COMPETITIVENESS OF GASIFICATION AT THE BULWER ISLAND, AUSTRALIA REFINERY

Transcription

1 COMPETITIVENESS OF GASIFICATION AT THE BULWER ISLAND, AUSTRALIA REFINERY 1999 Gasification Technologies Conference San Francisco, California October 17-20, 1999 Ram Ramprasad and Tarun Vakil, BOC Process Systems Jim Falsetti, Texaco Power and Gasification Mohammed Islam, Kvaerner Process 1

2 SUMMARY In keeping with the BOC Group s aim to explore opportunities beyond traditional industrial gas markets, BOC has recently been involved in the development of the Queensland Clean Fuels Project (QCFP) at BP Amoco s Bulwer Island Refinery in Australia. This project illustrates the competitiveness of gasification technology in refinery situations, particularly when advantage is taken of co-production of several products and integration with the refinery s processes. A unique aspect of this refinery project is the application of gasification technology not to heavy residues, as is common, but to refinery gases. The project aims to achieve BP Amoco s distillate and gasoline quality targets and to meet projected distillate market demands of Queensland and Australia's East Coast. The central element of QCFP is the installation of a 17,000 bbl/day hydrocracking unit at the refinery. The hydrocracker allows the refinery to produce increased yields of low sulfur diesel and gasoline. The hydrocracker consumes more hydrogen than current refinery production rates, necessitating the development of a hydrogen production scheme. Traditional solutions in this situation would likely have involved the production of hydrogen internally by BP Amoco using reformers or across-the-fence production of hydrogen by BOC using steam methane reformer technology. Instead, BOC Gases and the BP Amoco Refinery have jointly developed a novel hydrogen supply scheme for the proposed new hydrocracker. A scheme based on the partial oxidation of refinery gases using the Texaco Gasification Process (TGP) allowed both parties to maximize project returns through the synergies between the two operating companies. The partial oxidation unit requires oxygen that will be supplied from a new air separation unit (ASU) that BOC will build adjacent to the refinery. The ASU will spur BOC s future development of the Queensland s industrial gases market, and the partial oxidation plant becomes a ready source of carbon dioxide and hydrogen for BOC. In addition, the ASU allows the refinery to use oxygen enrichment on the Residue Cracker Unit (RCU), significantly improving the overall return of the project. The partial oxidation plant Front End Engineering Design (FEED) package was jointly developed by the project team, which incorporated engineering expertise and experience from BOC Gases, BP Amoco Oil, Kvaerner Process and Texaco Development Corporation. 2

3 BACKGROUND In keeping with The BOC Group s aim to explore opportunities beyond traditional industrial gas markets, BOC has been working with BP Amoco over the last few years to supply industrial gases for an expansion of BP Amoco s Bulwer Island refinery at Brisbane in Queensland, Australia. During the mid-1990 s, the BP Amoco Refinery identified the need for a mild hydrocracker unit (MHC) to meet the future local demand for diesel and jet fuel and for cleaner transportation fuels. The refinery hydrogen balance indicated that an additional hydrogen source would be required to satisfy the large additional demand of the hydrocracker. BOC and BP Amoco worked together to develop a scheme that best met the needs of both companies. By taking advantage of local circumstances, BOC was able to propose hydrogen production technology that offered BP Amoco a lower cost than traditional solutions. This project illustrates the competitiveness of gasification technology in refinery situations. NOVEL SOLUTION Traditional solutions in this situation would likely have involved the production of hydrogen internally by BP Amoco using reformers or across-the-fence production of hydrogen by BOC using steam methane reformer (SMR) technology. Instead, BOC Gases and the BP Amoco Refinery explored a novel hydrogen supply scheme for the proposed new hydrocracker based on the partial oxidation of refinery gases. A scheme involving Auto-Thermal Reforming (ATR) was also considered. SMR technology has the greatest number of industrial applications; however, SMRs have limited feed flexibility and, as they are catalyst-based, are prone to performance degradation over time and require extensive feed pre-treatment. Partial oxidation is a non-catalytic process that can use a diverse range of feed stocks (natural gas / refinery off-gases / butane / olefins / residues) and does not require feed treatment. The technology is widely utilized, and commercially proven. The technology does however require a source of pure oxygen, which adds complexity and operating expenditure. ATR technology is catalyst-based and does not have extensive operating references at the required H2 capacity. A quantitative analysis of these alternatives was carried out using a weighted rating of the key factors associated with the plant. These factors included cost, technical risk, feed stock flexibility, utilities consumption, operability, future expandability and convertibility to alternative feed stocks, maintainability, reliability and environmental impact. Based on the overall weighted ratings analysis, partial oxidation technology was chosen for this project. A detailed MHC hydrogen supply study confirmed that an over-the-fence, combined partial oxidation / air separation unit (ASU) supply scheme yielded the greatest Net Present Value of all the schemes considered. This approach allowed both parties to maximize project returns through the synergies between the two operating companies. The partial oxidation unit requires oxygen that will be supplied from a new ASU that BOC will build adjacent to the refinery. The ASU will spur BOC s future development of 3

4 the Queensland industrial gases market, and the partial oxidation unit becomes a ready source of carbon dioxide and hydrogen for BOC. In addition, the ASU allows the refinery to pursue oxygen enrichment on the Residue Cracker Unit (RCU), significantly improving the overall return of the project. Among partial oxidation technologies, the Texaco technology (TGP) was chosen as it has considerable experience in processing all types of feeds and can be readily tailored for processing light hydrocarbon streams and minimization of excess steam generation. The TGP unit can also be modified in the future to process residue feeds, thereby giving the refinery a long-term residue conversion route. Several other synergies between BOC s industrial gas complex and the refinery provided additional value to the project. The following key commercial and technical issues were considered in developing this project. For an overview of the process flows, please refer to Figure 1. (a) By addition of a solvent-based CO2 recovery process followed by a cryogenic CO2 purification unit, BOC will be able to recover pure CO2 from the TGP syngas stream for merchant sales into the food and beverage markets. (b) BOC will be able to extract a small stream of 99.5% pure H2 from the PSA product stream and further purify it for merchant sales. (c) Additional oxygen will be required for O2 enrichment of the furnaces of the existing and new refinery sulfur recovery units for increased capacity. (d) The refinery will have access to low and high pressure nitrogen from the ASU, the former for inerting and purging applications, the latter particularly for MHC and partial oxidation unit start-ups and shutdowns. Nitrogen and argon will also be available for BOC s merchant sales. (e) Overall process integration can be achieved by utilizing excess steam from the partial oxidation unit, with LP steam being used in the CO 2 recovery process and some LP and MP steam being supplied to the refinery. (f) Overall process integration with a separately installed cogen unit at the site allows heat integration of demineralised water (DMW) streams. (g) The new hydrogen plant will receive all utilities such as DMW, compressed air etc. from the refinery s existing and new joint-shared utility systems resulting in additional savings. (h) The PSA tailgas will be used as a fuel in the MHC fractionator furnace. PROJECT DEVELOPMENT A preliminary process scheme and a plant cost estimate, within 30% accuracy, were produced first. This preliminary scheme was taken as the starting point for the next step of value engineering and brainstorming to further optimize the process scheme. This study was initiated to generate the required improvements in capital expenses (capex) and 4

5 operating expenses (opex). The project team arrived at significant improvements, and conclusively proved that the partial oxidation option was the most cost-effective. The value engineering study team comprised experts from: BP Amoco Refinery, Bulwer Island, and BP Amoco Oil technical staff BOC Gases Australia and BOC Central Technical staff Kvaerner Process technical staff Texaco Development Corporation Technical staff A BP Amoco representative from the refinery facilitated the sessions during which about 300 value engineering ideas were generated by the team. A preliminary review and screening of these ideas led to about 120 ideas that were deemed worth pursuing. These ideas were further assessed on the basis of potential value and probability of success and packaged into about 50 individual value engineering studies for further analysis. The exercise led to improvements that generated savings of about $4.5 MM in capex and about $0.1 MM in opex. The NPV of total savings was calculated at $3.5 MM. One big source of savings was from the use of a multi-service compressor for feed and product H2 services, as compared to using two separate compressors. The Preliminary Design Package (PDP) development was carried out in 1997 followed by a Front-End Engineering Design (FEED) phase in Both these phases also involved staff from Kvaerner Process Houston. The FEED activity developed detailed cost estimates and product pricing, which was evaluated by BP Amoco s management for project approval. The project and funding approval was granted thereafter; which cleared the way for detailed engineering design phase. Currently, the detailed design is underway; following completion of plant construction, the start-up is anticipated in year An important aspect of the project is the decision to execute it under an alliance of the owners and Kvaerner Process along with Stork ICM and Fluor Daniel (who are partners in the execution phase of the project). The partners will work as a single team to share the project risk, providing a major incentive to drive down project costs with completion of the project on or before the scheduled date in a safe and environmentally responsible fashion. The alliance includes commercial incentives that encourage and reward improvement. The plant will be virtually a grass root facility constructed in parallel with the MHC unit, while sharing common utilities with the refinery and the MHC where possible. The partial oxidation and CO2 recovery units will be within the BP Amoco refinery plot area. These plants will be owned and managed by BOC and operated under contract by BP Amoco staff. The ASU will be owned and operated by BOC and located immediately outside the refinery fence. PROCESS DESCRIPTION The partial oxidation unit for hydrogen includes the following major process units (please refer to the process block diagram on Figure 2): 5

6 1. Feed gas compression 2. Oxygen supply system 3. Texaco gasifier with water quench and syngas scrubber 4. CO shift reactor 5. Process gas waste heat recovery 6. MDEA system for CO2 removal 7. PSA for hydrogen product recovery 8. Hydrogen product compression Other support units include the ASU for O2 and N2 products, and a CO2 purification unit for CO2 recovery. The plant design capacity is about 78,000 Kg/day (32 MMscfd) of contained H2 product, at a minimum 99.5% purity, with less than 10 ppm each of CO and CO2. The product H2 is compressed to about 2700 psig for delivery to the MHC. The CO2 purification unit will produce about 150 MTPD high purity CO2 for merchant sales. Gasifier Feed Collection and Compression The gasifier feed will consist of refinery off-gas streams, supplemented by natural gas, if necessary. Feed stream compositions and flow rates are dependent on refinery operating mode (i.e., crude type, operating rates, operating severity etc.) and will vary frequently. The gasifier and hydrogen units are designed to tolerate these changes with minimal disruption to hydrogen supply. Refinery streams that form the feed are: Reformer off-gas from NGRU: This gas contains high concentrations of hydrogen and is the major source of hydrogen currently produced in the refinery. The gas contains chlorides that must be removed, as the gasifier and other vessels are either made of stainless steel or have stainless steel cladding that may suffer corrosion cracking. The gas will be passed through a fixed bed of activated alumina that will absorb all chlorides. Naphtha Hydrotreater Off-gas / RCU Off-gas / DHT HP & LP Off-gases: These gases will be blended and scrubbed of H2S and chlorides by the refinery in an Amine Scrubber before being routed to the hydrogen plant. H2S removal is necessary to prevent contamination of the CO2 product. The blended gases are referred to as "RCU Off-gas". The feed streams are collected and mixed in the feed compressor suction drum and compressed to about 850 psig using two multi-service feed Compressors that also compress product H2. The compressed gas is preheated to around 600 F by exchange with the shift reactor effluent. Oxygen Supply The ASU utilises the latest technology in process design and hardware. The plant uses a packed water-wash tower to cool the air and a pre-purification unit that uses molecular sieve to remove water and CO 2 (along with hydrocarbons) that would otherwise freeze and block the cold equipment. This is followed by high efficiency heat exchange between the incoming air and the products, and a double column arrangement, thermally linked via a reboiler-condenser, to carry out the distillation of the air into oxygen, nitrogen and argon. 6

7 The main feature of the ASU is the simplicity of the arrangement of its rotating machinery, which leads to a very high level of plant reliability and flexibility. With the energy of just two air compressors, a main and a booster, the plant is able to deliver not only two gaseous O2 streams at elevated pressure, but also up to 250 TPD of liquid products. Other key features of the ASU include: (1) Sophisticated interlock functions to protect against failures or mal-operation and keep the plant in a safe condition in case of power failure. (2) Use of structured packing in the distillation process, which results in increased plant flexibility, better plant control and lower power consumption. (3) Liquid storage and vaporization facilities to seamlessly supply, in the event of an outage, up to 600 TPD of back-up O2 and up to 100 TPD of back-up N2. (4) Internal liquid pumping of the oxygen eliminates the need for a dedicated oxygen compressor. Gasification Preheated feed and oxygen are fed into a Texaco gasifier via a feed injector. The reaction zone operates at around F and psig. The reaction zone is lined with refractory and, as in many high pressure and temperature pressure vessel reactor designs, the pressure vessel shell includes continuous skin temperature monitoring. The reaction zone temperature is monitored by thermocouples supplied by Texaco specifically designed for high temperature duty. Both the feed and oxygen rates are continuously monitored to minimize temperature fluctuations and prevent excursions. The primary reaction in the gasifier reaction zone is partial oxidation, where hydrocarbons react with oxygen to give carbon monoxide and hydrogen as per the following reaction: C n H m + n/2 O 2 = nco + m/2 H 2 There is insufficient O2 in the reaction zone and the gasifier remains a reducing atmosphere - a small portion of the N2 in the feed may reduce to form ammonia. To protect the process feed injector from the high gasifier temperature and radiant heat from the refractory, the injector incorporates an independent cooling water circuit. Hot syngas leaving the reaction section passes through a water quench system and the syngas passes into the quench section (water bath) at the base of the gasifier. The saturated syngas exiting the quench section is cooled and saturated at the exit pressure. The quench section cools and saturates the syngas; removes the small amount of soot which forms during the gasification reaction; and absorbs water-soluble byproducts. Quenched syngas from the gasifier is further contacted with water in another water scrubbing system to ensure intimate mixing and saturation of the syngas. The resultant two-phase mixture out of the second water-scrubbing step enters the base of a syngas Carbon Scrubber column that ensures that no particulate matter passes downstream with the syngas stream. Counter-current contact between syngas and liquid water sprayed from the top occurs in the upper section of the scrubber. 7

8 Water from the base of the scrubber is pumped to the gasifier quench. As this is a closed boiling circuit, a blow-down is required to control the accumulation of soot and other contaminants. A slipstream of quench water from the base of the gasifier is also blown down. Shift Reaction Section Clean saturated syngas from the syngas scrubber is preheated to around 600 F in a stand-alone shift preheat furnace. The syngas then enters the shift reaction section comprised of two reactor beds in series. The preheated feed enters the first reactor where the bulk of the CO is converted to H2. The shift reaction converts carbon monoxide and water to form carbon dioxide and hydrogen through the following reaction: CO + H 2 O = CO 2 + H 2 The reaction is highly exothermic resulting in a large temperature rise across the reactor. The syngas leaves the first bed at around 800 F and is routed to the feed gas pre-heater. The syngas is then further cooled to 700 F by direct water injection before entering the Second Reactor. With little residual CO present in the feed to this reactor, the exotherm across it is less pronounced. Heat Recovery Section Several exchangers and Knock Out drums are utilized to optimize waste heat recovery from the syngas stream exiting the shift reaction section. The syngas exiting the second shift reactor is cooled to around 450 F in a process condensate heater. It is then cooled in two waste heat boilers where 165 psia and 65 psia saturated steam are generated. After the condensate is separated, the syngas is further cooled in a heat exchanger and, finally, in a water cooler, to 100 F before it is sent to another separator for condensate removal. Combined hot and cold separator condensate is pumped and returned to the syngas scrubber after being preheated in the condensate heater to about 475 F. To prevent accumulation of ammonia in the shift cooling train, a small slipstream of condensate is blown down directly to the refinery sour water stripper. CO2 Recovery Section The CO2 recovery unit is based on BASF's MDEA process. Syngas leaving the final separator is split, with part of the stream entering an absorber column, with the remaining syngas bypassing the CO2 recovery unit. In the absorber, the CO2 and H2S in the syngas are adsorbed by the amine flowing through two packed beds. Sweet syngas leaving the absorber is mixed with the bypassed syngas stream and routed to the PSA section for hydrogen recovery. The rich amine is heated in a lean / rich amine exchanger, and sent to the top of a stripper column. This column uses two packed beds where the rich MDEA is stripped of CO2 and H2S by steam flowing upwards. The lean MDEA from the bottom of the column is cooled in the exchanger and then in a water cooler before being pumped back to the top of the absorber. A slipstream of the lean MDEA is pumped through mechanical filters before being fed to the absorber. 8

9 The stripped CO2, H2S and water vapor are cooled in an overhead condenser. The condensate is separated and pumped back to the top of the stripper as reflux. The vapor stream is sent to the CO2 purification unit. Hydrogen Recovery and Purification The syngas stream flows to a suction KO drum to collect condensate from piping heat losses and minimize the amount of liquid water entrained into the PSA. The unit is made up of 9 beds, with a design H2 recovery of 90% and product purity of 99.5mol%. Each bed is filled with several layers of adsorbent, which specifically target contaminants present in the feed to the unit. H2 passes through the beds while contaminants are adsorbed on to the bed. After the bed is loaded with contaminants, the adsorbent is regenerated by reducing the pressure. The PSA beds continuously cycle through the adsorption, de-pressure, desorption, and pressure steps. Hydrogen product from the PSA unit is routed through filters and coalescers to remove and adsorbent dust and is then compressed for delivery to the refinery. Effluent Treatment The hydrogen plant effluent streams are steam condensate, waste water, excess steam (as by-product) and PSA off-gas. The steam condensate is flashed in a sour water stripper atmospheric flash drum and then pumped to the refinery de-aerator system. Gasifier blow down (wastewater) is routed to the sour water stripper for treatment to remove ammonia and HCN, and for ph adjustment. Clean runoff is segregated to minimize storm water load on the existing API oil/water separator. The PSA off-gas is routed to the refinery. CURRENT STATUS AND FUTURE ACTIVITIES BP Amoco and BOC have approved the project and funding. Detailed engineering design by Kvaerner Process Melbourne, to be finished by the end of 1999, is proceeding in parallel with construction activities, with mechanical completion expected by mid 2000 followed by startup in September

10 Figure 1: Refinery - Industrial Gas Complex: BPA, Bulwer Island BO GAN LOX, LIN, LAr GO to FCCU Liquid Gas Trailer Filling ASU & Liquefier Hydrogen Trailer Filling POX H 2 Plant Hydrogen Steam Refinery Feed Gas Oil Refinery Steam CO2 Cogen Plant CO 2 Liquefaction CO 2 Separation Natural Gas MW 10

11 NGRU OFF-GAS Figure 2: BULWER ISLAND, AUSTRALIA PARTIAL OXIDATION SCHEME Feed Gas Compress. BFW INJECTION O2 TO BP REFINERY N2 HP OXYGEN AIR BLENDED RCU OFF-GAS K.O. drum Feed prehtr FLUE ASU MAC gasifier proc. cond. scrubber shift reheat furnace TO S.G. SCRUBBER 150 psig steam first FUEL second shift shift reactor reactor 50 psig steam BLOWDOWN TO SWS Rec. to scrubber Rec. to POX & scrubber pump proc cond heater CONDENSATE from cold K.O. 150 psig steam gen BFW 50 psig steam gen BFW filter PSA H2 for BOC MERCHANT SALES H2 TO BP REFINERY hot K.O. DMW TO COGEN DMW heater DMW FROM COGEN shft trim cooler CWS cold K.O. CO2 absorber pump CWS to prod cond heater H2 PSA pump lean MDEA cooler lean / rich exchanger CO2 stripper ovhd cond E-1603 reboiler PURGE pump Purge gas as refinery fuel CO2 PURIFICATION reflux drum PURE CO2 blow down to SWS 11