Energy Recovery with Compact Heat Exchangers

Compact heat exchangers are used for heat recovery applications where high efficiency is vital, space or weight constraints apply, or exotic materials are required.

Marcos Matsufugi

Alfa Laval

The refinery business is under constant pressure to increase efficiency. A highly competitive market combined with rising energy and feedstock costs require refineries to ramp up production while cutting operating costs.

Switching from shell-and-tube to welded plate heat exchangers (also known as compact heat  exchangers) is a proven and straight forward way of solving the problem. The use of compact heat exchangers offers benefits in four areas:

• •       Energy savings
• •      Less maintenance
• •       Increased production
• •       Lower installation costs.

Energy savings

Up to 50% of a refinery’s operating budget is tied up in energy costs, making energy efficiency a top

priority. Energetics Incorporated estimates that the petroleum refining industry in the US could cut energy use by as much as 54% by incorporating best practices and new technology.

Recovering and reusing energy is a profitable and easy way to cut energy costs. All refineries do this to some extent, but most still use outdated shell-and-tube heat exchangers with low thermal efficiency.

Investing in more efficient heat exchangers is profitable for energy-intensive plants such as refineries. Payback periods are often less than six months.

Cut fuel costs

Heat recovery efficiency can be increased by up to 50% by simply switching from shell-and-tube to

welded plate heat exchangers. More energy is then put back to use, energy that would otherwise have gone to waste. Atmospheric and vacuum distillation units are typical units with a high energy consumption and they represent an enormous potential for better heat integration.

Preheating of crude oil is the process that requires the largest amount of energy and where most gains can be made by using compact heat exchangers for heat recovery. There are plenty of other units in a refinery, such as hydrotreating, reforming and FCC, where switching to compact heat exchangers can be very profitable.

Reduced fuel consumption also leads to lower emissions of CO2, NOx and SOx. If the plant operates under a cap-and-trade system this will cut operating costs even further.

Efficiency up to five times higher

The heat exchanger is a key component in heat recovery. The choice of heat exchanger is important and has a direct impact on a company’s bottom line. Figure 1 shows the heat recovery level as a function of initial cost in a compact heat exchanger and a shell-and-tube. The yield from the compact heat exchanger is up to 25% higher than for the shell-and-tube at a comparable cost. Shell-and-tube solutions with the same level of heat recovery are often several times more expensive than a compact heat exchanger.

Turbulence and counter-current flow

The superior thermal efficiency of a compact heat exchanger is a result of its highly turbulent flow (see Figure 2). The corrugated heat exchanger plates cause much higher turbulence in the fluid than in a shell-and-tube at the same flow velocity.

The formula below describes the overall heat transfer coefficient. High turbulence increases the film heat transfer coefficients ( a 1 and  a 2). Thin plates (small  d ) also have a  positive effect on heat transfer. The result is an overall heat transfer coefficient (k) that is three to five times higher than for a shell-andtube heat exchanger:

k = Overall heat transfer coefficient, W/m²°C

a = Film heat transfer coefficient, W/m²°C

d = Wall thickness, m

l = Wall conductivity, W/m°C

Another important feature of compact heat exchangers is the capability to operate with a countercurrent flow; hot fluid enters the heat exchanger at the end where the cold fluid exits. This makes it possible to handle crossing-temperature programmes in a single heat exchanger (that is, to heat the cold fluid to a temperature that is higher than the outlet temperature of the hot fluid). This is especially important in heat recovery, since the maximum amount of energy is recovered when the cold fluid is heated to a temperature very close to that of the hot fluid.

The high efficiency means compact heat exchangers can exploit temperature differences as low as 3°C. This makes it possible to recover heat from sources that have previously been deemed worthless.

Case study: feed/effluent exchanger

A refinery in the US replaced two shell-and-tubes with a single compact heat exchanger as a feed/effluent exchanger in an isomerisation plant. The result was a 43% increase in heat recovery, from 5.8 MW to 8.3 MW. As an added bonus, the new solution also allowed the refinery to eliminate a downstream air cooler (see Table 1).

Case study: overhead condensers

A refinery in Italy replaced old air coolers on the atmospheric distillation column with two compact heat exchangers. The heat that was previously cooled off into the air is now recovered and used for preheating crude oil. The result is additional heat recovery of 11.5 MW (39.3 MMBtu/h) and an annual saving in fuel of €2.5 million (see Table 2).

Profitable energy recovery

Energy-saving investments often have short payback periods, even at much lower energy price levels than today’s. In the future, energy efficiency will most likely be a prerequisite for staying in business.

In its World Energy Outlook 2008 report, the International Energy Agency (IEA) predicts world energy demand to increase by 45% over the next 20 years. It also predicts that the supply of fossil fuels will not be able to meet this demand, even when taking new, undiscovered fields into account.

More and more governments around the world will probably start charging industries for emitting CO2, with emission credits becoming more and more expensive. The result of all this will undoubtedly be increasing energy prices; just how much is hard to predict. In 2007, the IEA predicted oil prices to stay at $50–55 per barrel until 2030. A year later, in June 2008, they peaked at $147 dollars.

There are many ways to fight the energy challenge. Consulting firm McKinsey made a thorough investigation of future energy needs and supply, comparing the benefits of different alternatives. It came to the following conclusion: “McKinsey has looked long and hard to obtain an affordable, secure energy supply while controlling climate change. Energy efficiency stands out as the single most attractive and affordable component of the necessary shift in energy consumption.”

Obviously, the first step towards lower energy costs is to start using less energy. Increasing efficiency is the least costly and most easily implemented solution to the energy challenge for most refineries.

Less maintenance

One of the key features of a compact heat exchanger is the highly turbulent flow. Apart from improving heat transfer, it also makes heat exchangers less susceptible to fouling problems. The high turbulence means fouling deposits are not deposited on the heat transfer areas. This results in longer service intervals, more operating time and more recovered heat than with a shell-and-tube design. Less fouling also leads to lower cleaning costs.

This self-cleaning effect is especially large in spiral heat exchangers (SHE). These are compact heat exchangers with a single channel design. This design causes fouling deposits to be flushed away wherever they start to build up. Spiral heat exchangers are the correct choice for heavy-fouling duties and can handle solids, slurries and fibres. Typical duties for spiral heat exchangers in refineries are cooling fluid catalytic cracking (FCC) bottom products or visbroken residues.

The smaller heat transfer area compared to a shell-and-tube heat exchanger means cleaning will be both quicker and require fewer cleaning chemicals. The small heat transfer area also leads to a smaller hold-up volume, which means compact heat exchangers respond faster to process changes. The equipment can therefore be shut down and restarted more quickly when serviced.

Energy savings

Fouling leads to higher energy consumption. Heat transfer efficiency drops as fouling builds up, meaning the boiler or burner has to provide more heat. Pumping the fluid through a fouled heat exchanger also requires more power to compensate for the increasing pressure drop. Reduced fouling will also have a positive effect on energy bills.

Case study: feed/effluent

exchangers I

One of the largest refineries in the US had severe fouling problems in a desalter unit where two shell-and-tubes were used for cooling the desalter effluent. The problem was solved by substituting the two shell-and-tube exchangers for one spiral heat exchanger. The higher thermal efficiency meant a heat transfer area in the new heat exchanger could be half the size of the shell-and-tubes.

One of the main problems with shell-and-tube exchangers was the fast-increasing pressure drop caused by fouling. After the spiral heat exchanger was installed, the pressure drop was stable and thermal performance was much better over time.

The old shell-and-tubes had to be cleaned every month. The new spiral heat exchanger was cleaned for the first time after 14 months.

No heavy fouling was observed, only a thin layer of grease on the effluent side and minor scaling on the feed-water side (see Table 3). The compact nature of the spiral heat exchanger means it is easier to perform maintenance.

Increased production

Many refineries have bottlenecks related to heating or cooling. It is often impossible or very costly to increase heating or cooling capacity, meaning they are left unresolved. Investing in more efficient heat exchangers is often the best way to overcome these limitations. The higher the efficiency of the heat exchanger, the more heat can flow through it. This means the process fluid is heated or cooled with the extra degrees needed to resolve the bottleneck, simply by raising heat exchanger efficiency. The result is higher production capacity at a low investment cost.

Compact heat exchangers resolve bottlenecks without adding any additional investment or operating costs for more heating.

More performance per square metre

Thanks to the smaller heat transfer area required, compact heat exchangers offer significantly higher capacity per square metre of floor space than shell-and-tube exchangers offer. As restrictions in pace and building structures often apply, switching to compact heat exchangers is a straightforward way to boost production without having to rebuild the plant. Using the same support structures, you get the required capacity boost simply by substituting the old equipment with new.

More uptime

Compact heat exchangers require less downtime for maintenance than do shell-and-tube exchangers, since service intervals are longer and the cleaning process is faster. Increased uptime also leads to higher production output over time.

In the desalter example above, shell-and-tubes had to be cleaned 12 times per year and the compact heat exchanger less than once a year. The increase in uptime is substantial and leads to higher production output.

Case study: feed/effluent

exchangers II

To improve overall performance in its semi-regenerative catalytic reforming process, a refinery in France replaced 12 shell-and-tube feed/effluent heat exchangers with a single, large-scale compact heat exchanger. This resulted in a 33% increase in capacity and reduced pressure drop from 4 to 1.5 bar.

Improved heat recovery also led to lower energy consumption by 5.6 MW (19.1 MMBtu/h) and lower emissions for the fired heater. The payback time was 12 months.

Lower investment costs

Total investment costs are usually significantly lower for compact heat exchangers than for shell-and-tube  exchangers. This is because the costs for the heat exchanger and installation are often lower, and because the utility systems can be used more efficiently.

Lower costs for the heat exchanger

Since the required heat transfer area is three-to-five times smaller for a compact heat exchanger than for a corresponding shell-and-tube design, much less material is needed to build the unit. This has a positive effect on price, especially when tough conditions call for exotic materials such as high-alloy steel or titanium.

Case study: atmospheric distillation

unit I

Petrobras compared the costs for shell-and-tubes and compact heat exchangers. Heat exchangers were to be used in an atmospheric distillation unit, to preheat crude using heat recovered from kerosene and HVGO streams. The comparison showed that the costs for shell-and-tube exchangers were 3.8 and 5.6 times higher for the respective positions.

Lower installation costs

Installation costs can be cut considerably by using welded plate heat exchangers instead of shell-and-tube exchangers when expanding plant capacity. The foundations can be made smaller and the heat exchangers are easier to fit into existing structures thanks to their compact nature and lighter weight.

When estimating the total installed cost, a factor of 3.0–3.5 times the cost of the heat exchangers is often used for shell-and-tubes, compared to less than two for compact heat exchangers.

Case study: atmospheric distillation

unit II

A refinery in Asia analysed different options for heat recovery on the atmospheric distillation column. Special alloys had to be used in the heat exchangers due to the aggressive media. Since the shell-and-tube solution would require a larger heat transfer area, the cost became 2.3 times higher than for a compact heat exchanger setup (see Table 4).

A shell-and-tube installation (including space for extracting the tubes) would also occupy a 20 times larger volume on-site, 840 m³ (12 x 14 x 5 m) compared to 37.8 m³ (1.8 x 6 x 3.5 m).

Lower costs for utility systems

Before investing in new utility systems such as cooling towers and boilers, it is wise to see if the same result can be achieved by increasing heat recovery. Recovering more energy in the process often leads to reduced heating and cooling needs. Switching to compact heat exchangers often means production can be increased while still using the same utility systems.

Reliability

Compact heat exchangers offer the best of two worlds and combine the benefi ts of traditional plate heat  Exchangers with those of shell-and-tube exchangers. The all-welded design ensures trouble-free performance that does not change over time.

Many of the compact heat exchangers that are in use in refi neries have been operating for decades and are still delivering top results. Apart from reliable sturdiness, compact heat exchangers bring you high efficiency, compact size, minimum maintenance, low pressure drop and the ability to operate at high pressures and temperatures.

They can be used in many positions in a refi nery. The installations are often for heat recovery applications, where high efficiency is essential (crude preheating, feed/effluent heat recovery and boiler feed water preheating). Compact heat exchangers are often being used where space or weight constraints apply (overhead condensers and reboilers) and where exotic materials are required due to corrosion (desalter water, naphtha toppings, sour water, amines and alkylation).

The self-cleaning effect in spiral heat exchangers also makes them very suitable for heavy fouling applications (cooling FCC bottoms or visbroken residues).

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Preheat Train Network Modifications

In this case history, a crude distillation unit (CDU) preheat train network in a Saudi Aramco refinery was simulated and analyzed for anticipated modifications to the network. This analysis helped eliminate inefficiencies in the network, and, based on the insights from the analysis, various options were generated and the existing network was reconfigured. The reconfiguration allowed the temperature of the crude preheat network, which processes Arab Light crude oil, to be increased to the maximum of 277°C from a previous temperature of 261°C.

Existing configuration.

Desalted crude from the tank is heated by the crude column top pumparound, light gasoil (LGO) product, heavy gasoil (HGO) product, LGO pumparound (LGO PA), HGO pumparound (HGO PA), heavy vacuum gasoil (HVGO) pumparound and vacuum residue (VR) product, as shown in Fig. 1 in exchangers E1 to E7, respectively. The current crude preheat temperature entering the CDU furnace is around 261°C. This exchanger network is validated using heat exchanger design software and by adjusting the foulingcoefficients.

 

Modifications required.

The base-case network was altered for anticipated modifications in the future. The reasons for the modifications are listed below:

Vacuum slop circuit. In the current configuration (Fig. 2), the vacuum slop is recycled to the vacuum tower through the vacuum furnace. The purpose of this recycle is to recover the VGO components and send the VGO to the hydrocracker; however, this is not achieved in the current operation due to vacuum furnace limitations and insufficient separation in the wash section. As a result, this vacuum slop stream (which is lower in viscosity) goes with the vacuum tower bottoms. The mingling of streams deteriorates the feed to the asphalt oxidizer and creates operational problems in meeting the penetration property of the asphalt.

 

To address this concern, the vacuum slop stream from the vacuum tower is available at a temperature of 380°C, which is withdrawn as a separate cut and is used to increase the preheat temperature of the crude. This proposed new exchanger is configured to be in parallel with the existing heat exchanger E4 in Fig. 1. Fig. 3 shows the rerouting of the vacuum slop.

 

Future splitter configuration. To meet the clean gasoline specification of 1% benzene in gasoline, the existing naphtha splitter must remove the benzene precursors in the catalytic reformer feed by increasing the initial boiling point of the heavy naphtha. This process requires a higher reboiler duty. In addition, the heavy naphtha from the hydrocracker needs to be processed in the naphtha splitter, as this feed also contains benzene precursors.

Currently, hydrocracker heavy naphtha is not part of the naphtha splitter feed. The hydrocracker heavy naphtha feed volume is 12,500 barrels per day (bpd), and the existing naphtha splitter capacity is 23,000 bpd. Figs. 4 and 5 show the naphtha system’s current and planned configurations, respectively. As the current naphtha splitter cannot handle this higher throughput with higher reboiler requirement, the existing naphtha splitter will be mothballed. The existing reboiler, which uses HGO PA flow and gives a duty of 10.4 million kilocalories per hour (MMkcal/hr), will also be mothballed.

High-pressure steam will be used in the reboiler of the new naphtha splitter to meet the higher reboiler requirements. For the column to be in heat balance, this 10.4 MMkcal/hr of heat removal is required. In the proposed exchanger network, this stream (HGO CR) will be used to preheat the crude. 

Synthesis of crude preheat train.

A new, preliminary heat exchanger network (Fig. 6) was synthesized to accommodate the above modifications. While modifying the crude preheat train network, the following impact on the equipment was kept in mind:

• Prevention of vaporizations in the furnace pass-control valves, as it is difficult to control two-phase flows across pass-control valves. Inadequate flow in the furnace pass flows will also lead to coking
• Column heat balance.
• Column hydraulics.
• Impact of hot streams going directly to the other unit.

The changes made in the base-case network are listed below:

·      Exchanger N1 was added parallel to E4 (see Fig. 6) using vacuum slop (vacslop) and vacuum residue ex-E7 as the hot fluid. This modification is required to improve the viscosity of the vacuum residue to the asphalt oxidizer. The current viscosity of the feed to the asphalt oxidizer is 1,500 centistokes (cst), and the required viscosity is 2,000 cst.

·     Another exchanger N2 (E5-2, similar to E2) was added parallel to E2 using HGO PA fluid ex-E5 (hereafter referred to as E5-1) as the hot fluid. This modification is performed to accommodate the 10.4-MMkcal/hr duty in the HGO PA circuit.

·     Increased area in E4 from the 2-parallel-1-series arrangement to a 2-parallel-2-series design and added cooler N3 downstream of E4.

Due to the first two modifications, the inlet temperature to E4 has increased, which decreases the logarithmic mean temperature difference (LMTD) available across the unit. Since E4 is the LGO PA exchanger, the column will not be in heat balance if the required heat removal is not performed. The required duty was 18.8 MMkcal/hr, and the available duty was 12.7 MMkcal/hr (see Table 1). Therefore, additional area and a cooler were added in the LGO PA circuit to meet the duty requirement of the column.

The required HGO PA duty is 26.8 MMkcal/hr, and the available duty is 29.8 MMkcal/hr. As the heat removed in HGO PA is higher by 3 MMkcal/hr, the requirement of LGO PA duty will come down by 3 MMkcal/hr. As both LGO and HGO are mixed outside of the column and go to the diesel hydrotreater (DHT), the splitting of the duty between LGO and HGO pumparound is not a concern from a separation point of view. However, it does impact the column draw temperature, which will slightly reduce the LMTD across E3 (HGO product/crude exchanger) and E5 (HGO PA/crude exchanger).

Results of network modification.

In the modified network, the obtained preheat temperature was 266°C. The duty, LMTD and area of each exchanger in the network are presented in Table 1. From Table 1, it can be observed that:

·    Exchanger E6, which has a higher area, is experiencing the lowest LMTD; therefore, any modification that increases the LMTD will significantly increase the heat recovered from E6.

·     The exchanger preceding exchanger E6 is heated by HGO circulating reflux (CR), which is at 337°C; this is higher than the hot stream (HVGO CR) temperature of E6, which has decreased the LMTD in E6.

This preliminary network was analyzed for possible improvement in the preheat temperature. The analysis indicated that heat recovery can be increased by 45% by boosting the area by 56% (see Table 2).

The analysis also indicated that the driving force across exchanger E7 further limited the heat recovery. Fig. 7 displays the driving-force plot. The figure indicates that the driving force in E7 can be increased by decreasing the inlet temperature in E7. This temperature adjustment can be achieved by operating E5 in parallel with E7.

Case 1. Based on the insights derived from Table 1 and Fig. 7, to improve the heat recovery, the crude stream in E7 and E5 was split by operating E5 in parallel with E7. The objective of this modification is to increase the LMTD across E7 and E6. However, it also decreases the LMTD across E5-1. The net effect is shown in Table 3, and the modified network is shown in Fig. 8. With this arrangement, the preheat temperature has increased from 266°C to 269°C.

Case 2. From LMTD and approach data in Table 3, it can be inferred that heat recovery in E5-1 can still be improved by increasing the area. Hence, another case study was performed by adding two similar exchangers in a series in E5-1. The results are tabulated in Table 4. The preheat was found to be increased to 277°C.

The HGO PA is now providing an extra 4.2 MMkcal/hr more than required, which will reduce the LGO PA duty requirement by the same amount for the column to be in heat balance. Then, the required LGO PA cooler duty comes down to 2.6 MMkcal/hr.

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Ultrasound applied to crude oil desulfurization

An innovative method for upgrading crude oils will find application across multiple industry sectors.

Following field trials completed late in 2008, Houstonbased SulphCo, Inc. reported it has successfully used a 5,000 b/d mobile “Sonocracking” unit to duplicate on a commercial scale its proprietary process that applies high-energy, high-frequency sound waves, so-called ultrasonics, in conjunction with oxidation chemistry to improve the quality of crude oil and crude oil fractions.

Dr. Florian Schattenmann, SulphCo chief technology officer, said use of high-powered ultrasound can significantly accelerate the sulfur compound oxidation needed to upgrade crude oils and petroleum products into sweeter (i.e., containing less sulfur) crudes and products (e.g., diesel), potentially eliminating or reducing the need for hydrotreating.

The technology works by taking the sulfur, chemically bound to some of the molecules in the oil, and oxidizing it using hydrogen peroxide - a classic oxidant - together with the ultrasound. On a molecular level, the hydrogen peroxide donates one of its two oxygen atoms to the sulfur to form water as the byproduct. The treated oil typically has less sulfur, lower viscosity, and a higher API gravity. In addition, remaining sulfur is thereby converted to a different sulfur species that can be more easily separated.

In operation, the oil, hydrogen peroxide solution, and catalyst are introduced into a reactor, where very intense mixing happens in the cavitation zone generated by the ultrasound. The reaction takes place in half a second or less. The water and oil separate, with the water subsequently being recycled and new hydrogen peroxide added to offset that used in what is “more or less” a closed-loop system.

Applications of SulphCo’s Sonocracking technology are currently being evaluated, the company said, in oil production, transportation, and refining. One reason to assume that multiple uses will be found is that an increasing proportion of the overall market consists of medium, heavy, or sour crudes. In addition, current and expected future industry regulatory requirements will exert pressure to move towards lower sulfur content in most petroleum products.

The traditional method for removing sulfur from oil involves hydrotreating, entailing capital-intensive investments in high-pressure, high-temperature hydro-desulfurization (HDS) units as well as boilers, hydrogen plants, and sulfur recovery units. The deeper the desulfurization required, or the heavier or more sour the crude used for feed, the more expense involved.

At the moment, Schattenmann said, the primary market focus for SulphCo’s technology is the downstream sector of the oil industry, but upstream and midstream applications are already envisioned. “If you can reduce the sulfur content of oil before it goes into the separator or pipeline, there are many benefits. For example, you may be able to meet pipeline specifications without having to add more expensive oil blends to your stream. The upstream and mid-stream guys get really excited at the prospect of having this kind of a simple solution to increase value.”

While the base design and capacity for the technology consists of a 5,000 b/d processing line, successive lines can be added to scale capacity. SulphCo has implemented skid-mounted modular Sonocracking units with 15,000 b/d capacity and currently has 210,000 b/d of capacity constructed.

The cavitation induced as oil and additives stream through the reactor and past the ultrasonic probe leads to the creation of bubbles at the sites of refraction owing to the “tearing” of the liquid caused by the negative pressure of the intense sound waves. The bubbles then oscillate under the effect of positive pressure, growing to an unstable size as the wave fronts pass. The bubbles eventually burst, generating excess heat and pressure in and around every micrometer- and sub micrometer-sized bubble. This happens in a matter of “nanoseconds,” Schattenmann said, and each bubble behaves as a micro-reactor, accelerating the chemical reaction described earlier owing to the heat released and localized pressures obtained.

Subsequent to the completion of the commercial-scale field trials in late 2008, Dr. Larry D. Ryan, SulphCo CEO, said, “Additional technical iterations and analysis will continue as we identify, execute, and evaluate the multiple processes necessary to comply with future customer requirements.”

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Refinery Feedstocks

The basic raw material for refineries is petroleum or crude oil, even though in some areas synthetic crude oils from other sources (Gilsonite, tar sands, etc.) and natural gas liquids are included in the refinery feedstocks. The chemical compositions of crude oils are surprisingly uniform even though their physical characteristics vary widely. The elementary composition of crude oil usually falls within the following ranges.

In the United States, crude oils are classified as paraffin base, naphthene base, asphalt base, or mixed base. There are some crude oils in the Far East which have up to 80% aromatic content, and these are known as aromatic-base oils. The U.S. Bureau of Mines has developed a system which classifies the crude according to two key fractions obtained in distillation: No. 1 from 482  to 527°F (250 to 275°C) at atmospheric pressure and No. 2 from 527 to 572°F (275 to 300°C) at 40 mmHg pressure. The gravity of these two fractions is used to classify crude oils into types as shown below.

The paraffinic and asphailic classifications in common use are based on the properties of the residuum left from nondestructive distillation and are more descriptive to the refiner because they convey the nature of the products to be expected and the processing necessary.

CRUDE OIL PROPERTIES

Crude petroleum is very complex and, except for the low-boiling components, no attempt is made by the refiner to analyze for the pure components contained in the crude oil. Relatively simple analytical tests are run on the crude and the results of these are used with empirical correlations to evaluate the crude oils as feedstocks for the particular refinery. Each crude is compared with the other feedstocks available and, based upon the operating cost and product realization, is assigned a value. The more useful properties are discussed.

API Gravity

The density of petroleum oils is expressed in the United States in terms of API gravity rather than specific gravity; it is related to specific gravity in such a fashion that an increase in API gravity corresponds to a decrease in specific gravity. The units of API gravity are °API and can be calculated from specific gravity by the following:

In equation (1), specific gravity and API gravity refer to the weight per unit volume at 60°F as compared to water at 60°F. Crude oil gravity may range from less than 10°API to over 50°API but most crudes fall in the 20 to 45°API range. API gravity always refers to the liquid sample at 60°F (15.6°C). API gravities are not linear and, therefore, cannot be averaged. For example, a gallon of 30°API gravity hydrocarbons when mixed with a gallon of 40°API hydrocarbons will not yield two gallons of 35°API hydrocarbons, but will give two gallons of hydrocarbons with an API gravity different from 35°API. Specific gravities can be averaged.

Sulfur Content, wt%

Sulfur content and API gravity are two properties which have had the greatest influence on the value of crude oil, although nitrogen and metals contents are increasing in importance. The sulfur content is expressed as percent sulfur by weight and varies from less than 0.1% to greater than 5%. Crudes with greater than 0.5% sulfur generally require more extensive processing than those with lower sulfur content. Although the term ‘‘sour’’ crude initially had reference to those crudes containing dissolved hydrogen sulfide independent of total sulfur content, it has come to mean any crude oil with a sulfur content high enough to require special processing. There is no sharp dividing line between sour and sweet crudes, but 0.5% sulfur content is frequently used as the criterion.

Pour Point, °F (°C)

The pour point of the crude oil, in °F or °C, is a rough indicator of the relative paraffinicity and aromaticity of the crude. The lower the pour point, the lower the paraffin content and the greater the content of aromatics.

Carbon Residue, wt%

Carbon residue is determined by distillation to a coke residue in the absence of air. The carbon residue is roughly related to the asphalt content of the crude and to the quantity of the lubricating oil fraction that can be recovered. In most cases =the lower the carbon residue, the more valuable the crude. This is expressed in terms of the weight percent carbon residue by either the Ramsbottom (RCR) or Conradson (CCR) ASTM test procedures (D-524 and D-189).

Salt Content, lb/1000 bbl

If the salt content of the crude, when expressed as NaCl, is greater than 10 lb/1000 bbl, it is generally necessary to desalt the crude before processing. If the salt is not removed, severe corrosion problems may be encountered. If residua are processed catalytically, desalting is desirable at even lower salt contents of the crude. Although it is not possible to have an accurate conversion unit between lb/1000 bbl and ppm by weight because of the different densities of crude oils,1 lb/1000 bbl is approximately 3 ppm.

Characterization Factors

There are several correlations between yield and the aromaticity and paraffinicity of crude oils, but the two most widely used are the UOP or Watson ‘‘characterization factor’’ (KW) and the U.S. Bureau of Mines ‘‘correlation index’’ (CI).

where

TB _ mean average boiling point, °R

G _ specific gravity at 60°F.

The Watson characterization factor ranges from less than 10 for highly aromatic materials to almost 15 for highly paraffinic compounds. Crude oils show a narrower range of KW and vary from 10.5 for a highly naphthenic crude to 12.9 for a paraffinic base crude.

The correlation index is useful in evaluating individual fractions from crude  oils. The CI scale is based upon straight-chain paraffins having a CI value of 0 and benzene having a CI value of 100. The CI values are not quantitative, but the lower the CI value, the greater the concentrations of paraffin hydrocarbons in the fraction; and the higher the CI value, the greater the concentrations of naphthenes and aromatics.

Nitrogen Content, wt%

A high nitrogen content is undesirable in crude oils because organic nitrogen compounds cause severe poisoning of catalysts used in processing and cause corrosion problems such as hydrogen blistering. Crudes containing nitrogen in amounts above 0.25% by weight require special processing to remove the nitrogen.

Distillation Range

The boiling range of the crude gives an indication of the quantities of the various products present. The most useful type of distillation is known as a true boiling point (TBP) distillation and generally refers to a distillation performed in equipment that accomplishes a reasonable degree of fractionation. There is no specific test procedure called a TBP distillation, but the U.S. Bureau of Mines Hempel and ASTM D-285 distillations are the tests most commonly used. Neither of these specify either the number of theoretical plates or the reflux ratio used and, as a result, there is a trend toward using the results of a 15:5 distillation (D-2892) rather than the TBP. The 15:5 distillation is carried out using 15 theoretical plates at a reflux ratio of 5:1. The crude distillation range also has to be correlated with ASTM distillations because product specifications are generally based on the simple ASTM distillation tests D-86 and D-1160. The TBP cut point for various fractions can be approximated by use of Figure bellow. A more detailed procedure for correlation of ASTM and TBP distillations is given in the API Technical Data Book—Petroleum Refining published by the American Petroleum Institute, Washington, DC.

Metals Content, ppm

The metals content of crude oils can vary from a few parts per million to more than 1000 ppm and, in spite of their relatively low concentrations, are of considerable importance. Minute quantities of some of these metals (nickel, vanadium, and copper) can severely affect the activities of catalysts and result in a lowervalue product distribution. Vanadium concentrations above 2 ppm in fuel oils can lead to severe corrosion to turbine blades and deterioration of refractory furnace linings and stacks.

Distillation concentrates the metallic constituents of crude in the residues, but some of the organometallic compounds are actually volatilized at refinery distillation temperatures and appear in the higher-boiling distillates.

The metallic content may be reduced by solvent extraction with propane or similar solvents as the organometallic compounds are precipitated with the asphaltenes and resins.

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API Oil-Water Separator

An API oil-water separator is a device designed to separate gross amounts of oil and suspended solids from the wastewater effluents of petroleum refineries, petrochemical and chemical plants, natural gas processing plants and other industrial sources.

The name is derived from the fact that such separators are designed according to standards published by the American Petroleum Institute (API).

Description of the design and operation

The API separator is a gravity separation device designed by using Stokes' Law to define the rise velocity of oil droplets based on their density and size. The design of the separator is based on the density difference between the oil and the wastewater because that difference is much smaller than the specific gravity difference between the suspended solids and water. Based on that design criterion: most of the suspended solids will settle to the bottom of the separator as a sediment layer, the oil will rise to top of the separator and the wastewater will be the middle layer between the water on top and the solids on the bottom.

Typically, the oil layer is skimmed off and subsequently re-processed or disposed of, and the bottom sediment layer is removed by a chain and flight scraper (or similar device) and a sludge pump. The water layer is sent to further treatment consisting usually of a dissolved air flotation (DAF) unit for further removal of any residual oil and then to some type of biological treatment unit for removal of undesirable dissolved chemical compounds.

Parallel plate separators are similar to API separators but they include tilted parallel plate assemblies (also known as parallel packs). The underside of each parallel plate provides more surface for suspended oil droplets to coalesce into larger globules. Any sediment slides down the topside of each parallel plate. Such separators still depend upon the specific gravity between the suspended oil and the water. However, the parallel plates enhance the degree of oil-water separation. The result is that a parallel plate separator requires significantly less space than a conventional API separator to achieve the same degree of separation.

History

The API separator was developed about 75 years ago by the API and the Rex Chain Belt Company. The first API separator was installed in 1933 at the Atlantic Refining Company (ARCO) refinery in Philadelphia. Since that time, virtually all of the refineries worldwide have installed API separators in their wastewater treatment plants. The majority of those refineries installed the API separators using the original design based on the specific gravity difference between oil and water. However, many refineries now use plastic parallel plate packing to enhance the gravity separation.

Other oil-water separation applications

There are other applications requiring oil-water separation. For example:

·    Oily water separators (OWS) for separating oil from the bilge water accumulated in ships as required by the international MARPOL Convention.

·     Oil and water separators are commonly used in electrical substations. The transformers found in substations use a large amount of oil for cooling purposes. Moats are constructed surrounding unenclosed substations to catch any leaked oil, but these will also catch rainwater. Oil and water separators provide a quick and easy cleanup of an oil leak

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