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 WELLS WELL FLOW LINES RECEIVING MANIFOLD SEPARATION FACILITY STORAGE TRANSPORTATION 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 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 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 SEPARATION SYSTEM OIL separators a. two phase b. three phase c. horizontal d. vertical e. spherical 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 . separators are fitted with different internals to facilitate separation provided with different instruments for pressure and level control down stream may have a meter for measurement of quantity and taken to storage tank or separated oil may be taken for further treatment . separated gas is taken out of separated and may be sent for sale or for process requirement gas may further be treated if required gas compressors are used for compressing for transportation . . . . . . . they create less disturbance than plates or angle iron. . design of the baffles is governed by the structural supports required to resist the impact-momentum load.VESSEL INTERNALS Inlet Diverters: Two main types: baffle plates and centrifugal diverters. angle iron. flat plate. cutting down on re-entrainment or emulsifying problems. advantage of using a half sphere or cone is . baffle plate can be a spherical dish. or anything that will accomplish a rapid change in direction and velocity of the fluids and disengage the gas and liquid. cone. . Centrifugal inlet diverters use centrifugal force. have a cyclonic chimney or may use a tangential fluid race around the walls. to disengage the oil and gas. these inlet diverters 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 . rather than mechanical agitation. . . . . This foam can be stabilized with the addition of chemicals at the inlet. Many times a more effective solution is to force the foam to pass through a series of inclined parallel plates or tubes .Wave Breakers In long horizontal vessels it is necessary 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. . A vortex could suck some gas out of the vapor space and re-entrain it in the liquid outlet.Vortex Breaker It is normally good to include a simple vortex breaker to keep a vortex from developing when the liquid control valve is open. . wire mesh pads are made of finely woven mats of stainless steel wire wrapped into a tightly packed cylinder. liquid droplets impinge on the matted wires and coalesce. centrifugal force devices. or packing. vanes.Mist Extractor Liquid carryover occurs when free liquid escapes with the gas phase. mist extractors are made of wire mesh. if the velocities are too high. if the velocities are low. the liquids knocked out will be re-entrained .effectiveness of wire mesh depends largely on the gas being in the proper velocity range. the vapor just drifts through the mesh element without the droplets impinging and coalescing . . . . . if present)remove all phases through their respective outlets. retain liquids long enough for separation to occur. scrub the gas through as efficient mist extractor. control and maintain the gas-oil interface (and oil-water. lower the gas velocity to allow liquids to drop out.Separator must do the following Separate the bulk of the liquid from the gas in a primary separating section. Oil: flow rate.Information required: for design Separator operating temperature and pressure. Impurities: quantities and description of paraffin. Gas: flow rate. specific gravity. acid-gas content. specific gravity. specific gravity. waxes. viscosity. sand. etc. corrosion and scaling tendencies. . foaming tendencies. Water: flow rate. . DRAG FORCE IF FLOW IS LAMINAR THEN . FOR TERBULENT FLOW . HORIZONTAL SEPARATOTOR -SIZING GAS CAPACITY . LIQUID CAPACITY SLENDERNESS RATIO SEAM TO SEAM LENGTH . VERTICAL SEPARATOTOR -SIZING GAS CAPACITY GAS CAPACITY . SLENDERNESS RATIO SEAM TO SEAM LENGTH . . . . . . . . . . SINGLE PHASE FLOW LIQUID GAS MULTIPHASE FLOW WELL FLOW LINES PROCESS LINES . MULTIPHASE FLOW BUBBLE PLUG STRATIFIED WAVY SLUG SPRAY . . . . .5 × 10-6) fLQl2 (SG) ΔP where d = pipe inside diameter. ft. f = Moody friction factor. psi (total pressure drop). . B/D. d5 = (11. L = length of pipe. General Equation.Pressure Drop for Liquid Flow. dimensionless. Ql = liquid flow rate. SG = specific gravity of liquid relative to water. in. ΔP = pressure drop. f = Moody friction factor. in. . T = flowing temperature. ft. and L = length.Pressure Drop for Gas Flow. dimensionless. psia. Q g = gas flow rate. MMscf/D. psia. P2 = downstream pressure. d = pipe ID.2 [ SQ2g ZT f L] d5 Where P1 = upstream pressure. S = specific gravity of gas. P12 − P22 = 25. Z = compressibility factor for gas. dimensionless.. °R. Weymouth Equation: used for high-Reynoldsnumber flows Qg = 1. T1 = temperature of gas at inlet.1d2. psia.67 [P21 – P21 ]1/2 [LSZT1 ]1/2 where :Qg = gas-flow rate. And Z = compressibility factor for gas. psia. d = pipe inside diameter. dimensionless. ft. P2 = downstream pressure. MMscf/D.L = length. in. °R S = specific gravity of gas..P1 = upstream pressure. . temperature of gas at inlet. psia.: used for moderate-Reynoldsnumber. Lm-length. Zcompressibility factor for gas. good operating conditions: 0. P2-downstream pressure.85).95. Qg = 0.Qg-gas-flow rate. dpipe ID. dimensionless . miles.028E [ P21− P2 2 2 ]0. psia.°R.961ZTLm] 0. S-specific gravity of gas.53 [ S0. in. MMscf/D. average operating conditions: 0.Panhandle Equation.0..51 Where:E-efficiency factor (new pipe: 1. P1-pressure.51 d2. T. Spitzglass Equation.0.MMscf/D. ΔhW. in. Assumptions: f-(1+ 3.03d)]1/2 Where:Qg-gas-flow rate.inches of water.pressure loss.6/d + 0.≤ 10% of P1 . For vent lines Qg = 0. P1-15 psia.03d) (1/100). T-520°R. Z = 1.6/d + 0.09[ Δhwd5]1/2 [ SL(1 + 3.ΔP. d-pipe ID. :for larger-dia.: for smaller-dia.(ΔP<10% of P1).also recommended for long runs of pipe (> 20 miles)like cross country transmission pipelines and for moderate Reynolds numbers. . 12 in. Spitzglass Eqn:for low-pressure vent lines< 12 in.000 psig) applications. and less).in dia. Panhandle Eqn.and high Reynolds number.Simplified Gas Formula: recommended for most generaluse flow applications. medium.+diameter).pipe (generally.to high-pressure (+/–100 psig to > 1.pipe (12-in. Weymouth Eqn. also recommended for shorter lengths of segments (<20 miles) within production batteries and for branch gathering lines. ρM -density of the mixture. and d = pipe ID. psi. API RP14E . L = length. dimensionless. lbm/ft3. in. lbm/hr. W = rate of flow of mixture.Simplified Friction Pressure-Drop provides an approximate solution for friction pressure drop in twophase-flow problems that meet the assumptions stated.4 × 10-6 f LW 2 ρM d5 Where ΔP = friction pressure drop. ΔP =3. ft. f = Moody friction factor. lbm/ft3 (air = 1). S = specific gravity of gas at standard conditions. B/D. lbm/ft3. MMscf/D. relative to water.180Q gS + 14. And SG = specific gravity of liquid.The formula for rate of mixture flow is W = 3. QL = liquid flow rate. .6QL(SG) where Q g = gas-flow rate. .The density of the mixture is given by ρM =12.7P + RTZ Where P = operating pressure. ft3/bbl.409(SG)P + 2. And Z = gas compressibility factor. relative to water.7RSP 198. dimensionless. lbm/ft3 (air = 1). lbm/ft3. R = gas/liquid ratio. psia. T = operating temperature. S = specific gravity of gas at standard conditions. SG = specific gravity of liquid. °R. psi. and ΔZ = increase in elevation for segment.433(SG)ΔZ . Where ΔPZ = pressure drop because of elevation increase in the segment. ft. The total pressure drop can then be approximated by the sum of the pressure drops for each uphill segment. .The pressure drop at low flow rates associated with an uphill elevation change may be approximated with Equation ΔPZ ≈ 0. SG = specific gravity of the liquid in the segment. relative to water. ρM is the average density of the mixture at flowing conditions. It can be calculated from ρM = (12409)(SG)P + (2. non-corrosive or corrosion controlled services.7)RSP (198. and S = specific gravity of the gas relative to air. 150 to 200 may be used for continuous. values of C = 100 for continuous service and C = 125 for intermittent service are conservative. Industry experience to date indicates that for solids-free fluids.Calculate the erosional velocity of the mixture with Ve =C/ρM1/2 where C = empirical constant. up to 250 have been used successfully .7)P + ZRT Where SG = specific gravity of the liquid (relative to water). in. ft3/bbl. R = gas/liquid ratio.. Z = compressibility factor.000V] 1/2 Where d = pipe ID. to determine the pipe size. d= [ (11.Once a design velocity is chosen.7P )QL] 1/2 [1. T = gas/liquid flowing temperature. B/D.9 + ZT R/ 16. °R. ft/sec. dimensionless. . And QL = liquid-flow rate. psia. V = maximum allowable velocity. P = flowing pressure. FOR EROSIVE SERVICE FITTINGS . are entrained in the flow stream. In twophase flow. Erosion of the pipe wall itself could occur if solid particles.Multiphase-Line Sizing: minimum fluid velocity in multiphase systems must be relatively high to keep the liquids moving and prevent or minimize slugging. maximum recommended velocity is 60 ft/sec to inhibit noise and 50 ft/sec for CO2 corrosion inhibition. particularly sand. . This is called erosion/corrosion. recommended minimum velocity is 10 to 15 ft/sec. guidelines from API RP14Eshould be used to protect against erosion/corrosion. it is possible that liquid droplets in the flow stream will impact on the wall of the pipe causing erosion of the products of corrosion. andTolmanufacturers allowable tolerance. psi.95 electric fusion weld. 0. in. 0. The B31.3 wall-thickness calculation formula is t = te + tth + [ Pdo ] [ 100 ] *2(SE + PY) + *100 − Tol] where t-minimum design wall thickness.te-corrosion allowance. % (12.3 Code. 10 pipe > 20 in.60 furnace butt weld]..Wall-Thickness Calculations: B31. psi E = longitudinal weld-joint factor [1.3 is a very stringent code with a high safety margin. ANSI/ASME Standard B31. straight or spiral seam APL 5L.Y-derating factor (0. API 5L).0 seamless. 0. S-allowable stress for pipe.. ..tth-thread or groove depth.5 pipe up to 20 in. do-outside diameter of pipe. in. in.-OD. P-allowable internal pressure in pipe. double butt. OD.85 electric resistance weld (ERW). in.4 for ferrous materials operating below 900°F). 60 furnace butt weld]. double submerged arc weld and flash weld. 0. psi. measurement and regulation stations. such as pump stations. F = derating factor.B31. and E = longitudinal weld-joint factor [1. ERW. P = internal pressure in pipe. 0.. and tank farms.4 is t = Pdo 2(F ESY ) .72 for all locations. The wall-thickness formula for Standard B31.4 Code.0 seamless. in. psi. 0..80 electric fusion (arc) weld and electric fusion weld.SY = minimum yield stress for pipe. do = OD of pipe. in. pigging facilities. . Where t = minimum design wall thickness. is used often as the standard of design for crude-oil piping systems in facilities. The B31. is often used as the standard of design for natural-gas piping systems in facilities.B31. SY . measurement and regulation stations. psi..8 wall-thickness formula is t = Pdo 2F ETSY Where t-minimum design wall thickness. such as compressor stations.minimum yield stress for pipe. dO ..8 Code. psi F-design factor E. and tank farms. gas-treatment facilities.OD of pipe.longitudinal weld-joint factor and T-temperature derating factor . P-internal pressure in pipe. in. in. INTELLEGENT PIGS (for health monitoring) . SLUG CATHCERS ARE REQUIRED AT THE RECEIVING END OF THE PIG. DIFFERENT TYPE OF PIGS(for cleaning) foam rubber cups brush pigs etc. PIGGING OPERATION REQUIRES PIG LAUNCHERS AND RECEIVERS. ONSHORE: ZONE CLASSIFICATION SELECTION: a) diameter b) wall thickness c) material of construction d) pipe coating . street crossing c) railway crossing . road .ROUTE: a)selection b) route survey c) right of way or use SPECIAL REQUIREMENTS: a) area b) highway . water streams f) wet lands and marshes etc ENVIRONMENTAL CONCERNS SAFTY CONCERNS .d) bridge crossing e) river. PIPE LINE CONSTRUCTION: PIPE LINE STORAGE AND TRANSPORTATION SITE PREPRATION LINE STRINGING TRENCHING WELDING(API 1104.ASME SECTION IX Boiler and pressure vessel code) . WELD TESTING JOINT AND PIPE LINE COATING PIPE LINE LOWERING BACKFILLING VARIOUS CROSSINGS FINAL TIE INS TESTING . IN S LAY PIPE IS WELDED IN HORIZONTAL POSITION AND LEAVES THE BARGS HORIZONTALLY. WELDED PIPES ARE LOWERED FROM THE REAR OF THE BARGE. IN J LAY PIPE IS WELDED VERICALLY HELD AND PIPE LEAVES THE BARGE VERTICALLY . IN SHALLOW WATERS PIPE IS S LAYED AND IN DEEPER WATERS IT IS J LAYED. . . . . . . . . . . PIGGING OPERATIONS PE 607: Oil & Gas Pipeline Design. Maintenance & Repair 2 . UTILITY PIGS Mandrel pigs Foam pigs 11 PE 607: Oil & Gas Pipeline Design. Maintenance & Repair . UTILITY PIGS Solid cast pigs Spherical pigs or spheres PE 607: Oil & Gas Pipeline Design. Maintenance & Repair 12 . IN LINE INSPECTION TOOLS PE 607: Oil & Gas Pipeline Design. Maintenance & Repair 14 . ULTRASONIC INSPECTION TOOLS PE 607: Oil & Gas Pipeline Design. Maintenance & Repair 16 . . LIQUID PROCESSING . etc. agitation occurs as fluid flows into the well bore. for an emulsion to exist. oil and water are the two mutually immiscible liquids.. . emulsifying agent in the form of small solid particles. is present in the formation fluids. one of which is intimately dispersed as droplets in the other. up the tubing. asphaltenes.an emulsion is a heterogeneous liquid that consists of two immiscible liquids. and through the surface choke. paraffins. TYPES: WATER IN OIL OIL IN WATER WATER IN OIL IN WATER . . . . emulsion production must be expected from wells. poor operating practices increase emulsification . because these both are impossible. operating practices that involve the production of excess water because of poor cementing or reservoir management can increase emulsion-treating problems. however. or nearly so. as can a process design that subjects the oil/water mixture to excess turbulence .Prevention of Emulsions: Excluding all water from the oil while the oil is produced and/or preventing all agitation of well fluids would prevent emulsion from forming. thus preventing coalescence. they come out of solution and attach themselves to the droplets of water as these droplets are dispersed in the oil. some emulsifiers are asphaltic . .Emulsifying Agents: surface-active compounds that attach to the water-droplet surface and lower the oil/water interfacial tension. barely soluble in oil and strongly attracted to water. asphaltic emulsifiers form thick films around the water droplets and prevent droplet surfaces from contacting when they collide. these substances usually originate in the oil formation. collect at the oil/water interface) can act as emulsifiers. calcium carbonate. shale particles. but can form because of an ineffective corrosioninhibition program.Oil-wet solids (sand. zinc compounds.etc. aluminum sulfate. silt. paraffin. iron hydroxides. . iron sulfide . 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 . . crude oils with low API gravity form more stable and higherpercentage-volume emulsions than do oils of high API gravity. highviscosity/high-density oils usually contain more emulsifiers than do lighter oils. emulsions of high-viscosity crude oil usually are very stable and difficult to treat because the viscosity of the oil hinders movement of the dispersed water droplets and thus retards their coalescence. asphaltic-based oils tend to emulsify more readily than do paraffin-based oils.Stability of Emulsions. Generally. . 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.: Emulsions always are more viscous than the clean oil in the emulsion. in oilfield emulsions.Effect of Emulsions on Fluid Viscosity. μe / μo = 1 + 2.1 f2 where μe = viscosity of emulsion. .this ratio can be approximated using equation . and f = fraction of the dispersed phase. cp. cp. if no other data are available. μo = viscosity of clean oil.5 f + 14. Sampling and Analyzing : treating unit or system performance can be monitored by regularly withdrawing and analyzing samples of the contents at multiple levels in the vessel or multiple points in the system. samples should be representative of the liquid from which they are taken. particularly beneficial when treating emulsions that involve viscous oils.samples from a pressure zone can be taken without further emulsification of the liquids if the velocity of the discharging liquid is controlled . so emulsification should not be allowed to occur when the sample is extracted . Bottle Tests – Most Common Method Measure Sedimentation Rate Estimate Resultant Oil Quality Vary Chemical Type and Dosage . 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 . BOTTLE TEST • • Chemical Dossage Mixing 100 cc Emulsion • • Heating to process temperature 24 hours settling evaluation cc Oil cc Emulsion cc Water t = t1 t=0 . 62 1.Chemical Bottle Test Water in Oil % By Difference Electrostatic Bench Test BS&W Measured % A B C D E 2.3 5.35 Red: Best Performance .12 2.2 4.7 6 2.20 2.01 1.6 5. HEATING 2. SETTLING OF SEPARATED WATER a) NATURAL SETTLING b) FORCED SETTLING . EMULSION STABILITY HOW TO DESTABLIZE METHODS TO DESTABLIZE: 1. CHEMICAL ADDITION 3. .WHY HEATING: Using heat to treat crude-oil emulsions 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. which helps coalescence by causing the dispersed-phase droplets to collide more frequently . and the curves on this chart should be used only in the absence of specific data. Heat increases the droplets’ molecular movement.Crude-oil viscosities vary widely. . at temperatures below 180°F. thus accelerating settling. dissolve paraffin crystals). adding heat will increase the density difference. Heat also might increase the density difference between the oil and the water.. 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 might deactivate the emulsifier (e.g. In general. The vapor leaving the oil phase can be vented to a vapor recovery system or compressed and sold with the gas. or loss of volume. Because the light ends are boiled off. Either way.Heating well fluids is expensive. there probably will be a net income loss . This causes “shrinkage” of the oil. the remaining liquid has a lower API gravity and thus might have less value. Adding heat can cause a significant loss of the lower-boiling point hydrocarbons (light ends). . emulsion-heating requirements vary in accordance with daily and/ or seasonal atmospheric temperatures e.g. In some geographic areas. If the oil is above inletfluid 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.Fuel is required to provide heat. or in winter months . during a rain. at night. and so the cost of fuel must be considered. . BENEFITS OF HEATING . the fuel required for treating depends on the temperature rise. beneficial to separate free water from the emulsion to be treated. and the flow rate. . heating a given volume of water requires approximately twice the energy needed to heat the same volume of oil. the amount of water in the oil. B/D. ρo = specific gravity of oil. qo = oil flow rate.5qoρo + qwρw) where Q = heat input.the heat input for an insulated vessel (heat loss is assumed to be 10% of heat input) can be approximated Q = 16ΔT(0. Btu/hr. B/D. ΔT = temperature increase. . and ρw = specific gravity of water. qw = water flow rate. °F. DISADVANTAGES: EXPENSIVE GAS EVOLUTION LOSS OF LIGHTER FRACTION REDUCES API GRAVITY SOME TIME DECREASES GRAVITY DIFFERENCE IN PHASES . TYPES: Water soluble Oil soluble ACTION INJECTION Injection point Dilution CHEMICAL SELECTION . NATURAL AIDED . NATURAL SETTLING: COALSCING SYSTEM Plates Packing AGITATION SETTLING TIME AIDED SETTLING Electrostatic coalescence . density difference between the oil and the water causes the water to settle through and out of the oil by gravity. Gravity settling is the oldest.Gravity Settling. gravitational separation of water from oil is controlled by the well known Stokes law V =2gr2(D2. simplest.D1 ) /9µ V-droplet falling velocity g-gravitation constant r-particle radius D2-specificgravityof water D1-specific gravity of oil µ-viscosity of oil . and most widely used method for treating crude-oil emulsions. 5665 x 10-2 when r-particle size in microns D2-specificgravityof water at conditions D1-specificgravityof oil at condition µ-viscosity of oil at conditions in centipoises.parameters which control the falling velocity of water particle are the droplet size. Application of heat will reduce the oil gravity as well as viscosity Rewriting Stokes equation in more easily usable form V= Cr2(D2 – D1)/µ value of C is 2. density difference and viscosity of oil. . water droplets polarize and align with electric force.Emulsion subjected to high voltage electrical field high voltage. . electrical attraction brings the droplets together and causes them to coalesce. the positive and negative poles of the droplets are brought adjacent to each other. effect repeats with each cycle. the surface tension pulls them back toward a spherical shape.droplets dispersed in oil that are subjected to alternating-current (AC) field become elongated along the lines of force. as voltage rises during the first half-cycle. weakening the film so that it breaks more easily .droplets are relaxed during the lowvoltage part of the cycle. increase the droplet diameter decrease the distance between droplet . it is required to increase that the applied voltage gradient.force existing between droplets is mathematically given by the following equation: F= KƐ2d6/S4 (with S≥d) F-attractive force between droplet K-Dielectric constant for the system Ɛvoltage gradient d-diameter of droplet s-distance between droplet From this equation it is evident that in order to increase the force between droplets to help them coalesce. the droplet will distort sufficiently to rupture its film at a critical point causing the droplet to break into smaller .Critical voltage gradient Dielectric constant for the system T-Surface tension d-Diameter of droplet . submicronic droplets The critical voltage gradient can be expressed for a particular droplet as Ec ≤k(T/d)1/2 where Ec. If the voltage gradient applied to a particular droplet is increased beyond a certain critical voltage (Ec) peculiar to the droplet.. VERTICAL HORIZONTAL WITH ONLY HEATING ARRANGEMENT WITH ELECTROSTATIC COALESCENCE . EMULSION ENTERS AT THE TOP IN GAS SEPARATION CHAMBER EMULSION FLOWS THROUGH THE DOWNCOMES TO THE BOTTOM OF THE VESSEL EMULSION MOVES UP THROUGH HEATING SECTION WATER SEPARATION IN COALESCING SECTION . INTERPHASE CONTROLLER CONTROLS WATER LEVEL IF PROVIDED WITH ELECTRSTATIC COALESCER OIL MOVES ACROSS IT FOR FURTHER DEHYDRATION INTERPHASE CONTROLLER MAINTAINS WATER LEVEL WATER CAN BE DRIANED THROUGH WATER SIPHON . . BATTERY OF VERTICAL TREATERS . 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 . HORIZONTAL FLOW CONFIGURATION: EMULSION ENTERS AT THE TOP OF THE VESSEL FLOWS ALONG A LONGITUDINAL BAFFLE ENTERS HEATING SECTION FROM THE BOTTOM HEATED OIL TRAVELS THROUGH A SLOT IN THE PARTITION . FREE WATER AT THE BOTTOM FLOWS OUT CLEAN OIL FLOWS TO THE TOP AND COLLECTED VERTICAL FLOW CONFIGURATION: OIL ENTERS THROUGH FORNT SECTION AND FLOWS DOWN FREE WATER IS SEPARATED . EMULSION FLOWS THROUGH A SPREADER AND IS HEATED HEATED OIL ENTERS THE INERMEDIATE OR SURGE CHAMBER ADDITIONAL GAS SEPARATES OUT EMUSION ENTERS COALSECING CHAMBER THRUGH BOTTOM SPREADER . OIL MOVES THROUGH THE WATER ALYER AND GOES TO THE TOP CLEAN OIL IS COLLECTED FROM THE TOP WATER DARINED OUT FROM THE BOTTOM . . . ELECTROSTATIC TREATERS . OIL PRODUCTION BATTERY WITH SEPARATION AND TREATING . ELECTROSTATIC COALESCENCE DISCUSSED EARLIER COALESCING CHAMBER CONTAINS ELECTROSTATIC GRID ELECTROSTATIC GRID: AC COMBINATION . 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 . . . EMUSION FLOWS THROUGH THE GRID AND ELECTRIC 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 . DIPOLAR ATTRACTION FILM STRETCHING WATER TOLERANCE LIMITATIONS MINIMAL DROP MOVEMENT LOW CHARGE DENSITY LIMITS ON USEFUL FIELD STRENGTH . 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 . 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 . + UPWARD OIL FLOW .+ + - .+ . DC FIELD BENEFITS MOST AC FIELD BENEFITS. PLUS . . . . . •DROPLET TRANSPORT •NET ELECTROSTATIC CHARGE BUT. •MUST AVOID ELECTROLYTIC REACTIONS •WATER TOLERANCE IS REDUCED . . . INSULATOR HANGERS RAILS ELECTRODE PLATES . . 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. 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.DUAL POLARITY: Dual polarity AC/DC Electrostatic unit provides this needed electrical gradient. .The application of dual polarity DC potential. both positive 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 the clean oil. Provides Combined AC/DC Fields For Combined Benefits Drop Polarization Film Rupture Water Tolerance Drop Movement Drop Charge Density Minimizes Induced Corrosion . COMPARATIVE ANALYSIS 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 stages requirements 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 desalting process (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 . 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 Single stage desalting Two stage desalting Dilution water fresh water water recycle Water mixed with crude mixing efficiency problem of water solubility in oil at elevated temperatures In produced brine with a high salt concentration, it might 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 (in which fresh water is used to 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) mixing dilution water with the produced water lowers the effective value of Csw in eqn. if a singlestage desalting system requires 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 THE MIXING VALVE Differential Pressure Controller DPC To Desalter Crude Flow Mixing Valve Static Mixer (Optional) is occasionally installed either upstream or downstream of the mixing valve . SIZING EQUATIONS . RETENATION TIME . WATER DROPLET SIZE Function of viscosity For conventional treaters For Electrostatic traters . . Oil field processing generally consists of two categories of operations: Separation of natural gas from free liquids ( crude oil. NATURALGAS PROCESSING . (sand). Removal of impurities from natural gas and any condensate form. brine ) and entrained solids. di-oxide Hydrogen Sulphide . N2.It is crucial link between natural gas production and its transportation to market NATURAL GAS PROCESSING 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.O2 traces Free of particulate solids & liquid water Other key Byproducts of Natural Gas Processing Helium Carbon. 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. It involves: Simple Separation + Dehydration (Separation of hydrocarbon condensate. H2S) component as H2S is toxic and both are corrosive) . The individual unit operations commonly used in field handling natural gas are: Basic fields processing schemes: Prevention of hydrate formation Sweetening Dehydration Condensate recovery and hydrocarbon dew point control Compression Flow measurement Heating and cooling Pipe line transport of natural gas . Glycol and methanol are comparable Merits of methanol: It can be used at any temperature Recovery is marginally economically due to its low cost and high vaporization losses. Lower capital investments Methanol can dissolve existing hydrates . increasing glycol regeneration heat load.DE-MERITS OF METHANOL It is co-absorbed with water vapor by glycol. . Methanol can also reduced the capacity of solid desiccant pallets because methanol is readily co-absorbed. Aqueous methanol can corrode steel in glycol steel and re boiler. Demerits of glycol Its not chosen below 15 F because of its high viscosity and difficulty of separation from liquid HC . Merits of glycol (TEG/DEG) It exhibits higher depression of hydrate formation temperature. Can be recovered easily. Cheaper where continuous injection is required. . Without intimate mixing glycol injection may not prevent hydrate formation . It can not attack or dissolve existing hydrates. disulphide (RSSR) etc is usually 10 to 20 gr / 100 scf (160-200 ppmv) CO2 concn 2-3% .25 gr / 100scf) Max total sulfur content including mercaptans (RSH). Carbon Sulfide (COS). Removal of Acid Gases Permissible Acid Gas Concentration H2S concn < 4 ppm v (0. Ucarsol. Batch Process Iron Sponge. Chem Sweet. Sulpha Check Aqueous Amine Solutions Moethanolamine Diethanolamine Diglycolamine Methyl diethanolamine (Solutions are regenerated. Flexsorb & Optisol) (These Solution absorb organic sulfur and are capable of high acid gas loading) . Physical Solvent. Water Sulfinol. are used to remove large amount of Sulfur and CO2) Mixed Solutions (Mix of Amine. Direct Oxidation to Sulfur Stretford. Physical Solvents Selaxol Rectisol 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. Sulferox Locat (These Process practically eliminate H2S emissions) . Du Pont. Zeochem & Davison Chemical Molecular Sieves For low acid gas concentration. Grace. Cynara (Dow). lb / day = 1. If S < 20 lb/day – Batch Process If S > 100 lb / day – Amine Solution Sulfur Content. Adsorption Linde. International Permeation and Monsanto are most suitable for bulk CO2 separation.34 (MMSCFD) (gr/H2S/100SCF) . Air Products. gas is simultaneously dried Membranes Example AVIR. especially when the feed gas concentration is very high In General. PIC G/L 9 over head scrubber meter flow Flash vessel Closed drain 1 LP flare Glycol Dehydration Unit M Rich glycol TCV Reboiler Storage tank Stripping gas Closed drain Recirculation pump M Booster pump Ajay Kumar Neelam .Gas from Compressor HP flare Fuel gas contactor Fuel gas HUT LP flare coalescer sep . . RECTANGULAR HORIZONTAL VERTICAL SPHERICAL . OPEN FIXED ROOF FLOATING ROOF: EXTERNAL FLOATING ROOF INTERNAL FOATING ROOF CLOSED FOATING ROOF . RIVETED BOLTED SHOP WELDED FIELD WELDED . . LIQUID GAS . ACCURACY Linearity Repeatability Resolution Turndown . Linearity :ability to maintain a meter factor through-out the stated turndown.0.Accuracy: difference from the actual measurement and the meter reading. temperature. accuracy is stated in following terms: Repeatability :meter’s ability to reproduce same measurement for a set of constant conditions of flow rate.15% or +/-0. Repeatability of a custody transfer meter should be within +/-. viscosity.025% in 3 runs or +/. density. pressure.25% for custody transfer use. Depending on meter size and application this is typically +/-0.05% of each other in 5 consecutive prove runs. . is a measure of the smallest increment of total flow that can be individually recognized by the meter. Turndown is the meter’s flow range capability.000 bbl/hr is said to have a 10:1 turndown. Turndown. The flow range of the meter is the ratio of 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.Resolution. FLOW RATE PRESSURE TEMPERATURE VISCOSITY ACCURACY . INFERS FLOW . DIRECT .POSITIVE DISPLACEMENT INDIRECT . The volume flow rate can be calculated from the revolution rate of the mechanical device. the volume of the fluid that passes the chamber can be obtained by counting the number of passing parcels or equivalently the number rounds of the rotating/reciprocating mechanical device. measure volumes of fluid flowing through by counting repeatedly the filling and discharging of known fixed volumes.Positive displacement flowmeters. also know as PD meters. Hence. a rotating/reciprocating mechanical unit is placed to create fixed-volume discrete parcels from the passing fluid. A typical positive displacement flowmeter comprises a chamber that obstructs the flow. . Inside the chamber. TURBINE METERS CORIOLIS METERS PRINCIPLE : INFERS FLOW BY MEASURING SOME DYNAMIC PROPERTY OF THE FLOW STREAM Density is related to frequency.Measures density and mass flow rate Principle: As fluid moves through a vibrating tube(s). by the following equation ρ = C0 + C1T2 Where.Coriolis force causes distortion which is directly proportional to mass flow rate. though not linearly. ρ = Density of fluid C0 & C1 = Constants T = Tube time period . . . . ORIFICE METER TURBINE METER CORIOLIS METER ULTRASONIC METER . Principle: differential pressure proportional to squire of flow rate Standards: AGA 3 ISO 5167 . psia .quantity rate of flow at base conditions. pf absolute static pressure. cfh C ’.orifice flow constant.BASIC EQUATION: qh =C ’ (hw pf )1/2 where: qh . hw differential pressure in inches of water at 600F. cfh(Fr) Reynolds number factor (Y) expansion factor (Fpb) pressure base factor (Ftb) temperature base factor (Ftf) flowing temperature factor (Fg) specific gravity factor(Fpv) supercompressibility factor(Fm) manometer factor for mercury meter(Fl)gauge location factor.C ’=(Fb)(Fr)(Y)(Fpb)(Ftb)(Ftf)(Fg)(Fpv)(Fm)(Fl)(Fα) Where: (Fb) basic orifice factor.(Fα) orifice thermal expansion factor . 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 . . . . . . Sucker Rod Tubing Anchor/Catcher Sucker Rod Pump Assembly Reservoir . . High System Efficiency. Upgraded Materials Reduce Corrosion Concerns. Economical to Repair and Service. High Salvage Value for Surface & Downhole Equipment . Flexibility -Adjust Production Through Stroke Length and Speed. Positive Displacement/Strong drawdown. Optimization Controls Available. Potential for Tubing and Rod Wear Gas-Oil Ratios Most Systems Limited to Ability of Rods to Handle Loads ( Volume Decreases As Depth Increases . Wellhead Surface Drives Continuous & Threaded Sucker Rods Subsurface PC Pumps & Accessories . Vertical Electric Wellhead Drive Tubin g Sucker Rod Stator Rotor . Low Capital Cost Low Surface Profile for Visual & Height Sensitive Areas High System Efficiency Simple Installation. Quiet operation Pumps Oils and Waters with Solids Low Power Consumption Portable Surface Equipment Low Maintenance Costs Use In Horizontal/Directional Wells . Limited Depth capability Temperature Sensitivity to Produced Fluids Low Volumetric Efficiencies in High-Gas Environments Potential for Tubing and Rod Coupling Wear Requires Constant Fluid Level above Pump . . . Injection Gas In Produced oil Completion Fluid Production Packer Side Pocket Mandrel with Gas Lift Valve Reservoir . High Degree of Flexibility and Design Rates Wireline Retrievable Handles Sandy Conditions WellAllows For Full Bore Tubing Drift Surface Wellhead Equipment Requires Minimal Space Multi-Well Production From Single Compressor Multiple or Slim hole CompletionProduced . Needs High-Pressure Gas Well or Compressor One Well Leases May Be Uneconomical Fluid Viscosity Bottom hole Pressure High Back-Pressure . Wellhead Equipment Power Cables Pumps & Motors Variable Speed Drives Gas Separators . ESP’s can be very effective at moving large volumes of fluid with low GLR’s. however. capital costs and run life must be fully understood to ensure profitability: high PI low GOR oil wells (up to 1000 scf/bbl with separator) 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 gather data on first pump run for re-design Inadequate service facilities Scaling on impellers Solids erosion Inadequate gas separation > 10% through pump Emulsion formation in pump High bottom hole temperatures high temperature insulation is available . Produced Hydrocarbons Out Tubin g Pum p Seal Section Motor Control Motor . High Volume and Depth Capability High Efficiency Over 1.000 BPD Low Maintenance Minor Surface Equipment Needs Good in Deviated Wells Adaptable in Casings > 4-1/2” Use for Well TestingVent . Available Electric Power Limited Adaptability to Major Changes in Reservoir Difficult to Repair In the Field Free Gas and/or Abrasives High Viscosity Higher Pulling Costs . . BROADLY DEFINED AS DETERIORATION OF MATERIAL OR ITS PROPERTIES UNDER THE INFLUENCE OF ENVIRONMENT INEVITABLE PHNENOMENON IN OILFIELD OPERATIONS IT EXTENDS FROM WELL TO DELIVERY POINT INITIALLY NOT ENOUGH ATTENTION WAS GIVEN . UNTIMELY FAILURE OF EQUIPMENT STARTED ANALYSIS OF CAUSE LEAD TO CONCLUSION THAT CORROSION WAS THE CULPRIT PROBLEM MULTIPLIED WHEN NEWER TECHNOLOGIES LIKE STEAM INJECTION,INSITU COMBUSTION,POLYMER INJECTION etc. WERE PUT TO USE DEEPER AND HIGH TEMPERATURE WELLS MULTIPLIED THE PROBLEM IMPORTANCE OF CORROSION The three main reasons for the importance of corrosion are: economic, safety, and conservation. economic impact of corrosion result from the corrosion of piping, tanks, metal components of machines, ships, marine structures , etc safety of operating equipment by causing failure (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 the metal, but also of the energy, the water, and the human effort that was used to produce and fabricate Temperature Typical E&P process temperatures range from -100ºC to >200ºC Corrosion rates increase with 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 ENTIRE CHAIN OF OPERARITONS EXPOSED TO CORROSION WELLS: Tubing Casing Down hole equipment like pumps, packers etc. WELL HEAD FLOW LINES well fluid line process lines water injection lines etc. PROCESS EQUIPMENT STORAGE TANKS TRUNK LINES WATER HANDLING SYSTEMS THERMODYNAMIC CRITERIA ELECTROCHEMICAL CRITERIA H2S CORROSION 250 Formation of a thin protective FeS surface film often means general corrosion rates are low on steels Main risk is localised pitting corrosion where film is damaged Pitting will be galvanically driven 251 H2S is soluble in water Produces a weak acid and lowers the pH H2S H+ + SH At low concentrations, H2S helps form protective FeS film Main risk is localised pitting corrosion which can be rapid H2S also poisons combination of atomic hydrogen into molecular hydrogen Atomic hydrogen H+ + e- H dangerous to steels!! X H + H H2 252 H2 H H+ 2+ Fe 2S FeS Film Metal Matrix H Applied Stress Higher Strength Steels YS > 500 MPa No Applied Stress Low Strength Steels YS < 550 MPa H2 H H HH H H2 253 Stress Cracking promoted by high stress levels e. residual welding HAZ WELD HAZ Hardness readings 254 . Temperature Maximum susceptibility at low temperatures for carbon steels (15-25°C).g.Key parameters: pH and pH2S Domain diagrams for carbon steel Material hardness High strength steels and areas of high hardness susceptible. higher for CRAs (570°C). pH. chlorides. pH2S Nickel-base alloys such as 625 and 825 have high resistance Testing: NACE TM0177 255 . Avoid wetness Minimise hardness Guidance on limits in ISO 15156 Optimise microstructure and minimise residual stresses Upgrade to CRAs Martensitic and duplex stainless steels have limited resistance H2S limits for duplex and super-duplex steels are complex Function of temperature. Materials requirements 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 . CO2 CORROSION 257 . + H 2H H2 Fe Fe2+ + 2eFe + H2O + CO2 FeCO3 + H2 258 . CO2 always present in produced fluids Corrosive to carbon steel when water present Most CRAs have good resistance to CO2 corrosion.HCO3. Mechanism CO2 + H2O H2CO3 H2CO3 + e. General & pitting corrosion Mesa corrosion Flow-assisted-corrosion (CO2) Localised weld corrosion 259 . 30°C.• 6” CS production flowline (Magnus. 2%CO2 • Heavily pitted pipe wall and welds (not necessarily uniform corrosion) • Didn’t fail – removed due to crevice corrosion of hub sealing faces 260 . 90bar. 1983) • 25mm thick. the partial pressure is the pressure exerted by one component if it alone occupied the volume.6 0. pH . (ºC) 130 75 149 pCO2 (bar) 0. temperature.CO2 prediction model For an ideal gas mixture.6 30 Carbon steel corrosion rate (mm/yr) 7 6 >50 261 . velocity. Main factors pCO2. Total pressure is the sum of the partial pressures of each gas component in the mixture Temperature. Prevent access of corrosion inhibitor to the metal Provide locations for bacteria proliferation Galvanic effects (area under deposit at more negative potential than area immediately adjacent to deposit) Formation of concentration cells/gradients 262 . Produced sand can affect inhibitor efficiency Inhibitor adsorption loss Sand (and other solid) deposits give increased risk of localised corrosion. Internal CO2 corrosion of carbon steel needs to be managed 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 Retention time Continuous injection Adsorption onto clean surfaces Clean steel 264 . 05 CO2 dominates mixed CO2/H2S H2S dominates H2S corrosion (CO2/H2S < 20) Initial corrosion rate high Protective FeS film quickly slows down corrosion to low level The corrosion rate is much less than the Cassandra prediction 265 .CO2/H2S > 500 500 > CO2/H2S > 20 20 > CO2/H2S > 0. dissolved gases: oxygen can cause severe corrosion even at very low ppm(less than 1 ppm) usually causes pitting solubility a function of pressure and temperature . carbon dioxide carbon dioxide forms a weak acid with water not so corrosive as compared to oxygen called sweet corrosion .being a strong oxidizing agent. it will increase corrosion rates in presence of other gases like hydrogen sulfide. solubility a function of pressure and temperature increased pressure increases solubility. increased temperature reduces solubility hydrogen sulfide very soluble in water forms a weak acid . reaction with iron produces iron sulfide ( which deposits in the form of black powder) and hydrogen produced hydrogen may cause blistering combination of hydrogen sulfide and carbon dioxide is more aggressive . even minute quantities of oxygen can be disastrous 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 cause pitting higher velocities generally cause higher corrosion higher velocities in presence of suspended solids can cause corrosion-errosion . EROSION & EROSIONCORROSION 272 . Bubble (bubbly) flow Liquid Plug flow Gas Gas Liquid Stratified flow Gas Liquid Wave (wavy) flow Gas Liquid Liquid Gas Slug flow Annular flow Churn flow Mist (spray) flow 273 . − 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.• Various multi-phase flow regimes possible. Erosion Caused by high velocity impact & cutting action of liquid and/or solid particles Erosion failures can be rapid Erosion-corrosion Occurs in environments that are both erosive and corrosive. Erosion and corrosion can be independent or synergistic. Erosion of tungsten carbide choke trim 274 . weld beads Trinidad Areas exposed to excessive flow rates Sand washing Washing infrequently allowing sand to accumulate High pressure drop during washing of separators Sea water systems High flow areas in water injection / cooling systems Algeria (duplex) 275 . bends. valves. Areas wherever flow is restricted or disturbed T-pieces. chokes. Sand accumulation Build up of sand in a test separator Large pressure drop across sand drain pipework during washing Occurred within 2 minutes of opening the drain Pressure drop Rapid failure Erosion at bend 276 . Sand allowed to accumulate in separator Wash nozzles embedded in sand PCV not working properly High pressure / flowrate Nozzle not erosion-resistant Erosion of wash nozzle Spray changed to a jet causing erosion of shell Local changes to operating procedures not communicated Frequency of sand washing Risk not captured or assessed in RBI Water spray Water jet 277 . Progressive nozzle damage 278 . wastage equals sum of individual wastage rates synergistic. wastage rate > sum of individual rates localised protective film breakdown at bends. Occurs in environments that can be erosive and corrosive. elbows areas of turbulence 279 . Erosion and corrosion can either be: independent of each other. 5ms-1 Water-swept pits (horse-shoe shaped) 280 . Water speed or local turbulence damages or removes protective film 90-10 Cu-Ni susceptible to internal erosion-corrosion (impingement) at velocities >3. No solids required Typical locations Pump impellers (rapid change in pressure which damages films) Stirrers. Occurs at high fluid velocities Formation & collapse of vapour bubbles in liquid flow on metal surface. hydraulic propellers Use erosion resistant materials Stellite. tungsten carbide 281 . use inhibitors . UNIFORM CORROSION: idealized form of corrosion less damaging uniform thinning prevention: protective coating proper material selection. GALVANIC CORROSION:(BIMETTALIC CORROSION) 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 . Relative area of anode and cathode can significantly affect corrosion rate. Corrosion of base metal (anode) stimulated by contact with noble metal (cathode). A conducting electrolyte (typically seawater). Two different metals in contact with the electrolyte. An electrical connection between the two metals.g. Relative positions within the electrochemical series (for given electrolyte) provides driving potential and affects rate. Three conditions are required for galvanic corrosion. presence of salts 284 . Higher conductivity increases corrosion e. 4”CuNi pipe with a 550mm isolation spool (i. 5x OD) Leaks experienced on CuNi spools at welds Same problems with CuNi / 6Mo 285 .e. Firewater – CuNi / super duplex stainless steel connections. ETAP platform Techlok joints in a firewater piping system Piping: super-duplex Seal rings: 17-4PH 286 . Brass tubesheet in seawater service Brass is Cu-Zn alloy Cu is more noble than Zn Zn dissolves preferentially leaving Cu behind Result Loss of strength Difficult to seal Remedy Add arsenic to the brass 287 . g. Avoid dissimilar materials in seawater system designs MoC for later changes Avoid small anode/large cathode Avoid graphite gaskets & seals Avoid connecting carbon steel to titanium alloys Galvanic corrosion or hydrogen charging of titanium may occur Electrical isolation between different alloy classes Install distance spools. rubber Apply a non-conducting internal coating on the more noble material.g. Extend coating for 20 pipe diameters. GRP Line the noble metal internally with an electrically non-conducting material e. 288 . separation of at least 20x pipe diameters Solid non-conducting spool e. Example : CuNi-Super duplex Distance spool: solid. 289 . GRP Distance spool: noble metal internally lined with an electrically non-conducting material such as rubber Apply a non-conducting internal coating on the more noble material.g. non-conducting material e. OTHER CORROSION MECHANISMS 290 . concentrated solutions of inhibitors and biocides) require CRAs – vendor will specify 316 SS is typical Notable exceptions: Hypochlorite: very corrosive. e.g. Chemicals can be corrosive Carbon steel OK for non-corrosive chemical piping. titanium or GRP piping required Avoid titanium alloys in dry methanol service due SCC SCC of a titanium seal exposed to pure methanol instead of 5% water content 291 .g. methanol Corrosive chemicals (e. • Carbon steel open drain pipework. • Seepage of scale inhibitor (passing valve) • Scale inhibitor pH <2. • Chemical entered drains. not flushed 292 . Inadequate mixing – corrosion Intermittent use switch off when not flowing 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 Main Flow Injected Fluid Impingement 293 . boilers Oxidation Oxidation significant >530°C Oxidation rate varies with temp. fired heaters. metal dusting. hot salt thermal fatigue and creep 294 . Environments less common in E&P Flare tips. but CrMo alloys needed for high temps Flare tips: 310 SS. alloy 800H Other high temperature mechanisms sulphidation (H2S and SO2) carburizing. gas composition and alloy Cr content Firetubes: usually CS. Material: carbon/low-alloy steels Environment: aqueous amine systems Cracking due to residual stresses at/next to non-PWHT’d weldments Cracking develops parallel to the weld Mitigation: PWHT all CS welds including repair and internal/external attachment welds. Use solid/clad stainless steel 304 SS or 316 SS Intergranular cracking Amine piping welds require PWHT to avoid SCC 295 . Acid gases absorbed by rich glycol or Organic acids from oxidation of glycol and thermal decomposition products Condensation of low pH water giving carbonic acid attack. Glycol usually regarded as benign Corrosion in glycol regeneration systems usually due to. off-skid piping mix of regular CS and LTCS 296 . Risk recognised in design On-skid: CRA piping & clad vessels However. g. smallbore nozzles & with heavy valve attachments Presence of corrosive environment exacerbates the problem Can lead to pitting. Combined action of cyclic tensile stress and a corrosive environment Fatigue is caused by cyclic stressing below the yield stress Cracks start at stress raisers Can occur due to vibration e. which acts as stress concentrators 297 . 2” A106 GrB carbon steel piping Wet gas service.2%CO2 and 160ppm H2S Operating @ 120°C and 70bar Elbow exposed to vibration (used in a gas compression train) Crack located at 12 o'clock position Crack initiated internally 298 . 1. EXTERNAL CORROSION – SURFACE FACILITIES 299 . External corrosion of unprotected steel surfaces External corrosion of coated surfaces Corrosion under insulation (CUI) Corrosion under fireproofing (CUF) Pitting & crevice Corrosion Environmental cracking 300 . adhesive tape or nameplates 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. Bare steel surfaces At locations of coating breakdown Under deposits such as dirt. 301 . pitting or cracking. 302 . Seen as flaking. cracking. Corrosion can be general attack. Damage can be extensive or localised. and blistering of coating with corrosion of the substrate. 303 . Carbon/low alloy steels usually covered in compact scale/thick scab Stainless steels have light stains on the surface possibly with stained water droplets and / or salts. Corroding copper alloys covered in blue/green corrosion products. 304 . 25Cr super-duplex (PREN ≥40) Seawater service 12 months exposure in tropical climate External corrosion along welds Poor quality fabrication 305 . Bolted joints Onshore and offshore: exposed to frequent wetting 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 . General corrosion Galvanic corrosion Crevice corrosion Stress corrosion cracking 307 . g. 316 SS / carbon steel 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 . Corrosion General surface corrosion Galvanic corrosion e. Location of graphite gaskets 309 . handrails Cable trays and unistruts Threaded plugs Valve bodies. xmas trees. Valves Valve handles Chain-wheels Valve body Structures Stairways and walkways Gratings. piping Dissimilar metals 310 . ladders. continuously wet areas will fail Poor original surface preparation / paint application Mechanical damage Small area of damage can lead to major corrosion 311 . Deterioration of coating with time All paints let water through . 312 . results in wetting and corrosion of the metal Carbon steel corrodes in the presence of water due to the availability of oxygen. CUI Water seeps into insulation and becomes trapped. CUF Same mechanism except water gets behind the fireproofing. Process Personnel protection (PP) Winterisation Acoustic Challenge the need Remove unnecessary insulation Replace PP with cages Mitred joint ‘Lobster-back’ joint Pre-formed bends 313 . Typical insulation types. 4” gas compression recycle line Operating pressure. burst rather than leaked 314 .02mm nominal WT Rockwool insulation Extensive corrosion – rupture Unusual. 35bar 3 bar pressure surge Temperature: 50ºC 6. 4mm NWT Failed during plant start-up External corrosion scale. 2” fuel gas piping outside edge of platform . Rockwool Operating @ 5bar. 5. CUI Focus on internal corrosion Previous survey found defect in an adjacent line. 45°C. heat-traced.exposed CS. Failed line in survey but not failed area. Features selected from onshore not site survey 315 . • 4” CS hydrocarbon line • 55°C. radiographed – ok to refurbish. • Found during needle-gunning (paint removal) • Max pit depth 10mm • Insulation permanently removed 316 . inlet to PSV (153 bar) • Thermally-sprayed aluminium (TSA) • CUI found. Scaling runs in two horizontal distinct lines along each side. CS offshore vessel Operating at 85°C and 11 bar PFP coating (passive fire protection) Extensive corrosion scabbing on both sides of vessel. 400x300x30mm 400x100x25mm 317 . Scaling directly above lower seam of insulation location of water retention. O2) 316L stainless steel commonly used for instrument tubing Particularly susceptible at supports and fittings. 6Mo. not easy or practical. 318 . Stainless steels in marine environments (chlorides. superduplex Alternative mitigation methods (coating. Primary mitigation is materials selection (higher PREw) Tungum. cleaning). 316 SS tubing super-duplex tubing 316 SS (pitting/crevice corrosion) super-duplex (no pitting) 319 . Pitting and crevice corrosion of 316ss piping Clamps Plastic retaining blocks 320 . Mechanism same as internal chloride SCC however: Numerous variables influence susceptibility therefore guidance differs Material. seek expert advice Chloride SCC is characterised by transgranular crack paths 321 . stress. oxygen and temperature No absolute guidance available. chlorides. can raise external temperature above threshold limits! SCC failure of 316L 322 . UK HSE: Coat 22Cr duplex >80°C NORSOK M-001 SCC temp limits: 22Cr duplex >100°C 25Cr super-duplex >110°C Recent testing has shown failures at 80°C now recommend 70°C as limit Reliant on external coatings to act as barrier (isolate from environment) Beware solar heating . well casings: external corrosion caused by faulty electrical insulation between wellhead and flow line or gas gathering line oil wells with known casing leaks should be checked for external corrosion internal corrosion is frequently caused by " breathing” of air if the casing-tubing annulus is open to the atmosphere. . buried drain lines beneath tanks and crevices where moisture can collect between tank and supports.vessels: external corrosion of tanks set on soil foundations. faulty gas blankets. . and solids accumulation on tank bottoms . internal corrosion caused by "breathing " air into vessels . a comparison of several tests conducted periodically at a single point or simultaneously at several points in a system give a more accurate appraisal of whether corrosion control can be economically justified four techniques are used commonly . MEASUREMENT OF CORROSION: measurements are usually made over an extended time because single tests do not provide reliable values of damage. depending on the cause of the corrosion.a specific technique may be more suitable . and operating conditions a combination of techniques will provide the most useful information. . the equipment involved. visual inspection: out of service equipment can be inspected to determine corrosion damage entire equipment can be scanned rather than the local areas . records and descriptions are essential for future reference and comparison. mechanical feelers contact the inside metal surface and detect metal loss due to pitting . or rod wear.caliper survey: surveys are run with wire line to inspect the internal surface of tubing or casing. better detail is obtained with instruments where all infeelers record. metal thinning. such as the Kinley tool . caliper surveys are most useful if they are conducted periodically to determine the progression of pits or area metal loss. . casing inspection log: magnetic flux leakage detection tools are available from a variety of service companies. which is transmitted to the logging truck where it is recorded as a "kick" on a strip chart. such as a pit. and tools have since evolved . principal of magnetic flux leakage was adapted by Shell Development Company for use on a downhole logging device. tools use the distorted magnetic field around an anomaly in the pipe wall. to create a signal in a pick-up coil . pitting is easily missed. erosion corrosion etc. time required for an ultrasonic pulse introduced at one surface to traverse the metal thickness. disadvantage : measures a tiny area of the total surface.ultrasonic thickness tests: use the principle of speed of transmission of a sound wave through a material is a constant characteristic of the material. and return to the detector is measured and converted to metal thickness. useful where erosion. are problems . reflect off the other surface. . metal loss rate tests: most common of all corrosion rate measurement tests.area of coupon . after being exposed to the corrosive fluid for four to six weeks. 00 1 in) . coupon are removed cleaned of all corrosion products without any attack of the metal by cleaning weight loss. corrosion coupons are strips of mild steel. and exposure time used to calculate corrosion rate . which is reported in mils per year (MPY) of metal loss (one mil equals. . corrosion of the pipe may also be negligible. metal of the coupon is seldom identical with metal of the pipe line. corrosion rate of coupon may not be identical with that of the pipe. if corrosion is negligible on installed coupon.corrosion rates through coupons can be inexpensive if the number of coupons used in a system is large and personnel for processing coupons are available. therefore. . coupons must be accurately weighed before exposure .corrosion of the coupon must be prevented while it is stored or being transported to and from the test location grease. oil.coupon preparation: usually by sandblasting and degreasing. or fingerprints on the uncorroded coupon will prevent the coupon from corroding properly when exposed. bridge consists of four resistances.electrical resistance method: instrument measures electrical resistance of an exposed metal sensor and is an adaptation of the Wheatstone bridge. wire or tube of steel etc is exposed to the corrosion environment. changes in resistance as corrosion reduces the cross-section of the probe provide a very precise measure of corrosion rate this technique appreciably reduces total time required to obtain reliable corrosion rate . the probe resistances . small strip. sensitive instrument not easily repaired in the field. somewhat expensive.however. results do not always correlate with results from longer term coupon tests . 2. 3 .Disadvantages of the electric resistance meter to measure corrosion rate are: 1 . the instrument and measurements can be checked easily for accuracy. . . an external current is applied from the auxiliary electrode to the test electrode to change its potential with respect to the reference electrode by 10 to 20 mill volts . applied current is related to metal loss and corrosion rate . meter measures corrosion current but does not measure metal loss from corrosion as the electric resistance meter does.Linear Polarization Resistance Method-(Corrosion Rate Meter).meter uses a two or three-electrode probe that is inserted into the system. Chemical Test for Corrosion Rate: measurement of iron dissolved in produced water stream can indicate a metal-loss rate. . this type of corrosion is usually associated with gas wells and wells producing sweet crude . the test is applicable primarily to CO2 corrosion in which water-soluble ferrous bicarbonate Fe(HC03)2 is the corrosion product. corrosion product must be water soluble. common practice is to supplement iron count data with tubing caliper surveys run in key wells at intervals of one to two years. iron content is measured in parts per million and then converted to iron loss in pounds per day using the water production rate of the test well. the loss may be high and damage small but in pitting corrosion.iron loss rates may not correlate with equipment failures. the loss could be low and damage severe. . with uniform corrosion . Control measures might then be limited to vulnerable places . preliminary study may show that leaks and repairs are confined to certain parts of the system. example. most flow line leaks may occur at road crossings or near tank batteries or wells .Corrosion Records In any production operation. a study of corrosion records can be started at any time if records of purchases and repairs due to corrosion are available. cathodic protection etc. governmental regulations . coatings . ways to minimize corrosion: materials selection. . and environmental considerations . CORROSION CONTROL: usually impossible or too expensive to stop all corrosion. may sometimes be allowed to proceed at an acceptable rate if the projected economic loss from corrosion is less than the cost of corrosion control corrosion control is also influenced by safety aspects. design . engg. expensive alloys are used in sucker rod pumps because other means of corrosion control are not so effective . there are applications where high-priced alloys are more economical than the use of steel.76 .Material selection Metals and Alloys iron and steel are most commonly used in oil field operations because of lower cost. . ease of fabrication and strength.materials used in sucker rod pumps in sour service are categorized for use by the degree of system corrosiveness in NACE Standard MR-O I . embrittlement is not a problem . metals are selected for metal loss control. 17 In carbon dioxide and oxygen environments . NACE Standard RP04-75 lists materials that have been used in aerated and nonaerated salt water handling systems . acceptable metals to resist embrittlement in an H2S environment are shown in NACE Standard MR-O l -75 .when hydrogen sulfide is present. . the effect of hydrogen embrittlement on the strength and durability of a metal is a concern. . (2)use inhibitors. or (6) select metals so that anodic area is large compared to cathodic area. other means of controlling ( 1 ) select metals close together in the galvanic series.simple solution is to use similar metals . (3) use proper coatings.Galvanic corrosion is primarily a metals selection problem. (4) electrically insulate . (5) use cathodic protection. but over-design should be avoided . some of the more prevalent corrosion problems resulting from improper design: . future failures are inadvertently built into system design.Corrosion Control Through Original Design savings in future repair and maintenance are usually possible through proper planning for corrosion .new installation should be designed to last the life of the project. many types of corrosion can be eliminated or minimized by proper engineering design. Crevices cause concentration cell corrosion . 2. Dissimilar metals coupled together cause galvanic corrosion. If it is too high . 3. protective films are eroded. 4.1. solids settle and shelter bacteria. Improper selection of metal may result in sulfide embrittlement.If fluid velocity is too slow . 6. . Air-exclusion equipment is undersized.Poor drainage of lines and equipment may cause concentration-cell corrosion. 5. Trace amounts of oxygen set up concentration cells . 7.Flow lines or gas-gathering lines are either not insulated from the well. Installation of insulating flanges or fiberglass-reinforced plastic nipples should be standard procedure at the wellhead in flow lines and gas-gathering lines.Pump suction conditions may promote cavitation 8. or insulation is not maintained These are only a few examples of corrosion problems resulting from poor design. . immersed in the same electrolyte (salt or acid solution) . will have an electrical potential difference between them. . it is the basic arrangement of the drycell battery . This system is called a galvanic cell.Galvanic Cells and Corrosion-Resistant Metals Two different metals . current will flow from one metal to the other. and. if the two metals are connected together. an extreme example . are "passive" metals. serious pitting of admiralty brass tubes in a cooling system was observed adjacent to steel baffles. .Metals such as magnesium . definite values of the electric potentials are not given because metals and alloys do not have definite and fixed potentials in sea water. or aluminum etc. zinc .are “active" metals such as nickel and monel. 5 Mg. 1 .6 Mn) Steel or iron Cast iron Chromium stainless steel 1 3% Cr (active) . 5 Cu.Galvanic Series of Metal and Alloys in Flowing Sea Water Magnesium and magnesium alloys Zinc Com mercially pure a l u m i n u m ( 1 1 00) Cad m i u m Aluminum 2024 (4. 0. Ni-Resist Cast Iron (high Ni) 1 8-8 stainless steel (active) 1 8-8 Mo stainless steel (active) Lead-tin solders Lead Tin Nickel (active) Inconel (active) Hastelloy B (60 Ni. 6 Fe. 1 Mn) . 30 M o. in cathodic protection through the use of sacrificial anodes including sacrificial metallic coatings . so the galvanic couple causes only a slight increase in the corrosion rate per unit area of the steel . and the steel body is so heavy that it seldom fails. corrosion is transferred from the steel to the more active metal whose only function is to corrode and protect the steel . The relative area of the steel is large. . when in doubt. couplings .Insulating Flanges or Nipples: Insulating flanges . or nipples in a pipe line can be installed and tested during construction at a much lower cost than after the pipe line is in operation. . during construction. insulating flanges or nipples should usually be installed. they can be easily shorted out if not needed . it is not always possible to determine where the insulating joints will be needed. . Materials that will be contacted by wet CO2 or water containing CO2 must be carefully selected Wellhead equipment where water and CO2 are alternately injected are generally constructed of special alloys. Valves and meters are commonly type 316 stainless steel or aluminum bronze .CO2 Enhanced Oil Recovery Projects--Corrosion problems can be so severe that they become the limiting factor in determining whether CO2 injection projects are economical . threaded stainless steel connections should be avoided because of frequent galling problems during makep.Low carbon stainless steel ( 316-L) should be used for welded components to avoid sensitization to rapid corrosion in the heat-affected zone.thick-film epoxy coatings have blistered severely in high pressure CO2 service. thin-film phenolics and epoxy-modified phenolics have given good service in injection well tubing . special precautions are usually taken to separate the CO2 and water injection piping. .continuous inhibitor treatments may be required in the water injection system .bind flanges or removable spools are used to prevent backmixing of CO2 and water in surface piping .Separators and water tanks should be internally coated and have cathodic protection. or holidays. importance of surface preparation. which is the most critical step in any coating application must be stressed . in the coating by sacrificing themselves through galvanic action.Coatings: prevent corrosion by isolating the substrate metal from the corrosive environment. such as galvanizing or zinc-rich paints. have the additional effect of protecting the steel at pinholes. coatings. and (5) ceramic and metallic coatings for smaller parts including those coatings used for purposes other than corrosion resistance e. (3) external pipeline coatings.chrome hard-facing.coatings in production operations can be catagorized as ( 1 ) internal coatings and liners for tubulars. (2) immersion coatings such as used in oil field tanks . (4) atmospheric coatings or paints . .g. threaded and coupled pipe should use couplings that have been coated in the stand-off area with the same material .joint has always been a weak link in corrosion resistance for internally coated pipe . except in the case of paints or where corrosion is rather mild.Coatings are seldom used as the sole method of preventing corrosion. inhibitors and cathodic protection are usually used in combination with coatings to approach 100% protection as closely as economically possible. and other chemical s . 2 . nitrites. waterflood equipment. Inorganic inhibitors .Inhibition with Chemicals: is widely used to reduce corrosion. phosphates . which include a wide variety of high molecular weight compounds. Organic inhibitors . flow lines. Inhibitors control corrosion in tank s . well casing. and gas plants . . arsenic . which include chromates. There are two general types of inhibitors based on chemical composition:1 . tubing . Organic inhibitors have wide application in petroleum production. in high temperature acidizing and in the treatment of steel surfaces in preparation for painting.they provide an effective means for controlling corrosion in gas condensate wells and sour oil wells and in acidizing oil and gas wells .Inorganic inhibitors are used in closed cooling systems . service wells. or it can be created by " slugging" the flow. film efficiency depends on inhibitor concentration and contact time with the metal surface . this type of inhibitor.Most of the effective chemicals used in oil and gas wells.increases resistance to corrosion current . film can be formed and maintained on metal surfaces by continuously adding the inhibitor to a flow stream.and lease equipment are long-chain nitrogen compounds. a film formed on the wall of the pipe or vessel. oxygen causes growth of bacteria.Removal of Corrosive Gases:sourcesof water used in waterflooding contain up to 8 ppm oxygen. which further aggravates corrosion and increases solids content of the water. mixing oxygen-containing water with oil field waters containing either dissolved iron or hydrogen sulfide causes precipitation of iron oxide or iron or iron sulfide . with 1 ppm oxygen. steel or iron corrodes several times as fast as in oxygenfree water. and counter flow gas stripping . The low pressure and the small amount of oxygen in vapor contacting the water causes the dissolved oxygen to bubble out of solution . Chemical Scavengers-Sodium sulfite .Three methods that are economically feasible for the removal of oxygen are chemical scavengers . Vacuum Deaeration-Creating a vacuum in a packed tower and passing water over the packing will reduce the oxygen content in water. vacuum deaeration . ammonium bisulfite . or sulfur dioxide may be added to water to react and remove oxygen. .Gas Stripping-Natural gas in a counter-flow stripping column causes an oxygen-free environment.a packed column or tray-type column can be used. which permits dissolved oxygen to escape from water. tray-type column is preferred where fouling with suspended matter or bacterial slime is a problem this system is usually designed to use not more than two cubic feet of gas per barrel of water being stripped of oxygen . corrosion current stops flowing and corrosion stops.if an outside electrical power source is used to impose a counter current with sufficient voltage to overpower the voltage of the corrosion cell. from pipe into soil. or casing wall into the formation. This technique is called cathodic protection-steel becomes a cathode . tank wall into salt water. .Cathodic Protection :corrosion occurs where electrical currents discharge from metal into an electrolyte . for example . Design of Cathodic Protection:cathodic protection system should be designed so that the output of the anodes will provide the minimum-required current density to all parts of the protected structure . the required current cannot be predicted exactly because the exposed area is not known.on coated structures .in these cases . . the corrosion engineer must use voltage measurements to fix current requirements and the location of anodes or an estimate based on prior experience with similar coated structures. fiberglass reinforced plastics (FRP) are replacing steel in many environments where only steel was available to handle the stresses earlier. although the fiberglass must be used at a lower percentage of ultimate strength than steel. plastic pipe and plastic tanks are frequently used to eliminate corrosion . . fiberglassreinforced polyester sucker rods are available with ultimate strength exceeding that of some steel rods .Nonmetallic Materials: if operating temperatures and pressures allow .