ADVANCED PROCESS CONTROL QATAR GAS ONE YEAR EXPERIENCE

ADVANCED PROCESS CONTROL QATAR GAS ONE YEAR EXPERIENCE Bouchebri El-Hadi Senior Process Engineer Benmouley Abdelkader Head of Process Qatar Liquefied Gas Company Limited. Ras Laffan Industrial Area, Doha, Qatar belhadi@qatargas.com.qa abenmouley@qatargas.com.qa ABSTRACT The objective of this paper is to present the Qatar Liquefied Gas Company one year experience with the Advanced Process Control Technology. Advanced Process Control was implemented in the Onshore Facilities with the objective of Maximizing LNG production and reducing Steam consumption. The paper will present details of APC configuration, covering not only the liquefaction facilities but also treating, sulfur recovery, and fractionation units. An overview will be presented of the actual APC performance improvement both during acceptance testing and normal operation after implementation. PO-58.1

I INTRODUCTION Qatar Liquefied Gas Company is located in Ras Laffan Industrial Area about 90 Km North of Doha, State of Qatar. The Qatar Gas company is composed of two major areas i.e. offshore and onshore Facilities; the offshore facility represents three well head platforms and three gas treatment (Dehydration) trains. The dehydrated gas and condensate are transported to the onshore facilities via an 82 km pipeline (32 diameter). The Company main business objective is to produce Liquefied Natural Gas and condensate as per design specifications and optimize use of plant facilities. As part of Qatar Gas Plant optimization effort, Qatar Gas contracted Honeywell Hi Spec Solution to implement Advanced Process Control (APC) for Upstream, 3 LNG Process Trains and Acid Gas Enrichment and SRU units at the Ras Laffan facilities in Qatar. The three LNG Trains have been de- bottlenecked where a considerable capacity increase has been reached; an important aspect in the plant operation is that ambient conditions especially the summer (Day-Night) temperature affects the LNG run down capacity due to gas turbine limitations. The APC project second phase implementation was conducted on the Acid Gas Enrichment (AGE) and Sulfur Recovery Unit (SRU) units; the second phase APC implementation was initiated after the phase I APC implementation results exceeded the guaranteed values. The aim of Advanced Process Control (APC) implementation is to operate the plant at the best operator conditions all the time without sea line pressure and LNG through put variation. These new operating conditions were predicted to increase the cumulative LNG production by 1.0% with the Robust Multi Predictive Controllers Technology (RMPCT) controllers and additional 0.5 % with the profit Optimizer. The overall steam reduction (Amine regeneration & fractionation units) was predicted to be reduced by 5 %. For the SRU and AGE units, the APC objectives were set to increase the sulfur recovery by 0.1%, reduce the SO2 emission by 14.4% and reduce the steam consumption by 5.1% in the AGE re-boilers units The project has started in December 14 th 2004 for a period of 13 months; the performance test was conducted from 23 to 29 January 2006 for winter test and from 10 to 17 July 2006 for summer test. The phase II project was started November 5 th 2006, and it s scheduled for a period of 6 months. Twenty five (25) RMPCT controllers were connected to the DCS (Foxboro) Platform; the Profit Optimizer handles the optimization constraints for the all 25 controllers. The APC was implemented for the following sections: A. Upstream onshore section B. Condensate stabilization units PO-58.2

C. LNG Trains 1, 2 and 3 Acid Gas Removal D. LNG Trains 1, 2 and 3 Fractionation E. LNG Trains 1, 2 and 3 Liquefaction units F. Acid Gas Enrichment units** G. Sulfur Recovery Units** **: Controllers in Commissioning Phase Qatar Liquefied Gas Company Plant General Overview Qatar Gas Overview LNG PLANT LNG STORAGE LNG LOADING -53M CD 1450 MMSCFD 82 km OFFSHORE UPSTREAM SEPARATIO N DOWNSTREAM LNG PLANT OFF-PLOTS / HARBOUR / JETTY CONDENSATE STORAGE ONSHORE SULFUR LNG TANKERS,LNG, CONDENSATE, SULFUR PO-58.3

II- PROCESS OVERVIEW Qatar Gas onshore plant receives the de-hydrated gas (condensate & Gas) from the offshore platform via 32 pipeline. A first separation is taking place in the slug catcher where gas will feed the three LNG Trains and condensate will be stabilized in the three upstream trains. The stabilized condensate (under RVP control) will be pumped to storage section from the bottom of strippers, while the strippers overhead gas will be compressed and mixed with the slug catcher gas to form the LNG trains Feed Gas. The three identical LNG Trains are composed of the following section: Acid gas removal section: removes H 2 S and CO 2 under Amine Absorption reactions; the rich Amine solution is regenerated at low pressure and high temperature in the Amine regenerator column where the overhead acid gas is send to the Acid Gas Enrichment unit for further treatment. The sweet gas is under H 2 S and CO 2 on line control. Dehydration section: the sweet gas is dehydrated for moisture removal; the dry sweet gas is under on line moisture content monitoring. Mercury removal section: removes mercury for exchanger protection. Liquefaction section: the treated gas is pre-cooled in HP-MP LP propane Chillers to reach -30 Deg C before entering the scrub column. The bottom of the scrub column is directed to fractionation for further separation while the column overhead is sent to the Main Heat Exchanger for liquefaction. Refrigeration section: two main loops are included in this section; Multi refrigerant MR (N2, C1, C2 & C3) and propane circuits. The MR is compressed in three stages, cooled in the propane chillers then expanded through two Joule Thomson Valves in the Main heat exchanger to liquefy the Natural gas via three bundles (warm, middle and cold). Fractionation: composed of three columns De-ethanizer, De-Propanizer, De- Butanizer; the scrub column bottom stream is feeding the De-ethanizer, the deethanizer bottom is feeding the De-propanizer and the De-Propanizer bottom is feeding the De-Butanizer. The De-Butanizer bottom (mainly C 5 +) is routed to the De- Iso- Pentanizer for Iso and Normal C 5 separation. The three columns (De-C 2, De-C 3, and De-C 4 ) overheads are mixed in a same stream and pre-cooled in a propane chiller before entering the Main Heat Exchanger and being mixed with the Natural Gas as an LPG for heating value correction. Nitrogen section: nitrogen is removed from the LNG to maintain the Heating Value as per design figure; the nitrogen is extracted at low pressure and temperature from the LNG in the nitrogen rejection column. The mixture nitrogen-methane from the column overhead is compressed and mixed with the fuel gas streams The LNG leaving the nitrogen column at -160 Deg C is pumped to the LNG Storage tanks. Helium: the Helium Extraction unit extracts helium from the LNG at low temperature in a cold box unit; the produced helium is send to Ras Gas Company for storage and commercialization. PO-58.4

Acid Gas Enrichment AGE: The Qatar Gas Ras Laffan facility has two Acid Gas Enrichment (AGE) units or trains, in series with two Sulfur Recovery Units (SRU). These trains receive sour gas from the LNG Trains 1, 2 and 3 Acid Gas Recovery (AGR) Units through a common header. The AGE process units include an Acid Gas Absorber, Amine Solution Regenerator, Reject Gas Incinerator and auxiliary equipment. The operating scheme uses the concept of Acid Gas Enrichment (AGE) to achieve the design objectives of sulfur recovery unit, with the advantage of separating most of the hydrocarbons and CO 2 from the H 2 S in the acid gas from the Sulfinol units prior to this gas being fed to the Claus plants. This increase of H 2 S in the acid gas means that the Claus unit should not be susceptible to coking or other problems caused by carbon formation. The enriched acid gases from the AGE amine regenerators are combined in one header and fed to the two existing SRU. Sulfur Recovery Unit: The SRU units process the enriched acid gas feed from the AGE units and converts the H 2 S and other sulfur compounds to high purity sulfur. The Qatar gas SRU utilizes the SuperClaus-99 process for recovering elemental sulfur from the acid gas. The operating objective is to recover as much of the sulfur in the feed as possible. The process scheme consists of three ordinary Claus Reactor stages, followed by a Super Claus Reactor stage in which H 2 S is selectively oxidized. The basic philosophy of the SRU operation is to control the partial combustion of H 2 S with the ratio of air to maintain a specified H 2 S concentration at the outlet of the third stage Claus Reactor. The main reaction in the main burner is: 3 H 2S + O2 SO2+ H 2O + heat 2 The major part of the residual H 2 S combines with the SO2 to form sulfur, according to the equilibrium reaction: 3 2 H S SO S + H O heat 2 + 2 2 2 2 2 By this reaction, known as the Claus reaction, sulfur is formed in vapor phase in the main burner (X0901) and combustion chamber.the primary function of the waste heat boiler is to remove the major portion of heat generated in the main burner. The secondary function of the waste heat boiler is to utilize the above mentioned heat to produce HP steam. III- ADVANCED PROCESS CONTROL (APC) PROJECT A. Scope of Work: The project scope of work was decided based on other LNG plants experience as a guide line and the Qatar Gas Engineers experience in the existing LNG plant. The scope of work was finalized as follows: Tuning of all relevant PID controllers. Full training for Engineers and Operators to be provided. Provision of all relevant hardware and software. Performance test over 5 days for both winter and summer conditions. Performance Guarantee Based on the benefit study, APC project to guarantee a minimum of 10 m3/hr LNG increase per train. PO-58.5

B. Control Objectives and Strategy 1- Upstream The upstream section optimization philosophy objectives are to maintain the sea line pressure steady, control the pre-flash drum level at constant value and optimize the condensate Reid Vapor Pressure (RVP) based on summer & winter limitations. a) Slug catcher & Pre-flash drum Controller (# 1) Control the Slug catcher and Pre-flash Drums levels while using the available buffer capacities. Balance the load among the three strippers by adjusting the individual feed flows. Condensate. b) Condensate Stripper controllers (# 3) the design of this RMPCT controller is to control stabilizer bottoms RVP derived from pressure compensated temperature. The stabilizer overheads nc5 derived from pressure compensated temperature, and the condensate heater process stream passes temperature difference by balancing the condensate flow from one pass to another to maintain the Delta T Passes as low as possible. This will eliminate the high coil skin temperature. 2- Downstream The down stream area optimization philosophy objectives are to maximize the LNG run down from each train without exceeding any design or safety limit parameters. To achieve these optimization objectives, the Advanced Process Control philosophy was divided in three different areas; where the RMPCT Controllers were implemented for each separate area. a) Acid gas removal (# 3): One Profit controller (RMPCT) per train is connected to the Acid Gas Removal unit (Absorber & Rich Amine Regenerator) to optimize: Lean Amine Circulation Re-boilers Steam flow Consumption. Regenerator reflux to Rich Amine Ratio (as per Vendor recommendations). Achieving the above optimization targets without exceeding the below constraints: Sweet Gas H 2 S & CO 2 content as per design limitations. Regenerator bottom temperature as per vendor specifications. b) Liquefaction (# 3): One profit controller (RMPCT) per train is handling the Manipulated Variables (M V ) and the Controlled Variables (C V ) for the liquefaction and the refrigeration units to maximize the LNG production per train. The philosophy is: Maintain MR gas turbine close to the Machine Limited conditions all the time. Maintain the Propane gas turbine close to the machine limited conditions all the time. Maintain the LNG temperature outlet the Main Heat Exchanger constant at a desired value all the time. Scrub column overhead C 5 + to be controlled at the design minimum value. LNG Heating Value to be controlled at the desired value. PO-58.6

End Flash Gas Compressor load to be controlled below the alarm setting. The above conditions will optimally react to the day-night feed gas fluctuation and therefore the best operator will be on duty all the time. c) Fractionation (# 9): Three profit controllers (RMPCT) per train will be optimizing respectively the Deethanizer, De-propanizer and De-Butanizer operating conditions as follows: Maintain De-Ethanizer Column Pressure & Temperature Profiles constant as per desired values (Design conditions). Maximize the De-C 2 overhead Ethane recovery. Minimize the De-C 2 Re-boiler steam flow. Maintain the De-C 3 Column pressure & temperature profiles constant as per preferred values (Design cases). Maximize the De-C 3 overhead propane recovery. Minimize the De-C 3 Re-boiler Steam Flow. Maintain the De-C 4 Column pressure & temperature profiles constant as per preferred values (Design cases). Maximize the De-C 4 overhead butane recovery. Minimize the De-C 4 Re-boiler Steam Flow. OptimizetheDe-C 4 bottom RVP by inferential calculation d) Acid Gas Enrichment (#3) 1 Profit controller: is proposed in order to achieve optimum and stable distribution of the combined acid gas feed from the LNG AGR units using advanced control system 2 profit controllers: This controller is proposed in order to achieve optimum and stable distribution of the combined acid gas feed from the LNG AGR units using advanced control system. e) Sulfur Recovery Unit (#3): 1 profit controller: Optimum and stable distribution of the combined enriched acid gas feed from the AGE units is an important objective of the advance control system. Therefore, a single Profit Controller application is specified for distribution of the enriched acid gas feeds to the two SRU. 2 profit controllers: The SRU units process the enriched acid gas feed from the AGE units and converts the H2S and other sulfur compounds to high purity sulfur. The operating objective is to recover as much of the sulfur in the feed as possible. The process scheme consists of three ordinary Claus Reactor stages, followed by a Super Claus Reactor stage in which H2S is selectively oxidized, and all associated ancillary equipment. For the SRU, two Profit Controllers are envisioned, one for Train 1 SRU and one for Train 2 SRU. PO-58.7

3 Profit optimizer: The profit optimizer controller is linked to the twenty five profit controllers, where all the constraints for the overall plant are handled in order to maintain the total plant at Optimum Conditions (Maximum LNG rundown and minimum acceptable energy consumption) without violating the design specifications and equipments characteristics. The profit optimizer objective function can be presented as follows: J = i P i Y i P j F j + P k Where J = the objective function to be minimized (QR/h) P i = the marginal value of the i th product (QR/m 3 ) Y i = the flow of the i th product (m 3 /h) P j = the marginal cost of the j th feedstock (QR/m 3 ) F j = the feed rate of the j th feedstock (m 3 /h) P k = the marginal cost of the k th utility, e.g. (QR/unit) + j k U k PO-58.8

Qatar Liquefied Gas Company APC phase I overview Profit Controller Profit Controller Profit Controller Profit Optimiser Profit Controller Profit Controllers PO-58.9

Load Distribution Controller Profit Controller 1 Per Train Load Distribution Controller Profit Controller 1 Per Train IV- Performance Test results After Profit Optimizer was commissioned, a performance test was conducted in LNG Train-2 for a period of 6 days; the test was conducted in winter and summer period The performance test conditions were as follows: Train-2 Feed gas fixed at 590MMscftd. PO-58.10

Feed gases for other trains were floating on sea line pressure (Pressure maintained between 79.8: 80.5 Barg). Train-2 lean amine flow limited by a fixed high limit value to protect the lean amine pump from power over load. Lean Amine to Feed Gas Ratio floating between 1.64 to 1.8 m 3 /MMscft. A. Tangible benefits The below table shows a comparison between the main benefit objectives agreed and the results obtained during the performance tests conducted during six days respectively in winter and summer periods. APC Phase I Winter Test Summer Test Guaranteed Values % LNG Increase + 6.5 + 3.5 + 1.5 %Steam flow reduction % Fuel Gas to Condensate Heaters - 3.5 1-10.8-5 - 4.2-0.6 Not measured as a guaranteed parameter 1 : steam flow reduction target hasn t been reached due to the Lean Amine to the Feed Gas Ratio was set at a wide range (Design R =1.6 m 3 /MMscft) to avoid any sudden breakthrough of H 2 S or CO 2 at very high feed rate. The below table gives the comparison results from 2004 to 2006 respectively pre and post APC: APC Phase I 2004 To 2006 Guaranteed Values % LNG Increase + 4.6 +1.5 % Steam reduction - 7.1-5 The above results are not only from the APC implementation but also due to: Full involvement of Operation personnel during the two performance test periods. Better tuning of the main plant controllers. The below table gives the APC phase II average guaranteed parameters. APC Phase II Guaranteed Values % Sulfur Recovery + 0.1 % Emission Reduction - 14.4 % Steam Reduction - 5.1 Performance test is scheduled during the 2007 first quarter; the results will be presented during the conference poster session. PO-58.11

B. Non tangible benefits: Maintain sea line pressure steady between 79.8 to 80.5 Barg Maintain slug catcher & pre-flash drum level steady. Maintain the condensate on- spec RVP steady at a desired fixed value. Maintain the condensate heater two passes temperature close to each other. Maintain the Amine regenerator bottom temperature (LNG Trains and AGE units) constant at a desired fixed value. Maintain the Amine regenerator column reflux to rich Amine ratio within the vendor recommended range. Maintain the Claus and super Claus reactors parameters steady close to design conditions. In addition to the above non tangible benefits, a survey results from Operation Department (End users) is presented in the below table: Criteria Overall satisfaction Benefit value of APC Work load Process values meeting the set points Interface Man-Machine Rating Very Good Very good Less with APC Automatic and will not exceed the fixed ranges Friendly V- CONCLUSION Advanced Process Control Technology Qatar Gas experience is less than 1 Year since the phase I project commissioning. The results obtained during the performance are exceeding the guaranteed value regarding the LNG production. Results of APC implementation is convincing. APC has helped to maintain sea line pressure and load distribution among the three downstream trains. APC has helped to reduce variation in many important parameters such as LNG trains feed gas day- night variation. Overall benefit figures in terms of production rise and energy savings are valuable. PO-58.12

VI- APPENDIX: A. Performance test Process Data Trends Comparison: The process data were compared during 6 days performance test before and after APC implementation. Trend-1: Winter Test Steam to rich Amine Ratio Pre APC: Steam To Rich Amine Ratio Pre APC ( Kg Steam / M3 R Amine) 100 95 90 85 80 75 23-Jan-05 24-Jan-05 25-Jan-05 26-Jan-05 27-Jan-05 28-Jan-05 29-Jan-05 Steam To Rich Amine Ratio KgSteam / M3 R Amine Trend-2: Winter Test Steam to Rich Amine ratio Post APC Steam To Rich Amine Ratio Post APC (Kg Steam / M3 R Amine) 100 95 90 85 80 75 23-Jan-06 24-Jan-06 25-Jan-06 26-Jan-06 27-Jan-06 28-Jan-06 29-Jan-06 Steam To Rich Amine Ratio KgSteam / M3 R Amine Trend-3: Winter Test LNG rundown Pre APC: PO-58.13

2FI805.PV P801A/B LNG Rundown Prduction Flow Pre APC (M3/H) 110.0% 107.5% 105.0% 102.5% 100.0% 97.5% 95.0% 92.5% 90.0% 2005-01-23 2005-01-24 2005-01-25 2005-01-26 2005-01-27 2005-01-28 2005-01-29 2FI805.PV P801A/B LNG RUNDN PROD F M3/H Trend-4: Winter Test LNG rundown Post APC: 2FI805.PV P801A/B LNG Rundown Production Flow Post APC (M3/H) 110.0% 107.5% 105.0% 102.5% 100.0% 97.5% 95.0% 92.5% 90.0% 2006-01-23 2006-01-24 2006-01-25 2006-01-26 2006-01-27 2006-01-28 2006-01-29 2FI805.PV P801A/B LNG RUNDN PROD F M3/H PO-58.14

Trend-5: Summer Test LNG Rundown Pre APC: Summer Test LNG Rundown Pre APC 1000 980 960 940 LNG Rundown M3/H 920 900 880 860 Summer Base Line = 937 M3/H 840 820 800 10-Jul-04 11-Jul-04 12-Jul-04 13-Jul-04 14-Jul-04 15-Jul-04 16-Jul-04 17-Jul-04 Date 2FI805.PV Trend-6: Summer Test LNG Rundown Post APC: Summer Test LNG Rundown Post APC 1100 1080 1060 Summer test LNG Increase = 3.49 % 1040 LNG Rundown M3/H 1020 1000 980 960 940 920 Summer Base Line = 937 M3/H 900 12-Jul-06 12-Jul-06 13-Jul-06 13-Jul-06 14-Jul-06 14-Jul-06 15-Jul-06 15-Jul-06 16-Jul-06 16-Jul-06 Date 2FI805.PV PO-58.15

B. 1 Year performance process data comparison: The process data were compared between year 2004 and 2006, the results are shown in the following trends. Trend 7: Year 2004 steam consumption: Pre APC Total Steam to Total Sulfinol Ratio Kg/M3 130 120 Steam to Amine Ratio Kg/M3 110 100 90 80 Average Steam to Amine ratio = 107 Kg/M3 70 60 2003-12-30 2004-02-18 2004-04-08 2004-05-28 2004-07-17 2004-09-05 2004-10-25 2004-12-14 Year 2004 Total Steam to Total Sulfinol Ratio Kg/M3 Trend 8: Year 2006 steam consumption: Post APC Total Steam To Total Sulfinol Ratio Kg/M3 130 120 Steam Consumption reduction =7.14% 110 Total Steam To Total Amine Ratio 100 90 80 Average Steam to Amine Ratio Kg/M3 70 60 2005-12-29 2006-02-17 2006-04-08 2006-05-28 2006-07-17 2006-09-05 Year 2006 Total Steam To Total Sulfinol Ratio Kg/M3 PO-58.16

Trend-9: Total plant LNG rundown year 2006: Total Plant LNG Production Post APC 3200 3100 4.6 to 5.2 % Increase on total LNG run down 3000 LNG Run Down M3/H 2900 2800 2700 2600 2500 2400 Average LNG run down = 2817 2300 2200 29-Dec-05 17-Feb-06 08-Apr-06 28-May-06 17-Jul-06 05-Sep-06 25-Oct-06 14-Dec-06 Year 2006 Year 2006 total LNG run down Trend-10: Total plant LNG rundown year 2004: 3200 Pre APC Year 2004 total LNG run down 3100 3000 LNG run down M3/H 2900 2800 2700 2600 2500 2400 2300 Average LNG production = 2657 M3/H 2200 30-Dec-03 18-Feb-04 08-Apr-04 28-May-04 17-Jul-04 05-Sep-04 25-Oct-04 14-Dec-04 Year -2004 Year 2004 total LNG run down PO-58.17

Trend-11: Condensate heater passes temperature difference Year 2006 Condensate Heater passes post APC 5.00 4.50 4.00 Condensate Heater Passes DT C 3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.00 2005-12-29 2006-02-17 2006-04-08 2006-05-28 2006-07-17 2006-09-05 2006-10-25 2006-12-14 Year-2006 Absolute Heater passes Delta T U-H8100 DEG C Absolute Delta T U-H8200 DEG C Trend-12: Condensate heater passes temperature difference Year 2004 Condensate Heater Passes Delta T pre APC 5.00 4.50 4.00 3.50 Heater passes DT C 3.00 2.50 2.00 1.50 1.00 0.50 0.00 2003-11-25 2004-01-14 2004-03-04 2004-04-23 2004-06-12 2004-08-01 2004-09-20 2004-11-09 2004-12-29 2005-02-17 Year-2004 Absolute Heater Passes Delta T U-H8100 DEG C Absolute Heater Passes Delta T U-H8200 DEG C PO-58.18