Downstream in the oil and gas industry

Crude unit

The refining of crude oil begins in the crude unit, whose main role is to separate out the various components.

How crude units work

Heavy crude oil typically contains salts. Chloride salts not only cause plugging downstream in the refining process, but also corrode equipment in the form of hydrochloric acid (HCl) – formed by hydrolysis under high temperatures. Crude oil with a significant salt content must first go through a desalter to remove the impurity. In this pretreatment step, crude oil is heated to slightly above the boiling point of water, then mixed with fresh water to dilute the salt. Next, the mixture goes to a settling tank for a separation of the oil and salt water. An electrostatic field accelerates the separation process.

After desalting, the crude oil is heated to about 540 °F (280 °C). This partially vaporised feedstock enters from near the bottom of the crude distillation unit (CDU), also called atmospheric distillation unit because processing occurs close to atmospheric pressure: 1.2 to 1.5 atm (17.6 to 22 psi) at the top of the column. This column has a reboiler at the bottom and a condenser at the top, creating a temperature gradient. The fractions with a higher boiling point – the heavier, less volatile compounds – remain near the bottom, while the fractions with a lower boiling point – the lighter, more volatile compounds – rise to the top. Perforated trays stacked along the column allow the lighter compounds to keep rising while the heavier compounds trickle downward. The separated hydrocarbon components, or fractions, are drawn off at various heights along the distillation column according to their boiling points.

Residual oil can be further separated, but thermal distillation cannot occur at atmospheric pressure because the required high temperatures would damage the hydrocarbons.

For additional distillation, the residual oil enters a vacuum distillation unit (VDU). In pressures as low as 10 inH₂O (0.36 psi), the boiling points of heavier oils is low enough to avoid thermal decomposition, or cracking. The vacuum furnace heats the residual oil to about 750 °F (400 °C), where it vaporises in the low-pressure environment and fractionates into various components for further processing and refining:

• Light gas oil and heavy gas oil (also called vacuum gas oils) – to be made into lube oil base stocks or as feedstock for hydrocrackers and fluid catalytic cracking (FCC) units
• Vacuum residue – as feedstock for coker units, FCC units, hydrocrackers, and hydrotreaters

Measurement solutions for crude units

There are three main applications for flexible multipoint temperature assemblies in a crude unit:

• Flash zone coke formation monitoring. Both atmospheric and vacuum distillation columns have flash zones, where some of the hot feedstock “flashes” into vapour upon entering the column. By radially measuring the temperature distribution for hot spots in the flash zone packing, operators can detect early coke formation and adjust the wash oil rate accordingly to minimise or eliminate coke deposits.
• Temperature monitoring of the tower top and overhead temperature gradient. As the overhead gases cool, it is possible for different salts – ammonia chloride or salts formed from overhead inhibitors – to crystallise at different temperatures ahead of the overhead wash system. Early formation can lead to salt deposition and metal corrosion. A multipoint solution allows operators to better control the temperatures at the tower top in order to minimise or eliminate early salt formation.
• Tray temperature measurement. A multipoint thermocouple is a simple way to take multiple temperature measurements from a single nozzle.

Furnace tubeskin thermocouples

WIKA offers innovative thermocouple solutions for fired heaters. Thanks to extensive thermocouple testing at our state-of-the-art R&D facility near the Houston Ship Channel, we can help determine the proper configuration and placement of temperature sensors for your furnaces.

Regardless of its placement location, the thermocouple has to be routed and installed correctly. For example, users must account for the furnace tube’s thermal expansion as well as protect the sensor from direct heat coming from the burners. If routed and installed incorrectly, the thermocouple is likely to suffer a shorter service life and could even malfunction.

With WIKA’s advancements in tubeskin thermocouple technology, accuracy is not the only thing that has been optimised. Ease of installation is also a key feature of our temperature measurement solutions, as our field service personnel continually collaborate with WIKA design engineers to streamline the process. Whether the sensor has a moulded heat shield or not, installation is quick and reliable – every time.

Coker unit

Coker units use high temperature (< 900 °F / 480 °C) and high pressure to break down, or crack, the larger hydrocarbon molecules of the vacuum residue to produce lighter, higher-value fractions. Thermal cracking in a coker also yields solid carbon, called petroleum coke (pet coke), used as an energy source or primary material in manufacturing.

How coker units work

A delayed coker unit (DCU), the most common type of coker, has two main components: a fired heater and two or more coke drums. In the fired heater, furnace tubes carry the feed through radiant and convection sections, where it reaches its thermal cracking temperature. This fluid then enters the coke drum, where the cracking occurs. (Thus “delayed,” because the reaction does not take place in the heater or reactor.) The hydrocarbon vapours exit from the top of the drum, while coke settles at the bottom. When one drum is full, it is taken offline for decoking while another one, now decoked, is put back online. High-pressure water cutters remove the solids from the coke drum.

Another type is the fluid coker. The feed is sprayed into the burner as a fluidised solid, and is burned again both for fuel and to further crack the long hydrocarbon chains. A flexicoker is like a fluid coker but with the option of either partial or total gasification of the coke. The advantage of fluid cokers and flexicokers is higher yields of high-value liquid hydrocarbons.

Advantages of accurate temperature measurement in cokers

Regardless of the type of coker, these units work under challenging conditions: extremely high temperatures, heavy vibration, corrosive and volatile feeds. Safety and optimal yields require reliable instrumentation to continuously monitor and control the processes. In particular, a coker heater should be balanced on both the process side and fire side.

With accurate information on temperature and process flow, a refinery’s furnace tubes can have three times the run length compared to an average heater. Accurate tubeskin temperature measurement is paramount. If a tubeskin thermocouple (TSTC) reads high, operators will unnecessarily decrease the run time, resulting in reduced production. And if it reads too low, operators would unknowingly increase the run time, thereby increasing the risk of a burst tube and an unplanned shutdown.

WIKA has a portfolio of innovative TSTCs designed to maximise production and plant safety. We also offer installation services and a state-of-the-art furnace monitoring programme with infrared scanning, equipment health checks, data analyses, and troubleshooting.

Fluid catalytic cracking (FCC) unit

Like a coker unit, a fluid catalytic cracking (FCC) unit converts heavy residual oil into lighter, higher-value products such as gasoline and the light olefins of propylene and butylene. But unlike a coker, which uses just high temperatures to crack long hydrocarbon chains, fluid catalytic cracking introduces a catalyst to make this process more efficient.

How FCC units work

In a reactor, residual oil is mixed with silica-alumina, aluminosilicate zeolite or another catalyst. This physical contact, in the presence of suitable temperatures and pressures, results in a chemical reaction that fractionates the feedstock into smaller molecules, which are separated and drawn off in the fractionator. The catalyst is not chemically changed during this reaction, but carbon does coat the powder, beads or pellets. The spent catalyst enters the regenerator, where the carbon is burned off, then returns to the reactor.

Temperature monitoring in FCC units

FCC units, the money makers of modern refineries, can run continuously except for a planned shutdown every five years for regular maintenance. Ideally, the turnaround time is short so the equipment can start refining again. But if the startup is not done properly, condensation may occur, the catalyst becomes wet and sticky, and the unit has to be shut down again for cleaning. To avoid this costly scenario, it is important to continuously monitor the dipleg temperature while rewarming the unit in order to prevent condensation. Another key area for temperature monitoring is in the regenerator, to ensure that the conditions are hot enough to combust the carbon and regenerate the catalyst.

Alkylation unit

An alkylation unit makes iso-paraffins called alkylates. It produces this high-octane gasoline blending component by combining isobutane (from the refinery’s isomerisation unit) with propylene or butylene (from an FCC unit) in the presence of a catalyst. Also call an alky, this unit is an important part of meeting today’s strict fuel standards for reduced emissions.

Types of alkylation units

There are four types of alkylation units today, named after the catalyst used. The conventional ones are the hydrofluoric acid alkylation unit (HFAU) and the sulphuric acid alkylation unit (SAAU). The primary challenge with these units is that liquid acid catalysts are corrosive, toxic, and potentially harmful to the environment. Therefore, it is paramount to prevent emissions and leaks. WIKA’s diaphragm monitoring system features a second, internal diaphragm, which ensures the reliable separation of the environment and the process in case the primary diaphragm fails. If this occurs, the pressure monitored in the intermediate space increases, and the system alerts operators of the rupture event. To avoid the inherent risks of using liquid acids, some refineries are adopting solid acid alkylation and ionic liquid alkylation. Both technologies show promise, as the catalysts are less hazardous to handle, regenerate, and dispose of than HF or H₂SO₄.

Regardless of the catalyst or technology, alkylation requires precise temperature and pressure ranges for optimal chemical reactions.

Continuous Catalyst Regeneration (CCR) Reformer

Catalytic reforming is a process where naphthas are converted to high-octane gasoline blend components, or reformates, using a catalyst in the presence of high heat and elevated pressures. As one of the chemical reactions is dehydrogenation, catalytic reforming produces large amounts of hydrogen, which is used in hydrocrackers and elsewhere in the refinery.

How CCR reformers work

In a typical continuous catalyst regeneration (CCR) reformer, the process begins with the furnace heating the naphtha feed to the appropriate temperature. From there the feed enters a series of reactors, where slow-moving beds of catalyst, typically platinum-based, accelerate the chemical reaction to produce a range of higher-value hydrocarbons. The resulting reformates, along with reformer gas and hydrogen, are separated.

Processes in the reactor deposit coke on the catalyst. After exiting the last reactor, the spent catalyst is routed to the regenerator to be decoked, then it returns back again to the reactor.

Continuous catalyst regeneration is more popular and efficient than semi-regenerative reforming, which uses fixed-bed catalyst that can be regenerated only during shutdowns every few months. CCR, on the other hand, can operate nonstop except for a turnaround every three or so years.

Where to monitor temperature in a CCR reformer

Temperature plays a key role in optimising a CCR reformer’s chemical processes, and temperature sensors operate under challenging conditions.

• Furnace: Accurate and robust tubeskin temperature measurement is important for safe operation and optimising unit throughput. A typical CCR unit has multi-cell furnaces – one for each catalyst bed/zone – that features tubes arranged in wickets or arbours. Both the tube and tube header expand in high heat, so the instrument must deal with three-dimensional differential expansion.
• Reactor: Temperature sensors in moving catalyst beds serve to monitor catalyst performance and detect uneven flow distribution. However, measuring instruments are susceptible to erosion from repeated contact with catalyst pellets. A heavy-walled engineered cable offers protection against moving catalysts and high temperatures.
• Regenerator: Here, the spent catalyst undergoes oxidation to remove the coke deposit, then chlorination to restore its acidity. A flexible multipoint thermocouple monitors gas temperatures in each zone to ensure maximum catalyst life. In this high-temperature and corrosive environment, the superalloy Inconel is the recommended material for measuring instruments.

As CCR units can vary significantly depending on the licensor, understanding the differences is key to proper instrumentation.

Hydrocracker

Hydrocracker units allow for upgrading a variety of low-value feedstock into the middle distillates of jet fuel, diesel, kerosene, and light gas oil.

How hydrocracking units work

As the name implies, hydrocracking reactors break apart heavier gas oils in a hydrogen-rich atmosphere, and they do so with a fixed-bed catalyst (usually zeolite), elevated temperatures (750–1,500 °F / 400–815 °C), and high pressures (1,000–2,000 psi/70–140 bar). The cracked mixture then enters a fractionator, where distillates with lower boiling points are drawn off, and the remaining oil with a higher boiling point is recycled into the reactor to be converted again.

Hydrogen plays two functions in this process:

• Combination with cracked, unsaturated hydrocarbon to form saturated high-value products
• Control of the temperature in the reactor (hydrogen saturation is exothermic, so adding more hydrogen results in more heat)

Heavy gas oils usually contain significant amounts of sulphur and nitrogen. In a two-stage hydrocracker, the first stage is hydrotreatment: using a catalyst to remove the impurities from the feedstock, and bonding hydrogen with sulphur and nitrogen to produce gaseous hydrogen sulfide (H₂S) and ammonia (NH₃). Washwater dissolves these gases, and the resulting ammonium hydrosulphide (NH₄HS) is routed away for stripping. For single-stage hydrocrackers, the feedstock must first go through a hydrotreater to remove the unwanted compounds.

The importance of temperature monitoring in hydrocrackers

Catalytic cracking is an endothermic process, while hydrogen saturation releases heat. Thus, hydrocracking safety and efficiency depend on keeping the reactor temperature within a certain range. Monitoring the temperature profile allows operators to better understand and control the reactor’s performance, especially to prevent thermal runaways.

As hydrocracking units vary in design depending on the licensor, it is important to work with specialists who understand the industry and can design a wide range of temperature profiling systems for hydrocracking units – all complemented by expert multipoint installations and 24/7 customer support. WIKA has a long history of engineering measurement solutions that help refineries prevent unplanned shutdowns, improve run lengths, and increase profitability.

Hydrotreater

Hydrotreaters, also called hydrodesulphurisation (HDS) units, are process equipment that remove sulphur as well as nitrogen, oxygen, heavy metals, and other unwanted products from blend stocks or feedstocks. This is one of the most important steps in modern refinery operations, as:

• Refineries must meet increasingly stringent environmental standards for lower emissions in natural gas and transportation fuels.
• Hydrotreating prolongs catalyst life, as sulphur and nitrogen compounds can poison metal catalysts.
• Impurities in feedstock can foul processing units, so hydrotreating increases run lengths and avoids unnecessary shutdowns of downstream equipment.

How hydrotreaters work

Similar to a hydrocracker, a hydrotreater mixes feedstock with hydrogen, heats the mixture to 500–750 °F (260–400 °C) in a furnace, then sprays it into a reactor. In the presence of metal catalysts and under high temperatures (575–750 °F / 300–400 °C) and high pressure (440–1,910 psi / 30–130 bar), the hydrogen reacts with the feedstock to remove the sulphur by making gaseous hydrogen sulphide (H₂S) and nitrogen (by making ammonia, or NH₃). At the same time, the hydrogen saturates the olefins and aromatics.

There are several categories of hydrotreaters, defined by the type of feedstock they treat – from residues, heavy naphtha, and kerosene to diesel, vacuum gas oil, and FCC gasoline.

Temperature monitoring prevents hydrotreating issues

Temperature sensors in hydrotreating units play a key role in safety and productivity. In a variety of locations, flexible multipoint thermocouple like the Flex-R® check for hotspots, monitor catalyst performance, and look for areas of maldistribution, especially at outlet points. At inlet points, temperature sensors monitor the performance of reactor internals.

Isomerisation Unit

Isomerisation improves the quality of gasoline by transforming straight-chained hydrocarbons, which are lower octane, into branched-chain hydrocarbons, which are higher octane. Compared to catalytic reforming, isomerisation is more economical and produces fewer CO₂ emissions and hazardous byproducts.

What is isomerisation?

Isomers are molecules with the same molecular formula but different molecular arrangement. For example, normal butane (n-C4) is a straight-chain molecule with 4 carbon atoms and 10 hydrogen atoms. Its isomer, isobutane (i-C4), is also C₄H₁₀ but has a CH₃ group branching off from the central carbon atom.

Due to these structural differences, branched-chain hydrocarbons behave differently, both physically and chemically, from their straight-chain cousins. For example, normal pentane and hexane are low octane, around 66–70 RON (research octane number), whereas isopentane and isohexane are around 82–87 RON.

There are two types of isomerisation units:

• C4 isomerisation units convert butane (n-C4) into isobutane (i-C4) for use in alkylation units.
• C5/C6 isomerisation units convert pentane (n-C5) into isopentane (i-C5) and hexane (n-C6) into isohexane (i-C6) for use as blend stock.

The C5/C6 isomerisation process

First, light naphtha is hydrotreated to remove sulphur, nitrogen, and other unwanted products. The treated feedstock is then mixed with varying amounts of hydrogen (depending on the catalyst used) and sprayed into the reactor, an environment with fixed-bed catalyst and moderate heat (200–400 °F / 93–204 °C).

Isomerization processes use one of three types of catalysts.

The next steps depend on the type of catalyst used. In general, the reactor effluent enters vessels where the products are separated:

• H₂ is recovered and reused in the reactor.
• The isomerates are routed for downstream blending.
• If HCl is produced, it is removed and treated.
• The cracked gases of C₁ (methane), C₂ (ethane), C₃ (propane), and C₄ (butane) are recovered and removed.
• Any unconverted C₅ and C₆ are recycled back to the reactor as feedstock.

Temperature monitoring of catalysts

For isomerisation units to continue producing high-octane isomerates, the catalyst needs to be at peak performance. Operators can monitor for channeling, maldistribution, and general catalyst activity with multipoint thermocouple at various points along the fixed beds. Having a complete temperature profile can prolong catalyst life, increase processing efficiency, and improve plant safety.

Amine unit

Using nitrogen-containing compounds known as amines, amine units strip unwanted hydrogen sulphide and carbon dioxide from natural gas. Amine treating is one of the best ways to remove acid gases and make petroleum products suitable for use.

The basics of amine treating

An amine unit contains several steps for sweetening sour gas and recycling the amine solvent.

• 1. Before amine treating, the dirty process is routed to a sour gas knockout (KO) drum to remove water and oil droplets.
• 2. The pretreated gas enters the bottom of the amine column, also called an absorber or contactor.
• 3. As the sour gas rises, it makes contact with the lean amine (without acid gases) solution raining down from the top. The greater the contact, the more H₂S and CO₂ are absorbed.
• 4. At the top of the contactor column, the sweetened gas is piped away at the clean process outlet.
• 5. The clean process enters the sweet gas KO drum, where any remaining amine is collected and reused, and the natural gas is piped further downstream.
• 6. The amine solution, which is now saturated with acid gases (rich amine), settles to the bottom of the contactor and is routed to the stripping column.
• 7. In the stripper, steam from the reboiler separates the acid gases from the rich amine.
• 8. The acid gases are cooled in the condenser and piped to recovery units for processing.
• 9. The stripped amine passes through a series of filters for further cleaning.
• 10. The amine, now lean again, is piped back to the top of the contactor for reuse.

Measurement solutions for optimised amine treating

Temperature monitoring and control play a key role in the efficiency of amine units. Specifically, the process gas and amine solution operate best within a narrow temperature range.

• If the amine is too cool when it makes contact with the hydrocarbons, the dirty process gas could condense and foam, resulting in poorer gas quality. Ideally, the lean amine is just slightly hotter than the gas temperature at the inlet.
• But if the lean amine is too hot, it will flow too quickly and not absorb enough acid gases.
• If the dirty process gas is too hot as it enters the amine column, it will rise too quickly and make contact with the lean amine too close to the clean process outlet at the top of the column. In this situation, foaming could occur, resulting in poorer gas quality and possible amine loss.
• If the rich amine is too hot, acid gases will break out of the solution and attack the metal surfaces, resulting in corrosion.
• If the filtering system’s temperature is too cool, it will not be as effective in removing contaminants from the amine solution before it is pumped back into the contactor, resulting in less efficient absorption of acid gases.

Amine circulation rate, gas flow rate, inlet gas temperature, and amine concentration all affect the efficiency of amine treating operations. With quality instrumentation like multipoint thermocouple, especially the TC96-M miniature multipoint thermocouple, refiners have the precise, real-time information they need to make smart operational decisions.

Hydrogen unit

Hydrogen is a critical component in refineries today, necessary for transforming lower-value hydrocarbons into higher-value products. The hydrogen used in hydrocrackers, hydrotreaters, and isomerisation units can come from a CCR reformer, which makes H₂ as a byproduct. Additional demand can be supplied by a steam methane reformer (SMR), which converts methane – usually from natural gas – and water into hydrogen.

1. If necessary, natural gas is first desulphuurised in a hydrotreater.

2. An SMR uses elevated pressure (44–360 psi / 3–25 bar), high temperatures (1,290–1,830 °F / 700–1,000 °C), a fixed-bed catalyst, and superheated steam to reform methane into hydrogen and carbon monoxide.

CH₄ + H₂O → 3 H₂ + CO

3. Carbon monoxide is an impurity that is difficult to remove. So, the resulting synthesis gas from the steam reformer now undergoes a water gas shift reaction to convert carbon monoxide into carbon dioxide and additional hydrogen.

CO + H₂O → CO₂ + H₂

This process also requires a catalyst but slightly lower temperatures of 400–900 °F (200–480 °C).

4. There are two main ways to remove the carbon dioxide from hydrogen.

• Pressure swing adsorption (PSA) uses high pressure and adsorbent materials to capture unwanted gases. The process then swings to low pressure, which prompts the materials to give up their respective gases, thus restoring their adsorbent properties.
• CO₂ methanation uses an amine solvent to capture carbon and then convert it into CH₄ using a catalyst and the appropriate temperature and pressure conditions. The created methane is then routed back to the steam reformer.

Both methods generate an almost pure steam of hydrogen for a refinery.

Measurement solutions for hydrogen units

Since steam reforming is endothermic, this process requires a regular supply of heat from a furnace. Furnace tubeskin temperatures can reach up to 1,500 °F (815 °C). Temperature measurement solutions include tubeskin thermocouples, flexible multipoint thermocouple and thermocouples in thermowells and pipewells. Temperature sensors also allow operators to make data-backed decisions regarding catalyst replacement.

Monitoring and controlling pressure, level, and flow are also key to efficient processes during steam methane reforming.

Sulphur recovery unit

Sulphur is an unwanted product in oil and gas as their combustion produces environmental pollutants. After removal in desulphurisation in a hydrotreater or another processing unit, a sulphur recovery unit (SRU) uses the Claus process to convert the resulting hydrogen sulphide into sulphur, a saleable product used in manufacturing and for making fertilisers.

Steps of sulphur recovery in a refinery

The Claus process has two stages for recovering sulphur:

1. Thermal stage

Hydrogen sulphide combusts with the oxygen in air to produce elemental sulphur.

2 H₂S + O₂ → 2 S + 2 H₂O

The oxidiser temperature is maintained above 1,560 °F (~850 °C). The hot effluent then enters a condenser, where the steam is diverted away from the sulphur. As the hydrogen sulphide is only partially oxidised, ~70 % of the sulphur is separated out, and the stream still contains hydrogen sulphide. Additional combustion with air creates sulphur dioxide.

2 H₂S + 3 O₂ → 2 SO₂ + 2 H₂O

2. Catalyst stage

The effluent of the condenser is reheated, since sulphur condensation fouls the catalyst. The hot mixture then goes through a series of fixed-bed catalyst reactors (Claus reactors) to further separate out the sulphur.

2 H₂S + SO₂ → 3 S + 2 H₂O

The catalyst stage occurs at lower temperatures of 600–625 °F (~315–330 °C) but above the dew point of sulphur.

The Claus process recovers 95–97 % of the H₂S in the feedstream, but that percentage is not high enough to meet today’s strict regulations for air pollution control. Therefore, the final step is to treat the tail gas, using a tail gas treatment unit (TGTU). Basically, the sulphurous tail gas is heated and hydrogenated to produce hydrogen sulphide, which goes through an amine unit. The stripped hydrogen sulphide then goes back to the oxidiser to recommence the Claus process.

The importance of temperature measurement in sulphur recovery

Accurate temperature monitoring and control play an enormous role in every stage of an SRU, from oxidisers and condensers to reheaters, reactors, and tail gas treating units (TGTUs). For example, if the temperature of a Claus reactor is too low, the catalyst will not react optimally. Furthermore, the sulphurous gas will condense and foul the catalyst.

Flare stack

For both economic and environmental reasons, refineries find ways to recover and recycle almost all the residual products of their processes. But there are certain gases that cannot be reused, and those are safely burned off. Also, in case of overpressure or other dangerous situations, emergency shutdown (ESD) systems ensure that hazardous vapors are automatically evacuated from sensitive areas of the plant, routed via flare lines to a flare stack for combustion.

A flare stack controls the combustion of these unwanted gases, which produces less harmful products that are released into the atmosphere. For example, methane has a global warming potential (GWP) of 27–30, compared to carbon dioxide’s GWP of 1. Burning off any unrecovered methane produces carbon dioxide and water.

Various lines for air, steam, and unwanted gases feed into a flare stack and are ignited at the flare tip. Instruments for measuring flow velocity help control the process for greater safety and efficient combustion. Thermocouples that are routed to the flare stack are critical for monitoring the pilots that support the flare.

Electric Substation

Large downstream operations typically co-own an electric substation with the region’s utility company. In a refinery, operators need to transform voltage levels and redirect the electricity to where it is needed.

Medium- and high-voltage equipment today rely on various gases for insulation and arc quenching. WIKA is a global provider of gas handling solutions for the power transmission and distribution industry, and our portfolio of products enable downstream companies and electricity providers alike to monitor, analyse, and handle all types of insulating gases in breakers, transformers, switchgear and more.

The most common gas found in gas-insulated equipment is sulphur hexafluoride (SF₆). It has excellent dielectric strength for reliable arc quenching. At the same time, it is the greenhouse gas with the highest known global warming potential (GWP). Leak prevention is paramount to avoiding the hazards of using SF₆ gas.

A full subsidiary of WIKA, WEgrid Solutions provides a comprehensive suite of products and services designed for the safe handling of SF₆ as well as alternative gases. Online gas-density monitoring with trend analysis enables condition-based service and maintenance, allowing substation operators to increase safety, reduce costs, and protect the environment.

Calibration & Services

WIKA offers a wide range of services for the downstream oil and gas industry.

Calibration Center: Consultation, design, and implementation – all from one source

Let WIKA calibrate your reference and test equipment, either in our ISO 17025-accredited laboratories or at your location. In addition to offering a wide range of calibration instruments, we offer calibration services for pressure, temperature, force, flow, and electrical measurands, as well as SF₆ gas density instruments.

Calibrated instruments produce accurate data, a prerequisite for the type of smart decision-making that leads to safer operations and greater production. But calibration products are just part of the equation.

For a complete solution that is as unique as your downstream operations, partner with WIKA. Our oil and gas specialists can design a high-performance calibration system from our extensive product range, with:

• Adaptability for test items
• Pressure and vacuum supply
• Components for pressure control and fine adjustment
• Voltage supply and multimeters for calibrating electrical test items

Another one of our strengths is project planning. We can design, build, and implement application-specific systems for any type of on-site calibration, from manual workstations to fully automated test systems in production lines.

Furnace Comprehensive Monitoring Programme (FCMP)

Fired heaters are the heart of many refinery units, and poor performance has a negative impact on safety and productivity. To help your equipment operate as close to target conditions as possible, we offer three levels of furnace monitoring to meet your refinery’s needs.

• Basic: infrared scanning + thorough audit to identify equipment issues
• Advanced: the basic plan + regular monitoring and evaluation
• Comprehensive: the advanced plan + actionable intelligence and in-depth understanding of the issues

Diaphragm seal system repair

Don‘t replace when you can repair. With WIKA’s services for diaphragm seal (DS) systems, customers can realise significant savings compared to the cost of buying a new unit. This is because the service life of the process transmitter is longer than that of the wetted parts. Therefore, when a diaphragm seal system stops working, only in rare cases must the entire unit be replaced.

We service both our own diaphragm seal systems and those from other manufacturers. And with a location right next to the Houston Shipping Channel, we offer fast repair services for the area’s refineries. A diaphragm seal drop box, at your facility or ours, means even more convenience.

R&D Center

Located near the Houston Ship Channel, WIKA’s R&D Center is a world-class facility created to help refineries get the most out of their assets. At the heart of this campus is a full-size process unit designed and built in accordance with ASME and API guidelines. The 9.6M BTU furnace is capable of replicating a wide range of the processes that take place in larger-scale heaters and reactors, allowing us to test and verify the performance of our temperature instruments in actual working conditions.

But this state-of-the-art facility isn’t just for WIKA’s use. Our customers also benefit from a range of services:

• Replicate a refinery unit’s temperature measurement issues in an active fired heater designed for this purpose.
• Support sensor testing requirements without equipment damage or a costly refinery shutdown.
• Receive hands-on training to get the most out of measuring instruments and process units, including insights on the optimal placement and configuration of tubeskin thermocouples.

Along with expert advisory and our portfolio of quality instruments for the oil and gas industry, WIKA’s R&D Center has helped refineries around the world improve process efficiency, reduce turnaround time, and increase yields and margins.

Installation

Our experienced technicians and engineers are available for on-site support in the installation and commissioning of WIKA instruments and systems. Our range of field services includes supervision, advisory, welding work, analysis and troubleshooting, inspection, maintenance, and repairs. From new projects to oversight during planned or unplanned shutdowns, our global team is at your side.

Professional development

Our industry experts are available for workshops, seminars, and consultations across all our product lines – at your location or ours. Contact us for more information on training and upskilling your team.