Sub­sea pipe­line cor­ro­sion man­age­ment

DEMM Engineering & Manufacturing - - MAINTENANCE MATTERS -

At off­shore oil and gas fields around the world, there are thou­sands of kilo­me­tres of sub­sea pipe­lines con­nect­ing drilling rigs and pro­duc­tion plat­forms to well­heads and on­shore fa­cil­i­ties. Th­ese rep­re­sent bil­lions of dol­lars of in­vest­ment by com­pa­nies over many years.

Own­ers of th­ese high-value as­sets must un­der­stand the cost im­pli­ca­tions of ig­nor­ing the ef­fects of cor­ro­sion. There are many ad­van­tages of plan­ning for cor­ro­sion con­trol and mit­i­ga­tion, two of which are that the life of an as­set can be ex­tended and main­te­nance time and costs re­duced.

The marine en­vi­ron­ment is a harsh one and pipe­lines are ex­posed to a range of ex­ter­nal phys­i­cal, cli­matic and chem­i­cal ef­fects that can cause cor­ro­sion and degra­da­tion to the out­side of the pipes. Not to men­tion the flu­ids flow­ing through a pipe­line are them­selves cor­ro­sive to the in­side sur­faces.

Mon­i­tor­ing the im­pact of cor­ro­sion on sub­sea pipe­lines and off­shore struc­tures is a crit­i­cal as­pect of en­sur­ing pipe­line in­tegrity. A key way of min­imis­ing cor­ro­sion is to em­ploy ap­pro­pri­ate pro­tec­tion tech­nolo­gies. Com­pa­nies such as Deep­wa­ter Aus­trala­sia (DWA), Car­bo­line and In­de­pen­dent Main­te­nance Ser­vices Pty Ltd (IMS) sup­ply prod­ucts and ser­vices that meet the var­ied chal­lenges of off­shore and deep­wa­ter oil and gas op­er­a­tions around the world.

To en­hance the ef­fec­tive­ness of the work of com­pa­nies like DWA, IMS and Car­bo­line, the Aus­tralasian Cor­ro­sion As­so­ci­a­tion (ACA) works with in­dus­try and academia to re­search all as­pects of cor­ro­sion in or­der to pro­vide an ex­ten­sive knowl­edge base that sup­ports best prac­tice in cor­ro­sion man­age­ment, thereby en­sur­ing all im­pacts of cor­ro­sion are re­spon­si­bly man­aged, the en­vi­ron­ment is pro­tected, pub­lic safety en­hanced and economies im­proved.

Most of the world’s shal­low water oil and gas de­posits have been found. As the de­mand for oil has in­creased, ex­plo­ration com­pa­nies

have been look­ing at reser­voirs in deeper and deeper wa­ters. The cost of float­ing fa­cil­i­ties and plat­forms over deep water reser­voirs is ex­tremely high, so projects with equip­ment lo­cated on the sea floor are be­com­ing com­mon.

Ac­cord­ing to David Flan­ery, Busi­ness De­vel­op­ment Man­ager at DWA, the method of cor­ro­sion pro­tec­tion se­lected de­pends on the ma­te­rial that is used to con­struct off­shore in­fras­truc­ture. Pipe­lines are of­ten epoxy or con­crete en­cased whereas a plat­form usu­ally has large amounts of ex­posed steel. Sub­sea as­sets of­ten re­quire pro­tec­tive sys­tems that in­clude spe­cial coat­ings with a long- du­ra­tion op­er­a­tional life, sac­ri­fi­cial ca­thodic pro­tec­tion sys­tems, or com­bi­na­tions of th­ese.

Ricky Collins, Sales Man­ager Aus­trala­sia at Al­tex Coat­ings, a re­gional Car­bo­line sup­plier, stated man­u­fac­tur­ers have de­vel­oped in­su­lat­ing prod­ucts that have been de­signed to with­stand the rigours of deep­wa­ter op­er­a­tions. The ma­te­rial used in th­ese has been specif­i­cally en­gi­neered for use with sub­sea pipe­lines.

Sur­face coat­ings and other cor­ro­sion preven­tion meth­ods are usu­ally main­tained by com­pa­nies such as IMS. The scope of the work th­ese com­pa­nies carry out on off­shore struc­tures ranges from gen­eral main­te­nance work through sur­face prepa­ra­tion and coat­ing to spot blast­ing and paint­ing.

Ac­cord­ing to Jan Sikora, Op­er­a­tions Man­ager at IMS, all of the work his com­pany does to keep off­shore struc­tures in op­ti­mal con­di­tion is planned proac­tively by the as­set own­ers. “Reg­u­lar in­spec­tions are car­ried out to de­ter­mine the con­di­tion of an off­shore in­stal­la­tion and then the as­set owner plans the sched­ule and scope of works to be car­ried out by us,” he added.

There are a va­ri­ety of meth­ods for se­cur­ing a pipe­line while on the sea bed. The depth of the water above the pipe de­ter­mines whether it must be buried or weighted to keep it in place. In gen­eral, if the water depth is less than 50 me­tres, most coun­tries re­quire that pipe­lines be laid in a trench.

The work­ing and op­er­at­ing en­vi­ron­ment for equip­ment and pipe­lines in the deep ocean are vastly dif­fer­ent to those of coastal ac­tiv­i­ties. The tem­per­a­ture of sea­wa­ter at depths of thou­sands of me­tres drops to around 2°C. Oil from deep wells can be as hot as 176°C. As the hot oil comes up from the well it trav­els through the much colder pipe­line and the fluid in the pipe can quickly cool down. At ap­prox­i­mately 21°C, the water and gas mix­tures in the pipe can form gas hy­drates or paraf­fins. If the build- up of paraf­fins is too great, it can ul­ti­mately block the pipe­line. Such block­ages can be ex­tremely costly to clear and, if a pipe­line rup­tures, can cause cat­a­strophic dam­age to equip­ment and the en­vi­ron­ment.

Sub­sea Flow As­sur­ance is a term used in the off­shore oil and gas in­dus­try to de­scribe pro­cesses that en­sure sub­sea pipe­lines and equip­ment main­tain oil flow. It is there­fore es­sen­tial that ap­pro­pri­ate in­su­lat­ing ma­te­ri­als are ap­plied to in­fras­truc­ture in or­der to main­tain or at least slow down the heat loss from the flu­ids be­ing trans­ported. Man­u­fac­tur­ers of sur­face coat­ings have worked to de­velop suit­able ma­te­ri­als to han­dle the ex­treme con­di­tions of deep water ac­tiv­i­ties.

“An off­shore pro­duc­tion field is a very com­plex sys­tem,” Flan­ery said. “Ide­ally, all the dif­fer­ent com­po­nents and their sep­a­rate cor­ro­sion pro­tec­tion needs should be care­fully planned at the de­sign stage.” For ex­am­ple, oil and gas flows from the reser­voir, through the sub­sea tree and, typ­i­cally, to a man­i­fold or pipe­line end ter­mi­na­tion (PLET) via a jumper pipe. Flu­ids pass along the pipe­lines to a pro­duc­tion plat­form for pro­cess­ing be­fore be­ing sent to a tanker or on­shore fa­cil­ity for fur­ther pro­cess­ing. (A jumper is a short flex­i­ble or rigid length of pipe that is used to con­nect a flow­line to other com­po­nents.)

There can at times be a de­sign gap be­tween the cor­ro­sion pro­tec­tion sys­tems of two ad­ja­cent as­sets, such as a flow­line and a man­i­fold. This can oc­cur be­cause each spe­cial­ist com­pany man­u­fac­tures its spe­cific com­po­nent and dif­fer­ent con­trac­tors lay them on the sea bed. The cor­ro­sion pro­tec­tion sys­tem for each as­set is some­times not com­mu­ni­cated be­tween com­pa­nies and of­ten the op­er­a­tor may not take holis­tic over­sight of the field. “You can­not just look at a pipe­line in iso­la­tion,” Flan­ery said. “It is al­ways part of a much larger sys­tem.”

Typ­i­cal off­shore pipe­lines are com­posed of 12 me­tre lengths of pipe welded end-to- end on a pipe lay ves­sel. Each joint is covered with a fac­tory ap­plied anti- cor­ro­sion coat­ing, ex­cept for ap­prox­i­mately 60 cen­time­tres at each end. Th­ese ar­eas are left bare to pre­vent the heat from welding op­er­a­tions from dam­ag­ing the coat­ing. Once the girth weld is com­pleted be­tween the two joints, an un­coated area of ap­prox­i­mately 1.2 me­tres re­mains. Most pipe­lines are de­signed to use a field ap­plied joint coat­ing, typ­i­cally in the form of a heat shrink­able sleeve.

Ca­thodic Pro­tec­tion (CP) is a tech­nique used to con­trol the cor­ro­sion of a metal sur­face by mak­ing it the cath­ode of an elec­tro­chem­i­cal cell. A sim­ple method of pro­tec­tion con­nects the metal to be pro­tected to a more

eas­ily cor­roded “sac­ri­fi­cial metal” to act as the an­ode. The sac­ri­fi­cial metal then cor­rodes in­stead of the pro­tected metal.

The most com­mon CP sys­tem for pipe­lines uses bracelet an­odes that are clamped onto the pipe­line ap­prox­i­mately ev­ery 10 joints, or 120 me­tres. The an­ode is bonded to the pipe­line via small wires, or bond­ing straps, fas­tened to studs welded di­rectly to the pipe­line.

Reg­u­lar in­spec­tions are a re­quire­ment of any com­pany op­er­at­ing an off­shore field and they must be able to cer­tify that there is no dan­ger of a pipe­line rup­tur­ing. For com­pli­ance, usu­ally the en­tire length of the pipe­line needs to be sur­veyed ev­ery five years.

One method of mon­i­tor­ing a pipe­line’s CP sys­tem is called Elec­trode Field Gra­di­ent (EFG) mea­sure­ment where a Re­motely Op­er­ated Ve­hi­cle (ROV) or diver swims along the en­tire length of a pipe­line to record the field gra­di­ent of the pipe­line’s CP sys­tem. Field gra­di­ent can be used as an in­di­ca­tion of ca­thodic pro­tec­tion ac­tiv­ity. The field gra­di­ent strength is a func­tion of the dis­tance be­tween the ref­er­ence elec­trode ar­ray and the pipe­line. How­ever, all pipe­line sur­veys must in­clude pe­ri­odic “stabs” along its length to re­cal­i­brate the EFG readings.

“While towed or au­tonomous un­der­wa­ter ve­hi­cles can be used, you can­not re­ally tell how good a pipe­line is with­out con­tact­ing it,” Flan­ery added.

One of the lat­est meth­ods for sur­vey­ing pipe­lines is to in­stall CP test sta­tions at a reg­u­lar, cal­cu­lated in­ter­val, sim­i­lar to those for on­shore buried pipe­lines. This en­ables a more rapid and ac­cu­rate pipe­line sur­vey us­ing min­i­mal sur­vey equip­ment aboard a sur­vey ves­sel. An ROV or diver is re­quired to make con­tact readings at th­ese test sta­tions us­ing a spe­cial probe. This method al­lows the sur­vey ves­sel to plan stops along the pipe­line cor­ri­dor and drop a diver or ROV into the water only at those lo­ca­tions. The diver or ROV ‘stabs’ the test sta­tion and this is cor­re­lated with the readings from an EFG probe to de­ter­mine the in­tegrity of the CP sys­tem at that point. Next, a nearby an­ode can be lo­cated and stabbed. Dur­ing both con­tact mea­sure­ments the volt­age gra­di­ent is recorded.

From th­ese readings, the sur­vey crew can use on­board pipe­line CP at­ten­u­a­tion mod­el­ling to de­ter­mine the next ap­pro­pri­ate sur­vey site and re­port on what ac­tions may need to be taken im­me­di­ately or planned to main­tain op­ti­mal op­er­a­tions.

DWA has a range of cor­ro­sion con­trol and mon­i­tor­ing equip­ment that can be quickly de­ployed to site and eas­ily added to a pipe­line to en­hance the ef­fec­tive­ness of the mon­i­tor­ing pro­gram.

Sev­eral deep­wa­ter pipe­line coat­ings are pre­mium-grade, tough, re­silient glass syn­tac­tic polyurethane elas­tomers that pro­vide the re­quired ther­mal insulation prop­er­ties and are 100 per­cent solids ‘cast in place’ ma­te­rial. “The term ‘100 per cent Solids’ im­plies a coat­ing in solid form, but this is mis­lead­ing,” said Al­tex Coat­ings’ Collins. “The term ac­tu­ally means that the coat­ing con­tains no sol­vents or VOCs.” Zero Volatile Or­ganic Com­po­nent ( VOC) coat­ings pose no fire hazard and only low health risk while the coat­ing is be­ing ap­plied. They are also very en­vi­ron­ment friendly as haz­ardous or­ganic sol­vent vapour is not gen­er­ated and re­leased into the air.)

“Syn­tac­tic foams” con­tain the right com­bi­na­tion of resins, pig­ments and glass-spheres to pro­vide the nec­es­sary prop­er­ties to han­dle the en­vi­ron­ment and ap­pli­ca­tion pa­ram­e­ters. Stan­dard light­weight insulation is not suit­able for the deep­wa­ter en­vi­ron­ment. They can­not en­dure long term water ex­po­sure and low tem­per­a­ture, more im­por­tantly due, un­der the ex­treme pres­sures (3000– 6000 psi) at th­ese water depths, most insulation ma­te­ri­als will sim­ply col­lapse and not sur­vive the 25-year life ex­pectancy of the equip­ment.

Collins added “A prod­uct like Car­bo­line’s Car­both­erm 735 will han­dle all th­ese con­di­tions and yet is flex­i­ble enough to tol­er­ate move­ment, bend­ing and vi­bra­tion dur­ing shipment, in­stal­la­tion and op­er­a­tion.”

Work­ing on the struc­tural cross mem­bers of an off­shore plat­form re­quires a unique com­bi­na­tion of skills, but also ad­di­tional safety pre­cau­tions. IMS staff need to be good cor­ro­sion preven­tion technicians as well as pro­fi­cient ab­seil­ers.

“Both of the skills are very im­por­tant in our job and we em­pha­sise that safety is ob­served in all as­pects of our work,” Sikora said. “When we find the right per­son with the ap­pro­pri­ate cor­ro­sion qual­i­fi­ca­tions, we train them in rope ac­cess. To en­sure the safety of our work­ers is not com­pro­mised, we also hire ex­pe­ri­enced Level 3 ab­seil­ers and then train them in cor­ro­sion preven­tion tech­niques.”

Com­pre­hen­sive plan­ning is the pri­or­ity when deal­ing with the con­straints and chal­lenges of off­shore cor­ro­sion con­trol. “Once we get to an off­shore site, if we for­get some­thing it is hard to ar­range de­liv­ery of more ma­te­ri­als or tools,” Sikora added. “You can’t just jump in your van and drive to the lo­cal hard­ware store.”

The weather and ac­cess can also im­pact on work at an off­shore site. There is of­ten lim­ited space for the work­ers and all their equip­ment on an off­shore plat­form and some­times the work­ers must travel on and off the plat­form ev­ery day, which re­stricts the ac­tual work­ing hours avail­able.

For­tu­nately, the lat­est polyurea and polyurethane coat­ings and primers have been de­vel­oped to have rapid cure times so that struc­tures can be covered quickly.

“With an ef­fec­tive pro­tec­tion sys­tem and reg­u­lar main­te­nance, an off­shore field should have an op­er­a­tional life of up to 40 years,” Flan­ery added.




Newspapers in English

Newspapers from New Zealand

© PressReader. All rights reserved.