Check List API Rp 14c

7/27/2019 Check List API Rp 14c

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API RP 14C CHECKLIST

TABLE OF CONTENTS

A.1 Wellhead and Flow Lines

A.2 Wellhead Injection Lines

A.3 Headers

A.4 Pressure Vessels

A.5 Atmospheric Vessels

A.6 Fired and Exhaust Heated Components

A.7 Pumps

A.8 Compressors

A.9 Pipelines

A.10 Heat Exchangers

A.11 Miscellaneous Items Not Specifically Addressed in 14C


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WELLHEADS AND FLOW LINES

Wellheads furnish surface control (manual and automatic) and containment of well fluids and provide downhole access for well servicing. Flow lines transport hydrocarbons

from the wellhead to the first downstream process component.

For analysis purposes and assignment of safety devices, flow line are divided into flow line segments. A flow line segment is any portion of a flow line that has an assignedoperating pressure different from other portions of the same flow line. These flow line segments can be classified s either initial (beginning at wellhead), intermediate, or final

(terminating at another process component) segments. Thus, a flow line that experiences a reduction in operating pressure due to some inline pressure reducing device, such as a

choke, and has two different assigned operating pressures, will have an initial and final segment. A flow line that experiences no reduction in operating pressure due to a

pressure reducing device will have only one segment. In this case, the initial and final flow line segment will be the same. Each flow line segment must be analyzed to determine

appropriate safety devices. Recommended safety devices for typical wellheads and flow lines are shown in Figures A.1.1, A.1.2 and A.1.3.

14C ITEM SAC REFERENCE NOTES


a. High Pressure Sensor (PSH)1. PSH installed.2. Flow line segment has a maximumallowable working pressure greater thanmaximum shut in pressure and isprotected by a PSH on downstream flowline segment.

b. Low Pressure Sensor (PSL)1. PSL installed.2. Flow line segment is between the welland the first choking device and is lessthan 10 feet (3m) in length or, in the caseof an underwater installation, reasonablyclose to that distance.

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14CITEM SACREFERENCE NOTES

c. Pressure Safety Valve (PSV)1. PSV installed.2. Flow line segment has maximumallowable working pressure greater thanthe maximum shut-in pressure.3. Two SDVs (one of which may be theSSV) with independent PSHs, relays, andsensing points are installed where there isadequate flow line volume upstream ofany block valves to allow sufficient timefor the SDVs to close before exceeding

the maximum allowable working pressure.4. Flow line segment is protected by aPSV on upstream segment.5. Flow line segment is protected by aPSV on downstream component thatcannot be isolated from the flow linesegment and there are no chokes or otherrestrictions between the flow line segmentand the PSV.

d. Flow Safety Valve (FSV)1. FSV installed.2. Flow line segment is protected by FSV

in final flow line segment.Additional Items outside of 14Crequirements

Are the manual boarding valves designedto prevent slugged flow when the SDVopens?

Is there periodic verification of the chokesize against the maximum rate of flowallowed by downstream pressureprotection systems?

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Is positive isolation present on all highpressure and intermediate pressureheader valves and bypass valves that tieinto the low pressure manifold?

Is there a management system in place toswitch the SCADA system to the propersetting for pressure monitoring when theheaders are switched between high andintermediate pressure wells or betweenintermediate and low pressure wells?



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For analysis purposes and assignment of safety devices, flow line are divided into flow line segments. A flow line segment is any portion of a flow line that has an assigned

operating pressure different from other portions of the same flow line. These flow line segments can be classified s either initial (beginning at wellhead), intermediate, or final











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For analysis purposes and assignment of safety devices, flow line are divided into flow line segments. A flow line segment is any portion of a flow line that has an assignedoperating pressure different from other portions of the same flow line. These flow line segments can be classified s either initial (beginning at wellhead), intermediate, or final











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WELLHEAD INJECTION LINES

Injection lines transfer fluids to the wellbore for artificial lift or reservoir injection. Recommended safety devices for typical wellhead injection lines are shown inFigure A-2.

14C ITEM SACREFERENCE

NOTES

A.2 Wellhead Injection Lines

a. High Pressure Sensor (PSH)1. PSH installed.2. Line and equipment areprotected by an upstream PSH.

b. Low Pressure Sensor (PSL)1. PSL installed.2. Line and equipment areprotected by an upstream PSL.

c. Pressure Safety Valve (PSV)1. PSV installed.2. Line and equipment have amaximum allowable workingpressure greater than themaximum pressure that can beimposed by the injection source.3. Line and equipment areprotected by an upstream PSV.

d. Flow Safety Valve (FSV)1. FSV(s) installed.



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PSV

PSHL FSV SDV

FSV

PSV

FSVPSHL

PSV

FSVPSHL


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HEADERS

Headers receive production from two or more flow streams and distribute production to the required process system, such as the low, intermediate or highpressure production and test separation facilities. Recommended safety devices for typical headers are shown in Figure A-3.


A.3 Headers

a. High Pressure Sensor (PSH)1. PSH installed.

2. Each input source is equipped with aPSH set less than the maximum allowableworking pressure of the header.3. Header is protected by downstreamPSH that cannot be isolated from theheader.4. Header is for flare, relief, vent, or otheratmospheric service and has no valving inthe outlet piping.

b. Low Pressure Sensor (PSL)1. PSL installed.2. Each input source is protected by a

PSL and there are no pressure controldevices or restrictions between the PSLand the header.3. Header is for flare, relief, vent, or otheratmospheric service.



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c. Pressure Safety Valve (PSV)1. PSV installed.2. Header has a maximum allowableworking pressure greater than themaximum shut in pressure of anyconnected well.3. Pressure relief protection is providedon each input source having a maximumshut-in pressure greater than themaximum allowable working pressure ofthe header.

4. Header is protected by downstreamPSV that cannot be isolated from theheader.5. Header is for flare, relief, vent, or otheratmospheric service and has no valving inthe outlet piping.6. Input source is a well(s) having apressure greater than the maximumallowable working pressure of the headerand is equipped with two SDVs (one ofwhich may be the SSV) controlled byindependent PSHs connected to separaterelays and sensing points. Other inputsources having a pressure greater thanthe maximum allowable working pressureof the header are protected by PSVs.



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PRESSURE VESSELS

Pressure vessels handle hydrocarbons under pressure for liquid-gas separation, dehydration, storage, and surge. Some pressure vessel applications requireheat input. This discussion covers only the effects of heat input to the process section of a heated vessel. Heating equipment is covered in A.6 and A.10.Pressure vessels associated with compressors, other than compressor cylinders, should be protected in accordance with this section. Compressor cylinders and

cases are covered in A.8. Recommended safety devices for typical pressure vessels are shown in Figure A-4.


A.4 Pressure Vessels

a. High Pressure Sensor (PSH)1. PSH installed.2. Input is from a pump or compressorthat cannot develop pressure greater thanthe maximum allowable working pressureof the vessel.3. Input source is not a wellhead flow

line(s), production header, or pipeline andeach input source is protected by a PSHthat protects the vessel.4. Adequately sized piping without blockor regulating valves connects gas outlet todownstream equipment protected by aPSH that also protects the upstreamvessel.5. Vessel is final scrubber in a flare,relief, or vent system and is designed towithstand maximum built upbackpressure.

6. Vessel operates at atmosphericpressure and has an adequate ventsystem.



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b. Low Pressure Sensor (PSL)1. PSL installed.2. Minimum operating pressure isatmospheric pressure when in service.3. Each input source is protected by aPSL and there are no pressure controldevices or restrictions between thePSL(s) and the vessel.4. Vessel is scrubber or small trap, is nota process component, and adequateprotection is provided by downstreamPSL or design function (e.g., vessel is gasscrubber for pneumatic safety systems orfinal scrubber for flare, relief, or ventsystem).5. Adequately sized piping, without blockor regulating valves connects to gas outletto downstream equipment protected by aPSL that also protects the upstreamvessel.



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c. Pressure Safety Valve (PSV)1. PSV installed.2. Each input source is protected by aPSV set no higher than the maximumallowable working pressure of the vesseland a PSV is installed on the vessel forfire exposure and thermal expansion.3. Each input source is protected by aPSV set no higher than the vessels, atleast one of these PSVs cannot beisolated from the vessel.4. PSVs on downstream equipment cansatisfy relief requirement of the vesseland cannot be isolated from the vessel.5. Vessel is final scrubber in a flare,relief, or vent system, is designed towithstand maximum built up backpressure, and has no internal or externalobstructions, such as mist extractors orback pressure valves.6. Vessel is final scrubber in a flare,relief, or vent system, is designed towithstand maximum built up backpressure, and is equipped with a rupturedisk or safety head (PSE) to bypass anyinternal or external obstructions, such asmist extractor or back pressure valves.

d. High Level Sensor (LSH)1. LSH installed.2. Equipment downstream of gas outlet isnot a flare or vent system and can safelyhandle maximum liquid carryover.3. Vessel function does not requirehandling separated fluid phases.4. Vessel is small trap from which liquidsare manually drained.



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e. Low Level Sensor (LSL)1. LSL installed to protect each liquidoutlet.2. Liquid level is not automaticallymaintained in the vessel and the vesseldoes not have an immersed heatingelement subject to excess temperature.3. Equipment downstream of liquidoutlet(s) can safely handle maximum gasrates that can be discharged through theliquid outlet(s) and vessel does not havean immersed heating element subject toexcess temperature. Restrictions in thedischarge line(s) and may be used to limitthe gas flow rate.

f. Check Valve (FSV).1. FSV installed on each outlet.2. The maximum volume of hydrocarbonsthat could backflow from downstreamequipment is insignificant.3. A control device in the line willeffectively minimize backflow.

g. High Temperature Sensor (TSH)1. TSH installed.2. Heat source is incapable of causingexcess temperature.



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ATMOSPHERIC VESSELS

Atmospheric vessels are used for processing and temporary storage of liquid hydrocarbons. Some applications require heat input to the vessel. This discussioncovers only the effects of heat input to the process section of an atmospheric vessel. Heating equipment is covered in A.6 and A.10. Recommended safetydevices for typical atmospheric vessels used in a production process system are shown in Figure A.5. Vessels such as those used for diesel fuel and chemical

storage that are ancillary to the production process system are not covered by this recommended practice. However, some of the recommendations contained inAppendix C.1, Emergency Support Systems, might be applicable when installing such equipment.


A5. AtmosphericVessels

a. Vent1. Vent installed.

b. Pressure-Vacuum Relief Device(PSV).1. PSV installed.2. Vessel has second vent capable of

handling maximum gas volume.3. Component is a pressure vessel, notsubject to collapse, that operates inatmospheric service and is equipped withan adequately sized vent.4. Vessel has no pressure sources(except blanket gas and/or manual drains)and is equipped with an adequately sizedvent.

c. High Level Sensor (LSH).1. LSH installed.2. Fill operations are continuously

attended.3. Overflow is diverted or contained byother process components.



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d. Low Level Sensor (LSL).1. LSL installed.2. Adequate containment system isprovided.3. Liquid level is not automaticallymaintained in the vessel and vessel doesnot have an immersed heating elementsubject to excess temperature.4. Component is final vessel in acontainment system designed to collectand direct hydrocarbon liquids to a safelocation.

e. High Temperature Sensor (TSH)

High temperature sensors are applicableonly to vessels having a heat source.1. TSH installed.2. Heat source is incapable of causingexcess temperature.

Additional items not specificallyrequired in 14C

Is there an oil/water interface level alarmon the last water treatment tank?

Is their vacuum protection on the hot oil

surge tank to prevent its collapse during ashutdown?

Is there a high level alarm on the sumpsurge tank or final tank in the watertreatment system?



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PSV

AtmosphericVessel

Notes:TSE designations are symbolic and are not intended to reflect actuallocation or quantity.

Figure A-5 Recommended Safety Devices-Atmospheric Tank


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FIRED AND EXHAUST HEATED COMPONENTS

Fired and exhaust heated components are used for processing and heating hydrocarbons. Included are both direct and indirect fired atmospheric and pressurevessels and tube-type heaters equipped with either automatically controlled natural or forced draft burners. Also included are exhaust heated components thatuse exhaust gases from other equipment such as turbines and engines as a heat source, and that may or may not be supplementary fired. This sectiondiscussed the required protection for firing equipment of a fired component and for the heating section of exhaust heated components. Protection for the processportion of a fired or exhaust heated component is discussed under the appropriate component. Recommended safety devices for a typical fired vessel equippedwith a natural draft burner or a forced draft burner are shown in Figures A.6.1 and A.6.2, respectively. Recommended safety devices for a typical exhaust heatedcomponent are shown in Figure A.6.3.


A.6 FiredandExhaustHeatedComponents

a. High Temperature Sensor (mediumor process fluid) (TSH)1. TSH installed.2. Component is a steam generator

protected by a PSH and, if fired, by a LSL.3. Component is an indirect water bathheater in atmospheric service and isprotected by an LSL.

b. High Temperature Sensor (stack)TSH).1. TSH installed.2. Component is isolated and does nothandle combustible medium or processfluids other than fuel.3. Component is exhaust heated withoutsupplemental firing and medium is not

combustible.c. (Deleted in Second Edition.)

d. Low Pressure Sensor (air supply)(PSL).1. PSL installed.2. Component is equipped with a naturaldraft burner.3. Forced draft burner is equipped withanother type of low air supply sensor.4. Component is exhaust heated withoutsupplemental firing.



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e. High Pressure Sensor (fuel supply)(PSL).1. PSH installed.2. Component is exhaust heated withoutsupplemental firing.

f. Low Pressure Sensor (fuel supply)(PSL).1. PSL installed.2. Component is equipped with a naturaldraft burner.3. Component is exhaust heated withoutsupplemental firing.

g. Flame Failure Sensor (BSL).1. BSL installed.2. Component is exhaust heated withoutsupplemental firing.

h. Low Flow Sensor (heated medium)(FSL).1. FSL installed.2. Component is not a closed heattransfer type in which a combustiblemedium flows through tubes located inthe firing or exhaust heated chamber.

i. Motor Interlock (forced draft fanmotor).1. Motor interlock installed.2. Component is equipped with a naturaldraft burner.3. Component is exhaust heated withoutsupplemental firing.



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j. Flame Arrestor (air intake).1. Flame arrestor installed.2. Component is equipped with a forceddraft burner.3. Component is located in an isolatedarea and not handling combustiblemedium or process fluids other than fuel.4. Component is exhaust heated withoutsupplemental firing.

k. Stack Arrestor.1. Stack arrestor installed.2. Component is equipped with a forceddraft burner and (i) the fluid being heatedis non-flammable, or (ii) the burner draftpressure at the exit of the transfer sectionis higher than the fluid pressure (head).3. Component is isolated so processfluids will not contact stack emissions.4. Component is exhaust heated withoutsupplemental firing.

l. Pressure Safety Valve (mediumcirculating tube) (PSV).1. PSV installed.2. Component is not a tube type heater.3. PSV installed on another componentwill provide necessary protection and thePSV cannot be isolated from the tubesection.

m. Check Valve (medium circulatingtube) (FSV).1. FSV installed on each outlet.2. The maximum volume of combustiblemedia that could backflow fromdownstream equipment is insignificant, ormedium is not combustible.3. Component is not a tube type heater.



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Electric HeatersNot specifically covered under 14C

Check ABS requirements

High temperature alarm and shutdown

Low level sensor

Low flow sensor



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a. High Temperature Sensor (mediumor process fluid) (TSH)1. TSH installed.

2. Component is a steam generatorprotected by a PSH and, if fired, by a LSL.3. Component is an indirect water bathheater in atmospheric service and isprotected by an LSL.

b. High Temperature Sensor (stack)TSH).1. TSH installed.2. Component is isolated and does nothandle combustible medium or processfluids other than fuel.3. Component is exhaust heated without

supplemental firing and medium is notcombustible.

c. (Deleted in Second Edition.)



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j. Flame Arrestor (air intake).1. Flame arrestor installed.2. Component is equipped with a forceddraft burner.3. Component is located in an isolatedarea and not handling combustiblemedium or process fluids other than fuel.4. Component is exhaust heated withoutsupplemental firing.

k. Stack Arrestor.1. Stack arrestor installed.2. Component is equipped with a forceddraft burner and (i) the fluid being heatedis non-flammable, or (ii) the burner draftpressure at the exit of the transfer sectionis higher than the fluid pressure (head).3. Component is isolated so processfluids will not contact stack emissions.4. Component is exhaust heated withoutsupplemental firing.




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Low level sensor

Low flow sensor



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a. High Temperature Sensor (mediumor process fluid) (TSH)1. TSH installed.2. Component is a steam generator

protected by a PSH and, if fired, by a LSL.3. Component is an indirect water bathheater in atmospheric service and isprotected by an LSL.

b. High Temperature Sensor (stack)TSH).1. TSH installed.2. Component is isolated and does nothandle combustible medium or processfluids other than fuel.3. Component is exhaust heated withoutsupplemental firing and medium is not

combustible.



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c. (Deleted in Second Edition.)








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j. Flame Arrestor (air intake).1. Flame arrestor installed.2. Component is equipped with a forceddraft burner.3. Component is located in an isolated

area and not handling combustiblemedium or process fluids other than fuel.4. Component is exhaust heated withoutsupplemental firing.

k. Stack Arrestor.1. Stack arrestor installed.2. Component is equipped with a forceddraft burner and (i) the fluid being heatedis non-flammable, or (ii) the burner draftpressure at the exit of the transfer sectionis higher than the fluid pressure (head).3. Component is isolated so process

fluids will not contact stack emissions.4. Component is exhaust heated withoutsupplemental firing.




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Low level sensor

Low flow sensor



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PUMPS

Pumps transfer liquids within the production process and into pipelines leaving the platform. Pipeline pumps transfer produced hydrocarbons from the processsystem to a pipeline. Pumps that occasionally transfer small volumes of hydrocarbons from ancillary equipment (swab tanks, sumps, etc.) to a pipeline thatreceives the bulk of its volume from another source are not considered pipeline pumps. Glycol powered glycol pumps circulate glycol within a closed system.

Other pumps transfer produced liquids, heat transfer liquids, or chemicals within the production process system or from the containment system to the processsystem (booster/charge pumps, sump pumps chemical injection pumps, heating medium circulating pumps, glycol pumps, etc.). Recommended safety devicesfor typical pump installations are shown in Figures A.7.1, A.7.2, and A.7.3.


A.7 Pumps

a. High Pressure Sensor (PSH)pipeline pumps.1. PSH installed.

b. High Pressure Sensor (PSH) other

pumps.1. PSH installed.2. Maximum pump discharge pressuredoes not exceed 70% of the maximumallowable working pressure of dischargepiping.3. Pump is manually operated andcontinuously attended.4. Small, low volume pumps, e.g.,chemical injection pumps.5. Pump discharges to an atmosphericvessel.6. Pump is a glycol powered glycol pump.



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c. Low Pressure Sensor (PSL) pipelinepumps.1. PSL installed.2. Pump does not handle hydrocarbons.

d. Low Pressure Sensor (PSL) otherpumps.1. PSL installed.2. Pump is manually operated andcontinuously attended.3. Adequate containment is provided.4. Small. Low volume pumps, e.g.,chemical injection pumps.5. Pump discharges to an atmosphericvessel.

e. Pressure Safety Valves (PSV)pipeline pumps.1. PSV installed.2. Pump is kinetic energy type andincapable of generating a head greaterthan the maximum allowable workingpressure of the discharge piping.



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f. Pressure Safety Valves (PSV) other pumps.1. PSV installed.2. Maximum pump discharge pressure isless than the maximum allowable workingpressure of discharge piping.3. Pump has internal pressure reliefcapability.4. Pump is a glycol powered glycol pump,and the wet glycol low pressure dischargepiping is rated high than the maximumdischarge pressure.

5. Pump is a glycol powered glycol pump,and the wet glycol low pressure dischargepiping is protected by a PSV on adownstream component that cannot beisolated from the pump.

g. Check Valve (FSV) all pumps.1. Check valve installed.



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PUMPS

Pumps transfer liquids within the production process and into pipelines leaving the platform. Pipeline pumps transfer produced hydrocarbons from the processsystem to a pipeline. Pumps that occasionally transfer small volumes of hydrocarbons from ancillary equipment (swab tanks, sumps, etc.) to a pipeline thatreceives the bulk of its volume from another source are not considered pipeline pumps. Glycol powered glycol pumps circulate glycol within a closed system.

Other pumps transfer produced liquids, heat transfer liquids, or chemicals within the production process system or from the containment system to the processsystem (booster/charge pumps, sump pumps chemical injection pumps, heating medium circulating pumps, glycol pumps, etc.). Recommended safety devicesfor typical pump installations are shown in Figures A.7.1, A.7.2, and A.7.3.


A.7 Pumps


b. High Pressure Sensor (PSH) other

pumps.1. PSH installed.2. Maximum pump discharge pressuredoes not exceed 70% of the maximumallowable working pressure of dischargepiping.3. Pump is manually operated andcontinuously attended.4. Small, low volume pumps, e.g.,chemical injection pumps.5. Pump discharges to an atmosphericvessel.6. Pump is a glycol powered glycol pump.




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e. Pressure Safety Valves (PSV)pipeline pumps.

1. PSV installed.2. Pump is kinetic energy type andincapable of generating a head greaterthan the maximum allowable workingpressure of the discharge piping.



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f. Pressure Safety Valves (PSV) other pumps.1. PSV installed.2. Maximum pump discharge pressure isless than the maximum allowable workingpressure of discharge piping.3. Pump has internal pressure reliefcapability.4. Pump is a glycol powered glycol pump,and the wet glycol low pressure dischargepiping is rated high than the maximum

discharge pressure.5. Pump is a glycol powered glycol pump,and the wet glycol low pressure dischargepiping is protected by a PSV on adownstream component that cannot beisolated from the pump.




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PUMPS

Pumps transfer liquids within the production process and into pipelines leaving the platform. Pipeline pumps transfer produced hydrocarbons from the processsystem to a pipeline. Pumps that occasionally transfer small volumes of hydrocarbons from ancillary equipment (swab tanks, sumps, etc.) to a pipeline thatreceives the bulk of its volume from another source are not considered pipeline pumps. Glycol powered glycol pumps circulate glycol within a closed system.Other pumps transfer produced liquids, heat transfer liquids, or chemicals within the production process system or from the containment system to the process

system (booster/charge pumps, sump pumps chemical injection pumps, heating medium circulating pumps, glycol pumps, etc.). Recommended safety devicesfor typical pump installations are shown in Figures A.7.1, A.7.2, and A.7.3.


A.7 Pumps


b. High Pressure Sensor (PSH) otherpumps.1. PSH installed.2. Maximum pump discharge pressuredoes not exceed 70% of the maximumallowable working pressure of dischargepiping.3. Pump is manually operated andcontinuously attended.4. Small, low volume pumps, e.g.,chemical injection pumps.5. Pump discharges to an atmosphericvessel.6. Pump is a glycol powered glycol pump.




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e. Pressure Safety Valves (PSV)pipeline pumps.

1. PSV installed.2. Pump is kinetic energy type andincapable of generating a head greaterthan the maximum allowable workingpressure of the discharge piping.

f. Pressure Safety Valves (PSV) other pumps.1. PSV installed.2. Maximum pump discharge pressure isless than the maximum allowable workingpressure of discharge piping.3. Pump has internal pressure relief

capability.4. Pump is a glycol powered glycol pump,and the wet glycol low pressure dischargepiping is rated high than the maximumdischarge pressure.5. Pump is a glycol powered glycol pump,and the wet glycol low pressure dischargepiping is protected by a PSV on adownstream component that cannot beisolated from the pump.




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COMPRESSORS

Compressor units transfer hydrocarbon gases within the production process and into pipelines leaving the platform. Recommended safety devices for a typicalcompressor unit are shown in Figure A.8.


A.8 Compressors

a. High Pressure Sensor (PSH) suction1. PSH installed.2. Each input source is protected by aPSH that will also protect the compressor.

b. High Pressure Sensor (PSH) discharge.1. PSH installed.2. Compressor is protected by adownstream PSH, located upstream ofany cooler, that cannot be isolated fromthe compress.

c. Low Pressure Sensor (PSL) suction.1. PSL installed.2. Each input source is protected by aPSL that will also protect the compressor.

d. Low Pressure Sensor (PSL) discharge.1. PSL installed.2. Compressor is protected by adownstream PSL that cannot be isolatedfrom the compressor.

e. Pressure Safety Valve (PSV) suction.1. PSV installed.2. Each input source is protected by aPSV that will also protect the compressor.



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f. Pressure Safety Valve (PSV) discharge.1. PSV installed.2. Compressor is protected by adownstream PSV, located upstream ofany cooler, that cannot be isolated fromthe compressor.3. Compressor is kinetic energy type andincapable of generating a pressuregreater than the maximum allowableworking pressure of the compressor ordischarge piping.

g. Check Valve (FSV) final discharge.1. FSV installed.

h. High Temperature Sensor (TSH).1. TSH installed.

Items not specifically required by 14C

Does activation of the SDV on the gasexport riser initiate a shutdown of the gascompressors?

Is there a management system to assureonly the low-pressure switches for the gascompressors are bypassed duringstartup?



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PIPELINES

Offshore pipelines direct liquids and gases between platforms or between a platform and shore facility. Pipelines are classified as (a) incoming, (b) departing, or(c) bi-directional, depending on the direction of flow at the platform. An incoming pipeline directs fluids onto the platform and a departing pipelines transportsfluids from the platform. A bi-directional pipeline can transport liquids in either direction. Pipelines can be further classified according to the delivery or receiving

point as follows:

Incoming pipelines:Deliver to platform facilities,Delivery to departing pipeline,

Departing pipelines:Receiving from platform facilities,Receive from incoming pipeline(s),Receive from both platform utilities and incoming pipeline(s),

Bi-directional pipelines:Deliver to and receive from platform facilities,Deliver to and receive from another bi-directional pipeline,

Delivery to and receive from other bi-directional pipelines and receives from platform facilities.


A.9 Pipelines

a. High Pressure Sensor (PSH).1. PSH installed.2. Delivering pipeline protected by PSHlocated on upstream component.3. Each input source is protected by aPSH that also protects a departing or bi-directional pipeline.

4. The pipeline is protected by a PSHlocated on a parallel component.

b. Low Press Sensor (PSL).1. PSL installed.2. Delivering piping protected by PSLlocated on upstream component.3. Each input source is protected by aPSL that also protects a departing or bi-directional pipeline.4. The pipeline is protected by a PSLlocated on a parallel component.



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c. Pressure Safety Valve (PSV).1. PSV installed.2. Pipeline has a maximum allowableoperating pressure greater than themaximum allowable operating pressure ofthe pipeline is protected by a PSV set nohigher than the maximum allowableoperating pressure of the pipeline.4. The pipeline does not receive inputfrom the platform process.5. Input source is a well(s) having apressure greater than the maximum

allowable operating pressure of thepipeline and is equipped with two SDVs(one of which may be the SSV) controlledby independent PSHs connected toseparate relays and sensing points.Other input sources having a pressuregreater than the maximum allowableoperating pressure of the pipeline areprotected by PSV.

d. Check Valve (FSV).1. FSV installed.2. Departing pipeline is equipped with an

SDV controlled by a PSL.3. Each input source is protected by anFSV located so that no significant lengthof pipeline is unprotected from back.4. Pipeline is used for bi-directional flow.



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Additional items not required by 14C

Is there an SDV on the gas export line toprevent reverse flow and blowing downthe pipeline through the pig launcher?

Is the buy-back system designed forpipeline pressure?

Do the shutdown valve(s) on the gas andoil export lines initiate a shutdown of theboarding SDV, in time to prevent relievingof PSVs to the atmosphere and/or liquidcarryover to the vent/flare system?



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HEAT EXCHANGERS

Heat exchangers transfer thermal energy from one flow stream to another while maintaining isolation of the two flow streams. Recommended safety devices fora typical shell-tube heat exchanger are shown in Figure A.10.1. This section does not apply to exchangers used with primary heat sources such as turbineexhaust exchangers that should be analyzed under A.6, Fired Components. This section may be used to analyze heating or cooling coils inserted into vessels,

but the vessels themselves should be analyzed under A.4 or A.5 as appropriate. This section may also be used to analyze heat exchangers using air to cool orheat hydrocarbons, in which case only the hydrocarbon section need be considered.


A.10 Heat Exchangers

a. High Pressure Sensor (PSH).1. PSH installed.2. Input source to heat exchanger sectioncannot develop pressure greater than themaximum allowable working pressure ofthe heat exchanger section.

3. Each input source is protected by aPSH that also protects the heatexchanger section.4. A PSH is installed on a downstreamcomponent and cannot be isolated fromthe heat exchanger section by block orregulating valves.

b. Low Pressure Sensor (PSL).1. PSL installed.

2. Minimum operating pressure isatmospheric pressure when in service.3. PSL installed on another componentwill provide necessary protection and thePSL cannot be isolated form the heatexchanger section when the heatexchanger is in service.



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c. Pressure Safety Valve (PSV).1. PSV installed.2. Each input source is protected by aPSV set no higher than the maximumallowable working pressure of the heatexchanger section and a PSV is installedon the heat exchanger section for fireexposure and thermal relief.3. Each input source is protected by aPSV that is set no higher than themaximum allowable working pressure ofthe heat exchanger section and that

cannot be isolated from the heatexchanger section.4. PSVs on downstream equipment cansatisfy relief requirement of the heatexchanger section and cannot be isolatedfrom the heat exchanger section.5. (Deleted in Fourth Edition).6. Input sources to the heat exchangersection cannot develop pressure greaterthan the maximum allowable workingpressure of the heat exchanger sectionand the heat exchanger section cannot be

overpressured due to temperature orpressure in the other section.7. Each input source is protected by aPSV set no higher than the maximumallowable working pressure on the heatexchanger section and the heatexchanger section cannot beoverpressured due to temperature orpressure in the other section.



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A.11MiscellaneousItemsnot specifically

addressedin 14C

Is the instrument air/gas system sized toensure that a production shutdown iscontrollable when the low-pressure signalon the instrument air header activates?

For those locations with multiple platformstied together, has a comprehensivefunctional loop test of all instrument andend devices been conducted?

Is there a load shedding procedure forplatforms, which have the potential forsharing electrical power?

Have relief devices that vent to theatmosphere instead of a vent/flare boombeen modeled to determine if a gas cloudcould form on the platform if theyactivate?

If there are divert valves in the reliefsystem to direct flow to different vent/flarebooms, is there a management system to

assure all valves to at least one ventboom are locked open?

If there is only one vent/flare boom, isthere a procedure to assure all valves tothe vent/flare boom are locked open?

Has it been verified that the vent systemis unlikely to have a fire flash back due tooxygen?

Vent tip design prevents air ingress.

The vent lines are purged continuously.



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Do the startup procedures includeprecautions to prevent liquid carryoverfrom the heater treater to the fuel gassystem?

All equipment subject to leaks or overflowshould be protected by curbs, gutters ordrip pans that drain to a sump.

All gravity drain piping networks should bedesigned to prevent escape of gas fromsumps through the drains. This istypically accomplished by water seals

located at each drain. Check valves shallnot be considered appropriate.

Pressure drains should not be combinedwith gravity drains prior to sump entry.



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EMERGENCY SHUTDOWN SYSTEMS (ESD)

An Emergency Shutdown (ESD) system is a system of manual control stations strategically located on a platform that, when activated, will initiate shutdown ofall wells and other process stations. This system may include a number of independent process shutdown systems that can also be actuated separately.

Activation of the ESD system should result in the termination of all production activity on the platform, including the closing of all pipeline SDVs. The ESDSystem should be designed to permit continued operation of electric generating stations and fire fighting systems when needed in an emergency.

The ESD System provides a means for personnel to manually initiate platform shutdown when an abnormal condition is observed. Fusible elements of the fireloop may be integrated with the ESD control loop.

C.1.1EmergencyShutdownSystems

Emergency shutdown activation stationsshould be located at:

Helideck.

Exit stairways land at each deck level.

Boat landings.

At the center or each end of a bridgeconnecting two platforms.

Emergency evacuation stations.

Near the drillers console during drillingand workover operations.

Near the main exists of living quarters.

The time it takes for any safety device toeffect component or platform shutdownshould not exceed 45 seconds.

The ESD station should be protectedagainst accidental activation. This isusually accomplished by some sort ofcover.



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The ESD switch should be identified byshutdown function. It could onlyshutdown a piece of equipment, initiate aproduction shutdown or initiate and fullplatform shutdown.

The ESD switch or valve should be quickactivating.

The ESD switch or valve should becorrosion resistant.

ESD stations at boat landings may utilizea loop of synthetic tubing in lieu of a

switch or valve.

ABS Requirements (3-3/7.3.4)




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FIRE DETECTION SYSTEMS

A method of automatically detecting fires on an offshore platform should be provided to allow for early response. Pneumatic fusible element (TSE) systems orvarious electrical fire detection devices, including flame (USH), thermal (TSH), or smoke (YSH) detection devices, should be installed in all areas classified(Division 1 or 2) by API Recommended Practice 500 and in all buildings where personnel regularly or occasionally sleep.

C.1.2.2Fire DetectionSystems Pneumatic

FusibleElementSystems

This system should be placed over or

near equipment such as pumps,compressors, electrical switchgear,flammable storage, chemical storage,separators, and oil storage vessels/tanks.

System should shutdown productionactivities except those required to controlthe fire.

C.1.2.3 Electrical Fire DetectionSystems

Various electrical fire detection devicescan be used, such as rate of rise

temperature indicators, smoke detectors,fire eyes.




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Common locations of these devicesincludes:

Quarters

Buildings

Switchgear

For enclosed platforms, you could expectto see some type of electrical firedetection in every room.

System should activate alarms, initiateshut-in actions or activate fire suppression

systems.ABS Requirements (3-3/7.3.2 & 3-8/7.1)

COMUSTIBLE GAS DETECTION SYSTEMS

The accumulation of combustible gases in the atmosphere on offshore platforms could create a threat to safety. Accumulations are more likely to occur inenclosed areas. Two methods for increasing safety are providing adequate ventilation and installing combustible gas detector systems. The gas detector (ASH)system should alert personnel by audible and/or visual alarm to the presence of low level concentrations of flammable gas or vapor. Also, it should either shut offthe gas source or remove all sources of ignition if the concentration approaches the lower explosive limit (LEL) of the gas present.

C.1.3CombustibleGasDetectionSystemCombustible gas detectors should belocated in:

A. All enclosed areas that are Division 1or 2

B. B. All enclosed areas that containnatural gas fueled prime movers.

C. Buildings where personnel regularlyor occasionally sleep and that containa flammable gas source




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Shutdown devices controlled by gasdetector systems should be normallyenergized (fail-safe).

In enclosed areas containing flammablegas compressors, the minimum number ofsensors is one per compressor unit. Plusan additional sensor per three units orfractional part thereof.

This requires a minimum of two sensorsin all enclosed compressor buildings.

Providing adequate ventilation is an

acceptable alternative to installing gasdetection systems except in buildingswhere personnel regularly or occasionallysleep or in enclosed areas that containcompressors handling flammable gas

Gas detection maybe omitted in enclosedareas on platforms not provided withcontinuous AC power if the enclosed areacontains NO ignition source, NOcompressor handling flammable gas andis not a building where personnelregularly or occasionally sleep.

ABS Requirements (3-3/7.3.3 & 3-8/7.3)



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SUMPS

A sump may be a tank, a closed-end pipe, or an open-end pile. All sumps should be equipped with an automatic discharge to handle maximum inflow. Vents areinstalled on atmospheric sumps for the purpose of safely dissipating hydrocarbon vapors. Depending upon design and location, a sump pile vent may fulfill thispurpose without a flame arrestor being installed. Due to possible plugging from corrosion, the low flow/low pressure (no static electricity), and distance frompotential ignition/flash back sources, a flame arrestor could be eliminated in a sump pile located close to the water level.

Properly designed open-end sump piles are occasionally used to collect deck drainage or drips and to dispose of treated produced water. Except duringemergency upset condition, vessels (e.g. flare scrubbers, condensate accumulators, and various fuel filter scrubbers) should not discharge liquid hydrocarbonsdirectly into an open-end sump pile. Open-end sump piles should be protected against hydrocarbon discharge (overflow and/or underflow). The type ofprotection should be determined on a case-by-case basis. Some factors that should be considered include pile length, liquid properties, maximum inflow rate,wave action, and tidal fluctuation.

C.1.6SumpsandSumpPiles

Vents are installed on atmospheric sumpsfor the purpose of safety dissipatinghydrocarbon vapors. A flame arrestormay NOT be necessary.

Except during emergency upsetconditions, vessels should not dischargeliquid hydrocarbons directly into an open-end sump pile.

Open end sump piles should be protectedagainst hydrocarbon discharge. Items toconsider in open end sump piles includepile length, liquid properties, maximuminflow rate, wave action and tidalfluctuation.


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PNEUMATIC SUPPLY SYSTEMS

The pneumatic supply system provides the control medium for the surface safety system. The platform safety and shutdown systems generally require a powersupply at a pressure adequate to operate valve actuators and an instrument supply at a lower pressure.Hydrocarbon gas (fuel gas, blanket gas) has been used as a pneumatic supply. This poses unique problems, the gas is vented at all its instrument termination

points and may leak at any of its fittings. Hydrocarbon gas is also flammable. If the platform is using hydrocarbon gas as a pneumatic supply a risk assessment

should be conducted prior to its approval.

C.2 PneumaticSupplySystems

The time it takes for any safety device toeffect component or platform shutdownshould not exceed 45 seconds.


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SYSTEMS FOR DISCHARGING GAS TO ATMOSPHERE (VENTS AND FLARES)

Systems for discharging gas to the atmosphere provide a means for conducting discharged gas from process components under normal conditions (flare, vent)and abnormal conditions (relief) to safe locations for final release to the atmosphere. These should be locations where the gas will be diluted with air to belowthe LEL so it will not be a threat to the facility or where it can safely be burned.

These systems originate at the normal gas exit or pressure relief device of a process component and terminate at the designated safe locations. They can varyfrom an exit nipple on an individual PSV or control valve to a piping network connected to the outlet of several valves. If gas is discharged from a pressurevessel during normal operation (flare, vent), a scrubbing vessel should be provided to remove liquid hydrocarbons.

C.2.2FlaresandVents

Gas vented from a flare or vent at a safelocation should be diluted with air tobelow the lower flammable limit so it willnot be a threat to the facility or where itcan safely be burned.

If gas is discharge from a pressure vessel

during normal operation, a scrubbingvessel should be provided to removeliquid hydrocarbons.

The following should be considered inselecting a safe discharge point for a ventor flare:

a. personnel safety

b. the discharge volume

c. the location in relation to otherequipment, particularly fired vessel orignition sources, crew quarters,

control rooms, fresh air intakes,helicopter and boat approaches.

d. Prevailing wind direction and in caseof underwater discharges, theprevailing current.

Atmospheric gas discharge systemshould be designed in accordance with

API RP 520 and 521.

Check List API Rp 14c

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Transcript of Check List API Rp 14c