OIL D-1.pptx E&P industry

7/27/2019 OIL D-1.pptx E&P industry

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PRODUCED WELL FLUID IS A MIXTURE OF

OIL,GAS,WATER,SOLIDS etc.

BUYERS HAVE CERTAIN REQUIREMENTS WHICH ARE

TERMED AS SPECIFICATIONS FIELD PROCESSING ACHIEVES THIS BY PROCESSING

THE WELL FLUID


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WELLS

WELL FLOW LINES

RECEIVING MANIFOLD

SEPARATION FACILITY

STORAGE

TRANSPORTATION


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WELLS ARE CONNECTED TO A RECEIVING

MANIFOLD BY FLOW LINES

RECEIVING MANIFOLD HAS PROVISION TO DIVERT

WELLS TO NECESSARY PROCESSING SYSTEM RECEIVING MANIFOLD CAN BE DESIGNED TO

SPECIFIC REQUIREMENT DEPENDING UPON TYPE

OF WELL FLUID


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PROCESSING FACILITY COMPRISES OF:

separation facility to separate oil, gas and water

treatment of produced water, solids(if any) for their

disposal

auxiliaries like power generation, compressors,

pumps, instrumentation, safety systems, fire

fighting system


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emergency systems means of evacuation etc.

requirement will differ for onshore and offshore

operation but basic processing system is same

capital intensive

can be custom made


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SEPARATION SYSTEM OIL

separators

a. two phase

b. three phase

c. horizontal

d. vertical

e. spherical


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separation can be single stage or multistage

depending upon crude type and pressure

separator is a pressure vessel which is designed to

separate oil water and gas by gravity separation

separator sizing is done based on crude quality

separator type is decided by crude properties


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separators are fitted with different internals tofacilitate separation

provided with different instruments for pressure

and level controldown stream may have a meter for measurement of

quantity and taken to storage tank or separated oil

may be taken for further treatment


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VESSEL INTERNALS

Inlet Diverters: Two main types: baffle plates and

centrifugal diverters, baffle plate can be a spherical

dish, flat plate, angle iron, cone, or anything that willaccomplish a rapid change in direction and velocity of

the fluids and disengage the gas and liquid, design of

the baffles is governed by the structural supports

required to resist the impact-momentum load,advantage of using a half sphere or cone is , they create

less disturbance than plates or angle iron, cutting down

on re-entrainment or emulsifying problems.


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Centrifugal inlet diverters use centrifugal force,rather than mechanical agitation, to disengage the

oil and gas, have a cyclonic chimney or may use a

tangential fluid race around the walls, these inletdiverters are proprietary but generally use an inlet

nozzle sufficient to create a fluid velocity of about

20 fps centrifugal diverters work well in initial gas

separation and help to prevent foaming in crudes


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Wave Breakers In long horizontal vessels it isnecessary to install wave breakers, which are

nothing more than vertical baffles spanning the

gas-liquid interface and perpendicular to the flow.Defoaming Plates Foam at the interface may occur

when gas bubbles are liberated from the liquid.

This foam can be stabilized with the addition of

chemicals at the inlet. Many times a more effectivesolution is to force the foam to pass through a

series of inclined parallel plates or tubes


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Mist Extractor Liquid carryover occurs when freeliquid escapes with the gas phase, mist extractors

are made of wire mesh, vanes, centrifugal force

devices, or packing. wire mesh pads are made offinely woven mats of stainless steel wire wrapped

into a tightly packed cylinder, liquid droplets

impinge on the matted wires and coalesce,


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effectiveness of wire mesh depends largely on the

gas being in the proper velocity range, if the

velocities are too high, the liquids knocked out will

be re-entrained , if the velocities are low, the vaporjust drifts through the mesh element without the

droplets impinging and coalescing


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DRAG FORCE

IF FLOW IS LAMINAR THEN


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FOR TERBULENT FLOW


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GAS CAPACITY

HORIZONTAL SEPARATOTOR -SIZING


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LIQUID CAPACITY

SLENDERNESS RATIO

SEAM TO SEAM LENGTH

VERTICAL SEPARATOTOR SIZING


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VERTICAL SEPARATOTOR -SIZING

GAS CAPACITY

GAS CAPACITY


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SLENDERNESS RATIO

SEAM TO SEAM LENGTH


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SINGLE PHASE FLOW

LIQUID

GAS

MULTIPHASE FLOW

WELL FLOW LINES

PROCESS LINES


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MULTIPHASE FLOW

BUBBLE

PLUG

STRATIFIED

WAVY

SLUG

SPRAY


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Pressure Drop for Liquid Flow.General Equation.

d5 = (11.5 10-6) fLQl2 (SG)

P

where d= pipe inside diameter, in.,

f= Moody friction factor, dimensionless,

L = length of pipe, ft, Ql= liquid flow rate, B/D,

SG = specific gravity of liquid relative to water,P = pressure drop, psi (total pressure drop).


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Weymouth Equation: used for high-Reynolds-number flows

Qg = 1.1d2.67 [P21 P2

1 ]1/2

[LSZT1 ]1/2

where :Qg = gas-flow rate, MMscf/D, d = pipe insidediameter, in.,P1 = upstream pressure, psia, P2 =downstream pressure, psia,L = length, ft,

T1 = temperature of gas at inlet, R S = specificgravity of gas, And Z = compressibility factor for gas,dimensionless.


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Panhandle Equation.: used for moderate-Reynolds-number.

Qg = 0.028E [ P21 P2

2 2 ]0.51 d2.53

[ S0.961ZTLm

] 0.51

Where:E-efficiency factor (new pipe: 1.0; goodoperating conditions: 0.95; average operatingconditions: 0.85),Qg-gas-flow rate, MMscf/D, d-

pipe ID, in., P1-pressure, psia, P2-downstreampressure, psia, Lm-length, miles, T- temperature ofgas at inlet,R, S-specific gravity of gas, Z-compressibility factor for gas, dimensionless


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Spitzglass Equation. For vent lines

Qg = 0.09[ hwd5]1/2

[ SL(1 + 3.6/d + 0.03d)]1/2

Where:Qg-gas-flow rate,MMscf/D,

hW- pressure loss,inches of water, d-pipe ID, in.

Assumptions: f-(1+ 3.6/d + 0.03d) (1/100),

T-520R, P1-15 psia, Z = 1.0,P- 10% of P1


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Simplified Gas Formula: recommended for most general-use flow applications.

Weymouth Eqn.: for smaller-dia.pipe (generally, 12 in. and

less), also recommended for shorter lengths of segments

(

1,000 psig) applications,and high Reynolds number.

Panhandle Eqn.:for larger-dia.pipe (12-in.+diameter),also

recommended for long runs of pipe (> 20 miles)like crosscountry transmission pipelines and for moderate Reynolds

numbers.

Spitzglass Eqn:for low-pressure vent lines< 12 in.in

dia.(P


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Simplified Friction Pressure-Drop providesanapproximate solution for friction pressure drop in two-phase-flow problems that meet the assumptionsstated.

P =3.4 10-6 f LW 2M

d5

Where P = friction pressure drop, psi,

f = Moody friction factor, dimensionless,

L = length, ft, W = rate of flow of mixture, lbm/hr,

M -density of the mixture, lbm/ft3, and d = pipe ID, in.

API RP14E


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The formula for rate of mixture flow is

W = 3,180QgS + 14.6QL(SG)

where

Qg = gas-flow rate, MMscf/D,

QL = liquid flow rate, B/D,

S = specific gravity of gas at standard conditions,

lbm/ft3

(air = 1),And SG = specific gravity of liquid, relative to water,

lbm/ft3.


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The pressure drop at low flow rates associated with anuphill elevation change may be approximated with

Equation

PZ

0.433(SG)Z ,

Where PZ = pressure drop because of elevation

increase in the segment, psi,

SG = specific gravity of the liquid in the segment, relative

to water, and Z = increase in elevation for segment, ft.The total pressure drop can then be approximated by

the sum of the pressure drops for each uphill segment.


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Once a design velocity is chosen, to determine the pipesize,

d = [ (11.9 + ZT R/ 16.7P )QL]1/2

[1,000V] 1/2Where d = pipe ID, in.,

Z = compressibility factor, dimensionless,

R = gas/liquid ratio, ft3/bbl,

P = flowing pressure, psia,

T = gas/liquid flowing temperature, R,

V = maximum allowable velocity, ft/sec,

And QL = liquid-flow rate, B/D.


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FOR EROSIVE SERVICE FITTINGS


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Multiphase-Line Sizing: minimum fluid velocity inmultiphase systems must berelatively high to keep theliquids moving and prevent or minimize slugging,recommended minimum velocity is 10 to 15 ft/sec,maximum recommended velocity is 60 ft/sec to inhibit

noise and 50 ft/sec for CO2 corrosion inhibition. In two-phase flow, it is possible that liquid droplets in the flowstream will impact on the wall of the pipe causingerosion of the products of corrosion. This is callederosion/corrosion. Erosion of the pipe wall itself could

occur if solid particles, particularly sand, are entrainedin the flow stream, guidelines from API RP14Eshould beused to protect against erosion/corrosion.


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Wall-Thickness Calculations: B31.3 Code. ANSI/ASMEStandard B31.3 is avery stringent code with a high safetymargin. The B31.3 wall-thickness calculation formula is

t = te + tth + [ Pdo ] [ 100 ]

*2(SE PY) + *100 Tol]

where t-minimum design wall thickness, in.,te-corrosionallowance, in.,tth-thread or groove depth, in. P-allowableinternal pressure in pipe, psi, do-outside diameter of pipe,in., S-allowable stress for pipe, psi E = longitudinal weld-jointfactor [1.0 seamless, 0.95 electric fusion weld, double butt,

straight or spiral seam APL 5L, 0.85 electric resistance weld(ERW), 0.60 furnace butt weld],Y-derating factor (0.4 forferrous materials operating below 900F), andTol-manufacturers allowable tolerance, % (12.5 pipe up to 20in.-OD, 10 pipe > 20 in. OD, API 5L).


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B31.4 Code. is used often as the standard of design forcrude-oil piping systems in facilities, such as pump stations,pigging facilities, measurement and regulation stations, andtank farms. The wall-thickness formula for Standard B31.4 is

t = Pdo

2(F ESY ),

Where t = minimum design wall thickness, in., P = internalpressure in pipe, psi, do = OD of pipe, in.,SY = minimum yieldstress for pipe, psi, F = derating factor, 0.72 for all locations,

and E = longitudinal weld-joint factor [1.0 seamless, ERW,double submerged arc weld and flash weld; 0.80 electricfusion (arc) weld and electric fusion weld, 0.60 furnace buttweld].


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B31.8 Code. is often used as the standard of design fornatural-gas piping systems in facilities, such ascompressor stations, gas-treatment facilities,measurement and regulation stations, and tank farms.The B31.8 wall-thickness formula is

t = Pdo2F ETSY

Where t-minimum design wall thickness, in., P-internalpressure in pipe, psi, dO - OD of pipe, in.,

SY - minimum yield stress for pipe, psi F-design factorE- longitudinal weld-joint factor and T-temperaturederating factor


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DIFFERENT TYPE OF PIGS(for cleaning)

foam

rubber cups

brush pigs etc.

PIGGING OPERATION REQUIRES PIG LAUNCHERS

AND RECEIVERS.

SLUG CATHCERS ARE REQUIRED AT THE RECEIVINGEND OF THE PIG.

INTELLEGENT PIGS (for health monitoring)


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ROUTE:

a)selection

b) route survey

c) right of way or use

SPECIAL REQUIREMENTS:

a) area

b) highway , road , street crossingc) railway crossing


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d) bridge crossing

e) river, water streams

f) wet lands and marshes etc

ENVIRONMENTAL CONCERNS

SAFTY CONCERNS


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PIPE LINE CONSTRUCTION:

PIPE LINE STORAGE AND TRANSPORTATION

SITE PREPRATION

LINE STRINGING

TRENCHING

WELDING(API 1104,ASME SECTION IX Boiler andpressure vessel code)


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WELD TESTING

JOINT AND PIPE LINE COATING

PIPE LINE LOWERING

BACKFILLING

VARIOUS CROSSINGS

FINAL TIE INS

TESTING


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WELDED PIPES ARE LOWERED FROM THE REAR OFTHE BARGE.

IN SHALLOW WATERS PIPE IS S LAYED AND IN

DEEPER WATERS IT IS J LAYED. IN S LAY PIPE IS WELDED IN HORIZONTAL POSITION

AND LEAVES THE BARGS HORIZONTALLY.

IN J LAY PIPE IS WELDED VERICALLY HELD AND PIPE

LEAVES THE BARGE VERTICALLY


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2PE607:Oil&GasPipelineDesign,Maintenance&Repair

PIGGINGOPERATIONS


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UTILITYPIGS

FoampigsMandrelpigs


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UTILITYPIGS

Solidcastpigs Sphericalpigsorspheres

IN LINE INSPECTION TOOLS


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INLINEINSPECTIONTOOLS


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ULTRASONICINSPECTIONTOOLS


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LIQUID PROCESSING


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an emulsion is a heterogeneous liquid that consistsof two immiscible liquids, one of which is intimately

dispersed as droplets in the other, for an emulsion

to exist, oil and water are the two mutually

immiscible liquids, emulsifying agent in the form of

small solid particles, paraffins, asphaltenes, etc., is

present in the formation fluids, agitation occurs as

fluid flows into the well bore, up the tubing, andthrough the surface choke.


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TYPES:

WATER IN OIL

OIL IN WATER

WATER IN OIL IN WATER


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Prevention of Emulsions: Excluding all water fromthe oil while the oil is produced and/or preventingall agitation of well fluids would prevent emulsionfrom forming; however, because these both are

impossible, or nearly so, emulsion production mustbe expected from wells, poor operating practicesincrease emulsification , operating practices thatinvolve the production of excess water because of

poor cementing or reservoir management canincrease emulsion-treating problems, as can aprocess design that subjects the oil/water mixtureto excess turbulence


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Emulsifying Agents: surface-active compounds thatattach to the water-droplet surface and lower theoil/water interfacial tension, some emulsifiers areasphaltic , barely soluble in oil and strongly

attracted to water, they come out of solution andattach themselves to the droplets of water as thesedroplets are dispersed in the oil, asphalticemulsifiers form thick films around the water

droplets and prevent droplet surfaces fromcontacting when they collide, thus preventingcoalescence.


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Oil-wet solids (sand, silt, shale particles, paraffin,iron hydroxides, zinc compounds, aluminum sulfate,

calcium carbonate, iron sulfide ,etc. collect at the

oil/water interface) can act as emulsifiers, these

substances usually originate in the oil formation,

but can form because of an ineffective corrosion-

inhibition program,


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most crude-oil emulsions are dynamic and transitory,interfacial energy per unit of area is fairly high in

petroleum emulsions compared to that in

emulsions commonly encountered in other

industries, so they are thermodynamically unstable

in that the total free energy will decrease if the

dispersed water coalesces and separates


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Stability of Emulsions. Generally, crude oils with lowAPI gravity form more stable and higher-percentage-volume emulsions than do oils of highAPI gravity, asphaltic-based oils tend to emulsify

more readily than do paraffin-based oils, emulsionsof high-viscosity crude oil usually are very stableand difficult to treat because the viscosity of the oilhinders movement of the dispersed water droplets

and thus retards their coalescence, high-viscosity/high-density oils usually contain moreemulsifiers than do lighter oils.


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Effect of Emulsions on Fluid Viscosity.: Emulsionsalways are more viscous than the clean oil in the

emulsion, in oilfield emulsions, the ratio of the

viscosity of an emulsion to that of the clean crude

oil depends on the shear rate to which the

emulsion has been subjected, for many emulsions

and for the shear rates normally encountered in

piping systems,


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this ratio can be approximated using equation , if noother data are available.

e

/ o

= 1 + 2.5 f + 14.1 f2

where e = viscosity of emulsion, cp; o = viscosityof clean oil, cp; and f = fraction of thedispersed

phase.


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Sampling and Analyzing : treating unit or systemperformance can be monitored by regularlywithdrawing and analyzing samples of the contents atmultiple levels in the vessel or multiple points in thesystem, particularly beneficial when treating emulsionsthat involve viscous oils, samples should berepresentative of the liquid from which they are taken,so emulsification should not be allowed to occur whenthe sample is extracted ,samples from a pressure zone

can be taken without further emulsification of theliquids if the velocity of the discharging liquid iscontrolled


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Bottle Tests Most Common Method

Measure Sedimentation Rate

Estimate Resultant Oil Quality

Vary Chemical Type and Dosage


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Electrostatic Bench Tests

Measure Response of Emulsion to

Electrostatic Field: Power Requirements

& Sedimentation Rate

Measure Resultant Oil Quality

Vary Chemical Type & Dosage and

Electrostatic Field Type


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cc Oil

cc Emulsion

cc Water

Chemical

Dossage

Mixing

Heating to

process

temperature

24 hours

settling

evaluation

t = 0t = t

1

BOTTLE TEST

100 cc

Emulsion


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Chemical Bottle Test Electrostatic Bench

Test

Water in Oil

% By Difference

BS&W

Measured %

A 2.2 2.12

B 4.6 2.01

C 5.3 1.62

D 5.7 1.20

E 6 2.35

Red: Best Performance


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EMULSION STABILITY

HOW TO DESTABLIZE

METHODS TO DESTABLIZE:

1. HEATING2. CHEMICAL ADDITION

3. SETTLING OF SEPARATED WATER

a) NATURAL SETTLINGb) FORCED SETTLING


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WHY HEATING: Using heat to treat crude-oilemulsions has four basic benefits:

Heat reduces the viscosity of the oil, which allows

the water droplets to collide with greater force and

to settle more rapidly The chart can be used to

estimate crude-oil viscosity/temperature

relationships.


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Crude-oil viscosities vary widely, and the curves onthis chart should be used only in the absence of

specific data. Heat increases the droplets

molecular movement, which helps coalescence by

causing the dispersed-phase droplets to collide

more frequently


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Heat might deactivate the emulsifier (e.g., dissolveparaffin crystals), or might enhance the action of

treating chemicals, causing the chemical to work

faster and more thoroughly to break the film

around the droplets of the dispersed phase of the

emulsion. Heat also might increase the density

difference between the oil and the water, thus

accelerating settling. In general, at temperatures

below 180F, adding heat will increase the density

difference.


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Heating well fluids is expensive. Adding heat cancause a significant loss of the lower-boiling point

hydrocarbons (light ends). This causes shrinkage

of the oil, or loss of volume. Because the light ends

are boiled off, the remaining liquid has a lower API

gravity and thus might have less value. The vapor

leaving the oil phase can be vented to a vapor

recovery system or compressed and sold with thegas. Either way, there probably will be a net income

loss


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Fuel is required to provide heat, and so the cost offuel must be considered. If the oil is above inlet-

fluid temperature when it is discharged from the

treating unit, it can be flowed through a heat

exchanger with the incoming well fluid to transfer

the heat to the cooler incoming well fluid. In some

geographic areas, emulsion-heating requirements

vary in accordance with daily and/ or seasonal

atmospheric temperatures e.g., at night, during a

rain, or in winter months


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BENEFITS OF HEATING


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the fuel required for treating depends on thetemperature rise, the amount of water in the oil,

and the flow rate, heating a given volume of water

requires approximately twice the energy needed to

heat the same volume of oil, beneficial to separate

free water from the emulsion to be treated,


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the heat input for an insulated vessel (heat loss isassumed to be 10% of heat input) can be

approximated

Q = 16T(0.5qo

o

+ qw

w

)

where Q = heat input, Btu/hr, T = temperature

increase, F, qo = oil flow rate, B/D, qw = water flow

rate, B/D, o = specific gravity of oil, and w =

specific gravity of water.


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DISADVANTAGES:EXPENSIVE

GAS EVOLUTION

LOSS OF LIGHTER FRACTIONREDUCES API GRAVITY

SOME TIME DECREASES GRAVITY DIFFERENCE IN

PHASES


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TYPES:Water soluble

Oil soluble

ACTION INJECTION

Injection point

Dilution CHEMICAL SELECTION


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NATURAL AIDED


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NATURAL SETTLING: COALSCING SYSTEM

Plates

Packing AGITATION

SETTLING TIME

AIDED SETTLINGElectrostatic coalescence


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Gravity Settling. Gravity settling is the oldest,simplest, and most widely used method for treatingcrude-oil emulsions, density difference betweenthe oil and the water causes the water to settle

through and out of the oil by gravity, gravitationalseparation of water from oil is controlled by thewell known Stokes law

V =2gr2(D2- D1 ) /9 V-droplet falling velocity

g-gravitation constant r-particle radiusD2-specificgravityof water D1-specific gravity of oil

-viscosity of oil


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parameters which control the falling velocity ofwater particle are the droplet size, densitydifference and viscosity of oil. Application of heatwill reduce the oil gravity as well as viscosity

Rewriting Stokes equation in more easily usableform

V= Cr2(D2 D1)/ value of C is 2.5665 x 10-2 when

r-particle size in microns

D2-specificgravityof water at conditions

D1-specificgravityof oil at condition -viscosity of oilat conditions in centipoises.


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Emulsion subjected to high voltage electrical fieldhigh voltage, water droplets polarize and align with

electric force, the positive and negative poles of the

droplets are brought adjacent to each other,

electrical attraction brings the droplets togetherand causes them to coalesce.


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droplets dispersed in oil that are subjected toalternating-current (AC) field become elongated

along the lines of force, as voltage rises during the

first half-cycle,droplets are relaxed during the low-

voltage part of the cycle, the surface tension pullsthem back toward a spherical shape, effect repeats

with each cycle, weakening the film so that it

breaks more easily


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force existing between droplets is mathematicallygiven by the following equation:

F= K2d6/S4 (with Sd) F-attractive force betweendroplet K-Dielectric constant for the system -

voltage gradient d-diameter of droplets-distance between droplet

From this equation it is evident that in order toincrease the force between droplets to help them

coalesce, it is required to increase that the appliedvoltage gradient, increase the droplet diameterdecrease the distance between droplet


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. If the voltage gradient applied to a particulardroplet is increased beyond a certain critical voltage(E

c) peculiar to the droplet, the droplet will distort

sufficiently to rupture its film at a critical point

causing the droplet to break into smaller ,submicronic droplets The critical voltage gradientcan be expressed for a particular droplet as

Eck(T/d)1/2

where Ec- Critical voltage gradient Dielectricconstant for the system T-Surface tension

d-Diameter of droplet


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VERTICAL HORIZONTAL

WITH ONLY HEATING ARRANGEMENT

WITH ELECTROSTATIC COALESCENCE


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EMULSION ENTERS AT THE TOP IN GAS SEPARATIONCHAMBER

EMULSION FLOWS THROUGH THE DOWNCOMES

TO THE BOTTOM OF THE VESSEL

EMULSION MOVES UP THROUGH HEATING SECTION

WATER SEPARATION IN COALESCING SECTION


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INTERPHASE CONTROLLER CONTROLS WATER LEVEL IF PROVIDED WITH ELECTRSTATIC COALESCER OIL

MOVES ACROSS IT FOR FURTHER DEHYDRATION

INTERPHASE CONTROLLER MAINTAINS WATERLEVEL

WATER CAN BE DRIANED THROUGH WATER SIPHON


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BATTERY OF VERTICAL TREATERS


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BATTERY OF VERTICAL TREATERS


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MOST WIDELY USED CONSTRUCTION SIMILAR TO FREE WATER KNOCK

OUT VESSEL THOUGH NOT EXACTLY SAME

HORIZONTAL OR VERTICAL FLOW CONFIGURATTION OIL AND WATER INTERPHASE CONTROLLERS

MAINTAIN LEVELS


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HORIZONTAL FLOW CONFIGURATION:EMULSION ENTERS AT THE TOP OF THE VESSEL

FLOWS ALONG A LONGITUDINAL BAFFLE

ENTERS HEATING SECTION FROM THE BOTTOMHEATED OIL TRAVELS THROUGH A SLOT IN THE

PARTITION


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FREE WATER AT THE BOTTOM FLOWS OUTCLEAN OIL FLOWS TO THE TOP AND

COLLECTED

VERTICAL FLOW CONFIGURATION:OIL ENTERS THROUGH FORNT SECTION AND FLOWS

DOWN

FREE WATER IS SEPARATED


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OIL MOVES THROUGH THE WATER ALYER AND GOESTO THE TOP

CLEAN OIL IS COLLECTED FROM THE TOP

WATER DARINED OUT FROM THE BOTTOM


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ELECTROSTATIC TREATERS


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ELECTROSTATIC COALESCENCE DISCUSSED EARLIER COALESCING CHAMBER CONTAINS ELECTROSTATIC

GRID

ELECTROSTATIC GRID:

AC

COMBINATION


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AC FIELDS USED ARE IN THE RAGE OF 12 TO 23 Kv.

MOST EFFECTIVE FOR LARGER WATER DROPLETS

DIFFERENT COFIGURATIONS:

TWO GRID SYSTEM ALSO KNOWN AS SINGLE HOT

DOUBLE AND TRIPLE HOT DESIGN ALSO AVAILABLE


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EMUSION FLOWS THROUGH THE GRID ANDELECTRIC COALESCENCE TAKES PLACE

SEPARATED WATER FLOWS DOWN AND CLEAN OIL

GOES TO THE TOP

DOUBLE AND TRIPLE HOT SYSTEMS INCREASE THE

RETENTION TIME OF EMULSION ACROSS THE

ENERGISED ELECTRODES THEREBY INCREASING

EFFICIENCY


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DIPOLAR ATTRACTION

FILM STRETCHING

WATER TOLERANCELIMITATIONSMINIMAL DROP MOVEMENT

LOW CHARGE DENSITY

LIMITS ON USEFUL FIELD STRENGTH


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AC/DC TREATERS ELECTRODES ARE PARALLEL PLATES

PLATES ARE CONNECTED TO TWO OPPOSITELY

ORIENTED DIODES

BOTH DIODES ARE CONNECTED TO SAME END OF

TRANSFORMER SECONDARY WINDING

PLATES ARE CHRGED ON ALTERNATE HALF CYCLES

OF AC


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AC/DC TREATERS ELECTRODES ARE PARALLEL PLATES

PLATES ARE CONNECTED TO TWO OPPOSITELY

ORIENTED DIODES

BOTH DIODES ARE CONNECTED TO SAME END OF

TRANSFORMER SECONDARY WINDING

PLATES ARE CHRGED ON ALTERNATE HALF CYCLES

OF AC


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+ -

- + - +

+ -

UPWARD

OIL FLOW

DC FIELD BENEFITS

MOST AC FIELD BENEFITS PLUS


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MOST AC FIELD BENEFITS, PLUS . . .

DROPLET TRANSPORTNET ELECTROSTATIC CHARGE

BUT. . .

MUST AVOID ELECTROLYTIC REACTIONS

WATER TOLERANCE IS REDUCED


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ELECTRODE PLATES

RAILS

INSULATORHANGERS


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DUAL POLARITY:Dual polarity AC/DC Electrostatic unit provides this

needed electrical gradient. The use of AC in the low

gradient area between the water interface and the

charged electrode has proven to be essential in this

higher water content area of the process. The

droplets removed from the stream in this area are

very large and respond quite readily to this

changing field because their individual size and

number places them closer together.


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The application of dual polarity DC potential, bothpositive and negative to the high gradient area

between the electrodes successfully coalesces the

majority of even the one and two micron droplets

resulting in a much lower water content in theclean oil.


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Provides Combined AC/DC Fields

For Combined Benefits

Drop Polarization

Film Rupture

Water Tolerance

Drop Movement

Drop Charge Density

Minimizes Induced Corrosion

COMPARATIVE ANALYSIS


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AC Field

Proven technology in conventional

desalting process

Electrostatic dehydration/desalting

under AC electric field

Traditional desalting technology Lower comparative cost

High oversizing design

High sensitivity to emulsion tightness

(high stability) and high water content

High desalting multiple stagesrequirements

Good technical support

High control requirements

Dual Polarity

Proven technology in conventional

desalting process

Electrostatic dehydration/desalting

under Dual polarity (AC/DC) electric

field and electrodynamic desaltingprocess (exclusive technologies)

Improved desalting technologies

Higher comparative cost

Optimal design (low oversizing)

Low sensitivity to emulsion tightness(high stability) and high water content

Low desalting multiple stages

requirements

Excelent technical support

High control requirements


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To reduce salt content in crude oil Source of salt:

water produced along with oil

some times produced oil contains salt crystals Desalting Why

Salt may cause corrosion, foul equipment

Contract requirement


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Dilution waterfresh water

water recycle

Water mixed with crudemixing efficiency

problem of water solubility in oil at elevated

temperatures


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In produced brine with a high salt concentration, itmight not be possible to treat the oil to a low

enough water content ( < 0.2% is difficult to

guarantee), desalting system such as the one

shown schematically consists of a mixing device (inwhich fresh water is usedto wash the crude oil)

and any of the electrostatic treating systems

described(which then are used to dehydrate the oil

to a low water content)


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mixing dilution water with the produced waterlowers the effective value ofCswin eqn. if a single-

stage desalting systemrequires too much dilution

water or is unable to reach the desired salt

concentration, then a two stage system is used,such as the one shown schematically


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THE MIXING VALVE


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Differential Pressure Controller

Mixing Valve

Crude

Flow

Static Mixer (Optional) is

occasionally installedeither upstream or

downstream of the

mixing valve

To Desalter

DPC

SIZING EQUATIONS


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WATER DROPLET SIZEF ti f i it


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Function of viscosity

For conventional treaters

For Electrostatic traters


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Oil field processing generally consists of

NATURALGASPROCESSING


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Oil field processing generally consists of

two categories of operations: Separation of natural gas from free liquids

( crude oil, brine ) and entrained solids,(sand).

Removal of impurities from natural gasand any condensate form.

NATURAL GASPROCESSING

It is crucial link between natural gas production and its


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g ptransportation to market

Pipe line Quality Natural Gas Calorific Value 1035 (+ 50) Btu / cu feet

Specified dew point temperature level

H2S < 4 ppm, CO2 2-3%, H2O < 7 lb / MMSCF, N2,O2traces

Free of particulate solids & liquid water

Other key Byproducts of Natural Gas Processing Helium

Carbon- di-oxide

Hydrogen Sulphide

I i l


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It involves:-

Simple Separation + Dehydration (Separation of hydrocarbon condensate, liquid water and

solid particles) Gas Compression (Condensate Removal)

(Involves removal of condensate by compression) Natural Gas Liquids (NGL) Recovery (NGL is recovered by coding to ease transportation)

Gas Dehydration (Dehydration is the removal of water content to prevent

formation of gas hydrates and to increase the calorific value Gas Sweetening (It is to remove acid gas (CO2, H2S) component as H2S is toxic

and both are corrosive)

The individual unit operations commonlyused in field handling natural gas are:

Basic fields processing schemes:


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Basic fields processing schemes:

Prevention of hydrate formation Sweetening

Dehydration

Condensate recovery and hydrocarbon dewpoint control

Compression

Flow measurement

Heating and cooling Pipe line transport of natural gas


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Glycol and methanol are comparableMerits of methanol:

It can be used at any temperature

Recovery is marginally economically due to itslow cost and high vaporization losses.

Lower capital investments

Methanol can dissolve existing hydrates

DE-MERITS OF METHANOL

It is co-absorbed with water vapor by glycol


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It is co-absorbed with water vapor by glycol,

increasing glycol regeneration heat load. Aqueous methanol can corrode steel in glycol

steel and re boiler.

Methanol can also reduced the capacity of soliddesiccant pallets because methanol is readilyco-absorbed.

Merits of glycol (TEG/DEG)

It exhibits higher depression of hydrateformation temperature.


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formation temperature.

Cheaper where continuous injection isrequired.

Can be recovered easily.

Demerits of glycol

Its not chosen below 15 F because of its highviscosity and difficulty of separation fromliquid HC

Without intimate mixing glycol injection maynot prevent hydrate formation


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not prevent hydrate formation .

It can not attack or dissolve existing hydrates.


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Removal of Acid Gases

Permissible Acid Gas Concentration

H2

S concn < 4 ppm v (0.25 gr / 100scf)

Max total sulfur content including mercaptans(RSH), Carbon Sulfide (COS), disulphide (RSSR) etcis usually 10 to 20 gr / 100 scf (160-200 ppmv)

CO2

concn 2-3%

Batch Process


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Iron Sponge, Chem Sweet, Sulpha Check

Aqueous Amine Solutions Moethanolamine

Diethanolamine

Diglycolamine Methyl diethanolamine

(Solutions are regenerated, are used to remove large amount ofSulfur and CO2)

Mixed Solutions (Mix of Amine, Physical Solvent,Water Sulfinol, Ucarsol, Flexsorb & Optisol)

(These Solution absorb organic sulfur and are capable of high acidgas loading)

Physical Solvents Selaxol

Rectisol Purisol


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Purisol

Fluor Solvent These can be regenerated without heat and

simultaneously dry the gas (Used for bulk removal of CO2 frequently offshore)

Hot Potassium Carbonate Solutions Hot Pot Catacarb etc.

Direct Oxidation to Sulfur Stretford, Sulferox Locat

(These Process practically eliminate H2S emissions)

Adsorption

Linde, Zeochem & Davison Chemical Molecular Sieves


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For low acid gas concentration, gas is simultaneouslydried

Membranes

Example AVIR, Air Products, Cynara (Dow), Du Pont,

Grace, International Permeation and Monsanto aremost suitable for bulk CO2 separation, especially whenthe feed gas concentration is very high

In General,

If S < 20 lb/day Batch Process If S > 100 lb / day Amine Solution

Sulfur Content, lb / day = 1.34 (MMSCFD)(gr/H2S/100SCF)

contactor

over head

coalescer sep.

G/L

HUT

HP flareFuel gas

LP

flare

9

Gas from Compressor

Fuel gas

PIC


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Reboiler

M

MRecirculation pump Booster pump

Flash vesselscrubber

Storage tank

Ajay KumarNeelam

1

flow

meter

Rich glycol

Closed drain

Closed drain

LP flare

Stripping gas

GlycolDehydration

Unit

TCV


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189/367

RECTANGULAR HORIZONTAL

VERTICAL

SPHERICAL


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OPEN FIXED ROOF

FLOATING ROOF:

EXTERNAL FLOATING ROOF

INTERNAL FOATING ROOF

CLOSED FOATING ROOF


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RIVETED BOLTED

SHOP WELDED

FIELD WELDED


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LIQUID GAS


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ACCURACYLinearity

Repeatability

Resolution

Turndown

d ff f h l d


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Accuracy: difference from the actual measurement andthe meter reading, accuracy is stated in followingterms:

Repeatability :meters ability to reproduce samemeasurement for a set of constant conditions of flow

rate, temperature, viscosity, density, pressure.Repeatability of a custody transfer meter should bewithin +/-.025% in 3 runs or +/- 0.05% of each other in5 consecutive prove runs.

Linearity :ability to maintain a meter factor through-out

the stated turndown. Depending on meter size andapplication this is typically +/-0.15% or +/-0.25% forcustody transfer use.


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Resolution. is a measure of the smallest incrementof total flow that can be individually recognized bythe meter.

Turndown.Turndown is the meters flow range

capability. The flow range of the meter is the ratioof maximum flow to minimum flow over which the

specified accuracy or linearity is maintained. a

meter with a minimum flow rate of 100 bbl/hr and

a maximum flow of 1,000 bbl/hr is said to have a

10:1 turndown.


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FLOW RATE PRESSURE

TEMPERATURE

VISCOSITY

ACCURACY


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DIRECT - POSITIVE DISPLACEMENT INDIRECT - INFERS FLOW

P iti di l t fl t l k PD


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Positive displacement flowmeters, also know as PDmeters, measure volumes of fluid flowing through bycounting repeatedly the filling and discharging ofknown fixed volumes. A typical positive displacementflowmeter comprises a chamber that obstructs theflow. Inside the chamber, a rotating/reciprocating

mechanical unit is placed to create fixed-volumediscrete parcels from the passing fluid. Hence, thevolume of the fluid that passes the chamber can beobtained by counting the number of passing parcels orequivalently the number rounds of the

rotating/reciprocating mechanical device. The volumeflow rate can be calculated from the revolution rate ofthe mechanical device.


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TURBINE METERS CORIOLIS METERS

PRINCIPLE :

INFERS FLOW BY MEASURING SOME DYNAMIC

PROPERTY OF THE FLOW STREAM


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Measures density and mass flow rate


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Measures density and mass flow rate

Principle: As fluid moves through a vibratingtube(s),Coriolis force causes distortion which is directlyproportional to mass flow rate.

Density is related to frequency, though not linearly, bythe following equation

= C0 + C1T2

Where,

= Density of fluid

C0 & C1 = Constants

T = Tube time period


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ORIFICE METER TURBINE METER

CORIOLIS METER

ULTRASONIC METER


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Principle:differential pressure proportional to squire of flow

rate

Standards:

AGA 3

ISO 5167


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BASIC EQUATION:qh =C

(hw pf)1/2

where: qh -quantity rate of flow at base conditions,

cfh C-orifice flow constant,

hw differential pressure in inches of water at 600F, pf

absolute static pressure, psia


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C =(Fb)(Fr)(Y)(Fpb)(Ftb)(Ftf)(Fg)(Fpv)(Fm)(Fl)(F)Where: (Fb) basic orifice factor, cfh(Fr) Reynolds

number factor (Y) expansion factor (Fpb) pressure

base factor (Ftb) temperature base factor (Ftf)

flowing temperature factor (Fg) specific gravityfactor(Fpv) supercompressibility factor(Fm)

manometer factor for mercury meter(Fl)gauge

location factor,(F) orifice thermal expansion factor


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Principle:Difference in transit time of high frequency sound

waves travelling between a pair of fixed sound

transducers with the flow and against the flow

determines the flow


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Sucker Rod Pump Assembly

Tubing Anchor/CatcherSucker Rod

Reservoir


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High System Efficiency,


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High System Efficiency,

Optimization Controls Available,

Economical to Repair and Service,

Positive Displacement/Strong drawdown,

Upgraded Materials Reduce CorrosionConcerns,

Flexibility -Adjust Production Through StrokeLength and Speed,

High Salvage Value for Surface & DownholeEquipment


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Potential for Tubing and Rod Wear

Gas-Oil Ratios

Most Systems Limited to Ability of Rods to

Handle Loads ( Volume Decreases As DepthIncreases


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Wellhead Surface Drives

Continuous & Threaded Sucker Rods

Subsurface PC Pumps & Accessories


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RotorStator

SuckerRod

Tubing

Vertical Electric WellheadDrive


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Low Capital Cost

Low Surface Profile for Visual & Height

Sensitive Areas

High System Efficiency

Simple Installation,

Quiet operationPumps Oils and Waters with Solids

Low Power Consumption

Portable Surface Equipment

Low Maintenance Costs

Use In Horizontal/Directional Wells


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Limited Depth capability

Temperature Sensitivity to Produced Fluids

Low Volumetric Efficiencies in High-GasEnvironments

Potential for Tubing and Rod Coupling Wear

Requires Constant Fluid Level above Pump


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Production Packer

Side Pocket Mandrel withGas Lift Valve

Produced oilInjection Gas In

Completion Fluid

Reservoir


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High Degree of Flexibility andDesign Rates

Wireline Retrievable

Handles Sandy Conditions

WellAllows For Full Bore

Tubing Drift

Surface Wellhead Equipment

Requires Minimal Space

Multi-Well Production From

Single CompressorMultiple or Slim hole

CompletionProduced


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Needs High-Pressure Gas Well or

Compressor

One Well Leases May Be Uneconomical

Fluid Viscosity

Bottom hole Pressure

High Back-Pressure


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Wellhead EquipmentPower Cables

Pumps & Motors

Variable Speed DrivesGas Separators

ESPs can be very effective at moving large volumes


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of fluid with low GLRs, however, capital costs and run

life must be fully understood to ensure profitability:

high PI low GOR oil wells (up to 1000 scf/bbl withseparator)

high water cut producers Casing size limits size and capacity

Requires reliable electrical supply at reasonable cost

Normally run on tubing, cable deployed for offshore

Inadequate design as a result of poor IPR data


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q g p

gather data on first pump run for re-design

Inadequate service facilities

Scaling on impellers

Solids erosion Inadequate gas separation > 10% throughpump

Emulsion formation in pump

High bottom hole temperatures

high temperature insulation is available


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Motor

SealSection

Pump

Tubing

MotorControlProduced Hydrocarbons Out


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High Volume and Depth Capability

High Efficiency Over 1,000 BPD

Low Maintenance

Minor Surface Equipment NeedsGood in Deviated Wells

Adaptable in Casings > 4-1/2 Use for

Well TestingVent


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Available Electric Power

Limited Adaptability to Major Changes inReservoir

Difficult to Repair In the Field

Free Gas and/or Abrasives

High Viscosity

Higher Pulling Costs


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BROADLY DEFINED AS DETERIORATION OF


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MATERIAL OR ITS PROPERTIES UNDER THE

INFLUENCE OF ENVIRONMENT

INEVITABLE PHNENOMENON

IN OILFIELD OPERATIONS IT EXTENDS FROM WELLTO DELIVERY POINT

INITIALLY NOT ENOUGH ATTENTION WAS GIVEN

UNTIMELY FAILURE OF EQUIPMENT STARTED


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ANALYSIS OF CAUSE LEAD TO CONCLUSION THAT

CORROSION WAS THE CULPRIT

PROBLEM MULTIPLIED WHEN NEWER

TECHNOLOGIES LIKE STEAM INJECTION,INSITUCOMBUSTION,POLYMER INJECTION etc. WERE PUT

TO USE

DEEPER AND HIGH TEMPERATURE WELLS

MULTIPLIED THE PROBLEM

IMPORTANCE OF CORROSION The three main


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reasons for the importance of corrosion are:

economic, safety, and conservation.

economic impact of corrosion result from the

corrosion of piping, tanks, metal components ofmachines, ships, marine structures , etc

safety of operating equipment by causing failure


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(with catastrophic consequences) of, for example,

pressure vessels , boilers , turbine blades and

rotors, etc.

Loss of metal by corrosion is a waste not only of themetal, but also of the energy, the water, and the

human effort that was used to produce and

fabricate

Temperature

Typical E&P processf


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temperatures range from-100C to >200C

Corrosion rates increasewith temperature

Pressure

Pressure: up to 10,000psi Increase partial pressure of

dissolved gases

Flowrate & flow regime

High-flow: erosion and

corrosion-erosion. Low-flow or stagnant

conditions promote bacteria

245

CORROSION IN OIL FIELD


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ENTIRE CHAIN OF OPERARITONS EXPOSED TO


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CORROSION

WELLS:

Tubing

Casing

Down hole equipment like pumps, packers etc.

WELL HEAD

FLOW LINES


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well fluid line

process lines

water injection lines etc.

PROCESS EQUIPMENT

STORAGE TANKS

TRUNK LINES

WATER HANDLING SYSTEMS


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THERMODYNAMIC CRITERIA

ELECTROCHEMICAL CRITERIA


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H2S CORROSION

250

F ti f thi t ti F S f fil ft


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Formation of a thin protective FeS surface film often meansgeneral corrosion rates are low on steels

Main risk is localised pitting corrosion where film is damaged

Pitting will be galvanically driven

251

H2

S is soluble in water


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2 Produces a weak acid and lowers the pH

H2S H+ + SH-

At low concentrations, H2S helps form protective FeSfilm

Main risk is localised pitting corrosion which can berapid

H2S also poisons combination of atomic hydrogen intomolecular hydrogen

H+ + e- H

H + H H2

252

X

Atomic hydrogen -dangerous to steels!!

H2 H+

S2-

Fe2+

H


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253

HHH

H

H

Higher Strength Steels YS > 500 MPa Low Strength Steels YS < 550 MPa

Applied Stress No Applied Stress

H2

H2

SH

H

FeS Film

Metal Matrix

Key parameters:

pH and pH2S

D i di f bHAZ WELD HAZ


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Domain diagrams for carbonsteel

Material hardness

High strength steels and areas ofhigh hardness susceptible.

Temperature Maximum susceptibility at low

temperatures for carbon steels(15-25C), higher for CRAs (5-70C).

Stress Cracking promoted by high

stress levels e.g. residualwelding

254

Hardness readings

Avoid wetness

Mi i i h dUpgrade to CRAs


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Minimise hardness

Guidance on limitsin ISO 15156

Optimisemicrostructure and

minimise residualstresses

Martensitic and duplexstainless steels have limitedresistance

H2S limits for duplex and

super-duplex steels arecomplex

Function of temperature,pH, chlorides, pH2S

Nickel-base alloys such as

625 and 825 have highresistance

Testing: NACE TM0177

255

Materials requirements

Reference ISO 15156 and GP 06 20


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Reference ISO 15156 and GP 06-20 pH2S and pH

Temperature

Chlorides

Hardness limits Welding QA/QC (HIC)

Maintain hardness limits

HIC testing for plate products

256


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CO2 CORROSION

257

CO2

always present inproduced fluids


258/367

2produced fluids

Corrosive to carbon steelwhen water present

Most CRAs have good

resistance to CO2corrosion.

258

Mechanism

CO2 + H2O H2CO3H2CO3 + e

-HCO3- + H

2H H2Fe Fe2+ + 2e-

Fe + H2O + CO2 FeCO3 +H2


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259

Mesa corrosion

Localised weld corrosionlow-assisted-corrosion (CO2)

General & pitting corrosion


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260

6 CS production flowline (Magnus, 1983)

25mm thick, 90bar, 30C, 2%CO2

Heavily pitted pipe wall and welds (not necessarily uniform

corrosion)

Didnt fail removed due to crevice corrosion of hub sealingfaces

Main factors

pCO2 temperature velocity pH

For an ideal gas mixture, the partial pressure is the

pressure exerted by one component if it alone occupied

the volume. Total pressure is the sum of the partial

f h i h i


261/367

pCO2, temperature, velocity, pH- CO2 prediction model

Temperature, (C) pCO2 (bar) Carbon steel corrosion rate(mm/yr)130 0.6 7

75 0.6 6

149 30 >50

261

pressures of each gas component in the mixture

Produced sand can affect inhibitor efficiency

Inhibitor adsorption loss


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Inhibitor adsorption loss Sand (and other solid) deposits give increased risk of localised

corrosion;

Prevent access of corrosion inhibitor to the metal

Provide locations for bacteria proliferation

Galvanic effects (area under deposit at more negative potentialthan area immediately adjacent to deposit)

Formation of concentration cells/gradients

262

Internal CO2 corrosion of carbon steel needs to be managed

Usually mitigate by chemical inhibitors


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Usually mitigate by chemical inhibitors Simple geometries only (mainly pipelines)

Assume inhibitor availability (90-95%)

Inhibited corrosion rate of 0.1mm/year

Remaining time at full predicted corrosion rate Apply a corrosion allowance for the design life

If calculated corrosion allowance >8mm use CRAs

263

Filming type


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Filming type Retention time

Continuous injection

Adsorption onto clean

surfaces

264

Clean steel

CO2/H2S > 500 CO2 dominates

500 CO /H S 20 i d CO /H S


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H2S corrosion (CO2/H2S < 20)

Initial corrosion rate high

Protective FeS film quickly slows down corrosion to lowlevel

The corrosion rate is much less than the Cassandra

prediction

265

500 > CO2/H2S > 20 mixed CO2/H2S

20 > CO2/H2S > 0.05 H2S dominates

dissolved gases:

oxygen


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oxygen

can cause severe corrosion even at very lowppm(less than 1 ppm)

usually causes pittingsolubility a function of pressure andtemperature

being a strong oxidizing agent, it will increasecorrosion rates in presence of other gases like


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corrosion rates in presence of other gases like

hydrogen sulfide, carbon dioxide

carbon dioxide

forms a weak acid with waternot so corrosive as compared to oxygen

called sweet corrosion

solubility a function of pressure and temperature

i d i l bilit i d


268/367

increased pressure increases solubility, increased

temperature reduces solubility

hydrogen sulfide

very soluble in water

forms a weak acid

reaction with iron produces iron sulfide

( hi h d it i th f f bl k d ) d


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( which deposits in the form of black powder) and

hydrogen

produced hydrogen may cause blistering

combination of hydrogen sulfide and carbon dioxideis more aggressive

even minute quantities of oxygen can be disastrous

t ll b f d b lf t


270/367

may occur naturally or may be formed by sulfate

reducing bacteria

PHYSICAL VARIABLES:

temperature rates generally increase

pressure concentration of dissolved gases

velocity

stagnant or low velocity may have low rates but can


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stagnant or low velocity may have low rates but can

cause pitting

higher velocities generally cause higher corrosion

higher velocities in presence of suspended solids cancause corrosion-errosion


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EROSION & EROSION-

CORROSION

272

Gasiquid Various multi-phase flow regimespossible;


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273

LiquidGas

Bubble (bubbly) flow

Stratified flowGas

LiquidAnnular flow

Churn flow

GasLiquid

Plug flow

Wave (wavy) flow

Liquid GasSlug flow

Mist (spray) flow

erosion characteristics

distribution of phases

carrier phase for solids

Flow regimes with particles in the gas

show higher erosion rates than those

with particles in the liquid phase.

Erosion

Caused by high velocity


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y g yimpact & cutting action ofliquid and/or solidparticles

Erosion failures can be

rapid Erosion-corrosion

Occurs in environmentsthat are both erosive andcorrosive.

Erosion and corrosion canbe independent orsynergistic.

274

Erosion of tungsten carbide choke trim

Areas wherever flow is restricted

or disturbedT pieces bends chokes al es


275/367

T-pieces, bends, chokes, valves,weld beads

Areas exposed to excessive flowrates

Sand washing Washing infrequently allowing

sand to accumulate

High pressure drop during washingof separators

Sea water systems

High flow areas in water injection /cooling systems

275

Trinidad

Algeria (duplex)

Sand accumulation

Build up of sand in a test


276/367

pseparator

Pressure drop

Large pressure drop acrosssand drain pipework during

washing

Rapid failure

Occurred within 2 minutes ofopening the drain

276

Erosion at bend

Sand allowed to accumulate inseparator

Wash nozzles embedded in sandPCV ki l


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PCV not working properly

High pressure / flowrate

Nozzle not erosion-resistant

Erosion of wash nozzle

Spray changed to a jet causingerosion of shell

Local changes to operating proceduresnot communicated

Frequency of sand washing

Risk not captured or assessed inRBI

277

Water spray

Water jet


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278

Progressivenozzledamage

Occurs in environments that can be erosive and

corrosive.


279/367

Erosion and corrosion can either be:

independent of each other;

wastage equals sum of individual wastage rates

synergistic; wastage rate > sum of individual rates

localised protective film breakdown at bends,elbows areas of turbulence

279


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Water speed or local turbulence damages or removesprotective film

90-10 Cu-Ni susceptible to internal erosion-corrosion(impingement) at velocities >3.5ms-1

Water-swept pits (horse-shoe shaped)

280

Occurs at high fluid velocities

Formation & collapse of vapour


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p pbubbles in liquid flow on metalsurface.

No solids required

Typical locations

Pump impellers (rapid change inpressure which damages films)

Stirrers, hydraulic propellers

Use erosion resistant materials

Stellite, tungsten carbide

281

UNIFORM CORROSION:

idealized form of corrosion


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idealized form of corrosion

less damaging

uniform thinning

prevention:

protective coating

proper material selection, use inhibitors

GALVANIC CORROSION:(BIMETTALIC CORROSION)

two dissimilar metals with different corrosion


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two dissimilar metals with different corrosion

potential

metal with lower potential will corrode first

grooving of interface

this principle is applied in beneficial way for

corrosion control in cathodic protection

Three conditions are required for galvanic corrosion;

A conducting electrolyte (typically seawater).Two different metals in contact with the electrol te


284/367

Two different metals in contact with the electrolyte. An electrical connection between the two metals.

Relative positions within the electrochemical series (forgiven electrolyte) provides driving potential and affectsrate.

Corrosion of base metal (anode) stimulated by contact withnoble metal (cathode).

Relative area of anode and cathode can significantly affectcorrosion rate.

Higher conductivity increases corrosion e.g. presence ofsalts

284

Firewater CuNi / superduplex stainless steel

connections. 4CuNi pipe with a 550mm


285/367

4 CuNi pipe with a 550mmisolation spool (i.e. 5x OD)

Leaks experienced on CuNispools at welds

Same problems with CuNi /6Mo

285

ETAP platform

Techlok joints in a


286/367

firewater piping system

Piping: super-duplex

Seal rings: 17-4PH

286

Brass tubesheet in seawater

service Brass is Cu Zn alloy


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Brass is Cu-Zn alloy

Cu is more noble than Zn

Zn dissolvespreferentially leaving Cu

behind Result

Loss of strength

Difficult to seal

Remedy Add arsenic to the brass

287

Avoid dissimilar materials

in seawater system designs MoC for later changes

Electrical isolation between

different alloy classes Install distance spools,


288/367

g

Avoid small anode/largecathode

Avoid graphite gaskets &seals

Avoid connecting carbonsteel to titanium alloys

Galvanic corrosion orhydrogen charging oftitanium may occur

p ,separation of at least 20x pipediameters

Solid non-conducting spoole.g. GRP

Line the noble metalinternally with an electricallynon-conducting material e.g.rubber

Apply a non-conducting

internal coatingon the morenoble material. Extend coatingfor 20 pipe diameters.

288

Example : CuNi-Superduplex


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289

Apply a non-conducting internal coating on the more noble material.

Distance spool: solid, non-conducting material e.g. GRP

Distance spool: noble metal internally lined with an electrically non-conducting material such as rubber


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OTHER CORROSION

MECHANISMS

290

Chemicals can be corrosive

Carbon steel OK for non-corrosivechemical piping, e.g. methanol


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p p g, g

Corrosive chemicals (e.g. concentratedsolutions of inhibitors and biocides)require CRAs vendor will specify

316 SS is typical Notable exceptions:

Hypochlorite: very corrosive, titanium orGRP piping required

Avoid titanium alloys in dry methanol

service due SCC

291

SCC of a titanium seal exposed topure methanol instead of 5%

water content

Carbon steel open drain pipework.

Seepage of scale inhibitor (passing valve)

S l i hibi H


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Scale inhibitor pH


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switch off when notflowing

Areas affected Impingement / turbulent

areas Bends and low points

Use quill/other mixer Upgrade material Thicker schedule

Valve arrangement Make self-draining Enable quill removal

293

Main Flow

Injected Fluid

Impingement

Environments less common in E&P

Flare tips, fired heaters, boilers Oxidation


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Oxidation

Oxidation significant >530C

Oxidation rate varies with temp,gas composition and alloy Crcontent

Firetubes: usually CS, but Cr-Mo alloys needed for hightemps

Flare tips: 310 SS, alloy 800H

Other high temperature mechanisms

sulphidation (H2S and SO2) carburizing, metal dusting, hot

salt

thermal fatigue and creep

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Material: carbon/low-alloy steels

Environment: aqueous amine systemsC ki d t id l t


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Cracking due to residual stressesat/next to non-PWHTd weldments

Cracking develops parallel to theweld

Mitigation:

PWHT all CS welds includingrepair and internal/externalattachment welds.

Use solid/clad stainless steel 304 SS or 316 SS

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Intergranular cracking

Amine piping welds requirePWHT to avoid SCC

Glycol usually regarded as benign

Corrosion in glycol regeneration

systems usually due to; Acid gases absorbed by rich glycol


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Acid gases absorbed by rich glycolor

Organic acids from oxidation ofglycol and thermal decomposition

products Condensation of low pH water

giving carbonic acid attack.

Risk recognised in design

On-skid: CRA piping & clad

vessels However, off-skid piping mix of

regular CS and LTCS

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Combined action of cyclic tensile

stress and a corrosiveenvironment


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Fatigue is caused by cyclicstressing below the yield stress Cracks start at stress raisers Can occur due to vibration e.g.

smallbore nozzles & withheavy valve attachments Presence of corrosive

environment exacerbates theproblem Can lead to pitting, which acts

as stress concentrators

297

2 A106 GrB carbon steel piping


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Wet gas service, 1.2%CO2 and160ppm H2S

Operating @ 120C and 70bar

Elbow exposed to vibration (usedin a gas compression train)

Crack located at 12 o'clock position

Crack initiated internally

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EXTERNAL CORROSION

SURFACE FACILITIES

299

External corrosion of unprotected steel surfaces

External corrosion of coated surfaces

C i d i l i (CUI)


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Corrosion under insulation (CUI)

Corrosion under fireproofing (CUF)

Pitting & crevice Corrosion

Environmental cracking

300

Bare steel surfaces

At locations of coating breakdown

Under deposits such as dirt, adhesive tape or nameplates Mating faces between pipe/pipe support saddles & clamps


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Mating faces between pipe/pipe support saddles & clamps

Isolated equipment not maintained or adequately mothballed

Water sources include:

sea spray and green water (FPSO or semi-sub)

rain

deluge water

leaking process water

condensation

downwind of cooling towers.

301


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Damage can be extensive or localised.

Corrosion can be general attack, pitting or cracking.

Seen as flaking, cracking, and blistering of coating withcorrosion of the substrate.

302

Carbon/low alloy steels usuallycovered in compact scale/thickscab

St i l t l h li ht t i


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Stainless steels have light stains onthe surface possibly with stainedwater droplets and / or salts.

Corroding copper alloys covered in

blue/greencorrosion products.

303


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304

25Cr super-duplex (PREN40)

Seawater service 12 months exposure in


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12 months exposure intropical climate

External corrosion alongwelds

Poor quality fabrication

305

Bolted joints

Onshore and offshore: exposed to frequent wetting Low alloy bolts


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Low alloy bolts

General or localised corrosion

Galvanic corrosion in stainless steel flanges

CRA bolts susceptible to pitting and/or SCC

Crevice corrosion under bolt heads and nuts

Hydrogen embrittlement possible

Fatigue

306


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General corrosion Galvanic corrosion

Crevice corrosion Stress corrosion cracking

Corrosion General surface corrosion

Galvanic corrosion e.g. 316 SS / carbon steel


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g / Use of graphite gaskets

Potential problems Failure of flanged connection

due to corroded fasteners Joint leak

Corrective actions Change gasket/fastener

materials Replace graphite gaskets with

non-asbestos or rubber material

308


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Location of graphite gaskets

Valves

Valve handles Chain-wheels

l b d


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Valve body

Structures

Stairways and walkways

Gratings, ladders,handrails

Cable trays and unistruts

Threaded plugs

Valve bodies, xmas trees,

piping Dissimilar metals

310

Deterioration of coating with time All paints let water through - continuously wet areas will fail

Poor original surface preparation / paint application Mechanical damage


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g Small area of damage can lead to major corrosion

311

CUI

Water seeps into insulation andbecomes trapped, results in


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becomes trapped, results inwetting and corrosion of themetal

Carbon steel corrodes in the

presence of water due to theavailability of oxygen.

CUF

Same mechanism except watergets behind the fireproofing.

312

Typical insulation types;

Process Personnel protection

( )


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(PP)

Winterisation

Acoustic

Challenge the need Remove unnecessary

insulation

Replace PP with cages

313

Lobster-back joint

Mitred joint

Pre-formed bends

4 gas compression recycle

line Operating pressure, 35bar


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3 bar pressure surge

Temperature: 50C

6.02mm nominal WT

Rockwool insulation

Extensive corrosion rupture

Unusual, burst rather thanleaked

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2 fuel gas piping outsideedge of platform - exposed

CS, heat-traced, Rockwool

Operating @ 5bar 45C

Focus on internal corrosion

Previous survey founddefect in an adjacent line.

Failed line in survey but


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Operating @ 5bar, 45C,5.4mm NWT

Failed during plant start-up

External corrosion scale,CUI

Failed line in survey butnot failed area.

Features selected from

onshore not site survey

4 CS hydrocarbon line

55C, inlet to PSV (153 bar)

Th ll d l i i (TSA)


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316

Thermally-sprayed aluminium (TSA)

CUI found, radiographed ok to refurbish.

Found during needle-gunning (paint removal)

Max pit depth 10mm

Insulation permanently removed

CS offshore vessel

Operating at 85C and 11bar


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PFP coating (passive fireprotection)

Extensive corrosion

scabbing on both sides ofvessel.

Scaling runs in twohorizontal distinct linesalong each side.

Scaling directly above

lower seam of insulation location of water

retention.

317

400x300x30mm

400x100x25mm

Stainless steels in marine

environments (chlorides, O2) 316L stainless steel

l d f


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commonly used forinstrument tubing

Particularly susceptible atsupports and fittings.

Primary mitigation ismaterials selection (higherPREw)

Tungum, 6Mo, super-duplex

Alternative mitigationmethods (coating, cleaning),not easy or practical.

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316 SS tubing super-duplex tubing


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316 SS (pitting/crevice corrosion) super-duplex (no pitting)

Pitting and crevice

corrosion of 316sspiping


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Clamps

Plastic retainingblocks

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Mechanism same as internal chloride SCC however: Numerous variables influence susceptibility therefore

guidance differs Material, stress, chlorides, oxygen and temperature

N b l t id il bl k t d i


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No absolute guidance available, seek expert advice

321

Chloride SCC is characterised by trans-

granular crack paths

UK HSE:

Coat 22Cr duplex >80C NORSOK M-001 SCC temp limits:

22Cr duplex >100C


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22Cr duplex >100C

25Cr super-duplex >110C

Recent testing has shown failures at

80C now recommend 70C as limit

Reliant on external coati

OIL D-1.pptx E&P industry

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