buku pintar migas

BUKU PINTAR MIGAS INDONESIA

PROCESS ENGINEERING AND

SAFEGUARDING THEORY

Engineering passion series – 2009 publication

Limited explanation for Pressure Vessel, Pump and Compressor

A compilation by:

Alvin Alfiyansyah Ronaldo Reagan

Process Engineering and Safe Guarding Theory Halaman 1 dari 1 Kontributor : Alvin Alfiyansyah dan Ronaldo Reagan


PROCESS ENGINEERING AND SAFEGUARDING THEORY

CONTENTS ……………………………………………………………………………........ 2 1. PRESSURE VESSEL ………………………………………………………………… 4

1.1. Definition of Pressure Vessel (Separator)……………………………………… 4 1.2. General Requirements and Representation in PFD/P&ID…………………… 6 1.3. Engineering Requirements …………………………………………………….. 6 1.4. Major Type of Separator………………………………………………………… 8 1.5. Piping Engineering Requirements …………………………………………….. 22 1.6. Instrumentation Requirements ………………………………………………... 25 1.7. Equipment Protection Requirements …………………………………………. 25 1.8. Operational Aspect Requirements and Failure Modes ………………………. 27 1.9. Vessel/Separator Calculation Theory ………………….……………………… 42

2. PUMPS ………………………………………………………………………………… 50

2.1. Description ……………………………………………………………………… 50 2.2. Pump Classification ……………………………………………………………. 50 2.3. Safety Device ……………………………………………………………………. 56 2.4. General Requirements………………………………………………………….. 59 2.5. Engineering Requirements…………………………………………………….. 59 2.6. Equipment Protection Requirement…………………………………………… 65 2.7. Pump Common Operational Aspect and Failure Modes…………………….. 68 2.8. Basic Selection Criteria………………………………………………………… 69 2.9. Equipment Selection and Design………………………………………………. 72

3. COMPRESSOR …………………………………………...…………………………. . 85

3.1. Definition of Compressor …………………………………………………….... . 85 3.2. Selection of Compressor ...……………………………………………………… 85 3.3. Process Condition and Limitation ……………………………..……….……… 92 3.4. General Requirements…. ……………………………………………….……… 104 3.5. Engineering Requirements…. ….………….…………………………………. . 104 3.6. Piping and Instrumentation Requirements…. ….……………..……………… 105



Below is basic engineering study comprising explanation of several

equipments that have been often used in Oil and Gas Industry especially in upstream operations. Reader shall take his/her own

consideration during thoroughly use part of this article for engineering purpose.



1. PRESSURE VESSEL

Commonly known in production and process system as Separator, Scrubber and various Knock Out Drums.

1.1 Definition of Pressure Vessel (Separator)

A separator is a vessel used in oil fields to remove well-stream liquid(s) from the gas. The separators may be either 2-phase or 3-phase and may be either vertical or horizontal. 2-phase type remove the total liquid from the gas, while 3-phase type remove not only total liquids, but also remove free water from liquid phase (hydrocarbon). 3-phase separator may use a boot to collect free water removed/separated from hydrocarbon liquid. Separation vessels usually contain as follow: A – Primary Section. B – Secondary Section (Gravity Settling). C – Coalescing Section. D – Sump or Liquid collecting Section.

Figure 1.1 Theory of Separation Process at Horizontal Separator Section A is used to separate the main portion of free liquid (bulk of liquid droplets) in the inlet stream. It contains the inlet nozzle which may be tangential, a diverter baffle, or half open pipe to take advantage of the inertial effects of centrifugal force or an abrupt change of direction to separate the major portion of the liquid from the gas stream. Section B is designed to utilize the force of gravity (of liquid droplets having big dimension) to enhance separation of entrained droplets. It consists of a portion of the vessel through where the gas moves relatively lower than maximum allowable vapor velocity with little turbulence.



Section C utilizes a coalescer or mist extractor to separate the very small droplet of liquids from the gas by impingement on a surface where they trapped, coalesced, collected and grow become bulk droplet sizes and then removed fall to the bottom vessel through gravity settling. In vertical vessel, where mist extractor is horizontal position, bulk droplet of liquid fall down to the bottom vessel counter current flow direction from gas flow direction.

Figure 1.2 Theory of Separation Process at Vertical Separator

Section D can be called as the sump or liquid collector which acts as receiver for all liquids separated from the gas in the section A, B, and C.

Figure 1.3 Gravity Settling Theory (2001 ASHRAE Meeting in Cincinnati, Nestle USA)



1.2 General Requirements and Representation in PFD/P&ID General requirement and representation of separator system in PFD/P&ID: A. Symbols, identification and essential internals, and the outline should be as simple as

practical, including all essential such as sump, domes and body flanges. B. The relative size and elevation, although not to scale, should be indicated specially for

critical elevation. C. Skirts and support should be shown in P&ID for good representation. Height of skirt shall

be indicated if P&ID will be used for construction or to have AFC (Approved for Construction).

D. Pressure vessel determined here can be scrubber, separator, filter separator, knock out drum, pulsation bottle, pig launcher, pig receiver, slug catcher, solid bed dehydrator and column.

1.3 Engineering Requirements

Engineering requirements for separators: A. As stated on above paragraphs, a pressure vessel acting as a complete separator must

have the following: - A primary separation section to remove the bulk of the liquid from the gas. - Sufficient liquid capacity to handle surges of liquid from gas line. - Sufficient length or height to allow the small droplets to settle out by gravity (to

prevent undue entrainment). - A means of reducing turbulence in the main body of the separator so that proper

settling may take place. - A mist extractor to capture entrained droplets or those which are too small to settle by

gravity. - Prime function by of a separator are separation of vapours from liquid, separation of

two immiscible liquid phase, separation of solid particles from liquid phase, hold-up volume for liquids. The final design of the vessel should be able to perform one or more of above listed functions as per the need of the process.

B. A separator can be vertical or horizontal, also spherical vessel may also be used for high

pressure and high liquid hold up system like storage of light liquid hydrocarbon, etc. The choice between horizontal and vertical primarily depend upon following process requirements: relative liquid and vapor load, availability of plot area, economics, and special consideration. Horizontal separators can be single or double barrel and can be equipped with sumps or boots and also equipped with weir plate if it has function as 3 phase separation. From process point of view of relative liquid and vapor load consideration, general guidelines are summarized below:



Table 1.1 Guidance to Determine Type of Vessel

SELECTION GUIDELINES FOR TYPE OF VESSEL (HORIZONTAL OR VERTICAL)SYSTEM CHARACTERISTICS TYPE OF VESSEL

Large vapor load, less liquid load (by volume) Vertical Large liquid load, less vapor load (by volume) Horizontal Large vapor load, large liquid load (by volume) Horizontal with split flow∗ Liquid-Liquid separation Horizontal Liquid-Solid separation Vertical ∗Split flow vessel has got one entry in the centre and two vapor outlets on each end, head exits can be used where plot space is limited.

Provided L/D ratio is selected a horizontal vessel is more efficient than a vertical for

the same flow area. Vapor velocity in a horizontal vessel can exceed the liquid settling velocity so provide

L/D >1, but not for vertical vessel. Horizontal vessels are more effective and geometrically more practical for a heavy

liquid phase removal than vertical vessel. Horizontal separators generally give large interface area and may give long retention time that is needed to remove the gas from the liquid where Liquid/Gas Ratio is great. This separator is also good for liquid-liquid separation.

A rising liquid level in a vertical vessel does not alter the vapour flow area. Consequently vertical vessels are preferred for compressor and fuel gas Knock Out drum.

Vertical vessels utilize a smaller plot area and are easier to instrument with alarms and shutdown control. For floating installation are preferred as less “sloshing” occurs.

C. In horizontal vessel, representation in PFD/P&ID, the vapor and liquid outlets including

the possible water sump, shall be located at the opposite side of the inlet (at a minimum distance from tangent line).

D. All inlets, where liquid may enter, are preferably to be provided with deflector when no

other device is specified for process reasons.

E. All liquid outlet nozzles shall be provided with vortex breakers. Internally extended vortex breaker shall be used in fouling service and for hydrocarbon liquid outlet where the liquid is separated from water or aqueous solutions to prevent water from entering product.

F. Avoid vessel with thickness greater than 100 mm as these require special fabrication and

can prove expensive cost.

G. Count down the following critical data to count the trains required: 1. Number of Reservoir.

The number of separation trains is also influenced by the number of production reservoirs. If more than one reservoir is being produced, and the available flowing wellhead pressure (FWHP) can not match the other reservoirs, a second separation train may be needed.



If the available FWHP from the second reservoir is sufficient to match the second stage of separation of the first reservoir, then the second reservoir production can be separated in the second stage of a single train of production separators.

2. Gas/oil Ratio.

The gas/ratio influences the diameter of separators, and will influence the decision to retain a single train. At a higher gas/oil ratio, vessel diameter will increase for the same amount of crude produced because gas flow rates will control vessel size.

3. Wax Content.

The wax content may influence the number of separation trains. Production could be interrupted by shutdown of the separation train if wax build-up (swelling) occurs and the separation train vessels need to be steamed, or cleaned in some other manner. Usually, in sizing the piping for 2-phase (gas and oil), swelling factor is considered.

Thus, if wax content is high and processing conditions require heating, upsets in the heating system could occur, and more than one train of crude separation would be favored.

4. Sand Content.

If the sand content of the reservoir fluid is severe and not controllable by gravel packing at the reservoir face, cleanout of the crude separator may be required.

Under these maintenance conditions, more than one separation train would be favored to avoid interrupting crude production.

5. Turndown Ability.

The turndown ability of a large single train of crude separation is a concern. This concern can be overcome by use of dual control valves on the liquid and gas outlets, sized to accommodate the full flow range.

Another method to accommodate low flow rates would be to use the test separator as a start up separation vessel until full crude production permits the larger single train operation. Configuration may be a big production separator with highest flow rate and 2 small test separators with low flow rate or may be 2 big production separators and 2 small test separators.

6. Availability.

Equipment components can be evaluated to determine statistical reliability, a factor which may support the case for more than one train of separation. In the past, however, this evaluation has not been an overwhelming reason to decide for two or more trains. Other considerations, as discussed herein, will affect this decision.

Usually, redundancy of vessels does not in itself improve availability of the process unless the characteristics of the fluid being processed force frequent cleanouts (sand, scale clogging). However, redundancy of instruments, valves, and pumps can improve availability since these items have relatively high failure rates.



1.4 Major Type of Separator

Major type of separators used in the oil /gas/water separation process is described in the following paragraphs.

a. Test Separator

A test separator determines the oil, water and gas properties of each producing reservoir or well, and monitors the reservoir's productivity. A standard test separator would separate and measure the oil, water and gas phases. The liquids have their densities measured by an accurate densimeter after the oil and water are completely separated in a test container. A conventional test separator may be horizontal or vertical. The test separator is sized for the maximum "best" full well potential and anticipated gas and water rates. The operating pressure of the test separator would be the same operating as the first stage separator. The size of the test separator is normally fixed by the residence time required for oil/water separation.

Figure 1.4 3-phase Test Separator (www.slb.com)

b. Production separator

A production separator is used to separate liquid and gas phases of well fluid. The separation process would be followed by other process treatments to produce the required quality of the produced liquid and gas. A production separator as a unit process may be a series of a first stage production separator and a second stage production separator. The type of separator may be a horizontal or vertical separator and the separation type may be a two-phase separation or a three-phase separation.

c. Knock Out Drum A Knock out drum is a type of separator which falls into one of two categories: free water and total liquid knock outs. This drum is provided when liquid separation is likely in the waste line. Knock out drum is important if substantial cooling of heavy liquids is possible considering winter conditions. A level gauge and drain connections are built into the knock out drum.


http://www.slb.com/


Figure 1.5 Knock Out Drum (www.mrw-tech.com)

d. Free Water Knock Out Drum (FWKO Drum)

A free water knock out drum is used to separate free water from well-fluids (streams of gas, oil and water). Type of the separator is a three-phase separator and the gas and oil usually leave the vessel through the same outlet to be processed by other equipment. The water is removed from disposal.

Figure 1.6 Free Water Knock Out Drum (www.alliedeq.com)

These vessels are often used upstream of a treater to help separate and remove excess free water from the oil-water emulsion so the energy is not wasted in heating the free water within a fired treating vessel. Standard design is 50 – 75 psi. These vessels can be heated or cold depending on the design requirements.


http://www.mrw-tech.com/

http://www.alliedeq.com/


e. Total Liquid Knock Out Drum The total liquid knock out is normally used to remove the combined liquids from a gas stream.

f. Flare Knock Out Drum This equipment is as same principle as Knock Out Drum located between Blow Down Valve/BDV (include R.O.) and Flare or Vent Stack. The purpose is to separate liquid produced from depressurization at BDV before the gas inlet to Flare or Vent Stack.

Figure 1.7 Flare Knock Out Drum (www.crimtech.com)

Figure 1.8 Flare Knock Out Drum above Ground (www.tornadotech.com)


http://www.crimtech.com/

http://www.tornadotech.com/


Figure 1.9 Flare Knock Out Drum below Ground (www.tornadotech.com)

g. Regeneration Gas Knock Out Drum

Regeneration Gas Knock Out Drum (vertically orientation) using horizontal wire mesh pad is used to separate free-water from the regeneration gas used in Molecular Sieve Dehydration Unit after the gas is used to regenerate (heating phase) the dehydrator and condensed in cooler. This separator generally has internal coating with epoxy or polyester to protect the shell made by carbon steel from water corrosion.

h. 3-phase gravity separators 3-phase gravity separators are one of the main surface production units in the petroleum industry. They are used to separate hydrocarbon streams produced at the facility into their component phases: gas, oil, and water, by gravity settling based on difference in density and droplet sizes. Depending on the philosophies used to control the liquid-liquid phases, horizontal separators come in 3 configurations: interface control with boot, interface control with weir, and bucket & weir. A weir is used to maintain the oil level separated from the water level. Example type of weirs is vertical weir plate which is perpendicular from liquid flow. Type of bucket and weir design eliminates the need for all liquid interface controllers. Because the flow enters this separator either directly from a production well or a separator operating at a higher pressure, the vessel must be designed to separate the gas that flashes from the liquid as well as the oil and water. The separated oil is skimmed over a weir or bucket & weir. However, the most common used to be configuration interface control with weir.


http://www.tornadotech.com/


Figure 1.10 Theory of Process Control at Horizontal Separator

The unit receives 3 phase fluid and separates it into gas, oil and water streams through gravity settling. The oil/water interface in the left section is maintained at the desired level controller which manipulates the water outlet valve. The separated oil above water surface is skimmed or floated over the weir to the right section and its level is kept at the desired point by another level controller which also manipulate the oil outlet flow as well as to the water outlet flow at certain control settings to ensure that outlet water is free from oil where as outlet oil is free from water.

Figure 1.11 3-Phase Gravity Separator (www.sog.ca)


http://www.sog.ca/


The gas disengages from the liquid phases and flows horizontally through the vessel length and out from left section of vessel through a mist extractor to ensure that liquid carryover in the effluent gas stream will not exceed 0.1 gallon of particle larger than 10 microns per MMSCF of gas. Separator pressure is regulated by manipulating the gas outlet flow using Pressure Control valve.

Figure 1.12 3-Phase Offshore Production Separator (www.jord.com.au)

i. Scrubber

A scrubber is a type of separator which is designed to separate liquid content from the gas where the feed gas stream has unusually high gas-to-liquid ratios. This separator type usually is used in Glycol plants, Amine contactor plants, extraction plants, instruments, or compressors (include compressor station) for protection from entrained liquids. In Glycol and Amine contactor plants, feed gas is separated from the bulk liquid carryover before inlet to absorber columns. This will minimize inefficiency contact between feed gas and the solvent (absorbent) liquid. Scrubber in compressor station is used to protect the compressor from liquid carryover in the gas which can cause damage to the compressor (liquid slugging), reduce lifetime of bearing, shaft seals, and rotors, decrease in cooling capacity, increase in power consumption. Exception for screw type, the scrubber can be uninstalled where liquid phase may inlet to the compressor section without damaging its compressor.


http://www.jord.com.au/


Figure 1.13 Vertical Gas Scrubber (www.tfes.com)

In refrigeration system, Separators not only act as scrubber to protect compressor unit, they also have functions as follow:

1. Provide sufficient volume for possible swelling and foaming of the liquid charge

caused by sudden pressure reduction. 2. Provide sufficient surge volume for excess liquid returning from evaporators and

return lines. 3. Provide sufficient ballast volume to prevent pumps from starving liquid. 4. Provide sufficient Net positive Suction Head (NPSH) above its required NPSH to

prevent pumps from cavitations.

Figure 1.14 Scrubber (www.allards-international.com)


http://www.tfes.com/

http://www.allards-international.com/


j. 3 phase separator with immersion (internal) heater In condensate stabilization Unit, the column type is always preferred. But, if based on economic and feasible study conclude that energy consumption at reboiler section and dimension of calculated column is not acceptable to achieve stabilized condensate, 3 phase separator heated with electrical (or any other heat sources) immersion heater internally should be considered. Maximum temperature can be 150 oC. Boot should to be provided to collect water droplet separated from mixture fluid. The location of boot should be as far as enough from immersion heater to prevent re-mixture of separated water to the separated gas as water can be evaporated by immersion heater which operated above 100 oC. A temperature gauge should to be placed near and above Boot to check/monitor water temperature in the separator. Location of immersion heater should be downstream section of separator where feed inlet from upstream section below mist extractor. Usually, condensate outlet designed to have maximum BS&W OF 0.5 %. Maximum heating temperature in separator 150 oC can be applicable to result stable condensate where maximum TVP (@ 37.8 oC) 5 psig and RVP (@ 37.8 oC) 10 psia. Furthermore, the criteria are subjected based on company criteria and engineering study.

Figure 1.15 3-Phase Horizontal Separator (with Immersion Heater)

k. Pulsation Bottles / Pulsation Dampener (suction and Discharge)

In reciprocating compressors, the simplest pulsation bottles are pressure vessels which are unbaffled internally and mounted on or near a cylinder inlet or outlet. Performance of volume bottles is not normally guaranteed without a detailed analysis. Volume of bottles is sized empirically to provide adequate volume to absorb most of the pulsation. For more accurate sizing, reciprocating compressor manufacturers can be consulted. Suction pulsation bottles are also designed for the same pressure as the discharge bottle. In reciprocating pumps, pulsation dampener is used and placed both in suction and discharge lines. In suction line, this pulsation dampener act like as a stabilizer to reduce pressure fluctuations at the pump. This pulsation dampener shall be installed as close as possible to the pump. This equipment consists of a small pressure vessel containing a cushion of gas (sometimes separated from the pumped fluid by a diaphragm). Installing pulsation dampener in suction line may not be required if the suction piping is big (oversized) and short, or if the pump operates at less than 150 rpm.



In discharge line, pressure fluctuations also occur. The use of pulsation dampener in discharge line is also effective in absorbing/reducing flow variation caused by pressure fluctuations and should be considered if vibration on the piping appears to be a problem. Discharge pulsation dampener will minimize pressure peaks and also contribute to extend pump life and pump valve life.

l. Spherical Separator This separator is intermittently used for high pressure service where compact size is preferred and liquid volumes are small. Factors considered for this separator are: Compactness, limited liquid surge capacity, and minimum steel for present pressure.

m. Horizontal separators Because of their flexibility, horizontal separators are used successfully as production separators, test separators, wellhead separators, slug catcher, free water knock outs, degassing drum, flare scrubbers, inlet separators and floating production separators.

Figure 1.16 Horizontal oil-Gas Separator (Pecten Cameroon Offshore)

Horizontal separator performance is determined by the characteristics of the fluid being separated, the size of vessel and the type of internals installed. In general, liquid carryover in the effluent gas stream will not exceed 0.1 gallon of particle larger than 10 microns per MMSCF of gas if mist extractor (mist eliminator) is used. These separators are similar to the vertical but handle larger volumes of liquid. If foaming problems are possible, these separators are able to get more surface area on the oil for the foam to break down.


http://www.telusplanet.net/public/compact/products/vertsep.html


Figure 1.17 Horizontal Separator Package (www.gastech.com)

n. Vertical Separators

Vertical type of separator is used when gas/liquid ratio is high to give sufficient space for gravity settling. The main separation takes place with retention time and then the mist pad to remove the smaller liquid particles. Sometimes, where space available is small, vertical type is preferred than horizontal type.

Figure 1.18 Vertical Separator

o. Horizontal Filter Separators

These separators are equipped internally with cartridge filter element in upstream section and Coalescer in downstream section. There is split liquid reservoir to collect separated liquid.


http://www.gastech.com/


Figure 1.19 Horizontal Filter Separator (www.alliedeq.com)

These separators are suited to removal even relatively small quantities of dispersed liquid. This is required in Molecular Sieve Dehydrator Unit where sales gas required very low water dew point. Before the wet gas (having impurities like sands and mechanical) inlet to dehydrator, the gas shall be separated first from water or oil, sands and mechanical dispersed in the flowing gas to decrease loading of liquid and mechanical impurities and protect early damage of Molecular Sieve bed and ensure the life bed/adsorbent as guaranteed by manufacturer.

Figure 1.20 Horizontal Filter Separator (www.ccithermal.com)


http://www.alliedeq.com/

http://www.ccithermal.com/


Figure 1.21 Horizontal Filter Separator (Peerless Mfg. Co.)

From above figure, a section A (first-stage) show that the gas comes into the filter-coalescer section through the inlet nozzle and the T-Feed chamber that distributes the gas flow into two directions, first, the closure end of the vessel (section B) and the outlet end of the first-stage chamber (section C). The flow enters filter element section, named as coalescer (section D). At this section, the main separation is happen where greater solid particles and greater liquid droplets fall down to the bottom of the vessel to be removed and collected in the first-stage liquid reservoir. The fluid having smaller solid particles and smaller liquid droplets will flow to the section E and F. Smaller solid particles and smaller liquid droplets will be trapped in Filters having multi layers (section E) where trapped smaller liquid droplets will be coalesced and combined into larger size. Gas and the coalesced liquid droplets flow into the second-stage, a vane pack section (section F). The vane pack separates the liquid droplets from the gas at high velocity, draining the liquid into the second-stage drain sump for complete removal.

p. Slug Catcher

The gas coming by long distance offshore or onshore pipeline has substantial amount of liquid due to the condensation during transmission in the pipeline. Quite often the liquid comes out at the first equipment in the form of ‘slug’ rather than in uniformly dispersed phase. The slug of liquid can be fairly large often a few KM long and coming in at a high velocity. The equipment to trap the slug and separate out the gas is called Slug Catcher.



Figure 1.22 Horizontal Slug Catcher (webwormcpt.blogspot.com)

Slug catcher is vessel located at the downstream end or other intermediate points of a long distance pipeline to absorb the fluctuating liquid inlet flow rates through liquid level fluctuation. This equipment may be either a vessel or constructed of parallel pipes called fingers type. Sufficient volume must be same for liquid level fluctuation. Mostly, in high pressure operation, fingers type of slug catchers is frequently desired than vessel to avoid wide wall thickness.

Figure 1.23 Horizontal Slug Catcher (www.midcofabricators.com)

q. Pig Launcher

When water presented in piping line for long time, pipeline is pigged to minimize corrosion and this operation will also improve pressure drop-flow rate performance as the water accumulated in sags in the pipeline has main constitution for partial blockages that increase pressure drop. The pipeline is pigged using pig launcher which is designed like as pressure vessel.


http://www.midcofabricators.com/


Figure 1.24 Pig Launcher (www.acpbm.com)

r. Pig Receiver

Pig receiver is used to receive pigged water from the upstream pipeline and acted opposite of pig launcher function.

1.5 Piping Engineering Requirements

A. The number connection on vessel, particularly below liquid level, should be minimized. Nozzle sizes on vessel should not be smaller than 150# class for strength reason.

B. Vents, drains, and utility connections shall be closed with a blind flange or capped.

C. All vessels shall have a high point valve vent. It shall be ensured that the vessel can never

be isolated from this vent when spading off at the process flanges. To prevent pulling vacuum in equipment which is not designed for vacuum, the size of the vent and drain connection shall be the same. As guidelines, vent for process line shall be provided with ¾” NPT.

D. All vessels shall have a low point valved drain. Generally this drain should be located on

the bottom line and outside of the skirt, between the vessel and pipeline shut-off location (spade, valve or blind flange). The drain shall be located on the bottom of the vessel when no bottom line is present, or when the bottom line is not flush with the lowest point of the vessel. As guidance, drain lines for pressure vessel should be sized to empty the required vessel volume by gravity flow within two hours. As guidelines, ½” NPT can be provided for line 1” - 4”, for line 6” - 8” shall be provided with ¾” NPT drain and greater than 10” line shall be provided with 1” NPT drain. Or other guidelines, till 4” line size can be provided with ¾” NPT drain and greater than 6” line size shall be provided with 1” NPT drain.


http://www.acpbm.com/


E. For equipment and piping containing LPG gases, including water drain on LPG vessel, operational drains shall consist of a spring loaded valve and a manual valve located a minimum of 600 mm upstream of the spring loaded valve to prevent freezing and operable from the same location as the spring loaded valve.

The drain line-up to and including the manual valve shall be maximum 2”, and the spring loaded valve and downstream piping should be ¾”. However, for strength reason, the spring loaded valve may be increased to 1 ½” and the downstream piping to 1” for typical process vessel. Prevention against the vapor escaping for vent and drain line to atmosphere is mandatory.

F. A utility connection for purge and steam-out purposed should be installed with 2” valve as guidance. The utility connection shall not be connected permanently to the utility header. If the vessel is divided into more than one compartment, for example by baffles, a utility connection per compartment should be considered.

G. An access opening shall be provided for each vessel. Manhole shall have a minimum

clear inside diameter of 16”-18” as guidelines (usually is 24” used to in Middle East and Center Asia). The nominal minimum diameter for inspection openings (hand hole) is 6” as guidelines. Required size of access openings in a column with removable trays should not be smaller than 10” x 18”, and if no man way is possible, the cover plate of the tray shall be split.

H. Spades and spectacle blinds are used for isolation prior to inspection, testing,

maintenance or entry or personnel. Spectacle blinds have to be provided in the following cases:

In line of equipment which can be blocked in with the unit still in operation. At equipment nozzles of 10” and larger, although the company may choose to use

spectacle blinds for smaller nozzle. At equipment nozzle of rigid piping (i.e. where a spade can not be installed),

regardless of pipe size. For a very large vessel nozzle (i.e. 30”), at location which are difficult to access, an alternative location of the spectacle blind can be considered. Examples of this condition are: • A transfer line from a furnace to large fractionators, where the fractionator’s inlet

flange shall be deleted entirely, because it is prone to leak due to thermal shock during start-up and shut down. The spectacle blind should be located in the furnace outlets. The transfer line now becomes part of the fractionators and should be provided with an inspection manhole at the furnace end and in the top and/or bottom plate of the inlet device.

In this case, it will obviously not anymore possible to pass the inlet device through its own nozzle. This should then be accommodated by nearby manhole. In either case, care should be taken that no other connection exist or will be temporarily made between the vessel and the spectacle blinds that would defeat the isolation of the vessel.



• An overhead line ending in a more convenient condenser inlet nozzle or even dividing up into a number of smaller and more manageable condenser nozzles where the spectacle blinds can be located.

I. Spacer and spades shall be installed instead of spectacle blinds in the following cases:

In lines with operating temperatures below 0 °C. Piping rating 300# and below, where size is 3 inch or below, spade blind can be

useful. Piping rating is 300# or 600#, range temperature from -29 oC – 260 oC and sizes

of inlet or outlet lines of the pressure vessel are above 250 mm (10 inch). Piping rating is 150# and sizes of inlet or outlet lines of the pressure vessel are

above 16 inch.

J. Spectacle Blind shall be installed if (subjected to the user policy): Piping rating is 600# and below, range temperature from -29 oC – 260 oC and size

of inlet or outlet lines of the pressure vessel is below 250 mm (10 inch). Piping rating is 150# and sizes of inlet or outlet lines of the pressure vessel are

below 16 inch.

K. For piping rating is 900# and above (using connection like ring), positive isolation is given by spool piece which is easy to be removed and blind flanges.

L. De-pressurizing, drainage or sample manual globe valve which possible provoke freeze

condition during operation in winter seasons having very low temperature, should be located minimum 600 mm downstream of a block valve. This will protect block valve from getting freezing whenever insulation or heat tracing is used covering the block valve.

M. The valves that are not used when the line or equipment is under pressure (i.e. vent at

vessels) are not installed with DB&B isolation, but isolation may be provided with blind flange.

N. Double block and bleed (DB&B) isolation should be installed on piping line if:

1. Operating pressure > 70 barg, > 35 barg if LNG 2. The presence of H2S where its partial pressure > 1 bar, or 3. Fluid very corrosive and abrasive with high concentration of acid component

including water presence (all chemical component where hydrogen bonded with inorganic should be considered as acidic)

O. Positive isolation may not be required if:

1. At rating pressure (ANSI) 150# RF, piping size < 8” 2. At rating pressure (ANSI) 300# RF, piping size < 6” 3. At rating pressure (ANSI) 600# RF & RJ, piping size < 4” 4. At rating pressure (ANSI) 900# RF & RJ, piping size < 2”

P. Flange connections, 6” and larger in hydrogen service operating above 200 °C, which are

not readily accessible, shall have smothering steam rings with weather protection covers to extinguish a possible fire from leaking hydrogen. For flanges closer to grade, steam



lances can be provided as an alternative. The steam supply line valve to the rings should be operable from a safe distance.

Q. The use of bends outside the vertical plane through the axis of the feed nozzle shall be

avoided within ten pipe diameters of two phase flow inlet nozzle in order not to generate vapor flow maldistribution. In addition, to avoid entrainment in large fractionator (distillation column such as Crude Distillation Unit (CDU), High Vaccuum Unit (HVU), Thermal Gas-Oil Unit (TGU)), the transfer line should run down to feed nozzle without pockets.

R. Where no connection to flare is available for process reason, a manual valve or a valve

with TSH/PSH should be provided for depressuring to flare during shutdown as example in column overhead system. This connection will not be required for units normally operating at sub atmospheric pressure.

1.6 Instrumentation Requirements

A. If a temperature indicator is required at the outlet, it should preferably be located on the top of outlet line.

B. A pressure gauge shall be installed on every vessel and normally located in vapor space.

It should be clearly visible from grade or easily accessible platforms, i.e. installation on the tall vessel or column should be avoided.

C. Where exothermic processes are possible outside the normal temperature range, wide

range thermocouples shall be installed at considered location where exothermic processes will result first in the part side of equipments so that, should an exothermic processes occurs, the maximum temperature can be monitored. This information is important for metallurgical reason. These thermocouples and indicators shall be in addition to narrow range thermocouples and indicators used for control and normal process monitoring (i.e. for hydro treating, hydro cracking, isomerization, polymerization reactors where in situ regeneration take place). In solid bed dehydrator (pressure vessel), it is recommended to install two thermocouples with three thermo elements on top section and bottom section of the bed to monitor heat distribution in the bed during hot regeneration phase.

1.7 Equipment Protection Requirements

A. Pressure relief valves shall be connected to the protected equipment in the vapor space above any contained liquid or to piping connected to vapor space, downstream of the equipment blinding point. Pressure Safety Valve (PSV) should be installed at pressure vessel to protect vessel from over pressure. Set point at PSV shall no higher than maximum allowable working pressure of the vessel. PSV line is vented to atmosphere at safe height or location from operator.

B. High Pressure Sensor (PSH) should be installed as an alarm initiation pressure to give

sufficient time for operator to do safety operation and also use High High Pressure Sensor (PSHH) to shut off inflow fluid to vessel if operator fails to handle over pressure. If fluids inlet to the vessel is coming from a well, PSH and PSHH should always be installed at



vessel considering increase pressure due to change in reservoir conditions, artificial lift, work-over activities, etc.

C. To avoid vacuum condition in the vessel, Low Pressure Sensor (PSL) as an alarm

initiation pressure to give sufficient time for operator to do safety operation and also use Low Low Pressure Sensor (PSLL) to shut off inflow fluid to vessel if operator fails to handle vacuum pressure. PSL and PSLL should always be considered to be installed when possible leaks large enough to reduce pressure occur. Providing a make up system having high pressure can be done to maintain adequate pressure in the vessel from vacuum condition.

D. Height of Liquid level should be controlled with control device both in top side of

maximum liquid level (surge volume) and bottom side. In top side, High Level Sensor (LSH) to give sufficient time for operator to do safety operation and also use High High Level Sensor (PSHH) to shut off inflow fluid to vessel if operator fails to handle liquid over flow level.

E. In bottom side, Low Level Sensor (LSL) as an alarm initiation for operator should be

used and use Low Low Level Sensor (LSLL) to shut off inflow fluid to vessel if operator fails to close liquid outlet at the bottom vessel to avoid gas blowby. In the heated component of vessel (like 3 phase separator with immersion (internal) heater), LSLL should be located above the immersed tubes (hot tube). LSH (include LSHH) and LSL (include LSLL) sensors should be installed in external columns that can be isolated from the vessel.

F. If the pressure vessel is heated, a High Temperature Sensor (TSH) should be installed to shut off the heat source when process fluid temperature becomes excessive. This is applicable at, i.e., 3-phase horizontal separator heated by immersion heater where this separator is used as condensate stabilizer.

TSH sensor should be installed in thermowells for ease removable and testing. The thermowell should be located where it will be accessible and continuously immersed in the heated fluid. Use nozzle with sufficient size for 3 temperature elements if TSH is to be used to sense temperature in the vessel.

G. Consider to install a check valve as flow safety device (FSV) at outlet lines both gas outlet line and liquid outlet line(s) of pressure vessel if significant fluid volumes could back flow from downstream equipment is possible.

H. For vessel fitted with demister (i.e. wire mesh, vane pack), a pressure relief valve

downstream of demister is allowed if the velocity of the largest relief flow is not greater than 3 times that of the design operating flow. The relief connection shall be upstream of demister for larger relief flows. It should be noted that blockage can not occur as result of fouling, solidification, collapse of internals, etc. Otherwise, the relief connection shall be located upstream of the potential restriction.



I. The inlet piping between protected equipment and inlet of relief valve should be designed so that the total pressure loss does not exceed 3% of the valve set pressure. The pressure loss should be calculated using the maximum rated capacity of the pressure relief valve. Excessive pressure loss will cause rapid opening and closing the valve, or chatter. The nominal size of the inlet piping must be the same as or larger than the nominal size of the valve inlet flange. The inlet piping of pressure relief valve shall be self draining back into the process.

J. All process equipment containing under normal operating condition at least 2 tons of

LPG (butane or volatile liquid) shall be provided with remotely operated depressuring valves. High rate depressuring of plant facilities is applied during an emergency. This will for instance, serve to avoid a BLEVE in the event of a fire and can also reduce the consequence of leakage. For the purpose of sizing depressuring system, each unit area shall be divided in probable fire areas. Within each fire area, one depressuring valve can serve a number of equipment items which are normally interconnected and can be isolated as sub system.

K. For 2 phase separator of gas-free water separation, the separators may have internal

coating to protect the shell made by carbon steel from water corrosion as explain on above paragraph.

1.8 Operational Aspect Requirements and Failure Modes

A. During design review, process and piping engineer shall consider appropriate routine access to valves and several instruments in pressure vessels. Main and secondary escape route in pressure vessel position shall be arranged with careful prediction of future piping and instruments modification. Integration of piping plan, equipment plan and instrument plan drawings shall be used to review this purpose during engineering phase.

B. In Commissioning, overfilling with water happens in example for hydro testing when the

vessel or support is not designed for it, might lead to overstressing the shell or bottom head and/or overloading the support or foundation.

C. In Start-up, similar to water, hydrocarbon especially heavy hydrocarbon, can lead to

damage if the equipment is overfilled during start-up and the design has not catered for a full vessel. More frequently equipment is designed for full water load, but the overhead vapor lines or column and transfer line are not.

D. In Start-up, inadequate air removal happens when oxygen left in the vessel, due to

insufficient purging and may lead to internal fire/explosion.

E. In Start-up, inadequate water removal happens when water introduced in hot environments often causes steam explosions resulting in damage to vessel internals.

F. In Start-up, overpressure often happens when spades and spectacle blinds are not

removed or opened and the vessel is isolated from pressure relief valve. Also, when purging with an advertently closed vent will cause pressure build up to the operating pressure of the purge fluid, which can be higher than the design pressure of vessel.



Similarly starting a reboiler before commissioning the overhead cooling system will rapidly overpressure a column.

G. In Start-up, vacuum will happens when developed by inadequate venting when draining a

liquid full vessel or when condensing steam and no gas make up provided for.

H. In Shutdown, inadequate purging happens when air entering vessel caused by inerted improperly, may contact phyroporic iron and start burning when insufficiently wetted, thus initiating a hydrocarbon fire/explosion.

I. In Normal Operation, ingress of air should be avoided because air leaking into system at

sub-atmospheric pressure may cause internal fire/explosion. And small amounts of air may have an adverse effect on product/solvent quality, and be careful when disposed of contaminated air which can cause problem.

J. In Normal Operation, draining water from sumps of pressurized vessels, the downstream

system should be checked in effect of capable to cope over draining and draining to atmosphere from pressurized vessel is not recommended.

K. Internal Components of Separators and separator component example are shown below:

Inlet Diverters There are many types of inlet diverters. Figure 1.25, Inlet diverter: a component of internal separator to quickly change of direction to separate the major portion of the liquid from the gas stream. In the other hand, inlet diverter will break up the bulk of the inlet stream into smaller particles. The inlet device controls the inlet momentum by redirecting the inlet stream and dissipating/dispersing the energy of the inlet fluid. A box type diverter is always used with the two sides in the vertical plane open to flow (at right angles to incoming flows).

Figure 1.25 Inlet Diverter There are various types available all of which are used by manufacturers. These types are listed below: a. The dished end type of inlet diverter directs the inlet fluid back into the vessel head.

This is used in cases where the inlet nozzle is in the head of vessel. b. The fluid is directed back against the vessel head by a 90o elbowed pipe. This type is

uses for gases.



c. Presently the most common of all types is either a vane, angle or pipe type inlet diverter in a box type arrangement.

Baffle Horizontal baffle is used to reduce liquid/liquid settling volume which impact to retention time, since droplets only need time to settle to the baffle rather than to the bottom of the drum. The baffle is designed so that settled liquid flows to the inlet end of the drum and the down of the drum walls to the bottom. The following direction can be observed in providing settling baffles: a. Make the minimum vertical distance between adjacent baffles, or baffle and drum

range from 15” – 19” for access. b. Make the distance from the end of the baffle to the adjacent end of the drum ¼ the

drum diameter. c. Provide a 2” lip on each baffle at the outlet end of the drum. d. Provide 2 slots, 1” wide and ¼ as long as the drum, located at between drum and

baffle, at each section of the inlet end of the baffle. Figure 1.26 and Figure 1.27 show several basic, commonly used types in oil and gas industry.

Figure 1.26 Deflector baffle

Figure 1.27 Cyclone Inlet Baffle



The first is a deflector baffle. This can be a hemispherical dish, flat plate, piece of angle iron, metal cone, or just about any shape that will cause a rapid change in the direction and velocity of the fluids and thus disengage the gas and liquid. The advantage of using devices such as the hemisphere or cone is that they create fewer disturbances than flat plates or angle irons, cutting down on reentrainment or emulsification problems. The second device shown is a cyclone inlet, which uses centrifugal force rather than mechanical agitation to disengage the oil and gas. This inlet can have a cyclonic chimney, as shown, or may use a tangential-fluid race around the walls of the vessel. Cyclonic inlets generally create a fluid velocity of about 20 ft/s around a chimney whose diameter is perhaps 2/3 that of the vessel diameter. Spiral fins, or helices, are also sometimes used in the last few feet of inlet piping, particularly in the Middle East. Wave Breakers In long horizontal vessels it is sometimes necessary to install wave breaker(s) as shown in Figure 1.28. These are nothing more than vertical baffles or partial cross-sectional area plate that span the gas-liquid interface perpendicular to the flow direction while still letting liquid pass through, and prevent waves caused by liquid surges.

Figure 1.28 Wave Breaker Defoaming Plates Foam may occur at the gas-oil interface when gas bubbles are liberated from certain liquid mixtures. This foam can be stabilized with the addition of chemicals upstream of the separator inlet. Often, a more effective solution, since refineries sometimes object to defoamer chemicals in crude oil, is to force the foam to pass through a series of inclined parallel plates or tubes as shown in Figure 1.29 and Figure 1.30; this leads to the coalescence of the foam bubbles.



Figure 1.29 Defoaming Plates

Figure 1.30 Foam Breaker/Defoaming Plate (www.vmeprocess.com)

Vortex Breaker It is normally a good idea to include in a separator design a simple vortex breaker, as shown in Figure 1.31 (slotted pipe), Vortex breakers are required to maintain flow rate of liquid phase continuity from vessel whenever the intersection of the minimum liquid level (i.e. the lowest effective working level) and the nozzle velocity is below nozzle velocity calculated without using vortex breaker at various liquid flow rates. This will also avoid gas blowby event. Vortex breaker may be located before the liquid outlet nozzle(s) to prevent gas or oil entrainment with the bottom liquid. LSLL shall be determined above vortex breaker Figure 1.32 (platform).


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Figure 1.31 Vortex Breaker (slotted Pipe)

Figure 1.32 Platform Vortex Breaker Figure 1.33 (crossed plates) and Figure 1.35, these are to keep a vortex from developing when the liquid control valve is open.



Figure 1.33 Crossed Plate Vortex Breaker

Figure 1.34 Vortex Breaker (webwormcpt.blogspot.com)

A vortex could suck some gas out of the vapor space and re-entrain it in the liquid outlet.

Figure 1.35 Position Crossed Plate Mist Eliminator (Mist Extractor), Mist Eliminator is an entrainment in a separator to remove small liquid droplets lower than 100 micron and free the gas from liquid content.



The use of mist extractor will give high overall percentage removal of droplet liquid even very small liquid droplets. Also, the use of mist extractor can significantly reduce the required diameter of separator because of its more efficient in removing liquid droplets from the gas that using gravity settling method.

Figure 1.36 SS Wire Mesh Pad ready to be installed (www.evergreenindia.com)

Minimum distance upstream and downstream of the mist extractor between gas inlet and outlet nozzles should be provided for space required for gravity settling separation and also for full utilization of mist extractor. The mist extractor of the coalescing side may be a series of vane, woven wire mesh pad or a centrifugal device design. The mist extractor will remove the small droplets (normally down to 10 microns diameter) of liquid (both oil and water) from the flowing gas stream before the gas leaves the vessel. Liquid carryover in the outlet gas is normally less than 0.1 gallon per MMSCF. Figure 1.37, Figure 1.39 and Figure 1.44 show three of the most common mist extraction devices: wire mesh pads, vanes, and arch plates.

Figure 1.37 Wire Mesh Pad Wire mesh pad is fabricated in pad form from symmetrical interlocking loops of knitted metal wire or plastic monofilaments with a high free volume and large impingement area.



Wire mesh pads which are a static, in-line device are made of finely woven mats of stainless steel wire wrapped into a tightly packed cylinder.

The construction of a wire mesh mist eliminator is often specified by certain thicknesses (usually 3 to 7 inches) and mesh density (usually 10 to 12 lb/ft3). A pad thickness of 4 inch also can be used as minimum; 6 inch is mostly widely used and up to 12 inch may be required for fine mists. Wire Mesh pad types are frequently used as entrainment separators for the removal of very small liquid droplets and, therefore a higher overall percentage removal of liquid. Experience has indicated that a properly sized wire mesh eliminator can remove 99% of 10 micron and larger droplets. Although wire mesh eliminators are inexpensive they become plugged more easily than the other types.

Figure 1.38 Separation Process at Vertical Separator using Wire Mesh Pad

(www.evergreenindia.com)

The effectiveness of wire mesh depends largely on whether or not the gas is traveling at the proper velocity. If the velocity is too high, the liquids knocked out will be re-entrained. If the velocity is too low, the vapor will just drift through the mesh element without the droplets impinging and coalescing. Or, wire mesh pads are efficient only when the gas stream velocity (defined as allowable vapor velocity) is low enough that re-



entrainment of the coalesced droplets does not occur and also fouling and hydrate formation are possible not occur.

The type is generally in horizontal position (at a 90o angle) of flow gas direction and entrained liquid passing vertically upward. When vapour carrying entrained liquid droplets or mist passes through the mesh pad (in perpendicular flow of pad position), the vapour passes freely through the layered mesh structure. But, the liquid droplets, having greater inertia, contact the large wire surface exposed and briefly held there. As more droplets collect, they coalesce and grow in size and become large enough to drain back into the bottom of vessel. The overhead product is pure vapour containing practically no liquid. The separating action of a separator largely depends upon the contact surface area necessary for impingement which must be evenly distributed. Generally speaking, a higher free volume leads to a lower pressure drop. In critical cases, it may be necessary to decide whether pressure drop or efficiency should be sacrificed.

If fouling or hydrate formation is possible, wire mesh pad is typically not used. Vane or centrifugal types are generally more acceptable. The pressure drop across the wire mesh pad is sufficiently low (usually less than 1 inch H2O) to be considered negligible for most application.

Meanwhile, pressure drop at wire mesh pad shall be considered if application is at vacuum service and at equipments having a blower or a fan as the prime mover. When flooding happens, pressure drop at wire mesh pad may also occur significantly.

Figure 1.39 Vane Mist Extractor Vane-type mist eliminators force the gas flow to become laminar between corrugated parallel plates. Droplets impinge on the plate surfaces, where they coalesce and fall to the liquid-collection section of the vessel. Typically, vane is one of appropriate choices (beside of centrifugal) if fouling or hydrate formation is possible or expected.



Figure 1.40 Vane Mist Extractor (www.vmeprocess.com)

Figure 1.41 Vane Mist Extractor Construction (www.petroeng.ru)

But, it should be noted that as vane type separators depend upon inertial forces for performance, sometimes turndown can being a problem. Vane-type eliminators are sized by their manufacturers to assure both laminar flow and a certain minimum pressure drop. For configuration of vertical gas flow – horizontal vanes position, the vanes are designed to provide optimum deflection to the gas containing entrained liquid particles. The entrained liquid particles can not follow the deflected gas path and are collected as they accumulate along the wall of the vane mist eliminator. Collected liquids (entrained liquid particles) run down counter current to the direction of gas flow.


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Figure 1.42 Theory of Configuration of Vertical Gas Flow – Horizontal Vanes Position

For configuration of horizontal gas flow – vertical vanes position, specially designed sinusoidal vanes having a provision for a phase separation chamber are employed. The gas flow is split by these vanes and the entrained liquid particles are driven by inertial forces to the walls in the phase separation chambers. Re-entrainment is avoided as a separate liquid drainage path is provided in the phase separation chamber.

Figure 1.43 Theory of Configuration of Horizontal Gas Flow – Vertical Vanes Position

Arch plates are designed to function essentially in the same method as the vanes. The plates are formed as concentric cylinders, sometimes corrugated, on which the gas impinges and coalesces.



Figure 1.44 Arch Plates Some separators have centrifugal mist eliminators which cause the liquid drops to be separated by centrifugal force (Figure 1.45).

Figure 1.45 Centrifugal Mist Eliminator These can be more efficient than either wire mesh or vane-type mist eliminators and are the least susceptible to plugging. However, they are not in common use in production operations because their liquid removal efficiencies are much more sensitive to small changes in flow rate. In addition they require relatively large pressure drops to create the centrifugal force necessary for separation. Commercial units have capacities of 5 – 500 gpm and are able to remove water from hydrocarbon down to the certain range of ppm.



Three-Phase Separator Components Internal components of three-phase separators are similar or identical to those for two-phase separators. Two additional components found in three-phase separators are coalescing plates (section D of Figure 1.21) and sand jets. Coalescing Plates It is possible to use various plate or pipe coalescer designs to aid in the coalescing of oil droplets in the water and water droplets in the oil. Some tests have indicated that some reduction in vessel size (and therefore cost) is possible. Because of the potential for plugging, however, it is recommended that coalescer be used to extend the capabilities of existing three-phase separators or where there are severe space limitations. Sand Jets and Drains In horizontal three-phase separators, one major problem is the accumulation of sand and solids at the bottom of the vessel. Generally the solids settle to the bottom and become well packed. If these solids are allowed to build up, they will disrupt efficient separator operation by taking up vessel volume. To remove the solids, the separator is temporarily taken out of operation, sand drains are carefully opened, and high-pressure fluid, usually produced water, is pumped through sand jets which agitates the solids and flushes them down the drains (Figure 1.46).

Figure 1.46 Sand Jets and Drains The sand jets are normally designed with a 20 ft/s jet tip velocity; they are positioned to give good coverage of the vessel bottom. To prevent the settled sand from clogging the sand drains, sand pans or sand troughs are used to cover the outlets. These are inverted troughs with slotted side openings.

L. Physical Principles that affected in Separator sizing is shown in the following:



1. Critical Point This is the condition at which the specific properties of the gas and liquid are identical.

2. Multi Component System A typical phase diagram of a multi component system is presented in Figure 5. In the upper left-hand side the fluid is only that a similar plot for a single component would produce only a line and not an envelope. Some of the points on the curve are defined in subsequent paragraphs.

3. Cricondenbar

This is the maximum pressure at which liquid may exist.

4. Cricondentherm This is the maximum temperature at which liquid and vapor may co-exist in equilibrium.

5. Retrograde Region This area inside the phase envelope is where condensation of liquid occurs by lowering pressure or increasing temperature.

6. Oil Reservoirs These reservoirs contain hydrocarbons below their critical temperature; the fluid can be either liquid above the bubble point or two-phase below it.

7. Gas Condensate Reservoir This reservoir contains hydrocarbons at a temperature between the critical point and the cricondentherm. As pressure declines to the dew point, liquid forms consisting mainly of the heavier components. As pressure declines below the dew point, liquid formation increases as long as pressure is in the retrograde region. Below this region, some revaporizations occur.

8. Gas Reservoir This reservoir contains fluids above the cricondentherm. No liquid in the reservoir can form at any pressure However, cooling in the well may result in formation of liquids.

The physical differences of the fluid components are density, particle size, and viscosity. These differences will be influenced by fluid velocity, which may create a separating force, in the case of a mist eliminator (high velocity), or increase the residence time for oil and water to separate (low velocity). In one case, the high velocity is used to create momentum between the gas and liquid particles in the gas to effect separation. The effect of low velocity is to reduce turbulence and allow the differences in densities and gravity to influence the separation. Heat any be used to reduce the viscosity and density of oil relative to water, thus improving the settling rate. Heat also reduces interfacial surface tension which promotes coalescence (increase droplet size).



The Mechanism of Particle Collection The basic separation methods are: a. Settling out under the influence of Gravity separation. b. Settling out under Centrifugal force/action. c. Impingement and Coalescence on solid surface followed by settling out.

9. Quality Lines These lines show constant gas volume weight percentages which intersect at the critical

point and are essentially parallel to the bubble point and dew point curves. The bubble point curve represents 0% vapor and the dew point curve 100 vapor.

Although vapor-liquid separators are used to separate the vapor phase from the liquid

phase as the primary task, they may also provide surge capacity. For example, they acted as surge drum downstream of condenser used in Refrigeration Unit.

1.9 Vessel/Separator Calculation Theory

A. Factors which effect separation efficiency are defined below. a. Particle diameter b. Base diameter c. Gas velocities d. Gas and liquid densities e. Pressure f. Temperature g. Surface and interfacial tension h. Viscosity i. Foam j. Emulsion k. Flow rate surges l. Slug

a. Particle diameter

Particle diameter is one the most important properties affecting separation efficiency, because it is the predominant factor in determining the settling velocity in all applications other than Newton's Law. Any design allowing high efficiency in the separation of larger particles, if the maximum liquid handling capacity is not exceeded.

An entrained liquid system is basically unstable, the particles either coalescing or vaporizing if given sufficient time. This time either vaporizing or coalescing, is inversely proportional to size, and proportional to the amount of inter-particle contact. It is on this latter premise that impingement separators are based.

b. Base diameter The base diameter is the minimum particle size which has a terminal velocity equal the

average carrier fluid velocity. For particles which are larger than size of base diameter will theoretically be removed from the carrier stream.



In practice, some particles larger than base diameter may not be separated due to turbulence and isolated high velocity areas and some particles smaller than the base diameter will be separated because they do not have to fall the maximum distance across the gas space.

c. Gas velocities These values are usually set for particles greater than 200 micron to be separated by

gravity in the gas-liquid separation section of a separator, while smaller particles are removed by the mist extractor.

The net effect or higher gas velocities is to increase the size of particles reaching the

mist extractor. d. Gas and liquid densities These densities affect efficiency only as a factor in establishing the allowable fluid

velocities. e. Pressure Pressure affects the allowable velocity and actual flowing volume. The effect of an

increase in pressure is an increase in capacity. Both the gas and liquid densities are affected because more of the lighter components of the gas are driven into the liquid phase, thereby changing the density of both phases.

f. Temperature Temperature affects gas and liquid separator capacities in that it affects the actual

flowing volume and density. The net affect of an increase in temperature is to decrease the gas capacity of a given separator size due to an increase in gas volume and velocity.

Higher temperatures reduce surface tension of a liquid, allowing larger particles to be

formed in turbulence. g. Surface and interfacial tension These factors affect efficiency from the standpoint of the size of the particles formed.

This affects the number of particles of a given size that will be present in the carrier stream. i. Surface tension.

A molecule on the surface of a liquid is subject to an inward force as a result of the attraction between molecules. This surface molecule tends to adjust itself to a minimum surface area causing the droplet to assume a spherical shape.

If one thinks of the attractive forces as a film over the liquid surface one can speak of the result as a surface tension. (Ref : "Gas Conditioning and Processing", John M. Campbell, (1976)).

ii. Interfacial tension.

The interfacial tension of immiscible liquids is less than the larger of the surface tensions of the component liquids.



Quantitative predictions may be made with Antonoff's Rule which states that, for two saturated liquid layers in equilibrium, the interfacial tension is equal to the difference between the individual surface tension of the two, mutually-saturated phases under a common vapor or gas (Chemical Engineer's Handbook, Robert H. Perry and Cecil H. Chilton, Fifth Edition, McGraw-Hill, 5-61 ff (1973)). A lower interfacial tension leads to coalescence, which produces larger particles that settle faster.

h. Viscosity An increase in either the temperature or pressure causes the gas viscosity to increase which retards smaller particle separation. Separation of two liquids is dependent on the

Figure 1.47 Effects of Reynolds Number On Drag Coefficient

viscosity of the continuous phase, and, therefore, it is not uncommon to add heat to lower the viscosity in a liquids separator (see Figure 1.47).



i. Foam Foam is a mixture of gas dispersed in a liquid and has a density less than the liquid but greater than the gas. This type of foam is called bubble foam. A foaming crude oil requires a greater interface area and longer retention time remove the gas from the liquid. Bubble foam may be caused by a pressure reduction which causes the lighter liquid component of the crude oil to flash and escape from the liquid.

Bubble foam may also be formed by aeration of the liquid in the flow line. This type of foam can be dispersed by the use of impingement baffles and residence time. A second type of foam is chemical foam, which is a surface tension phenomenon. The surface tension of the bubble is so strong that the bubble will not break. This type of foam is caused by iron sulfide particles, asphaltness and resins in the crude oil.

j. Emulsion

Water in oil and oil in water emulsions may also form because of turbulent two-phase mixing in the flow line. Oils bring emulsion increase the viscosity significantly and may cause fluid flow problems if not chemically treated.

De-emulsifier chemicals, usually polyglycol or sulfonate, are used to break the emulsions. The de-emulsifier chemical injection usually occurs prior to the time of fluid entry into the treating vessel to ensure the successful operation of the treating vessel.

The chemical should be injected at a place where thorough chemical mixing can be obtained prior to entry of the fluids into the treating vessel. The composition of "all fluids" encompasses the emulsion, free-water, and gas. The de-emulsifier chemical is added as the first step to break the emulsion. This chemical disperses throughout the oil and collects on the surface of the water droplets. The chemical has a stronger tendency to collect on the water-oil interface than does the emulsifying agent. The chemical causes the emulsifying agent to displace and disperse throughout the oil phase of the mixture.

The de-emulsifier molecules are small and, consequently, the firm thick ness is less at the water-oil droplet interface than that which existed with the original emulsifying agent. The resultant film is much thinner and the bond holding the droplets in dispersion is considerably weaker.

After displacement of the emulsifying agent by the de-emulsifier chemical, coalescing of the water drops begins, because the water drops can come much closer together with only a thin, weak film surrounding each drop. The molecular attraction between drops is also stronger, since less distance separates the drops. Upon droplet contact, this attraction is strong enough to pull the drops together, rupturing the surrounding film and allowing minute water droplets to coalesce into larger drops and to settle out the oil phase of the oil-water mixture.

k. Flow rate surges

Separator designs must include surge capacity to account for non-steady state flow rate which inevitably occurs in normal production operation and to provide sufficient liquid



storage capacity to allow instruments and operators to react to external operational upsets.

A 25% surge capacity is normally used for separator design. Surge capacity is determined as below.

LSHH volume ― NLL volume

Surge capacity = x 100 % …………… Eq. 1.1 LSHH volume l. Slug

Usually, slug is considered happen in well-pad facility and in gathering system. So, separator design shall consider possible liquid slugging of the separator.

B. VAPOR – LIQUID SEPARATION

- Separation of vapor and liquid in a vessel accomplished by the virtue of density

difference aided by gravity force. Gravity accelerates the falling of a particle until its force is offset by drag force. From then on, the particle falls at constant velocity known as Terminal velocity or Critical velocity.

1. ( )V

VLSC KV

ρρρ −

×=/ …………………………………………….………. Eq. 1.2

2. CDK ×= 003615.0 …………………………………………….………… Eq. 1.3

3. ( )V

VLSC C

DV ……………………………………... Eq. 1.4 ρρρ −

××= 003615.0/

Where:

ρL,V = Liquid or Vapor density (kg/m3) Vs/c = Terminal settling velocity (m/s) K = Correlating parameter (m/s) D = Particle diameter (micron) C = Drag coefficient

For most industrial system, K (in MKS unit) lies between 0.03 and 0.10 meter per second units. Lower values of K may be considered in aqueous systems where the surface tension has been reduced by surfactants. The effect of disengaging height (h, inch) versus K values may be given by equation

hK 0325.0021.0 += , 3 ≤ h ≤ 12 …………………………………….………. Eq. 1.5



with a maximum value of 0.4. This relation is standard for efficiency pads. Lower values can be expected in aqueous system where the surface tension has been reduced by surfactants. When the pad is installed in a vertical or inclined position, practice has shown that K values should be about 2/3 of the value for pads mounted in a horizontal position. A typical value of 0.048 is recommended for designing process liquid-vapor separator. For specific system, if detailed analysis becomes necessary, K value can be estimated from table as below (API RP 12J)

At high liquid rates, droplets tend to be re-entrained and the pad may become flood. Below equation to estimate K value can be used:

573.0263.00037.0 294.1 +

+−=x

K , 0.04 ≤ x ≤ 6.0 ………………………………... Eq. 1.6

Where:

L

V

V

L

WWx

ρρ

×= ……………………………………………………….………. Eq. 1.7

WL = Weight flow rate of Liquid (lb/hr) WV = Weight flow rate of Vapor (lb/hr) ρL = Density of Liquid (lb/ft3) ρV = Density of Vapor (lb/ft3)

For vertical 2 phase separator having horizontal wire mesh pad, K may be calculated by using equation:

( )[ ] 35.00001.0 +−×= PK …………………………………………….……... Eq. 1.8

Where,

P = Operating pressure, psig



For designing a liquid-vapor separator, actual vapor velocity, or maximum allowable vapor velocity should always be less than critical velocity calculated above. However, if special internals (like demister pads, etc.) are provided, vapor velocity higher than critical velocity may also be acceptable. For separator using wire mesh pad, a popular design velocity is about 75% of allowable critical velocity.

- For higher pressure (> 50 bar) or viscosities in excess of 0.01 cp, it is necessary to calculate Vs. The drag coefficient C is calculated using figure below, where:

( )2

3112 103072.1Re

μρρρ VLV DC −××××

=−

……………………………….. Eq. 1.9

Then Equation 1.4 is used to calculate Vs.

- If according to CREST engineering criteria, the liquid flow rate over the oil-water

interface should be less than 100 bbl/day.ft2.

Formula for the separation of droplets: a. STOKES LAW (ref : Ludwig)

For Re < 2 Vc = 5.45 x 10-10. (Dp

2 . (ρd - ρc)0.3 / (ρc0.29 . ρd

0.43)) …………………….. Eq. 1.10

b. INTERMEDIATE LAW (ref : Ludwig) For 2 < Re < 500 Vc = 2.216 x 10-6. (Dp

1.14 . (ρd - ρc) / μc2) ……………………….………. Eq. 1.11

c. NEWTON LAW (ref : Ludwig)

Re < 500 Vc = 5.45 x 10-3. (Dp . (ρd - ρc) / ρc )1/2 ………………………………….. Eq. 1.12 Re = (Vc x D x ρc) / (μc

2 x 103) ………………………………………… Eq. 1.13



Subscript c for the continuous phase (kg/m3) Subscript d for the dispersed phase Dp = droplet diameter (micron)

C. LIQUID-LIQUID SETTLING

Equation velocity for liquid-liquid settling:

Vc = g. (D2 . (ρH - ρL) / 18 μc

) ………………………………..…………………. Eq. 1.14

Where: ρH = density of heavy fluid (kg/m3)

ρL = density of light fluid (kg/m3) μc = continuous viscosity Setting the particle size to 125 micron and using more useful units gives: Vc = 0.513 (ρH - ρL) / μc

) ……………………………………………………….. Eq. 1.15 If calculated settling velocity is > 250 mm/min use D = 250 (maximum) and valid only for Re = 0.1 – 0.3. It is also possible to use Length Effective method to determine in which length, the separation between Light Liquid phase and Heavy liquid phase will be complete in sizing horizontal 3-phase separator. This method can also be used to know whether diameter size or length size will influence gas-oil-water separation in sizing final dimension of 3-phase separator. The most common configuration in sizing horizontal 3-phase separator is half full. Sizing 3-phase (gas-oil-water) Separator In spite of shape, the following requirements can be used as guidelines: a. All liquids including light liquid and heavy liquid (i.e. oil and water) shall be

separated from the gas phase flow in a primary separation section when inlet to the separator to remove main bulk droplets of liquids.

b. Gas velocity should be lower than maximum allowable superficial velocity to allow liquids to drop out from the gas phase.

c. Use a mist extractor before the gas phase flow leave the vessel through outlet nozzle to remove the small droplets (normally down to 10 micron of 99 % removal) of liquids.

d. Light liquid phase and heavy liquid phase should be separated well in gravity settling section (caused by difference in density) of the vessel. This section must be free from



turbulence flow so that, light liquid phase (i.e. oil) and heavy liquid phase (i.e. water) can be deflected well.

e. Liquids shall be kept in the vessel for along certain time to give sufficient time to allow separation between light liquid phase (i.e. oil) and heavy liquid phase (i.e. water). This hold time can be reduced by using Length effective method as one of methods in sizing 3-phas separator (horizontal).

f. The heavy liquid-light liquid interface shall be maintained to allow good removing outlet from separator without mixing between Oil and water both in separated oil section and in separated water section. A weir plate can be used to maintain heavy liquid-light liquid interface.

g. Heavy liquid phase and light liquid phase shall be removed from the vessel at outlet nozzles on different location. Light liquid outlet nozzle location is downstream of the weir plate whereas heavy liquid outlet nozzle location is upstream of the weir plate.

Of course, above guidelines can show that sizing 3-phase separator is a function of retention time for gas-liquids separation and for liquid-liquid separation. This retention time is related to capacity/volume of vessel. The main considerations in determining retention time are first, settling time required to remove heavy liquid phase from light liquid phase. Last, settling time require to remove light liquid phase from heavy liquid phase. This sufficient time will be influenced by their properties (mainly densities) and operating temperature.

D. SIZING NOZZLE Criteria for selection of nozzle size are depends on momentum criteria (ρ x v2) for gas phase (gas inlet and outlet nozzle) and velocity for liquid phase (liquid outlet nozzle) where:

ρm x vm2 ≤ 6000 kg/m.s2 (4031.8 lb/ft.s2) for 2 phase (gas + liquid)

ρg x vg2 ≤ 3750 kg/m.s2 (2519.9 lb/ft.s2) for gas phase

v not more than 3.7 m/s (12 ft/s) for liquid phase

E. SIZING PIPING LINE Criteria for selection piping line based on velocity and pressure drop/100 ft regarding to type of phase: - Gas Phase: Velocity should between 60 – 80 ft/s and pressure drop should below 5

psi/100 ft. - Gas-liquid phase: The criteria are mixture velocity should not exceed than erosional

velocity and pipe cross sectional area of flow area should exceed than its minimum required.

- Liquid phase: velocity should not exceed than 12 ft/s and maximum pressure drop should not exceed than 1.5 psi/100 ft.



2. PUMPS 2.1 Description

Pumps are equipments used to move/transfer liquids from one place, low elevation/location or a low pressure through piping system to another place, higher elevation/location or higher pressure.

2.2 Pump Classification

Pumps are classified as “kinetic” or “dynamic” types and “positive displacement” types. In kinetic type, energy is added to the pump continuously and this energy is imparted to the fluid to increase the fluid’s velocity within the pump by a rotating impeller generating centrifugal force. Then, the pressurized fluid exits through discharge pipe. This type of pump may be further divided into several categories based on their mechanical configuration, these include:

The type of flow (axial, radial, or mixed flow). Pump orientation (horizontal or vertical). Vertical submersible pump has special

application included for LNG, LPG and well water pump. Number of suction inlets (single or double suction). Number of stages involved (single, double or multi stages). Type of pump split casing (axially or radially split). In general radial split casing is

relatively cheaper than the axial split ones. According to ASME VIII Div 2, for pumps with total head more than and equal to 800 m, the outer casing is always one full casing; normally, the suction flange rating is 300# and discharge flange rating is 900# and higher.

Pump speed (example : in 50 Hz operation -> 1000 rpm or 1500 rpm or 3000 rpm, bigger pump smaller rpm). Commonly, this pump speed is determined by impeller profile in corresponding estimated specific speed range.

Other than above configuration, during pump selection, user shall consider following criteria:

Basic requirement met industry and company standard If the pump type at operating condition is well proven to operational and industry

experience under design and operating condition If it is the lowest possible equipment price and cost If it is met lowest possible installation cost If spare parts is guaranteed available for several years of operation If it is generally acceptable with the engineer’s practical experience.

In a positive displacement pump, the liquid is compressed mechanically. This will cause a direct rise in potential energy. Positive displacement pumps have a chamber containing cams, gears, plungers, screws, vanes motioned by rotation of the drive shaft to the casing. These pumps transport a volume of liquid constantly for each cycle against varying discharge pressure (head). They more or less have a constant flow regardless of the system pressure or head. There are two major type of positive displacement pump: reciprocating and rotary type.



The reciprocating type is subdivided into: • Fixed (or constant) volume type (or power pump) according to API RP 674, horizontal

type, piston or plunger, single or double acting type. • Controlled volume type also known as the metering or proportioning or chemical

injection, according to API RP 675, horizontal or vertical, piston or plunger or diaphragm, stroke controlled, manual or auto, or using variable speed electric motor.

In reciprocating pumps, the displacement is accomplished by linear motion of a piston in a cylinder. The rotary positive displacement pump is subdivided into: • Vane type • Lobe type • Gear type • Screw type • Rotary piston type

Lobe, gear and screw type of rotary pump is most frequently used in production system. Each type has its own advantages and limitations in operation. Rotary pumps operate on the principle that a screw, rotating vane or gear traps the liquid in the suction side of the pump housing and forces it to the discharge side of the pump housing. The 3 basic categories of rotary pumps are: • Gear pumps • Screw pumps (single screw, twin screw, triple screw) • Moving vane pumps

Diaphragm pumps are also categorized as positive displacement pumps as the diaphragm acts as a limited displacement piston.

Centrifugal (kinetic type) pumps and reciprocating pumps (one of positive displacement types of pumps) are the most common types of pumps used in gas processing plants.

Special Consideration 1. In some cases, the design pressure of the system may be set lower than the maximum

pump discharge pressure. For example, if the maximum pump discharge pressure considerably exceeds maximum operating pressure of the system (or downstream equipment), it will be more safe and economical to specify the lower design pressure of discharge pump and protect the system against overpressure with a pressure relief valve (PSV). But, the system should be checked carefully to ensure that at destination, pressure of liquid, discharged from pump, has enough pressure as required by the downstream equipment for process conditioning regarding pressure loss through pipelines and position of inlet of fluid at downstream equipment.

2. In the other hand, in some circumstance, the design pressure may be set higher than

maximum pump discharge pressure if the pump is not only the source of overpressure (e.g., downstream equipment backflow, tube rupture, surge, etc.).



3. When turndown required is less than 30%, minimum flow provisions shall be made.

4. A throttling valve that changes the system head-flow-rate will have no effect on the flow rate through the pump.

5. Diffuser construction is used to a limited extent in some high pressure, multistage

machines. The double suction arrangement (double suction is used to minimize axial thrust) has balanced axial thrust and is favored particularly for severe duty and where the lowered NPSH is an advantage. Multistage pumps, however, are exclusively single suction.

6. If two or more pumps are installed in parallel, the suction lines should be manifolded

together. It means that the lines should be sized so that the velocity in the common feed line is approximately equal to the velocities in the lateral lines feeding the individual pumps. This avoids abrupt velocity changes and minimizes acceleration head effects.

7. Submergence – at pressure vessel or atmospheric vessel, the suction system inlet or the

pump suction signal should have sufficient height of liquid to avoid vortex formation, which may entrain air or vapor into the pump system and cause loss of capacity and efficiency as well as other problems such as vibration, noise, and air or vapor pockets.

Shut Off Pressure The shut off pressure of a typical centrifugal pump is approximately equal to the sum of the maximum suction pressure and 125% of the net differential pressure generated by the pump, based on the possible maximum fluid density. Other pumps with steep H-Q curves such as turbine, multistage and mixed flow pumps, however, will have higher shut off pressures. Rotating discipline should be consulted to determine shut off pressure since it may influence the design pressure of downstream equipment.

The maximum discharge pressure will be used to set the design pressure of a pump casing. This is the sum of the maximum suction pressure and maximum differential pressure, which usually occurs at zero flow. In case where the feed vessel is protected by a safety relief valve, the maximum suction pressure will be equal to the sum of the safety valve set pressure and the maximum static head. Pump Cooling Water Requirement Cooling water is used to cool bearings, stuffing boxes, pedestals and glands to safe temperature conditions. The cooling water flow rate will vary with temperature and pump size. Pump Efficiency The efficiency of centrifugal pump varies from about 20% for low capacity pumps (less than 30 USGPM) to a high of almost 90% for certain large capacity pumps. Low head pumps using open type impellers are less efficient than closed impellers. Capacity Control Manual or automatic capacity control for one pump or several parallel pumps can be accomplished by one or a combination of the following methods:



a. On-off control. b. Recirculation. c. Variable speed driver or transmission. d. Variable displacement pump.

Pump Protection The protections may be considered as follow: 1. Low suction pressure. 2. High suction pressure (e.g. for centrifugal type). 3. High discharge pressure. 4. Low discharge pressure. 5. Low suction vessel level. 6. High discharge vessel level. 7. Low flow. 8. Flow reversal. 9. High temperature of bearing, case, etc. 10. High discharge temperature. 11. Vibration. 12. Lack of lubrication. 13. Over speed.

Protection may be considered for the pump driver and may be combined with pump protections. Pulsation at Reciprocating Pumps Pulsation is a phenomenon where pressure and flow are fluctuated at the reciprocating pump. To reduce pressure and flow fluctuations, pulsation dampeners can be installed both at suction line and discharge line. Pulsation dampeners are also effective in absorbing flow variations on the discharge side of the pump and should be considered if piping vibration caused by pressure fluctuation appears to be a problem. Discharge pulsation dampeners can minimize pressure peaks and contribute to longer pump and pump valve life. In multiple pump installations, pulsation dampeners should be installed.

In other conditions, pulsation dampeners may not required if the suction line is big and short, or if the pump operates at low speed (less than 150 rpm). Manufacturers should be consulted to design the pulsation dampeners. Computer analog programs can be used to conclude whether pulsation dampeners both at suction and discharge lines are required or not. But, it better to install pulsation dampeners both at suction line and discharge line than awaiting result of computer analog which usually expensive and need extra time. Pulsation dampeners can be liquid-filled, gas-cushioned, or tuned acoustically. A liquid-filled dampener (or called liquid-filled surge vessel) is a large surge vessel located close to the pump. The compressibility of the liquid itself is used to absorb pressure pulsations. Typical gas-cushioned dampener is a surge bottle with a gas/liquid interface. The high compressibility of the gas gives absorption of the pressure pulsations.



Tuned acoustical dampeners are formed when two liquid-filled vessels are connected by a short section of small diameter pipe called a choke tube. Impellers Impeller is the rotor that accelerates the liquid. With many kinds of impellers, they may differ in width and number and curvature of the vanes, and diameter. Type of the impellers may be closed impeller which is used for clear liquids. Open type of impellers is desirable if there is possibility of clogging (blocking) as with slurries or pulps (mainly fluids having high viscosity). The impeller may have both axial propeller and centrifugal vane action. This propeller gives high rate of flow but low developed pressure. The turbine impeller rotates in a case of uniform diameters. Turbine pump performance looks like that of positive displacement types. Like them, turbines are essentially self-priming which will not vapor bind.

Impeller types: a. Open impellers consist of vanes attached to a shaft without any form of supporting

sidewall and are suited to handling slurries or pulps without clogging. b. Semi enclosed impellers have a complete blanket (shroud) on one side. They are

essentially non-clogging, used primarily in small size pumps; clearance of the open face to the wall is typically 0.02 inch for 10 inch diameters.

c. Closed impellers have shrouds on both sides of the vanes from the eye to the periphery, used for clean liquids that have low viscosity (low density) liquids.

Figure 2.1 Impellers Type (www.cheresources.com)

Impeller inducers should be avoided as a means of lowering the NPSHR because of the unpleasant effects on pump performance.


http://www.cheresources.com/


Bearings Ball bearings convey a load from a rotating surface to a fixed surface through a series of rotating balls. The bearing has limited ability to handle thrust, high loads, or high speeds although the bearings are inexpensive and no need separate lubrication system. Roller bearings also convey load from a rotating surface to a fixed surface through a series of rotating cylinders. Hydrodynamic sleeve bearings convey the load via a slight oil layer between a rotating shaft and a fixed bearing surface. Hydrodynamic thrust transmits the load through a slight oil film/layer between a rotating shaft and a fixed bearing surface that consist of multiple pads that slope/tilt. NPSH (Net Positive Suction Head) Each pump requires a certain minimum pressure at its suction flange to assure that no vapor is flashed between the pump suction line and the cylinder or entrance to the impeller vane. If hydrocarbon liquid phase flow has low pressure even meet vapor pressure of its fluids, vapor could be released by the form of small bubbles that would then collapse in an “implosion” as the liquid is pressured in the pump. Simply, when a liquid’s falls below its vapor pressure, gas will be flashed. This is called cavitation and result in noise, vibration, greatly increased wear, and reduced pressure or throughput capacity. Furthermore, cavitation causes impeller damage, weaken pump performance, and also will cause no flow out from discharge pump. Cavitation can be avoided by assuring that the liquid’s pressure does not drop below its vapor pressure anywhere as it passes through the pump. To ensure this, the net head at the suction of the pump impeller must exceed a certain value. This minimum head is called the Net Positive Suction Head (NPSH) and is evaluated as NPSH = A + B – C – D ……………………………………………………………….. Eq. 2.1 Where: A = Pressure head at the source B = Static Suction Head C = Friction head in the suction line D = Vapor pressure of the liquid

Simplify, the definition of NPSH is the net pressure above the vapor pressure of the liquid being pumped. The minimum pressure required at the pump flange is expressed in feet of liquid and is called NPSH. Because the effects of cavitation can be severe, it is recommended that pumps be specified with a required NPSH that is 3 or 5 ft less than NPSH available. In determining NPSH, consideration must be given to: 1. All boiling point fluids either single or multi-component. 2. Fluids that contain dissolved gas which may be impinge on vapor pressure. 3. Foaming fluids as foam has trapped gas.



When flow rate increase, NPSH required also increase. NPSH required for a reciprocating pump is calculated in the same method as for a centrifugal pump, except that additional allowance must be made for the requirements of the reciprocating action of the pump. The additional requirement is expressed as acceleration head. This is the head required to accelerate the fluid column on each suction stroke. So that, at a minimum, this column will catch up with the receding face of the piston during its filling stroke. For reciprocating pump, the pressure at the suction flange must meet the same requirement. But, the pump Required NPSH is generally higher than for a centrifugal pump because of pressure drop caused by the valves and pulsation in the flow at suction line. Similarly, the available NPSH supplied to the pump suction must account for the acceleration in the suction piping caused by the pulsation flow, as well as the friction, velocity, and static head. Design Guidelines for Pressure/Atmospheric Vessel at Suction Line of Pump The NPSH Available will be calculated at rated flow and lowest operating level (LALL Set Point). A 3 ft margin can be deducted from the calculated available NPSH for suction system design and suction vessel elevation setting. There may be cases where layout constraints result in limited available NPSH and reduced margin may be required. This will be subjected to field condition or design condition at the system where pump is located. Suction Calculation It involves the summation of the feed vessel’s normal operating pressure and the static head less the pressure drop in the suction piping resulting from friction, inlet-exit, and other losses. The static head for vertical vessels is calculated from the bottom tangent line while for horizontal vessels, the bottom invert line is used. Usually, no credit is taken for the head contributed by liquid operating levels in a vessel. Discharge Calculation For pump discharge lines when fittings and valve count are not available, a reasonable estimate of the total equivalent length, fitting and friction loss can be used to predict the discharge pressure required as minimum.

2.3 Safety Device

Overpressure and leak are the events which are usually happen and influence a pump performance. A device is installed at discharge line of pumps to detect high pressure caused by overpressure event or low pressure event caused by leakage. This device is Pressure Gauge. Overpressure can be caused by blockage at discharge line of pumps. When discharge line of pumps is blocked, fluid pumped from the pump will be accumulated at blocked discharge line. As pump keep on operate, the accumulated fluid at blocked discharge line will cause high pressure.



Excess back pressure can also cause overpressure when fluid from downstream of discharge line come to the upstream of discharge line having higher pressure than pumped fluid. This will cause accumulation at discharge line and then will result on overpressure. If impeller speed operates higher than normal operation, fluid pumped will have overpressure. Increase in fluid density makes a pump difficult to force its fluid. When a pump is difficult to force its fluid, this pump will operate at higher pressure to force its fluid and possibly overpressure will happen. Leakage is an event where fluid escape or outflow from the pump. This can be caused by damage of seals as the impact of deterioration, erosion, corrosion, impact damage of pump, and vibration. Vibration usually happens when pumps operate at high speed impeller. For all hydrocarbon pipeline pump discharge lines, High Pressure Sensor (PSH) should be installed at discharge line of the pump with set point between maximum operating pressure and design pressure determined at equipment downstream of discharge line. This will give sufficient time for operator to do safe anticipations. High High Pressure Sensor (PSHH) should be installed at discharge line of the pump with set point is design pressure determined at equipment downstream of discharge line. This will shut off inflow and shut down the pump if operator fails to do safe anticipations. Rating pressure at discharge line should also be considered to determine set point at PSH and PSHH. Installations of Low Pressure Sensor (PSL) and Low Low Pressure Sensor (PSLL) at discharge line have the same purposes and installations with PSH and PSHH above. But, PSL set point is between minimum operating pressure and slightly above atmospheric pressure determined by equipment at downstream of discharge line of pump. The PSLL set point is slightly above atmospheric pressure. The PSL will give sufficient time for operator to do safe anticipation. The PSLL will shut off inflow and shut down the pump as well as the function of PSHH. Set point criteria at PSH and PSHH should also consider pressure loss at discharge line to the downstream equipment and rating pressure of discharge piping. PSH and PSHH sensors can be not installed at discharge line if maximum developed pump pressure at discharge line does not exceed 70% of the maximum allowable working pressure of the discharge line or the pump is manually operated and continuously observed to prevent overpressure. PSH and PSHH sensors also can be not installed if the volume flows of fluid are small e.g. chemical injection, and downstream equipment of discharge line is atmospheric vessel (open to atmospheric). PSL and PSLL sensors also can be not installed at discharge line if the pump is manually operated and continuously observed to prevent low pressure. PSL and PSLL also can be not installed if pump does not handle hydrocarbon fluids, adequate containment is provided, small and low volume pumps e.g. chemical injection, and downstream equipment of discharge line is atmospheric vessel (open to atmospheric). PSH and PSHH sensors are not required on glycol powered glycol pump. PSL and PSLL sensors should be provided on glycol powered glycol pumps to shut off wet glycol flow to the pump.



At suction line of centrifugal pump types, PSH and PSHH should be installed to anticipate high inlet pressure unless PSH and PSHH have been installed at equipment upstream of pump. Set point for PSH and PSHH should consider maximum inlet pressure to the pump. PSL and PSLL also should be installed to anticipate low pressure inlet to the pump which may cause cavitation. PSH (include PSHH) and PSL (include PSLL) sensors should be located on the pump discharge line upstream of the check valve (FSV) where FSV is located upstream of block valve. In a glycol powered glycol pump, the PSL and PSLL on the wet glycol high pressure line should be located between the pump and the SDV. A PSV should be installed at discharge line of all pipeline pumps (mainly positive displacement types), unless the pump is kinetic energy type which is incapable to generate a head greater than the maximum allowable working pressure of the discharge piping. The PSV is possible installed at discharge line of centrifugal pump if thermal expansion is possible happen. The PSV can also be not installed if the maximum pump discharge pressure is less than the maximum allowable working pressure of the line and maximum allowable working pressure at equipment downstream of discharge line. A PSV should be provided in the wet glycol low pressure discharge line of glycol powered glycol pumps unless the discharge line is rated higher than the maximum pump discharge pressure or discharge line has been protected by a PSV installed on a downstream equipment that can not be isolated from the pump. At discharge line, the PSV should be located upstream of any block valve. A Check Valve (FSV) should be provided in the pump discharge line to minimize back flow. The check valve should be located on the pump discharge line to minimize backflow, upstream of block valve. To prevent the flow of hydrocarbons from a storage tank (tank, separator, etc) that delivers production to a pipeline pump through the pipeline pump when pump has problems and/or to prevent the flow of hydrocarbons into the pipeline in the event of a pipeline leak, a SDV should be installed and located on near the outlet of a storage component. When glycol powered pumps are used, a SDV should be located near the high pressure wet glycol outlet of the glycol contactor to shut off flow from the contactor and to shut down the pumps. Y strainer should be installed at suction line of the pump to flow the fluids when the pump needs to be off mode. The Y strainer is located at downstream of any block valve on suction line and connected to the tank that collects the fluids.



Figure 2.2 Process Flow Diagram of Pump System

2.4 General Requirements

A. The outline should be simple as practical including centrifugal, reciprocating and rotary pumps.

B. Critical elevation, all vent and drain connections, hook-up for flushing oil, seal oil, steam oil and cooling water should be shown.

2.5 Engineering requirements

A. Pumps handling viscous liquids (which are more viscous than water) shall have their water performance correction compliant with the centrifugal pump section of the Hydraulic Institute Standards.

B. If a pump which is designed normally for light fluid is capable in pumping water or other

heavy fluids under some operating conditions, the shut-off differential head when pumping the heavy fluid should be used to determine the discharge pressure.

C. Pumps that have stable head/capacity curves (continuous head rise to shut-off) are

preferred for all applications and are required when parallel operation is specified. When parallel operation is specified, the head rise shall be at least 10% of the head at rated capacity.

D. Pumps with heads greater than 200 m per stages with more than 225 kW per stage may

require special requirements to reduce vane passing frequency vibration and low-frequency vibration at reduced flow rates. This will extend life of pumps operated.

E. Suction and Discharge nozzle shall be flanged (RF type if pressure above 10 bar and FF

type for lower pressure than 10 bar) for easy installation of the pump at installed suction and discharge lines. This also will make easy for maintenance when the pump need to be removed for internal inspection, maintenance, improvement, etc.

F. Sparing philosophy. In most cases, pumps are spared. Generally common spare pump for

different duties are not recommended. However, when there is a strong incentive to apply



common spare pumps, the effect of a possibly incorrect operational line-up should be carefully considered and taken into account for piping, safeguarding and equipment design.

G. Minimum flow requirement for centrifugal pump protection is not normally required. The

usual minimum flow is usually 30% of design flow which is more than the turndown of the process and the pumps are usually tolerant of running at minimum flow for sufficient time to allow operator action.

Number cases when arise of closure and throttling of discharge may result damage to pumps which protection will be required in following cases: - High speed pump cannot tolerate running below the specified minimum flow for

event shorts period of time. The minimum flow is typically 40% to 60% of design flow but can be as high as 80% of design flow. For this application, an instrumented minimum flow recycle shall be installed back to suction vessel rather than to direct suction to avoid overheating. Usually, only one recycle flow line is installed per pump set, not for each pump and spare and the recycle control valve is air fail open.

- The cheaper alternative of a permanent recycle flow above the minimum flow is

usually not an option for these pumps as the head falls off rapidly at flows not much higher than the design flow. A permanent recycle flow above the minimum flow, usually set by a restriction orifice, is often applied when the flows varies considerably for operational reasons and the pumps uses a little power, i.e. the extra flow is quite low. A typical example is oil removal from a vacuum column overheads system.

- In cases where the pump capacity is much larger then the normal required flow,

having been sized for an upset or non-routine operation, the pump typically operated on/off via level switches in the suction vessel. Examples include water removal from drainage pits of vessel boots. If no other requirements for minimum flow protection exist, minimum flow protection is not required to handle the special case of discharge control valve closing on instrument air failure.

H. Capacity Control (Positive-Displacement Pump) Variable speed driver shall be considered for capacity control. For constant speed drives,

the available capacity controls are by recycle system or by variable stroke methods. Because positive displacement pumps have virtually no variation in capacity with pressure, throttling off the discharge is not considered as the flow is not reduced, but instead will cause the pressure in the discharge system to rise and the pump’s power requirement to increase.

I. Pulsation Dampeners (Reciprocating pumps) As described on above paragraph, Pulsation dampeners are used to reduce pressure

pulsation in the liquid flow entering and being discharge from reciprocating pumps. Pulsation should not exceed plus or minus 1.5% of the absolute working pressure in the suction and discharge manifolds. Determining if pulsation dampener required are subject to rotating engineer, and sometimes with consultation to process and instrument engineer.



J. Priming (Centrifugal Pump) If at all possible, the pump should be below the lowest level of the liquid supply, so that

the pump remains primed at all every time and NPSH required are met. Where these criteria can not be met, for example in pumping below grade pits, specialist advice should be sought regarding alternatives such as self priming pumps and submerged pumps.

K. Net Positive Suction Head (NPSH) As described on above paragraph, in order to ensure that suction conditions for a pumps

are such that no vaporization occurs in the pump suction, there has to be sufficient suction pressure above the vapor pressure of the liquid, this is called NPSH available.

As installed, the available NPSH shall exceed the required NPSH by at least 1 m

throughout the entire operating range. For pumps taking suction from vacuum column, the margin between the available and required NPSH shall be at least 2 m.

Piping Requirements

1. Suction line should be designed to minimize friction losses. To do this, uses an adequate line size, long radius elbow, full bore valve, etc. Pockets should be avoided as air and vapor can be accumulated in the pocket. This will prevent vapor phase inlet together with liquid phase to the pump. Inlet air or vapor to the pump can cause pulsation and vibration.

2. When the pump is located below the source, it may use gravitational force to flow the liquid from the source to the pump through suction line. This can be done by sloped down the installation of suction line is from the source to the suction pump.

3. Suction lines should toward the source when it is below the pump. Vertical downward suction pipes require special care to avoid pulsation and vibrations that can be caused by air or vapor entrainment.

4. In double suction line to the pumps, elbows should be installed in a position parallel to

the impeller. 5. Sufficient liquid height above the suction piping inlet, or installation of a vortex breaker,

should be provided to avoid vortex formation which may result in vapors together with liquids entering the pump.

6. In the reciprocating pumps installations, the suction line is a critical part. The suction line

should be as short as possible and sized to provide liquid velocity not more than 3 ft/s, with a minimum of bends and fittings to minimize pressure drop. A centrifugal booster pump is often used ahead of a reciprocating pump to provide adequate NPSH which would also allow higher suction line velocities.

7. Size of suction line should be one or two times larger than pump suction connection. Use reducer to connect big size of suction line with pump suction connection.

8. The suction line should be as short as possible with minimum elbows and fittings.



9. To eliminate the possibility of gas pockets (as described above paragraph), use eccentric reducer near the pump, with flat side up to keep the top of line level.

10. For reciprocating pumps, install a pulsation dampener to minimize pulsation. The

installation should be as close to the pump as possible to ensure that pressure fluctuation not being formed again before inlet to the pump suction connection.

11. In multi-pump installation, velocity changes should be avoided. In addition, acceleration

head (ha) effects should be minimized. These can be done by size the main feed line to result the velocity as close as possible to the velocity in the each individual suction line to the individual pumps.

12. Suction piping shall not be routed than the lowest level of the liquid supply and shall not have a high point where gas can accumulate. If high point unavoidable, venting facilities located for frequent use shall be provided, i.e. in heat exchanger application between suction vessel and the pump.

13. For discharge line, sizing is determined by available head and economic considerations.

Velocities range from 3 – 15 ft/s would be sufficient. Additionally, discharge line for reciprocating pump should be sized to minimize pulsation. Pulsations in reciprocating pump discharge piping are also related to the acceleration head (ha), but are more complex than suction piping pulsations.

14. If possible, discharge lines should be short and direct enough.

15. Size of discharge line should be one or two times larger than pump discharge connection.

Use reducer to connect big size of discharge line with pump discharge connection. 16. Liquid velocity at discharge line should not exceed than 3 times of the liquid velocity in

the suction line. In reciprocating pumps, this will minimize pulsations. 17. For reciprocating pumps, install a pulsation dampener to minimize pulsations. The

installation should be as close to the pump as possible to ensure that pressure fluctuation not being formed again after liquid out from dampener.

18. Provision for piping of stuffing box leakage and other drainage away from the pump

should be provided. 19. Each pump shall be provided by block valve in suction at upstream of strainer and

discharge side. The suction shut-off valve and the downstream piping to the pump inlet shall have the same pressure rating as the line work at the pump discharge side.

20. Spectacle blinds, rather than spades, shall be provided at the pump side of the block

valves to obtain positive isolation, as it facilitates maintenance and also pipe-work is usually rigid. For pumps with a suction line 2 inches and smaller spectacle blind are not required since spades or blind flanges can be made available in field.



21. Permanent strainers shall be installed at all pump suction in downstream of block valves, in order to protect pump against foreign matter, i.e. positive displacement pump are particularly prone to damage.

Y type strainers shall be used for vertical suction lines. In horizontal suction lines, Y-type

strainers or bucket type may be used. For horizontal lines, 18” or larger and also in services where large amounts of solids can be expected, bucket type strainers shall be used. In some highly fouling services, especially when no spare pumps available, duplex type strainers set are used. These enable filter switching without stopping the pump. All type of filter in suction lines of 4” and larger should have a low point drain of 1” minimum with valve and cap or blind. At initial start-up, pumps shall be protected by temporarily inserting a fine mesh screen on the upstream side of the permanent strainer.

22. Since reciprocating pump are equipped with a pressure relief valve in the discharge line, a check valve in the common discharge line as close as possible to the main process line shall be installed to prevent back flow through this pressure relief valve in case of spring failure.

23. A check valve shall be installed in rotary and centrifugal pump discharge lines. The check valve shall be located upstream of and close to the discharge block valve. In

practice this lead to the situation that a spool-piece between the block valve and check valve is required in order to turn the spectacle in larger line size. For smaller line sizes a flange to flange connection may be possible, provided that removal of the stud bolts is possible in order to turn the spectacle.

24. For spare pump which have a common suction and discharge lines, a ¾” bypass with throttling valve shall be installed around the discharge check valve in cases indicated below. For line sizes 12” and larger, where flushing oil has to be supplied via this bypass, 1” should be considered: - To minimize thermal shock if the pump has to be kept on standby at temperature

below –30 °C or above 150 °C. - If by maintaining backflow solidification/freezing, corrosion or high viscosity

problem can be avoided. - If the spool-piece between the discharge block valve and the check valve needs to be

flushed and depressurized owing to the handling of toxic or high pour point material.

This feature allows a small flow which keeps the spare pump at operating temperatures, ready for immediate start-up. Plugging of spare pump and piping connections will thus be minimized. The bypass valve should be closed when the pump is running. The bypass of the check valve can be achieved as follow:

- Connecting a line and globe valve from the spool-piece downstream of the check

valve to the upstream piping. - Connecting a line and globe valve from upstream to the top cover of the check valve,

when the discharge valve and check valve are flanged together.



25. When the suction vessel operates under vacuum, the vent connection on the pump has to be permanently piped up to the vapor space of that suction vessel, this will allow positive filling of the pump with liquid before start-up, without opening of the discharge valve. The vent line shall have two valves, one at the column end and one at the pump end of the line and a spectacle blind at pump side.

26. A line-up to similar to that above should also be considered for automatic starting pumps

to ensure proper priming. In order to reduce the flow in the priming line a restriction orifice can be installed.

27. Pumps are normally fitted with a valved vent and drain connection. If not permanently piped up, the valves shall be fitted with blind flanges. Drain shall be installed on the casing and vents preferably on the discharge line. However, where the pumps still has a pocket the vent shall be installed at the highest point of the casing. Screwed connection should be avoided on pumps, as they tend to fail after: - Being disconnected, and not properly reconnected. - Threads are damaged by corrosion. - Being exposed to external force on piping/connection. - Being exposed to vibration.

28. When liquid is considered dangerous or dangerous that it is thought inadvisable to spill small amounts when the pump is opened up, the drain and/or vent connection of the pump can be piped up permanently to the drain system.

29. Pumps handling butane or lighter fluids shall have vent line to the flare system. He vent

line shall have two valves and a spectacle blind in between. Drains on LPG pumps shall be permanently blanked without valves.

30. A Remotely Operated Valves (ROV) shall be installed in the suction line of each

individual pump when the upstream system normally contains: - More than 4m3 of LPG (butane or more volatile liquid). - More than 10m3 of hydrocarbon liquid above its auto-ignition temperature. The purpose of an ROV is to provide quick shut-off in cases where loss of containment at the pump, (seal failure or pump casing failure), could escalate into major incident. In addition to the two cases defined above, the following factors have to be taken into account to decide if an ROV is required in other circumstances:

- The potential for damage and/or emergency escalation, for example in a congested

area. - The possibility of early warning. The time available and the possibility to take

corrective action. - The probability of failure of the pump (seal). For instance a pump in hot service could be the source of ignition in the event of leakage from an adjacent pump displacing a flammable liquid below the auto-ignition temperature.



In toxic service a ROV is not strictly necessary when there is no danger of fire/explosion and after an early warning (e.g. seal failure), the pump can be approached in suitable personal protective equipment. The ROV shall be provided with a local switch for opening/closing during normal operation and one or two emergency shut-off switches: - One can be optionally located in the control room - The other one shall be located at a safe distance of minimum 15 m from the pump and

within line of sight of the pump. Remote emergency operation shall always overrule local operation.

Simultaneously with the closing of the ROV, the drive of the pump shall also be tripped. In order to protect the pump against cavitation, it shall not be permitted to run before the ROV is sufficiently opened, typically 80%, and the pump drive shall be stopped when the ROV is less than 80% open.

31. Water cooling for centrifugal pumps shall be applied on the stuffing box jacket and bearing brackets where the pumped liquid temperature is in excess of 200°C and on the pedestal if the temperature shall exceeds 350°C. The decision whether water cooling is required is the responsibility of rotating engineer.

Instrumentation Requirements

A. A pressure gauge shall be installed on the discharge line of each pump, between the pump and the check valve. It should be clearly visible from the local pump start switch as well as from the discharge block valve.

2.6 Equipment Protection Requirement

A. Pressure relief Positive displacement pump, reciprocating and rotary, shall be safeguarded against a blocked outlet. Separate external full flow pressure relief valve shall be provided to protect these pumps and its associated piping system from damage by overpressure. A pressure relief valve integral with the pump is not permitted. The pressure relief valve shall be lined up between the discharge line upstream of the block (check) valve and the suction vessel. In this case, a locked open valve downstream the pressure relief valve is required to enable the pump to be isolated during operation. Alternatively the pressure relief valve may be lined up between the discharge line upstream of the block (check) valve and the suction line downstream of the block valve.

B. Thermal expansion relief valve Pumps in LPG service may require, on the suction side, a thermal expansion relief valve

with a downstream locked-open valve lined up to flare.



Pressure relieving may be required to prevent over-pressuring caused by thermal expansion of the trapped liquid if the temperature can increase due to solar radiation. It is recommended that the TERV is installed in the pump suction piping between the pump and its suction valve rather than in the pump discharge because of the larger margin between the set pressure of the TERV and the maximum working pressure.

Flushing requirement: A. Flushing facilities, for removing process material from the pump and to cool down prior

to opening for maintenance, should be provided for pumps handling: • Liquid solidifying or having high viscosities when “cold”. • Toxic product. • Expensive solvent or product. • Fouling process stream. • Any material not acceptable in the oily sewer system.

B. The flushing medium should be compatible with the process material in the pump, as well

as with the pump hardware. For pumps handling hydrocarbons, a high flash point / low pour point gas oil is often used. For watery system, a suitable type of water, usually industrial water, is applied.

C. Backflow protection of flushing medium supply system Fixed connection is normally used for flushing oil supply/return lines. Isolation is

obtained by a double block and bleed valve arrangement, normally with a spectacle blind between the blocks and with the bleed capped or blanked.

Shaft Sealing: A. In order to prevent liquid leakage out of the pumps (centrifugal or rotary), at the point

where the rotating shaft passes out through the pump casing, seal have to be provided. The purpose of the seal is to hold the pumped liquid inside the pump at the point where the drive shaft penetrates the pump body. Simply, the seal purpose is to prevent or minimize leakage of liquid out from the pump during operation. Two common methods that are used are stuffing boxes and mechanical seals. Stuffing boxes prevent leakage at the rotating shaft by using a soft packing which is compressed and may be lubricated or wetted with the pump liquid or with an independent source. Mechanical seals prevent leakage at the rotating shaft. In this type, smooth metal surfaces slide on each other and are lubricated with a very small leakage rate of the pump liquid or with an independent liquid/source. Types of seals for pump shafts are as follows: a. Packed stuffing box; the sealing liquid may be from the pump discharge or from an

independent source. b. Water cooled stuffing box.



c. Internal assembly mechanical seal; the rotating and fixed surfaces are detained together by the pressure of the pump liquid which also serves as lubricant. This will only cause a minor leakage.

d. Double mechanical seals with independent sealing liquid. Mechanical seals are the most common sealing devices for centrifugal pumps in process applications. Mechanical seals consist of a stationary and a rotating face, and the actual sealing takes place across these very smooth, precision faces. Seal faces may require cooling and lubrication. With a certain exceptions, such as pump in intermittent operation on less essential duties, in water duties, on fire fighting pumps, and in cooling water pumps, mechanical seal shall be applied for all duties for the following reason:

To minimize maintenance on the stuffing box assembly. To prevent loss of product. To safeguard personnel and equipment against harmful product.

B. Provision shall be made to ensure a stable flow of seal flushing fluid over the mechanical

seal faces. This is often obtained by internal circulation (cooled or heated if necessary) from the pump discharge to the seal chamber and via the seal back into the pump. A clean seal flushing medium from an external source, compatible with the pumping liquid shall be used when:

The pumped liquid contains abrasives which would damage seal faces. For safety reason, escape to the atmosphere of the pumped liquid is not allowed.

C. Double mechanical seal shall be allowed in following cases :

A suitable seal flushing liquid is not available. Toxic services. Inflammable liquids. Hydrocarbon services butane and lighter. Hydrocarbon services with a seal chamber vapor pressure exceeding 5 bar abs. Services with H2S containing liquids which upon seal failure will result in an H2S

leakage rate to the atmosphere exceeding 1 g/s. A suitable buffer liquid is then applied between the primary and the secondary seal to create optimum running conditions for the seal faces and to prevent leakage to atmosphere. External to the seal, a throttle bush is fitted to limit the amount of liquid release to atmosphere upon mechanical seal failure. A (steam) quench shall be used to this cavity, external to the seal under the following conditions:

Where leakage of liquid to atmosphere could become a potential source of fire hazard.

Where leakage of liquid to atmosphere could endanger personnel due to toxicity. Where the pumped liquid would crystallize on exposure to atmosphere.



2.7 Pump Common Operational Aspect and Failure Modes:

A. During design review, appropriate access to valves and instruments in pump design shall be carefully checked. Main and secondary escape route in each pump position shall be arranged with careful prediction of future piping and instruments modification. Integration of piping plan, equipment plan and instrument plan drawings shall be used to review this purpose during engineering phase.

B. Low or no flow

Drive or coupling failure The design should take into account that the check valve in the discharge may not work, therefore backflow can occur. For high differential pressure duties, the consequences of backflow to the upstream system are often unacceptable and in these cases the standard high integrity backflow protection system, should be applied. Also, the provision of a non slam type check valve should be considered to minimize the possibility of surges pressure in the discharge line work.

Loss of NPSH

This can be caused by the number of events: Fouling of the suction strainer (e.g. during start-up). Fail close of a ROV or MOV in the suction. Failure of an upstream booster pump. Contamination of the fluid to be pumped with material that flashes in the pump,

causing vapor lock. Loss of level in the suction vessel.

The loss of NPSH, especially with high differential pressure duties may lead, often in a short time span, to severe vibrations. This is unacceptable as these vibrations may lead to seal failure or seizure of the pump and therefore design precautions, preferably inherent in the system, should be taken such as: • Avoid the need for a booster pump. • Do not use common spares for incompatible process duties. If this is not possible: • The provision of a valve position trip should be applied. • The provision of a low pressure trip should be considered. • The provision of a low level trip should be considered in special cases such as for

multistage pumps. C. Full liquid flow relief valve

The provision of full flow relief valve in discharge pumps, particularly for centrifugal pumps, should be avoided. This can normally be achieved by up-rating the design pressure of the downstream equipment or by avoiding the installation of pumps in series. However, if such a relief valve is essential then care should be taken to avoid the violent chattering that is common with liquid relief, causing more severe vibrations, capable of loosening flange bolts in the vicinity. The relief valve should be of a type, especially suitable for liquid service, and not of the “universal” type. Also a high pressure or low



flow activated trip of the pump, or a minimum flow recirculation line should be considered in order to minimize the lifting/chatter of the relief valve

D. Noise Abatement Excessive equipment noise should preferably be eliminated by low noise design. Where other noise control measures, such as acoustic insulation or acoustic enclosures, are required, they shall not in any case obstruct operational or routine maintenance activities. The use of noise hoods should be avoided because of many additional safety requirements.

E. High suction speed Pumps with high suction speed tend to be at risk to vibration (which may cause seal and bearing problems) when they are operated at other than design flow rates.

2.8 Basic Selection Criteria

Criteria to select of the pump required for a special installation. First, determine the desired flow rate or head. Then, determine the NPSH available above its requirement. When a centrifugal selection is possible, a system head-flow-rate curve should be drafted. Other aspects which are not engineering consideration like life of installation, availability of spare parts and service at the location and the preferences of operating personnel, should be considered also in selecting type of pump. Basic Principle 1. Head

Head express the pressure that a pump must put out or the pressure generated by an equivalent height of liquid. The head required to pump a fluid between two points in a piping system can be calculated by rearranging Bernoulli’s Law:

12 HHHH fP −+= …………………………………………………………….. Eq. 2.2 Where: HP = Head pump required, ft H1 = Total fluid head (include elevation, pressure, and velocity) at point 1 (suction), ft H2 = Total fluid head at point 2 (discharge), ft Hf = Head loss due to friction between points 1 and 2, ft

2. NPSH Available NPSH should always exceed the NPSH required (NPSHa ≥ NPSHr) as defined above paragraph. NPSHa = hp – hvpa + hst – hf – hvh – ha ………………………………………….. Eq. 2.3 Where:



hp = Absolute pressure head due to pressure, atmospheric or otherwise, on surface of

liquid going to suction, feed of liquid hvpa = The absolute vapor pressure of the liquid at suction temperature, feet of liquid hst = Static Head, positive or negative, due to liquid level above or below the datum

line (centerline of pump), feet of liquid hf = Friction Head or head loss due to flowing friction in the suction piping,

including entrance and exit losses, feet of liquid

hvh = Velocity Head =gh ×

=2

2lυυ , feet of liquid

ha = Acceleration Head, feet of liquid lυ = Velocity of liquid in pipeline, feet/second

g = Gravitational Constant (Usually 32.2 feet/second2)

3. For centrifugal or rotary pump, the acceleration head (ha) is zero. In reciprocating types, ha is essential. Below equation is from the Hydraulics Institute:

gKCRLh P

a ××××

= lυ ………………………………………………………………. Eq. 2.4

Where: ha = Acceleration Head, feet of liquid L = Length of Suction Line, feet (Actual Length not Equivalent Length) lυ = Average Liquid Velocity in Suction Line, feet/second

RP = Pump speed, Revolutions/minute (rpm) C = Empirical constant based on type of Pump K = A factor correspond to the Reciprocal of the Fraction of the theoretical

acceleration head which must be provided to avoid an obvious disturbance in the suction piping.

g = Gravitational Constant (32.2 feet/second2) Note that Equation 2.4 is a conservative basis which gives sufficient provision for acceleration head.

4. Horse Power Hydraulic Horse Power is obtained by multiplying the weight rate of flow by the head difference across the pump and converting to horse power.

550QHHHP P ××

=ρ ………………………………………………………………. Eq. 2.5

Where: HHP = Hydraulic Horsepower where 1 HP equals to 550 ft.lb/sec Hp = Pump Head, ft



ρ = Liquid density, lb/ft3 Q = Liquid Flow rate, ft3/sec Other conversions of HHP:

3960.. PHqGSHHP ××

=∗

…………………………………………………………… Eq. 2.6

1714PqHHP Δ×

=∗

…………………………………………………………………... Eq. 2.7

58766PQHHP Δ×

=∗

………………………………………………………………….. Eq. 2.8

Where: S.G. = Specific Gravity of Liquid relative to water (water = 1) q* = Flow rate, gpm Q* = Flow rate, barrel/day ∆P = Pressure Increase, psi The input horse power to the shaft of the pump is called the Brake Horse Power:

ηHHPBHP = ……………………………………………………………………... Eq. 2.9

Where: BHP = Brake Horse Power η = Pump efficiency Driver Horse Power (HP) for Driver pump is calculated by:

*ηBHPHP = ……………………………………………………………………... Eq. 2.10

∗×=

ηηHHPHP …………………………………………………………………… Eq. 2.11

Where: HP = Driver Horse Power η* = Driver efficiency



2.9 Equipment Selection and Design Type selection: A. Centrifugal pumps

Centrifugal pumps are kinetic machines converting mechanical energy into hydraulic energy through accelerating the liquid by a revolving device - an impeller. Whenever possible this pump is used, because it offers good capacity and head performances ranges, smooth operation, easy flow control, and has a large capacity.

Figure 2.3 Centrifugal Pump Equipment (www.tssr.nl)

They require little maintenance because of the relative simple in construction, and are available in a large variety of materials. They operate at high speed so that they can be driven directly by electrical motors. The smallest robust conventional centrifugal pump has a capacity of 3-5 m3/hr. Although non centrifugal pumps are infrequently used in refinery and centrifugal plants, they are of a great importance for certain low flow, high viscosity like slurries (using open impeller) or high discharge pressure application. Some of their disadvantages are: 1. One stage pump can not develop high pressure except at very high speeds (i.e. 10,000

rpm). Multistage pumps for high pressures are expensive, mainly in corrosion-resistant materials.

2. Pump efficiencies will drop off quickly when flow rates much different from those at

peak efficiency. 3. Centrifugal pumps are not self-priming and in some case, their performance drop off

quickly with increasing viscosity (means increasing density).


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Description of Centrifugal pumps Centrifugal pumps are kinetic type and classified as either radial flow or axial flow. In radial flow, flow enters the center of the rotating wheel (impeller) and is forced radially to the outside by centrifugal force. Within the impeller, the velocity of the liquid is increased, and this is converted to pressure by case.

Figure 2.4 Installed Centrifugal Pump (www.skf.com)

Generally, centrifugal pump consist of a stationary pump casing and an impeller mounted on a rotating shaft. The casing provides a pressure periphery for the pump and contains canal/conduit to direct the suction and discharge flow appropriately. The pump casing has suction and discharge penetrations for the main flow passageway of the pump and normally has small drain and vent fittings to remove gases trapped in the pump casing or to drain the pump casing for maintenance.

Figure 2.5 Simplified Diagram of a Typical Centrifugal Pump single volute

(www.engineersedge.com)


http://www.skf.com/

http://www.engineersedge.com/


Figure 2.6 Centrifugal Pump View (www.wfdasia.com)

The centrifugal pump casing steer the liquid from the suction connection line to the center or eye of the impeller. The vanes of the rotating impeller convey a radial and rotary motion to the liquid, forcing the liquid to the outer periphery of the pump casing where it is collected in the outer part of the pump casing called the volute. The volute is a section that expands in cross-sectional area as it covers around the pump casing. The purpose of the volute is to collect the liquid discharged from the periphery of the impeller at high velocity and gradually cause a reduction in fluid velocity by increasing the flow area. This will convert the velocity head to static pressure. The fluid is the n discharged from the centrifugal pump through discharge connection line.

Figure 2.7 Centrifugal Pump at Offshore Platform


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In axial flow, flow is developed by axial thrust of a propeller blade. This flow is parallel to the axis of the shaft. A velocity is imparted by the impeller vanes, which are shaped like airfoils. Practically, axial flow is limited to heads under 50 ft or so.

Figure 2.8 Axial Flow Centrifugal Pump (www.britannica.com)

Radial flow pumps develop a higher head per stage and operate at slower speeds than axial flow pumps. Therefore, axial flow designs are used in very high flow rate, very low head applications. Centrifugal Pump consist of a rotor (impeller) in a casing in which a liquid is given a high velocity head that is largely converted to pressure head by the time the liquid reaches the outlet. Although several impellers can be installed in series to create more large heads, centrifugal pumps are only practical for achieving high pressure when there are large flow rates. This is as well as kinetic energy equation, where energy is as means as mass and velocity. That’s why centrifugal type is more preferable for large flow rate application. Double volute pumps or called split volute pumps are another type of centrifugal pumps using volute. This type is constructed in a manner that results in two distinct volutes where each volute will receive fluids that is discharged from a 180 degrees region of the impeller at any given time.

Figure 2.9 Simplified Diagram of single and double volute (www.engineersedge.com)


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Below is simplified drawing of centrifugal pumps construction.

Figure 2.10 Simplified drawing of centrifugal pumps construction

(www.cheresources.com)

Figure 2.11 Centrifugal Pump Parts (www.cheresources.com)

B. Reciprocating and Metering Pump

For capacities lower than 0.5 m3/hr or 100 gpm, a reciprocating pump usually selected. Types of reciprocating pumps used are Diaphragm type that often used for metering service. Their utility in such applications overbalances the drawback of their intrinsic low efficiencies, of the order of 20%. Piston or plunger pumps perform well if high pressures and/or lower capacities are needed, provided that flow pulsations do not adversely affect plant control.





Figure 2.12 Reciprocating Pump Skid (www.popeoiltool.com)

In reciprocating pump, energy is added to the fluid intermittently by moving one or more boundaries linearly with a piston, plunger, or diaphragm in one or more fluid-containing volumes. Simply, these pumps fill on the backstroke and exhaust on the forward stroke (See Figure 2.14 A and B below). If liquid is pumped for along linear movement in one direction only, then the pump is classified as “single acting”. If the liquid is pumped along both direction movements, it is classified as “double acting”. Double-acting types which fill and exhaust on the same stroke have the advantage of operating at low speeds and can pump heavy liquids (high viscosity) which are difficult to handle with normal centrifugal or higher speed plunger pumps.

Figure 2.13 Simplified Diagram of a Typical Reciprocating Pump

(www.elchem.kaist.ac.kr)


http://www.popeoiltool.com/


A special type of reciprocating pump is diaphragm pump. The pump utilizes the action of a diaphragm moving backward and forward within a fixed chamber. Sometimes, the diaphragm is used to power a reciprocating pump with air or natural gas.

Figure 2.14 (A and B) Simplified Sketch of a Diaphragm-type Reciprocating Pump When

The Pump Fill on The Backstroke (A sketch) and Exhaust on The Forward Stroke (B sketch) ( www.rpi.edu)

Diaphragm pump can handle corrosive material and are often used for chemical injection. For highly dangerous liquids hydraulically actuated double diaphragm pumps are suitable.

Figure 2.15 Large Reciprocating Pump Used To Circulate The Mud (drilling fluid) on a

Drilling Rig (www.osha.gov)


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C. Rotary Positive Displacement Pump Viscosity problem of centrifugal pumps become appreciable at 40 cSt and serious at 100 cSt for small pump. Larger centrifugal pumps have a somewhat greater viscosity tolerance.

Figure 2.16 Positive Displacement, Rotary Gear Pump (www.actionwebs.com)

Figure 2.17 Cutaway of Positive Displacement Rotary Pump (www.grancopump.com)


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When a centrifugal pump is not economically justified for pumping a viscous liquid, a rotary positive displacement pump should be considered, provided the liquid is free from solids. The simplest type is the gear pump, which is generally used for small capacities (0.5 – 10 m3/hr) at 150 atm. Screw pump are used for capacities 5 – 200 m3/hr.

Figure 2.18 External (left) and Internal (right) Gear Pumps (www.britannica.com)

Principally, rotary pumps operate by having a component rotates inside a chamber to create one or more cavities or openings from suction to discharge by forcing the trapped liquid. Rotary pumps have the same characteristic as reciprocating pump. But, at low speed, leakage between the cavities will increases as low force. At very low speed, the reduction in efficiency can be very significant. This can be means not enough force to release liquid from the pump.

D. Screw pumps

Screw pumps are fixed for high viscosity liquids like polymers and dirty liquids. These types are compact, silence, and efficient.

Figure 2.19 Installed Screw Pump (www.equipnet.com)


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http://www.equipnet.com/


Figure 2.20 Engine Driven Screw Pump Skid (www.amjad-africa.com)

Figure 2.21 400HP Screw Pump Package (www.amjad-africa.com)


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E. Peristaltic pumps These types force the liquid by compressing a tube behind it with a rotor. Primarily, they are used as metering pumps at low capacities and pressures in corrosive and sanitary services when resistant flexible tubes such as those of Teflon can be used, and in laboratories.

Figure 2.22 Peristaltic Pump. 0.5" Flanged Inlet and Outlet Connections. 1.1kW 1410

rpm Motor Driven (www.wayvik.com) Peristaltic pump is also suitable for handling aggressive, high viscosity, high density products, such as abrasive slurries, corrosive acids, gaseous liquids, sand/cement mortar, liquid accelerator, etc.

Figure 2.23 Peristaltic Pump (www.water.siemens.com)


http://www.wayvik.com/

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F. Turbine pumps Turbine pumps are mainly applied for small capacity and high pressure service. In some ranges, they are more efficient than centrifugals. They are suited to handling volatile liquids because of their high suction lifts. But, these types are not suited for viscous liquids or abrasive slurries as blocking will happen at turbine section.

Figure 2.24 Vertical Turbine Pump Station (www.rainbird.com)

Figure 2.25 Vertical Turbine Pump Station with Stainless Steel Filter

(www.rainbird.com)


http://www.rainbird.com/

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Figure 2.26 Steam turbine pump station (www.cinergex.net)

Several kinds of positive displacement types are listed as follows: a. Valve action of a double acting reciprocating piston pump. b. Single acting piston pump operated by a crank. c. Simplex double acting pump. d. Duplex double acting pump. e. Internal gear pump. f. External gear pump. g. Double screw pump. h. Peristaltic pump, in which fluid is squeezed through a flexible tube by the follower. i. Double diaphragm pump. j. Turbine pump also are called regenerative or peripheral. These types are essentially self-priming and have a high tolerance for entrained gases but not usually for solids unless they may be become crushed or flattened.


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3. COMPRESSOR This section is includes Centrifugal/Axial, Reciprocating, Rotary Compressors.

3.1 Definition of Compressor

A gas compressor is mechanical equipment used to increases the pressure of flowing gas by reducing its volume (the gas is being compressed). Compression of a gas naturally increases its temperature. Compressors have the same purpose with pumps: both increase the pressure on a fluid and both can transport the fluid through a pipe. In contrary, as gas fluids are being compressed, the compressor also reduces the volume of gas fluids. But, liquid fluids can not be compressed, so the main action of a pump is to transport liquid fluids. The main types of gas compressors are illustrated below:

Figure 3.1 Diagram of The Main Types of Gas Compressors

3.2 Selection of Compressor

The choice of the type of compressor depends primarily on the required flow to be compressed, the density of the gas in conjunction to with the compression ratio and the duty to be performed. Compressor should be selected by rotating engineer in consultation with process engineer. 1. Axial compressor:

Axial compressor can handle large volume flow and are more efficient than centrifugal compressor. However, centrifugal are less vulnerable and hence more reliable, have wider operating ranges and are less susceptible to fouling. Axial compressor should be considered only for air or non-corrosive gases.


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(a) The axial flow compressor consists of rows of alternate rotating (rotor) and fixed (stator) blades. A row of rotors followed by a row of stators is known as a stage and there may be many stages attached to a single shaft.

Figure 3.2 Multi Stages Axial Compressor

Figure 3.3 Axial Flow Compressor Skid (www.powergeneration.siemens.com)

2. Centrifugal compressor:

This type of compressor can handle required flow with a reasonable efficiency and no unrealistic number of stages is required to meet high head. This compressor is preferred


http://www.powergeneration.siemens.com/


choice because it has the potential to operate continuously for long periods, if properly designed and assembled. If the flow at discharge condition is 300 m3/hr or more than, a centrifugal compressor shall always be considered.

Figure 3.4 Integrally Geared Centrifugal Compressor

(www.powergeneration.siemens.com)

Figure 3.5 Centrifugal Compressor (www.geoilandgas.com)


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Figure 3.6 Centrifugal Compressor (www.friotherm.com)

3. Reciprocating compressor:

If the required flow is too small for centrifugal compressor or where the head is so high that an undesirably large number of stages would be necessary that will fall into reciprocating compressor selection. A drawback is that reciprocating compressor generally cannot fulfill the minimum requirement of continuous uninterrupted for two year period, due to fairly high maintenance requirements. For this reason, a full capacity spare shall be provided as general rule for this type of compressor in critical services. Alternatively, three half capacity of machines shall be specified, two running in parallel with the third unit as spare.

Figure 3.7 Reciprocating Compressor Skid (www.norwalkcompressor.com)


http://www.friotherm.com/

http://www.norwalkcompressor.com/


Figure 3.8 Vertical Single-Acting Reciprocating Compressor

(www.sweethaven02.com)

Figure 3.9 Reciprocating Compressor Skid (www.norwalkcompressor.com)


http://www.sweethaven02.com/

http://www.norwalkcompressor.com/


Figure 3.10 Complete Skid-mounted of Reciprocating Compressor (www.lonestarcompressor.com)

Figure 3.10 shows a complete skid-mounted compression package (reciprocating type) including the motor driver, instrumentation and control panels, heat exchangers, separators and any other auxiliary equipment, per API-618.

4. Rotary and Screw compressor

This type of compressor may be chosen for relatively small flows with relatively large heads and shall be considered only where there is proven experience of acceptable performance of this compressor in the duty concerned and only where there are advantages over a reciprocating compressor. Successful applications are a liquid ring compressor for vacuum duty, an oil flooded rotary screw compressor for propane service in cooling unit or for tool air. The application of oil flooded rotary screw compressors for instrument air, and of dry running rotary screw compressor, sliding vane compressor and rotary lobe compressor for process duties might be considered as alternatives.


http://www.lonestarcompressor.com/


Figure 3.11 Casing of Oil free Rotary Screw Compressor (www.classzero.com)

Figure 3.12 Rotary Screw Compressor Unit (www.brehob.com)


http://www.classzero.com/

http://www.brehob.com/


Figure 3.13 Rotary Screw Compressor unit with 90 HP Natural Gas Driver (www.wellsitecompressor.com)

Figure 3.14 Diagram of Rotary and Screw Compressor Unit (en.wikipedia.org)

3.3 Process Condition and Limitation

A. Surge Condition at Centrifugal Compressor Operation of centrifugal compressors can be defined from three operating parameters: flow of fluids inlet to the compressor, speed of impeller and head available based on suction line design and NPSH minimum.


http://www.answers.com/topic/rotaryscrewcompressor-gif-1�

http://www.wellsitecompressor.com/


Stable operating compressor is provided when the head is lower than head capability and the flow rate of the gas inlet to the compressor is greater than the head available. When head is decrease, flow rate of gas inlet to the compressor should be increased. This will avoid surge condition. Surge condition will occurs when a sudden decrease of the gas flow rate inlet to the compressor causing increase in the peak head. At constant speed, the compressor can not maintain as much as flow rate of the gas against a higher pressure. So, flow rate become more decrease. A decrease of flow results in a decrease of discharge pressure. When the suction pressure is higher than the compressor outlet pressure, the fluids at discharge line tends to reverse or even flow back in the compressor. As a consequence, pressure at discharge section of compressor will decrease and inlet pressure to the compressor will increase and the flow reverses again. At certain low flow rate of the gas, the head capability will be reached for the same speed. At this point, surge is occurs. This point is named surge limit or surge point. Surge repeats and occurs in cycles. When surge point is reached, some of its compressor components like diffusers and impeller may start to operate in stall condition. Stall occurs when the gas flow rate inlet to the compressor begins to separate from a flow surface. Simply, surge is ultimate result of system instability. A commonly used method to avoid surge condition is to recycle part of the pressurized fluid from the discharge compressor line back to the compressor suction line. This will decrease pressure at discharge section of compressor and increase inlet flow rate to the compressor, resulting in stable working conditions. The amount of recycled flow rate is determined by the position of a control valve (anti surge valve). This method is implemented through anti surge system. The anti surge system provide stability of compressor system from surge condition by modulating a surge control (by-pass) valve around the compressor (covering not only between suction and discharge line, but also suction line of suction scrubber and discharge cooler at discharge line). A typical anti surge system consists of: 1. Pressure and temperature transmitter at suction and discharge lines. 2. A flow differential pressure transmitter (DPT) across the compressor flow meter or

direct DPT connected to surge controller. 3. An algorithm in the control system. 4. A surge control valve with equivalent accessories.



Figure 3.15 Simplified Flow Diagram of anti surge system where PDT across the flow meter (FT) both at suction and discharge line to detect pressure differential (PD).

An anti surge system will determine the compressor operating point using the pressure, temperature and flow data provided by PT, TT, and FT installed at suction and discharge line that are connected to the anti-surge controller. At certain condition, Pressure Differential Transmitter (PDT) can be installed directly to detect differential in pressure at suction and discharge line without detect differential flow at suction and discharge line through using flow meters at suction and discharge line.

Figure 3.16 Simplified Flow Diagram of anti surge system where PDT connected to both

suction and discharge line to detect pressure differential (PD). A Pressure Transmitter (PT) located at discharge line can be used to control discharge pressure through controlling speed of driven.



There are five essentials to avoid surge conditions: 1. An accurate surge limit model – it shall predict the surge limit over the applicable

range of gas inlet conditions and property of the gas. 2. A suitable control algorithm – it must ensure to avoid surge condition without make

action for change in the process conditioning that is unnecessary. 3. The correct instrumentation – instrument that will be used must be selected to meet

the requirements for speed, range and accuracy. 4. Proper recycle valve that selected for the compressor – Valves must fit with the

compressor. The valves shall be capable of changes in capacity both in large and rapid conditions, as well as small and slow.

5. Proper recycle valve that neither selected for the system volumes – the valve characteristic must be fitted and capable as well as fast and large enough to ensure the surge limit is nor reached during a shut down. The piping system has the dominant factor in the overall system response. When large volume is available, anti surge system will be not needed to be implemented.

To avoid surge, it must be known where the compressor will surge, the more accurately surge location predicted, the more of the range operating of the compressor available to the user and can be used to set up the set point at anti surge system to protect compressor from stall which damage to the its compressor. One of the most important items in anti surge system is a surge-relief valve. This item plays the essential anti surge system. The valve should have fast stroking speed extremely when opening (typically under 3 seconds). The valve should have high capacity to anticipate impact of the abnormal capacity occurred during start up and shut down (double the minimum for start up and shut down). The valve should be very stable in throttling control. Last, extreme noise abatement should be up to 30 decibels. The most idea to realize the anti surge system is that the realization of safe scenario for anti surge system to protect compressor system shall concern to the total system in the location of the anti surge system. Point of view shall not only consider for compressor itself or compressor system, but also systems installed at upstream and downstream of compressor system, and not as isolated items or isolation scenario looking only at the compressor itself.

B. Safety Device system by Control Box as Local panel at Reciprocating Compressor

Single Stage Dry Seal Using Water-Based Cooling System All indicator and control device should be connected to control box as local panel. At suction line: 1. Before the gas inlet to suction scrubber, flow indicator should be installed to record

flow rate of gas. This indicator is connected to control box. Change in flow rate of inlet gas will be controlled through start/stop device which is switched by hand operator locally.



2. Pressure indicator (PI) and temperature indicator (TI) should be installed for local purpose checking.

3. Also, for local purpose checking, cone strainer should be installed to check pressure

fluctuations. 4. Pressure indicators should be installed and connected to control box where PSHH and

PSLL are installed to detect changes of pressure at suction line. Hand local pressure control switch can be done by only using PI with set points are based on lowest and highest pressure at acceptable value as same as PSHH and PSLL to prevent overpressure and too low pressure inlet of the gas to compressor.

5. Temperature indicator should be installed and connected to control box where TSHH

is installed to detect high temperature at suction line. Hand local temperature control switch can be done by only using TI with set point is based on highest temperature at acceptable value as same as to TSHH to prevent over temperature inlet of the gas to compressor.

6. Pulsation dampener should be installed at suction line to reduce pressure and flow fluctuations which can cause pressure loss.

At discharge line: 1. Pressure indicator (PI) and temperature indicator (TI) should be installed for local

purpose checking.

2. Pressure indicators should be installed and connected to control box where PSHH and PSLL are installed to detect pressure at discharge line. Hand local pressure control switch can be done by only using PI with set points are based on lowest and highest pressure at acceptable value as same as PSHH and PSLL to prevent over pressure at downstream piping line and equipment and also to prevent low pressure inlet of the gas to downstream equipment as pressure loss at piping lines. PI should also be used to control pressure at discharge line through remote control.

3. Temperature indicator should be installed and connected to control box where TSHH is installed to detect high temperature at discharge line. Hand local temperature control switch can be done by only using TI with set point is based on highest temperature at acceptable value as same as to TSHH to prevent over temperature at downstream equipment related with process conditioning required or design temperature at its equipment.

4. Pressure Safety valve (PSV) should be installed to protect discharge piping line and also downstream equipment from over pressure where discharge PSV line is vented to atmosphere at safe height or location from operator.

5. Check Valve (FSV) should be installed to prevent back flow from downstream line where downstream pressure is higher than discharge pressure from compressor.



Additionally, VSHH should be installed when motor driven is used to control vibration with set point is based on highest vibration value at acceptable value to prevent damage of compressor system caused by high vibration. ESD should be connected to the control panel to shut down the compressor through interlock (PLC) if system failure is happen which may damage downstream equipment or compressor itself based on safety scenario and predictable & unpredictable events. Compressor system should have two ways to shut down. First, through start/stop hand switch manually and second, through control room automatically. For isolation, the block valve can be used at suction line of suction scrubber and discharge line of pulsation dampener. The type of isolation device will be influenced by piping line size both suction and discharge lines, pressure, and component of the gas (sweet or acid gas). If downstream equipment require dry and clean gas quality for process conditioning purpose at this equipment, oil system may not be suitable to cool and lube the piston and cylinder. Water-based cooling system can be applicable.

C. Limitation of Compression Ratio per stage for Multi Stage Compression Discharge temperature has main influence in determining final maximum of compression ratio for each stage although duty required for each compressor also give impact to compression stages and trains required. Rod loading can also be used beside of discharge temperature. At high temperature operation, it should be considered for the possibility of fire and explosion because of the oil vapors present when the handled gas contains oxygen where oxygen is one of the main component of combustion with the oil vapors. Carbonization in oil can also happen at high temperature which may cause blocking event. A safe operating temperature at compressor may be considered to be approximately 300 oF if there is oxygen in the gas loaded. If there is no oxygen, 350oF of operating temperature can be used as maximum, although vendor or mechanical propose other values. In designing booster compressor station, discharge temperature and duty required for each compressor shall be considered in designing multi stage compressions. Packing and seals life should be considered in determining discharge temperature for each compressor. At multi-stage operation, equal ratio of compression per stage is used (including pressure drop at suction and discharge lines, cooler, and suction and discharge scrubbers if necessary).



At high compression pressure, compression ratio should be decrease for each next stage (downstream) to reduce excessive rod loading. This also will reduce size of cylinder to produce the same capacity as high compression ratio means low volumetric efficiency. In multi stage compressors, suction temperature also should be consider being as low as possible to prevent thermal stress complication which may influence to discharge temperature. To avoid high temperature operating at next stage, a cooler is used between discharge line of the first compressor and suction line of the next/interstage compressor. Economic power required can be gained with pre-cooling of the gas for next stage of compressor. Use a scrubber located after the cooler and before the gas enters to next compressor to separate produced liquid phase. This will protect the compressor from liquid carryover in the gas which can cause damage to the compressor. Another method for interstage cooling are within the casing (named inter cooler). The design philosophy for choosing a compressor should include the following considerations:

a. Good efficiency over a wide range of operating conditions. b. Maximum flexibility of configuration. c. Low maintenance cost. d. Low lifecycle cost. e. Acceptable capital cost. f. High availability.

Flexibility of configuration will play important role during operation. Design of every blade installed at each compressor stages should be easy to be removed. This is not only for maintenance purpose, but also we should consider that after 5 or 10 years, flow rate and pressure of feed gas will drop down significantly. This will give effect to the increasing power consumption and increasing discharge temperature at first compressor stage. Anticipation can be taken by removes one or some blades from second or third compressor stage and installed to the first compressor stage. This action should not impact to increasing power consumption and discharge temperature at second or third compressor stages significantly over their designs.

D. Sizing Piping Line at Reciprocating Compressor In reciprocating compressor, the first-stage suction line should be sized for a pressure drop not exceed than 0.5 psia or 1% of operating pressure and maximum actual velocity of 30 ft/s. As increased pressure at interstage and discharge line, the compressibility factor will decrease and impact to decrease actual volume of the gas. So, criteria values for sizing the interstage and discharge piping can be higher than suction line. These values are pressure drop not to exceed 2% of operating pressure or 5 psi, whichever is less and a maximum velocity of 50 ft/s.



E. Special Consideration Molecular Weight Molecular weight is an important consideration in the design of a centrifugal compressor. When this or any type of compressor is to be used in multiple services, the vendor is to be supplied with data on the molecular weight of the gases. Compressor Power Estimation Compressor power estimates shall include gear losses. When a compressor is to be used in vacuum or refrigerant service, peak driver load may be required during start-up and a foot note to this effect is to be added to the specification form. The final determination of compressor power requirements and discharge gas temperatures is part of the vendor’s responsibility. Corrosive Compound Corrosive compounds in the gas (such as Sulphur Oxides, Hydrogen Sulphides, acidic compound, Chlorides, and all inorganic component bonded by Hydrogen atom that is acidic compounds), are to be specified by the process engineer these may determine the selection of materials by Foster Wheeler or the compressor manufacturer. Start-Up Considerations Start-up methods are to be considered by the process engineer since items such as anti-surge control system, by-pass lines, valve lifters and pockets on reciprocators, etc., are involved. In addition, compressors generally require a running-in period during which time and alternative feed gas may be used. If air is to be used for running-in, then suitable vents, etc. may be an additional requirement.

F. Compressor Selection and Comparison a. Centrifugal compressors are the preferred type for the majority applications. b. Reciprocation compressors are to be considered for conditions of low flow rate, high

differential pressure, intermittent loads, varying gas densities, and varying discharge pressures, combined with moderate temperatures.

c. Screw compressors may be employed for applications involving relatively low flows and differential pressures. Their selection should be referred to the rotating equipment specialists.

G. Safety Considerations

The following potential hazards are to be considered for compressor installations. a. At high pressure, many reactions proceed at higher rates, e.g. the reaction between a

hydrocarbon lube oil and oxygen or air. The discharge temperature of air from reciprocating compressors is generally limited to about 300oF – 330oF (149oC – 166oC). Compressor circuits frequently have automatic shut-down instrumentation, which operates on high gas discharge temperature.



b. Excessive discharge pressures from positive displacement machines can be attained if a discharge valve is inadvertently closed. Therefore, safety valves are mandatory for this class of compressors.

c. Adequate ventilation of the compressor house should be provided when compressing

toxic of flammable gases. This is frequently accomplished by omitting the siding from a portion of the compressor house.

d. Adequate inlet K.O. Drum should be provided where necessary to prevent liquid

slugs from damaging compressors. Providing demisters in the K.O. Drum can reduce entrainment.

e. Rotating compressors and their drivers have speed limitations. Trip-outs are indicated

and these are usually by the vendor and specified by the Mechanical Equipment Section.

H. Bearing and Seal Losses

The polytrophic horse power absorbed by the gas compression phase does not include additional power, which is required for bearing and seal losses. The combined losses may be estimated from the table below and are to be added to the polytrophic power requirement.

Shaft Sealing : 1. Centrifugal Compressor

Mechanical contact type seal should be considered for gas compressor since it offers the advantage of low oil consumption. The correct functioning of this type of seal is also less sensitive to sudden fluctuations in gas pressure which can occur during off-design conditions. Liquid-film-seal type should be used for the following duties: • Corrosive and/or fouling gases in direct contact with the seal members when

a clean buffer gas can not be made available. • Mechanical and/or thermal condition which are beyond proven capabilities

of the contact type seals.

Labyrinth-type seal are acceptable only for compressor handling non toxic and non flammable gases such as air and nitrogen. Restrictive ring type seals are not favored and their application is subject to the explicit approval of the Sr. Process Engineer. The usual sealing liquid is oil. The application of other sealing liquid such as water, in those cases where the contact between process gas and seal oil could be hazardous, or where traces of seal oil in the process stream could spoil a catalyst shall be discussed with Sr. Process Engineer or Principal Engineer.



2. Rotary Compressor In general, all centrifugal compressor shaft sealing systems as written above will give smooth operation in the design.

3. Centrifugal Fans

In general, labyrinth type seal is required for non flammable, non corrosive, non toxic gas at ambient temperature. An inert gas sealing system may be considered if leakage, either air to inside or gas to outside, is not allowed for process reason. For high temperature service, above 200 oC, a restrictive ring or labyrinth type shaft seal including a sealing gas system is preferred. If maximum sealing effect is required, mechanical contact type seal may be considered, however, this type of seal shall not be specified for high temperature service.

4. Screw Compressor

This type is often used in chemical and petrochemical plants. These compressors handle “dirty” gases with small solid contaminants. Therefore gas sealing system with mess and recycle line for lubricants have been specially made for this purpose.

I. Gear Losses The mechanical efficiency of gears used to transmit power from a driver to a compressor varies based on type of gears and gear loss. Here are as follows: Type of Gear Mechanical Efficiency, % Gear Loss, % Single Reduction 98 – 98.5 2 – 1.5 Double Reduction 97 – 97.5 3 – 2.5 Triple Reduction 96 – 96.5 4 – 3.5

J. Internal Design Pressure for Compressor System

a. A process piping and equipment which forms part of centrifugal or axial compressor

system can usually be considered as analogous to the liquid-full pumped systems considerations and the design pressure may be determined in a similar manner. However, factors will be different and should be set on a case by case basis.

b. Reciprocating compressors must be fitted with a safety relief valve on the discharge on each stage, set high enough to prevent its discharge during normal operation.

K. General Safety Device for Compressor Unit

During design review, appropriate access to valves and instruments in compressor design shall be carefully checked. Operation and maintenance access, main and secondary escape route in each compressor position shall be arranged with careful prediction of future piping and instruments modification. Integration of piping plan, equipment plan



and instrument plan drawings shall be used to review this purpose during engineering phase.

Reciprocating compressor required protection against overpressure due to blocked outlet, a relief valve often installed as safeguard on discharge line upstream of the block valve and routed to flare system. The provision of automatic block-in and/or depressuring a compressor might be considered, when seal failure could result in release of toxic gas. The compressor safeguarding system is often activated by one of the following condition:

• High liquid level in scrubber. • High speed of turbine or compressor. • High discharge temperature. • For reciprocating compressor, each cylinder usually have its own dedicated

temperature measuring point. • High discharge pressure. • Low discharge flow. • Surge. • Axial displacement. • Low seal oil pressure. • Low lube oil pressure.

Noise Abatement Excessive equipment noise should be preferably eliminated by low noise design. Where other noise control measures, such as acoustic insulation of acoustic enclosures, are required, they shall not in any case obstruct operation or maintenance personnel activities. The use of noise hoods should be avoided since many requirements of safety design is implemented in present.

PSH, PSHH, PSL and PSLL sensors should be installed on suction line and discharge line of compressor unit. These sensors can be not installed if input source, upstream of suction line is protected by these sensors. The PSH should give alarm for high pressure and PSL should give alarm for low pressure. But, PSHH and PSLL should be used to shut off all process flow rate inlet to the compressor and if compressor use fuel gas at its driven, these sensors should also shut off fuel gas flow rate to the driven. But, if the electrical motor is used as driven, the PSHH and PSLL should also shut off the electrical motor. Location of PSH, PSHH, PSL and PSLL on suction line should be as close as practical to the compressor, and on discharge line, upstream of check valve and any block valve. Suction line should also be installed with PSV to protect compressor from over pressure. If the source, upstream of suction line has been installed with PSV with set point not also to protect the source (equipment), but also to protect the compressor, PSV may not be installed at suction line of compressor. At discharge line, PSV should be provided to protect piping line and downstream equipment from over pressure. If downstream of



discharge line or equipment has been installed with PSV, PSV may not be necessary installed at discharge line of compressor. When kinetic energy type of compressor is used, PSV may not be provided on the discharge line if the compressor is not capable to increase pressure greater than the maximum allowable working pressure of its compressor or discharge line and downstream equipment. Location of PSV on suction line should be as close as practical to the compressor, and on discharge line, where PSV can not be isolated from the compressor. At discharge line location of PSV is upstream of check valve and any block valve. At suction line, location of PSV is upstream of any block valve. Check valve should be installed in discharge line located at downstream of PSV and upstream of any block valve to prevent back flow coming from downstream equipment. TSH should be installed at suction line to give alarm whenever suction temperature is at maximum near design temperature. TSHH should be installed to shut off inlet flow rate of the gas to the compressor. The TSHH should also shut off fuel gas used for driven or electrical motor driven. This will protect cylinder or case from over heating. Location of TSH and TSHH on suction and discharge line should as close as practical to the cylinder or case of compressor. Block valve should be installed on suction and discharge line for isolation the compressor during maintenance or any event where compressor must be isolated. Location of block valve on suction line is at downstream of PSV, and on discharge line, downstream of check valve. SDV should be installed on each process line (both suction and discharge line) and fuel gas line or electrical motor driven whenever compressor needs to be shut down. The result, the compressor can be isolated from all input sources. SDV should be triggered by a signal from ESD system and fire loop, and by any abnormal pressure condition sensed in the suction and discharge line. SDV should be triggered also by manual whenever ESD system fails to actuate SDV. A blow down valve (BDV) should be installed on the final discharge line which can not be isolated from any block valve. The BDV may be triggered by a signal from fire loop, gas detector, and ESD system or manually hand switched. Over pressure at suction line may be caused by excess flow rate of gas, failure of suction pressure control system, and may be caused by compressor or driven malfunction (fuel gas turbine, diesel engine, or electrical motor driven). Over pressure at discharge line, may be caused by blocked or restricted discharge line, excess back pressure, and high inlet pressure to the compressor or over speed at driven.



Leakage event caused by deterioration, erosion, corrosion, impact damage, high vibration at compressor unit may impact to low pressure at discharge pressure of the gas from compressor. High temperature event at compressor may be caused by high temperature of the gas inlet to the compressor. This can be happen when cooler get fails to cool down temperature of the gas flow rate that will go to suction compressor. Cooler failure installed at internal of compressor may cause excess temperature at cylinder or case. When internal cooler is fails, the gas discharged from compressor will has high temperature that can be higher than design temperature at discharge piping line and downstream equipment of discharge line. Excess compression ratio that is higher than normal condition may also cause excess temperature at discharge line. This may happen when speed of driven compressor is higher than normal condition. Whenever turn down is happen caused by insufficient flow rate of the gas from upstream of suction line of compressor, may cause excess temperature at discharged gas outlet from compressor. Compressor valve failure can also impact to excess temperature at discharged gas outlet from compressor.

3.4 General Requirements

A. The outline should be as simple as practical and critical elevation should be stated.

3.5 Engineering Requirements

A. For centrifugal compressor, capacity control (down to a certain minimum) by means of a variable speed driver is favored such as may be provided by steam turbine, an adjustable speed electric motor or a two-shaft gas turbine. For constant speed drives, capacity control can be achieved by suction throttling or recycle systems. Discharge throttling is not commonly used as it is inefficient. Variable inlet guide vanes may only be considered for dry, clean and non corrosive gas.

B. For centrifugal fans, capacity control (down to a certain minimum) by means of a variable speed driver is sometimes used, such as may be provided by a steam turbine or variable speed electric motor. Inlet guide vanes for capacity control shall only be specified for clean and non corrosive gas.

C. Centrifugal compressor with anti-surge control

It is an inherent characteristic of the centrifugal compressor that its performance becomes unstable at some minimum flow point, known as surging. The objective of an anti-surge control system is to ensure that the flow into centrifugal compressor is sufficient at the required pressure differential across the compressor.



With an anti-surge controller measuring the total compressor flow and the pressure differential, the controller can be set at a predetermined minimum, in excess of the estimated surge parameters, so that when the process falls below the minimum set point, the kickback or recycle flow valve will open, returning the gas to the compressor suction and thereby assuring a continuous minimum flow to the compressor inlet.

D. For reciprocating compressors, adjustable speed electric motor drivers can be considered for capacity control. The use of variable volume clearance pockets for capacity control is not favored and its application requires the explicit approval of the principal. The use of reverse flow control by means of adjustable spring-loaded suction valves should only be used in clean gas service and suction pressure where reliable operation has been demonstrated. For constant speed drives capacity control can also be achieved by a recycle system.

E. Entrainment knock-out facilities In order to prevent liquid carry over, adequate provision shall be made for separate entrainment knock-out facilities, which shall be installed as close as possible to, and upstream of the machine (i.e. suction scrubber).

F. Pulsation suppression devices for reciprocating compressors As pulsations can have a damaging effect on the piping even at moderate pressure levels, pulsation suppression devices shall be provided at the suction and discharge side of each cylinders. Cylinders operating in parallel may be connected to a common suction and common discharge pulsation device. Pulsation can cause significant pressure drop. Volume bottle should be applied for pulsation damping. Determination if pulsation devices are required is responsibility of rotating engineers, sometimes in consultation with process and instrument engineers.

G. Interstage Cooling Interstage cooling is applied, in consultation with rotating equipment engineer, when the discharge temperature can become too high. For reciprocating compressors, the maximum actual discharge temperature shall not exceed 150 °C for mechanical reasons. Special consideration shall be given to services, such as high pressure hydrogen or applications requiring non lubricated cylinders, where temperature limitation should be lower. Discharge temperature shall not exceed 135 °C for hydrogen rich services, molecular weight of 12 or less (API RP 618). Vendor consultation is required to determine proper interstage cooling as required.

3.6 Piping and Instrumentation Consideration

A. The suction line between knock out drum or scrubber and compressor shall be as short as practicable, without pockets and slope towards the knock out drum. Condensation and



accumulation of condensate in this suction line shall be prevented e.g. by heat tracing (in 4 season country) and several design case of reciprocating compressor.

B. Suction lines shall be connected to the top of the header, except for suction line at least

one pipe smaller than the header, which may be connected concentrically at the side of the header.

C. Complete isolation shall be possible designed from process and auxiliary system, such as

flare and nitrogen. Permanent isolation shall be provided by spectacle blinds, removable spool piece or elbows.

D. In each compressor suction line, a temporary suction strainer shall be installed

downstream of the block valve of the compressor and as close as possible to the compressor suction nozzle. Suction strainer shall be provided to safeguard the compressor from extraneous solid material getting inside the machines, particularly during the first month of operation or after maintenance shutdown. The strainer shall be conical type incorporated within a spool piece of adequate length to facilitate bulk removal. Pressure tapping might be provided across the strainer to enable fouling estimation.

E. A check valve shall be installed in discharger line for following suggested reason :

For rotary and centrifugal compressor, check valves are required to prevent reverse flow and consequently reverse rotation of the compressor after shutdown. While for reciprocating compressor, check valves are required to prevent backflow through the relief valve in case of spring failure.

F. Any recycle line shall be routed to the inlet of the knock out drum via cooler/condenser.

The control valve in recycle line shall be self draining to both sides without pockets. Special provision shall be made for depressuring and purging in the compressor. Nitrogen purge to be available for air removal to safe location and for gas removal to flare or, if gas is non toxic and lighter than air to safe location. This installation shall permit test run facility of the compressor on air or other test gas under the condition recommended and specified by manufacturer (vendor). Depending to pressure and line size, as guide class 600 and above, a pressurizing bypass may be needed for commissioning purpose.

G. When recycle line is used for capacity control, the recycle valve shall be capable of

smooth control and for this reason an arrangement of two valves in parallel may be considered. If the compressor required on-stream performance checking, suitable instrumentation shall be indicated for this purpose in drawing such as flow, pressure, temperature and vibration.




Author:

Alvin currently works as Managing Safe Work (MSW) Champion for Chevron Indonesia Company, East Kalimantan. He is in charge at facilitating, deploy and monitoring safe work practice implementation in Kalimantan Operation and across IndoAsia Business Unit, direct report to OE/HES Manager, and works under direct guidance of Operation Managers and Sr. VP Kalimantan Operation. Previously in Chevron, he is in charge for facilitating process safety study, Safety in Design (ergonomic base) review, reviewing contractor HES program in capital project and major modification, project HES evaluation, also construction and installation review. He has been working as SHEQ Advisor, Process and Safety Engineer in various oil and gas contractor company. He is a member of KMI, IIPS, PII, CCPS Global network and AIChE. He can be further contacted in [email protected] .

Alvin’s references:

1. API, ASME and various industry standards for pressure vessel, pump and compressor. 2. Technip design work experience 2002-2006. 3. Engineers India work book. 4. Various engineering articles from legacy Unocal. 5. Process Engineering and Safeguarding Manual, EPMI. 6. Various engineering and solution company best practice in process engineering.

Co-Author:

Ronaldo Reagan? People always compare his name with that Brazillian famous soccer striker. Yes, both of them have same famous name: Ronaldo. Otherwise, they compare him with Ronald Reagan, the fortieth President of the United States (1981-1989). But, Ronaldo is just Ronaldo with complex ideas, but logic and simple as better engineering practises and solutions with approach of process (design) engineering of upstream oil and gas plants (main process facilities). He can be further contacted in [email protected] .

Ronaldo’s references:

1. API, ASME and various industry standards for pressure vessel, pump and compressor. 2. Section 7, 12, and 13 of Gas Processors Suppliers Association. 3. Various engineering and equipment design criteria and philosophy company best practice in process safety and process

engineering. 4. NORSOK STANDARD – Process Design, P-001 5th Edition, September 2006. 5. Ken Arnold and Maurice Stewart, “Surface Production Operations”, Volume 1 and 2. 6. John M. Campbell, “Gas Conditioning and Processing”. 7. James R. Couper and friends, “Chemical Process Equipment”, 2nd Edition. 8. Daniel A. Crowl and Joseph F. Louvar, “Chemical Process Safety”, 2nd Edition. 9. Email correspondences with oil and gas company client representative during the design (both basic (FEED) and detail engineering)

experience. 10. Engineering articles from internet.

mailto:[email protected]

mailto:[email protected]

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