A Novel Pairing of Technologies to Achieve Todays Sulphur

A Novel Pairing of Technologies to Achieve Today’s Sulphur Emission Stringency With Minimum Facility Investment By Angela F. Slavens and Keith R. Didriksen Black & Veatch INTRODUCTION Throughout the history of oil and gas production, a host of drivers have obliged the industry to employ increasingly stringent restrictions on allowable emissions from processing facilities. More specifically, over the past 30 years, sulphur dioxide emissions have received considerable scrutiny due to acid rain awareness and concern. As a result, the global oil and gas industry has seen sulphur plant sulphur recovery efficiency (SRE) requirements increase from levels that can be achieved by merely employing conventional modified-Claus technology, to values reaching 99.9% and above, on a continuous basis - the standard for most new large-scale facilities built today. This paper explores a unique concept of combining two well-proven sulphur recovery technologies to achieve today's SRE requirements with minimum life-cycle cost. The coupling of an amine-based tail gas treating unit (TGTU) with a highly-efficient Claus sub-dewpoint sulphur recovery unit (SRU) was the unanticipated outcome of a recent project executed by Black & Veatch (B&V). Pairing these two technologies was not the obvious approach from the start, but after a comparison of the new configuration to a more conventional design, the choice was obvious for the particular project at hand. Admittedly, many of the key drivers for the technology selection were unique to the requirements for this specific project; however, the analysis concluded that there is also much evidence to suggest that pairing sub-dewpoint technology and amine-based tail gas treating may be an attractive arrangement for other existing and greenfield developments, when recovery efficiency in excess of 99.5% is required. This paper discusses general evidence supporting that claim and provides an in-depth account of the key factors which led to the ultimate technology selection for the sulphur complex associated with the Reliance Petroleum Jamnagar Expansion Refinery Project (JERP). RECENT TECHNOLOGY DEVELOPMENTS TO MEET RISING SRE REQUIREMENTS Throughout recent history, conventional modified-Claus sulphur recovery technology has been employed in oil and gas processing facilities for conversion of H2S to elemental sulphur, with demonstrated recovery efficiencies ranging from 92% to 98%, and recoveries in this range were often sufficient to meet environmental emissions standards. However, with increasing global concern over sulphur emitted to the atmosphere, both from the processing facility as well as end products, progressively stricter restrictions have been imposed on processing facilities, resulting in the need for increased sulphur plant recovery efficiencies. And so arose the emergence of the tail gas treatment unit, designed to be installed at the back end of the SRU, and capable of achieving overall SRU / TGTU recovery efficiency in excess of 99.9%. In addition to the application of technologies designed to treat the SRU tail gas for incremental recovery efficiency gains, the industry has also seen the emergence of various technology developments aimed at achieving higher SRE within the SRU itself. Among these technologies is the sub-dewpoint sulphur recovery process, intended to achieve 99.0 to 99.5% SRE in the SRU alone. This type of process is founded on the principle of operation at the lower temperatures favored by the Claus reaction equilibrium, while also overcoming the inherent problem of catalyst deactivation due to liquid sulphur formation in the catalyst bed. One of the most commonly employed sub-dewpoint technologies is the Amoco Cold Bed Adsorption (CBA) process. The CBA process was originally designed to achieve the required SRU recovery efficiency without the need to install a separate TGTU downstream; however, today’s 99.9+% requirement is not achievable with the use of CBA technology alone. Therefore, many existing CBA facilities that do not have the possibility to be “grandfathered” with respect to emissions are left with the question of how to achieve incremental SRE gains in the range of 0.5% to 1.5%. RELIANCE JAMNAGAR REFINERY PROJECT The dilemma described above is precisely what B&V were faced with when commissioned to engineer the new sulphur recovery facility for the Reliance JERP complex, and is what eventually led to the development of the innovative concept to combine amine-based H2S TGTU technology with sub-dewpoint Claus SRU technology. A brief background discussion about the refinery’s historical development is included below, followed by an account of the key factors which led to the realization of this unique technology pairing as the preferred option for implementation for the new sulphur recovery complex that will begin operation in 2008. Jamnagar Refinery Background Reliance Petroleum Ltd. built the world’s largest grassroots refinery in 1999, and are currently in the process of expanding to double the capacity, making the Jamnagar Refinery Complex the largest in the world. In addition to its impressive size, Reliance’s Jamnagar Refinery can process a wide variety of crude oils ranging from sweet to heavy, with sulphur content up to 4.5 wt%. Reliance's existing refinery and petrochemical complex (referred to as DTA – Domestic Tariff Area) processes 660,000 BPD of heavy, sour crude and is currently exporting a large proportion of its products. The high sour crude processing capability is centered on the 3 x 675 MTPD Cold Bed Adsorption (CBA) sub-dewpoint sulphur trains, which B&V licensed, engineered and procured for the grassroots refinery development from 1996 to 1999. At present, B&V are carrying out EPCm scope of work for the sulphur processing facilities associated with the new Jamnagar Expansion Refinery Project, which is planned for mechanical completion in 2008. When completed, the expanded Jamnagar Refining Complex will have a total sulphur processing capacity of nominal 4,050 MTPD (6 x 675 MTPD). The Reliance Refinery expansion provides a clear example of the increasing restrictions being imposed on refiners with respect to emissions. Just 10 years ago, when the original refinery was built, an SRE of 98.7% was sufficient to meet environmental requirements, and this was accomplished with the application of CBA technology. However, as India and the rest of the world prove to be increasing concern about environmental emissions, the recovery efficiency requirement for the new JERP units has been increased to 99.9%. JERP Sulphur Complex Project Objectives In late 2005, Reliance approached B&V with a request to deliver a sulphur processing facility for the new refinery expansion that would match the capacity of the existing facility, while also achieving the increased recovery efficiency specification. There are many well-known tail gas treating technologies designed to achieve 99.9% sulphur recovery; therefore, the increased SRE specification alone was not a concern for B&V. However, as Reliance have a reputation for successfully pioneering new ground while maximizing value creation, the more stringent recovery efficiency specification was not the only challenge associated with this endeavor. The following mandatory project objectives were also communicated by Reliance at the outset of project development: 1. Record-time schedule – In order to achieve start-up of the new facilities as early as possible, Reliance conveyed a desire to meet a 26 month project schedule, reducing the original grassroots refinery project schedule by approximately 10 months. 2. Repeat concept – In support of minimizing schedule, Reliance requested maximum duplication of the existing facility design. In addition to reduced schedule, the repeat concept would also provide the advantage of operational consistency between the existing DTA and new JERP facilities, allowing for a reduced learning curve in commissioning, startup and operation of the new facilities. 3. Lowest cost – It came as no surprise that the investment cost for the new sulphur facilities would exceed that of the original plant due to labor and material cost escalations over the past 10 years, as well as the addition of new tail gas treating facilities to achieve the more stringent recovery efficiency. However, it also came as no surprise that Reliance were intent on minimizing JERP capital investment and life-cycle costs. DEVELOPING THE OPTIONS Taking into account the increased recovery efficiency specification in conjunction with the additional key project objectives described above, B&V and Reliance began to consider process configuration alternatives for further evaluation and comparison. Technology Considerations The first thought was to install conventional tail gas treating units downstream of the SRUs to achieve 99.9% overall SRE for each SRU / TGTU train. However, given the fact that aminebased tail gas treating technology is readily capable of achieving 99.9% recovery with upstream SRU recovery efficiencies as low as 92%, it was not instinctive to consider incurring the high cost of CBA technology to achieve excessive recovery efficiency in the SRU, when a TGTU was to be installed downstream. Thus, B&V first examined conventional Claus technology for the JERP SRU design. After discussing the various execution, schedule and cost aspects associated with the Claus SRU option, it became apparent that Reliance had a strong desire to limit changes from the existing DTA SRU design, providing as true of a clone as possible and allowing for full realization of objectives 1 and 2. Accordingly, development of a cost-effective TGTU technology option to achieve 99.9% overall recovery, while maintaining CBA technology for the SRU, was attractive. Train Configuration Considerations The number of SRU trains in a sulphur plant is most often determined based on acid gas processing capacity redundancy requirements for the oil / gas processing facility as a whole. To the contrary, because it is possible to maintain SRU operation even when the TGTU is out of service, the number of TGTU trains is often determined based on redundancy requirements for recovery efficiency, rather than processing capacity. Thus, it is not uncommon to equip multiple SRU trains with a common TGTU. The number of SRU trains for the JERP facility was determined by Reliance from the outset of project development and was repeated from the DTA design, but the number of TGTU trains was a design aspect still up for discussion. An analysis was carried out to determine the redundancy requirement for TGTUs processing CBA tail gas versus TGTUs processing conventional Claus SRU tail gas. Table 1 gives the results of such an analysis for several different Claus and CBA configurations, assuming a three train SRU design (similar to the design of the Reliance DTA facility). The recovery efficiencies stated in the table assume rich acid gas feed (> 90 vol% H2S) at End of Run (EOR) catalyst conditions. Table 1 – Sulphur Recovery Efficiency for Conventional Claus vs. CBA SRU Technology and Associated TGTU Requirements Three Train Operation Recovery Efficiency (per Train) 2-Bed Claus SRU + TGTU Claus SRU Claus TGTU TOTAL 3-Bed Claus SRU + TGTU Claus SRU Claus TGTU TOTAL CBA SRU CBA TGTU TOTAL 96.0% 3.9% 99.9% 99.0% 0.9% 99.9% 96.0% x 3 3.9% x 2 98.6% 99.0% x 3 0.9% x 2 99.6% 96.0% x 3 3.9% x 1 97.3% 99.0% x 3 0.9% x 1 99.3% 96.0% x 3 3.9% x 0 96.0% 99.0% x 3 0.9% x 0 99.0% 94.0% 5.9% 99.9% One TGTU Out of Service 94.0% x 3 5.9% x 2 97.9% Two TGTUs Out of Service 94.0% x 3 5.9% x 1 96.0% Three TGTUs Out of Service 94.0% x 3 5.9% x 0 94.0% 3-Bed (Rotate R2, R3) CBA SRU + TGTU Table 1 documents the recovery efficiency achieved in each individual SRU / TGTU train and illustrates that the required recovery efficiency for the TGTU processing CBA SRU tail gas is much lower than for the TGTU processing conventional Claus SRU tail gas – 0.9% vs. 3.95.9%, respectively. Table 1 also illustrates that for the case of CBA SRU technology, the overall SRE will be 99.0% when all three TGTUs are out of service vs. 97.9% to 98.6% when only one out of three TGTUs is out of service for the Claus SRU options. Thus, it was concluded that if CBA technology is employed for the SRU, a single TGTU would be acceptable to meet overall SRE redundancy and reliability requirements for the sulphur processing facility. Options 1 and 2 Defined As a result of the technology and redundancy analyses performed, two clear process configuration options emerged, which are illustrated in Figures 1 and 2. Option 1 (Figure 1), depicts a conventional configuration for multiple Claus SRU trains, each paired with its own dedicated TGTU. This arrangement offers parallel redundancy in both acid gas processing capacity and SRE. Option 2 (Figure 2), illustrates the unique technology combination which is the subject of this paper. The same number of SRU trains have been employed in order to maintain parallel acid gas processing redundancy, yet because the SRU trains are CBA units, in this case one common TGTU can be employed. As indicated in Table 1, the option 2 configuration, despite being equipped with only a single TGTU, actually provides for greater SRE redundancy than the option 1 configuration. It is important to note that even though a common TGTU is considered for option 2, each SRU must be equipped with its own dedicated incinerator, to maintain acid gas processing redundancy by allowing the SRUs to remain in service in the event that the common TGTU is shutdown. Figure 1 – Option 1 Process Configuration – 3 x Claus SRU + 3 x Claus TGTU Figure 2 – Option 2 Process Configuration – 3 x CBA SRU + 1 x CBA TGTU COMPARING THE OPTIONS Options 1 and 2 were compared on the basis of economics, project execution schedule and operability, in an attempt to identify the more attractive of the two. Economic Comparison In order to identify the lowest life-cycle cost alternative, the economic comparison considered capital investment cost, operating and maintenance cost, and risk of environmental excursion, which could potentially result in financial penalty. Each of these financial criteria is explored in detail in the discussion that follows. Capital Cost Table 2 indicates the relative capital investment requirement for an individual SRU / TGTU, depending on the SRU technology employed, and gives a tabulation of the relative capital cost of the entire sulphur processing facility for each option. The expected trends are clear: • • • A Claus SRU (option 1) is less costly than a CBA SRU (option 2) A common 100% TGTU (option 2) is less costly than three 33.3% TGTU trains (option 1) TGTU cost is a lower percentage of overall facility cost when it is installed downstream of a CBA SRU (option 2) than when it is installed downstream of a Claus SRU (option 1) Table 2 – Relative Investment Cost Comparison of Options 1 and 2 Number of TIC per Train Trains (Units of Cost)* Option 1 – 3 x Claus SRU (2-Bed) + 3 x Claus TGTU Claus SRU 3 x 33.3% 100 Claus TGTU 3 x 33.3% 87 Claus SRU + TGTU Option 2 – 3 x CBA SRU (3-Bed) + 1 x CBA TGTU 3 x 33.3% CBA SRU 125 1 x 100% CBA TGTU 159 CBA SRU + TGTU Total Facility TIC (Units of Cost)* 300 261 561 375 159 534 % of Total Facility TIC 55% 45% 100% 70% 30% 100% * The values in the table are given in generic “units of cost,” which do not correspond to actual monetary figures, and are used for the purpose of relative comparison only. Given the observed trends, it is not particularly surprising that the net result is only a minor capital investment cost differential between the two options. For option 1, the 94% recovery Claus SRU cost advantage is consumed by the high cost of three 5.9% recovery efficiency TGTUs. Similarly, the higher 99% recovery CBA SRU cost for option 2 is balanced by a lower cost for a common TGTU with only 0.9% recovery efficiency. As an aside, it can be observed that despite a significant reduction in SRE, TGTU investment cost is not proportionally reduced. This is because even though substantially reducing amine circulation rate proportionally reduces the size of the equipment in the amine circulation loop and regeneration system, most equipment in a TGTU is actually sized based on process gas volumetric flow rate. Consequently, since the tail gas rates for options 1 and 2 are essentially the same, the capital cost differential is limited to the savings gained by the reduction in amine circulation rate achieved with option 2, which amounts to approximately 5% of TIC. Operating Cost Although a rigorous operating cost analysis was not carried out, there exist conclusive data to support the general claim that a CBA / TGTU train (option 2) combination is significantly more energy efficient, and therefore less costly to operate, than a Claus / TGTU (option 1). The following evidence supports this conclusion. 1. Claus SRU vs. CBA SRU Steam Balance The difference in steam balance for CBA vs. Claus SRUs can be approximated by ratioing LP and LLP steam production rates based on the approximate difference in SRE - 99% vs. 94-96%, respectively. Additionally, due to the fact that process gas reheat is not required upstream of the “lag” CBA reactor bed(s), the HP steam that is normally utilized for accomplishing this in a Claus unit is not required for a CBA facility. A simplified comparison of CBA SRU vs. Claus SRU steam balance is approximated in Table 3. As in Tables 1 and 2 above, the figures included in Table 3 assume rich acid gas feed processing. Table 3 – Approximate Steam Balance for CBA vs. Claus SRU (Nominal 2 x 675 MTPD) Option 2 3-Bed CBA HP Steam Export (kg/hr) LP Steam Export (kg/hr) LLP Steam* Export (kg/hr) TOTAL (kg/hr) 136,000 Option 1 3-Bed Claus 128,000 2-Bed Claus 130,600 CBA Improvement Over Claus 4-6% Comments Claus SRU utilizes HP steam for reheat upstream of 2nd and 3rd reactors Claus LP steam production is reduced in proportion to SRE Claus LLP steam production is reduced in proportion to SRE 37,000 35,900 35,200 3-5% 6,000 5,820 5,700 3-5% 179,000 169,720 171,500 4-5% * If BFW pre-heat is considered in lieu of LLP steam production, a nominal capital investment increase will be incurred, yet steam export can be maximized. Table 3 illustrates that an overall steam balance improvement of 4-5% can be expected in a CBA SRU vs. a Claus SRU. Depending on the economics of steam in the context of the plant-wide steam balance, this level of improvement could result in a significant annual operating cost savings for the facility. 2. Claus TGTU vs. CBA TGTU Amine Circulation Rate As mentioned in the capex discussion above, most of the equipment in a TGTU is sized based on tail gas volumetric flow rate rather than quantity of H2S in the tail gas. Therefore, despite a large reduction in recovery efficiency requirement, substantial capital investment savings cannot be realized for the CBA TGTU option, due to insignificant variance in tail gas volumetric flow rate. On the other hand, TGTU amine circulation rate is primarily a function of total quantity of H2S to be absorbed by the amine solvent; thus, significant reductions in amine circulation rate, and subsequently electric power and steam consumption, can be achieved for the CBA TGTU option. Table 4 provides a tabulation of approximate amine circulation requirement for several nominal size units. Table 4 – Required Amine Circulation Rate for CBA TGTU vs. Claus TGTU Option 1 Claus TGTU Sulphur in Amine Tail Gas Circ. Rate (kmol/hr ‘S’) (m3/hr) 3 x 200 MTPD SRUs 2-Bed SRU 3-Bed SRU 3 x 300 MTPD SRUs 2-Bed SRU 3-Bed SRU 3 x 600 MTPD SRUs 2-Bed SRU 3-Bed SRU 2-Bed SRU 3-Bed SRU 3 x 66 = 198 3 x 49 = 147 3 x 74 = 222 3 x 55 = 165 3 x 230 = 690 3 x 200 = 600 3 x 240 = 720 3 x 210 = 630 --3 x 21 = 63 --3 x 24 = 72 --1 x 220 = 220 --1 x 235 = 235 3 x 33 = 99 3 x 25 = 75 3 x 160 = 480 3 x 130 = 390 --3 x 10 = 30 --1 x 150 = 150 3 x 22 = 66 3 x 16 = 48 3 x 125 = 375 3 x 110 = 330 Option 2 CBA TGTU Sulphur in Amine Tail Gas Circ. Rate (kmol/hr ‘S’) (m3/hr) --3 x 7 = 21 --1 x 120 = 120 3 x 675 MTPD SRUs Table 4 illustrates that the common CBA TGTU amine circulation rate is approximately equal to the circulation rate for a single TGTU train for the Claus option. In other words, the amine circulation requirement for option 2 is approximately one third of the circulation requirement for option 1. Taking this significant circulation rate reduction into account, along with the fact that two fewer TGTUs are required, one can deduce that at least a 60% reduction in TGTU LP steam consumption will be observed for option 2. The electric power reduction will be less pronounced at around 30%, due to the large power requirement for the quench circulation loop, which will remain relatively unchanged between options 1 and 2. In addition to the significant reduction in utility costs for option 2 explained above, there are also obvious operating and maintenance cost advantages associated with operating and maintaining only a single TGTU (option 2), rather than three separate TGTUs, as in option 1. While difficult to quantify, it is reasonable to assume a reduction in personnel and maintenance costs of greater than 50% by operating one common unit, rather than three separate trains. Risk of Incurring Penalty due to Environmental Excursion Referring back to the SRE comparison given in Table 1, it is clear that the CBA / TGTU configuration (option 2) will provide for higher overall sulphur complex recovery efficiency on a yearly rolling average than option 1. This is due to the fact that a shutdown of the common TGTU will result in a less significant effect on overall recovery efficiency than an upset or shutdown of just one of the three dedicated TGTUs for the Claus configuration (option 1). Thus, option 2 results in operational upsets and spurious trips having a dampened effect on the overall SO2 emissions bubble for the processing facility, ultimately increasing operating flexibility and reducing the risk of financial penalty resulting from SO2 excursions. In summary, an economic analysis reveals that the CBA / TGTU configuration (option 2) is superior to the Claus / TGTU configuration (option 1) in all respects, and therefore proves to be the lowest life-cycle alternative. Apart from allowing for a marginal reduction in capital investment cost, a CBA / TGTU configuration is also expected to provide the following key advantages over the lifetime of the facility, when compared with the Claus / TGTU option. • • • • • SRU steam export increase in the range of 4-5% TGTU LP steam consumption reduction of at least 60% TGTU electric power consumption reduction on the order of 30% Personnel and maintenance cost reduction of 50% or greater Significant risk reduction with respect to environmental excursion(s) While the capex and opex advantages afforded by option 2 were very attractive to Reliance, economic factors alone were insufficient to allow a conclusive decision to be reached. It was still necessary to address Reliance’s other fundamental project objectives, mainly centered on schedule optimization and a focus to reap the advantages of a repeat concept implementation. Schedule Comparison While the economic comparison above can be applied somewhat universally, a schedule comparison requires consideration of site-specific and project-specific elements, which cannot be evaluated from a general perspective. Hence, options 1 and 2 were compared on the basis of engineering execution approach, in order to determine which option would be more readily capable of achieving the aggressive schedule set forth by Reliance, taking into account all relevant project-specific considerations. The results of the schedule analysis are given in Table 5, which clearly illustrates that maximizing design duplication, combined with engineering, procuring and constructing a single common unit makes option 2 the clear winner with respect to minimization of JERP project execution schedule. Table 5 – JERP Project Execution Schedule Comparison of Options 1 and 2 Evaluation Criterion Total Number of Equipment Items - Number of drawings - Equipment lead times - Erection time Engineering and Design Repeatability (Reduction in Engineering Hours) Operation and Maintenance Requirements - Time required to train on unfamiliar units - Ability to train on existing systems Option 1 (Claus / TGTU) Option 2 (CBA / TGTU) Most (-1) Longest (-1) Longest (-1) Lowest (-1) Fewest (+1) Shortest (+1) Shortest (+1) Highest (+1) Highest (-1) Lowest (-1) Lowest (+1) Highest (+1) Overall Sulphur Complex Footprint TOTAL SCORE* Largest (-1) (-7) Smallest (+1) (+7) * A positive value represents the preferred (i.e. minimum schedule) option for each evaluation criterion; a negative value indicates the least preferred option. JERP Facility Under Construction (19 months into project schedule) Comparison on Basis of Proven Design and Operational Simplicity Historically, option 1 has been the most common industry process configuration for achieving 99.9% SRE, and would clearly be the preferred option with respect to proven design and ease of operation. Option 2 has two obvious disadvantages – 1) While CBA and amine-based tail gas treating technologies are both well proven, the two have not been combined in a single processing train, and 2) utilization of a common TGTU for three SRUs presents tie-in, layout and operational challenges that do not exist for option 1. The main challenges associated with option 2 are described below. CBA Impact on TGTU Operation The Cold Bed Adsorption process is a cyclic process which uses the same catalyst as conventional Claus technology, but in a low temperature range such that sulphur is produced more efficiently, followed by adsorption onto the catalyst surface. Before the catalyst becomes significantly deactivated by liquid sulphur, it is regenerated to restore its activity, which is accomplished by flowing hot gas through the reactor to heat the catalyst and desorb (vaporize) the sulphur. The dynamic nature of the CBA process presents the following unique design considerations for the downstream TGTU, related to fluctuations in tail gas flow rate and composition: • • Number of SRUs in regeneration at any given time should be optimally limited to one, to prevent excessive hydraulic fluctuations in the TGTU TGTU hydrogen control scheme should be conservatively designed to ensure complete conversion of all tail gas sulphur compounds to H2S in the hydrogenation reactor, taking into consideration fluctuating SRU tail gas flow rate and composition Common TGTU Considerations As noted previously, it is not unusual to provide a common TGTU for multiple SRUs; however, the advantages of reduced cost and footprint do not come without challenges. Some of the commonly experienced difficulties are noted below: • If not properly safeguarded, a single TGTU presents a potential common point of failure for all of the upstream SRU trains, which defeats the purpose of installing multiple SRU trains in the first place • • TGTU layout symmetry (in relation to the SRUs) is important to prevent the potential for unbalanced flow through the SRU trains TGTU equipment and piping size can become unmanageable depending on the size and number of upstream SRU trains - it should be noted that the Reliance 2,025 MTPD TGTU is approaching the maximum practical size with respect to mechanical design and fabrication • Special valving requirements must be considered to accommodate positive isolation of each SRU train, allowing for operation of the TGTU while one or more SRUs is removed from service for maintenance • Start-up / Shut-down procedures are more complicated for an individual SRU when it is tied into a common downstream TGTU versus when it is equipped with its own dedicated tail gas unit The operational and design challenges identified were not insignificant; however, both Reliance and B&V agreed that the cost and schedule advantages associated with option 2 far outweighed any such potential difficulties which could arise. Therefore, it was agreed that these operational challenges would not be a concern if given proper consideration during design, commissioning and start-up. Accordingly, identifying and openly discussing potential design and operational concerns would be a key activity throughout project execution and startup planning. SELECTING THE PREFERRED OPTION In order to minimize schedule, allowing for start-up of the new facilities as early as possible in 2008, Reliance made the decision to maximize duplication and proceed with the option 2 repeat concept (3 x CBA + 1 x TGTU). This option would also provide added advantages of highest recovery efficiency when the TGTU is out of service and minimum training requirements for Reliance operations staff. Because the initial investment cost differential between the two options was minor, capital cost did not prove to be a key determining factor in the option selection process. However, operating and maintenance cost considerations weighed heavily into the decision, as these factors bolstered option 2 into the lowest life-cycle cost position. Although potential design and operational challenges associated with JERP SRU Incinerator Stack (one of three - designed to receive tail gas from TGTU, or from SRU directly when common TGTU is bypassed) merging the two technologies were identified, schedule and cost advantages were deemed to far outweigh any special engineering and operation considerations that would be required to address these issues. SUMMARY AND CONCLUSION In summary, the new JERP sulphur recovery complex at the Jamnagar Refinery is being designed to achieve the same guarantee capacity as the existing DTA facilities, albeit at increased SRE – 99.9% vs. 98.7%. This will be accomplished via repeating the existing DTA CBA design and installing a common downstream TGTU for the three SRU trains. While both technologies are well proven, the Reliance JERP Refinery will be the first to combine CBA and amine-based H2S absorption TGTU technologies in a single sulphur recovery complex. B&V are carrying out the innovative design to provide alignment with all of Reliance’s technical objectives, while also meeting aggressive project execution targets set forth by Reliance. Eventually Reliance plan to install a common TGTU downstream of the existing DTA CBA units, and the design of the JERP TGTU is expected to be cloned. Although the unique coupling of CBA and amine-based TGTU technologies was developed solely to meet Reliance’s specific project needs, there is much evidence to support the implementation of this type of arrangement for other existing and greenfield developments, when recovery efficiency in excess of 99.5% is required. Despite project-specific drivers, generally speaking, a CBA / TGTU configuration is expected to provide lower life-cycle cost, higher efficiency and improved reliability, when compared to a more traditional Claus / TGTU approach. As with the implementation of any new concept, there will most definitely be operating challenges and learning curves to overcome during the initial operation period of the units. However, past experience shows that a Reliance / B&V team will develop a highly successful cooperation to overcome any such obstacles with ease. ACKNOWLEDGMENT The authors of this paper would like to thank the following individuals for their valuable contributions. Cyril Tandy Reliance Industries Limited A. Poddar Senior Executive Vice President (Projects) Reliance Industries Limited E. James Senior Vice President Reliance Industries Limited J. Bagchi General Manger (Projects) Reliance Industries Limited Hector Brouwer de Koning Vice President & Project Director Black & Veatch Energy Javid Talib Vice President & Senior Project Manager Black & Veatch Energy REFERENCES “CBA Process Exceeds 99.3% Sulfur Recovery at India's Newest Refinery – Reliance Petroleum Company's Jamnagar Refinery,” Upendra M. Bokare et al., Sulphur 2000, San Francisco, California, November 2000. “Enhanced Process Configurations for the CBA Process,” David K. Stevens and William H. Buckhannan, Sulphur Magazine No. 225, March-April 1993, p. 37. “Cold Bed Adsorption Subdewpoint Technology for Improved Sulphur Recoveries,” David K. Stevens, Black & Veatch Pritchard, Inc. Internal Paper, October 1997. “Reliance Petroleum Using CBA Technology to Meet India’s Emission Regulations at Lowest Cost,” Richard J. Wissbaum, Johnny E. Johnson and Dr. Partha P. Maitra, Sulphur 98, Tucson, Arizona, November 1998. “Sulphur Recovery Guidelines Review,” Advisory Group Report, April 2000. ### (Angela F. Slavens is Vice President of Black & Veatch’s Sulphur Technology, and Keith Didriksen is Manager of Estimating for Black & Veatch’s GOG Business Line)