Potentials & Applications for the ProPure Co-current Contactors

Trond O. Høyland & Harald Linga ProPure AS, Bergen, Norway

Abstract Efficient fluid mixing and exposure between the fluid phases are essential issues for unit operations including mass transfer (physical flashing, extraction or chemical reactions) or dispersion of speciality chemicals into the multiphase flow. For this purpose ProPure has developed contactor solutions based on combinations of an injection mixer and an in-line multiphase flow remixer. Traditionally in gas purification, the fluid exposure between gas and liquid is carried out by means of counter-current flow in vertical vessels. Compared to counter-current contactors, the theoretical loading capacity of a co-current contactor is always lower than or equal to that of a counter-current contactor whenever selectivity is not required. As the ProPure co-current contactors yield higher sour gas removal selectivity, the ProPure gas treatment technology is competitive for e.g. the removal of H2S with regenerative amine solvents and irreversible scavenging chemicals. For a typical offshore application for selective H2S-removal, the solvent circulation rate with co-current contactors can be reduced with 60 % compared to a conventional amine plant. Using H2S scavenging with co-current contactors rather than conventional injection and mixing technology, laboratory and field tests have demonstrated 30-40 % reduction in consumption of the chemical. The ProPure contactors have also been designed for liquid purification, and have been delivered for liquid-liquid extraction, injection of chemicals into liquid flow as well as devices for enhancing rapid and efficient phase transition between gases and liquids. In this context the contactor has been developed for desalting and dehydration of crude oil. Increased mixing efficiency at reduced pressure drop and reduced wash water consumption has yielded improved desalting and separation of oil from water. CTour® is a new concept developed by ProPure for removal of environmentally harmful components from produced water. Based upon field testing and pilot, the CTour® concept reduces discharge of free oil by 70-90% and dissolved components by 15-90% dependent on the nature of the components. Removal of predominantly oil soluble components is better than 70%. Introduction Fluid mixing operations are essential unit operations both in the oil & gas industry and in the chemical process industry in general. The industrial investments related to mixers are considerable, and as an example the investments in the US on mixers in 1990, exclusive vessels and reactors, were estimated to $150 Million/year (Smith, 1990). Proper fluid mixing or contacting is decisive for the product quality and the operational reliability for downstream process equipment. Key features for the contactor or mixer relate to efficiency, design and scale-up, mechanical robustness and applicability for retrofitting and debottlenecking. For gas purification processes the efficiency is primarily measured according to the amount of solvent needed to reduce the specified concentrations of impurities such as H2S and CO2 to specified levels. In 1997 Statoil initiated the development and testing of a co-current gas-solvent contactor. The technology was based on ProPure`s (formerly Framo Purification) expertise and experience within gas-liquid mixing and multiphase flow. Since 1997 many other applications have been developed, among them scavenging of H2S from natural gas (Knudsen et al., 2002; Linga et al., 2002) and selective H2S-removal from refinery off-gas and from high pressure hydrocarbon gas using amines (Linga et al., 2001; Nilsen et al., 2001 & 2002). The ProPure contactors have also been designed for liquid purification (Nilsen & Linga, 2002), and the ProPure co-current contactors have been delivered for liquid-liquid extraction, injection of chemicals into liquid flow as well as devices for enhancing rapid and efficient phase transition between gases and liquids. ProPure`s range of patented liquid/liquid contactors also comprises a design specially applicable for desalting and dehydration of crude oil. This paper summarizes the key components of the ProPure contactors and selected applications with performance data for the contactors are shown.

Key components of the ProPure contactor technology As key components in the co-current contactors, ProPure applies a variety of designs based on two basically different mixers, the injection mixer and the in-line mixer. The ProPure injection mixer The ProPure injection mixer as shown in Figure 1, is a gas flow driven “one-shot” contactor. This means that the liquid (solvent) supplied to the contactor is transformed to small liquid droplets by locally increasing the dynamic pressure of the gas flow. Any mixing represents a permanent pressure drop. With this injection mixer the permanent pressure drop is associated with the momentum transfer from the gas to the liquid. This is accomplished within a short distance, rather than exerting the momentum transfer between phases during the passage of relatively long flow conduits exhibiting high wall shear stress. In this way the ProPure mixers differ from most static mixers (Streiff & Rogers, 1994). As a result, a high degree of mixing with a correspondingly large interfacial surface between gas and liquid can be achieved at a low to moderate pressure drop with the injection mixer. The droplet generation mechanism can be considered as a process where an annular liquid film initially is supplied homogeneously at the pipe circumference, and, secondly, exposed to gas flow with high inertial force. The high ratio between the inertial force and the surface tension force (the Weber number) favors break-up of the entrained liquid filaments into small droplets (secondary break-up). As a result, a high exposure area between the gas and liquid, well distributed over the pipe cross-section, is generated. As the co-current contactor is operated at much higher gas flow velocities than a counter-current contactor, the size of the co-current contactor can be smaller. Also, operational difficulties in connection with flooding and/or non-homogeneous gas-liquid distribution, which are common in counter-current absorption towers, are not a problem with co-current contacting. The ProPure in-line mixer The principal layout of the ProPure in-line mixer is shown in Figure 2. With regards to operation, the in-line mixer has similarities with a cylindrical plug valve. The in-line mixer is typically made with one or two cylinders depending on the turn-down in flow rate required. The cylinders can be rotated so that the mixer either can be set in mixing position or in full bore position. The mixer can therefore be operated so that the pipeline in which it is mounted can be pigged. As the cylinders are designed with different pairs of in- and outlets, the mixing intensity can be varied. The channels at the mixer inlet side are arranged such that the generated jet-flows are directed towards a common focus line according to “finger folding” pattern between the channels pointing upwards and downwards respectively. A certain shear stress is needed for the break-up of the dispersed phase. With the channel arrangement, high shear flow conditions in the whole mixing chamber are enabled, and thus efficient mixing can be achieved with a low or moderate pressure drop.

Gas

Solvent

Figure 1. The ProPure injection mixer (US Patent No. 6,284,024 B1)

Figure 2. The ProPure in-line mixer. (US Patent No. 5971604 ”Mixing valve with adjustable elements and central chamber”).

At the outlet side, the channels are oriented in parallel to the pipe axis. As the outlet channels also are designed to represent a certain pressure drop exceeding the frictional pressure drop for the pipe flow, the flux of the homogeneous multiphase flow mixture will be distributed evenly over the pipe cross section by the parallel outlet channels. The pressure drop over the outlet also serves to reduce short-circuiting of the flow within the mixer chamber. Selective H2S removal from natural gas The common approach towards selective H2S removal of natural gas is the use of an appropriate chemical with selective absorption characteristics in combination with conventional absorption columns. Due to the very high gas-liquid interfacial area available for mass transfer and the short reaction time obtained in the ProPure co-contactor, this equipment has a significantly higher selectivity for H2S over CO2 than counter-current contactors. Several presentations of the compact alkanolamine plant concept have already been published, see e.g. Nilsen et al. (2002). The application is selective removal of hydrogen sulphide (H2S) in the presence of carbon dioxide (CO2), based on the novel co-current ProPure gas-liquid contactor and a regenerative solvent. The key technology of the compact alkanolamine plant is the ProPure co-current contactor, which is a gas flow-driven “one-shot” contactor based on the injection mixer. The co-current contactor replaces the counter-current tower in a conventional amine plant. The small liquid droplets generated promote a high gas-liquid mass transfer rate at low to intermediate permanent pressure drops. The compact alkanolamine plant’s selectivity is achieved by the short retention time combined with the high gas-solvent exposure area throughout the contactor. Compared to counter-current contactors, the gas residence time is considerably shorter, typically 30 –100 times shorter. Therefore, CO2 co-absorption is significantly reduced, allowing higher solvent H2S-loading capacity. Tertiary amines, such as MDEA, yield selective H2S-removal as the solvent proton reaction with H2S is instantaneous whereas the reaction with CO2 undergoes several (slow) intermediate reactions. The higher the ratio between the CO2 and H2S concentrations, the more competitive the compact alkanolamine plant becomes. Due to the contactor operating at high gas velocities, its size is much smaller compared to conventional equipment. The selective nature results in significantly lower circulation rates, which reduces the amine regeneration system’s overall size.The contactor mixing section is crucial for the selectivity and the resulting performance. Typically, the selectivity towards H2S is 35 to 100 times higher for the contactor mixing section than for the downstream pipeline. Process Application For a given application, the length of the contactor pipeline and the solvent feed rate can be varied in order to arrive at the specified H2S-concentration for the gas while minimising the amount of co-absorbed CO2. The droplets generated in the contactor mixing section will undergo phases of coalescence and deposition to the liquid film on the downstream pipe wall. Thus, the effective reaction area will inevitably drop downstream if no efficient re-mixing is imposed. This effect reduces both the actual absorption rate and the selectivity towards H2S in the contactor pipeline. Consequently, it is possible to adapt the process piping configuration to the requirements of a given application, e.g. for a selective H2S removal application a very short downstream piping layout will be necessary. Multiple solvent feed configuration and gas-liquid re-mixing can also be used in order to achieve optimal performance and process control. Due to the very high selectivity towards H2S obtained in the contactor, the loading capacity for H2S will increase. With the higher H2S loading capacity, the solvent circulation rate in the process can be reduced correspondingly. Using the ProPure kinetic model implemented in HYSYS Process together with the experimentally determined specific reaction rates as input, the design solvent feed rate can be calculated. Figure 3 shows a principal flow scheme for Figure 3. Process Layout for compact alkanolamine plant

the compact alkanolamine plant. The process is based on a conventional absorption-regeneration cycle. The main difference is the absorption section which can be extended to multiple stages which is attractive if a high degree of H2S-removal is necessary to achieve H2S-outlet specification. The weight of an amine plant is dependent on the amine circulation rate and the size of the gas-liquid contactor. For a high-pressure gas sweetening plant, a conventional absorption column can contribute to half of the dry process equipment weight. For the compact co-current process the contactor is not much heavier than a pipe spool piece, and the gas-liquid separator can be integrated in the dehydration column or compressor suction scrubbers, thus only adding a few extra meters of shell weight. For the worst case when a dedicated scrubber must be applied, the associated weight will still be less than half of the weight of an absorption column. H2S scavenging The operators in the North Sea agreed with the Norwegian Pollution Control Authority (SFT) to target 2005 as the year for “zero emission of harmful compounds”. As the discharge of scavenger chemicals at some North Sea offshore installations has represented a significant contribution to the environmental impact factor (EIF), this has been an obvious motivation for supporting the development of new technology for reducing the scavenger consumption. H2S scavenging is usually carried out with chemical utilisation far from the theoretical potential of the scavenger. For polishing purposes (achieving the H2S-specification of 2.5 ppmv), typically less than 30 % utilisation of the solvent capacity is reported. This is due to the small exposed area (contacting area) between the gas and scavenger phase for most injection methods, and also in the downstream process equipment (mainly piping equipment and heat exchangers). Another factor reducing the efficiency may be the co-absorption of CO2. The Statoil K-Lab scavenging loop offers possibilities for varying types and locations of injection mixers, pipeline configuration and length. Statoil has carried out scavenger testing at K-Lab since 1999, and it has been reported that typically 30 % reduction in the use of chemical can be obtained with ProPure`s technology in comparison with conventional technology for H2S scavenging. The latest publication from this work was presented by Linga et al. (2002). Process Application The first installed large-scale ProPure injection mixers (24” systems) have been in operation at the offshore field Åsgard B from July 2001 onwards, and so far the H2S-treatment has been based on feeding the scavenger to the two horizontally mounted ProPure injection mixers installed in series. The first performance tests at Åsgard B were carried out by Statoil in July 2001 with an inlet H2S-concentration of 7 ppmv. With the scavenger injection rate applied, the outlet concentration was measured to be below 0.5 ppmv, which is far below the specification of 2.5 ppmv. The results from testing at K-Lab and field testing are shown in Figure 4. This polishing performance yielded scavenger consumption close to 12 litre/kg H2S. Comparing with the data for a similar mixer configuration and operation at K-lab, the field data from Åsgard B indicate that the scale-up of the ProPure injection mixers from 2” to 24” yields an equally good or even better scavenger performance. For the Åsgard B data, results with close to 50-50 scavenger distribution between the two mixers are selected.

H2S

-con

cent

ratio

n re

lativ

e to

inle

t [ %

]

distance from injection point [m]

H2S

-con

cent

ratio

n re

lativ

e to

inle

t [ %

]

distance from injection point [m]Distance from injection point [m]

H2S

-con

cent

ratio

n re

lativ

e to

inle

t [%

]H

2S-c

once

ntra

tion

rela

tive

to in

let [

% ]

distance from injection point [m]

H2S

-con

cent

ratio

n re

lativ

e to

inle

t [ %

]

distance from injection point [m]Distance from injection point [m]

H2S

-con

cent

ratio

n re

lativ

e to

inle

t [%

]

Figure 4. H2S-data scaled with the inlet concentration with serially mounted FramoPure injection mixers, 50-50 distribution and quill.

In order to arrive at 3 ppmv with the quill injection, it is estimated that the pipeline (or the residence time) has to be increased with a factor of 3, i.e. increasing the pipeline from 50 to 150 m. Alternatively this outlet H2S-specification can be achieved by increasing the injection rate with a factor of more than 5. Again this clearly demonstrates that in order to evaluate the scavenging performance both the degree of removal and the scavenger consumption must be considered. The data also illustrate the potential of reduced scavenger consumption and reduced pipe lengths associated with the installations of efficient injection mixers. Since the Åsgard installation, more than thirty injection mixers for H2S scavenging have been delivered, comprising some of the largest offshore installations in the North Sea, the Sangachal Terminal Azerbaijan, IKA Field Croatia and Bongkot Thailand. Field testing have been carried out on some of these installations, and the reduction in scavenger consumption after implementing injection mixers compared with alternative injection methods (quill, nozzle, static mixer) are shown in Figure 5. Desalting of crude oil Produced crude oil is a mixture of hydrocarbon liquids, water, natural gas and salts. Natural gas and free water are separated by gravity. The salts are dissolved in water, called brine water, except for a small amount of oil-coated salts. These salts are sourced to potentially cause corrosion, fouling, plugging, scaling, coking, slagging, catalysts poisoning, and other detrimental effects on plant refinery operation. Thus, desalting is a key preparation step for crude oil separation and refining processes. The desalting process works by washing the crude with wash water and then removing the water to leave dry, low salt crude oil. A typical process layout for a desalting unit is shown in Figure 6. A conventional desalting process comprises injection of wash water (3-6 % of crude oil flow rate) utilizing a static mixer or mixing valve for washing the crude oil with water. The conventional static mixer / mixing valve yields a high pressure drop which combined with non-homogeneous shear forces serve to generate of undesirable stabile emulsions of water and crude oil. Electrostatic coalescers, imposing an electrical field which enhancing the water droplets coalescence, are used for separating the salty wash water from the crude oil. Implementing the ProPure technology for improved crude oil desalting at existing crude treatment plants, implies replacement of the conventional static mixer / mixing valve with the ProPure mixing system. The ProPure mixing system, consisting of a combination of injection mixers and in-line mixers or a single in-line mixer, depending on the application, increases the mixing efficiency considerably and at the same time reduces the pressure drop and the shear forces added to fluid.

2826

42

35

0

5

10

15

20

25

30

35

40

45

K-Lab 2" Gullfaks B 8" North Sea 8" Åsgard B 24"Scavenging application & pipe dim.

Red

uctio

n in

sca

veng

er c

onsu

mpt

ion

[ % ]

Figure 5. Reduction in scavenger consumption with injection mixers compared with alternative injection methods

Effluentwater

LCLC

Crude oil

Demulsifierchemical

Desaltedcrude oil

Wash water

Heatexchanger

Recycle wash water pump

1st Stage desalter

2nd Stage desalter

Wash water pump

ProPuremixing system

ProPuremixing system

Effluentwater

LCLCLCLC

Crude oil

Demulsifierchemical

Desaltedcrude oil

Wash water

Heatexchanger

Recycle wash water pump

1st Stage desalter

2nd Stage desalter

Wash water pump

ProPuremixing system

ProPuremixing system

Figure 6. Typical process layout for a desalting unit

Process Application The first installed full scale ProPure mixing system (14” in-line mixer) for desalting of crude oil has been in operation at the Statoil Mongstad Refinery, Norway, since January 2006 onwards. The in-line mixer, see Figure 7, is installed in parallel with the existing conventional static mixer / globe valve. The existing conventional static mixer / globe valve represents a high pressure drop which creates non-homogeneous shear forces and creation of undesirable stabile emulsions of water and crude oil. The desalting system at Statoil Mongstad is similar to the process layout given in Figure 6 and the in-line mixer is installed upstream the 1st stage desalter. The full scale ProPure mixing system (14” in-line mixer) for desalting of crude oil at Statoil Mongstad has been in operation successfully for six months treating 1000 t/hr (2.2 M lbm/hr) crude oil with an API of 36 (light oil) at 10 bar and 120 0C. Parameters to be tested are pressure drop over the in-line mixer, wash water injection flow rate and demulsifier injection flow rate. To be able to evaluate the performance of the in-line mixer, reference tests with the existing static mixer / globe valve have been carried out. The tentative performance data indicate that ProPure in-line mixer yields acceptable desalting performance with 25 % reduction in fresh water injection rate compared to the existing static mixer / globe valve at Statoil Mongstad. Typically, 65 % reduction in oil in water from the 1st stage desalter is achieved. Mixer internals covering the range 0.15-0.8 bar pressure drop over the in-line mixer has been tested, and typically the water content in desalted crude from 2nd stage desalter separator has been within 0.07 – 0.20 vol %. Removal of dispersed and dissolved hydrocarbons from produced water For the Norwegian sector of the North Sea there is a strong focus on reducing the potential environmental impact from discharges of produced water. The operators together with the Norwegian authorities have agreed on “Zero Harmful Discharge Strategies”. In addition, the new OSPAR regulations demanding less than 30 mg/l dispersed oil in discharge water, and a 15 % reduction in total oil content in the produced discharged water compared with the year 2000 level will be implemented by 2006. The CTour® technology serves to remove dissolved hydrocarbons as well as enhanced removal of dispersed oil as based upon condensate injection into the produced water. The principle of the CTour® process is to use a liquid condensate as a coalescing and extraction medium. The condensate serves to enhance the removal of dispersed oil in the downstream separation equipment by coalescence between the small dispersed hydrocarbon droplets and the larger and more easily separable condensate droplets. Offshore tests show that “heavy” dissolved hydrocarbons, like C6+ phenols and PAH, will to a high degree follow the dispersed hydrocarbons. There is also potential for a high level of extraction of the remaining dissolved components from the produced water to the condensate phase. Typically 99.5% of the condensate is separated in the hydrocyclone and routed back to main process.

Figure 7. ProPure full scale mixing system (14” in-line mixer) installation for desalting at Statoil Mongstad Refinery

Suction Scrubber

Hydrocyclone

CompressorGas

Oil

CleanWater Condensate Pump

CTourProcess

Water

1. Stage Separator

2. Stage SeparatorMixers

StandardProcess

Suction Scrubber

Hydrocyclone

CompressorGas

Oil

CleanWater Condensate Pump

CTourProcess

Water

1. Stage Separator

2. Stage SeparatorMixers

StandardProcess

Figure 8. CTour® Process Flow Diagram

A flow diagram of the CTour® process is given in Figure 8. The CTour® process includes the following steps and constraints:

• A suitable condensate stream is harvested from the production plant. • Inject 0,5 – 1,5% (v/v) condensate in liquid form into the produced water stream • Ensure sufficient condensate dispersion and mixing with ProPure mixing technology – with

respect to contact area and distribution of condensate in the entire produced water pipe flow. • Keep pressure drop over the ProPure mixers at a minimum in order to avoid further

dispersion of oil droplets. • Establish adequate contact time between condensate and water – with respect to the

extraction process – and coalescence of oil and condensate droplets • The condensate containing the contaminates is separated from the water in a separation

process - like a standard hydrocyclone • The reject, containing condensate and contaminates, is cycled back to the production

process. The ProPure mixer train consists of the ProPure injection mixer and in-line mixer in series. The target for the ProPure mixer train as installed in the CTour® process is to transfer the injected condensate into a close to uniform droplet size distribution at separable droplet sizes and high exposure area at acceptable pressure drop. Process Application The CTour® technology will be implemented for all Statfjord installations within 2006. Statfjord is one of the largest offshore installations in the North Sea and CTour® will treat approximately 1,4 mill bpd of water from the field. The CTour® low pressure pilot of Statfjord C has been in operation since March 2004, whereas the first high pressure CTour® installation, at Statfjord C, has been in operation since 2005. The CTour® low pressure pilot installed at Statfjord C has demonstrated to be robust towards variations in inlet concentrations and flow rate. Increased removal effect for most EIF component groups up to 0.75 vol% condensate injection has been confirmed. In addition, up to 40 % reduction of the corrosion inhibitor discharge has been reported. The overall performance of the LP hydrocyclone base line has increased from approximately 70% to 85-90%. Dispersed oil out of LP hydrocyclone has been as low as 1 – 5 mg/l. Conclusions Efficient fluid mixing and exposure between the fluid phases in concern are essential for unit operations including extraction, mass transfer (physical flashing or chemical reactions) or dispersion of speciality chemicals into the multiphase flow. ProPure has developed contactor solutions based on combinations of an injection mixer and an in-line mixer. The performance for an amine based process based on the ProPure contactors is demonstrated; selective H2S-removal from natural gas. The compact alkanolamine plant serves to reduce solvent circulation rate as compared to conventional amine technology. The reductions in CAPEX, size and OPEX are particularly pronounced the higher the CO2-concentration. For H2S scavenging, the injection mixer reduces scavenger consumption with 30 % compared to conventional technology. The full scale implementation of ProPure technology for desalting at Statoil Mongstad Refinery has shown to yield acceptable performance with 25 % reduction in fresh water injection rate as compared to the existing static mixer / globe valve. Also improvements for oil in water from the 1st stage desalter and salt content in desalted crude have been recorded for low and moderate pressure drop. The CTour® low pressure pilot installed at Statfjord C for treatment of produced water has successfully been in operation since 2004. The system has demonstrated to be robust towards variations in inlet concentrations and flow rate. Increased removal effect are recorded for most EIF component groups up to 0.75 vol% condensate injection, and up to 40 % reduction of the corrosion inhibitor discharge with produced water is achieved. The overall performance of the LP hydrocyclone base line has increased from approximately 70% to 85-90% with the CTour® installation. Dispersed oil content in treated water has been as low as 1 – 5 mg/l.

References Baker J. R & Rogers J.A (1989) ”High Efficiency Co-Current Contactors for gas Conditioning Operations”, Laurence Reid Gas Conditioning Conference, Norman, Oklahoma , 1989. Carter T. G., Behrens S.D. & Collie III J.T (1998) “Addition of Static Mixers Increases Treating Capacity in Central Texas Gas Plant” 77th GPA Annual Conv., Tulsa, Oklahoma , 1998. Isom C. & Rogers J. (1994) “Sour –Gas Treatment Gets More Flexible”, Chemical Engineering, July 1994. Kane L. & Romanow S. (2001) “Improved Contactor removes more H2S”, Hydrocarbon Processing May 2001, pp. 19-20. Knudsen B., Tjelle S. & Linga, H. (2001) “A New Approach Towards Environmentally Friendly Desulphurisation”, Environment in Oil and Gas Exploration and Production, Kuala Lumpur, Malaysia, March 2002. Linga H., Nilsen E., Nilsen F.P., Soerum P.A., Johansen S. & Pedersen T. (2001) “New Selective H2S Removal Process for the Refining Industry”, NPRA 2001 Annual Meeting, New Orleans. Linga H., Høyland T., Nilsen I., Nilsen F.P. & Knudsen B. L. (2002) "Efficient Injection Mixers Reduce the Scavenger Consumption in H2S Removal ", GPA Spring Conference 2002, Bergen, Norway. Nilsen F.P., Lidal H. & Nilsen I. (2002) “Novel Contacting Technology Selectively Removes H2S”, Oil & Gas Journal May, 2002 Nilsen F.P, Linga H. & Lidal H. (2001) ”Selective H2S-removal in 50 ms”, GPA Annual Conference 2001, Amsterdam, September 2001. Nilsen F.P, Nilsen I. & Lidal H. (2002) ”Selective H2S-removal applications using novel contacting technology”, GPA Annual Conference 2002, Dallas, March 2002. Nilsen F.P. & Linga H. (2002) ”Potential & Applications for the ProPure Co-current Contactors”, IFP Sessions, Paris, October 2002. Parkinson G. (2001) “A little contactor does a big job in H2S removal“, Chemical Engineering April 2001, pp. 18. Schneider G. (1983) “Static Mixing Units in the Petroleum Industry”, Sulzer Technical review, 1/1983. Smith J. M. (1990) “Industrial Needs for Mixing Research”, Trans. IChemE, Vol. 68, Part A, Jan. 1990. Streiff F.A. & Rogers J.A. (1994) “Don`t Overlook Static-Mixer Reactors”, Chemical Engineering, no. 6, 1994. Torvik H., Bergersen L. & Paulsen C (2005) “One Year of Operational Experience with CTour at Statfjord C”, 3rd Produced Water Workshop NEL, Aberdeen, UK, April 2005.

Appendix A. Technology and application summary for ProPure co-current contacting

Business area Application Process Fluid systems Technology advantage

Gas Processing H2S scavenging Chemical injection system H2S scavenging chemical/natural gas Reduced chemical consumption

Selective H2S removal Compact Alkanolamine Plant (CAP)

Amine/natural gas Improved H2S selectivity

Bulk CO2 removal Compact Alkanolamine Plant (CAP)

Amine/natural gas Reduced contactor size

Selective H2S removal for refinery off-gas

3-stage amine treatment Amine/natural gas Improved H2S selectivity

Partial dehydration Co-current dehydration Glycol/natural gas Reduced contactor size

Hydrate inhibition Chemical injection system Glycol or methanol / natural gas Increased efficiency

Oil Processing Desulphurisation Chemical injection system Amine or caustic/petroleum or LPG Improved selectivity and efficiency

Desalination Chemical injection system Water/oil with salt Improved efficiency

Viscosity adjustment Mixing system Condensate/oil Efficient homogenisation

Additive mixing Mixing system Additive/petroleum Efficient homogenisation

Contaminant removal Injection system Sulphuric acid/petroleum Improved chemical efficiency

Water in oil sampling Mixing system Oil with water Efficient homogenisation

Water-oil separation Mixing system Water/oil/de-emulsifier Efficient homogenisation

Production Chemical injection

Flocculant injection Chemical injection system Chemical/produced water Improved chemical efficiency

Antifoam injection Chemical injection system Chemical/amine or other Improved chemical efficiency

Corrosion inhibitor injection Chemical injection system Chemical/process liquid Improved chemical efficiency

Drag-reduction chemical Chemical injection system Chemical/pipeline stream Improved chemical efficiency

H2S removal from well-stream Chemical injection system H2S scavenger/wellstream Improved chemical efficiency

Biocides injection Chemical injection system Chemical/injection water Improved chemical efficiency

Water treatment Organics removal CTour Condensate/produced water Light weight organics removal

Water stripping Gas-liquid flow mixing Gas/Injection water Improved stripping efficiency

Methanol removal Gas-liquid flow mixing Methanol/process gas Improved stripping efficiency

Other mixing applications

Homogenisation upstream of mass flowmeter

3-phase flow mixing Gas/oil/water Efficient homogenisation

Heat-exchanger refrigerant homogenisation

Gas-liquid flow mixing Gas/oil/water Efficient homogenisation

De-bottlenecking and process studies

LPG removal from amine Gas-liquid mixing LPG contaminated amine/process gas Improved stripping efficiency