INTERNAL CORROSION OF PETROLEUM PIPELINES Saher Shawki

Transcription

1 Saher Shawki INTRODUCTION Petroleum pipelines carrying oil, gas or petroleum products are not immune of corrosion although hydrocarbon fluids by itself are not corrosive. However, the presence of corrosive constituents such as water, salts CO 2, H 2 S or even abrasive material (sand) contribute largely for internal corrosion. Failure due to internal corrosion was recorded in petroleum pipelines for production and transportation. The failure cases are very diverse in nature due to a great number of reasons ranging from the design stage, including material selection, to basic requirements of operation, testing and maintenance (Bazzoni et al., 1989; Donham, 1987). In this paper detailed scheme of analysis is provided for two failure cases due to corrosion regarding pipeline material selection, structural engineering and operational management, referring to R&D and consulting experience. In some cases more than one reason contribute to the failure. The first case represents a typical case of core pipeline corrosion in deep well with fluids containing high levels of CO 2, water and sand. The second case was diagnosed as a result of wrong construction design of the above ground pipeline routing and negligence of treatment operation. CASE I: INTERNAL CORROSION of 3.5 CORE TUBES PIPELINE Service History An oil field faced significant corrosion problems occurred and appeared in The field is located in North Delta region, Egypt and started production in Two core petroleum pipelines of wells # 1 and # 4 with multi-phase flow (gas/condensate/water) suffered catastrophic pitting corrosion problems. Several samples of the corroded pipes from the two wells were subject of failure analysis (Fig 1). Pipeline and Fluid Details The following are the data of the pipe material and the fluid characteristics of the two wells (almost identical). Fluid composition gas/condensate/water Pressure (psi) start 4700 present 2150 CO 2 partial pressure start 37 present 19.5 (bar) Flow velocity (ft/sec) N/A Water content (%) ~ 45% Oil/ Condensate content ~ 55% (%) Sand content High Temperature ( o C) o C H 2 S partial pressure None ph value 6.5 Depth of inspected pipe 1240 (m) Pipe dimensions φ3. 5 ' t 8 mm Pipe material Carbon steel API grade L-80 Visual Examination of the Failed Pipes Figure 2 shows that the internal surfaces of the pipes were severely damaged. The damage is manifested Journal of Engineering and Technology 112

2 by a large number of deep pits; many of them are opened to the outer surface. Deep longitudinal grooving (with pitting) is also apparent. The surface is covered by carbonate/oxide iron deposits. Corrosion attack is clear on the tube internal surface as well as the jointing screws. Fig. 2: (a) Internal surface of the corroded tube showing grooving, deep ting and open pits. (b) Close-up of the internal corroded surfaces. Presumed Causes of Failure Corrosion of carbon steel pipes for multi-phase production (gas/condensate/water) is a major problem facing many hydrocarbon production wells all over the world. The most common material loss is caused by CO 2 partial pressure. The corrosion is influenced by a number of parameters such as: temperture, flow velocity, ph value, and water wetting and to a lesser exent: metal composition and microsturcture, H 2 S partial pressure, oxygen entry, and scaling index (for carbonate). It is well known that the CO 2 gas dissolves in water to form carbonic acid which lowers the ph value and reacts with iron forming iron carbonate which deposite on the pipewall (Waard and Milliams, 1975). The carbonate film is porous and can be removed mechanically by the stream velocity, exposing fresh iron surface to be attacked. The data shown in the above table are considered very hostile environment to be in contact with the internal surface of the pipes. It should be noted that corrosion in industrial system and particulary in such condition is never uniform. Locacalized corrosion by pitting or crater formation is most feared in practice and that what happened in the case under investigation. It is estimated in the present case that penetration (opened pits or total material loss) is as high as 3 8 mm/yr. Localized corrosion once started will accelerate by forming galvanic corrosion between severaly attacked and less attacked or protected areas. Deposits and scales of iron oxide or cabonate temperarely protect some areas of the surface. It is assumed that most of the corrosion damage and material loss occured in the first year of operation; when the CO 2 partial pressure was at its highiest level as shown above. Conclusions and Recommendations The fluid characterstics given for the wells are very aggressive specially CO 2 partial pressure, flow velocity, water content and sand. The failure of the core pipes is due to severe corrosion attack estimated to be 3 8 mm/yr, which nessitates replacement of the pipelines. Pipeline material is not suitable to combate the aggressive condition of the well fluid. It is only good for its mechanical Journal of Engineering and Technology 113

3 properties to withstand the operating pressure. It is recommended to use another grade of steel that contain chromuim content higher than 3% (compared to 0.23% of the failed steel). Some economic estimates suggest the use of stainless steel in replacement of carbon-steel. The final costs are rather the same when extending the life time of the pipeline by at least 5 folds (Celant et al., 1989; Dugstad et al., 1994). It is useless to use inhibitors to reduce corrosion, since high flow rate will wash out any inhibitor film formed adhering to the surface. CASE II: FAILURE OF CRUDE OIL SHIPPING PIPELINE Background Crude oil is transported from a field in Eastern Desert/ Egypt, through buried 10 pipeline (for~90 km) to a treatment plant for water and salt separation. The treated oil is then pumped through 18 bare pipeline extending 7 km above ground to join the main 10 pipeline (10 km) to the shipping station at the Red Sea. The 18 pipeline junction failed due to internal corrosion. Figure 3 shows a sketch of the pipeline network involving the failed section. Although this section is bare, no signs of surface corrosion were noted over 25 years in a clean desert atmosphere. Fig. 3: Sketch of the pipeline network (not to scale) Along the 7 km train, the pipes lie directly on the ground according to its natural topography of elevations and depressions (Fig. 4) without any pipelevel supports. Fig. 4: Sketch of 18 pipeline train showing some depressions. Frame showing some pipes not resting completely on the ground The pipeline data and operating history are as follows: Pipe material: grade API- X42 thickness 7.3 mm longitudinal seam welded Crude oil Characteristics: water content 5 %, Sulfur 4.5%, ph value 6-6.5, temperature 45 o C. Operation: pressure 14 bar. Journal of Engineering and Technology 114

4 plant was separate periods of during the last pipeline failure. History: The treated shutdown for two 9 and then 6 months two years before The Incident: Indication of a trouble was signaled by pressure drop and oil quantity shortage at the shipping station. The pipeline track was surveyed and spelled oil was found in one of the train depressions. One pipe was found ruptured open to a perfect longitudinal line extending to about 2 meters along the seam welding line, with slight bulging in the middle of the opening (Fig. 5). Huge amounts of crude oil were spilled due to the failure estimated by 10,000 barrels. The opening was in the position 6 O clock in contact with the ground. Field Inspection Ultrasonic wall thickness measurements indicated that all 12 O clock thickness measurements were mm; while 6 O clock thickness measurements (ground contact) were mm. Rusting of the outer surface of the pipe is very light due to dry desert atmosphere. Some corrosion scales was observed in places where the pipes are in contact with the ground, however loss of material is rather mild. The seam welding line is occasionally in direct contact or near ground. Diagnostic Investigation Visual examination of the failed pipe showed thick lip rupture. Large amounts of solid debris and waxes were found accumulated in all three removed pipes at 6 O clock position. Average wall thickness measurements in different locations on two of the removed pipes are shown in Fig. 6. Fig. 6: Wall thickness measuring point & position of cut piece for lab investigation Fig.5: Photos of opened pipe along the seam weld. Action taken by the petroleum company: About 500 barrels of the spilled oil were recovered by pumping out from the ditch in the sand around the failure location. Three pipes (each 12 m) were cut (failed pipe in the middle) and replaced by new ones to reoperate the line. For laboratory investigation: A piece (4 х 10 cm) was cut at one end of the failed pipe along the Journal of Engineering and Technology 115

5 rupture line. Figure 5 shows the inside surface after light cleaning with organic solvents. Severe pitting is clear. Loss of metal due to corrosion discloses lack of penetration of seam welding during pipe fabrication. The constituted a V groove with one edge more corroding than the other. In the root of the V groove a crack was found at higher magnification full of light brown oxide deposits (Fig. 7 c ). Fig.7: Cut piece showing (a) severe pitting corrosion (b) close-up of corrosion around seam welding groove. (c) Electron micrograph of the V groove with oxide deposits at the root. of stagnant conditions which lasted for 9 and 6 months respectively which provide ideal condition for pitting initiation. -Most important consideration for the failure is the weld imperfection. Unfortunately the seam line of the particular pipe was situated at 6 O clock position, i.e. the bottom of the pipe. This position is perfect for water gathering added to it a lower part of the infused weld groove. In terms of corrosion this creates crevice corrosion which deepens the attack and may lead to metal crating at the root of the V groove. - Hydrogen ions are generated by reaction of steel with a sour environment; the ions undulate at voids e.g. V groove and form hydrogen gas. Internal pressure and residual mechanical stresses can eventually cause hydrogen induced cracking (HCl) in the steel. -Pits are nucleation sites of stress corrosion cracking (SCC) in sour oil. Occurrence of pitting enhances the stress at the pit bottom and the root of the V groove. -The superimposed stress due to mechanical positioning of the pipe in the field and the added 14 bar pressure of the fluid contribute to the progress of the crack(azevedo,2007). Failure Analysis: -Severe internal pitting corrosion of the steel in the 6 o clock position after 25 years of service. This is a result of water separated from the crude sour oil (PH 6-6.5) gathered particularly in topographic depression at the failure site. Adds to this 2 periods When the thickness at the base of the crack / crevice reach 70% of specified minimum yield strength of the pipe internal, the metal rupture and the crack is opened with bulging shown in Fig 5. Moreover the crack will extend on both sides of the opening along the weld (seam) line. Opening will stop just due to the release of the fluid pressure. CONCLUSIONS AND RECOMMENDATIONS Failure occurred in one badly fabricated seam welded pipe. Internal pitting corrosion, due to sour Journal of Engineering and Technology 116

6 oil, during 25 years of service was a trigger of cracking in the infused weld grooves which ended to complete rupture of the pipe. Two other factors contributed to the failure; (a) positioning of the weld (seam) line at the bottom (6 o clock position where water can best accumulate, and (b) stagnant long shut down periods. We can t ignore the possible malfunction of the treatment plant with respect to water and salt content in the treated oil. In short, this section of the line is already damaged internally. Further rupture cases of the pipes were anticipated. To keep the extent of damage same as at the time of rupture and to avoid further deterioration, a number of actions was recommended to the oil company. As an immediate action: leveling of the pipes at the low laying areas should be carried out using concrete or sand bags as supports. For further action: any pipe having the seam weld line in the 6 Oclock position should be accurately inspected for the remaining wall thickness. Decision is up to the operators, to cut and remove the pipe if the thickness is critical or wait for complete rupture. Costs will govern the decision in either case. General Conclusions Internal corrosion of petroleum pipelines is very serious as far as its impact on the economy, environment and safety of operation. Cases displayed in this paper, although classical, confirmed that there is no one reason that contributes to a specific failure. Failure due to internal corrosion is so diverse and covers all stages of pipeline industry starting by material selection (represented by Case I), construction design and operation (for Case II) up to inspection and monitoring. A common factor that can be noted as most effective in several corrosion failure is the inadequate structural design of the pipelines including material selection. Economic consideration should not be confined to the cost constraints but should target safe operation as priority, and aim to extend the project life time of the pipeline to the designed period. REFERENCES Azevedo, C. R. F. (2007). Failure Analysis of a Crude Oil Pipeline, Engineering Failure Analysis, 14, pp Bazzoni, B. et al. (1989). "Criteria for Internal Corrosion Evaluation and Material Selection in Oil & Gas Industry ", Engineering Solutions for Corrosion in Oil and Gas Applications, NACE Conference, Milan, paper No. 12. Celant, M., Cheldi, T. and Condanni, D. (1989). "Controlling Corrosion in Deep Hot, Sour Wells for Oil Production" Engineering Solutions for Corrosion in Oil and Gas Applications, NACE Conference, Milan, paper No. 9. Donham, J.E. (1987). Corrosion in Petroleum Production Operations, Metals Handbook, 9th Ed. ASM International, vol. 13, Corrosion, p Waard, C.de and Milliams, D.E. (1975) "Carbonic Acid Corrosion of Steel", Corrosion 31, 5, pp Dugstad, A., Lunde, L. and Nesic, S. (1994) Control of Internal Corrosion in Multiphase Oil and Gas Pipelines, Proceedings of Conference, Prevention of Pipeline Corrosion, Houston, USA. Journal of Engineering and Technology 117