Enhancing Refinery Profitability by Gasification, Hydroprocessing& Power Generation

Clint F. Penrose, Paul S. Wallace, Janice L. Kasbaum,M. Kay Anderson, and William E. Preston

Texaco Power and GasificationA Division of Texaco Inc.

4800 Fournace PlaceBellaire, Texas 77401

Presented at theGasification Technologies Conference

October, 1999San Francisco, California

Table of Contents

I. Introduction 1

II. Technology Applications 3

III. Process Description 6

IV. Integration Refinery System 12

V. Integration Advantages 18

VI. Sample Economics 22

VII. Conclusion 25

VIII. References 26

1

I. INTRODUCTION

The ability to better handle heavy crudes or heavy bottom streams enhances the economicpotential of most refineries and oil fields. Refineries with the flexibility to meet the increasingproduct specifications for refined fuels will continue to show positive profit margins. Upgradingheavy oil – be it heavy crude oil in the oil field or heavy bottom streams in the refinery – is anincreasingly prevalent means of extracting maximum value from each barrel of oil produced.Upgrading can convert marginal heavy crude oil into light, higher value crude, and can convertheavy, sour refinery bottoms into valuable transportation fuels. On the downside, most upgradingtechniques leave behind an even heavier residue whose disposition costs may approach the valueof the upgrade itself.

Solvent deasphalting and residue coking are used in heavy-crude-based refineries to upgradeheavy bottom streams to intermediate products that may be processed to produce transportationfuels. The technology may also be used in the oil field to enhance the value of heavy crude oilbefore it gets to the refinery. A beneficial use is often difficult to find for the byproducts fromthese processes, asphaltenes and petroleum coke.

The Texaco Gasification Process is a market leader in the conversion of heavy oils, petroleumcoke, and other heavy petroleum streams to valuable products (i.e. Hydrogen, Power, etc.). Byintegrating heavy oil processing with gasification, important synergies may be realized. Theseinclude: increased crude and fuel flexibility; enhanced profitability through reduced capital andoperating cost; lower environmental emissions; and increase reliability and efficiency of utilities.In fact, integrating these technologies often provides economic benefits that justify the combinedprocesses in instances where using either technology on its own may not be consideredeconomically viable.

The integration between bottoms processing units and gasification can serve as a springboard forother economically enhancing integration. The integration of gasification with existing or newhydroprocessing unit, and power generation unit, presents some unique synergies that willenhance the profitability of refiners and heavy oil producers. For example, it is sometimespossible to incorporate upstream units such as crude distillation, which will further enhance theeconomics and the flexibility of the facility.

2

II. TECHNOLOGY APPLICATIONS

An integrated gasification, hydroprocessing, and power generation facility is ideal for upliftingthe economics of an existing refinery. The technology integration can be utilized by refiners thatalready process heavy crude oils or by sweet crude refineries that are looking to increase marginsby purchasing lower cost heavy crude. The integration also provides an economically alternativeto heavy oil field processing.

Refinery Applications

An integrated gasification, hydroprocessing, and power generation facility can increase the crudeand operating flexibility of the refinery. Flexibility is increased by allowing the refinery toprocess heavier crudes, convert heavy bottoms into high value product (i.e. Hydrogen, power,etc.), and create intermediate products (Deasphalted oil, diesel, sweet cat fed, etc.) to match thecapabilities of the existing refinery unit.

The economics of most refineries are handicapped by the relatively high cost of their heavybottoms processing or lack thereof. Heavy bottoms often need to be blended with valuableproduct or sold at depressed value on the solid fuels market. In addition, most refineries are notable to take advantage of lower priced heavy crude because they lack the processing capabilities.

The Texaco Gasification Process (TGP) is capable of converting these bottom materials(asphaltenes or petroleum coke) to synthesis gas (“syngas”), which mainly consists of hydrogenand carbon dioxide. Refiners may utilize syngas in a number of ways. The syngas can beconverted to hydrogen by use of the Texaco Hydrogen Generation Process (THGP), which maybe used in the refinery for hydroprocessing units such as hydrocracking or hydrotreating. Thesyngas may also be used by Texaco Gasification Power Systems (TGPS) cogeneration facilitiesto provide low cost power and steam to the refinery. If the refinery is part of a petrochemicalcomplex, the syngas can be used as a chemical feed stock.

The gasification of refinery bottoms allows the refinery to produce more intermediate productsfrom the deasphalting or coking units. These intermediate products along with otherintermediates from crude distillation can be hydroprocessed with low cost hydrogen that isproduced using THGP. The many synergies of integrating gasification, hydroprocessing andpower generation result in lowering the capital and operating costs.

Oil Field Application

For heavy crude oil producers, upgrading by integrating gasification with solvent deasphaltingand power/steam cogeneration increases the value of their crude. Deasphalting removes theheavy components, reduces the metal content, reduces the Conradson carbon, and increases theAPI gravity of the crude. The lighter crude is more easily transported and has properties muchcloser to the design crude oils of most refineries. This allows the upgrader to maximize refinedproducts production, which allows the refinery to justify a higher crude price.

The gasification unit provides the oil producer with clean syngas that can be fed to a TGPScogeneration unit to produce power and steam. The steam generated would then be used for well

3

injection to enhance oil production in the field, and the power would be sold. The syngas alsomay be sold to third parties for its chemical value.

4

III. PROCESS DESCRIPTIONS

Crude Distillation

A diagram of a crude unit is shown in Figure 1.

Crude distillation units are usually the first major process units in a refinery. These units employa distillation process to separate crude oil into various fractions according to boiling points of thevarious materials in the crude. The fractions are then distributed to a variety of downstreamprocessing units for further separation and polishing. Higher efficiencies and lower costs areachieved by splitting the distillation into an atmospheric step and a vacuum step.

First, the feed crude is fractionated at atmospheric pressure where lighter fractions are removed.The higher boiling point bottom fractions are fractionated in a distillation unit operated under ahigh vacuum. A vacuum distillation unit is used to separate the heavier portion of crude becausethe high temperatures that are needed to process all the crude at atmospheric pressure wouldcause thermal cracking of some of the crude materials. This thermal cracking would result inloss of dry gas, discoloration of some products, and equipment fouling.

HeaterHeater

Figure 1 Figure

Topped Crude

EXG “A”

Gas toLPG

Refinery

LSR Gasolineto Treating

Naphtha

EXG “A”

EXG “B”

Side CutStrippers

ATMTower

STM

7500F

CW

STM

STM

Steam

Gas Oil

CrudeCharge

Crude

Charge

Atm.Tower

Stm

Heater

Desalter2500F

Salt Water

EXG “B”

Salt Water

Heater

Stm

Stm

Side Cut

Strippers

Naphtha

Gas Oil

Stm

Topped Crude

To Vacuum Tower

LSR Gasoline

To Treating

3 to 10 PSIG1100F

RefluxDrum

Water

Water

RefluxDrum

Gas to LPG

Recovery

7 to10 MM Steam Heavy Vac Gas Oil

Vacuum Residual

OilyWater

CW CWCW

NonCondensibleGas

Steam

Ejectors

Sump

CW

VacuumTower

7300Fto

8500F Light Vac Gas Oil730 0F

to 850 0F

Stm

VacuumTower

Stm

Ejectors

NoncondensibleGas

Sump

Oily Water

Light Vac Gas Oil

Heavy Vac Gas Oil

Vacuum Resid

Crude Atmospheric & Vacuum Distillation

5

It is usually necessary to desalt the crude feed prior to the distillation process. Desaltingminimizes the fouling and corrosion that can occur when salt deposits accumulate on heattransfer surfaces, and minimizes acids form by breakdown of chloride salts. The desalter processalso removes the suspended solids and dewaters the crude oil. These suspended solids usuallyinclude sand, clay, soil, iron compounds, and other particles picked up during the production ortransit of the crude oil.

The salt in the crude is in the form of dissolved or suspended salt crystals in the water emulsifiedwith the crude oil. Desalting is carried out by mixing the crude oil with water at elevatedtemperatures. The temperature of the water and crude oil is determined by the density of thecrude oil. The salt dissolves in the water, and the water is separated from the crude in a settlingtank. The separation of the crude oil and water is assisted by adding various chemicals, or byusing a high-potential electrical field to break the emulsion of the crude and water mixture.Heavier crudes require the addition of lighter oils to essentially dilute (or to “cut”) the crudebefore desalting.

After desalting, the crude oil is heated via a series of heat exchangers and fired heaters beforebeing charged to the atmospheric distillation unit. These units are usually operated between 650and 750 ºF (343 TO 399 ºC). Initial flashing of the crude charge results in lighter ends beingprocessed in the atmospheric unit and the heavier bottoms being sent to the vacuum distillationunit. The light ends may include products such as light straight-run gasoline (butane, propane,pentanes), naphtha, kerosene, diesel and jet fuel. The atmospheric distillation is assisted by theuse of side steam strippers to further separate the crude materials that are fractionated in the maindistillation unit.

The atmospheric bottoms are distilled under vacuum to lower the boiling temperatures of thematerials, preventing thermal cracking and the resultant loss of products. The atmosphericbottoms require additional heating via a fired heater before entering the vacuum distillationcolumn. Furthermore, the desired operating pressure of the vacuum distillation unit ismaintained by the use of steam ejectors, barometric condensers or vacuum pumps, and surfacecondensers. The vacuum distillation units are usually operated with absolute pressure rangingfrom 25 to 40 mmHg, and temperature ranging from 730 to 850 ºF (388 to 454 ºC). The vacuumdistillation unit further fractionates the crude oil into heavy gas oil, vacuum gas oil, and vacuumresidue. The gas oils are then hydroprocessed or cracked to produce gasoline, jet fuel and dieselfuels. Heavier gas oils are used to produce lubricating oils. The vacuum residue is usuallyprocessed in a visbreaker, coker, or deasphalter to produce heavy fuel oil (requireshydroprocessing) and asphalts or petroleum coke.

Hydrocracker

A diagram of a hydrocracker unit is shown in Figure 2.

6

The aromatic cycle oils that are present in vacuum gas oils and coker distillates are bestprocessed in a hydrocracker unit. These materials usually resist catalytic cracking, but the highpressures and hydrogen atmosphere make them relatively easy to hydrocrack. Hydrocrackingunits typically operate with conditions ranging from 500 to 800 ºF and from 1,000 to 2,000 psig(260-425 ºC and 6,900-13,800 kPa.), and may involve one or two reaction stages. Thesevariables will change with the age of the catalyst, the product desired, and the properties of thefeedstock.

A hydrotreater is sometimes used to pretreat the feed to a hydrocracker unit, or to process thenaphtha and middles distillate stream from the atmospheric distillation unit. Pretreating of thehydrocracker feed is needed to protect the hydrocracker catalyst from various poisonouscomponents. The hydrotreater completes a variety of hydrogen and catalytic reactions, whicheffectively saturate the olefins, and remove sulfur, nitrogen, and oxygen compounds from thefeed. Metal is also removed via cracking of the material that contains metals. The nitrogen andsulfur compounds are removed by conversion to ammonia and hydrogen sulfide.

H2 MakeupGas C1 C4 LSR

Naphtha

Diesel

H2 Recycle

Feed

Option For Feed To Second Stage

Figure 2

Hydrocracker Unit

7

The hydrocracker feed is mixed with make-up hydrogen and recycled gas (high in hydrogencontent and passed through a heater to the hydrocracker reactor. The hydrogen rich gas isseparated from the reactor effluent, scrubbed to remove H2S, and recycled back to the reactor.The liquid products are fractionated in a distillation column where products such as light andheavy naphtha, jet fuel, and diesels are recovered. The fractionated bottoms are used as feed tothe second stage of the hydrocracker, or recycled to the reactor in the case of a single stage unit.

Both the hydrocracker and hydrotreater processes require a source of hydrogen, a sour gasprocess to treat hydrogen sulfide and acids, various stages of compression, and a source of heatto meet the operating temperatures. Depending on the size of the units and the overall refinery,these units usually require a dedicated source of hydrogen such as a reformer or pipeline, and adedicated sour process facility. Depending on the source of hydrogen and the hydrogenpurification facility used to treat the recycled high hydrogen gas, several stages of compressionare usually required to keep these hydrogen streams at the operating pressure of thehydroprocessing units.

Deasphalting

A diagram of a deasphalting unit is shown as Figure 3.

HeavyOil Feed Extractor

Fired Heater

Steam

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GasifierFeed Pump

SOLVENTRECOVERY

Heat FromGasification

Asphalt FeedTo Gasifier

DeasphalterOil To

Hydrotreater

SolventRecyclePump

Figure 3

Deasphalter Unit

8

The bottom product from the vacuum unit is called vacuum residue, which consist of long chainparaffinic material and asphaltenes. As much as 80% of the residue from vacuum crude oiltowers is paraffinic material that can be upgraded to diesel fuel.

The paraffinic components must be separated from the asphaltenes so that they can be cracked inconventional cracking units. This separation may be accomplished using solvent extraction. Theextractor uses a hydrocarbon such as propane, butane or pentane to extract the paraffiniccomponents from the feed stream. The heavy oil feed is mixed with the solvent. The asphaltenesare insoluble in the solvent, and are separated from the paraffinic components by settling. Theextractor produces solvent-rich deasphalted oil (DAO) and an asphaltene stream that containssome residual solvent.

The solvent-rich DAO is heated and flashed to recover the solvent. Some processes employsuper critical conditions to recover the solvent from the DAO. In either case, heat must besupplied to the process to achieve separation of the solvent from the DAO. Fired heaters andhigh-pressure steam are common sources for the heat. The solvent is returned to the extractor,and DAO is routed to a steam stripper for final solvent recovery. Typically the DAO is thenhydro-treated to remove sulfur, acids and metals, and to maximize yield in the downstreamcracking units.The solvent that is entrained in the asphaltenes must also be recovered. The solvent- containingasphaltenes are heated above the minimum asphalt pumping temperature. This ensures that theasphalt will be pumpable after the solvent is removed. The heat source is typically a fired heateror high-pressure steam. The solvent is steam stripped from the asphaltenes in a trayed tower, andis recycled to the extractor. The asphaltenes leave the stripper hot and must be cooled prior toblending for sales.

Solvent deasphalting can be a cost-effective way to produce oil that can be converted to morevaluable streams such as diesel from residual distillation products. The asphalt product from theprocess is highly viscous at ambient temperature. To market this material, it is sometimes “cut” -blended with a significant amount of expensive distillate products. This requirement is oftendetrimental to the unit’s overall economics.

The deasphalting unit requires significant amounts of heat to recover the solvent used in theextraction. Whether a fired heater generates this heat or it is obtained by the use of high-pressuresteam, the energy cost is significant. Finally, when a fired heater is used, stack emissions result.

Petroleum Coker

A diagram of a delayed coker is shown in Figure 4.

9

One example of refinery bottoms processing is a petroleum coker unit, which produces a solidbyproduct. Petroleum coker units are used to pretreat vacuum residuals for catalytic crackers.Pretreating with cokers reduces the coke formation on the catalytic cracker catalyst, increases thethroughput of catalytic cracker, reduces the metal content of the catalytic cracker feedstock, andreduces the net refinery yield of low-priced residual fuels. Delayed, Fluid, and Flexicoker arevarious types of coking processes that produce a variety of coke products. These cokingproducts display a variety of shapes (circle to needle), sizes, and ranges in sulfur content from0.3 to 8%. Delayed cokers are usually 15-20% more efficient than fluid cokers, and 2-40% moreefficient than flexicokers.

The delayed coking process was developed for the thermal cracking of vacuum residuals,aromatic gas oil, and thermal tars. Hot fresh liquid feed is charged to the fractionation column ofthe coker unit. The bottoms from the fraction column is heated to approximately 900oF andcharged to the bottom of the coke drum. The thermal cracking reaction that occurs in the cokedrum produces gas, naphtha, and gas oil. These products are transferred to the bottom of thefractionation column for distillation. The naphtha and gas oils are further processed in sidestrippers to the fractionation column.

9250F

STM

1000F5-10 PSIG

15

7

6

4

1

8

1

CokeDrums

8200F 25-30 PSIG CW Gas

RefluxDrum

UnstabilizedNaphtha

STM

Gas OilGas OilStripper

Heater Fractionator

Fresh FeedCoke

Figure 4

Delayed Coker Unit

10

Coker liquids typically require hydrotreating to remove sulfur and nitrogen before they can beprocessed into finished products. In addition, the heavier fractions require cracking to producefinished products. The coker light ends are primarily recovered through compression, multi-stage cooling, and separation.

Texaco Gasification Process

The Texaco Gasification Process was developed in the late 1940s. It was intended to producehydrogen and carbon monoxide - syngas - for chemical plant and refinery applications. It wasdesigned to process natural gas. In the 1950s, it was modified for heavy oil feeds, in the 1970sfor solid feeds like coal, and in the 1980s for petroleum coke.

Nearly from its inception, the process has been an attractive means for hydrogen production.The technology for this production has become the Texaco Hydrogen Generation Process(THGP). In the late 1970s, the process was modified to incorporate a combined cycle powerplant. This technology became specialized to the degree that it has become its own technology,now named Texaco Gasification Power Systems (TGPS).

Texaco gasifiers will soon produce 4.6 billion standard cubic feet of syngas per day. There arecurrently forty-eight operating installations around the world, and eighteen more in engineeringand construction phases. The majority of this capacity is still used for chemical production, butthe percentage used for power production has been rising the fastest. Soon at least 45% of thesyngas generated by Texaco gasifiers will be used for power production.

Among commercially proven technologies, Texaco Gasification Process based plants remain themost environmentally benign means of generating valuable products from sulfur-containingfeedstocks. Power plants with TGPS technology emit a fraction of the NOx and SOx pollutantsthat are produced from conventional or fluidized bed boiler installations. Even advanced boilersystems produce solid wastes in quantities far in excess of those produced in TGPS plants.

Texaco gasification converts coal, petroleum coke, and heavy oils such as vacuum residue andasphaltenes into synthesis gas (syngas) which is primarily hydrogen and carbon monoxide.Syngas has a variety of uses. Power, steam, hydrogen, and other products can be produced inany combination. To obtain maximum economic benefit from the unit, a low value feedstock isdesirable.

The heat generated by the gasification reaction is recovered as the product gas is cooled. Whenthe quench version of Texaco Gasification Process is employed, the steam generated is ofmedium and low pressure. A quench gasification flow scheme as would be applied to theintegration with deasphalting is shown in Figure 5. Note that the low-level heat used fordeasphalting integration is the last stage of syngas cooling. In non-integrated cases, much of thisheat is uneconomical to recover and is lost to air fans and to cooling water exchangers.

11

The deregulation of various power markets has made it more attractive for refineries to becomeself-generators of power and steam. The configuration for cogeneration is usually determined byseveral variables including the power and steam demand, desired reliability, and theopportunities for merchant sales. Given the opportunity for merchant power sales, aconfiguration of multiple trains of combustion turbines, heat recovery steam generators (HRSG)and a condensing steam turbine offers the most flexibility and high reliability to most refineries.

This configuration insures that there will always be at least one source of steam and power underthe typical scenarios of planned and unplanned outages. The actual size of the turbine will bedetermined by the power and steam demand of the refinery. In addition, it may be necessary tosupplemental fire the HRSG under various outage scenarios to maintain the minimal power orsteam requirements.

Many refiners and heavy oil producers currently generate some of their required power.However, self-generators are in the minority, and the majority of the required power is suppliedby outside electric utilities. Furthermore, refiners usually depend on lower efficiency equipmentsuch as small combustion/steam turbines and boilers for most of their self-generated power andsteam.

Figure 5

Ashpalt From Stripper

O2

Byproduct

Coke Solids

Shift

(Optional)

Sulfur

Purification

Separation

Hydrogen To

HTU

Crude

H2

Fuel

Gas

DiluentCO2

HP

Steam

Export

LPSTM

HPSTM

Heat ToDeasphalter

Texaco Gasification Unit

Filtration

AGR

SulfurProcessing

DeasphalterSolvent

BLR

HRSG

12

IV. INTEGRATED REFINERY SYSTEM

A refinery’s profitability can be greatly enhanced by integrating the traditional refinery unitswith gasification and power generation. The addition of a gasification unit and a power block tointegrate a refinery presents several synergies including:

− Integration for all process units− Heat integration and efficient use of low level heat− Common sulfur removal and acid gas removal units− Minimize required compression costs for hydrogen

Figure 6 shows some of the possible integration steps between the refinery unit, gasification, andpower generation:

Refinery Bottoms Integration (Liquids)

Figure 6

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CogenerationPlant

Sulfur

60,000 bbl/d

100,000 bbl/d

20,000 bbl/d

40,000 bbl/d

Bottoms20,000 bbl/d

Raw Syngas

Deasphalted Oil

Gas Oil/Distillates

Hydrocracker/ Hydrotreater Low SulfurProducts

90,000 bbl/d$23/ bblGasoline, diesel, other distillates

HP Hydrogen

Gasification

Solvent Separation

VacResid

Crude Unit

Ultra-Heavy Crude

M ayanVenezuelanKern RiverM ariner

$14/bbl

Solvent

5,000 bbl/d equiv(1,000,000 lb/h)$15/bbl equiv.Steam/Heat Export

Clean Syngas

Gas Cleanupand SulfurRecovery

5,000 bbl/d equiv(400 MW )$44/bbl equiv.( $25/MW -h)

Power Export

5,000 bbl/d equiv$15/bbl equiv

Refinery Gas/Natural Gas

Sour Gas

13

Crude Unit Integration

Viewing the refinery as one integrated system instead of several individual units has dramaticallychanged the design criteria for these units. A traditional crude distillation unit is usuallydesigned to maximize the number and amount of finished products that can be processed in thatunit. More stringent regulations for fuel specifications have made it necessary to hydroprocessthe products from the distillation units. To accommodate these regulations, new, integratedcrude distillation units will be designed to only produce intermediate products as feeds to thehydroprocessing units. This new design will simplify the crude unit by simplifying thefractionation and product finishing stripping steps.

The use of improved metallurgy in an integrated crude distillation unit allows the new crude unitto operate without an upstream desalting step. The majority of the chlorides that are present inthe crude stay in the distillation bottoms or heavy residue material and are later processed in thegasification section. Any chlorides that are present in the distillation products are separated andconverted to ammonium chloride, which is also treated in the gasification section.

By eliminating the desalting process it is possible to process heavier crudes without the additionof a cutter stock. In addition, the integrated configuration makes it possible to eliminate the firedheater. High-pressure steam from the HRSG is used to meet most of the heating requirements ofthe crude distillation unit. Supplemental heating to reach the highest temperatures can beachieved by using a heat transfer fluid that is heated by the HRSG.

Hydroprocessing Integration

The integration of the hydroprocessing unit provides various synergies with hydrogengeneration, acid gas cleanup, and heat integration.

Hydrogen: The low value feed stock to the gasification unit makes it economical to produce lowcost hydrogen for the hydroprocessing units. The high pressure of the hydrogen produced in atypical integrated gasification system minimizes the amount of compression required to meet thepressure requirements of a typical hydroprocessing unit. Additional energy from the high-pressure syngas feeding to the power block can be recovered in an expander to provide theenergy to compress the makeup hydrogen, recycle hydrogen, and purge hydrogen streams fromthe hydroprocessing units.

Acid Gas Removal: Given that an acid gas removal system is required for the gasification unit,an integrated refinery can use common acid gas removal and sulfur removal systems for thepurification of hydrogen and hydrogen-rich purge gas from the hydroprocessing units. The sourwater from the hydroprocessing units can be treated in the gasification unit or used as a source ofprocess water. The hydrotreater purge gases (required to reduce the buildup of light hydrocarbongases) are nitrogen stripped from the oil at pressure, scrubbed in the gasification unit, and fed tothe combustion turbines without compression.

Heat Integration: The use of steam and heat transfer fluid integration with the power block, andmakeup and recycle hydrogen heating within gasification, removes the need for fired heaters inthe hydroprocessing. As a result, the capital cost and emissions of the hydroprocessing units are

14

reduced. Eliminating the fired heaters will also lead to a reduction in NOx and SOx emission.The removal of the butane recovery section of the hydroprocessing units is another way forfurther reducing the capital cost of the hydroprocessing units.

Gasification and Deasphalting Integration

For maximum synergies, an integrated refinery system can close couple the deasphalter or otherliquid bottom processing units with the gasification unit. Gasification of the bottoms from thedeasphalter (i.e. asphaltenes) eliminates the need to use expensive distillate blending streams tomake the residue marketable. The asphaltenes are a low value feedstock for gasification, whichenhances the profitability of the integrated system.

Because of its high viscosity, the asphaltenes may require heating to improve the pumpingcharacteristics. Unfortunately, this material has poor heat transfer characteristics, and heating itwithout coking is difficult and expensive. Cutting the material with light oil to make thempumpable is too expensive. These characteristics also make it difficult to store the asphaltenes.

With the integrated deasphalter-gasification unit, the gasifier feed is taken directly from theasphalt stripper. The asphaltenes are heated to the temperature required for optimal pumping tothe gasifier prior to solvent removal, when its heat transfer characteristics are more favorable.The result is that viscosity limits on the asphaltenes are eliminated.

The gasifier charge pump draws from the bottom of the stripper and routes the material directlyto the gasifier. The working volume in the bottom of the stripper acts as a charge drum for thegasifier and minimizes the storage time for the asphaltenes. This short storage time eliminatesthe potential of the hot asphaltenes to polymerize.

If the deasphalter shuts down, the gasifier continues to operate using the heavy oil feed to thedeasphalter. The deasphalter feed can be gasified with only minor adjustments to the operatingparameters. The deasphalter feed is not as economically advantageous a feed as the deasphalterbottoms for an extended option. However, it will allow the gasifier to remain operating duringdeasphalter outages.

A key synergy of integrated solvent deasphalting and gasification is the sharing of each process’heat. The solvent deasphalting process requires a significant amount of heating to separate andrecycle the solvent used in the asphaltene extraction. The heat is used to vaporize the solventfrom the oil and the asphaltene streams so that it can be recovered and returned to the process.The gasification process produces heat that can be used for this solvent recovery in thedeasphalting unit.

The integration of the solvent deasphalter with the gasification unit enhances the overall energybalance. The low-level heat from quench gasification is used directly in a multi-stage sub-critical vaporization. Steam heat and a heat transfer fluid (both supplied from the HRSG)supplies the required heat to separate the solvent from the asphalt in the asphalt recovery section.

The products of deasphalting and gasification can also be beneficially integrated. Since thedeasphalted oil (DAO) requires hydrotreating and cat cracking to become diesel, the required

15

hydrogen can be produced by gasifying the asphaltene. This eliminates the need for externallysupplied hydrogen. The gasification unit can be further integrated with the hydrotreating unitand other hydroprocessing units as described above.

Power Block Integration

A diagram of the integrated power block is shown in figure 7.

Heat integrating provides various opportunities for coupling the refinery units with thegasification units and power generation. Two of the major integration points involve the use ofsteam and heat transfer fluid loops for process heating and steam drives for large compressionunits. As mentioned above, steam and heat transfer fluid heating can be used to replace firedheaters and other traditional sources of heat. When integrating gasification and power generationwith existing refinery units, the existing fired heater can serve as a backup during combustionturbine outages or used for trim heating.

Another point of integration with the power block is the use of steam driven compressors in theair separation unit (ASU). Using condensing steam turbines to power the air compressors in theASU reduces the condensing steam load of the power block. The amount of available steam willdepend on the refinery steam demand and power block configuration. In choosing the optional

Syngas/Refinery Gas/NG

GasificationHeating

Process

Heat Transfer

Fluid

RefineryProcessHeating

Condensate

ASU CompressionTurbine Drives

ST

Steam

DiluentN2/CO2

Air

CT

Note: Only one combustion turbine and HRSG is shown. A configuration of three combustion turbines and HRSGs would be used in an integrated facility for 100% reliability.

Figure 7

Integrated Power Block

steam balance, however, it should be noted that the ASU integration would reduce or possiblyeliminate the amount of steam available for a steam turbine in the power block. A portion of thecompressed air required for the ASU can also be extracted from the combustion turbinecompressors. Utilization of these integration steps will ultimately depend on the plantconfiguration and the power demand of the project.

Integration also provides a variety of fuel sources for the combustion turbines. This fuelmanagement option is a key feature of the integration configuration. Accordingly, syngas fuel,with diluent nitrogen and carbon dioxide from the gasification facility, is the primary fuel sourcefor the combustion turbines. In addition, the integrated facility provides other hydrocarbon fuelsfrom the refining unit’s purge and off-gas streams.

The fuel management concept is particularly of interest where the amount of syngas produced isnot enough to fully load the combustion turbines. In this case, natural gas is used as a makeupfuel. In addition, the design of the syngas combustion nozzles allows for the direct injection ofrefinery fuel gas into the combustion turbines. In traditional power plants, refinery off-gas canonly be used as boiler fuel or for supplemental firing in the HRSG’s. The proposed integrateddesign makes it possible to use syngas, natural gas, and refinery gas directly in the turbine.

Petroleum Coke Integration

Refinery Bottoms Integration (Solids)

Petroleum Co25,000 bbl/d eq

5,000 STPD$0/bbl

Sour Gas80,000 b$18/bbl

16

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G as Cleanupand Sulfur

Recovery

keuiv

Oilbl/d/d

Low Sulfur Products

90,000 bbl/d$23 / bblGasoline, diesel,other distillates

HP Hydrogen

Raw Syngas

Clean Syngas

CogenerationPlant

5,000 bbl/d1,000,000 lb/h

$15/bblSteam /Heat Export

5,000 bbl/d equiv

Refinery Gas/Natural Gas

5,000 bbl/d equiv(400 M W )$44/bbl equiv.( $25/M W -h)

Power Export

Sulfur

Sour Gas

Hydrocracker/Hydrotreater

Figure 8

17

Refineries that utilize a coker can incorporate similar integration steps as described for adeasphalter unit. The major synergies with a coker involve heat integration and the use of cokeroff-gas for power generation. The Texaco gasification technologies have demonstrated years ofcommercial experience in gasifying petroleum coke. The syngas produced from petroleum cokegasification can be used to generate power, steam, and hydrogen. A typical configuration forintegrating a coker unit with gasification, hydroprocessing and power generation is shown inFigure 8.

Integrating the coker with the power block will eliminate the need for a fired heater on the cokerunit. The use of high-pressure steam and heat transfer fluid loops from the HRSG can replace theheat needed by the coker. Using these alternate heat sources increases the run length betweendecoking and lead to higher yields of the products. In addition to the heat integration betweenthe coker and power block, the coker off-gases can also be integrated into the power block usingthe fuel management concept described above. The off-gases produced in the coker can bescrubbed, compressed, and used as fuel to power the combustion turbines. This would eliminatethe need for compression, cooling equipment, and utility costs.

The gasification of coke generates a significant amount of heat that can be recovered as low tomedium pressure steam. The low-pressure steam is used internally in the acid gas removal unit.The medium-pressure steam can be integrated with the power block to generate power or used inthe refinery if there is a need for low-medium pressure steam. The gasification unit can also beintegrated with hydroprocessing for the various synergies such as hydrogen use and sour gasprocessing. These synergies and integration points were previously described in thehydroprocessing integration section.

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V. INTEGRATION ADVANTAGES

The integration of new or existing refinery units with gasification, hydroprocessing and powergeneration presents significant advantages to each unit and the entire refinery or upgradingcomplex. The following advantages are described in detail in this section:

− Increased crude and fuel flexibility− Enhanced profitability through reduced capital and operating cost− Overall reduction in air emissions− Increased reliability and efficiency of utility supply

Increased Crude & Fuel Flexibility

Integrating a gasification unit into a refinery facility makes it possible to convert all lower valuebottoms material into higher value product and increases the refinery’s ability to process heaviercrude. Lower value bottom materials such as asphaltenes and petroleum coke can be gasifiedand converted to syngas. The syngas can be used as a source of hydrogen or as fuel incombustion turbines.

This improvement in heavy bottoms handling increases the refinery’s flexibility with crudepurchase and operations. The integrated refineries would have the capability to process heaviersour crudes such as Mayan, Venezuelan, Kern River, and Mariner.

With regards to fuel flexibility the presence of a gasification unit expands the fuel managementpossibilities to the use of syngas, natural gas, and refinery purge and off-gas hydrocarbon fuels,etc., for the generation of power and steam. The ability to use multiple fuels increases theoperating flexibility of the refinery and decreases the refinery’s dependence on external fuelssuch natural gas. In addition, syngas and its diluents such as nitrogen and carbon dioxide have agreater mass flow per unit BTU than natural gas. This result in the ability to generate 10 to 20%more power when compared to natural gas fired cogeneration units.

Enhanced Profitability Through Reduced Capital & Operating Cost

Integration gives the advantage of reducing the total capital and operating without reducing theefficiency of the overall facility. For example, simplifying the crude unit design to yield onlyintermediate products can dramatically reduce the cost of that unit. Another example is theelimination of supercritical solvent extraction steps from a conventional deasphalter.

Conventional fired heater or the use of high-pressure steam from a boiler for preheating thecrude distillation feed represents a significant use of fuel. These heat sources are also usedwidely in the hydroprocessing units such as hydrotreaters and hydrocrackers, and bottomsprocessing units such as deasphalters and cokers. Using the process heat from gasification andcombustion turbines as an alternative heat source greatly reduces the capital and operating costs.

The capital cost of the integrated refinery is lower due to shared equipment and common units.In conventional refineries, heat exchangers or fired heaters are required to provide energy forfeed heating, crude distillation, solvent separation, stripping, etc. The gasification unit and

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power block require heat exchangers, airfan coolers, and condensing turbines to streams. Bycombining these services the total number of exchangers is reduced, with capital cost savings.

Other services can be combined by integration: Hydrogen compression can be combined with thesyngas pressure letdown; the hydroprocessing sour gas treating can be combined with syngasacid gas removal and sulfur removal. Integrating these units and services reduces the capital andoperating cost of the facility. Table 1 illustrates typical capital cost saving.

Estimated Capital Costs Saving Vs. Non-Integrated Case

Refinery Units Non-Integrated Case Integrated Case

Crude Unit $ 600 /bbl $ 350 /bblSolvent Deasphalter $ 1,250 /bbl $ 550 /bblHydrotreater $ 1,500 /bbl $ 1,000 /bblHydrocracker $ 3,000 /bbl $ 1,800 /bblCoker $ 4,000 /bbl $ 3,000 /bbl

Overall Reduction in Air Emission

The asphaltene and petroleum coke material produced in traditional bottoms processing units(deasphalters, cokers, etc.) typically have high sulfur contents. The sulfur components in theasphaltenes become part of residual fuel oil when the asphaltenes are blended with distillates.These sulfur components are also present in petroleum cokes that are sold on the open market.The sulfur is then emitted when the residual fuel oil or petroleum coke is combusted.

Since the integration of the refinery, gasification, and power generation units minimizes theamount of fuel consumed to generate the heat required for the process units, less NOx, SOx andcarbon dioxide are emitted to the atmosphere. Also, when the asphaltenes and coke are gasified,the sulfur is converted to hydrogen sulfide. This is removed from the syngas using conventionalacid gas absorption technology and converted to elemental sulfur. As a result, the ultimateemissions of sulfur oxides to the atmosphere are substantially reduced. An example of a typicalreduction in sulfur content leaving the refinery is shown in Figure 8.

Integrated RefineryEstimated Capital Cost Benefits

Table 1

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Increased Reliability & Efficiency of Utilities

The redundancies that are typically built into an integrated gasification and power unit ensures avirtual 100% reliability of refinery utilities such as hydrogen, power, and steam. The proposedintegration features a multiple train gasification unit with sufficient syngas throughput capacity,equivalent to at least twice the required hydrogen production capacity. If one of the gasifiersshuts down, syngas can be instantaneously diverted from the power block and purified to meetthe hydrogen requirements. This ensures the reliability of the hydrogen supply to thehydroprocessing units.

Similarly, virtually designing the power block with multiple trains attains 100% reliability in thesteam and power supply to the refinery. Typically, the desired configuration involves the use ofthree combustion turbines, to ensure that there is no single point of steam or power failure duringroutine maintenance. In many cases, two large combustion turbines can meet the power and/orsteam demand. However, the increased reliability of a three-turbine configuration usually

REFINERY FUEL-BASED SULFUR EMISSIONS

CO

NTA

INE

D S

ULF

UR

(LTP

D)

0

50

100

150

200

250

300

350

400

Coke/Resid Fuel Oil

Medium Crude (20 API) Heavy Crude (13 API)

Basis: 100,000 BBL/D crude with 2.5% sulfur

Crude Vac. Resid Syngas

Figure 8

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justifies any additional cost. The ability to use various combinations of syngas, natural gas andrefinery gas also increases the reliability of integrated power generation.

By replacing traditional heat sources such as fired heaters and boiler steam with the integrateduse of HRSG steam and heat transfer fluid loops dramatically increases energy efficiency of theutility system. Table 2 illustrates some typical efficiency improvements.

Refinery IntegrationEstimated Operating Cost Benefits

Estimated Energy Cost Savings vs. Non-Integrated CaseCrude Unit

Thermal Energy (Fuel Gas/Steam) 50% Power 10% Deasphalter

Thermal Energy 20% Power Not Significant

Hydrotreater/HydrocrackerThermal Energy 20%Power 80%

Coker (Coker Case Only)Thermal Energy 20%Power Not Significant

CogenerationThermal Energy 25%Power 20%

Table 2

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VI. SAMPLE ECONOMICS

Refining

Integrating a refinery or heavy oil upgrading with the gasification and power generationtechnologies is economically attractive. Profit margins can be enhanced because the integratingfacility:

• Has the ability to run heavier sour crude• Produces valuable intermediate products from vacuum residue• Eliminates the asphaltenes and/or petroleum coke by gasification• Increases the reliability and efficiency of utilities• Assures a reliable, value-added supply of hydrogen, power, steam, and other utilities• Reduces environmental emissions such as SOx and NOx

In a case study, a US Gulf Coast can significantly enhance their profitability by adding a nominal100,000 bbl/day crude distillation unit along with the appropriate gasification, hydroprocessing,and power generation units. The project can increase the refinery’s ability to process heavycrude, balance the requirements of existing process units by supplying more intermediateproducts, and add self-generation of hydrogen, power, and steam. Net income estimates for thiscase study are summarized in Table 3.

Feed/Product $/DayRevenues Unstabilized Naphtha (BPD) 13,000 300,000 Sweet FCCU Feed (BPD) 23,000 540,000 Naphtha/Kerosene/Diesel 52,000 1,360,000 Power Export (MW) 235 160,000Total Revenue 2,370,000

Expenses Saudi Heavy Crude (BPD) 70,000 1,110,000 Maya Crude (BPD) 30,000 430,000 Natural Gas (MMBTU/h) 700 40,000 Operation & Maintenance ($/Day) 80,000Total Expenses 1,660,000

Total Benefit ($/Day) 710,000

Integrated RefineryNet Income

Table 3

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The estimated capital cost requirements, including modifications to existing unit, areapproximately $650 million. This gives a simple payout of about 3 years for the project. Highlyleveraged project financing can significantly enhance the return due to the capital-intensivenature of the project. Securing such project financing should be relatively easy given the recentsuccessful project financing of Texaco Gasification based power generation projects.

Some of the advantages of a totally integrated refinery can be achieved by integrating the TexacoGasification Process (TGP) with existing bottoms processing and/or hydroprocessing facilities.The gasification of the bottoms eliminates the need to blend the bottom streams for sale. Thesyngas produced from gasification of heavy bottoms can be used to generate power or hydrogenfor the hydroprocessing needs of the refinery. These integrations will greatly improve theeconomics of any refinery. These benefits can be obtained without significantly retrofitting theexisting refinery units. Other benefits such as heat integration, sour gas processing, andminimized compression may be added if the facility is willing to complete more substantialretrofits to existing refinery units. These additional integrations will substantially benefit therefinery’s bottomline.

Oil Fields

The technology is also attractive to facilities producing heavy oil. Integrated solventdeasphalting (also possible to use cokers), gasification, and power generation, enhances theeconomics of heavy oil production by:

• Increasing the value of the crude• Eliminating the asphaltenes using gasification• Producing syngas for hydrogen, power, or steam

In some heavy oil fields, an uplift of $3-$7 per barrel may be realized for the upgrade of heavycrude to deasphalted oil, distilled kerosene, and diesel components. When about 100,000bbl/day of crude are treated, revenues in the field are enhanced by about $570,000 a day.Petroleum coke gasification requires more capital than the gasification of asphaltenes.Therefore, the cost benefit will be reduced if a coker unit is used to upgrade the heavy oil.

In the simplest case, syngas produced from the asphaltenes can be used in new power generationfacilities or as a replacement for natural gas in the steam flood field’s existing cogeneration unit.The syngas is valued at current avoided natural gas prices. However, the real cost of the syngascan be fixed. This eliminates the natural gas fuel price risk over the 20-year life of the field.Typical natural gas savings may amount to about $175,000 per day. Opportunities for powermarket will further enhance the economics of these projects. Simple payouts for this type ofproject are about two years.

Due to its higher volume per unit Btu as compared to natural gas, the syngas-fed cogenerationunit produces more power and steam than the natural gas fed unit. This additional powerproduction covers nearly all of the additional power requirements of the new process units in an

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integrated facility. The production facilities’ revenues are enhanced by the incremental increasein steam production since this increases oil production.

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VII. CONCLUSION

The upgrade of heavy oil by integrating gasification with hydroprocessing and power generationcan greatly enhance the profitability of existing refineries. Some of the integration benefits canalso enhance the economics of heavy oil production. Using the Texaco gasification technologiesto convert the undesirable asphaltenes and petroleum coke byproducts into clean syngas is thecornerstone to the integration of the processes. The hydroprocessing technologies serve toupgrade the intermediate product from bottoms processing or crude distillation into high valuetransportation fuels. The power block provides highly efficient and reliable utilities for the entireintegrated facility.

The unique means of integrating these processes discussed in this paper saves capital andoperating cost, improves the reliability and efficiency of the entire facility, lowers emissions, andmaximizes the advantages of each process. Use of this integrated process will increase theflexibility of refining and oil production facilities, making them more prepared to meet thechallenges of new product regulations and to capture the benefits of changes in powerderegulation.

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VIII. REFERENCES

Gary, James H., and Handwerk, Glenn E., “Petroleum Refining Technology and Economics,”Third Edition, Marcel Dekker, Inc., New York 1994.

Wallace, Paul S., Anderson, M. Kay, Rodarte, Alma I., and Preston, William E., “Heavy OilUpgrading by the Separation and Gasification of Asphaltenes,” Houston 1998.