Refining and Sales

Crude Oil Fundamentals

12:33

Elemental Composition

of crude oil

 Petroleum is essentially a mixture of hydrocarbons, and hydrocarbons containing small quantities of oxygen, sulfur, nitrogen, vanadium, nickel, and chromium.  The hydrocarbons present in crude petroleum are

classified into three general types:

1. paraffins, 2. naphthenes, and 3. aromatics.

 In addition, there is a fourth type, olefins, that is formed during processing by the dehydrogenation of paraffins and naphthenes. 04:49 12:33 Nitrogen 0–0.6 2 0–3 Sulfur 11–14 Hydrogen 84–87 Carbon % wt Element

Paraffins, Naphthenes,Olefins & Aromatics

12:33

3.1 Crude Oil Properties

 Crude petroleum is very complex so no attempt is made by the refiner to analyze for the pure components it containes.

 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 feed stocks available and, based upon the operating cost and product realization, is assigned a value.

04:49 12:33 4

Crude Oil Characteristics

API

 Crude density is commonly measured by API gravity as it provides a relative measure of crude oil density.  The higher the API number, the lighter the crude  Classified as light >34, medium 24 – 26, or heavy <24)  Water has an API = 10

04:49 12:33 5

o

API=141.5

specific gravity @ 60oF− 131.5

CRUDE OIL CHARACTERISTICS

Sweet or sour & TAN

 Sulfur content measures if a crude is sweet (low sulfur) or sour (high sulfur)

1. <0.5% sulfur content = sweet 2. >0.5% sulfur content = sour

 High sulfur crudes require additional processing to meet regulatory specs

 Acid content measured by Total Acid Number (TAN)

 High acid crudes are those with TAN > 0.7  Acidic crudes highly corrosive to refinery

equipment

Salt Content or BS&W

 If the salt content of the crude, when expressed as NaCl, is greater than 10 lb/ 1000 bbl (approximately 30 ppm), it is generally necessary to desalt the crude before processing.  If the salt is not removed, severe corrosion problems may be

encountered.

04:49 12:33 7

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)

U.S. Bureau of Mines ‘‘correlation index’’ (CI).

04:49 12:33 8 Kw=T B 1 3 G 456.8 473.7G 552 87 _{ } B T , = CI where

TB = mean average boiling point, °R G = specific gravity at 60°F.

Watson characterization factor

KW < 10 aromatic materials KW 10 to 12 highly naphthenic

KW 12 to 15 highly paraffinic compounds.

04:49 12:33 9

The correlation index

The lower the CI value, the greater the concentrations of paraffin hydrocarbons in the fraction;

The higher the CI value, the greater the concentrations of naphthenes and aromatics. 

Distillation Range D86

The boiling range of the crude gives an indication of the quantities of the various products present.

04:49 12:33 10

Uses of Crude oil

12:33

 In general, the products which dictate refinery design are LPG, gasoline, diesel, jet fuel, and home and industry heating oils.

 Storage and waste disposal are expensive, and it is necessary to sell or use all of the items produced from crude oil even if some of the materials, such as high sulfur heavy fuel oil and fuel grade coke, must be sold at prices less than the cost of the crude oil.  Economic balances are required to determine

whether certain crude oil fractions should be sold as is (i.e., straight run) or further processed to produce products having greater value.

04:49 12:33 14

 Usually the lowest value of a hydrocarbon product is its heating value or fuel oil equivalent (FOE).  This value is always established by location, demand,

availability, combustion characteristics, sulfur content, and prices of competing fuels.

 Knowledge of the physical and chemical properties of the petroleum products is necessary for an understanding of the need for the various refinery processes.

 To provide an orderly portrayal of the refinery products, they are described in the following paragraphs in order of increasing specific gravity and decreasing volatility and API gravity.

04:49 12:33 15

The Standard oil blue barrel

• The Standard barrel of crude

(abbreviated bbl) is 42 US gallons (158.9873 L).

• This measurement originated in the

early Pennsylvania oil fields is based on the old English wine measure, the tierce.

• Earlier, another size of whiskey barrel

was the most common size; this was the 40 US gallons (151.4 L)

• In 1866 the oil barrel was

standardized at 42 US gallons. 12:33

Refining Technology

What’s in a Barrel of Crude Oil?

• Refineries upgrade crude oil to higher value products

12:33

Types of Refinery Processes

1. Physical Separation Processes

 Distillation/Fractionation  Extraction 2. Chemical Processes  Cracking/Conversion  Combination/Reformulation  Hydrotreating 12:33

Refinery Configuration Overview

1. Topping – Simple crude separation, no ability to change yield and quality

2. Hydroskimming – Simple crude separation, no ability to adjust yield. Can increase octane, lower sulfur

3. Conversion – Yield adjustment capability and quality improvement

4. Deep Conversion – Large yield/quality flexibility, fuel oil minimization.

12:33

Simple crude separation, no ability to change yield and quality

Simple crude separation, no ability to adjust yield. Can increase octane & lower sulfur

12:33

Reformer

Naphtha is catalytically processed and reformed to High octane Reformate.

12:33

Diesel Hydrodesulfurization (HDS)

Sulfur is catalytically removed in the presence of hydrogen

12:33

Conversion Refinery

Catalytic Cracking (FCC) – Large yield/quality flexibility, fuel oil minimization

Fluid Catalytic Cracking (FCC)

Makes gasoline out of vacuum gasoil (a stream heavier than diesel).

Using intense heat (about 1,000 deg F), low pressure and a powdered catalyst, the cat cracker converts heavy fractions into smaller gasoline molecules

Product streams typically have high sulfur content

Alkylation

Combines FCC gas propylenes / butylenes) with isobutane to produce a high octane stream called alkylate.

 Catalyst is sulfuric or hydrofluoric acid Alkylate is an excellent diluent for other

gasoline blending components

12:33

Diesel HDS and Aromatic

Saturation

Necessary for FCC LCO treatment 1st stage - requires Diesel HDS

2nd stage – aromatic saturation with noble catalysts

Process consumes high quantities of hydrogen Gains of 17 to 23 cetane numbers are possible

12:33

12:33

Deep Conversion Refinery Catalytic Cracking, Coking & Hydrocracking

– Yield adjustment capability and quality improvement

Hydrocracking

Similar and preferably lighter feeds than cat cracking

More flexible. Can optionally maximize gasoline, jet or diesel

Uses a different catalyst, much greater pressure than FCC and a lot of hydrogen Products have minimal sulfur

12:33

Visbreaking

Also vacuum residue feed

Mild form of thermal cracking. Reduces viscosity of residue

Produces small quantity of diesel.

Coking

Vacuum residue feed

Thermal cracking process. No catalyst involved.

Use heat and moderate pressure to turn heavy residues to lighter products and coke (a hard coal-like substance used as an industrial fuel).

Blending

Blending is the physical mixture of a number of refinery streams to a finished product. Options include:

Batch blending via manifolds into a tank In-line blending via injection of proportionate

components into a main stream

Additives/Improvers such as octane enhancers, detergents etc. are added before or after blending

12:33

Table 5.1. Hydroskimming Refinery

Complexity Calculation

Straight run gasoline treater 0.5 0.15 0.075

Kerosene hydrotreater 0.5 0.15 0.075

Distillate hydrotreater 0.5 0.20 0.100

Complexity 2.49

12:33

• What about more complicated refineries that convert much of that residual fuel into gasoline and distillates?

• The complexity factor of these gasoline refineries goes up rapidly because the units added are very expensive.

12:33

• Adding the flasher (complexity factor of 2.0), cat cracker (6.0), hydro cracker (10.0), alkylation unit (11.0), and the auxiliary treaters and equipment puts the complexity of the gasoline refinery in Figure 5.2 at 9-10.0. • The residual fuel yield in one of these

refineries is down in the range of 15-20%, while the gasoline yield is probably in the range of 45-55%.

12:33

• At the extreme range of complexity are the refineries that have facilities to produce the high value-added products such as lube oils or petrochemicals.

• The complexity factors, i.e., the capital costs, are high. For aromatics recovery, the complexity factor is 33; for olefins, depending on the feed and downstream treating, 10-20.

• It isn't unusual to see a refinery with 10% petrochemicals yield (ethylene, propylene, butadiene, and aromatics) with a complexity of 16 or more.

12:33

• Nelson's analysis relates refinery complexity to refinery cost and takes into account the economies of scale for refinery size.

The scale on the left is just an index. It must be calibrated to the current inflation adjusted cost of construction for a crude distilling unit. The rest of the chart shows the relationship of

crude distillation throughput, the normal indicator is for "refinery size” to complexity now the more sophisticated engineering approach to size.

12:33

Figure 5.3. Refinery Cost vs. Complexity

12:33

Product Yields of Different Crudes

38% 35% 24% 3% 60% 25% 14% 1% LPG & Gases Gasoline Distillate Heavy Gas Oil & Bottoms

Light Crude

Heavy Crude Crude Oil Fractions

•The light and sweat crude production (Brent and WTI) is declining

•Middle East has the largest growth potential, though the crude is sour

•S. America (e.g. Venezuela) has large heavy oil reserve •West and North Africa has potential in producing light and sweat crude

12:33

Deep Conversion Refinery Catalytic Cracking, Coking & Hydrocracking

netback

• The gross profit per barrel of oil produced by a refinery.

• A company calculates a netback by subtracting all of the costs of delivering a barrel of oil to the marketplace from all of the revenues produced from the sale of oil or hydrocarbon byproducts. • Oil and gas companies use the netback value to compare costs against competitors and to plan strategically for exploration and production of products.

• Costs included in the netback calculation may include refining and production costs, and distribution costs.

• Other costs involved with delivery of oil products to the market include taxes, royalties, and marketing costs.

Netback calculation

• Take a hydroskimming refinery processing West Texas sour crude and selling products into the spot market.

• Compare that to a gasoline refinery doing the same thing.

12:33

• It is clear that if West Texas sour crude is available to either refinery at a price of $28/bbl, and if the product prices are those shown, then the gasoline refinery will make more money than the hydro skimming refinery.

• The more complex refinery has a bigger operating margin than the less complex (simple) one.

• That's easy enough.

12:33

Table 5.2. Refining $28/bbl West Texas Sour Crude Hydroskimming Refinery Gasoline Refinery

% Volume Unit Costs or Price Revenue or Total Cost$ % Volume Unit Costs or Price Revenue or Total Cost. $ West Texas Sour Crude 100 28 (28.00) 100 $28 (28.00)

Gasoline 30 35 10.50 50 35 17.50 Jet fuel 10 33 3.30 20 33 6.60 Distillate fuel 20 31 6.20 24 31 7.44 Residual fuel 37 22 8.14 1 22 0.22 Refinery fuel 3 - - 5 - - Total outturn 100 28.14 100 31.76 Operating costs 100 1 (1.00) 100 3 (3.00) Operating margin 100 -0.86 100 0.76 12:33

• But change one variable and a slightly different message emerges in Table 5.3. • Instead of West Texas sour crude at $28/bbl,

substitute a very heavy crude like Mayan (from Mexico) at a price of $25/bbl.

12:33

• The distillation curve and other characteristics of Mayan crude are different than West Texas sour, but the hardware is still the same in each refinery.

• So the yields are quite different, and look what happens to the operating margins! • The simple refinery makes almost as much

money as the complex refinery. 12:33

Table 5.3. Refining $25/bbl Mayan Crude

Hydroskimming Refinery Gasoline Refinery

% Volume Unit Costs or Price Revenue or Total Cost$

% Volume Unit Costs or Price Revenue or Total Cost. $ 100 25 25.00 100 25 25.00 Gasoline 16 35 5.60 26 35 9.10 Jet fuel 12 33 3.96 20 33 6.60 Distillate fuel 22 31 6.82 27 31 8.37 Residual fuel 47 22 10.34 21 22 4.62 Refinery fuel 3 - - 6 - - Total outturn 100 26.72 100 28.69 Operating costs 100 1 (1.00) 100 3 (3.00) Operating margin 100 0.72 100 0.69 12:33

There are a few important observations at this point:

1. Mayan crude has about the same profitability in either type refinery, simple or complex. 2. Simple refiners can't afford to run West Texas

sour. The acquisition cost is too high for the product slate that is produced. Complex refiners make enough light products to give a positive margin.

12:33

3. It might be that the complex refiner has bid up the price of West Texas sour crude so that the simple refiner can't afford it.

4. The yields from Mayan are such that the complex refiner has hardly any room to bid it up and take it away from the simple refiner. The price of Mayan is already so high at $25/bbl that neither simple nor complex makes much margin ($0. 72-$0. 69/bbl). 12:33

• While that third observation might seem profound, it might also be a gross exaggeration. • The situation may instead be that there is so

much Mayan crude around that it fills up the complex refineries and some has to be run in the simple refineries, too. (Hence, the same margin in both types of refinery.)

• Furthermore, the product demands (and prices) are such that additional crude (West Texas sour) has to be run in complex refineries to meet the light oil demands.

12:33

• Deciding which of those conditions prevails often isn't possible by looking only at crude oil margins for any specific point in time. • There are too many variables to pin it down. • But as you'll see, changes over time can tell a

story.

12:33

One more example.

• Suppose the relationship between the light oil (gasoline, jet fuel, and distillate fuel) prices and the resid prices, i.e., the resid/light oil differential, changes.

• In Tables 5.2 and 5.3, the average resid/light oil differential is about $9.00. Say for some reason it increases to $13.00/bbl; light oils increase in price by $3/bbl, resid falls off by $1/bbl.

Table 4 refinery Operating Margins

Hydroskimming Gasoline

West Texas Sour

$9.00 spread -$0.86 $0.76

$13.00 spread -$0.63 $1.69

Mayan

$9.00 spread $0.72 $0.91

• At first glance it might seem that both types of refiners are better off-all the operating margins are larger.

• But closer examination indicates that the simple refiner is more vulnerable. • The spread between simple and complex

operating margins has increased, too. • That gives the complex refiner more room to

maneuvre, perhaps bidding up the crude prices to the point of eliminating any margin for the simple refiner.

12:33

Will the price be bid up?

• If the simple refiner can no longer afford to refine either crude, will his shutdown affect the product supply/demand balances? • Will that affect the resid/light oil differential? • And will that ultimately provide an incentive

for the simple refiner to start-up again?

12:33

5.1.1 Industry's Model

• All those questions are only a sample of what is asked every day as crude oil prices and product prices and differentials change.

• To cope, some rigor has been introduced to the analysis, and it shows up even in the industry press. • In general, refineries are classified as simple or

complex, although analysts often use' 'very complex" as well.

12:33

Crack spread

• Crack spread is a term used in the oil industry and futures trading for the differential between the price of crude oil and petroleum products extracted from it

• that is, the profit margin that an oil refinery can expect to make by "cracking" crude oil (breaking its long-chain hydrocarbons into useful shorter-chain petroleum products).

The futures markets

• In the futures markets, the "crack spread" is a specific spread trade involving simultaneously buying and selling contracts in crude oil and one or more derivative products, typically gasoline and heating oil.

• Oil refineries may trade a crack spread to hedge the price risk of their operations, while speculators attempt to profit from a change in the oil/gasoline price differential.

Factors affecting the crack spread

• One of the most important factors affecting the crack spread is the relative proportion of various petroleum products produced by a refinery. • Refineries produce many products from crude oil,

including gasoline, kerosene, diesel, heating oil, aviation fuel, asphalt and others.

• To some degree, the proportion of each product produced can be varied in order to suit the demands of the local market.

Factors affecting the crack spread

• Regional differences in the demand for each refined product depend upon the relative demand for fuel for heating, cooking or transportation purposes.

• Within a region, there can also be seasonal differences in demand for heating fuel versus transportation fuel.

• The mix of refined products is also affected by the particular blend of crude oil feedstock processed by a refinery, and by the capabilities of the refinery.

• Heavier crude oils contain a higher proportion of heavy hydrocarbons composed of longer carbon chains.

• As a result, heavy crude oil is more difficult to refine into lighter products such as gasoline. • A refinery using less sophisticated processes will

be constrained in its ability to optimize its mix of refined products when processing heavy oil.

Crude oil Crude oil Gasoline Fuel Oil FO Long Crude Oil Short Gasoline Short FO Crack Spread bbl galon galon galon 5 3 2

Jun-08 $125.96 $3.00 $3.20 $3.64 $15.00 $9.60 $7.28 $1.88 Jul-08 $126.00 $3.00 $3.19 $3.65 $15.00 $9.57 $7.30 $1.87 Aug-08 $125.76 $2.99 $3.18 $3.66 $14.97 $9.54 $7.32 $1.89 Sep-08 $125.45 $2.99 $3.16 $3.67 $14.93 $9.48 $7.34 $1.89 Oct-08 $125.14 $2.98 $3.03 $3.69 $14.90 $9.09 $7.38 $1.57 Nov-08 $124.83 $2.97 $3.00 $3.69 $14.86 $9.00 $7.38 $1.52

Simple Refinery

• hydrotreating of middle distillates, • cat reforming of naphtha.

12:33

Complex Refinery

• cat cracker,

• alkylation plant plus • gas processing.

Very Complex Refinery

• either an olefins unit or a

• Any crude run through these three refineries will have higher light oil yields in the very complex refinery than the simple. Take West Texas sour, for instance:

12:33

Table 5.5. Complexity and Yields

% Yield

Simple Complex Very Complex

Gasoline 30 50 65 Jet fuel 10 19 20 Distillate fuel 20 17 25 Residual fuel 35 20 0 Fuel (gain) 5 (6) (10) 12:33

• Another crude will have its own set of yields from each refinery. In the typical industry model, the yield for each crude for each type refinery has to be individually calculated. • In that way, the incentives to refine what and

where can be observed.

• Typically, that's done by looking at the results of the calculations two different ways: a snapshot of how the whole industry looks now and a look at how parts of it operate over time.

12:33

 Conversion capacity needed to capitalize on sour crude discounts

 Hydroskim – Breakeven or moderate margins; High resid yield

 When margins are positive – increase crude runs  When margins are negative – decrease crude runs

Cracking – Better margins; Lower resid yield Coking – Best margins; Lowest resid yield

 Maximize heavy crudes

• Ref_Margins.xls

6. Crude Distillation

 The crude stills are the first major processing units used to separate the crude oils by distillation into fractions according to boiling point so that each of the processing units following will have feedstocks that meet their particular specifications.  Higher efficiencies and lower costs are achieved if the crude

oil separation is accomplished in two steps:

 first by fractionating the total crude oil at essentially atmospheric pressure;

 then by feeding the high boiling bottoms fraction (topped or atmospheric reduced crude) from the atmospheric still to a second fractionator operated at a high vacuum.

04:49 12:33 77

Process Objective:

• To distill and separate valuable distillates (naphtha, kerosene, diesel) and atmospheric gas oil (AGO) from the crude feedstock. • Primary Process Technique:

• Complex distillation

Crude Distillation Unit (CDU)

Process Schematic

04:49 12:33 79

Process steps

• Preheat the crude feed utilizing recovered heat from the product

• Streams

• Desalt and dehydrate the crude using electrostatic enhanced

• liquid/liquid separation (Desalter)

12:33

• Heat the crude to the desired temperature using fired heaters

• Flash the crude in the atmospheric distillation column

• Utilize pumparound cooling loops to create internal liquid reflux

• Product draws are on the top, sides, and bottom

12:33

Typical Yields and Dispositions

Light Ends 2.3 LPG

Light Naphtha 6.3 Naphtha Hydrotreating Medium Naphtha 14.4 Naphtha Hydrotreating Heavy Naphtha 9.4 Distillate Hydrotreating Kerosene 9.9 Distillate Hydrotreating Atmospheric Gas Oil 15.1 Fluid Catalytic Cracking Reduced Crude 42.6 Vacuum Distillation Unit

12:33

VDU Process

The vacuum still is employed to separate the heavier portion of the crude oil into fractions because the high temperatures necessary to vaporize the topped crude at atmospheric pressure cause thermal cracking to occur, with the resulting loss to dry gas, discoloration of the product, and equipment fouling due to coke formation.

Process Objectives

• To recover valuable gas oils from reduced crude via vacuum distillation.

• Primary Process Technique:

• Reduce the hydrocarbon partial pressure via vacuum and stripping steam.

12:33

Process steps:

• Heat the reduced crude to the desired temperature using fired heaters • Flash the reduced crude in the vacuum

distillation column

• Utilize pumparound cooling loops to create internal liquid reflux

• Use Stripping steam to enhance separation • Product draws are top, sides, and bottom 12:33

Typical Yields and Dispositions

Light Ends <1 LPG

Light VGO 17.6 Distillate Hydrotreating Heavy VGO 12.7 Fluid Catalytic Cracking Vacuum residue (Resid) 12.3 Coking

12:33

Table 5.1 Boiling Ranges of Typical

Crude Oil Fractions

04:49 12:33 88

1050+ 1050+

Vacuum reduced crude (VRC)

800–1050 750–1050

Vacuum gas oil (VGO)

610–800 550–830

Atmospheric gas oil (AGO)

520–610 420–640

Light gas oil (LGO)

380–520 330–540

Kerosine

190–380 180–400

Heavy straight run naphtha (HSR)

90–190 90–220

Light straight run naphtha (LSR)

TBP ASTM

Butanes and lighter

Boiling ranges, °F / °C Fraction

Desalting Crude Oils

 If the salt content of the crude oil is greater than 10 lb/1000 bbl ((approx. 30ppm wt expressed as NaCl), the crude requires desalting to minimize fouling and corrosion caused by salt deposition on heat transfer surfaces and acids formed by decomposition of the chloride salts.

 In addition, some metals in inorganic compounds dissolved in water emulsified with the crude oil, which can cause catalyst deactivation in catalytic processing units, are partially rejected in the desalting process.

04:49 12:33 89

 The trend toward running heavier crude oils has increased the importance of efficient desalting of crudes.

 Until recently, the criterion for desalting crude oils was 10 lb salt/1000 bbl (expressed as NaCl) or more, but now many companies desalt all crude oils.  Reduced equipment fouling and corrosion and longer

catalyst life provide justification for this additional treatment.

Two stage desalting is used if the crude oil salt content is more than 20 lb/1000 bbl and, in the cases where residua are catalytically processed, there are some crudes for which three stage desalting is used.

The salt in the crude is in the form of dissolved or suspended salt crystals in water emulsified with the crude oil.

04:49 12:33 91

 The basic principle is to wash the salt from the crude oil with water.

 Problems occur in obtaining efficient and economical water/oil mixing, water wetting of suspended solids, and separation of the wash water from the oil.  The pH, gravity, and viscosity of the crude oil, as well

as the volume of wash water used per volume of crude, affect the separation ease and efficiency.

04:49 12:33 92

 A secondary but important function of the desalting process is the removal of suspended solids from the crude oil.

 These are usually very fine sand, clay, and soil particles; iron oxide and iron sulfide particles from pipelines, tanks, or tankers; and other contaminants picked up in transit or production.

 Total suspended solids removal should be 60% or better with 80% removal of particles greater than 0.8 micron in size.

04:49 12:33 93

• Desalting is carried out by mixing the crude oil with from 3 to 10 vol% water at temperatures from 200 to 300°F (90 to 150°C).

• Both the ratio of the water to oil and the temperature of operation are functions of the density of the oil.

04:49 12:33 94

Typical operating conditions

280–330 (140–150) 7–10 <30 260–280 (125–140) 4–7 30–40 240–260 (115–125) 3–4 >40 Temp. ° F (° C) Water wash, vol%

°API

 The salts are dissolved in the wash water and the oil and water phases separated in a settling vessel either by adding chemicals to assist in breaking the emulsion or by developing a high potential electrical field across the settling vessel to coalesce the droplets of salty water more rapidly (Fig. 5.6).  Either AC or DC fields may be used and potentials

from 12,000 to 35,000 volts are used to promote coalescence.

 For single stage desalting units 90 to 95% efficiencies are obtained and two stage processes achieve 99% or better efficiency.

 One process uses both AC and DC fields to provide high dewatering efficiency.

 An AC field is applied near the oil–water interface and a DC field in the oil phase above the interface.  Efficiencies of up to 99% water removal in a single

stage are claimed for the dual field process.  About 90% of desalters use AC field separation only.

04:49 12:33 97

Figure 6.3 One stage desalting

04:49 12:33 98

Figure 6.4 Two stage desalting

12:33

The dual field electrostatic process provides efficient water separation at temperatures lower than the other processes and, as a result, higher energy efficiencies are obtained.

04:49 12:33 100

• Heavy naphthenic crudes form more stable emulsions than most other crude oils and desalters usually operate at lower efficiencies when handling them.

• The crude oil densities are close to the density of water and temperature above 280°F (138°C) are needed.

• It is sometimes necessary to adjust the pH of the brine to obtain pH values of 7 or less in the water. • If the pH of the brine exceeds 7, emulsions can be formed because of the sodium naphthenate and sodium sulfide present.

04:49 12:33 101

For most crude oils it is desirable to keep the pH below 8.0.

Better dehydration is obtained in electrical desalters when they are operated in the pH range of 6 to 8 with the best dehydration obtained at a pH near 6.

The pH value is controlled by using another water source or by the addition of acid to the inlet or recycled water.

• Make up water averages 4 to 5% on crude oil charge and is added to the second stage of a two stage desalter.

• For very heavy crude oils (<15°API), addition of gas oil as a diluent to the second stage is recommended to provide better separation efficiencies.

04:49 12:33 103

Table 6.3 Crude oil desalting units investment cost

04:49 12:33 104 Costs included 1. Conventional electrostatic desalting unit 2. Water injection 3. Caustic injection 4. Water preheating and cooling

Costs not included

1. Waste water treating and disposal

2. Cooling water and power supply

Utility data (per bbl feed)

Power, kWh 0.01–0.02 Water injection, gal (m3_)1–3 (0.004–0.012) Demulsifier chemical, lb (kg)a 0.005–0.01 (0.002–0.005) Caustic, lb (kg) 0.001– 0.003 (0.005–0.0014) a _{1999 price approximately $1.50/lb.}

Frequently, the wash water used is obtained from the vacuum crude unit barometric condensers or other refinery sources containing phenols.

The phenols are preferentially soluble in the crude oil thus reducing the phenol content of the water sent to the refinery waste water handling system.

04:49 12:33 105

Suspended solids are one of the major causes of water in oil emulsions.

Wetting agents are frequently added to improve the water wetting of solids and reduce oil carry under in desalters.

Oxyalkylated alkylphenols and sulfates are the most frequently used wetting agents.

04:49 12:33 106

The following analytical methods are used to determine the salt content of crude oils:

HACH titration with mercuric nitrate after water extraction of the salt

Potentiometric titration after water extraction Mohr titration with silver nitrate after water

extraction

Potentiometric titration in a mixed solvent Conductivity

Although the conductivity method is the one most widely used for process control, it is probably the least accurate of these methods. Whenever used it should be standardized for

Atmospheric Topping Unit

• After desalting, the crude oil is pumped through a series of heat exchangers and its temperature raised to about 550°F (288°C) by heat exchange with product and reflux streams.

• It is then further heated to about 750°F (399°C) in a furnace (i.e., direct fired heater or ‘‘pipestill’’) and charged to the flash zone of the atmospheric fractionators.

04:49 12:33 109

• The furnace discharge temperature is sufficiently high [650 to 750°F (343 to 399°C)] to cause vaporization of all products with drawn above the flash zone plus about 10 to 20% of the bottoms product.

• This 10 to 20% ‘‘over flash’’ allows some fractionation to occur on the trays just above the flash zone by providing internal reflux in excess of the side stream withdrawals.

04:49 12:33 110

Reflux is provided by condensing the tower overhead vapors and returning a portion of the liquid to the top of the tower, and by pump around and pump back streams lower in the tower.

Each of the side stream products removed from the tower decreases the amount of reflux below the point of draw off.

04:49 12:33 111

 Maximum reflux and fractionation is obtained by removing all heat at the top of the tower, but this results in an inverted cone type liquid loading which requires a very large diameter at the top of the tower.

 To reduce the top diameter of the tower and even the liquid loading over the length of the tower, intermediate heat removal streams are used to generate reflux below the side stream removal points.

04:49 12:33 112

To accomplish this, liquid is removed from the tower, cooled by a heat exchanger, and returned to the tower or, alternatively, a portion of the cooled side stream may be returned to the tower.

This cold stream condenses more of the vapors coming up the lower and thereby increases the reflux below that point.

04:49 12:33 113

 The energy efficiency of the distillation operation is also improved by using pump around reflux.  If sufficient reflux were produced in the overhead

condenser to provide for all sidestream drawoffs as well as the required reflux, all of the heat energy would be exchanged at the bubble point temperature of the overhead stream.

 By using pump around reflux at lower points in the column, the heat transfer temperatures are higher and a higher fraction of the heat energy can be recovered by preheating the feed.

 Although crude towers do not normally use reboilers, several trays are generally incorporated below the flash zone and steam is introduced below the bottom tray to strip any remaining gas oil from the liquid in the flash zone and to produce a high flash point bottoms.

 The steam reduces the partial pressure of the hydrocarbons and thus lowers the required vaporization temperature.

04:49 12:33 115

 The atmospheric fractionator normally contains 30 to 50 fractionation trays.

 Separation of the complex mixtures in crude oils is relatively easy and generally five to eight trays are needed for each sidestream product plus the same number above and below the feed plate.  Thus, a crude oil atmospheric fractionation tower

with four liquid sidestream drawoffs will require from 30 to 42 trays.

04:49 12:33 116

 The liquid sidestream withdrawn from the tower will contain low boiling components which lower the flashpoint, because the lighter products pass through the heavier products and are in equilibrium with them on every tray.

 These ‘‘light ends’’ are stripped from each sidestream in a separate small stripping tower containing four to ten trays with steam introduced under the bottom tray.

 The steam and stripped light ends are vented back into the vapor zone of the atmospheric fractionator above the corresponding side draw tray (Fig. 5.8).

04:49 12:33 117

The overhead condenser on the atmospheric tower condenses the pentane and heavier fraction of the vapors that passes out of the top of the tower.

This is the light gasoline portion of the overhead, containing some propane and butanes and essentially all of the higher boiling components in the tower overhead vapor.

04:49 12:33 118

• Some of this condensate is returned to the top of the tower as reflux, and the remainder is sent to the stabilization section of the refinery gas plant where the butanes and propane are separated from the C5-180°F(C5-82°C) LSR gasoline.

• Installed costs of atmospheric crude distillation units are shown in Figure 4.9, and utility requirements are given by Table 5.4.

04:49 12:33 121 04:49 12:33 122

04:49 12:33 123 04:49 12:33 124

04:49 12:33 127 04:49 12:33 128

04:49 12:33 133 04:49 12:33 134

04:49 12:33 135 04:49 12:33 136

04:49 12:33 139 04:49 12:33 140

Vacuum Distillation

The furnace outlet temperatures required for atmospheric pressure distillation of the heavier fractions of crude oil are so high that thermal cracking would occur, with the resultant loss of product and equipment fouling.

04:49 12:33 141

 These materials are therefore distilled under vacuum because the boiling temperature decreases with a lowering of the pressure.

 Distillation is carried out with absolute pressures in the tower flash zone area of 25 to 40 mmHg (Fig. 4.9).

 To improve vaporization, the effective pressure is lowered even further (to 10 mmHg or less) by the addition of steam to the furnace inlet and at the bottom of the vacuum tower.

04:49 12:33 142

Addition of steam to the furnace inlet increases the furnace tube velocity and minimizes coke formation in the furnace as well as decreasing the total hydrocarbon partial pressure in the vacuum tower. The amount of stripping steam used is a

function of the boiling range of the feed and the fraction vaporized, but generally ranges from 10 to 50 lb/bbl feed.

• Furnace outlet temperatures are also a function of the boiling range of the feed and the fraction vaporized as well as of the feed coking characteristics.

• High tube velocities and steam addition minimize coke formation, and furnace outlet temperatures in the range of 730 to 850°F (388 to 454°C) are generally used.

 Typically the highest furnace outlet temperatures are for ‘‘dry’’ operation of the vacuum unit; that is, no steam is added either to the furnace inlet or to the vacuum column.  The lowest furnace outlet temperatures are for ‘‘wet’’

operation when steam is added to both the furnace inlet and to the bottom of the vacuum tower.

 Intermediate temperatures are used for ‘‘damp’’ operation of the vacuum unit when steam is added to the furnace inlet only.

 For most crude oils the furnaces can be operated from three to five years between turnarounds.

04:49 12:33 145

 The effective pressure (total absolute pressure– partial pressure of the steam) at the flash zone determines the fraction of the feed vaporized for a given furnace outlet temperature, so it is essential to design the fractionation tower, overhead lines, and condenser to minimize the pressure drop between the vacuum inducing device and the flash zone.  A few millimeters decrease in pressure drop will save

many dollars in operating costs.

04:49 12:33 146

The lower operating pressures cause significant increases in the volume of vapor per barrel vaporized and, as a result, the vacuum distillation columns are much larger in diameter than atmospheric towers.

It is not unusual to have vacuum towers up to 40 feet in diameter.

04:49 12:33 147

 The desired operating pressure is maintained by the use of steam ejectors and barometric condensers or vacuum pumps and surface condensers.

 The size and number of ejectors and condensers used is determined by the vacuum needed and the quality of vapors handled.

 For a flash zone pressure of 25 mmHg, three ejector stages are usually required.

04:49 12:33 148

 The first stage condenses the steam and compresses the non condensable gases, while the second and third stages remove the non condensable gases from the condensers.

 The vacuum produced is limited to the vapor pressure of the water used in the condensers.  If colder water is supplied to the condensers, a lower

absolute pressure can be obtained in the vacuum tower.

04:49 12:33 149

 Although more costly than barometric condensers, a recent trend is the use of vacuum pumps and surface condensers in order to reduce the contamination of water with oil.

 A schematic of a crude oil vacuum distillation unit is shown in Figure 5.10, and installed costs are shown in Figure 5.11, and utility requirements are given by Table 5.5.

Vacuum distillation

units investment cost

04:49 12:33 151

1. All facilities required for producing a clean vacuum gas oil (single cut) 2. Three stage jet system for operation of

flash zone at 30 to 40 torr 3. Coolers and exchangers to reduce VGO

to ambient temperature

Costs not included

1. Cooling water, steam, power supply 2. Bottoms cooling below 400° F (204°C) 3. Feed preheat up to 670°F (354 °C), ±10 (assumes feed is direct from atm crude unit)

4. Sour water treating and disposal 5. Feed and product storage 6. Multiple ‘‘cuts’’ or lube oil production

Utility data (per bbl feed)

Steam [300 psig (2068 kPa)], lb (kg) 10.0 (4.5)

Power, kWh 0.3

Cooling water circulation, gal (m3)a 150 (0.57)

Fuel, MMBtu (kJ)b 0.03 (31,650)

a _{30°F (16.7° C) rise.}

b _{LHV basis, heater efficiency taken into}

account.

Auxiliary Equipment

 In many cases, a flash drum is installed between the feed preheat heat exchangers and the atmospheric pipe still furnace.

 The lower boiling fractions which are vaporized by heat supplied in the preheat exchangers are separated in the flash drum and flow directly to the flash zone of the fractionator.

 The liquid is pumped through the furnace to the tower flash zone.

 This results in a smaller and lower cost furnace and lower furnace outlet temperatures for the same quantity of over head streams produced.

04:49 12:33 152

A stabilizer is incorporated in the crude distillation section of some refineries instead of being placed with the refinery gas plant. The liquid condensed from the overhead

vapor stream of the atmospheric pipe still contains propane and butanes which make the vapor pressure much higher than is acceptable for gasoline blending.

04:49 12:33 153

 To remove these, the condensed liquid in excess of reflux requirements is charged to a stabilizing tower where the vapor pressure is adjusted by removing the propane and butanes from the LSR gasoline stream.

 Later, in the product blending section of the refinery, n-butane is added to the gasoline stream to provide the desired Reid vapor pressure.

04:49 12:33 154

Crude Distillation Unit Products –

Dry Gas

Fuel gas. The fuel gas consists mainly of methane and ethane.

In some refineries, propane in excess of LPG requirements is also included in the fuel gas stream.

This stream is also referred to as ‘‘dry gas.’’

Wet gas

The wet gas stream contains propane and butanes as well as methane and ethane. The propane and butanes are separated to be

used for LPG and, in the case of butanes, for gasoline blending and alkylation unit feed.

LSR naphtha

The stabilized LSR naphtha (or LSR gasoline or straight run tops) stream is desulfurized and used in gasoline blending or processed in an isomerization unit to improve octane before blending into gasoline.

04:49 12:33 157

HSR naphtha or HSR gasoline

The naphtha cuts are generally used as catalytic reformer feed to produce high octane reformate for gasoline blending and

aromatics.

04:49 12:33 158

Kerosene

This cut overlaps both into HSR naphtha and light gas oil.

This stream is desulphurized and it s primarily used for aviation fuel or as illuminating oil.

04:49 12:33 159

Gas oils

The light, atmospheric, and vacuum gas oils arm processed in a hydrocracker or catalytic cracker to produce gasoline, jet, and diesel fuels.

The heavier vacuum gas oils can also be used as feedstocks for lubricating oil processing units.

04:49 12:33 160

Residuum

The vacuum still bottoms can be processed in a visbreaker, coker, or deasphalting unit to produce heavy fuel oil or cracking and/or lube base stocks.

For asphalt crudes, the residuum can be processed further to produce road and/or roofing asphalts.

04:49 12:33 163 04:49 12:33 164