Gas Processing

GAS PROCESSING Training Manual

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PETROCONSULT PROJECT

Company Doc. No.:

GAS PROCESSING

Contractor Job Cod :

Training Manual

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Information provided in this manual is designed to address the most commonly raised issues in the workplace relevant to the Gas Plant Mellitah The Manual will be reviewed at regular interval with the inclusion of all necessary amendments.

Copyright © Petroconsult SRL, Ploiesti, Str. Diligentei No. 18, Code 100575 www.petroconsult.ro All rights reserved ISBN 973-740-028-3 ISBN 978-973-740-028-4

Redacted, Eng. Radu Gratian PEPENE

Verified, Technical Manager Dr.Eng. Vasile SOMOGY

Aproved, General Manager, Eng. Mircea LABA

This Manual is legally property of Petroconsult S.r.l., and can not be reproduced partial or total and distributed without written assent of Petroconsult SRL.

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Company Doc. No.:

GAS PROCESSING


Training Manual


Information provided in this manual is designed to address the most commonly raised issues in the workplace relevant to the Gas Plant Mellitah The Manual will be reviewed at regular interval with the inclusion of all necessary amendments.

Copyright © Petroconsult SRL, Ploiesti, Str. Diligentei No. 18, Code 100575 www.petroconsult.ro All rights reserved ISBN 973-740-028-3 ISBN 978-973-740-028-4

Redacted, Eng. Radu Gratian PEPENE

Verified, Technical Manager Dr.Eng. Vasile SOMOGY

Aproved, General Manager, Eng. Mircea LABA

This Manual is legally property of Petroconsult S.r.l., and can not be reproduced partial or total and distributed without written assent of Petroconsult SRL.

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CONTENT

INTRODUCTION………………………………………………………………………………………………………

1.– CONDENSATE STABILIZATION & OFF-GAS COMPRESSION – UNIT 210……………………………… 1.1 – General……………………………………………………………… General…………………………………………………………………………………………………………… …………………………………………… 1.2 – Unit 210 – Condensate Stabilization, Off - gas Compression and Off – Specs. Storage……………………… 1.2.1 – Main Equipments……………………………………………………………………………………… 1.2.2 – Off – gas compression train……………………………………………………………………………… 1.2.2.1 – Main equipments of the Off-gas compression train…………………………………………………… 1.2.2.2 – Gas compressor auxiliaries……………………………………………………………………………… 1.3 – Condensate Stabilization & Off-gas Compression – Process Description………………………………… 1.3.1 – Off-gas compression……………………………………………………………………………………… 1.3.2 – Off- specs. Storag e…………………………………………… e………………………………………………………………………………………… …………………………………………… 1.4 – Routine Operating Procedures……………………………………………………………………………… 1.4.1 – Process Variables………………………………………………………………………………………… 1.4.1.1 – Stabilizer main process variables……………………………………………………………………… 1.4.1.2 – Off-gas compression section main process variables……………………………………………… 1.5 – Control system – Main process control loop……………………………………………………………… 1.6 – Star t-Up procedures…………………………………………………………………………………………. 1.6.1 – Start the 1 st train of condensate stabilization……………………………………………………………… 1.6.2 – Start the Off-gas compression system…………………………………………………………………… 1.7 – Shut Down procedures……………………………………………………………………………………… 1.8 – Common troubleshooting……………………………………………………………………………………

2.– GAS HC DEW POINT CONTROL – UNIT 340………………………………………………………………… 2.1 – General……………………………………………………………… General……………………………………………………………………………………………………… ……………………………………… 2.1.1 – Hydrocarbon dew point…………………………………………………………………………………… 2.1.2 – Gas Dew Point Control – Purpose and application……………………………………………………… 2.1.3 – Mai n procedures…………………………………………………………………………………………… 2.1.4 – Propane – characteristics, properties and combustion…………………………………………………… 2.2 – Gas dew point control using propane refrigeration………………………………………………………… 2.3 – Propane Refrigeration Unit – description of the package…………………………………………………

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2.4 – Gas Hydrocarbons Dew Point Control Process description………………………………………………. 2.4.1 – Process Variables…………………………………………………………………………………………. 2.5 – Start-Up of the 1 st train of Gas HC Dew Point Control…………………………………………………… 2.6 – Shut Down procedures……………………………………………………………………………………… 2.7 – Troubleshooting………………………………………………………………………………………………

3. – NGL FRACTIONATION – UNIT 320…………………………………………………………………………… 3.1 – General………………………………………………………………………………………………………. 3.2 – Unit 320 – General process description……………………………………………………………………… 3.2.1 – Main equipments of the NGL Fractionation Plant………………………………………………………. 3.2.2 – Detailed process description……………………………………………………………………………… 3.2.3 – Process Variables…………………………………………………………………………………………… 3.2.4 – Co ntrol syst em……………………………………………………………………………………………… 3.3 – Start – Up of the NGL Fractionation plant………………………………………………………………… 3.4 – Shut Down procedures……………………………………………………………………………………… 3.5 – Common troubleshooting……………………………………………………………………………………

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INTRODUCTION

Mellitah Plant treats Raw Gas and Unstabilized Condensate feedstock received from Sabratha Platform by two subsea pipelines of 36” and 10” respectively. The hourly feed rate of gas and liquid to be treated in the plant through the two pipelines to 3

produce 6.66 Billion Sm /year of Sales gas (including 1.1 swing factor) are the following: 3

• Raw Gas (36” pipeline): 1003.02 tons/h; 1.006 MMSm /h 3

• Unstabilised Cond. (10” pipeline): 109.30 tons/h; 156.1 Sm /h The above figures are referred to the scenario foreseen in winter season after 11 years of plant operation. For summer season of year 2 the hourly feed rate of gas and liquid to be treated in the plant through the two pipelines are the following: 3

• Raw Gas from 36” pipeline: 1017.10 tons/h; 1.018 MSm /h 3

• Unstabilised Condensate from 10” pipeline: 143.48 tons/h; 203.3 Sm /h Mellitah Plant produces 6.0 Billions/year standard cubic meters of sales gas (excluding swing factor) to be delivered to Mellitah Gas Compression Station (MGCS) and Local gas Compression Station (LGCS). The process units foreseen to treat the Raw Gas include Gas Sweetening, Gas Dehydration and Gas HC Dew Point Control. The Acid Gas from Gas Sweetening Unit is treated in Sulphur Recovery Units (SRU) to produce liquid Sulphur. The Sulphur Recovery Plant treats the Amine Acid Gas coming from Gas Sweetening units and the Sour Water from Gas Dehydration units and converts the H 2S contained, into elemental sulphur. The resulting Tail Gases will be thermally oxidised in the Incinerator Unit along with the Flash Gas and Regeneration Fuel Gas coming from Gas Dehydration and LPG Dehydration (WAFA) respectively. Mellitah Plant also includes units which produce Stabilized Condensate from the Unstabilized Condensate coming from the pipeline and NGL Fractionation Units which produce LPG, stabilized condensate and fuel gas. The stabilized condensate is stored in dedicated storage tanks. The LPG is sent to C3/C4 splitter in WAFA Coastal Plant. Fuel Gas is sent to WAFA Coastal Plant to be used as fuel for internal consumption. Above is presented the Block Flow Diagram which shows the interconnection of the units

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50-210 Condensate Stabilization(trains 1&2 ), Off-gas compression , 50-340 Gas Hc Dew Point Control ( trains 1;2;3), 50-320 NGL Fractionation (trains 1&2) with other units located on Mellitah platform.

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The raw(sour) gas delivered to the plant is a complex mixture of hundreds of different compounds of hydrogen and carbon, all with different densities, vapour pressures and other physical characteristics. As this mixture flows towards the plant, gases evolve from the liquids, water vapour condenses and some of the well stream changes in character from liquid to bubbles, mist and free gas. After the inlet production/field separators designed to separate and remove undesirable components and to separate the gas from the free liquids such as crude oil, hydrocarbon condensate, water and entrained solids, in gas plant trains there are a series of plants which separates the valuables products within trade requirements. Some theoretical considerations are necessary to be presents in followings paragraphs. Gas/liquid separation is an operation which main purpose is to separate liquid particles from a gaseous stream.

The forces imposed on particles in mechanical separators are gravity, drag and inertial forces. Gravity forces act vertically downward. Inertial forces are a result of particle circular motion. Drag forces are resistive forces. The methods used for reducing liquid particles in a gaseous stream are: a) Reduction of velocity of the gas; this enables the droplets to settle out by gravity. Gravity can act to remove larger droplets (d>250 microns). Into vertical separators the mechanism for particle separation from a gas stream is governed by the drag force generated by the relative motion between particle and surrounding fluid. The drag force F is directly proportional to droplet diameter, gas density and to the settling velocity. A particle falling will accelerate until the drag force balances the gravitational forces. Thereafter, the particle falls at constant velocity called “settling velocity”. Gravity settling : Liquid droplets will settle out from gas phase if the gravitational force acting on the droplet is greater than drag force of the gas flowing around the droplets.

b) Impingement of the droplets on special devices. Impingement separation allows particles to strike some type of surface in order to be removed. Separation depends primarily on the coalescing of droplets on an impingement surface, from which the enlarged droplets fall when the gravity force upon them exceeds the combined forces of vapour momentum and interfacial tension. Coalescing: Very small droplets such as fog or mist cannot be separated practically by gravity. These droplets can be coalesced to form larger droplets that will be settled by gravity. Coalescing devices in separator force gas to follow a tortuous path. The momentum of the droplets causes them to collide with other droplets or the coalescing medium forming larger droplets. These larger droplets can than settle out of the gas phase by gravity. Wire mesh screens and filter cartridges are typical examples of coalescing devices. Momentum: Fluid phases with different densities will have different momentum which corresponds to mass x time x velocity. If a two phase system changes direction sharply, greater momentum will not allow the particles of heavier phase to turn as rapidly as the lighter fluid.

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Some types of internals are used, such as: • •

Straightening vanes (see Figure 3) Mist pad (See Figure 2)

Typical impingement separators internals are represented in Figure1 Vane elements have a 97 to 99% efficiency for removal of liquid particles. The pad serves as the impingement surface for liquid separation and removes particles down to 5 µm. A typical wire-mesh mist eliminator is constructed from 0.0 11 inches wire at a density of 144 ³ kg/m . Such a mist pad can collect entrained mist and spray from a gas stream at 99% efficiency or better for droplets diameters larger than 6 microns. The term “mist” designates droplets diameters less than 10 microns. Spray refers to droplets greater than 10 microns. The mechanisms of interception and inertial impact a re the most important ones for the two types of separators previously named.

Interception occurs, in general, with droplets approximately the same dimensions as the target or larger. For example, a wire filament 0.011 inch (280 microns diameter) intercepts droplets roughly 280 microns or larger. Inertial impact occurs when a gas is forced to change direction around an object. The inertia of a droplet causes it to continue in the same direction. Collision with the object then causes the droplet to collect on the object’s surface. Inertial impacting is clearly the predominant mechanism of droplet capture for a wire-mesh mist eliminator.

Separators Internals

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Figure 2 - Typical Mist Pad Separator Figure3 - Typical vane separator

Stabilization of condensate is an attractive proposition for certain types of feed composition. Components Methane Ethane Propane Butane Pentane Hexane Plus

Before Stabilization, mole%

Stabilizer Bottoms, mole%

25 10 24 18 11 12

0.2 41.7 27.6 30.5

Stabilizer Overhead, mole% 42.7 14.8 41.5 1.0 -

Table 1 - Components in natural gasoline before and after stabilization

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Table reports a typical composition of a c ondensate before and after stabilization. The removal of the methane, ethane, and propane from the stream and the reduction of butane content increases the production of sales gas, as shown in the table In addition, stabilization reduces the vapour pressure of the finished condensate and makes it suitable for storage, blending and transportation purposes. Moreover, it sweetens the raw liquids entering the plant by removing the hydrogen sulphide and carbon dioxide contents.

Stabilization of condensate streams can be accomplished through either flash vaporization or fractionation.

Flash Vaporization. Many gas plants stabilize the recovered condensate by flash vaporization or simply by flashing. This process is based on the equilibrium principles between the vapour and liquid. Equilibrium vaporization occurs when the vapour and liquid phases are in equilibrium at the final temperature and pressure of separation. In practice, the liquid, with some gas in solution, flows i nto the constant pressure flash tanks and methane and ethane are released.

Stabilization by fractionation is a detailed process, very popular in the industry and precise enough to produce liquids of suitable vapour pressure. During the operation, the methaneethane-propane and most of the butanes are removed and recovered. The finished product from the bottom of the column is composed mainly of pentanes and heavier hydrocarbons, with small amounts of butane. The process actually makes a “cut” between the lightest liquid component (pentane) and the heaviest gas (butane). The bottom product is thus a liquid free of all gaseous components able to be stored safely at atmospheric pressure. Stabilization by fractionation is a modern operation and economically attractive next to flash vaporization. It is a single tower process since only one specification product is required. in Fig.4 the raw condensate from the inlet separator and other sources flows to the feed drum where its pressure is drastically lowered to a level depending on the grade of gasoline desired.

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Figure 4 - Common Stabilizer System

In the feed (flash) drum, the water carried in from the field, is dropped out and collected in the water leg in the bottom of the tank. When the level is high it is withdrawn, on level control, to suitable locations. The pressure-temperature conditions in the flash drum vary with the plant design. In the process shown in Fig.4 the pressure is controlled with a back pressure controller (PIC). At this pressure some light ends are vaporized and pass on to the low pressure gas sweetening 0 contactor at about 10 C. Figure 4 reports a typical stabilizer system that is not exactly the system used at Mellitah Plant but similar. The condensate level in the flash drum is controlled by a level controller and is usually recorded on a control room recorder. The condensate leaves the flash drum at about 10ºC, flows through the stabilizer feed bottom heat exchanger where its temperature is increased to 90 to 120ºC. It enters the stabilizer tower next, at the appropriate feed tray depending on the design, and flows downwards mixing with the hot vapours generated in the reboiler. An alternate feed point, as shown in Fig. 4 is also provided to accommodate varying feed compositions. In the stabilizer, the liquid is stripped of the light ends as it flows downwards to the bottom of the tower. It overflows from the bottom tray and runs into a seal chamber in the enlarged lower section of the tower. This section is the reservoir for the reboiler circulating pump. The adjacent pump well provides suction to the finished product pump which forces the gasoline through the heat exchanger, through another cooler, and on to storage. The reboiler pump discharges liquid to the reboiler where part of the liquid is vaporized. The vapour-liquid mixture from the reboiler returns to the stabilizer above t he seal chamber in the bottom of the tower. The reboiled liquid falls into the seal chamber while the ascending vapour is mixed with the descending feed in the tower. The chamber arrangement at the lower section of the stabilizer prevents the loss of suction at the reboiler pump. Also, the level control in the adjacent pump well excludes the possibility of

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blowing hot, high-pressure vapour into the condensate product storage tank. Vapour from the top of the tower is cooled and partially condensed in the stabilizer overhead condenser. The condenser outlet mixture is separated in the reflux accumulator and the liquid is pumped back to the top of the tower as reflux under level control. The overhead vapours from the reflux drum are preheated to prevent f ormation of liquid hydrocarbons and then flow through a back pressure controller to the low-pressure contactor for sweetening. A connection is usually provided to flare the vapour from the accumulator if such a necessity arises. A water drain in the tank is provided to drain any water that may have accumulated there.

Product Characteristics

The tables which follows, contains the quality requirements for the products of Mellitah gas plant, excepting the section for removing the hydrogen sulphide and other contaminants, and consequently the sulphur recovery. So, it may see the sales gas quality specification, stabilized condensate specification, LPG expected composition, and fuel off-gas from deethanizer.

Sales Gas Specification

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Stabilized Condensate Specification

LPG Specification C3 + C4: ≥ 99.0% mol C2-: ≤ 0.5% mol

Table LPG Expected Composition

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Fuel Off-Gas Deethanizer

Specification C3+: ≤ 7.5% mol

Table

Fuel Off-gas Deethanizer Expected Composition

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Products Conditions

In the following, have to show the contents and the objects of the three c hapter that deals with the processes of condensate stabilization, gas hydrocarbons dew point control and NGL fractionation.

The Chapter 1 presents Unit 210 – Condensate Stabilization, Off -gas Compression and the Off-specs. Storage . The above mentioned unit consists of two parallel trains, unit 51-210 and 52-210, plus common facilities unit 50-210, for Off-gas Compression and offspecs.storage. The Off-gas Compression unit has three independent lines, each equipped with compressor, driver, drums, exchangers, piping and instrumentation-control systems. During normal operations one compression is in running while two are in stand-by mode. A second train will be started when receiving gas from Bouri platform. There are presented the technical characteristics and the functionality details for the main equipments of the Unit 210 and for the gas compressor auxiliaries (scrubbers / K.O. drum, inter-coolers and after-coolers). It is explained the role and functionality of the Off-specs Condensate Storage Tank. The process variable are described pointing out the main process variable of the Stabilizer and for off-gas Compressors, follow by the Control system with its components: Control loops. So it may see the Condensate from pipeline to surge drum flow control, Condensate Cooling Control, Stabilizer reboiler temperature control, Stabilizer feed bottom exchanger flow and temperature Control, Off-gas Compressor capacity Control. In the final part of the Chapter 1 are provided the procedures for Start-up (restart after first st start-up or after general plant shut down) of the 1 condensate stabilization train and of the off-gas compression system as well as are provided the procedures for shut down of entire unit 210. Common troubleshooting are presented finally by short. The Chapter 2 is dedicated to Gas Hydrocarbons Dew Point Control – Unit 340 which is designed to separate the heavier condensable hydrocarbons from the dry gas arriving from Unit 311( Gas Drying Unit), in order to avoid further condensation in the sales gas pipelines. Three parallel trains, each designed for 33.3 % of the total capacity forms unit 340. Taking in account the specific technologies of this unit, the training manual follows the same pattern like in the previous chapter of this work.

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In the general overview, at the beginning of the chapter, some theoretical considerations about hydrocarbons dew point and a diagram P-T for dew point are provided to the trainees in order to facilitate the understanding of this term. Are explained in same time t he scope of this plant for reducing the condensable hydrocarbons, condensation of the liquid creates major problems in export pipeline, in metering, in safely operating of equipments. Small amount of water or condensate can reduce the efficiency of gas transportation lines, cause corrosion, forms hydrates, liquid slugs, could damage compressors, can cause serious safety hazards. This determines the gas transportation and distribution companies to request rigorously dew point analysis. 0 The condensation curves of a natural gas separated at 0 C and 70 bar g , with cricondenbar and cricondentherm points allows to know with certain accuracy the temperature of condensation at the various pressure or to find the pressure at which the condensation temperature is highest (cricondentherm). It is known that heavier hydrocarbons even in minimal percentages influenced dew point temperature. Are overviewed the main procedures for obtaining the lower dew point: LTS( Low Temperature Separation, the Joule-Thompson effect to refrigerate the gas); Absorption by glycol (when only water dew point has to be controlled); Dry bed adsorption ( simultaneously removing of water and heavier hydrocarbons); Mechanical refrigeration ( often using mechanical propane refrigeration plant with glycol injection); Turbo-expansion (Cryogenic plant) – the simultaneous expansion and refrigeration of the gas stream by means of the a turbo-expander permits to condense all the condensable hydrocarbons. 0 Refrigeration systems using propane can be apply to chill gas t o - 40 C. Before accomplish a description of the Gas Point Control using propane refrigeration are gave the characteristics and properties of the propane. The Propane Refrigeration Unit existing in Gas Dew Point Control Unit 210, consists of a closed loop in which the propane is flashed in 2 steps, vaporized, recompressed and condensed. The first flash step is the economizer system, which split t he main stream in to a liquid phase (used to refrigerate second flash step) and a gas phase that is routed to the Refrigeration Compressors. Description of the package of unit 51-340-XX-001(Propane Refrigeration Unit) is together with the corresponding process flow diagram. Description of the process which takes place in the Unit 340 is completed with useful details and technical characteristics of the main e quipments. The main process variable as the temperature of chilled gas that is controlled in cascade with level of evaporating propane in propane chiller is presented t ogether sales gas analysis, which depends directly by the temperature of the chilled gas. At the end of chapter 2 are includes the recommended operations for start-up and shut-down of the unit taking in account the interconnections with another plants on Mellitah platform. Finally are mentioned some troubleshooting possible to arise while running the plant.

The Chapter 3 entitled NGL Fractionation – Unit 320 , treats the process of separation from the condensate of Unit 340 the LPG (Liquefied Petroleum Gas) and the NGL (Natural Ga s Liquid). NGL is sent to storage while LPG is sent to Wafa Coastal Unit C3/C4 Splitter. At beginning in this chapter are reviewed the general notion about fractionation principle and equipment used. The Unit 320 has two identical parallel trains, the NGL Fractionation is de signed for a 50% turndown referred to the design case, as shows in G eneral Process Description.

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The plant comprises two essential sections: Deethanization and Debutanization where takes place the splitting of the NGL coming from Gas HC Dew Point Control Unit 340 mainly in valuables fraction LPG and C5+. Are described in details the technological streams pointed out the major variation of the parameters with its consequences. Main equipment existing in the plant are presented detailed together their construction types and their operating parameters. Complete operating parameters together Process Flow Diagram of the Unit 320 are gave in the paragraphs referring to Detailed Process Description. The main process variables as: the reflux rate, the reboiler heat input, the fractionator pressure, the feed rate and temperature are commented focusing directly to the both section: deethanizer and debutanizer being follow by apllicated control system in these cases. The final part of the Chapter 3 contains the start-up and shut down procedures of the NGL Fractionation unit and a detailed paragraph concerning to common troubleshooting.

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1. CONDENSATE STABILIZATION & OFF-GAS COMPRESSION

- UNIT 210

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1.1 General

Raw gas and unstabilised condensate, coming from Sabratha Platform by means of two different submarine pipelines, are received and sent to the treatments facilities. Condensate is sent to two identical condensate stabilization units. The produced stabilized condensate is delivered to the storage, while the off-gas also produced at the stabilization unit is joined with the raw gas stream coming from pipeline. The gas from the pipeline, jointly with the off-gas, is sent to three identical gas treatments trains. Each of them is composed by a sweetening unit, a dehydration unit and a hydrocarbon dew point control unit. In the sweetening unit, the CO 2 and H2S contained in the gas are completely removed and sent to SRU where H2S is converted to liquid sulphur. The sweetened gas is sent to a molecular sieves dehydration unit, where water is removed, and then to hydrocarbon dew point control, where, by means of external refrigeration, heavy HC are condensed and separated in order to match the sales gas characteristics. The recovered NGL from the dew point control unit is sent to two identical NGL fractionation units. More light components (C1, C2) are stripped out from NGL and sent to the fuel gas network. The liquid is then splitted into a LPG stream that is routed to WAFA Coastal Plant for C3/C4 production, and into a C5+ cut which is sent to storage.

1.2 - Unit 210 - Condensate Stabilization, Off- gas Compression and Off-Specs Storage

The Unit 210 is composed of the following sections: • Condensate Stabilization Surge Drum and Feed Pumps. • Stabilizer Feed/Bottom Exchangers. • Stabilizer. • Off-gas Compression • Off Spec Tank.

The Condensate Stabilization Unit consists of two parallel identical trains, Units 51-210 and 52-210, plus common facilities Unit 50-210, for Off gas Compression and Off -Specs storage. The Off-gas Compression unit arrangement is on three independent lines, each equipped with compressor, driver, drums, exchangers, piping and instrumentation/control system. During normal operations one compression is running while two are in “stand-by mode”. A

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second train is started when receiving gas from Bouri Platform Facilities to operate a partial unit by-pass are available. On this occasion part of the condensate is sent to Off- spec storage, under level c ontrol, while the balance of condensate is treated in the unit and consequently directed to product storage facilities from the stabilizer bottom. In case stabilizer column is in shut-down, but the surge drum is operating, condensate is passed through the vessel, as a first degassing stage (with vapour recovery) and then routed to tank for atmospheric flash. Only in case the Surge Drum is also out of service the condensate from pipeline and Slug Catcher will be diverted to Off-Spec Tank. Motorized valves are provided to operate the above mentioned deviation and the DCS is equipped with facilities to switch the Surge Drum level control to the relative valve on the line to off spec storage. In case of off-spec condensate detection, it can be diverted to the Off- Specs Condensate and stored for reprocessing. In this case, motorized valves are able to operate diversion downstream the level control valve. In case of an emergency occurring onshore, whereby unstabilized condensate is not possible to be processed in any of the Condensate stabilization units, the feed from the pipeline can be directed to Off-Spec storage. If such an emergency lasts for more than 12 hours the Marine Platform has to be shut down too. The following description is relevant to Units 50-210 (common facilities) and Unit 51-210 (same description of 51-210 is applicable also for Unit 52-210).

1.2.1 - Main Equipments.

Degassing Boot Condensate Surge Stabilizer Column Stabilizer Feed/Bottom Exchangers Condensate Trim Cooler Stabilizer Reboilers Off-specs. Condensate Pumps Off-specs. Condensate Tank

50-210-VA-004 50-210-VA-001 51-210-VE-001 51-210-HA-001 51-210-HA-003 51-210-HA-002 51-210-PH-001A/B 50-210-TA-001

Inside the Degassing Boot 50-210-VA-004 the condensate is flashed to LP Flare pressure (about 1.4 bara) in order to eliminate most of the light hydrocarbons, which may be cause of fixed roof damaging in case of direct flash in t he tank. The Degassing Boot is a vertical vessel measuring 1400 mm dia. and about 9100 mm height. It operates at about 1.4 bara. Condensate Surge Drum 51-210-VA-001 - operates at a temperature of about 29°C and at a pressure of about 8.5 barg. Overall dimensions of the Surge Drum are 3000 mm di a. and 9000 mm length, with the boot of 800 mm dia. and 900 mm height.

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Condensate stabilization column

The stabilizer tower is a vertical vessel designed to provide the necessary space, time, and means for the countercurrent contact between the ascending vapor and descending liquids. A typical stabilizer tower is shown in Figure 1.1 The column is divided into two sections, the top or the rectifying section, which includes all the trays above the feed tray; and the lower or stripping section, which contains all the trays below the feed. In some cases the stripping section is enlarged to accommodate the reboiler pump well and provide a surge space f or the bottom product pumps. The stabilizer can be a "packed tower", packed with a specific design of packing material or tray design using bubble cap, valve, or sieve trays. Tray types are a more common design, built with up to 40 trays in some units. Spacing of the trays depends on the design and height of the unit, but 45 cm to 50 cm distance is considered common. The Stabilizer Column 51-210-VE-001 operates at a temperature varying from about 32°C (top) to 155°C (bottom) and at a pressure of about 5.5 barg. Overall dimensions of the Stabilizer are 900 x 2000 mm dia. and 20,830 mm height. Stabilizer Reboiler 51-210-HA-002 feed is foreseen at 112°C/5.8 barg, outlet 155°C/5.8 barg.

Figure 1.1 - Condensate Stabilizer Tower

Stabilizer Feed /Bottom Exchangers 51-210-HA-001 is of the shell-and-tube type, with the stabilized condensate flowing through the shell side and the unstabilized condensate gas flowing through the tube side. The inlet temperature of the unstabilized condensate is 23.6°C and the pressure 18 barg, while outlet temperature will be 68°C and the pressure 17.6 barg. For the treated condensate is foreseen an inlet temperature of 155°C and a pressure of 5.8 barg, while at the outlet the temperature will be 125°C and the pressure 5.3 barg.

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Condensate Trim Cooler 51-210-HA-003 is of the shell-and-tube type, with the stabilized condensate flowing through the shell side and the cooling water flowing through the tube side. The inlet temperature of the unstabilized condensate is 55°C and the pressure 4.8 barg, while outlet temperature will be 40°C and the pressure 4.1 barg. For the cooling water the temperatures are 32/44°C

Figure 1.2 - Common type shell and tube exchanger

Stabilizer Reboilers 51-210-HA-002 is a shell-and-tube type Kettle reboiler. The internal diameter is 1.35 m, the length is 4.8 m . The reboiler service is to supply the additional heat to stabilizer by means of the MP steam condensation. The hydrocarbon flowing through the shell (114990 kg/h), is heated up from 112°C to 155°C, at a pressure of about 5.8 barg, while the MP steam, flowing through the tubes (11200 kg/h), is condensed and cooled down from 235°C to 165°C.

Figure 1.3 - Steam reboiler Kettle type

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Off-specs Condensate Pumps 50-210-PH-001A/B are vertical centrifugal pumps, electric 3

motor driven with a rated capacity of 39 m /h and a head of 16 barg.

Figure 1.4 - Typical vertical pump

Off-Specs Condensate Tank 50-210-TA-001 has a working capacity of 2280m3, a diameter of 15m and a height of 14.4.m. The tank is provided with three vacuum relief valves, with level and pressure indicators, level transmitter, breathing valve, venting control valve on a 8" line towards low-low pressure flare (fail closed type), It is blanketed with fuel gas to prevent entering of air. Two blanketing control valves of the fail open type on a 3" line bringing fuel gas to the tank will ensure a working pressure range from a minimum of –20 mm H2O to a maximum of 4000 mm H2O. Besides three sampling lines, at different height, and local temperature indicators are provided also fire fighting facilities.

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Figure 1.5 - Typical fixed roof tank with instrumentation

1.2.2 - Off – gas Compression Train The three off gas compression trains are shown in Figure 1.7 . Each train contains all the elements described previously as typical for the compression trains. Considering the A train, its components are reported hereafter:

1.2.2.1 - Main equipments of the Off-gas Compression Train : First stage K.O. Drum Off-gas compressor first stage First stage discharge cooler First stage discharge drum

50-210-VA-001 50-210-KB-001A 50-210-HC-001A 50-210-VA-002A

Off-gas compressor second stage Second stage discharge cooler Second stage discharge drum

50-210-KB-002A 50-210-HA-001A 50-210-VA-003A

50-210-VA001A First stage KO Drum: is an inlet separator/scrubber, 2.1 m3 capacity operating at a pressure of 4.5 bar and a temperature of about 37 °C. The overall dimensions are 0.9 m diameter and 3 m height. It is provided with gas inlet distributor, wire mesh

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demister and vortex breaker. 50-210-KB001A Off gas compressor first stage: is the first stage of a reciprocating compressor, electrical motor driven, which duty is to compress 6940 Nm3/h gas from 4.5 bar to 15 bar. The absorbed power for both stages is about 700 KW. The estimated compressibility factor is about 0.947. 50-210-HC001A First stage discharge cooler: is an intercooler (air cooled), type, 0.22 MW capacity, operating at a pressure of 15 bar and a temperature of about 102 °C (hot side). Air temperature considered to be 55° C. The cooler is provided with two fans, electric motor driven. One motor is single speed the ot her is double speed type. 50-210-VA002A First stage discharge drum: is a separator/scrubber, 1.2 m3 capacity operating at a pressure of 14.5 bar and a temperature of about 55 °C. The overall dimensions are 0.7 m diameter and 3 m height. It is provided with gas inlet distributor, wire mesh demister and vortex breaker. 50-210-KB002A Off gas compressor second stage: is the second stage of a reciprocating compressor, electrical motor driven, which duty is to compress 6940 Nm3/h gas from 15 bar to 44 bar. The estimated compressibility factor is about 0.917. 50-210-HA001A Second stage discharge cooler: is an aftercooler (water cooled), shell and tube type, 0.53 MW capacity, operating at a pressure of 44 bar and a temperature of about 133°C (hot side) and 4bar and 32°C (cold side). 50-210-VA003A Second stage discharge Drum: is a separator/scrubber, 1 m3 capacity operating at a pressure of 43.5 bar and a temperature of about 50°C. The overall dimensions are 0.6m diameter and 3.5m height. It is provided with gas inlet distributor, wire mesh demister and vortex breaker. The oldest, and probably the best known, of t he positive displacement machines is the reciprocating compressor that is the type used to compress the off-gas. It is a highly flexible machine, being readily adaptable to ratio changes and capacity changes within wide limits for any one particular machine. This machine works like a positive displacement pump. A piston is drawn back in the cylinder and the cylinder is filled with gas; then the piston is moved forward and the gas is forced out. The cylinder must be equipped with intake and discharge valves to control the flow of gas entering and leaving. Reciprocating compressors can be used on wide ratios of compression. In gas work they will normally be found operating from 1.1 - 1 to 5 - 1. They have a relatively high efficiency (72% in our case), the major efficiency loss being the pressure loss through the valves. As ratios increase this valve loss has less and less effect on efficiency. With the single-acting type, compression takes place at one end of the cylinder only; therefore, there is only one compression stroke for every crankshaft or flywheel revolution. With the double-acting type, compression takes place alternately at both ends of the cylinder, and therefore there are two compression strokes per revolution. A “two stage” compressor is illustrated in Figure 1.6

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Figure 1.6 - Two- stage Compressor

1.2.2.2 - Gas Compressor Auxiliaries Scrubbers / KO Drums

Before the flow stream from the pipeline is compressed to a higher pressure, it enters into vessels commonly called "scrubbers" or “KO drums”. These are located in close proximity to the compressors on the suction or intake header. The purpose of the scrubber is to remove all free liquids and any suspended solid from the gas stream. These liquids may be crude oil, hydrocarbon condensate, water, lubricating oil, drilling mud, acid and pipeline dirt. This material is displaced from low places in the gathering system or it may be entrained with the gas. The scrubber must have adequate storage and discharge capacity to accommodate large volumes of liquid. The scrubbers are usually equipped with mist extractors particularly on the high pressure stages, or they may contain just an angle baffle or wear plate below the gas entrance. In addition to this equipment, the scrubber is generally equipped with a liquid-level control and an automatic dump valve. Simultaneously

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with the functioning of this valve an automatic alarm is given. In the event of a further rise in level, an automatic shut-off will shut down the compressors. The liquid or condensate in the scrubber may be disposed off in several ways: a) Blown from it to the desired vessel or other location, if under pressure. b) Pumped from it. The back pressure valve is a valve used to prevent excessive pressure. If the pressure exceeds design, the back pressure valve opens to flare so the compressor will not be overloaded. If the pressure falls too low, the back pressure valve does not function. In such cases, a compressor may be removed from service. Back pressure regulators in the field are also used to maintain constant back pressure. They act similarly to a relief valve. That is, if the pressure becomes too great, the regulators release gas to the downstream side. Some systems are not even equipped with regulators between the well and the plant. The absence of regulators can only be tolerated, however, when connections are provided directly to the well and not to the separator. From the scrubber, the charge flows into the header. The header is simply a pipe, generally laid in horizontal position, from which extend a number of outlets or outlet pipes. The size of the intake header at some installations has been observed to be as large as 1 m. In travelling through the header, the gas may flow through the center outlet; it may flow through endoutlets, or it may flow through all of these on its entry into the compressor. The main objective in appropriately routing the flow of gas through the header is to insure the delivery of fairly equal quantities of the gas to each compressor. Intercoolers and Aftercoolers These are usually shell and tube type heat exchangers and may be arranged to have water flowing through the tubes and gas passing over the tubes or they may be arranged with gas flowing through water surrounded tubes. Intercooling involves cooling the gas between stages of compression, to reduce temperature, to reduce the volume to be compressed in the succeeding stage, to liquefy condensable vapours and to save power. An aftercooler is the heat exchanger on the discharge of the compressor following the completion of compression.

The reasons for cooling the gas are as follows: a) To remove water vapour and oil vapour from the stream between compression stages and after the last stage. When the gas is cooled, the water and oil vapours will condense and may then be drained from the bottom of the coolers. If the oil vapour is not condensed and removed, it will have a detrimental effect on the transmission efficiency. If water vapour is not removed from the gas, then it may collect in pipelines and cause hydrates or damage from freezing. b) In the case of an intercooler, another purpose is to decrease the amount of power required to compress the gas. Iso-cooling or cooling between stages, is most efficient when gas temperatures within the compressor approach 200°C. In fact, the use of an intercooler between stages of compression will reduce the power required for compression by 15%. For this same reason, in addition to using intercoolers, compressors are usually water jacketed in 28


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order to aid in removing the heat of compression and so approach isothermal compression. c) Other purposes in reducing the gas temperature by means of coolers are: to make cylinder lubrication more effective, to reduce weakening of parts due to high temperatures, and to reduce the possibility of explosions of oil vapour mixed with air. Intercoolers and aftercoolers may be either air-cooled or water-cooled. The air-cooled type is normally used when the compressor itself is air-cooled and it consists of a finned pipe through which the compressed gas passes. The water-cooled type, as mentioned previously, is of shell and tube construction with either the cooling water passing through tubes, or the compressed gas passing through watersurrounded tubes. Intercoolers should be provided with a safety valve, pressure gages and thermometers on the compressed gas side and also thermometers on the cooling water side. Fig. 1.8 shows an aftercooler in which the compressed gas flows through the tubes and the cooling water flows around the tubes. The usual direction of water flow is counter or opposite to the gas flow, so cooling water would enter at the bottom of the aftercooler and exit at the top. As the gas discharges from the aftercooler, it passes through a separator, where moisture and other particles are removed from the stream. Aftercoolers, like intercoolers, are fitted with pressure gages and thermometers and, if there is a shutoff valve between the aftercooler and the receiver, the aftercooler must also be fitted with a safety valve. Aftercoolers should always be equipped with separators which should be installed as close to the aftercooler as possible.

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Figure 1.7 - Off-gas compression train

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Figure 1.8 – After-cooler

Figure 1.9 - Vertical Scrubber

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1.3 - Condensate Stabilization & Off-gas compression – Process description The feed of Unit 51-210 is collected into the Condensate Surge Drum 51-210-VA-001 , which receives a combined stream formed by condensates from: • Condensate pipeline • Slug Catcher 50-190-VQ-001 and KO Drums 50-190-VA-001/002 st

nd

• Off gas Compressor 1 and 2 stage Discharge Drums 50-210-VA002A/B and 50-210-VA-003A/B • Condensates from Unit 330 – Gas Sweetening • Off Specs Condensate from Off-Specs Condensate Pump 50-210-PA-001 Each one of these streams is split upstream of the Surge Drums so that each train is fed with required flow rates. The ways to perform the splitting are described below: • the condensate from pipeline is split into two streams, each one with a separate flow controller placed at the inlet of the surge drum; upstream the splitting, on the combined feed, a pressure controller gives the set point to the flow controllers. The ratio of the two flow rates is adjustable by a hand Bias function. High level in the surge drum will act limiting the set point of the flow controller; • the condensate from the Slug Catcher boot is controlled by means of two flow controllers. • the condensates from Off gas Compression and from Unit 330, being small in quantity, are sent to either train 1 or 2; • the Off Specs Condensate from Off gas Condensate Pump 50-210-PA-001, being an intermittent flow rate, is sent either to train 1 or 2. Motorized valves are provided to operate selection.

The Condensate Surge Drum is equipped with a water disengaging pot. The separated wa ter is collected into the pot and sent to waste water treatment or to sour water stripper under interface level control. The separated gas is sent to Off gas Compression under pressure control. The condensate from the Surge Drum is sent by the Condensate Feed Pump to the Condensate Filter, in order to remove any fines particles carried from the pipeline. On pump discharge a connection is provided to route the condensate to the Degassing Boot and Off Specs Condensate Tank. The design intention is that, in case stabilizer column is in shut down, but the surge drum is operating, condensate is passed through the vessel, as a first degassing stage (with vapour recovery) and then routed to tank for atmospheric flash. Only in case the Surge Drum is also out of service the condensate from pipeline and Slug

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Catcher will be diverted to Off Spec Tank. Motorized valves are provided to operate the above described diversions and facilities are provided in DCS to switch the Surge Drum level control to the valve on the line to off spec storage. Downstream the Condensate Filter, the stabilizer feed is split in two streams: the first stream is preheated in the Stabilizer Feed/Bottom Exchanger and fed to an intermediate tray of the Stabilizer column, and the second stream is sent to the top tray of the Stabilizer. The reason of the double column feed is to provide, without need of creating a reflux stream, a rectifying section in the column. Overhead vapours leave the column under pressure control and are sent, after joining with gas separated in the Surge Drum, to Off Gas Compression. The heat to the Stabilizer Column is supplied by medium pressure steam through a Stabilizer Reboiler, kettle type. The Stabilized Condensate is sent to storage from the stabilizer bottom under level control after having been cooled down in the following exchangers: • Stabilizer Feed/Bottom Exchanger • Condensate Air Cooler Analyser is provided at the line to storage to check product quality. In case of detection of off-spec condensate, it can be diverted to the Off Specs Condensate and stored for reprocessing. In this case, motorized valves are provided to operate diversion downstream level control valve. Facilities to operate a partial unit bypass are also provided. In this situation part of the condensate is sent to Off Spec storage under a partialised level control signal from Surge Drum, meanwhile the balance of condensate is treated in the unit and sent to product storage from stabilizer bottom.

1.3.1 - Off gas Compression The Off gas Compression unit is formed by three independent lines, each one complete with compressors, drivers, drums, exchangers, piping and instrumentation/control system. During normal operations one compression train is operating and two are in stand-by mode. A second train is started while receiving gas from Bouri Platform The Off Gas Compressors are two stage reciprocating compressors. The Off gas from the Stabilizer Overhead, together with the Condensate Surge Drum Off gas (Trains 1 and 2) is st

sent to the Off gas Compressor 1 Stage KO Drum (Trains A, B and C). The Liquid separated in the drum (not normally expected) is sent to closed drain. st

The Off gas from the K.O. Drum enters the Off gas Compressor 1 Stage. At its outlet it is st

cooled in the Off gas compressor 1 Stage Discharge Cooler and sent to the Off gas st

Compressor 1 Stage Discharge Drum. The Condensate separated in the drum is sent to the Condensate Surge Drums. st

The Off gas from the 1 Stage Discharge Drum feeds the Off gas Compressor 2 nd

nd

Stage. At its

outlet it is cooled in the Off gas Compressor 2 Stage Discharge Cooler (water cooled) and

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Contractor Doc. No.: nd

sent to the Off gas Compressor 2 Stage Discharge Drum. The condensate separated in the drum is sent to the Condensate Surge Drums. This Off gas is sent to Unit 190 for further processing together with raw gas. The compressor control system includes: st

• 1 stage Suction pressure control, acting on compressor valve unloader and on recycle bypass control valve • Discharge high pressure control, operating on vent valves to LF fla re.

1.3.2 - Off - Specs Storage

An Off-Specs Condensate Storage Tank 50-210-TA-001 is provided to serve the following purposes: • to store the Unstabilized Condensate received from platform when one of the two Trains is out of order for maintenance • to store the Off Specs Condensate from Condensate Stabilization (Unit 210) or from NGL Fractionation (Unit 320). • to collect recovered hydrocarbons from closed drains The condensate diverted to Off-specs storage first enters a Degassing Boot 50-210-VA-004 in which the condensate is flashed to LLP flare pressure (about 1.4 bara) in order to eliminate most of the light hydrocarbons, which may be cause of fixed roof damaging in case of direct flash in the tank because of a sudden high pressure. The vapours from tank are sent to the LLP flare KO Drum through a dedicated line in order to have minimum back pressure in the tank. The degassed condensate flows to the Off-Specs Condensate Tank 50-210-TA-001. One Off-Specs Condensate Pump is used to deliver condensate to the desired train (51-210 or 52-210) for processing and/or reprocessing. In case of an emergency occurring onshore, so unstabilized condensate is not possible to be processed in any of the Condensate stabilization units, the feed from the pipeline can be diverted to Off-Spec storage. In case of longer than 12 hours of such emergency, the platform will also have to shut down. The condensate pipeline design allows for a sudden closure at onshore plant inlet. However, this should be avoided if possible. Here below closure sequence will be followed as an operating procedure: • throttling the condensate flow from the pipeline to 10-15% of design flow (and send an alarm to platform for information)

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• stabilization during a few minutes (approx. 5 minimum) • complete closure of the condensate flow Such a sequence allows shut down without any water-hammer in the pipeline, resulting in improved safety and could be implemented in case of shut down for process upset. Emergency shut down, as in case of fire, will be dealt by ESD with an immediate valve closure.

1.4 - Routine Operating Procedures Normal operation is defined as the operation of the plant under steady state conditions. However, under the heading "normal operation" certain process adjustments are required to meet variations in feed, temperature, pressure, component content. Remember that the everyday activity in the control room is supported by an amount of information produced by DCS, by laboratory and last but not lea st by various reports from the field inspection.

1.4.1 - Process Variables

Efficient fractionation will depend on one or more of the following factors: top (overhead) temperature, tower bottom temperature, the tower operating pressure, the components present in the tower feed, rate of reflux and temperature of tower feed. - Top Temperature

The top temperature of a fractionator is the temperature of the liquid on the top tray. It is the dew point temperature of the overhead product and depends on the composition of the overhead product(s). The top temperature is the lowest temperature in the tower and is limited by the amount of cooling that can be accomplished by the reflux. The top temperature is an indication of the overhead product quality and composition. A change in top temperature is also an indication of a change in tower feed. The top temperature is set just high enough to completely vaporize the overhead product. If the top temperature is controlled too low, there will be a loss of recovered overhead product.

- Tower Bottom Temperature

The bottom temperature is controlled to maintain the quality of the bottom product. If the bottom product contains too much overhead product, the bottom temperature is raised. Raising the bottom temperature will cause more heating fluid to flow through the reboiler and

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increase the expense of operating the unit. The bottom temperature of the tower should be maintained at the lowest point that produces a bottom product of acceptable quality. - Tower Pressure

The ease with which the overhead and bottom product can be separated in the fractionator depends on the relative vapour pressure of the two streams. The relative vapour pressure is determined by: Relative vapour pressure = vapour pressure of top product / vapour pressure of bottom product.

The higher the relative vapour pressure, the easier it is to fractionate the two streams. The relative vapour pressure of liquid hydrocarbons is greater at low temperatures. The operating pressure of the fractionator is determined by the vapour pressure of the overhead product at its condensing temperature. Suppose the reflux temperature is limited t o a maximum of 40ºC by the condensing water temperature. If, for example, the overhead product is propane, its vapour pressure will be f ound to be approximately 1260 kPa(g) at 40ºC. The minimum operating pressure of the fractionator must be 1260 kPa(g), because below that pressure the overhead propane product will not condense. For economical, effective operation a fractionator should operate at the lowest possible pressure. When the tower pressure is changed, the top and bottom temperatures must also be changed. If the pressure is increased, both temperatures must be increased to m aintain the quality of the overhead and bottom products. If the tower pressure is lowered, then both temperatures must be lowered. It may be necessary to operate the fractionator at a higher pressure to maintain high flow rates.

Figure 1.10 - Reflux Condenser Water Control

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- Components in the Feed

The quality of the feed to the tower determines the quality of the overhead and bottom products. For example, if it is desired t o split a mixture of propane and butane into two finished products and the feed contains appreciable amounts of ethane, the propane product will not meet the specifications.

-

Rate of Reflux

Whenever reflux is increased to the tower, the heat input must also be increased. It logically follows that the reflux rate should be as low as possible while maintaining the quality of both the overhead and bottom products. The procedure for determining the minimum reflux flow is to lower the reflux flow until either the overhead or bottom product quality just meets the specifications. After the minimum reflux rate is determined, the reflux ratio should be calculated as follows: Reflux ratio = reflux flow rate / overhead product flow rate

The reflux ratio will be different for each fractionator, but generally it will be between two and four. If the overhead product flow changes, the reflux rate must also be changed to maintain the product quality and efficient tower operation. This may be changed manually by the operator or accomplished by automatic controls. - Temperature of Tower Feed

The feed stream to the tower should be partly vaporized. If the feed contains 40% overhead product, then 40% of the feed should be vaporized by the heat contained in the feed. The operator has no way of knowing what percent of the feed is vaporized, so the feed temperature should be controlled at the same temperature as the temperature on the tray where the feed is entering. If the temperature of the feed cannot be changed, then the feed should enter the tower where the temperature is the same or close to the feed temperature. If the feed temperature is too high, extra vaporizing will occur and the top of the tower will be overloaded. 1.4.1.1 - Stabilizer main process variables : - Tray 14 -Temperature set at 100°C by temperature controller 51-210-TIC-0176 in cascade with 51-210-FIC-009 that controls the steam flow to Stabilizer Reboiler 51210-HA-002. An increase of this temperature, without changing other parameters, results in higher vapour rate through the Tray and a transfer of heavy component from the bottom to the top of the column. The main effect is decreasing the stabilised bottom flow and a major off-gas flow; on the contrary lowering this temperature light component may remain in the bottom liquid of the stabilizer and consequently the product is not stabilised. -

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-

-


Stabilizer bottom pressure set at 5.8 barg by 51-210-PIC-013, operating the pressure valve on stabilizer vapour line. Increasing this pressure light component remain in the bottom liquid of stabilizer and as result the bottom product will increase and it is not stabilised; on the contrary lower pressure allows that some heavy components are transferred to top of stabilizer in this case the off gas will increase and it is out of specification due to heavy component. Stabilizer feed bottom temperature set at 68°C by 51-210-TIC-006, by-passing the Stabilizer Feed/Bottom Exchanger; increasing this temperature increase the vaporisation of feed on Tray 6 and consequently more vapours travels up to top of column and as result off-gas may be out of specification due to heavy component.

Ratio between stabilizer feed to Tray 6 and feed to top Tray is carried out through 51-210HIC-0027; the normal ratio is 4.65. Increasing this ratio more cold condensate is fed to top Tray that means lower top temperature and lower flow rate; meantime the bottom flow rate will increase and therefore the stabilised bottom liquid may result “ out of specification”.

1.4.1.2 - Main process variable of the off gas compression section : st

Pressure on Off Gas Compressor 1 Stage K.O. Drum (50-210-VA-001A) set at 4.5 barg by pressure controller 50-210-PIC-0228 operating on: - master pressure controller - pressure recirculating valve from delivery of 2nd stage - the load of compressor. Increasing this pressure within the range allowed by stabilizer, more gas as final result is nd

recycled to suction from delivery of 2 compressor will be overloaded.

stage; on contrary lowering the suction pressure the nd

Temperature outlet Off Gas Compressor 2 Stage Discharge Cooler (50-210-HA-001A) is set at 50°C by 50-210-TIC-023 that controls the cooling water flow. An increase of the said nd

temperature diminishes the amount of condensate separated in the 2 Stage Discharge Drum 50-210-VA-003A; the contrary effect is obtained decreasing the temperature. Delivery nd

Pressure of 2 Stage Off Gas Compressor is 43.5 bar. st

st

1 Stage Off Gas Compressor Delivery Pressure and Temperature. Delivery Pressure of 1 Stage Off Gas Compressor is 15 bar and the temperature on Off Gas 1st discharge Drum 50st

210VA002A is 50°C due to cooling of gas in the Off Gas 1 discharge Cooler 50210HC001A; this temperature and pressure allow the condensation of part of heavy components.

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Table 1.1 - Main local indicators Variable Flow Flow Pressure Level Flow

Equipment/Service

Instrument tag

Condensate from 50-190VR-002 Condensate from 51-210VA-001 Gas from 51-210-VA-001 51-210-VA-001

51-210-FI-003A

0-150 Sm3 /hr

Normal Op. Value/Set Point 97.6 Sm3 /hr

51-210-PI-305/307

0-20 barg

18.6 barg

50-210-PI-005A/B 51-210-LG-301

0-15 barg 0-100%(1062600 mm)

11 barg 50%(1350 mm)

51-210-FI-006A

0-150 Sm /hr

103.26 Sm /hr

51-210-FI-009A

0-17,000 kg/hr

11,200 kg/hr

51-210-TI-312 51-210-TI-330 51-210-TI-313 50-210-PI-314A/B 50-210-PI-324

0-100 0 C 0-250 0 C 0-180 0 C 0-15 barg 0-6 barg

51-210-LI-013A

0-100%(1062600 mm) 0-50 barg

Level

Condensate from 51-210CL-001A/B MP Steam to 51-210-HA002 51-210-VE-001 51-210-VE-001 51-210-VE-001 50-210-PH-001A/B Off-gas to 50-210-KB001A 50-210-VA-001

Pressure

Off-gas to Header

Flow Temperature Temperature Temperature Pressure Pressure

50-210-PI-318

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Range

3

3

32 0 C 155 0C 94 0 C 12 barg 4.4 barg 50%(1350 mm) 44 barg


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Table 1.2 – Stabilized Condensate Analysis

Analysis

i C4 C4 / C5 i C5 C6 / C7 C7+ Distillation Water Salt Content H2 S RVP Specific Gravity

Method

Frequency

ASTM D 2597 ASTM D 2597 ASTM D 2597 ASTM D 2597 ASTM D 2597 ASTM D 86 UOP 481 ASTM D 3230 UOP 163 ASTM D 323 ASTM D 1298

daily daily daily daily daily daily daily daily daily daily daily

Table1.3Stabilized Overhead Gas Analysis Analysis C1 – C6 C3 i C4 i C5 C7+ H2S Mercaptans Water

Method ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945 UOP 212 or ASTM D 1945 UOP 212 ASTM D 5454

40

Frequency weekly weekly weekly weekly weekly weekly weekly weekly


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1.5 - Control System – Main Process Control Loop of Condensate Stabilization & Off-gas Compression – Unit 210

a) - Condensate from Pipeline to Surge Drum Flow Control

Reference P&ID: G-65-D-O-1021-01 Unit 51-210 – Condensate Stabilization Inlet Common Header G-65-D-O-1021-02 Unit 51-210 – Condensate Stabilization Surge Drum Condensate from 50-190-VR002 is sent to the units 51-210 (condensate surge drum 51-210VA001) and 52-210 (condensate surge drum 52-210-VA001). The 50-160-PIC053 signal feed the set point adjuster 50-160-PY053. The scope of the set point adjuster is to control the ratio between the signals to the two trains and to maintain the total of the two outlets equal to the inlet signal.

Figure 1.11 - Condensate from Pipeline to Surge Drum Flow Control

This means the 100% of 50-160-PIC053 output will be splitted in two signals, but in any case the sum of the two ratio will be 100% (e.g. 50% to unit 51-210 and 50% to unit 52-210, or 60% to unit 51-210 and 40% to unit 52-210 etc.).

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The low signal selector 51-210-FY003A receives the signals from 50-160-PY053 and high level constraint controller 51-210-LIC002 and select the lower one (normally is the pressure signal) and fixes the set point of 51-210-FIC003. The 51-210-FIC003 opens valve 51-210-FV003 when the pressure rises over the SP value and closes valve when pressure falls under SP value. In case the lower signal is coming from 51210-LIC002 (52-210-LIC002), the 51-210-FIC003 opens valve when level is lower than the SP value and closes valve when level is higher than SP value. Activation of interlock 51-210I5007 will drive 51-210-FIC003 to manual mode and output null by 51-210-XS007. b) - Condensate Cooling Control

Reference P&ID: G-65-D-O-1021-03 Unit 51-210 – Condensate Stabilization Stabilizer Feed / Bottom Exchanger The controller 51-210-TIC-011 opens valve 51-210-TV-011 when temperature rises over the SP value and close valve when temperature falls under the SP value.

Figure 1.12 - Condensate cooling control

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c) - Stabilizer Reboiler Temperature Control

Reference P&ID: G-65-D-O-1021-04 Unit 51-210 – Condensate Stabilization Stabilizer Feed/ Bottom Exchanger When temperature rises over 51-210-TIC017 set point, 51-210-TIC017 output signal will decrease the set point of 51-210-FIC009 in order to close valve 51-210-FV009.If the temperature is below the set point, 51-210-TIC017 output signal will increase the set point of 51-210-FIC009 in order to open valve 51-210-FV009. Activation of interlock 51-210-I5005 will cut the air supply to control valve 51-210-FV009 by action on solenoid valve 51-210-FY009A. In the same time and f or same reasons 51-210XS005 drives 51-210-FIC009 to manual mode and output null.

Figure 1.13 - Stabilizer Reboiler Temperature Control

d) - Stabilizer Feed Bottom Exchanger Flow Control and Temperature

Reference P&ID: G-65-D-O-1021-02 Unit 51-210 – Condensate Stabilization Surge Drum G-65-D-O-1021-03, G-65-D-O-1021-04 Unit 51-210 – Condensate Stabilization Stabilizer Feed/Bottom Exchanger G-65-D-O-1021-05 Unit 51-210 – Condensate Stabilization O utlet Header

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Feed Temperature on Tray 6. The stabilizer feed temperature is automatically controlled at 68°C. It determines the degree of condensate vaporisation on feed Tray and supplies heat to liquid/vapour equilibrium of Tray 6. Stabilizer Feed Rate on Top Tray . The Stabilizer Feed Rate on top Tray (reflux) is a ratio of the feed rate and it is adjusted to maintain 32°C on top temperature of stabilizer; the increase of top temperature allows that higher boiling component will contaminate the off gas fed to compression section. 51-210-LIC001 is a split range controller. The first portion of the output signal (0-60%) is sent to the signal multiplier 51-210-LY001B, which can adjust the ratio between the signals to the two column feed (51-210-FIC006 & 51-210-FIC007) by means of 51-210-HIC002 located in the DCS (i.e. 60-40 or 70-30 or other combination depending from operating conditions). The low signal selectors 51-210-FY006 (51-210-FY007) receives the signal from 51-210LY001 and from high flow constraint controller 51-210-HIC003 (51-210-HIC004) and select the lower one (normally the lower signal is from the level controller) and fixes the set point of 51-210-FIC006 (51-210-FIC007). The 51-210-FIC006 (51-210-FIC007) opens valve 51-210FV006 (51-210-FV007) when the level rises over the SP value and closes valve when level falls under the SP value. The second portion of the output signal of 51-210-LIC001 (60-100) is sent directly to 51-210LV001, in order to open valve when level rises over SP value and close when level falls under the SP value. Activation of interlocks 51-210-I5001/002 drives 51-210-LIC001, 51-210FIC006 and 51-210-FIC007 to manual mode a nd output null by 51-210-XS001 and 51-210XS002. The temperature of the condensate from the heart exchanger 51-210-HA-001 is controlled by 51-210-TIC-005 which operates the by-pass control valves 51-210-TV-006.

Figure 1.14 - Stabilizer Feed Bottom Exchanger Flow Control

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Figure 1.15 - Stabilizer Feed Bottom Exchanger Temperature Control

e) - Off-gas Compressor Capacity Control

Reference P&ID: G-65-D-O-1021-08 Unit 50-210 – Condensate Stabilization Off Gas st Compr. 1 Stage “A” K.O. Drum st nd G-65-D-O-1021-14 Unit 50-210 – Condensate Stabilization Off Gas Compr. 1 and 2 Stage “A st G-65-D-O-1021-11 Unit 50-210 – Condensate Stabilization Off Gas Compr. 1 Stage “ B” K.O. Drum st nd G-65-D-O-1021-15 Unit 50-210 – Condensate Stabilization Off Gas Compr.1 and 2 Stage “B” st G-65-D-O-1021-16 Unit 50-210 – Condensate Stabilization Off Gas Compr. 1 Stage “C” K.O. Drum st nd G-65-D-O-1021-17 Unit 50-210 – Condensate Stabilization Off Gas Compr. 1 and 2 Stage “C” Note: hereafter is described the capacity control only for KB001A/002A; KB001B/002B and KB001C/002C capacity controls are identical.

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Figure 1.16 - Off – gas Compressor Capacity Control

Compressor control capacity shall be Automatic or Manual (Auto/Man selector 50-210HSKB001A-2) by steps (0-50-75-100%). Even if the compressor load/unload step changing is done by operator from DCS, the recycle valve control will remain in any case under master pressure control (50-210-PIC022). For each step signal from master pressure controller 50-210-PIC022 acts on compressor recycle valve and on compressors valve unloader as described below. Suction pressure decrease:

Compressor Condition: Running 100% Load With recycle valve 50210PV022 in control condition, master pressure controller 50210PIC022 start to open the recycle valve 50210PV022. Once 50% (1) of the output signal is reached, than a digital output signal (XS003A=0), is sent to compressor PLC in order to reduce compressor capacity control from 100% to 75% (2). The master pressure controller will now operate with the new working condition on recycle valve 50210PV022. Compressor Condition: Running 75% Load With recycle valve 50210PV022 in control condition, master pressure controller 50210PIC022 start to open the recycle valve 50210PV022. Once 50% (1) of the output signal is reached, than a digital output signal (XS002A=0), is sent to compressor PLC in order to reduce compressor capacity control from 75% to 50% (2). The master pressure controller will now operate with the new working condition on recycle valve 50210PV022.

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Compressor Condition: Running 50% Load With recycle valve 50210PV022 in control condition, master pressure controller 50210PIC022 start to open the recycle valve 50210PV022. Once 100% (1) of the output signal is reached, than a digital output signal (XS001A=0), is sent to compressor PLC in order to reduce compressor capacity control from 50% to 0% (2). The master pressure controller will now operate with the new working condition on recycle valve 50210PV022. Suction pressure increase:

Compressor Condition: Running 0% Load With recycle valve 50210PV022 in control condition, master pressure controller 50210PIC022 start to close the recycle valve 50210PV022. Once 0% (1) of the output signal is reached, than a digital output signal (XS001A=1), is sent to compressor PLC in order to increase compressor capacity control from 0% to 50% (2). The master pressure controller will now operate with the new working condition on recycle valve 50210PV022. Compressor Condition: Running 50% Load With recycle valve 50210PV022 in control condition, master pressure controller 50210PIC022 start to close the recycle valve 50210PV022. Once 0% (1) of the output signal is reached, than a digital output signal (XS002A=1), is sent to compressor PLC in order to increase compressor capacity control from 50% to 75% (2). The master pressure controller will now operate with the new working condition on recycle valve 50210PV022. Compressor Condition: Running 75% Load With recycle valve 50210PV022 in control condition, master pressure controller 50210PIC022 start to close the recycle valve 50210PV022. Once 0% (1) of the output signal is reached, than a digital output signal (XS003A=1), is sent to compressor PLC in order to increase compressor capacity control from 75% to 100% (2). The master pressure controller will now operate with the new working condition on recycle valve 50210PV022.

1.6 - Start-Up Procedures

Restart after first start-up or after Plant General PSD The plant at restart condition (after the first start up) is in the following status: • Each unit is pressurized at its operating pressure. • All manual isolating valve between unit or upstream and downstream SDV, MOV, EBV, UV, are open. • All manual isolating valves on control valves are open. • Cooling water to all cooler is open.

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• Instrument air supply is available. • ‘Locked Open’ and ‘Locked Closed’ valves are in their normal operating positions. • All safety devices are ready for operation. • Electrical trace heating is energised; • All instruments are ready for operation. • All instrument vent/drain valves are SHUT. • All MOV, BDV and SDV valves are in position shown on the P&ID. • Acid and LP flare system are ready for operation. • Acid and LP flare system are ready for operation. • All process controllers are set at its normal operating value and the relevant control valves have the position according to the set, excluding those forced in manual mode with output zero through XS signal. • The raw gas and condensate incoming pipeline are isolated. • All process controllers are set at its normal operating value and the relevant control valves have the position according to the set, excluding those forced in manual mode with output zero through XS signal. • The raw gas and condensate incoming pipeline are isolated. st

1.6.1 - Start the 1 train of condensate stabilization • Check the pressure drop across 50-190-SDV-002A; if it is less than 3 bar, reset 50-190-SDV-002A; if the pressure drop is higher, reset 50-190SDV 002B. • Open 50-190-SDV-003 and 51-210-SDV-003. • Start to feed the Condensate Surge Drum opening gradually 51-210-FV003; condensate will flow to Condensate Surge Drum 51-210-VA-001; check the flow on 51-210-FIC-003 and check the level rising on 51-210-LIC-001 and 51-210-LIC-002.

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• When the level on Condensate Surge Drum 51-210-VA-001 reaches the 50% then open 51-210-EBV-004, start Condensate Feed Pump 51-210-PA001, verify that minimum flow 51-210-FIC-005 works properly; start to feed gradually the stabilizer column operating through 51-210-FIC-006, check the level increase on bottom of stabilizer column (51-210-LIC-006). • As soon as the level on bottom of stabilizer column is detect, (51-210-LIC 006) commission the reboiler 51-210-HA-002; gradually open the steam operating 51-210 FIC-009; check the temperature increase on 51-210TIC 017; when 94°C are detected, then put the instrument in cascade. • Check the profile of temperature on stabilizer column; when the top temperature start to increase, then start the reflux, (feed to try 1) operating through 51-210-FIC-007 to maintain 38°C at vapour line of column (51210 TI-013); the off gas is sent to LP flare by operation of 51-210-PIC-008. • Check the pressure drop across the column. • When the level on bottom of stabilizer reach the 50% the product start to flow to off-spec condensate storage tank. • Slowly increase the flow rate to reach 50% of design capacity of this train; 51-210-FIC-006 and maintaining the some ratio increase the flow rate on 51 210-FIC-007; at these new conditions, adjust the other operating condition such as feed temperature 51-210-TIC-006, temperature on try 14 51-210TIC 017 in cascade with steam flow controller 51-210-FIC-009, pressure on vapour line maintained by 51-210-PIC-008 sending off gas to LF flare, level on bottom of stabilizer 51-210-LIC-006, the product is sent to off spec condensate storage tank; check the pressure drop across the column, vapour line temperature, temperature of product to storage. • When the feed rate to stabilized have been increased, also the flow rate to Condensate Surge drum will be automatically increased; check the operating conditions on this vessel such as levels of condensate; 51-210-LIC-001 and

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002, level of interface in water pot 51-210-LDIC-004, pressure on Condensate Surge drum maintained by 51-210-PIC-027 sending off gas to LP flare, minimum flow of condensate feed pump 51-210-FIC-005. • Commission the analyser 51-210-AA-002 on stabilized condensate to storage tank and when the condensate meet the specifications, operate 51-210-HS 005 to position “A” in order to have the following MOV in the indicated position: −

51-210-MOV-007 to feed condensate to stabilizer column remain open;

− 51-210-MOV-008 condensate from delivery of 51-210-PA-001 unstabilized condensate to off specs tank remain closed; − 51-210-MOV-009 stabilized condensate to off specs tank is closed; − 51-210-MOV-010 stabilized condensate to storage tank is open and stabilized condensate will flow to appropriate condensate storage tank. • Increase the stabilizer flow rate to reach the design capacity then proceed with the start up of 2nd train of stabilization. • During stabilizer feed flow rate increase, check the flow rate of off gas sent to LP flare from stabilizer vapour line 51-210-FI-008 and when the flow is steady, the off gas compression system will be started up.

1.6.2 - Start the Stabilization Off Gas Compression System • Slowly increase the set point of 51-210-PIC-008 and decrease the set point of 51-210-PIC-013 so that the off-gas sent to LF flare is diverted to off gas compressor. • Commission the off gas compressor according to the manufacturer recommendation then start compressor operating 50-210-HSKB-001A-1; the MPC (Master Pressure Controller) by means of 50-210-PIC-022 automatically load the compressor or open the recirculation line from 50


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delivery of second stage to maintain the suction pressure of compressor. • With the compressor running check all operating parameters in the unit.

1.7 - Shut-down Procedures Condensate Stabilization, Off-gas Compression and Off-Specs Storage

As reported previously there are two parallel trains, each designed for 66.6% of total ca pacity, for condensate stabilization. Recompression of OVHD stabilizer column gas to be recycled to gas sweetening unit is accomplished by means of a 1x100% capacity two stage reciprocating compressor (50 210KB001A/002 A, common for two lines). 1x100% capacity identical compressor (50 210KB001B/002B) is installed as stand-by. The third identical compressor (50 210KB001C/002C) is foreseen in the unit, as common spare compressor for the two compressors A and B, when both running (Bouri case). The off-specs condensate tank 50-210-TA-001 will provide a sufficient storage capacity to store unstabilized condensate of one train for about 24 hours. This tank will serve to divert the unstabilized condensate from off-shore in case of an emergency in the downstream stabilization unit, thus avoiding to stop gas production. The arrangement described previously and the stand-by philosophy are good reasons to consider only the shut down of one condensate stabilization train. The relevant procedure consists in the following steps: 1) Start to reduce slowly the NGL condensate feed to the Stabilizer Column 51-210VE-001 (52-210VE-001) down to 50% of the plant capacity, reducing manually 51-210FIC003 (52-210FIC003) following the procedure described in the general shutdown of the unit 2) In the same time, increase the condensate feed flow rate in the running condensate stabilization train to the maximum allowed capacity, i.e. 66.6% 3) Reduce accordingly the load of the Off Gas Compressor (of the three) 50-210KB001/002 A or B or C which is running, to match the new load conditions of the condensate stabilization trains. 4) Stop the train when the capacity reached 50%, following the procedure described in the general shutdown of the unit.

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1.8 - Common Troubleshooting

There is a possibility of slugs of heavy liquids coming into the plant along with the inlet feed stream. This heavy liquid will flow through the feed drum to the stabilizer and out through the bottom with the condensate. Since these slugs should be intermittent, it will be necessary to be aware of this situation and adjust the operating conditions to compensate for the presence of the heavy material. All changes in the bottom temperature controller must be made slowly to allow the tower to stabilize (lineout) after each small change. A low bottom level alarm is also provided to warn the operating personnel of forthcoming erratic conditions. Figure 1.17 reports some probable upsets that may occur in the unit during normal operation together with the relevant operator action.

Figure 1.17 - Troubleshooting

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2. GAS HC DEW POINT CONTROL - Unit 340

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2.1.1 Hydrocarbon dew point

The condensation temperature of heavy hydrocarbon components in gas - commonly known as the hydrocarbon dew point - is a complex and difficult parameter to measure.Traditionally, this measurement has been made using a manual optical technique based on the cooling of a mirrored surface in contact with the hydrocarbon gas mixture. Whilst it is possible, with experience and application, to obtain repeatable results with a manual dew-point hygrometer, the subjective nature of this technique yields it ever le ss applicable in today's de-regulated gas markets where continuous and precise measurement of this critical parameter are demanded. Natural gas is made up of a large number of discrete components, from hydrogen to complex long chain hydrocarbons. Each component will have its own particular dew point, effectively defined by its concentration and vapour pressure. Therefore, as a sample of natural gas is cooled, each component will begin to condense as it becomes saturated at a particular temperature. Heavy hydrocarbons will be the first to condense, but in small quantity as they are normally the trace components in the gas mixture. Therefore, unlike for instance water dew point in an air system, the hydrocarbon dew point in natural gas is a non-distinct parameter that can be changed dramatically by small changes in gas composition or pressure. To complicate matters further, component molecules can interact and even form weak bonds together at higher pressures and therefore the phase relationship of natural gas follows a completely different pattern to that of simple gas mixtures. Indeed, the phase envelope folds back on itself at higher pressures, so effectively the hydrocarbon dew point reaches a peak (normally at about 27 bar g) and then reduces.

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A final physical point of note is that hydrocarbon condensates have an extremely low surface tension compared, for example, to that of water. Therefore, as condensation forms on a surface, it will tend to form a film rather than discrete droplets, rendering detection by traditional optical means far more difficult than the detection of water dew points.It is therefore vital that any technology used for the measurement of the effective hydrocarbon dew point of natural gas is extremely sensitive, repeatable and able to operate over a range of system pressures. Sensitivity of the order of 1ppm (molar) of condensate enables the analyser to detect the almost invisible films of condensate that are characteristic of hydrocarbon gases at dew point, due to their low surface tension. In order to achieve maximum accuracy in this difficult measurement, a flow de-coupling method is used. Discrete measurement cycles, at user definable intervals, lock a fixed sample of the hydrocarbon gas mixture into the measurement cell. As the optical surface is cooled, sequential condensation of hydrocarbon components occurs until the preselected optical trip level is reached that signals the effective hydrocarbon dew point temperature of the gas. The fixed sample means that there is representative condensation of all the hydrocarbon components and prevents preferential condensation of heavy ends that might occur with a flowing sample - this could lead to a falsely high indication of the hydrocarbon Figure 2.1 – Diagram P-T for HC Dew point .

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2.1.2


Gas Dew Point Control - Purpose and application.

The Gas HC Dew Point Control Unit has the duty to reduce drastically the condensable hydrocarbons (heavier HC), still present in the sweet and dried gas, so that condensation of hydrocarbons in the export pipeline is avoided. Condensation of liquid is a problem in metering, pressure drop and safe operation. Condensation of liquid can also be a major problem with two-phase flow and liquid slugging. To prevent the formation of liquids in the system, it is necessary to control the hydrocarbon dew point below the pipeline operating conditions. Since the pipeline operating conditions are usually fixed by design and environmental consideration, single-phase flow can only be assured by removal of the heavier hydrocarbons from the gas. Small amounts of water or condensate can impair the efficiency of gas transportation lines, cause corrosion, form hydrates and, in time may form liquid slugs that could damage compressors and burners and cause serious safety hazards. For this reason gas transportation and distribution companies specify, for the gas they have to transport, the maximum dew point temperatures (the temperature at which the liquids, water or hydrocarbons, will starts condensing).

Figure2.2 – A “typical” Hydrocarbon Dew Point Control Unit - a number of process components are added/modified/remove to suit the requirements of each individual application.

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While the water condensation curve has a positive slope (condensation occurs either reducing the temperature or increasing the pressure), this slope of a multicomponent hydrocarbon condensation curve is negative (or “retrograde”). The hydrocarbons condense when the pressure is reduced. Retrograde condensation occurs even with very lean gases ( e.g. 99.5 % methane) that have an appreciable long “tail” of heavy components, and is observed down to pressure of 15/30 barg. In order to know with a certain accuracy the temperature of condensation at the various pressures or to find the pressure at which the condensation temperature is highest ( cricondentherm) it is necessary either to have an experimental condensation curve or, a representative detailed gas composition up to at least C13. The heavier hydrocarbons even in minimal percentages have a great influence on the dew point temperature.

0

Figure 2.3 – Condensation curves of a natural gas separated at 0 C and 70 barg

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2.1.3 - Main procedures In order to obtain the lower dew point it may use one from following procedures: -

LTS ( Low Temperature Separation). When high pressure gas is available,

the expansion of the gas stream can be used to refrigerate the gas (JouleThompson effect) and condense heavy hydrocarbons and water that can be removed as liquids.(Figure2.6) Figure 2.4 - Horizontal low temperature separator Figure 2.5 – Vertical low temperature separator

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Figure 2.6 – LTS – Low Temperature Separator

Figure 2.7 - % of hydrocarbons recovery in a low temperature separator

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Absorption by glycol . When only water dew point has to be controlled a

simple

process is the absorption of water by glycols.

Dry bed adsorption.( Figure 2.8) By running the gas stream through adequate

adsorbing dry beds, water and heavier hydrocarbons can be removed simultaneously. Generally no LPG is recovered.

Figure 2.8 - Three tower Dew Point Control Plant – Adsorption Type

Commercial amorphous adsorbents are materials treated in order to develop a high porosity and a very large surface area per unit volume. Activated carbon, alumina, activated alumina gel, silicagel, are commercial adsorbents, marketed under several trade names. Their porosity is of de order of 50% and is made of a great number of interconnected capillary channels of various diameters that 2

develop an enormous surface (of the order of 500 m /g). They are suitable to adsorb molecules of various nature, specially polar, that fit in their pores. The most commonly used adsorbent for simultaneous water and hydrocarbon dew point control is silicagel. Molecular sieves are synthetic crystalline zeolites 0

having pores of constant diameter ( e.g. 3, 4, 5, 10 A ), ideal for adsorbing selectively small size molecules like H2O, CO2, H2S, Mercaptans, but too small

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for adsorbing heavy hydrocarbons. When the removal of hydrocarbons is not wanted, molecular sieves, rather than silicagel, can be used. Molecular sieves can obtain very low water dew points and are indicated when followed by cryogenic plants or when s is protected by graduated layers of inert ceramic balls. Mechanical refrigeration.( Figure2.9) By cooling the gas stream to low temperature by means of a refrigeration unit (e.g. with propane refrigerant), and removing the condensed NGL (the higher the pressure the lower must be the temperature). Refrigeration of a gas stream causes condensation of both water and hydrocarbons and therefore can be used to reduce t he dew point of the gas. However at high pressure and low temperature liquid water form hydrates and may plug valves and exchangers of the plant. In order to prevent hydrates formation it is necessary either to previously dehydrate the gas stream or to inject hydrate preventers like methanol, ethylene glycol or di-ethylene glycol. Methanol is used only in emergency or at start-up because it is mostly lost with the gas stream. Glycols (mono and di-ethylene) are preferred since they can be easily regenerated and recycled. It is adopted when sizeable amounts of condensate are expected (gasoline plant). The process may lead to the recovery of LPG. In the figure 1.9 it can see the gas runs first through a filter separator to remove all the liquid droplets, is then pre-cooled by the outgoing treated gas and finally chilled by means of a mechanical propane refrigeration plant.

Before the gas being cooled reaches the hydrate formation temperature a solution of glycol is sprayed into the gas stream to prevent the formation of hydrates. More glycol is injected at the chiller inlet. The condensates are separated from the gas stream in the low temperature separator. While the hydrocarbons are sent to the cold feed stabilizer and from there to storage, the diluted glycol is regenerated and recycled. The most expansive and complex part of the plant is the mechanical refrigeration unit.

Figure 2.9 – Flow diagram of a refrigeration Dew Point Control Plant with glycol

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Turbo-expansion (Cryogenic plants).( Fig.2.10) The simultaneous expansion

and refrigeration of the gas stream by means of a turbo-expander brings the gas to very low temperatures and permits to condense all the condensable hydrocarbons. With the turbo-expansion unlike the lamination through a valve, the gas stream produces work subtracting calories from the stream, and can reach much lower temperatures. The gas can thus be separated at a more convenient pressure and the work generated can be used to partially recompress the gas after separation of the NGLs. This process leads also to the recovery of gasoline, butanes, propane and ethane. Their fractionation is generally integrated with the dew point plant. Since at these low temperature the water would form hydrates, and the glycols would become too viscous and might clog the exchangers, this process requires a previous deep dehydration of the gas by means of molecular sieves adsorption. A dew point control plant is not necessarily economically justified by the recovery of NGL, sometimes it is necessary to meet the gas transportation or distribution company specifications.

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Figure 2.10 – Conceptual Diagram of a Cryogenic Plant

A cryogenic plant has four functional sections: -

Dehydration to remove moisture from the gas

-

Chilling and expansion to liquefy part of the gas

-

Demethanizing to remove the methan which liquefies.

-

Compression to boost gas pressure to sales gas pipeline pressure. Obviously, a pre-treatment stage is necessary in case of presence in the inlet gas of hydrogen sulphide and/or carbon dioxide.

The chilling section is the heart of the cryogenic plant. Gas can be chill by following procedures: a)

Heat exchange with cold gas

b)

Refrigeration

c)

Pressure reduction

d)

Removing energy from the gas as in an Expander 0

Refrigeration systems using propane can be apply to chill gas to -40 C. At temperature below this, ethane or ethylene is used for refrigerant, but the system is very expensive. Another means of lowering gas temperature is simply to reduce its pressure across a pressure 0 reducing valve. The temperature will drop approximately 1 C for each 125 kPa drop in 0 pressure,( 1 F for each 10 psi drop in pressure). Pressure reduction requires recompression, so its cost is high.

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2.1.4 Propane - Characteristics, Properties and Combustion Propane is a liquefied petroleum gas that comes out of both oil and gas wells. Propane does not occur naturally though. Raw crude oil or raw natural gas is refined to make different types of petroleum products, one of which is propane. Following it's refinement, propane is stored as a liquid under pressure until utilized, at which point it becomes a gas. Propane Properties - 440C

Propane Boiling Point Weight of 1 Gallon Liquid Propane at 60 0F

4.24 Lbs

Specific Gravity of Propane Gas at 60 0 F

1.52

Specific Gravity of Liquid Propane at 60 0F

0.51

Propane Boiling Point - Water boils at 212°F meaning that it becomes a gas at this temperature whereas water is still a liquid at 200°F. Propane is a liquid at -50°F and boils at 44°F. In other words, at 10 degrees below zero, propane is well past its boiling point. It means that propane is cold enough freeze your skin (and tissue underneath) to the point of severe damage. Specific Gravity of Propane Gas - One cubic foot of propane weighs .1162 lbs. and one cubic foot of air weighs .07655. Dividing .1162 by .07655 equals 1.52. What does this mean? Propane is heavier seek the lowest space available. Specific Gravity of Liquid Propane - One gallon of propane weighs 4.24 lbs. One gallon of water weighs 8.33 lbs. Dividing 4.24 by 8.33 equals .51. This means propane is less dense than water (lighter than water) and will not sink in water, so to speak. Propane Limits of Flammability - The lower and upper limits of flammability are the percentages of propane that must be present in a n propane/air mixture. This means that between 2.15 and 9.6% of the total propane/air mixture must be propane in order for it to be combustible. If the mixture is 2% propane and 98% air, there will not be combustion. If the mixture 10% propane and 90% air, combustion will not occur. Any percentage of propane in a propane/air mixture between 2.15% and 9.6% will be sufficient for propane to burn. However, an improper air/gas mixture can produce CO (carbon monoxide) that is a deadly product of incomplete combustion. Flash Point - The flash point is the minimum temperature at which propane wil l burn on its own after having been ignited. This number states that below -156°F, propane will stop burning on it's own. In other words, if the outside air temperature is -155°F, propane will burn on it's own. If the outside air temperature falls to -157°F, propane will no longer burn on it's own. However, if a source of continuous ignition is present, propane will burn below - 156°F. Ignition Temperate in Air - This number states that propane will ignite if it reaches a temperature between 920-1020°F. If propane is heated up to a temperature between 920 and 1020°F, it will ignite without needing a spark or flame. Maximum Flame Temperature - A propane flame will not burn hotter than 3595°F Before propane is used, it exists in one of two forms, liquid or vapor. Both liquid propane and vapor are usable but cannot be used interchangeably. In other words, a propane system

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designed to use vapor can't utilize propane in its liquid form and vice-versa. Additionally, the characteristics of propane liquid and propane vapor are so different that t he primary properties we are concerned with are as different as night and day. With propane liquid, temperature is the primary factor whereas weight is the main concern regarding propane vapor. Think of it this way, water is liquid and steam is water vapor. The same holds true for propane and is explained in detail below. Propane Liquid

Propane exists in its liquid form at or below its boiling point (-44°F) as well as when it stored under pressure. To further explain, if the temperature outside is -45°F, propane will be a liquid and you would be able to pour it out of a bucket. But as soon as the temperature rises to -44°F, the propane begins to boil and thus give off vapor. If the temperature outside is colder than -44°F, propane exists as a liquid. It's still propane but it looks a lot like water while at this cold temperature. It's colorless, odorless and tasteless...but who would take a drink of a any liquid that is 45 degrees below zero? Who would stick their finger in a glass of anything that is 45 degrees below zero? Holding a handful of ice can be quite uncomfortable (or painful) after some time but think how painful it would be if that handful of ice was almost 75 degrees colder. Because propane boils at a temperature that is over 70 degrees lower than the freezing point of water, it has the ability to freeze skin tissue in a very short period of time (severe frostbite). The temperature properties of liquid propane are such that be ing aware of possible danger when dealing with propane in its liquid state is extremely important.

Propane Vapour . Propane becomes a vapor at temperatures above -44°F. Similar to water when it boils and gives off steam, propane gives off vapor when it boils. One ma y refer to propane vapor as "flammable steam" for simplicity. However, for the propane vapor to be ignited, there must be the right mix of air and vapor. Propane vapor is heavier than air and will sink to and collect in the lowest point it can find. If propane is vented to the outside air, it will quickly dissipate with the slightest movement of air. Conversely, if propane is vented into an air tight structure with no air movement, the propane vapor will collect on the f loor and rise vertically if more propane is vented into the structure. This is extremely important to know because if there is a propane leak in a house or building, the propane vapor will seek the lowest possible point where it will collect. Keep in mind that one gallon of propane will produce over 36 cubic feet of vapor and this vapor will settle in the lowest possible place. If the propane vapor level continues t o rise, it may ignite if finds a source of ignition. The weight of propane vapor being heavier than that of air is a characteristic of propane gas that needs to be understood by all LP Gas users, not just propane

2.2. - Gas Dew Point Control using Propane Refrigeration The Propane Refrigeration Unit consists of a closed loop in which the propane is flashed in 2 steps, vaporized, recompressed and condensed. The first step flash is the economizer system, which splits the main stream in to a liquid phase (used to refrigerate second flash step) and a gas phase that is routed to the Refrigeration Compressors.

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The refrigerant medium used is propane product. The propane refrigerant make-up is stored in the Propane Refrigerant Storage Unit. The composition of the propane refrigerant, which was considered for the design of the unit, is: •

Ethane: 1.55 %mol

•

Propane: 96.54 %mol

•

I-Butane: 1.51 %mol

•

Butane: 0.45 %mol

For the initial fill of the system, the propane refrigerant is from road tankers. The quality of this fill followed the specifications, imposed to the onshore plant Propane product, which are summarized in Table 2.1 below.

Table 2.1 - Propane Composition

Composition, liquide volume %

Max 1 ppm vol Max. 2.0 Min. 95.0 Max. 3.0 Max 15 ppm vol

ASTM D-2163

Corrosive Compounds, Copper Strip

Max. No.1

ASTM D-1838

Total sulphur ppm (wt)

Max. 15

ASTM D-2784

Hydrogen Sulphide content

Negative

ASTM D-2420

Vapour pressure @ 100°F, psig (kPa(g)) Water Content, ppm (wt) Residues Residues number Oil number Oily residue, ppm(wt)

Max. 200 ( 1380)

ASTM D-1267

Max.10

ASTM E-700

Max.10 Pass test 20

ASTM D-2158

Methane Ethane Propane Butanes Pentanes +

Propane refrigeration is well suited to gas plant applications where chilling to between -12°C and -40°C is required. Boiling points of propane are -42°C at 101.35 kPa and 38°C at 1310 kPa. The propane refrigerant cycle can be thought of as heat pumping.

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Heat is brought into the system at a low-temperature level and "pumped up" to be discarded through the condenser to a high-temperature heat sink. Propane is the heat carrier. Propane as a refrigerant in externally refrigerated processes is effective when large rates of heat removal are required from the gas streams. It is readily available in large plants and has excellent thermodynamic qualities. Propane possesses much greater refrigerating effect than other refrigerants such as freon, ammonia and carbon dioxide. The boiling point of propane at atmospheric pressure is fairly low and requires large amounts of heat to convert it from a liquid to a gas in the chillers. When in vapour form after compression, it requires a low pressure to condense it for use a liquid in another cycle. It has no offensive odour and is not of poisonous or toxic nature. Further, propane is not corrosive to metals and can be safely stored in properly designed vessels. The biggest drawback of propane, however, is that it is inflammable and explosive when mixed with air. Great care is required to handle it and all safety precautions should be adhered to when charging the system initially, periodically or during any maintenance work in the system. Propane refrigeration systems require centrifugal compressors, condensers, surge tanks, economizers and evaporators or chillers to produce the required cold. The Refrigerant Compressors are two stage centrifugal compressors, driven by a fixed speed electrical motor and are configured as 2x 50% ( two in operation/none in stand-by).So in the event of only one compressor working, most of flow enters to the other compressor. Because of flow rate and suction pressure increasing, compressor load increases; so for the period required, operation is possible, only reducing flow rate to the working compressor. Each compressor has two inlets and one outlet. An anti-surge controller caters for the protection of each Refrigerant Compressor. Hot propane vapour from the Refrigerant Compressor discharge is recycled through

+

The centrifugal compressor is used to raise the condensing temperature of the propane refrigerant above the temperature of the available coo ling medium in the condenser. condenser.

+

+

+

The condenser is used to cool and condense the discharged pro pane pan e vapo ur from fro m the compres compressor sor back back to its its original original liquid liquid form form The economizer is designed to lower the temperature of the liquid refrigerant by flashing or heat exchange and improves the refrigeration cycle efficiency. The evaporators or chillers accomplish the transfer of heat from the gas stream to the boiling refrigerant thus lowering the temperature of the incoming gas.

Generally the entire refrigeration process depends upon two facts: That propane refrigerant has a low boiling point and will boil as soon as i t c ontact s the warm warm gas. gas. That the boiling point varies with w ith the pressure of the refrigerant. •

•

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Referring to the general flow diagram in Figure 2.11 the cooling is accomplished in the chillers by passing the inlet gas through the tubes, while maintaining a level of liquid propane at the proper pressure around the tubes in the chiller shell. The heat exchange surface or outside area of the tubes in the chiller, may be designed for a five degree approach, which means that the gas leaving the chillers will be five degrees warmer than the liquid propane in the chiller shell. Therefore, cooling the gas to -37°C requires that the propane be maintained at -42°C. Any pure liquid will have a specific boiling temperature corresponding to the pressure being exerted against it. For instance, water boils at 100°C when under atmospheric pressure at sea level. If the pressure is lowered or a vacuum pulled on the water, the boiling temperature is also lowered until it will boil at a room temperature of 26°C under a 736 mm vacuum. When the liquid boils, it absorbs heat from some source such as, in the case of a pan of boiling water, the flame below it. In the plant chillers, the propane will boil at -42°C if the pressure on it is held at atmospheric level and the boiling liquid will absorb heat from the gas in the tubes. For each kilogram of propane vaporized a definite amount of heat will be absorbed from the gas. Thus, heat is removed until the temperature of the gas has decreased to the desired level of -37°C. To cool the design volume of gas to -37°C, it will be necessary to vaporize 4,041 kg per minute of propane.

Figure 2.11 - Typical Propane Refrigeration System

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To hold the pressure in the shell of the chillers down to atmospheric pressure and to provide a continuous supply of propane to replace that which has vaporized, it is necessary to withdraw the vaporized propane from the chiller, compress it, to cool it until it is again a liquid and to reinject it into the chillers. Just as there is a definite boiling point for a pure liquid at any given pressure, so is there also a definite temperature at which the vapours will condense into a liquid for any pressure. In fact, they are the same temperature; that is, a pure fluid (which is either liquid or vapour) will boil or condense at the same temperature, if the pressure is held constant, depending on whether heat is added or withdrawn. The pressure to which the propane must be compressed then, is determined by the temperature to which it can c an be cooled. Since the propane condenser was designed with the same 5°C approach as the chillers and the t he design cooling water temperature is 22°C, the propane will leave the condenser shell at 50°C. To condense at 50°C, the propane must be at 928 kPa to allow pressure losses in the line and condenser, the compressor is designed for a discharge pressure of 966 kPa. From the condenser, the liquid propane flows to a surge tank which allows for minor upsets and changes in operating conditions. In flowing from the surge tank where t he temperature is 50°C to the she ll of the chi llers where the the temperatur temperaturee is 42°C, the propane loses much of its c ooling capacity in cooling itself. The power used in compressing the propane which has vaporized, vaporized, only to cool the remaining remainin g liquid, is lost in as much as it has not been used in cooling gas. To minimize this loss and increase the efficiency of the cycle, the pressure on the liquid is reduced in some steps. At the two intermediate steps, the liquid is allowed to boil or flash in vessels called flash tanks or open flash economizers, thus cooling itself to a temperature corresponding to the pressure level. The resulting vapour must then only be compressed from that pressure level to 966 kPa instead of from 7 to 966 kPa. This results in considerable savings in power.

2.3 - Propane Refrigeration Unit 51-340-XX-001 - description of the package. package.

The propane vapour coming from the process Propane Chiller, 51-340-HA-002, arrives at the battery limit of the Propane Refrigeration Unit, enters the Compressor Suction KO Drum and afterwards feeds the Propane Refrigeration Compressors (two in operation, one in stand-by). The suction pressure of compressor will be controlled by acting on its load capacity, which shall be able to vary from 0 to 100%. This pressure control is in turn fixing the operating pressure in the Propane Chiller. The compressed propane gas, which might have been contaminated by compressor oil, passes through the Compressor Discharge Oil Separator. Then, the propane is condensed in the Propane Condenser, using cooling water. The condensed liquid propane from the condenser enters the Propane Receiver. The Propane Receiver is sized for total hold-up of the Package Unit. Connection will be provided here for filling the Unit wit h propane from the production units (41/42-320) in Wafa Coastal Plant. From the Receiver, the liquid is sent on level control to the Economiser, 51-340-HA-005 that produces the cold refrigerant. A part of the liquid propane is flashed on the shell side of the Economizer. The liquid on the tube side gets cooled down to –5°C. The propane flashed gas is

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sent to the intermediate stage of the compressor. From the Economiser, the liquid propane arrives to the battery limit of the Propane Refrigeration Package at a temperature of –5°C maximum. The propane gets vaporized in the Propane Chiller at a temperature of –39°C. The vapour propane is delivered back to the battery limit of the Propane Refrigeration Unit for compression. The Propane Chiller is provided with a bottom boot collect the oil coming along with propane. This oil is sent back to the Propane Refrigeration Unit for feeding into the Compressor Oil System The temperature controller on the gas leaving the chiller operates in cascade on the propane side level controller in the propane chiller which acts on the liquid propane supply valve.

Figure 2.12 – Propane chiller level control

When the temperature rises over the set point value, 51-340-TIC-007 output will increase set point of 51-340-LIC-002 in order to open valve 51-340-LV-002, when temperature falls under the set point value, 51-340-TIC-007 output will decrease set point of 51-340-LIC-002 in order to close valve 51-340-LV-002.

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Figure 2.13 – Propane Refrigeration package 51-340-XX-001 51-340-XX-001

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2.4. - Gas HC Dew Point Control Process Description

Unit 340 is designed to separate the heavier condensable hydrocarbons from the dry gas arriving from Unit 311 in order to avoid any further condensation in the export gas pipeline. The Unit 340 is split over three parallel trains, each sized for 33,3% of the total capacity. The following description is relative to Train 1 but Trains 2 and 3 are identical to Train 1. The Unit 340 is composed c omposed of the following sections:

•

Pre-cooling.

•

Cooling.

•

Separation of NGL condensate.

•

Propane refrigeration system.

The Gas HC Dew Point Control is designed for a 50% turndown referred to the design case; the propane refrigeration system has a capacity that goes from 0 to 100% meaning that the system is able to operate continuously. The Gas HC Dew Point Control Unit has been designed to cool 12081.6 kmol/h of dry gas (considering Year 2 summer case). The Unit is designed to process a stream of dry gas, coming from unit 311, having a B.L. pressure of 35.7 barg and a temperature of 38.6°C in the summer time. The propane chilling system is a fully automatic system; normally two compressors are running while the third one in stand-by. The start-up of the two running compressors shall be done manually by a local push button. The stand-by compressor starts automatically in case of failure of one of the operating ones; a dedicated control panel (PLC based) is foreseen for each compressor, to avoid that a single machine failure causing the shutdown of the Unit and consequently of the whole plant. The main equipment necessary to complete the above mentioned task is the following: •

Raw Gas/Treated Gas Exchangers

51-340-HA-001A÷F

•

Propane Chiller

51-340-HA-002

•

NGL Condensate Separator

51-340-VA-001.

•

Propane Refrigeration Unit

51-340-XX-001

The dry gas from Unit 51-311 reaches the unit 340 through a 20" line (see Figure 2.17 ) on

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which is located a shutdown valve provided with a by-pass also isolated by a shutdown valve. The latter is designed to equalize main valve upstream/downstream pressures. Opening of the main shutdown valve is allowed only when the differential pressure is less than 3 barg. Downstream the shutdown valves are located pressure and temperature indicators, and transmitters with indication at DCS. The Raw Gas/Treated Gas Exchangers 51-340-HA-001A ÷F are of the shell-and-tube type, with the dry gas flowing through the shell side and the treated chilled gas flowing through the tube side. At the conditions foreseen for summer of year 2, the inlet temperature of the dry gas will be 38.6°C and the pressure 34.7 barg, while outlet temperature will be –14°C and the pressure 34.2 barg. For the treated chilled gas is foreseen an inlet temperature of –31°C and a pressure of 32.6 barg, while at the outlet the temperature will be 34.6°C and the pressure 32.0 barg, that are the export e xport gas characteristics. The 20" line is provided with sample connection, temperature, pressure and flow indicators and transmitters with indication and alarm at DCS, the pressure control valve driven by a controller located on the outlet of the condensate separator 51-340-VA-001 There is also a shutdown valve and its by-pass provided with another shutdown valve. The latter is designed to equalize main valve upstream/downstream pressures because opening of the main shutdown valve is allowed only when the differential pressure is less than 3 barg. Figure 2.14 - Common Shell and Tube Heat Exchanger

The treated pre-cooled gas from the shell of 51-340-HA-001A÷F flows, through a 20" line to the Propane Chiller 51-340-HA-002 where it is further cooled to -31°C by vaporising liquid propane supplied from the Propane Refrigeration Unit 51-340-XX-001

Chillers are heat exchangers used to lower the temperature of a fluid below that which could be achieved either using circulating water or atmospheric air. They are part of a refrigeration system that uses a boiling refrigerant such as propane or freon to obtain the desired cooling. Chillers (Figure 2.15 ) are generally kettle type shell and tube exchangers. The refrigerant is

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on the shell side and the tubes are maintained completely submerged in the refrigerant. The fluid to be cooled is circulated through the tubes, giving up heat, causing the refrigerant to boil (vaporize). The vaporized refrigerant is then compressed and condensed back into a liquid and recirculated to the chiller. One disadvantage of these units is the heat transfer surface which must be kept and free of any compressor oil or other fouling substances. Heavy oil deposits on the tubes surface turn viscous at lower temperatures, coating the tubes and reducing the effectiveness of heat transfer. Chillers are often provided with liquid refrigerant cleaning equipment called reclaimers or blow cases. They commonly receive a batch of heavy bottoms from the chiller boiling off the refrigerant and dump the heavy oil residue to a drainage system. Figure 2.15– Propane Chiller

The Propane chiller 51-340-HA-002 has a capacity of 3.22MW, the gas (238,322 Kg/h) enters at a temperature of –14°C to leave the chiller at 31°C. The propane flowrate is 33177 Kg/h.

The Propane Chiller 51-340-HA-002 is a heat exchanger of the kettle type, provided with a boot. The treated pre-cooled gas flows through the tube bundle immersed in the liquid propane coming from the Propane Refrigeration Unit 51-340-XX-001. The liquid propane absorbs heat from the treated pre-cooled gas, and vaporizes. Propane vapour gathers on the top of the shell and leaves the kettle through the 24" line to return to the Propane Refrigeration Unit 51-340-XX-001, while the compressor oil comes along with propane settles on the boot to be sent back to the Propane Unit. The temperature of the chilled gas is controlled by regulating the level of the liquid propane in the kettle: the temperature controller monitoring the chilled gas temperature operates the propane level controller which control the propane level control valve. The level of the oil in the boot is controlled through the interlock which closes the isolation valve on the 2" oil line and gives an alarm at DCS. Boot drain and level stacks drain may be

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directed to open drain system, while level vents are directed to the cold flare The mixed phase of gas and NGL condensed in the Raw Gas/Treated Gas Exchanger and in the Propane Chiller enters the NGL Condensate Separator 51-340-VA-001. The NGL Condensate Separator 51-340-VA-001 is a vertical vessel with a diameter of 3200 mm and a height of 6000 mm, provided with a distributor for the incoming chilled gas and a wire mesh pad demister. Heavier hydrocarbons settle to the bottom and exits through a breaker and a 6" line, under level control.

Figure 2.16 – Vertical 2-phase separator

The NGL Condensate Separator 51-340-VA-001 is a vertical vessel where heavier hydrocarbons settle to the bottom and exits through a breaker and a 6" line, under level control. A 3" line, leading to cold drain or to open drain systems, is foreseen for the vessel bottom drain and for level instrument drains. Level instrument vents are directed to cold flare. The vessel 51-340-VA-001 is also provided with the pressure safety valves discharging to

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the cold flare, and with the blow down valve controlled by t he interlock 51-340-I2001, also leading to the cold flare. The 20" line from the vessel 51-340-VA-001 conveying the chilled exchangers 51-340-HA-001A÷F is provided with sample connection, pressure and temperature indicators and transmitters. The 6" line from the bottom of 51-340-VA-001 is provided with the isolation valve controlled by the interlock and with an analyzer for C3/C4/IC4 detection. Hydrocarbon liquids separated in the NGL Condensate Separator a re sent, under level control, to the NGL Fractionation Units - Unit 320, after mixing with the corresponding streams from Trains 2 and 3. A minimum pressure drop is required for control valve to avoid flashing of the liquid. C3/C4 analyzer is provided to check NGL quality. Large hold up has been provided for NGL Condensate Drum to assure Plant flexibility. In case one of the two downstream NGL fractionation units shut down, two operation are possible: 1) The NGL Fractionation Unit that is in service is brought to its maximum capacity. If the DPCU's are kept to their normal operating chiller temperature (-31°C), this unit will be able to treat the NGL from two of the three gas treating trains. The third train must be stopped with consequent loss of production. 2) The DPCU's chiller temperature is increased to –5°C in all the three gas treating trains. In this condition the produced gas is still on spec for hydrocarbon dew point. The amount of produced NGL decreases and can be treated by one single unit if brought at its maximum capacity. Adequate time to perform any of the two operations is assured by vessel hold up. The treated gas from the NGL Condensate Separator is sent to the Raw Gas/Treated Gas Exchanger, it is mixed with the corresponding streams from Trains 2 and 3 and then joined with sales gas from Wafa pipeline before delivery to MGCS or LGCS. Before exiting the Dew Point Control Unit the outlet gas is analyzed in the analyzer to monitor Wobbe Index and GHV, and it is measured and totalized by the flow totalizer. In ca se of MGCS/LGCS temporary shut down the excess gas will be immediately flared.

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Figure 2.17 - Gas HC Dew Point Control – process flow diagram

2.4.1 - Process Variable The main process variable on Gas HC Dew Point Control is the temperature of chilled gas that is controlled at –31°C by 51-340-TIC-007 in cascade with 51-340LIC-002 evaporating propane in propane chiller. This temperature has effect on condensation of light components; increasing this temperature some light component is not condensed and on contrary decreasing this temperature lighter component are condensed. The dry gas from the Gas Dryer Unit is first pre-cooled in a feed/effluent heat exchanger from a temperature of 38°C to –13°C, and the treated gas is cooled in the Propane Chiller where the gas gets cooled to minus 31°C for base case. In the Propane Chiller, the cooling is achieved by commercial propane evaporating on the shell side at a pressure of 1.2 bara at the corresponding temperature of -37°C for base case. The outlet temperature of dry gas from chiller is automatically controlled at -31°C at a pressure of 34.2 bar. Conclusion: During routine inspection operation keep an eye on the instrumentation/parameters reported in Table 2.2 Table 2.3 reports the analysis of sales gas that may be extremely important for the operator of this unit.

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Table 2.2 - Main local indicators

Variable

Equipment/Service

Instrument Tag

Temperature

Propane to 51-340-HA002 Chilled Gas to 51-340VA-001 51-340-HA-002

Temperature Level Pressure

Treated Gas to Fiscal Metering

Range

Normal Value /Point

51-340-TI-308

-80÷200C

-370C

51-340-TI-308

-80÷200C

-310C

0÷100%(01650mm) 0÷40 barg

55%(900mm)

51-340-LI-004A 51-340-PI-302

32.0 barg

Table 2.3 - Sales Gas Analysis

Analysis

Method

Frequency

C1 – C3 i C4 C4 i C5 C5/C8 C7+ CO2 N2

ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945 ASTM D 1945

daily daily daily daily daily daily daily daily

st

2.5 - Start-up of 1 Train of Gas HC Dew Point Control • Line up the propane vapour to/from Propane Refrigeration Unit 51-340-XX-001. • Open slowly 51-340-LV-002 propane to Propane Chiller 51-340-HA-022; build up the propane level and when 50% level is reached, the put 51-340-LIC-002 in automatic at this value. • Commission 51-340-LIC-009 condensate from NGL Condensate Separator 51-340VA-001 to NGL fractionation; commission the relevant control valve on feed line. • Commission 51-340-PIC-004 and relevant control valve; treated gas from battery limit of unit 340 to H.P. Flare; set PIC at 33 bar in auto mode.

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• Put 51-340-PIC-010 in automatic set at 32.5 bar. • The dry gas from unit 311 is flared to HP flare by operation of 51-311-PIC-052; increase the set point of this instrument to feed the dry gas to Gas HC Dew Point Control • Check the temperature decrease on 51-340-TIC-007; when temperature reaches 31°C, put the instrument in automatic at this value; the instrument in cascade will operate the 51-340-LIC-002. • Check the level increase on NGL Condensate Separator 51-340-VA-001 and when the level reaches 50%, the NGL will be fed to unit 320 NGL Fractionation. • Check the level increase of oil on separation pot of NGL Condensate Separator 51340-VA-001 and when the level reaches 50%, the oil will be transferred manually to Propane Refrigeration Unit 51-340-XX-001 after reset 51-340-EBV-002 located on outlet nozzle of separation pot of NGL Condensate Separator 51-340-VA-001.

2.6 - Shut down procedures As reported previously three parallel trains each designed for 33.3% of total capacity are foreseen for gas HC dew point control. Each train is directly connected with the corresponding upstream trains of Unit 330 gas sweetening and Unit 311-Gas Dehydration. This means that when a single train 51, 52 or 53 of Unit 340 scheduled to shut down, the corresponding train 51, 52 or 53 of the unit 311 is to be shut down too, or kept running with dry gas discharged to HF through PV052 at unit outlet line. Remarks: If the train is scheduled to remain shut for a long period, it shall be better to also shut down one train of the downstream Unit 320-NGL Fractionation, taking care to increase the feed rate to the other train at 100% capacity. If the shut down is of short duration, keep both trains of NGL Fractionation running at lower capacity, say 33.3% for each train.

Proceed as follows: 1) Start to increase slowly the temperature of the chilled gas at outlet of Propane Chiller 340HA002, by acting from DCS on TIC007, which in turns operates in cascade on the chiller level controller LIC002 to reduce propane flow rate 2) Shut SDV002/A and SDV002/B on treated gas line to fiscal metering when it is supposed that chilled gas is out of specification, and contemporarily control the unit pressure by PIC004, discharging treated gas to HF

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3) Shut the condensate outlet valves SDV007 and SDV010 from NGL Condensate Separator 340VAOQI, when no liquid level appears to increase anymore. 4) Reduce accordingly the duty of the propane refrigeration unit, following the instructions of the package unit supplier

5) Shut completely the liquid propane to the chiller, and close manually LV002 from DCS 6) Depressurize the train to H.P. flare through PV004, then close the valve when pressure is balanced with the flare. 2.7 - Troubleshooting Beginning with the refrigerant compressors, especially on start up periods, the worst problem faced is the possible accumulation of liquid propane in the suction line. This problem will occur if the pressure and temperature conditions between the chillers and compressors are allowed to equalize and propane vapour condenses. To prevent this, all suction lines, liquid traps and drains should always be checked before the unit is started, particularly if the flow of propane to the chillers has not been blocked off. High discharge head conditions is encountered particularly in reciprocating compressors due to erratic operation of the condenser. Propane contaminated with oil picked up from the compressors is another problem in gas plants. This problem can be minimized by passing the compressed propane vapour through the oil separators (usually of cyclone type), separating the oil which is drained away later. The blow case (reclaimer) mentioned earlier is another means of removing the oil from the propane if this unit is properly operated. Excess liquid level build up in the suction scrubber and inter-stage bottles should be catched carefully. Some liquid may have to be returned back to the surge drum or dumped to the closed hydrocarbon drain system if levels become excessively high. Figure 2.18 reports some probable upsets that may occur in the unit during normal operation together with the relevant operator action.

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Figure 2.18 - Unit 340 Troubleshooting

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3. NGL FRACTIONATION - UNIT 320

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3.1 General

Fractionation is a unit operation utilized to separate mixtures into individual products. Fractionation involves separating components by relative volatility. The difficulty of a separation is directly related to the relative volatility of the components and the required purity of the product streams. Heat is introduced to the reboiler to produce stripping vapours. The vapour rises through the column contacting the descending liquid. The vapour leaving the top of the column enters the condenser where heat is removed by cooling medium. Liquid is returned to the column as reflux to limit the loss of heavy components overhead. Internals such as trays or packing promote the contact between the liquid and vapour streams in the column. Intimate contact of the vapour and liquid phases is required for efficient separation. Vapour entering a separation stage will be cooled which results in some condensation of heavier components. The liquid phase will be heated which results in some vaporization of the lighter components. Thus, the heavier components are concentrated in the liquid phase and eventually become the bottom product. The vapour phase is continually enriched in the light components which will make up the overhead product. The vapour leaving the top of the column may be totally or partially condensed. A tray-type fractionator (Figure 3.1) is a vertical, steel cylindrical vessel divided into a number of horizontal sections by metal trays. The top section contains the rectifying trays and is called the rectifying section. The centre section is called the feeding section and the bottom is called the stripping section. Most large fractionators use trays or plates instead of packing because they are easier to maintain and are not as subject to fouling as are packed towers. Products can be taken off at different levels (trays) if specific products are required. Trays are the most efficient method of fractionating liquid hydrocarbons. The action on the trays performs the following: - Strips the vapors from the descending liquid to produce an acceptable bottom product.

- Condenses the liquids from the ascending vapor to produce an acceptable overhead product. The number of trays required for a vessel will depend on such factors as: -If the products have a high relative vapor pressure, the products will be easier to separate and fewer trays will be required.

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-The purity required of the overhead and bottom products. -The efficiency of the action on the trays. Fractionator trays are named according to their function and location in the tower: -

Top tray is the highest tray in the tower.

-

Reflux tray is the tray where reflux enters the tower.

-

Intermediate trays are the trays below the reflux tray where the overhead product is enriched.

-

Feed trays are where the raw product enters the tower.

-

Stripping trays are the trays where the bottom product is stripped of overhead fractions. Seal pan is used to seal the bottom tray.

-

Chimney tray is used for liquid draw off or to maintain a liquid head to the reboiler.

Figure 3.2 shows a typical fractionator tray. The bolts around the circumference are used to install the tray to brackets welded to the vessel wall. The centre section of the tray can be removed without disturbing the main part of the tray so the vessel can be inspected or maintained. The weir on the right side of the tray maintains a liquid level on the tray.

Figure 3.1 - Fractionator

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Figure 3.2 - Fractionator tray

Installation of Trays . Trays are generally bolted into the fractionator so they can be removed for repairs, replacement, or for inspection of the vessel. They must be firmly installed to prevent surges from lifting the trays from their supports. Regardless of which type of tray or packing is used, the purpose is to provide intimate contact between the descending liquid and the rising vapor. Economics, product purity, cleanliness of the feed, operating pressures and temperatures, as well as other considerations enter into the choice of contacting equipment used in fractionators. Tray Spacing. Tray spacing is based on the mechanical design of the trays, the viscosity of the products, velocity of the rising vapor, and accessibility. The spacing must allow enough time and height for the entrained liquid droplets to disengage from the rising vapor. The most common spacing for trays is 60 cm. Flooding. Flooding takes place when the down-comers cannot carry away the liquid from the trays, causing a high level on the trays and products that are off specification. Flooding can be caused by high pressure drops, which in turn can be initiated by entrainment. Entrainment is a condition where the rapidly rising vapor stream carries liquid droplets from one tray to the tray above. Blowing. Blowing is the opposite of flooding. The rising vapor blows the liquid from the tray in a fine spray, leaving the tray essentially dry. The lack of contact between liquid and vapor greatly reduces the efficiency of the trays and off specification product results. Bubble caps. Bubble caps are very efficient and provide uniform distribution and action on each tray. Bubble caps provide intimate contact between the descending liquid and the ascending vapor. Although bubble cap trays provide effective fractionation, they have been replaced to a great extent by valve trays. Bubble cap trays provide an excellent means of explaining the action that takes place in a fractionator, as shown in figure 3.3

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Figure 3.3 – Fractionator in action

NGL Supply to Mellitah.

Raw gas and unstabilized condensate, coming from Sabratha Platform by means of two different submarine pipelines, are received and sent to the treatments facilities. Condensate is sent to two identical condensate stabilization units. The produced stabilized condensate is delivered to the storage, while the off-gas also produced at the stabilization unit is joined with the raw gas stream coming from pipeline. The gas from the pipeline, jointly with the off-gas, is sent to three identical gas treatments trains. Each of them is composed by a sweetening unit, a dehydration unit and a hydrocarbon dew point control unit. In the sweetening unit, the CO 2 and H2S contained in the gas are completely removed and sent to SRU where H2S is converted to liquid sulphur. The sweetened gas is sent to a molecular sieves dehydration unit, where water is removed, and then to hydrocarbon dew point control, where, by means of external refrigeration, heavy HC are condensed and separated in order to match the sales gas characteristics. The recovered NGL from the dew point control unit is sent to two identical NGL fractionation units. More light components (C1, C2) are stripped out from NGL and sent to the fuel gas network. The liquid is then splitted into a LPG stream that is routed to WAFA Coastal Plant for C3/C4 production, and into a C5+ cut which is sent to storage.

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3.2 - Unit 320 –General process description Unit 320 is designed to separate from the condensate of Unit 340 the Liquefied Petroleum Gas (LPG) and the Natural Gas Liquid ( NGL). NGL is sent to storage while LPG is sent to Wafa Coastal Unit C3/C4 Splitter. Lighter hydrocarbons are routed to Fuel Gas System Unit 420. Last but not least Off-spec NGL condensate, if any, is sent to U nit 210. The Unit 320 is split over two parallel Trains. The following description is relative to Train 1. Train 2 is identical to Train 1. The NGL Fractionation is designed for a 50% turndown referred to the design case. NGL capacities lower than said turndown may affect the distillation operation carried out in the NGL Fractionation due to a too low tray load. The Unit has enough capacity to treat on each line 618.9 kmol/h of NGL condensate (considering Year 2 summer case). The Unit is able to process a NGL feed having a B.L. pressure of 26 barg and a temperature of -33.3°C. The NGL from the two dedicated header collecting liquid streams from Unit 340 is feeding Trains 1 and 2. NGL is fed to the top tray of the Deethanizer 51-320-VE-001 . The overhead vapour is sent to the LPG Subcooler 51-320-HA-004 , where it is heated with the LPG from Debutanizer 51320-VE-002. It is then sent to the Fuel gas network. The deethanizer pressure controller operates on a control valve placed on the gas line to the Fuel Gas network, downstream of the LPG Subcooler. A pressure blow-off valve discharging to HP flare is installed for start-up purpose and upset conditions. The LP Steam flow to the Deethanizer Reboiler 51-320-HA-001 (kettle type) is regulated by a flow controller on the LP Steam inlet, acting on a valve on the LP Steam Condensate outlet and cascaded by a temperature controller placed on the sensitive tray of the column. The Deethanizer bottom product is fed to the Debutanizer 51-320-VE-002 under flow control, cascaded by the Deethanizer bottom level controller. The Debutanizer bottom product is sent under level control to the Debutanizer Bottom Cooler 51-320-HA-005 , wherein it is cooled by cooling water. The cooled product is delivered to storage after mixing with stabilized condensate from Unit 210 or to off spec tank in case of bad quality. Analyser to monitor condensate composition/TVP is provided at cooler outlet. The MP Steam flow to the Debutanizer Reboiler 51-320-HA-002 is controlled with a flow controller on the MP Steam inlet, acting on a valve on the MP Steam Condensate outlet and cascaded by a temperature controller placed on the sensitive tray of the column. The Debutanizer overhead vapour is sent to the Debutanizer Condenser 51-320-HA-003 , and then to the Debutanizer Reflux Drum 51-320-VA-001. The pressure controller on the Debutanizer operates on the hot bypass of the Debutanizer Condenser. The condenser operates partially flooded. In case from debutanizer is producing a vapour amount larger than condensing capacity, pressure increases in the column. The valve on hot by-pass reacts closing. This increasing differential pressure between inlet of condenser and reflux drum. Liquid is pushed out from exchanger until the increased surface available for condensation balances vapour production. In case of pressure in excess over the normal one due to not condensable in the Reflux Drum, a pressure control valve is provided venting to the HP Cold Flare.

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The liquid from the Debutanizer Reflux Drum is pumped by the Debutanizer Reflux Pump 51-320-PA-001A/B and split into two streams: Debutanizer Reflux and LPG product. Reflux is flow-controlled while LPG is sent, under flow control cascaded by Debutanizer Reflux Drum level control, to the LPG Subcooler where it is cooled down by means the Deethanizer Overhead gas. The LPG Subcooler outlet temperature controller operates on the control valve placed on the subcooler bypass, Deethanizer overhead gas side. The subcooled LPG is then mixed with the corresponding stream from Train 2. This combined LPG stream is sent to Wafa Coastal Plant (Mellitah) for splitting in propane/butane products.

3.2.1 Main Equipments of NGL Fractionation Plant

• Deethanizer

51-320-VE-001

• LPG Cooler

51-320-HA-004

• Deethanizer Reboiler

51-320-HA-001

• Debutanizer

51-320-VE-002

• Debutanizer Reboiler

51-320-HA-002

• Debutanizer Reflux Pumps

51-320-PA-001A/B

• Debutanizer Condenser

51-320-HA-003,

• Debutanizer Bottom Cooler

51-320-HA-005

The Deethanizer 51-320-VE-001 is a fractionating column with the diameter of 1700/2100 mm and the height of 31110 mm. It operates at –1/140°C (top/bottom) and 25 barg. The Debutanizer 51-320-VE-002 is a fractionating column with the diameter of 1700/2200 mm and the height of 35000 mm. It operates at 96/191°C (top/bottom) and 21 barg. Debutanizer Condenser 51-320-HA-003 is of the shell-and-tube type, with the LPG flowing through the shell side and the cooling water flowing through the tube side. The inlet temperature of LPG is 97°C and the pressure 21 barg, while outlet temperature will be 38°C and the pressure 19.5 barg. For the c ooling water the temperatures are 32/44°C . LPG Sub-cooler 51-320-HA-004 is a shell-and-tube exchanger, with the deethanizer overhead

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gas flowing through the tubes and the LPG flowing through the shell. LPG is cooled down from 38°C to 26°C, with a pressure drop from 31 barg to 27 barg, while the Deethanizer Overhead gas is warmed up from –1°C t o 28°C with a pressure drop from 25 to 24.5 barg. Debutanizer Bottom Cooler 51-320-HA-005 is of the shell-and-tube type, with the NGL flowing through the tube side and the cooling water flowing through the shell tube side. The inlet temperature of NGL is 190°C and the pressure 21 barg, while outlet temperature will be 40°C and the pressure 19 barg. For the c ooling water the temperatures are 32/44°C .

Figure 3.4 – Common Shell and Tube Heat Exchanger

Deethanizer Reboiler 51-320-HA-001 is a shell-and-tube type Kettle reboiler. The internal diameter is 1.27 m, the length is 6.8 m . The reboiler service is to supply the additional heat t o deethanizer by means of the LP steam condensation. The hydrocarbon flowing through the shell (76590 kg/h), is heated up from 118°C to 137°C, at a pressure of about 25.3 barg, while the LP steam, flowing through the tubes (6500kg/h), is condensed and cooled down from 170°C to 150°C. Debutanizer Reboiler 51-320-HA-002 is a shell-and-tube type Kettle reboiler. The internal diameter is 0.9 m, the length is 4.8 m . The reboiler service is to supply the additional heat to debutanizer by means of the MP steam c ondensation. The hydrocarbon flowing through the shell (85758 kg/h), is heated up from 182°C t o 190°C, at a pressure of about 21.3 barg, while the MP steam, flowing through the tubes (7477 kg/h), is condensed and cooled down from 235°C 0 to165 C . Debutanizer Reflux Pumps 51-320-PA-001A/B are horizontal centrifugal type, electric 3

motor driven, with a design capacity of 110 m /h each and a delivery pressure of barg. They operate at a temperature of 48°C.

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Figure 3.5 – Kettle Type Reboiler

Figure3.6 – A typical arrangement for using a Kettle-type reboiler

The location of each item is visible in Figure 3. 7

3.2.2 - Detailed Process Description

As reported previously the header collecting liquid streams within Unit 340, (op. parameters – 32°C and 27.5 barg), is split into two streams feeding the above mentioned Trains 1 and 2. The splitting is controlled by the level controller “cascaded” on the two flow controllers (one for each branch). The 8" line directed to train 1, provided with isolation and drain facilities, is fed to the top tray of the Deethanizer 51-320-VE-001 . It is important to control the temperature and the pressure of the column. The Deethanizer operates at 25 barg. The column pressure controller, operates a control valve

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located on the gas line to the Fuel Gas network (downstream the LPG Sub-cooler 51-320-HA004). The pressure blow-off valve operated by another pressure controller may discharge to HP Flare for start-up purpose and during upset conditions. The overhead vapour (–1°C and 25 barg), is sent to the LPG Sub-cooler 51-320-HA-004, where it is heated up to 28°C by the LPG from Debutanizer 51-320-VE-002 . The flow of Deethanizer overhead gas through tube bundle of the LPG Sub-cooler 51-320HA-004 is controlled modulating the temperature of the LPG f lowing through the shell side. The LPG temperature monitoring is performed by a temperature controller driving in split range two control valves (the first one being placed on the by-pass of the exchanger. As previously said, the deethanizing process requires external heat that is supplied by the Deethanizer Reboiler 51-320-HA-001 heated with low steam and returns pressure steam. The stream of the Deethanizer product, at 118°C, is withdrawn from the chimney tray (by means of a 10" line) and flows to the Reboiler, gets partly vaporized absorbing heat from the steam and returns to the Deethanizer through a 12" line at 137°C. The flow of LP Steam is controlled by the controller set by a tray temperature controller. The remainder flows back to the bottom of the Deethanizer at the same temperature. The Deethanizer bottom product flows to the Debutanizer 51-320-VE-002, at 136°C and 25.3 barg, through a 8" line, under fl ow control. The Debutanizer 51-320-VE-002 is a fractionating column operating at –1/140°C (top/bottom) and 25 barg. The Debutanizer bottom product, at 191°C and 21 barg, flows, through a line under level control to the Debutanizer Bottom Cooler 51-320-HA-005, where it is cooled (by cooling water) down to 40°C. The cooled product is delivered to storage facilities or to off- spec tank in case of bad quality. On the li ne of NGL to storage are installed isolation facilities. The analyzer 51-320-AT-002A/B provides condensate composition/RVP monitoring at cooler outlet. Pressure and temperature indicators and transmitters are installed at the battery limit. The debutanizing process requires also external heat, in this case supplied in the Debutanizer Reboiler 51-320-HA-002 by medium pressure steam. A stream of the Debutanizer product, withdrawn from the chimney tray at 182°C and 21 barg, by means of a 10" line flows to the Reboiler, gets vaporized (partially) absorbing heat from the steam and returns, at 190°C, to the Debutanizer by means of a 12" line. The remainder flows back to the bottom of the Debutanizer through a 6" line. The MP Steam flow is controlled by the flow controller, reset by tray temperature controller. The Debutanizer overhead vapour, at 97°C and 21 barg, flows to the Debutanizer Condenser 51-320-HA-003, and further on to the Debutanizer Reflux Drum 51-320-VA-001. The 10" overhead line from the debutanizer is provided with temperature and pressure instrumentation and depressurization facilities. The Debutanizer Condenser 51-320-HA-003 operates at 97/38°C (inlet/outlet) and 21 barg, while the Debutanizer Reflux Drum 51-320-VA-001 operates at 38°C and 20.8 barg. The Debutanizer Condenser 51-320-HA-003 is a shell-and-tube exchanger, with the LPG vapour flowing through the shell and the c ooling water flowing through the tubes. The pressure controller on the Debutanizer located at the centre of the column, operates on the hot 4" bypass of the Debutanizer Condenser acting on the control valve. The condenser operates partially flooded. If from debutanizer is flowing a vapour amount larger than condensing capacity, the pressure in the column will increase and the valve on hot by-pass tends to close. This increases the differential pressure between inlet of condenser and reflux drum thus pushing liquid out from condenser until the increased surface available for

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condensation balances vapour production. In case of pressure in excess, over the normal value due to “not condensable” in the Reflux Drum, the pressure control valve, operated by the pressure controller of the Reflux Drum, provides venting to the cold fl are, of the excess gas. The Debutanizer Reflux Drum 51-320-VA-001 is protected by the two pressure safety valves discharging to the cold flare. Also discharging to the cold flare, but through a restriction orifice, there is a blow-down valve, operated by an interlock. The liquid from the Debutanizer Reflux Drum is pumped by the Debutanizer Reflux Pumps 51-320-PA-001A/B and split into two streams: • Debutanizer Reflux • LPG product The Debutanizer Reflux Pumps 51-320-PA-001A/B are horizontal centrifugal type, electric motor driven, with a design capacity of 110 m3/h each. Debutanizer Reflux flow is controlled by means of a flow control valve, 51-320-FV-009, when flowing to the head of the column. LPG is directed, under flow control to the LPG Subcooler 51-320-HA-004 where it is cooled-down by the Deethanizer Overhead gas as previously explained. The LPG Sub-cooler 51-320-HA-004 is a shell-and-tube exchanger, with the deethanizer overhead gas flowing through the tubes and the LPG fl owing through the shell. LPG is cooled down from 38°C to 26°C, with a pressure drop from 31 barg to 27 barg, while the Deethanizer Overhead gas is warmed up from –1°C to 28°C with a pressure drop from 25 to 24.5 barg. The LPG Sub-cooler 51-320-HA-004 outlet temperature controller operates on the control valve placed on the sub-cooler by-pass (Deethanizer overhead gas side). The sub-cooled LPG is mixed with the corresponding stream from Train 2. The combined LPG stream finally is directed to Wafa Coastal Plant (Mellitah) for splitting into propane/butane products.

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Figure 3.7 - NGL Fractionation-unit 320 – Process flow diagram

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3.2.3 - Process Variables

In order to produce products that meet the required specifications the following variables must be controlled: •

The reflux rate.

•

The reboiler heat input.

•

The fractionator pressure.

•

The feed rate.

•

The feed temperature.

• The Deethanizer bottom operating pressure is automatically controlled and kept at 25.3 bar; this pressure combined with Tray 17 temperature automatically controlled meet the required deethanized NGL condensate that is fed to debutanizer. • The Debutanizer operating pressure is automatically controlled and kept at 21.3 bar; this pressure combined with the Tray 29 temperature automatically controlled meet t he required debutanized NGL that is sent to storage. a) The main process variable on deethanizer section are: • Temperature of Tray 17 set at 52°C by 51-320-TIC-003(18) in cascade with 51-320-FIC003 that controls the steam flow to Deethanizer Reboiler 51-320-HA-001. An increase of the said temperature without changing other parameters will increase the vapour rate through the Tray and will transfer heavy component from bottom to top of column. This results in diminishing the deethanized bottom flow and in more off-gas; a contrary effect is obtained lowering this temperature; light component is supposed to remain i nto the bottom liquid of deethanizer meaning the product is not “deethanized”. • Deethanizer bottom pressure is set at 25.3 barg by 51-320-PIC-005(19) operating the pressure valve on deethanizer vapour line. Increasing this pressure light component remain in the bottom liquid of deethanizer and as result the bottom product will increase and it is not deethanizer; on contrary lower pressure allows that some heavy components are transferred to top of deethanizer, in this case the off gas will increase and it is out of specification due to heavy component.

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b) The main process variable on debutanizer section are: • Temperature of Tray 29 controlled at 148°C by 51-320-TIC-021 in cascade with 51-320FIC-008 that operate the steam flow to Debutanizer Reboiler 51-320-HA-002. An increase of this temperature without changing other parameters, increase the vapour rate through the Tray and transfer heavy component from bottom to top of column the principal effect is on debutanizer bottom flow that decrease and the overhead product (LPG) flow that will increase and out of specification due to heavy components; the contrary is obtained lowering this temperature; light component remain in the bottom liquid of debutanizer and as result the product is not debutanized. • Pressure on bottom of debutanizer is c ontrolled at 21.3 barg by 51-320-PIC-013 operating the hot by-pass valve of debutanizer condenser. Increasing this pressure together with the pressure of debutanizer overhead accumulator allows that light component can remain in the bottom liquid of debutanizer and as result the bottom product will increase and it is not debutanized; on contrary lowering pressures allows that some heavy components are transferred to top of debutanizer, in this case the LPG product will increase and it is out of specification due to heavy component. Conclusion: During routine inspection keep an eye on the instrumentation/parameters reported in Table 3.1. Table 3.2. re ports the analysis of NGL that may be very important for the operator of this unit. . Table 3.1 – Main local indicators Variable Level Temperature Temperature Pressure Pressure Pressure Pressure

Equipment/service

Instrument tag

51-320-VE-001

51-320-LG-301

51-320-VE-001 51-320-VE-001 FG to FG Unit FG to FG Unit LPG from 51-320-PA001A/B LPG to 41/42-320XX001

Range

51-320-TI-321 51-320-TI-319 51-320-PI-305 51-320-PI-305

0-100%(3806280 mm) - 30 – 60 0C 0 0 – 60 C 0 – 40 barg 0 – 40 barg

51-320-PI-306

0 – 60 barg

30.6 barg

51-320-PI-316

0 – 40 barg

27 barg

Table 3.2 – NGL Condensate Analysis Analysis C1 – C3 i C4 C4 i C5 C5 – C6

Normal op.value/Set point 46% (3100 mm) 0.00C 0 39 C 26 barg 25 barg

Method ASTM D 2597 ASTM D 2597 ASTM D 2597 ASTM D 2597 ASTM D 2597

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3.2.4 - Control System

Deethanizer Temperature and Pressure Control

Reference P&ID: DEETHANIZER

G-65-D-O-103201

UNIT

51-320

–

NGL

FRACTIONATION

Flow of LP Steam is controlled by the controller 51-320-FIC-003, reset by sensitive tray temperature controller 51-320-TIC-003 and controlled by the interlock 51-320-I5001, driving the control valve 51-320-FV-003 placed on the steam condensate outlet. The deethanizer pressure is controlled by 51-320-PIC-005. The Deethanizer bottom product flows to the Debutanizer 51-320-VE-002, at 136°C and 25.3 barg, through a 8" line under flow control operated by 51-320-FIC-004, cascaded by the Deethanizer bottom level controller 51-320LIC-001.

Figure 3.8 – Deethanizer Control

Debuthanizer Temperature and Pressure Control

Reference P&ID: DEBUTHANIZER

G-65-D-O-103203

Unit

51-320–

NGL

FRACTIONATION

Flow of MP Steam is controlled by the controller 51-320-FIC-008, reset by sensitive tray temperature controller 51-320-TIC-021 and controlled by the interlock 51-320-I5001, driving the control valve 51-320-FV-008 placed on the steam condensate outlet.

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Figure 3.9 – Debuthanizer Control

3.3 - Start – up of NGL fractionation • Check the level increase on bottom of deethanizer; gradually open 51320-FV-003 located on SC condensate from deethanizer reboiler Check the temperature and pressure increase; the gas will be flared by operation of 51-320-PIC-002. • When the temperature on tray 16 reaches 100°C put 51-320-TIC-003 in cascade with 51-320-FIC-003, in auto mode.

• When the level on bottom of deethanizer is about 50%, NGL is fed to debutanizer by operation of LIC. • When the operating conditions of deethanizer are steady, then increase the set point of 51-320-PIC-002 so that the gas is not flared and sent to fuel gas system by operation of 51-320-PIC-005. • Check the level increase on bottom of debutanizer and as soon as level is detected, gradually open 51-320-FV-008 condensate from Debutanizer Reboiler 51-320-HA-002 Check the temperature and pressure increase; check the operation of hot by-pass of 51-320-HA-003 and operation of 51-320-PIC-017; excess of gas will be flared by this controller. • Check the debutanizer temperature and when t he temperature on tray 29

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reaches 160°C put 51-320-TIC-021 in cascade with 51-320-FIC-008 in auto mode. • Check the pressure on bottom of debutanizer; put 51-320-PIC-013 (hot by-pass in auto at 21 bar. • Check the level increase on Debutanizer Reflux Drum 51-320-VA-001 and as soon as level is detected, start Debutanizer Reflux Pump 51-320PA-001 and operating 51-320-FIC-009 reflux the liquid to top try of debutanizer. • When the level on bottom of debutanizer is near 50%, the product is sent to send off spec NGL to 50-210-VA-004 Degassing Boot. • When the level on Debutanizer Reflux Drum 51-320-VA-001 is near 50%, LPG is sent to fed unit 41. • Adjust the operating conditions of debutanizer to meet the NGL condensate on spec then open 51-320-MOV-004 to send on spec NGL to storage and close 51-320-MOV-002 off spec NGL to 50-210-VA004 Degassing Boot.

3.4 - Shut Down Procedure A reported previously two parallel trains (51 and 52), each designed for 66.6% of total capacity, are foreseen for NGL Fractionation. If the train is scheduled to remain shut for a long period, it shall be better to also shut down one train of the upstream Unit 340 Gas Dehydration. In any case, the feed rate to the running train has to be increased at 100% capacity of the train, to match the production capacity of the two running trains of Unit 340. If the shut down is of short duration, keep the three trains of Unit 340 running at lower capacity, say 16.6% of total plant ca pacity, corresponding to 50% capacity of each train. Proceed as follows: 1) Start to reduce slowly the NGL condensate feed to the deethanizer column down to 50%, by reducing manually FIC303/304 on 340VA001 outlet line; in the transitory phase, the excess NGL condensate in 340VA001 may be drained to CB in order to maintain the level in 340VA001

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2) Gradually shut the steam to the deethanizer reboiler HA001 and to the debutanizer reboiler HA002 by acting on the relevant steam flow rate controllers. 3) Shut the relevant steam condensate outlet on off valves SDV010 and SDV011. 4) Shut the NGL condensate feed to the deethanizer column on valves SDV001/A and SDV001/B 5) Stop the debutanizer reflux pumps PA001A/B and shut the discharge valve 6) Shut the LPG flow control valve FV006 to Wafa Coastal Unit C3/C4 splitter 7) Keep running the circulation of cooling water in the debutanizer condenser HA003 till the column is cooled at ambient temperature.

3.5 Common Troubleshooting

There are four problems associated with fractionators and each must be treated so as to solve the problem and not the symptom. • There is too much bottom product in the top product. • There is too much top product in the bottom product. • Both products are bad. • The tower is carrying over. When the top product contains too much bottom product, the top temperature will go up because the bottom product has a higher boiling temperature than the top product. When the bottom product contains too much top product, the bottom temperature will drop because the top product has a lower boiling temperature. Before any change is made to a fractionator that is producing off specification product, the other product must also be checked. If the re is too much bottom product in the overhead

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product, check the bottom product also to see what is happening in the tower.

Temperature Top goes up

Change Temperature

Top goes down

Temperature

Bottom goes down

Temperature

Bottom goes down

Temperature

Cause of change More bottom product in product Less bottom product in product Less top product in product More top product in product

top

Effect of Purity Top product less pure

top

Top product purer

bottom

Bottom product purer

bottom

Bottom purer

product

less

Table 3.3 - Product purity and change in t emperature

The following checks should be made: • Check all instruments, thermometers, pressure gauges, and flow meters to ensure they are giving accurate readings. • Check the feed temperature, if it is not within a few degrees of the temperature of the feed tray, adjust the feed temperature. • Ensure that the pressure controller is maintaining the tower pressure within 2% of the set point. If not, have the instrument adjusted. • Check that the reflux ratio controller is maintaining the desired reflux ratio on units so equipped. • Check both products to confirm that one or both products are off specification. • Ensure that the tower is not being fed in slugs. A level control on another fractionator or the fractionator feed tank may be cycling and causing the problem. Have the defective level controller adjusted or repaired. • Observe the flow of heating fluid to the reboiler. If the flow is cycling have the controller adjusted or repaired. • Check the overhead condenser. If it is water cooled there should be a difference in water temperature through the exchanger. A high pressure drop on the water side indicates fouling of the tubes and the exchanger may have to be cleaned. Check the fan speed and blade pitch, and for dirt or an obstruction if it is an aerial cooler. • Check the reflux pump, if it is cavitating there may be insufficient reflux

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