Enhancing Refinery Profitability by Gasification, Hydroprocessing & Power Generation

Transcription

1 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 Gasification A Division of Texaco Inc Fournace Place Bellaire, Texas Presented at the Gasification Technologies Conference October, 1999 San Francisco, California

2 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

3 I. INTRODUCTION The ability to better handle heavy crudes or heavy bottom streams enhances the economic potential of most refineries and oil fields. Refineries with the flexibility to meet the increasing product specifications for refined fuels will continue to show positive profit margins. Upgrading heavy oil be it heavy crude oil in the oil field or heavy bottom streams in the refinery is an increasingly 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 convert heavy, sour refinery bottoms into valuable transportation fuels. On the downside, most upgrading techniques leave behind an even heavier residue whose disposition costs may approach the value of the upgrade itself. Solvent deasphalting and residue coking are used in heavy-crude-based refineries to upgrade heavy bottom streams to intermediate products that may be processed to produce transportation fuels. The technology may also be used in the oil field to enhance the value of heavy crude oil before it gets to the refinery. A beneficial use is often difficult to find for the byproducts from these processes, asphaltenes and petroleum coke. The Texaco Gasification Process is a market leader in the conversion of heavy oils, petroleum coke, and other heavy petroleum streams to valuable products (i.e. Hydrogen, Power, etc.). By integrating heavy oil processing with gasification, important synergies may be realized. These include: increased crude and fuel flexibility; enhanced profitability through reduced capital and operating cost; lower environmental emissions; and increase reliability and efficiency of utilities. In fact, integrating these technologies often provides economic benefits that justify the combined processes in instances where using either technology on its own may not be considered economically viable. The integration between bottoms processing units and gasification can serve as a springboard for other economically enhancing integration. The integration of gasification with existing or new hydroprocessing unit, and power generation unit, presents some unique synergies that will enhance the profitability of refiners and heavy oil producers. For example, it is sometimes possible to incorporate upstream units such as crude distillation, which will further enhance the economics and the flexibility of the facility. 1

4 II. TECHNOLOGY APPLICATIONS An integrated gasification, hydroprocessing, and power generation facility is ideal for uplifting the economics of an existing refinery. The technology integration can be utilized by refiners that already process heavy crude oils or by sweet crude refineries that are looking to increase margins by purchasing lower cost heavy crude. The integration also provides an economically alternative to heavy oil field processing. Refinery Applications An integrated gasification, hydroprocessing, and power generation facility can increase the crude and operating flexibility of the refinery. Flexibility is increased by allowing the refinery to process 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 the capabilities of the existing refinery unit. The economics of most refineries are handicapped by the relatively high cost of their heavy bottoms processing or lack thereof. Heavy bottoms often need to be blended with valuable product or sold at depressed value on the solid fuels market. In addition, most refineries are not able 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 hydrogen and carbon dioxide. Refiners may utilize syngas in a number of ways. The syngas can be converted to hydrogen by use of the Texaco Hydrogen Generation Process (THGP), which may be used in the refinery for hydroprocessing units such as hydrocracking or hydrotreating. The syngas may also be used by Texaco Gasification Power Systems (TGPS) cogeneration facilities to provide low cost power and steam to the refinery. If the refinery is part of a petrochemical complex, the syngas can be used as a chemical feed stock. The gasification of refinery bottoms allows the refinery to produce more intermediate products from the deasphalting or coking units. These intermediate products along with other intermediates from crude distillation can be hydroprocessed with low cost hydrogen that is produced using THGP. The many synergies of integrating gasification, hydroprocessing and power generation result in lowering the capital and operating costs. Oil Field Application For heavy crude oil producers, upgrading by integrating gasification with solvent deasphalting and power/steam cogeneration increases the value of their crude. Deasphalting removes the heavy components, reduces the metal content, reduces the Conradson carbon, and increases the API gravity of the crude. The lighter crude is more easily transported and has properties much closer to the design crude oils of most refineries. This allows the upgrader to maximize refined products 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 TGPS cogeneration unit to produce power and steam. The steam generated would then be used for well 2

5 injection to enhance oil production in the field, and the power would be sold. The syngas also may be sold to third parties for its chemical value. 3

6 III. PROCESS DESCRIPTIONS Crude Distillation A diagram of a crude unit is shown in Figure 1. Crude Atmospheric & Vacuum Distillation Crude Crude Charge CW Gas to LPG Gas to LPGRecovery Refinery Stm Steam Ejectors Ejectors CW CW Noncondensible NonCondensible Gas Gas CW 3 to 10 PSIG F Reflux Reflux Drum Drum EXG A Water r LSR Gasoline LSR Gasoline To to Treating CW Sump Sump STM Stm Naphtha Naphtha EXG A EXG B Oily Oily Water Water Desalter F EXG B Salt Water Salt Water Heater Heater F Stm STM Atm. ATM Tower Stm STM Side Cut Strippers Strippers Gas Oil Gas Oil Topped Topped Crude Crude To Vacuum Tower Steam Stm F F to to F 0 F Light Light Vac Vac Gas Gas Oil Oil 7 to 10 MM SteamStm Heavy Vac Gas Gas Oil Oil Vacuum Resid Vacuum Residual Heater Vacuum Tower Figure 1 Figure Crude distillation units are usually the first major process units in a refinery. These units employ a distillation process to separate crude oil into various fractions according to boiling points of the various materials in the crude. The fractions are then distributed to a variety of downstream processing units for further separation and polishing. Higher efficiencies and lower costs are achieved 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 a high vacuum. A vacuum distillation unit is used to separate the heavier portion of crude because the high temperatures that are needed to process all the crude at atmospheric pressure would cause thermal cracking of some of the crude materials. This thermal cracking would result in loss of dry gas, discoloration of some products, and equipment fouling. 4

7 It is usually necessary to desalt the crude feed prior to the distillation process. Desalting minimizes the fouling and corrosion that can occur when salt deposits accumulate on heat transfer surfaces, and minimizes acids form by breakdown of chloride salts. The desalter process also removes the suspended solids and dewaters the crude oil. These suspended solids usually include sand, clay, soil, iron compounds, and other particles picked up during the production or transit of the crude oil. The salt in the crude is in the form of dissolved or suspended salt crystals in the water emulsified with the crude oil. Desalting is carried out by mixing the crude oil with water at elevated temperatures. The temperature of the water and crude oil is determined by the density of the crude oil. The salt dissolves in the water, and the water is separated from the crude in a settling tank. The separation of the crude oil and water is assisted by adding various chemicals, or by using 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 crude before desalting. After desalting, the crude oil is heated via a series of heat exchangers and fired heaters before being charged to the atmospheric distillation unit. These units are usually operated between 650 and 750 ºF (343 TO 399 ºC). Initial flashing of the crude charge results in lighter ends being processed in the atmospheric unit and the heavier bottoms being sent to the vacuum distillation unit. 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 the use of side steam strippers to further separate the crude materials that are fractionated in the main distillation unit. The atmospheric bottoms are distilled under vacuum to lower the boiling temperatures of the materials, preventing thermal cracking and the resultant loss of products. The atmospheric bottoms require additional heating via a fired heater before entering the vacuum distillation column. Furthermore, the desired operating pressure of the vacuum distillation unit is maintained by the use of steam ejectors, barometric condensers or vacuum pumps, and surface condensers. The vacuum distillation units are usually operated with absolute pressure ranging from 25 to 40 mmhg, and temperature ranging from 730 to 850 ºF (388 to 454 ºC). The vacuum distillation unit further fractionates the crude oil into heavy gas oil, vacuum gas oil, and vacuum residue. The gas oils are then hydroprocessed or cracked to produce gasoline, jet fuel and diesel fuels. Heavier gas oils are used to produce lubricating oils. The vacuum residue is usually processed in a visbreaker, coker, or deasphalter to produce heavy fuel oil (requires hydroprocessing) and asphalts or petroleum coke. Hydrocracker A diagram of a hydrocracker unit is shown in Figure 2. 5

8 Hydrocracker Unit H 2 Makeup Gas C 1 C 4 LSR H 2 Recycle Naphtha Diesel Feed Option For Feed To Second Stage Figure 2 The aromatic cycle oils that are present in vacuum gas oils and coker distillates are best processed in a hydrocracker unit. These materials usually resist catalytic cracking, but the high pressures and hydrogen atmosphere make them relatively easy to hydrocrack. Hydrocracking units typically operate with conditions ranging from 500 to 800 ºF and from 1,000 to 2,000 psig ( ºC and 6,900-13,800 kpa.), and may involve one or two reaction stages. These variables will change with the age of the catalyst, the product desired, and the properties of the feedstock. A hydrotreater is sometimes used to pretreat the feed to a hydrocracker unit, or to process the naphtha and middles distillate stream from the atmospheric distillation unit. Pretreating of the hydrocracker feed is needed to protect the hydrocracker catalyst from various poisonous components. The hydrotreater completes a variety of hydrogen and catalytic reactions, which effectively saturate the olefins, and remove sulfur, nitrogen, and oxygen compounds from the feed. Metal is also removed via cracking of the material that contains metals. The nitrogen and sulfur compounds are removed by conversion to ammonia and hydrogen sulfide. 6

9 The hydrocracker feed is mixed with make-up hydrogen and recycled gas (high in hydrogen content and passed through a heater to the hydrocracker reactor. The hydrogen rich gas is separated from the reactor effluent, scrubbed to remove H 2 S, and recycled back to the reactor. The liquid products are fractionated in a distillation column where products such as light and heavy naphtha, jet fuel, and diesels are recovered. The fractionated bottoms are used as feed to the 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 gas process to treat hydrogen sulfide and acids, various stages of compression, and a source of heat to 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 a dedicated sour process facility. Depending on the source of hydrogen and the hydrogen purification facility used to treat the recycled high hydrogen gas, several stages of compression are usually required to keep these hydrogen streams at the operating pressure of the hydroprocessing units. Deasphalting A diagram of a deasphalting unit is shown as Figure 3. Deasphalter Unit SOLVENT RECOVERY Heat From Gasification Heavy Oil Feed Extractor Fired Heater Steam Gasifier Feed Pump Solvent Recycle Pump Deasphalter Oil To Hydrotreater Asphalt Feed To Gasifier Figure 3 7

10 The bottom product from the vacuum unit is called vacuum residue, which consist of long chain paraffinic material and asphaltenes. As much as 80% of the residue from vacuum crude oil towers 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 in conventional cracking units. This separation may be accomplished using solvent extraction. The extractor uses a hydrocarbon such as propane, butane or pentane to extract the paraffinic components from the feed stream. The heavy oil feed is mixed with the solvent. The asphaltenes are insoluble in the solvent, and are separated from the paraffinic components by settling. The extractor produces solvent-rich deasphalted oil (DAO) and an asphaltene stream that contains some residual solvent. The solvent-rich DAO is heated and flashed to recover the solvent. Some processes employ super critical conditions to recover the solvent from the DAO. In either case, heat must be supplied to the process to achieve separation of the solvent from the DAO. Fired heaters and high-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 then hydro-treated to remove sulfur, acids and metals, and to maximize yield in the downstream cracking units. The solvent that is entrained in the asphaltenes must also be recovered. The solvent- containing asphaltenes are heated above the minimum asphalt pumping temperature. This ensures that the asphalt will be pumpable after the solvent is removed. The heat source is typically a fired heater or high-pressure steam. The solvent is steam stripped from the asphaltenes in a trayed tower, and is recycled to the extractor. The asphaltenes leave the stripper hot and must be cooled prior to blending for sales. Solvent deasphalting can be a cost-effective way to produce oil that can be converted to more valuable streams such as diesel from residual distillation products. The asphalt product from the process 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 often detrimental to the unit s overall economics. The deasphalting unit requires significant amounts of heat to recover the solvent used in the extraction. Whether a fired heater generates this heat or it is obtained by the use of high-pressure steam, 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. 8

11 Delayed Coker Unit F PSIG CW Gas F 5-10 PSIG Reflux Drum Coke Drums 7 Unstabilized Naphtha STM F Heater 1 Fractionator 1 Gas Oil Stripper STM Gas Oil Coke Fresh Feed Figure 4 One example of refinery bottoms processing is a petroleum coker unit, which produces a solid byproduct. 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 the throughput of catalytic cracker, reduces the metal content of the catalytic cracker feedstock, and reduces the net refinery yield of low-priced residual fuels. Delayed, Fluid, and Flexicoker are various types of coking processes that produce a variety of coke products. These coking products display a variety of shapes (circle to needle), sizes, and ranges in sulfur content from 0.3 to 8%. Delayed cokers are usually 15-20% more efficient than fluid cokers, and 2-40% more efficient 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 of the coker unit. The bottoms from the fraction column is heated to approximately 900 o F and charged to the bottom of the coke drum. The thermal cracking reaction that occurs in the coke drum produces gas, naphtha, and gas oil. These products are transferred to the bottom of the fractionation column for distillation. The naphtha and gas oils are further processed in side strippers to the fractionation column. 9

12 Coker liquids typically require hydrotreating to remove sulfur and nitrogen before they can be processed into finished products. In addition, the heavier fractions require cracking to produce finished products. The coker light ends are primarily recovered through compression, multistage cooling, and separation. Texaco Gasification Process The Texaco Gasification Process was developed in the late 1940s. It was intended to produce hydrogen and carbon monoxide - syngas - for chemical plant and refinery applications. It was designed to process natural gas. In the 1950s, it was modified for heavy oil feeds, in the 1970s for 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 power plant. 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 are currently forty-eight operating installations around the world, and eighteen more in engineering and construction phases. The majority of this capacity is still used for chemical production, but the percentage used for power production has been rising the fastest. Soon at least 45% of the syngas generated by Texaco gasifiers will be used for power production. Among commercially proven technologies, Texaco Gasification Process based plants remain the most environmentally benign means of generating valuable products from sulfur-containing feedstocks. Power plants with TGPS technology emit a fraction of the NOx and SOx pollutants that are produced from conventional or fluidized bed boiler installations. Even advanced boiler systems 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 and asphaltenes 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 in any combination. To obtain maximum economic benefit from the unit, a low value feedstock is desirable. The heat generated by the gasification reaction is recovered as the product gas is cooled. When the quench version of Texaco Gasification Process is employed, the steam generated is of medium and low pressure. A quench gasification flow scheme as would be applied to the integration with deasphalting is shown in Figure 5. Note that the low-level heat used for deasphalting integration is the last stage of syngas cooling. In non-integrated cases, much of this heat is uneconomical to recover and is lost to air fans and to cooling water exchangers. 10

13 Texaco Gasification Unit Ashpalt From Stripper O2 HP STM LP STM Heat To Deasphalter Deasphalter Solvent BLR Shift (Optional) AGR Sulfur Processing Crude H2 Fuel Gas Diluent CO2 Purification Separation Hydrogen To HTU HRSG Sulfur HP Steam Export Filtration Byproduct Coke Solids Figure 5 The deregulation of various power markets has made it more attractive for refineries to become self-generators of power and steam. The configuration for cogeneration is usually determined by several variables including the power and steam demand, desired reliability, and the opportunities for merchant sales. Given the opportunity for merchant power sales, a configuration 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 under the typical scenarios of planned and unplanned outages. The actual size of the turbine will be determined by the power and steam demand of the refinery. In addition, it may be necessary to supplemental fire the HRSG under various outage scenarios to maintain the minimal power or steam 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 supplied by outside electric utilities. Furthermore, refiners usually depend on lower efficiency equipment such as small combustion/steam turbines and boilers for most of their self-generated power and steam. 11

14 IV. INTEGRATED REFINERY SYSTEM A refinery s profitability can be greatly enhanced by integrating the traditional refinery units with gasification and power generation. The addition of a gasification unit and a power block to integrate 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, and power generation: Refinery Bottoms Integration (Liquids) Hydrocracker/Hydrotreater Low SulfurProducts 100,000 bbl/d Ultra-H eavy Crude Mayan Venezuelan Kern River Mariner $14/bbl Vac Resid 60,000 bbl/d Gas Oil/Distillates 20,000 bbl/d 40,000 bbl/d Solvent Crude Unit Deasphalted Oil Solvent Separation Bottom s 20,000 bbl/d HP Hydrogen Gasification SourGas Raw Syngas Gas Cleanup and Sulfur R ecovery 90,000 bbl/d $23/bbl Gasoline,diesel, otherdistillates Refinery Gas/ NaturalGas 5,000 bbl/d equiv $15/bblequiv Clean Syngas 5,000 bbl/d equiv (1,000,000 lb/h) $15/bblequiv. Steam /HeatExport Cogeneration Plant PowerExport Figure 6 Sulfur 5,000 bbl/d equiv (400 MW) $44/bblequiv. ($25/MW-h) 12

15 Crude Unit Integration Viewing the refinery as one integrated system instead of several individual units has dramatically changed the design criteria for these units. A traditional crude distillation unit is usually designed to maximize the number and amount of finished products that can be processed in that unit. More stringent regulations for fuel specifications have made it necessary to hydroprocess the products from the distillation units. To accommodate these regulations, new, integrated crude distillation units will be designed to only produce intermediate products as feeds to the hydroprocessing units. This new design will simplify the crude unit by simplifying the fractionation and product finishing stripping steps. The use of improved metallurgy in an integrated crude distillation unit allows the new crude unit to operate without an upstream desalting step. The majority of the chlorides that are present in the crude stay in the distillation bottoms or heavy residue material and are later processed in the gasification section. Any chlorides that are present in the distillation products are separated and converted 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 addition of a cutter stock. In addition, the integrated configuration makes it possible to eliminate the fired heater. High-pressure steam from the HRSG is used to meet most of the heating requirements of the crude distillation unit. Supplemental heating to reach the highest temperatures can be achieved by using a heat transfer fluid that is heated by the HRSG. Hydroprocessing Integration The integration of the hydroprocessing unit provides various synergies with hydrogen generation, acid gas cleanup, and heat integration. Hydrogen: The low value feed stock to the gasification unit makes it economical to produce low cost hydrogen for the hydroprocessing units. The high pressure of the hydrogen produced in a typical integrated gasification system minimizes the amount of compression required to meet the pressure requirements of a typical hydroprocessing unit. Additional energy from the highpressure syngas feeding to the power block can be recovered in an expander to provide the energy to compress the makeup hydrogen, recycle hydrogen, and purge hydrogen streams from the 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 the purification of hydrogen and hydrogen-rich purge gas from the hydroprocessing units. The sour water from the hydroprocessing units can be treated in the gasification unit or used as a source of process water. The hydrotreater purge gases (required to reduce the buildup of light hydrocarbon gases) are nitrogen stripped from the oil at pressure, scrubbed in the gasification unit, and fed to the combustion turbines without compression. Heat Integration: The use of steam and heat transfer fluid integration with the power block, and makeup and recycle hydrogen heating within gasification, removes the need for fired heaters in the hydroprocessing. As a result, the capital cost and emissions of the hydroprocessing units are 13

16 reduced. Eliminating the fired heaters will also lead to a reduction in NO x and SO x emission. The removal of the butane recovery section of the hydroprocessing units is another way for further 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 other liquid bottom processing units with the gasification unit. Gasification of the bottoms from the deasphalter (i.e. asphaltenes) eliminates the need to use expensive distillate blending streams to make the residue marketable. The asphaltenes are a low value feedstock for gasification, which enhances the profitability of the integrated system. Because of its high viscosity, the asphaltenes may require heating to improve the pumping characteristics. Unfortunately, this material has poor heat transfer characteristics, and heating it without coking is difficult and expensive. Cutting the material with light oil to make them pumpable 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 the asphalt stripper. The asphaltenes are heated to the temperature required for optimal pumping to the 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 directly to the gasifier. The working volume in the bottom of the stripper acts as a charge drum for the gasifier and minimizes the storage time for the asphaltenes. This short storage time eliminates the potential of the hot asphaltenes to polymerize. If the deasphalter shuts down, the gasifier continues to operate using the heavy oil feed to the deasphalter. The deasphalter feed can be gasified with only minor adjustments to the operating parameters. The deasphalter feed is not as economically advantageous a feed as the deasphalter bottoms for an extended option. However, it will allow the gasifier to remain operating during deasphalter 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 and recycle the solvent used in the asphaltene extraction. The heat is used to vaporize the solvent from 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 the deasphalting unit. The integration of the solvent deasphalter with the gasification unit enhances the overall energy balance. The low-level heat from quench gasification is used directly in a multi-stage subcritical 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 the deasphalted oil (DAO) requires hydrotreating and cat cracking to become diesel, the required 14

17 hydrogen can be produced by gasifying the asphaltene. This eliminates the need for externally supplied hydrogen. The gasification unit can be further integrated with the hydrotreating unit and other hydroprocessing units as described above. Power Block Integration Integrated Power Block Syngas/Refinery Gas/NG Air Steam ASU Compression Turbine Drives Gasification Heating ST Diluent N 2 /CO 2 CT Refinery Process Heating Condensate Heat Transfer Fluid Process 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 A diagram of the integrated power block is shown in figure 7. Heat integrating provides various opportunities for coupling the refinery units with the gasification units and power generation. Two of the major integration points involve the use of steam and heat transfer fluid loops for process heating and steam drives for large compression units. As mentioned above, steam and heat transfer fluid heating can be used to replace fired heaters and other traditional sources of heat. When integrating gasification and power generation with existing refinery units, the existing fired heater can serve as a backup during combustion turbine outages or used for trim heating. Another point of integration with the power block is the use of steam driven compressors in the air separation unit (ASU). Using condensing steam turbines to power the air compressors in the ASU reduces the condensing steam load of the power block. The amount of available steam will depend on the refinery steam demand and power block configuration. In choosing the optional 15

18 steam balance, however, it should be noted that the ASU integration would reduce or possibly eliminate the amount of steam available for a steam turbine in the power block. A portion of the compressed air required for the ASU can also be extracted from the combustion turbine compressors. Utilization of these integration steps will ultimately depend on the plant configuration and the power demand of the project. Integration also provides a variety of fuel sources for the combustion turbines. This fuel management 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 source for the combustion turbines. In addition, the integrated facility provides other hydrocarbon fuels from the refining unit s purge and off-gas streams. The fuel management concept is particularly of interest where the amount of syngas produced is not enough to fully load the combustion turbines. In this case, natural gas is used as a makeup fuel. In addition, the design of the syngas combustion nozzles allows for the direct injection of refinery fuel gas into the combustion turbines. In traditional power plants, refinery off-gas can only be used as boiler fuel or for supplemental firing in the HRSG s. The proposed integrated design makes it possible to use syngas, natural gas, and refinery gas directly in the turbine. Petroleum Coke Integration Refinery Bottoms Integration (Solids) SourGas Oil 80,000 bbl/d $18/bbl/d Hydrocracker/Hydrotreater SourGas Low SulfurProducts 90,000 bbl/d $23 /bbl Gasoline,diesel, otherdistillates Petroleum Coke 25,000 bbl/d equiv 5,000 STPD $0/bbl HP Hydrogen Refinery Gas/ NaturalGas 5,000 bbl/d equiv 5,000 bbl/d 1,000,000 lb/h $15/bbl Steam /H eatexport Raw Syngas Gas Cleanup and Sulfur R ecovery Clean Syngas C ogeneration Plant Pow erexport Sulfur Figure 8 5,000 bbl/d equiv (400 MW) $44/bblequiv. ($25/MW-h) 16

19 Refineries that utilize a coker can incorporate similar integration steps as described for a deasphalter unit. The major synergies with a coker involve heat integration and the use of coker off-gas for power generation. The Texaco gasification technologies have demonstrated years of commercial experience in gasifying petroleum coke. The syngas produced from petroleum coke gasification can be used to generate power, steam, and hydrogen. A typical configuration for integrating a coker unit with gasification, hydroprocessing and power generation is shown in Figure 8. Integrating the coker with the power block will eliminate the need for a fired heater on the coker unit. The use of high-pressure steam and heat transfer fluid loops from the HRSG can replace the heat needed by the coker. Using these alternate heat sources increases the run length between decoking and lead to higher yields of the products. In addition to the heat integration between the coker and power block, the coker off-gases can also be integrated into the power block using the fuel management concept described above. The off-gases produced in the coker can be scrubbed, compressed, and used as fuel to power the combustion turbines. This would eliminate the need for compression, cooling equipment, and utility costs. The gasification of coke generates a significant amount of heat that can be recovered as low to medium 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 in the refinery if there is a need for low-medium pressure steam. The gasification unit can also be integrated with hydroprocessing for the various synergies such as hydrogen use and sour gas processing. These synergies and integration points were previously described in the hydroprocessing integration section. 17

20 V. INTEGRATION ADVANTAGES The integration of new or existing refinery units with gasification, hydroprocessing and power generation presents significant advantages to each unit and the entire refinery or upgrading complex. 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 value bottoms material into higher value product and increases the refinery s ability to process heavier crude. Lower value bottom materials such as asphaltenes and petroleum coke can be gasified and converted to syngas. The syngas can be used as a source of hydrogen or as fuel in combustion turbines. This improvement in heavy bottoms handling increases the refinery s flexibility with crude purchase and operations. The integrated refineries would have the capability to process heavier sour crudes such as Mayan, Venezuelan, Kern River, and Mariner. With regards to fuel flexibility the presence of a gasification unit expands the fuel management possibilities 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 the operating flexibility of the refinery and decreases the refinery s dependence on external fuels such natural gas. In addition, syngas and its diluents such as nitrogen and carbon dioxide have a greater 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 the efficiency of the overall facility. For example, simplifying the crude unit design to yield only intermediate products can dramatically reduce the cost of that unit. Another example is the elimination of supercritical solvent extraction steps from a conventional deasphalter. Conventional fired heater or the use of high-pressure steam from a boiler for preheating the crude distillation feed represents a significant use of fuel. These heat sources are also used widely in the hydroprocessing units such as hydrotreaters and hydrocrackers, and bottoms processing units such as deasphalters and cokers. Using the process heat from gasification and combustion 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 for feed heating, crude distillation, solvent separation, stripping, etc. The gasification unit and 18

21 power block require heat exchangers, airfan coolers, and condensing turbines to streams. By combining 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 the syngas pressure letdown; the hydroprocessing sour gas treating can be combined with syngas acid gas removal and sulfur removal. Integrating these units and services reduces the capital and operating cost of the facility. Table 1 illustrates typical capital cost saving. Integrated Refinery Estimated Capital Cost Benefits Estimated Capital Costs Saving Vs. Non-Integrated Case Refinery Units Non-Integrated Case Integrated Case Crude Unit $ 600 /bbl $ 350 /bbl Solvent Deasphalter $ 1,250 /bbl $ 550 /bbl Hydrotreater $ 1,500 /bbl $ 1,000 /bbl Hydrocracker $ 3,000 /bbl $ 1,800 /bbl Coker $ 4,000 /bbl $ 3,000 /bbl Table 1 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 the asphaltenes 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 the amount of fuel consumed to generate the heat required for the process units, less NO x, SO x and carbon 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 conventional acid gas absorption technology and converted to elemental sulfur. As a result, the ultimate emissions of sulfur oxides to the atmosphere are substantially reduced. An example of a typical reduction in sulfur content leaving the refinery is shown in Figure 8. 19

22 REFINERY FUEL-BASED SULFUR EMISSIONS CONTAINED SULFUR (LTPD) Crude Vac. Resid Coke/Resid Fuel Oil Syngas Medium Crude (20 API) Heavy Crude (13 API) Basis: 100,000 BBL/D crude with 2.5% sulfur Figure 8 Increased Reliability & Efficiency of Utilities The redundancies that are typically built into an integrated gasification and power unit ensures a virtual 100% reliability of refinery utilities such as hydrogen, power, and steam. The proposed integration 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 gasifiers shuts down, syngas can be instantaneously diverted from the power block and purified to meet the hydrogen requirements. This ensures the reliability of the hydrogen supply to the hydroprocessing units. Similarly, virtually designing the power block with multiple trains attains 100% reliability in the steam and power supply to the refinery. Typically, the desired configuration involves the use of three combustion turbines, to ensure that there is no single point of steam or power failure during routine maintenance. In many cases, two large combustion turbines can meet the power and/or steam demand. However, the increased reliability of a three-turbine configuration usually 20

23 justifies any additional cost. The ability to use various combinations of syngas, natural gas and refinery gas also increases the reliability of integrated power generation. By replacing traditional heat sources such as fired heaters and boiler steam with the integrated use of HRSG steam and heat transfer fluid loops dramatically increases energy efficiency of the utility system. Table 2 illustrates some typical efficiency improvements. Refinery Integration Estimated Operating Cost Benefits Estimated Energy Cost Savings vs. Non-Integrated Case Crude Unit Thermal Energy (Fuel Gas/Steam) 50% Power 10% Deasphalter Thermal Energy 20% Power Not Significant Hydrotreater/Hydrocracker Thermal Energy 20% Power 80% Coker (Coker Case Only) Thermal Energy 20% Power Not Significant Cogeneration Thermal Energy 25% Power 20% Table 2 21

24 VI. SAMPLE ECONOMICS Refining Integrating a refinery or heavy oil upgrading with the gasification and power generation technologies is economically attractive. Profit margins can be enhanced because the integrating facility: 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 SO x and NO x In a case study, a US Gulf Coast can significantly enhance their profitability by adding a nominal 100,000 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 heavy crude, balance the requirements of existing process units by supplying more intermediate products, and add self-generation of hydrogen, power, and steam. Net income estimates for this case study are summarized in Table 3. Integrated Refinery Net Income Feed/Product $/Day Revenues Unstabilized Naphtha (BPD) 13, ,000 Sweet FCCU Feed (BPD) 23, ,000 Naphtha/Kerosene/Diesel 52,000 1,360,000 Power Export (MW) ,000 Total Revenue 2,370,000 Expenses Saudi Heavy Crude (BPD) 70,000 1,110,000 Maya Crude (BPD) 30, ,000 Natural Gas (MMBTU/h) ,000 Operation & Maintenance ($/Day) 80,000 Total Expenses 1,660,000 Total Benefit ($/Day) 710,000 Table 3 22

25 The estimated capital cost requirements, including modifications to existing unit, are approximately $650 million. This gives a simple payout of about 3 years for the project. Highly leveraged project financing can significantly enhance the return due to the capital-intensive nature of the project. Securing such project financing should be relatively easy given the recent successful project financing of Texaco Gasification based power generation projects. Some of the advantages of a totally integrated refinery can be achieved by integrating the Texaco Gasification 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. The syngas produced from gasification of heavy bottoms can be used to generate power or hydrogen for the hydroprocessing needs of the refinery. These integrations will greatly improve the economics of any refinery. These benefits can be obtained without significantly retrofitting the existing refinery units. Other benefits such as heat integration, sour gas processing, and minimized compression may be added if the facility is willing to complete more substantial retrofits to existing refinery units. These additional integrations will substantially benefit the refinery s bottomline. Oil Fields The technology is also attractive to facilities producing heavy oil. Integrated solvent deasphalting (also possible to use cokers), gasification, and power generation, enhances the economics 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 heavy crude to deasphalted oil, distilled kerosene, and diesel components. When about 100,000 bbl/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 generation facilities 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 syngas can 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 power market will further enhance the economics of these projects. Simple payouts for this type of project are about two years. Due to its higher volume per unit Btu as compared to natural gas, the syngas-fed cogeneration unit produces more power and steam than the natural gas fed unit. This additional power production covers nearly all of the additional power requirements of the new process units in an 23

26 integrated facility. The production facilities revenues are enhanced by the incremental increase in steam production since this increases oil production. 24

27 VII. CONCLUSION The upgrade of heavy oil by integrating gasification with hydroprocessing and power generation can greatly enhance the profitability of existing refineries. Some of the integration benefits can also enhance the economics of heavy oil production. Using the Texaco gasification technologies to convert the undesirable asphaltenes and petroleum coke byproducts into clean syngas is the cornerstone to the integration of the processes. The hydroprocessing technologies serve to upgrade the intermediate product from bottoms processing or crude distillation into high value transportation fuels. The power block provides highly efficient and reliable utilities for the entire integrated facility. The unique means of integrating these processes discussed in this paper saves capital and operating cost, improves the reliability and efficiency of the entire facility, lowers emissions, and maximizes the advantages of each process. Use of this integrated process will increase the flexibility of refining and oil production facilities, making them more prepared to meet the challenges of new product regulations and to capture the benefits of changes in power deregulation. 25

28 VIII. REFERENCES Gary, James H., and Handwerk, Glenn E., Petroleum Refining Technology and Economics, Third Edition, Marcel Dekker, Inc., New York Wallace, Paul S., Anderson, M. Kay, Rodarte, Alma I., and Preston, William E., Heavy Oil Upgrading by the Separation and Gasification of Asphaltenes, Houston