treatment. Acrolein Acrolein is a highly reactive acrylic aldehyde with a pungent odour and difficult to work with. It is a very effective Biocide at low concentrations and short contact times. In addition to being a Biocide, it is also an active sulphide scavenger. Acrolein can since recently be safely generated on-site from non-hazardous precursors and, if this novel technology can be developed into a fully functional system, acrolein Biocide will become more widespread. Application of biocides Biocides can be either dosed continuously at low dosage rates or injected batch wise. For water injection systems where the reservoir requires protection against bacteria, continuous Biocide injection is applied, while in production water systems

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batch injection is more commonly used. The frequency on the batch treatments can vary from daily to monthly and depends mainly on the rate of recovery of the remaining bacteria or recontamination. 100% kill of all bacteria is the ideal in Biocide treatments but in practice not often achieved. Very often a few microbes escape alive and are able to multiply again after some time. Some bacteria including SRB, are known quickly to become immune for a particular Biocide. To prevent this to happen the applied chemical has to be varied with another type of product on a regular (say monthly) basis.

Bactericides• Aerobic Bacteria• Chlorine• Chlorinated Phenols• Anaerobic• Less Sensitive to Chlorine• Amines, Aldehydes• Quaternary Ammonium Compounds• SRB’s Quickly Become Immune, Biocides Must be Varied.

• Biocides Must Kill 100% of the Population to be Effective.• Biocides Are Toxic and May Cause Environmental Impact.• Removing the Food and Oxygen Source is Preferred.

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6. Corrosion Corrosion is an electro-chemical process. This means that an electrical current flows during the corrosion process. For the current to flow there must be a driving force or a voltage source, and a complete electrical circuit. The driving force or voltage source in the corrosion process is the energy stored during the refining process of the metal from its original oxide- or salt form. The circuit is mostly consisting of one half of the metal surface to act as the anode (where the corrosion or oxidation takes place) while the other half is the cathode (where the reduction reaction takes place). Both are connected via a conductive water phase. The following steps can be identified in the corrosion process: 1. The driving force results in electrons to escape from the metal at the anode. 2. The electrons flow from the anode to the cathode. 3. At the cathode a reduction reaction takes place. The rate of corrosion is dependent on many factors including the following: 1. the type of metal (compare gold with iron or magnesium). The most difficult to

refine is the easiest to corrode. 2. the composition of the electrolyte (water with conducive salts) 3. the electron conduction between cathode and anode (compare with thickness of

electric cable and type material) 4. The pH of the water 5. The presence of dissolved gases like CO2, etc. 6. The oxygen content of the water.

Corrosion• Corrosion May be Considered as an Electrochemical

Reaction Involving Three Main Steps:• There is a Loss of Electrons from the Anode.

• Fe0 > Fe2+ + 2e-

• Electrons Flow Through the Steel from Anode to Cathode.• A Reduction Takes Place at the Cathode to Complete the

Electrochemical Cell.• For example: Oxygen may be Reduced: 1/2 O2 + H2O + 2e- > 2OH-

• Types of Corrosion• Oxygen Corrosion: 4Fe + 6H2O + 3 O2 > 4Fe(OH)3

• Carbon Dioxide Corrosion: Fe + CO2+ H2O > FeCO3 + H2

• Hydrogen Sulphide Corrosion: Fe + H2S > FeS + H2

• Bacterial Corrosion: Produces One of the Above Types.

`

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Common types of Iron corrosion encountered in the E&P Industry include the following: Oxygen corrosion Carbon dioxide or sweet corrosion Hydrogen Sulphide or sour corrosion Bacterial corrosion. The above types of corrosion are all the result of a (bio)chemical attack on the iron. Another type of corrosion is galvanic corrosion. Galvanic corrosion takes place when two different metals are placed in contact in an electrolyte. The corrosion rate of the more reactive metal will increase while the corrosion rate of the less reactive metal will decrease. This principle is often utilised in a beneficial way in cathodic protection. Steel from a facility or pipeline is connected to a more reactive metal such as magnesium and is thereby protected against corrosion. Under deposit corrosion occurs when two pieces of metal which are in different environments, e.g. different concentrations of corrosive agent. This results in an electrical current which increases corrosion under the deposit due to differential concentration. This happens often under deposits of sand tar, debris, etc. in combination with the presence of dissolved oxygen. Another form of under deposit corrosion can result from the presence of SRB underneath the deposit. In this case the release of H2S causes pitting corrosion.

Corrosion (Cont’d)

• Galvanic Cells Current Increases Corrosion Rate of Least Noble MetalUsed in Cathodic Protection

• Under Deposit CorrosionDifferential Concentration Cell in presence of Dissolved Oxygen

Corrosion Inhibitors Apart form using more corrosion resistant alloys, sometimes chemicals can be applied to reduce corrosion rates in production facilities. Most of the products reduce the corrosion rate by forming a protective water repellent layer on the metal parts in contact with the corrosive medium. For this reason corrosion inhibition injection has to be conducted in a continuous mode to ensure the protective film stays intact. Because of their hydrophobic nature most corrosion inhibitors are oil/condensate soluble. The few water soluble products available are found to be less effective.

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Another group of chemicals is claimed to work on the induction of passivity of the metal towards corrosion rather than by forming a water repellent film.

Corrosion Inhibitors• Most Common are Hydrophibic Adsorbing Materials that

Repel Water. A thin film of the product is reducing contactbetween fluids and to be protected metal.

• Most Water Soluble Inhibitors are found to be Less Effective

• Presence of Water is the Main cause for Corrosion.

• Compatibility with Demulsifiers, Drag Reducers, HydrateInhibitors, etc, but also with Materials used.

• Avoid Foaming and Emulsion problems

Because of their water repellent nature, corrosion inhibitors are often found to be incompatible with many demulsifiers and can result in stable emulsions to be formed. Also incompatibilities with other process chemicals such as drag reducers and hydrate inhibitors have been observed. For this reason, a detailed screening of potential corrosion inhibitor products is required to make sure that, in addition to its effectiveness to reduce corrosion, no incompatibilities with other system fluids or materials are the result. Further, environmental aspects will have to be taken into consideration. Selection of suitable products becomes more and more important now high temperature, high pressure (HTHP) reservoirs are being produced and with the production of hydrocarbons via sub sea installations. Where chemicals are being applied to reduce corrosion rates, a proper monitoring programme has to be in place to ensure actual corrosion is in agreement with the design values. A typical inhibitor screening program could be as follows: Preliminary: Test products recommended by supplier (maximum 2 per supplier) • exposure (weight loss) in a rotating cage @ 5 m/s for 1 to 7 days • electrochemical tests @ 1 m/s for 2 days • autoclave tests under actual anticipated pressures and temperatures

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• test metal in a solution of 10% NaCl, 10% CaCl2 • test welded pipeline specimens Advanced testing: • In flow loop tests, submit to intermittent slug-, annular dispersed-, and stratified

flow conditions • test the effects of other chemicals like scale- and wax inhibitors in the flow loop Final testing: Subject the inhibitor to test its corrosion protection efficiency by subjecting a metal piece to impingement jet and high shear stress flow conditions under ambient and actual field conditions, the presence of salt and oil, etc. The ultimate test remains to test the performance of the inhibitor under actual field conditions. And by monitoring using smart pigging, coupon monitoring and analysing the iron content in the water.

INHIBITOR TESTING

LABORATORY TESTS:Use suppliers recommended products• Tests in low pressure environment• Autoclave tests with weightloss coupons (res. P+T)• Flowloop testing• Field trials

FIELD MONITORING:• Smart pigging• Coupon monitoring• Iron counts

HTHP Environments and Subsea Installations make selection of most suitable products more important

Oxygen Corrosion is mainly of importance in water injection systems whereby oxygen is present in the surface water and is not totally removed.

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Oxygen attack is proportional to the rte at which oxygen is transferred to the steel surface (as influenced by oxygen concentration and fluid velocity) and the surface temperature (see Viewgraph). It generally initiates as uniform corrosion upon exposed steel surfaces. Scale deposition on these surfaces reduce these initial corrosion rates, but can locally result in under deposit corrosion causing increased rates or pitting corrosion. In surface waters at ambient temperatures oxygen content ranges between 7 and 8.5 ppm. This will cause a long term corrosion rate for steel between 0.5 and 3 mm/yr. Oxygen can diffuse in significant quantities into pressurised systems (e.g. across pump seals and vessel gaskets), while systems operating below atmospheric pressure are exceptionally prone to oxygen leakage.

Oxygen CorrosionMainly of Importance in Water Injection Systems

Oxygen attack on steel is proportional to:Oxygen ConcentrationFluid VelocityTemperature

Generally results in uniform corrosion on steel surfaces

Pitting corrosion can occur under scales/deposits

At O2 concentration < 5 ppb corrosion is negligible

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Oxygen Corrosion

Solubility of O2, effect of O2 concentration and temperature on corrosion of Mild Carbon Steel in Pure Water

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9 o C

Oxygen attack is usually prevented by oxygen removal or exclusion. However, upstream oxygen removal systems, corrosion should be avoided either by the use of corrosion resistant alloys, such as selected stainless steels or non-metallic materials (e.g. Glass Reinforced Epoxy, plastic piping), or in vessels, by the use of cathodic protection. The use of corrosion resistant materials and CP throughout the injection system will eliminate the need for oxygen control equipment or chemicals, but this can only be considered if oxygen contamination of the reservoir is acceptable (i.e. no dissolved iron present). Oxygen can be removed/excluded from the water either mechanically via deaeration, vacuum-, or (gas)stripping towers. The mechanical methods are often applied to remove the main part of the oxygen from the water stream while the remainder is removed chemically using oxygen scavengers. The advantage of this approach is that less chemical is required (cheaper) and that only small amounts of sulphite (a feed stock for SRB) will enter the water via the oxygen scavenger.

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O2 Corrosion Prevention

O2 Removal or Exclusion• Deairators/Vacuum/Stripping Towers• Oxygen Scavenging

Use of Corrosion Resistant Materials• Stainless Steel alloys• GRE piping/Coating

Cathodic Protection• Eliminates need for O2 Control• Only to be considered if Reservoir can accept O2

Oxygen scavengers Oxygen scavengers are all chemicals which react with the oxygen in the aqueous phase. The most commonly used product is Ammonium bisulphide (for reaction equation see Viewgraph below). The advantages of this product include the following: • reacts fast with oxygen in water and removes one ppm of oxygen per 6 ppm

NH4HSO3. • It does not react with air, so can be stored easily • It does not require a catalyst to activate • Is normally supplied in concentrated liquid form and easy to inject into the system

to be deoxygenated. Besides above advantages the product also has some disadvantages which are: • The product is corrosive in concentrated form (requires plastic drums) • Due to the oxidation from SO3 into SO4 , it provides a food supply to SRB Other oxygen scavengers are sometimes applied in water injection systems but have other negative aspects. Sodium sulphite is a powder and unstable is solution. The reaction rate with oxygen in water is slow compared to the above ammonium bisulphide and requires a catalyst (normally tracers of Cobalt ions) to become activated.

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Oxygen Scavengers

Ammonium Bisulphide: 2NH4HSO3 + O2 ===> (NH4)2SO4 + H2SO4

• 6 ppm NH4HSO3 reacts with 1 ppm O2• Does NOT react with Air• Does not require a Catalyst• Corrosive in Concentrated Form• SO4 supply to SRB

Other Oxygen Scavengers:Sodium Sulfite : Na2SO3Sodium Metabisulfite : Na2S2O5Sulfur Dioxyde : SO2

Another product is sodium metabisulfite which when contacted with water hydrates into sodium bisulphite as follows: Na2S2O5 + H2O 2NaHSO3 The main disadvantage of sodium bisulphite over the ammonium product is that it can be supplied in much lower concentrations and therefore much larger volumes need to be injected. Sulphur dioxide is also a potential oxygen scavenger but is a very corrosive gas and potentially dangerous gas. In water with oxygen the gas forms sulphuric acid which is very corrosive. For these reasons its applications have been very limited in the field.

2SO2 + 2H2O + O2 2H2SO4 (sulphuric acid) The reason for the stability of concentrated bisulphite solutions can be found in the Viewgraph below. Oxygen does not react with the bisulphite (HSO3) ion but only with the sulphite (SO3) ion. The sulphite distribution is like the one for carbonate (discussed under scaling) depending on the pH. High concentrations of ammonium and sodium bisulphite are slightly acidic (below pH 4.5) and as can be seen from the

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Viewgraph, no sulphite is present in the product below that pH. Normal water sources have a pH value above 4.5 and as result when the product is diluted with water the pH shifts upward resulting in the formation of some sulphite. If oxygen is present in this water, it will react rapidly with the sulphite resulting in the equilibrium trying to restore the situation by forming more sulphite. The chemical equilibrium for sulphite looks as follows:

SO2 + H2O HSO3- + H+ SO3= + 2H+

Factors Affecting Sulfite Reaction RateDistribution of Sulfite Species as a Function of pH

0

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As Only SO3= reacts with O2

No reaction with O2 below pH=4,5 H2S corrosion H2S corrosion is often encountered where gas with a high H2S content is produced. H2S is a gas but very soluble in water where it behaves as a weak acid. It reacts with iron to form a very insoluble iron sulphide corrosion product and usually adheres to the steel surface as scale. It is an excellent electron conductor and is cathodic to the underlying steel resulting in accelerated corrosion at defects in the scale layer. The FeS can also lead to well plugging when precipitating in the near wellbore area. Apart from its presence in the produced gas, H2S can also be generated as result of sulphate reducing bacterial activity. H2S itself is a very toxic gas and can be fatal when inhaled at levels of 5 ppm only. H2S can be removed from water streams by means of air, nitrogen, or flue gas stripping. In case air is used oxygen corrosion has to be taken care of. H2S can be chemically removed or inactivated in water streams via oxidation with chlorine (Cl2) or hydrogen peroxide (H2O2). The reaction with chlorine is as follows:

4Cl2 + 4H2O + H2S H2SO4 + 8HCl

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The reaction with hydrogen peroxide looks like this: H2O2 + H2S S0 (free sulphur) + 2 H2O Aldehydes, generally used as biocides, also react with H2S as sulphide scavengers. Apart from acrolein, relative large dosage rates are required to remove the hydrogen sulphide. In gas streams H2S can be chemically removed by for instance the Sulferox system whereby the H2S is converted to inert Sulphur. Amine and Claus units can also be used to remove the H2S.

H2S Corrosion

Aspects:Highly Toxic and Hazardous to PersonnelGeneral and Sulphide Cracking CorrosionFeS Precipitation (Well plugging)Can be Result of SRB in System

Chemical Removal:Chlorine (only for small amounts of H2S)Hydrogen PeroxydeAldehydes (also work as biocide)

Physical Removal:Air or Fluegas Stripping

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7. HSE Aspects Properties In many of the production processes, chemicals are used to improve or optimise these processes. Also, the produced gases, liquids and solids themselves, are all mixtures of chemicals. All these chemicals have their own particular Health, Safety and Environmental specifics or properties which include for instance: Toxicity to mammals, fish, etc. carcinogenity (materials increasing the risk to develop cancer) Corrosivity (property of the material to oxidise or corrode materials) Flammability (ease of the material to burn or explode when in contact with fire) Radioactivity (emission of alpha, beta, or gamma particles) (Bio)degradation. Rate with which a (toxic) material decomposes to harmless products. The HSE properties of all chemicals used in E&P operations need to be known before their use is allowed. These properties are important to be known for all products used and produced during oil field operations as this will allow to apply measures to safeguard against the negative aspects of these products and to avoid any health safety and environmental accidents. The measures to protect against harm caused by these products can include the use of protective clothing such as masks, goggles, breathing equipment, chemically resistant gloves etc. In addition of the above properties, all chemicals which can cause damage to humans or nature, require information on how to handle in case of a chemical spill. Environmental Legislation In many countries the disposal of E&P waste is subjected to environmental Legislation. This legislation sets rules for the safe disposal of particular E&P waste streams prohibiting or minimising any negative environmental impact. The legislation differs from country to country for the different waste streams, however, the tendency world-wide is that more and more stringent rules are being applied. For instance, in many European countries, produced water is only allowed to be re-injected into the reservoir of its origin and even in this case, should comply with certain restrictions on chemical composition, etc. Even, in the absence of legislation (or a very limited legislation) in a particular country, Shell Companies world wide have to obey the Group policies and rules with regard to the Environment in all their operations. One area of increasing concern is the presence of radioactive materials in many of the E&P produced waters. In their normal concentration in the produced water, activity levels are normally far below acceptable levels. However, by co-precipation with other scales in the production facilities and tubing, the radioactive components may become enriched (the so-called Technologically ENhanced Radioactive materials, or TENR), to activity levels well above allowed levels. Removal of these scales is only allowed to be conducted by approved radiological workers.

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The best approach to avoid these operational problems is to prevent the build-up of these scales by the use of scale inhibitors. Operational wastes include, apart from the radioactive scales above, also sand and silt produced from the reservoir, wax, asphaltenes, residual emulsion, spent and unused chemicals, containers, filter backwash sludge, etc. Depending on their properties, wastes can be categorised as hazardous, or non-hazardous wastes. In particular legislation on hazardous wastes is very strict and their safe disposal requires many control systems.

HSE Aspects• HSE Aspects of Process Chemicals and Produced materials

• Toxicity (people, fauna)• Carcinogeneity (people, fauna)• Corrosivity (people)• Flammability (people, nature)• Radio-activity

• Environmental Legislation of Waste Streams

• Produced Water• Waste Injection Water• Radioactive Scales• Operational Wastes• Drill Cuttings

Since 1990, all Shell Operating Units (OU’s) are required to monitor and report the quantities of all E&P waste streams as well as indicate their disposal route. These data are used as a tool to improve the Environmental performance of these OU’s and to set benchmarks. The next Viewgraph shows the discharge of chemicals against their total use in Shell Expro UK for the year 1994. The figure shows that a relative large fraction of these chemicals is discharged.

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HSE: Chemical Discharge - ExproHSE: Chemical Discharge - Expro• Total Chemicals Used - 7,625 Tonnes.• Total Chemical Discharged to the Sea - 2,970 Tonnes (~40%)

• Total Oil in Water Discharged to the Sea - 1,154 Tonnes. 1994 Data

Fulm

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A study in 1994 in BSP Brunei, indicated that of all chemicals ordered, between 20 and 40% is wasted and is disposed. The wastage of chemicals are mainly the result of: • improper handling or storage or the use of wrong handling equipment • leakage of liquid chemical from poorly maintained chemical injection systems • inaccuracy of dosing rates or lack of attention of the operator • products having reached the expiry date either as result inadequate stock

management • accidental- or sabotage spills This disposal is sometimes controlled, for instance to hazardous waste disposal sites or by incineration but, like for spills and leakages, can also be uncontrolled often resulting in a negative environmental impact. For many of the accidental spills measures can be taken to prevent the product to cause damage, for instance by installing drip pans underneath chemical injection pumps or providing rain cover for chemicals stored in metal drums. By systematically looking at the potential chemical waste streams and taking simple measures to avoid spillage, a significant reduction in the waste volumes is possible. This reduction has next to the environmental benefit also a financial reward as less chemicals have to be ordered.

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Minimise Chemical WasteMinimise Chemical WasteEstimated 20-40% of All Chemicals is Wasted as Result of:

• Improper Handling/Storage• Leakage from Injection Pumps and Containers• Overdosage• Products Expiry Date has Passed• Remains in Empty Container• Spills

It is common wisdom that most process chemicals have a negative impact on the environment. For instance demulsifiers because of their interfacial activity, often have some toxicity to marine life. Other chemicals are not directly toxic but have an impact on the environment because they consume oxygen from the water during their degradation process. For some products, the period that they negatively affect the environment can be short lived, while for other products this period can be very long. To minimise the impact of process chemicals, one option could be to prevent these chemicals to contaminate the environment (e.g. water, soil or air). In practice this is not possible as, apart of spillages, eventually a portion of these products has to be disposed of. Therefor, the best option to avoid impact is by not using chemicals. In practice, it is sometimes possible to engineer-out certain process problems. For instance, for some crude streams with emulsion problems, instead of chemicals heat can be applied to fully break these emulsions. In another case it is sometimes possible to prevent stable emulsion by avoiding excessive pressure drops in the production facilities. Up till now it has not been possible to engineer out all problems, and process chemicals are still quite often necessary in order to allow undisturbed production of hydrocarbon streams. Where chemicals are required, it is important that environmental aspects are also taken into consideration in the screening/selection process. Apart from the (cost)effectiveness and performance of the product, the most environmentally suitable product should be chosen.

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If Used with Unsufficient Care:Most Process Chemicals Have a Negative Impact on(Human) Health or the Environment

This Impact Can be Short-lived (e.g. Biodegradable Products)Or Persist for a Very Long Time (e.g. Certain Radio Isotopes, pesticides, etc.)

The Impact Can be Minimised by:• Using Most Environmentally Suitable Product• Applying Safe Handling Practices• Avoiding Spills• Minimise Chemical Waste

HSE Aspects of Process ChemistryHSE Aspects of Process Chemistry

For the environmental impact of a chemical to be established, many details about the product are required. Firstly, the chemical supplier has to provide all relevant toxicity and environmental data including biodegradation rate and how to handle in case of spills, contamination and accidents. Another important aspect when using chemicals is to know which part of the product is soluble in water and disposed with the production water and which part is oil (or gas) soluble. Eco-toxicity testing with a Micro-Tox unit can be used to measure the toxicity of produced water containing chemicals. This analytical method, being a qualitative testing, can be used to quickly measure the compounded effect of toxic chemicals in produced water. Another very important aspect in the selection of chemical relates to the local environmental legislation on waste streams. Legislation can be very complex and can differ from country to country. For countries where no specific or only limited legislation exist, Shell Companies are to consider the Group policies and advise. To assist Operating units in the management of their waste streams EP-HE, the EP Health, Safety and Environmental department, has issued the EP 95000 guidance documents. A significant part of these documents cover environmental subjects and include the following: • EP 95-0375 Environmental Quality Standards - Air • EP 95-0376 Monitoring Air Quality • EP 95-0377 Quantifying Atmospheric Emissions • EP 95-0380 Environmental Quality Standards - Water • EP 95-0381 Monitoring Water Quality

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• EP 95-0385 Environmental Quality Standards - Soil and Groundwater • EP 95-0386 Monitoring Soil and Groundwater • EP 95-0387 Contaminated Soil & Groundwater • EP 95-0390 Waste Management Guidelines • EP 95-0391 Classifying Waste • EP 95-0397 Oil Spill Dispersants These guidelines, in addition to local legislation, can be used to select the most acceptable (long-term) disposal route for the individual waste streams of an Operating Unit.

Environmental AspectsEnvironmental Aspects• Supplier to Provide Toxicity/Environmental Data

• Which Part of Chemical is Disposed with Water Phase

• What is Eco-Toxicity of Product (Micro-Tox)

• What is Local Legislation wrt Use/Disposal of Products

• Identify (Longterm) Acceptable Disposal Options for:• Chemical Waste• Water Phase• Sludge• Deposits/Scale

Minimise Impact This Viewgraph illustrates options which can be used to minimise the environmental impact of waste streams by applying a management approach. For produced water options are listed in order of environmental preference and should be followed where technically feasible and economically acceptable. The first and environmentally most attractive option is to avoid or significantly minimise the production of water. Technically this is possible by selecting the completion interval such that water breakthrough does not occur or very late in the production lifetime of the wells. This can sometimes be in contradiction with the production technically optimum completion interval. A second possibility could be to apply downhole dehydration whereby the downhole separated water is directly pumped into the water leg of the formation rather than being produced to surface. Where the minimise production option has been optimised, the next step is to dispose this water in the most acceptable manner. Virtually all countries accept re-

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injection of this water into the original reservoir as the best solution, sometimes under the condition that this water is not contaminated with toxic chemicals. Another, almost as good solution is to inject the water into a dry or non-potable aquifer. The definition potable or non-potable can differ from place to place but in most situations the salinity of the sea water is used as the limit value. The next option is disposal of the water into the sea. All countries have set quality criteria for this water before it is allowed to be disposed. One of these criteria related to the allowed oil in water content which is in most countries 40 mg per litre in offshore waters. Apart from the oil content, many countries since recently also have set limits to the toxicity and oxygen demand. Disposal to near shore or surface waters is one of the least attractive options and water quality requirements maintained by most legislators, therefor are more tight when compared to offshore disposal. For solid wastes sludges and deposits, are similar philosophy is applied where again avoiding is the best option. Downhole injection of sludges, including drilling muds, is becoming more popular. Incineration is also applied often as an acceptable manner to de-toxify certain chemical wastes. Stabilisation can be used where waste materials are encapsulated with insoluble materials such as lime cement, etc. Controlled land farming is also applied where the leachates from the area can be tested to avoid leakage of hazardous material from the land farm area.

Minimise Environmental ImpactMinimise Environmental ImpactWater Management:• Minimise Production (Downhole Dehydration/Completion)• Re-Injection into Original Reservoir or Non-Potable Aquifer• Disposal Into Sea after Treatment to Required Quality

Standards• Disposal Into Near-Shore or Surface Waters after TreatmentSludges/Deposits• Avoid Generation/Production• Downhole Injection• Incineration• Stabilisation (e.g. with Lime)• Controlled Landfarming

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Introduction to Production Chemistry

Documents

production processes

production facilities

production environment

emulsions objectives

potential production

organic deposits

emulsions constituents

emulsions contents objectives