Corrosion Problems in Oil Industry Need More Attention
18th February 2003Dr A K Samant, Suptdg. Chemist, Mud Services, Assam Asset, Sivasagar, Assam
Corrosion is becoming an increasing threat to the integrity of oil field structures including pipelines, casing and tubing world wide.
Failure of any of these systems could have disastrous consequences and may lead to safety problems both in onshore and offshore. In oil field, if corrosion is left unattended, it may cause failure either due to leaks in pipelines or collapse of well casing and tubing and thus significant losses of the products transported can take place. Plants would have to be shut down plant, contamination of products might take place and pollution and fire are possibilities. Since corrosion can not be eliminated entirely, the aim should be to reduce the corrosion risk to an acceptable level. Condition assessment of oil field installation, therefore, is of great concern not only in India, but all over the world. There is a need for uniform, consistent and reliable guidelines for assessment of health of existing structures, pipelines and well casings. Considering the importance of pipelines and well casings, a brief analysis of both the systems has been carried out. Protection Of PipelinesPipelines are considered as the safest and most economical method of delivering hydrocarbon products from one place to other both in offshore and onshore. However, like all other engineering plants, they are also susceptible to failure due to various reasons. In India, pipeline failures are reported both in onshore and offshore. Three-phase well fluid carrying pipelines, containing both water and corrosive gases such as carbon dioxide and hydrogen sulphide, are particularly susceptible to internal corrosion. When a new pipeline is planned to be installed, its integrity is assured by providing sufficient wall thickness, suitable material and quality control and by adopting suitable corrosion protection system. Pipelines are susceptible to both internal as well as external corrosion. The most common external corrosion protection system for pipelines is corrosion coating and installation of cathodic protection system. To achieve the effective protection, it is necessary to adopt both the above techniques together. For internal corrosion protection, mostly chemicals like corrosion inhibitors are used. However, when pipeline is found contaminated with bacteria, biocides and bactericides are used. Biocides are those chemicals, which kills the bacteria completely, whereas bactericides are chemicals, which suppress the growth of biological activity up to a permissible limit. In Indian offshore as well as onshore, fluid flowing through pipelines, have been found to be contaminated with bacteria. Failure investigation of some of the leaked pipelines showed bacterial induced corrosion as a major factor for pipeline leaks in the Indian offshore and onshore. Some operators are also using internal protective coatings as protective measure. In both the situations, quality of material used and application techniques play important role for complete protection against corrosion. This should be followed by a systematic operation of the line in such a way that they do not deviate from operational requirement specified by codes/standards. Pipelines deterioration can be minimised by periodic monitoring of pipelines using suitable measures like corrosion probes, coupons, fluid analysis and online monitoring loop lines etc. Further, maintenance measure should be both cost effective and prevent failure. Figure 1 & 2 shows diagrammatic representation of a leaking pipeline segment and use of clamp to stop leakage.
Periodic Assessment Of Pipeline ConditionFor the periodic assessment of the lines following techniques should be used: 1. Evaluation of corrosivity of fluid flowing through pipeline by corrosion monitoring probes 2. Monitoring of efficacy of cathodic protection and coating damage assessment 3. Measurement of wall thickness / metal loss in critical areas 4. Condition assessment based on analytical techniques. The purpose of above studies is to identify the most critical segment of the pipeline and detect the damage or defects before they cause serious problems. For prediction of corrosivity of flowing fluids, software is available. These software works based on the fluid parameters and operating data. Analysis of oil associated water and gas for presence of carbon di oxide and hydrogen sulphide gas, sulphate reducing bacteria and acid producing bacteria, bicarbonates and chloride ions, flow velocity, operating pressure and temperature etc. helps in assessing the corrosivity of fluid. Monitoring of efficacy of cathodic protection system and survey for detection of coating damage are performed to assess the external condition of pipeline. As mentioned earlier, pipeline failures are possible and reported, both due to internal as well as external factors. Therefore, both internal as well as external monitoring of pipeline is required for complete health assessment. The monitoring methods may be used in combination for more realistic picture of corrosion in the pipeline. Further following information should be maintained in the form of records before installation and removal of corrosion monitoring devices: 1. Operating pressure and temperature 2. Fluid analysis results like a) Water content and its composition b) CO2 and H2S content c) Number and types of bacteria 3. Flow rate 4. Pigging frequency 5. Corrosion inhibitor and bactericides dose, frequency and injection methods Corrosion control by protective coating supplemented with cathodic protection shall be provided in the initial design based on the study of environment and soil condition along the pipeline route and maintained during the service life of the pipeline system. During construction and initial phase of operations, temporary arrangement should be made to protect the pipeline cathodically. However, the pipeline system shall be permanently protected within a year of pipeline installation. External coating must be properly selected and applied. Coated pipeline shall be carefully handled and installed. Continuous potential logging (CPL) survey, once in five years or whenever inadequate CP is observed, should be carried out Pearson Survey, Direct Current Voltage Gradient (DCVG), Current Attenuation Test (CAT) Surveys to elaborate the coating defects should also be carried as and when required. Isolation of cathodically protected pipeline is recommended to minimise current requirement, facilitate testing and trouble shooting and improve current distribution. When two or more pipelines are laid in the same ROW / ROU periodical interference survey shall be conducted and suitable mitigating measures to be taken to avoid interference between the lines. Where stray current is known to exist which adversely affects the level of CP of the pipeline, additional monitoring should be carried out on monthly basis. Underground pipelines are generally routed under roads and railways in steel casings. Wherever these are essential, casing pipes should be electrically isolated from the carrier pipes by providing isolating spacers. The isolating spacers should be designed and spaced to withstand the loads caused by the movement of the carrier pipe under operational conditions. Periodic Pigging Of PipelinePigging should not only be used to remove scales and wax from internal pipe wall but effort should be to remove bacterial colonies, corrosion deposits by using suitable scrapers, and to facilitate the corrosion inhibitor film formation, thereby to reduce under deposit corrosion. Chemical injection in conjunction with pigging programme offers an efficient and cost effective technique to control internal corrosion in pipelines that carry oil with high water percentage and low flow velocities. Intelligent Pigging For Safe Operation Of PipelineIntelligent or smart pigs can detects and measure the pipe wall defects such as corrosion, weld defects and cracks. The use of intelligent pigs for inspection of pipelines has increased considerably. The most commonly used intelligent pigs use magnetic flux leakage (MFL) technique to detect corrosion pits and planar and axially oriented cracks. However, advance MFL based intelligent pig has been used to detect circumferentially oriented cracks in both oil and gas pipelines. Ultra sonic based intelligent pigs require a liquid coupling between transducers and the pipe wall and therefore restricts their use in gas lines unless they are run in a slug of liquid or the coupling has been attached by some means. The primary use of the results from an inline inspection using intelligent or smart pigging is not restricted to find out the health of the pipeline, but to calculate the maximum allowable operating pressure (MAOP) at which the pipeline can still safely be operated. Protection Of Well Casing & TubingConditions such as poor cementing, large variations in the casings metallic composition, fluid salinities, dissolved corrosive gases, etc. have been recognized as corrosion promoters in well casing and tubing. Downhole corrosion monitoring, to evaluate both - the extent of metal losses and the corrosion rate, is vital as corrosion initiation and propagation can not be predicted from theoretical estimates. Drill pipes are subjected to corrosion in the hole, standing in the rig, laying on the rack or during movement of location. Down hole corrosion is more detrimental, as it occurs in conjunction with cyclic loading. Large number of corrosion cells are formed on drill pipe and well casing surface due to material inhomogeniety and because of the presence of deposits or scales. Further, local corrosion may also be occurred due to formation of concentration cells causing pitting. Because of the presence of hydrogen sulphide and dissolved salts, corrosion fatigue and stress corrosion cracking are a major cause of drill pipe failures. Sulfide stress corrosion cracking is most common in presence of hydrogen sulfide and when the stress in the drill pipe and casing is higher. Corrosion inhibitors and biocides are used to control the corrosion and bacterial growth, but there is no assurance that they will do so, since a packer fluid remains in place until it is necessary to do remedial work on the well, which may not be for years. Therefore, leaving a water base drilling mud / brine in the hole as a packer fluid may result in development of casing or tubing leaks in the course of time. Similarly, on external surface of casing, generation of hydrogen sulphide by bacteria and high concentration of sulfates results in deterioration of cement. Corrosive fluid, water, microorganisms etc. penetrates the poor permeable cement and then able to attack the external casing metal resulting in leakage. Once leaks have started, corrosive water enters the well and can attack the casing wall. In Indian Offshore, well casing corrosion is a matter of serious concern. Some of the wells were cased more than two decades ago. Well casing survey of these wells is the prime concern. The some of the tools employed for well casing and tubing corrosion survey are Casing Inspection Tool (CIT), Multi-frequency Electromagnetic Thickness Tool (METT), Digital Cement Evaluation Tool (CET-D) & Corrosion and Protective Evaluation Tool (CPET). NACE standard RP-01-86 describes four methods or criteria for designing and evaluating cathodic protection systems for well casings. They are downhole potential profile surveys, E/Log i polarisation curves, mathematecal modelling combined with the measured wellhead potential, and average current density over the casing. Each technique has its advantages and disadvantages. None of the techniques gives direct information in polarisation of the casing surface at depth. Potential profile survey is the only technique in which the flow of protection current at depth can be confirmed. Downhole potential profile measurements have been used for a number of years in evaluating and optimising well casing cathodic protection. Recent advances in instrumentation have enabled high-resolution potential difference and casing resistance measurements to be recorded. As a consequence, current and current density profiles are free of the ambiguities present in earlier measurements. ConclusionCorrosion control is an important consideration. The periodic monitoring techniques and analytical assessment of corrosion severity is very important and critical since it provides the direction to ensure proper utilisation of materials and corrosion control methodologies. Therefore, correct and appropriate condition assessment techniques should be used to avoid premature failure and ensure maximum safety. Contact The Author: email@example.com, firstname.lastname@example.org
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(WO/1998/006552) PROTECTION OF PIPELINE JOINT CONNECTIONS
Note: OCR Text
Note: Text based on automatic OpticalCharacter Recognition processes. Pleaseuse the PDF version for legal matters
PROTECTION OF PIPELINE JOINT CONNECTIONS This invention relates to pipeline joint protection. More specifically, the invention provides a method and an apparatus for protecting exposed pipe joints on weight coated pipelines used in offshore applications. It has been a common practice in the offshore pipeline industry to use weight coated pipe for pipelines which were to be located on ocean floors or other underwater surfaces. The weight coats traditionally used have been made of dense materials, frequently concrete, applied several inches thick around the circumference of the pipe. The weight coats were to protect the pipeline and also to provide sufficient weight to maintain the pipeline submerged in a non-buoyant condition.
The weight coats usually have been applied to the full length of the pipe except for a short distance, usually about one foot from the end of each pipe section. The end portion of the pipe remained without the weight coat to facilitate welding sections of the weight coated pipe together to make up the pipeline. Sections of pipe have been placed on a barge and welded sequentially onto preceding sections forming a pipeline extending from the barge. The newly formed pipeline was on rollers and as the barge moved forward, the pipeline would be carried over the rollers, lowered, and laid on the bed of the body of water.
The portions of the pipe without the weight coat had a corrosion coating applied to the surface of the pipe to prevent the pipe from corroding due to exposure to the elements. Generally, the corrosion coatings used were heat shrinking tape or a fusion bonded epoxy. After the sections of pipe were welded together various techniques were used to protect the corrosion coating on the exposed portions of pipe around each joint.
One technique was to wrap sheet metal over the weight coating adjacent the exposed portion of the pipe and band the sheet metal in place with metal bands. Generally, a 26 to 28 gauge zinc coated sheet metal was used. The space between the pipe and sheet metal was then filled with a molten mastic which would solidify as it cooled. However, in most cases, the pipeline had to be in a condition for handling immediately after the sleeves were filled so that the laying of the pipeline could proceed without delays. The mastic filling did not set or harden to a sufficiently strong material within the required
-->time to allow further processing of the pipe and the mastic would leech out into the water if the pipeline was lowered before the mastic was adequately cured.
An additional problem associated with this technique was that the banding used to hold the sheet metal in place, as well as the sheet metal itself, would corrode after the pipejoint was underwater for a period of time. Once the banding corroded, the sharp ends of the sheet metal would come loose from the pipe. This created a particular problem in areas where commercial fishing was taking place. The sharp sheet metal ends would cut fishing nets which were being dragged over the pipeline by fishing trawlers. The destruction of fishing nets by the loose sheet metal created severe financial problems for fishing industries. In some cases, corrosion resistance banding, such as stainless steel banding, was used to avoid this problem, but it was more expensive and also subject to eventual failure.
Other techniques replaced the mastic filler with other types of materials. In the method disclosed in U.S. Patent No. 5,328,648, the exposed portion of pipe was covered with a mold which was then filled with a filler material. The filler materials were granular or paniculate matter such as gravel or iron ore which would not pack solidly or uniformly. Elastomeric polyurethanes or polyureas were then injected into the mold in an attempt to fill the interstices between the granular fill materials. After the polymer components had reacted completely the mold would be removed from the surface of the infill. This method could be difficult to use when the joint protection system was applied aboard the lay barge because the filler material, often gravel, had to be loaded and carried onto the barge. Additionally, there was often a lack of uniformity in the finished infill resulting from uneven polymer distribution in the filler material which created voids. Such voids could leave the corrosion coating exposed and subject to damage from fishing trawler nets or other objects moving through the water which might encounter the submerged pipeline.
Another technique, disclosed in U.S. Patent 4,909,669, involved wrapping the exposed portions of pipe with a thermoplastic sheet. The sheet overlapped the ends of the weight coat adjacent the exposed joint and was then secured in place by screws, rivets, or straps. To increase the rigidity and impact resistance this joint protection system required the installation of reinforcing members such as plastic bars or tubes to the interior of the
-->sheet. The reinforcement bars or tubes either had to be precut and stored on the barge or else cut to the required fitting form as part of the installation process on the barge. This required additional handling and made the installation process more difficult.
Another method of reinforcing this joint protection system was to fill the lower portion of the annular space between the pipe and the plastic sheet with a material such as pre-formed foam half shells. When foam half shells were used in the lower portion of the annular space to provide support, the upper portion of the joint and the corrosion coating was in effect protected only by the plastic sheet enclosing the upper portion which had no foam covering. This could cause a particular problem if the pipelines were located where they would encounter the drag lines or trawler boards attached to the nets of fishing trawlers. The corrosion coating on the upper portion of the pipe joint could become damaged by this type of towed object.
An additional problem with this joint protection system occurred when pipelines were laid in shallow waters, i.e., less than about 200 feet deep. Pipelines in shallow waters were often buried by using high pressure water jets which were directed at the ocean floor where the pipelines were to be buried. The water jets would wash out a trench into which the pipelines would be dropped for burial. The joint protection system could be damaged when the water jets came in contact with the pipeline joint because the plastic sheet over the top of the pipejoint was not reinforced. The present invention provides a method and an apparatus for mechanically protecting exposed pipeline joint sections. The method allows quick installation on lay barges where pipeline sections are welded together and does not require a long cure time before handling. The method for protecting exposed pipeline joint sections begins by foπning a pliable sheet of cover material into a cylinder which is fitted over the exposed portions of the joint connection. The longitudinal end portions of the pliable sheet of cover material overlap the adjacent edges of the weight coating. Side edge portions of the sheet of cover material forming the cylinder are then overlapped tightly such that an annular pocket is formed about the exposed joint section. The outside side edge is then sealed to the surface of the sheet of cover material, completely encasing the exposed pipe and the annular pocket or space. Polyurethane chemicals are then injected into the empty annular space where they react to form a high density foam which fills the annular space.
-->Other polymerizing or hard setting fluid compounds such as marine mastics, quick setting concretes, polymers, or elastomeric compounds may also be used to fill the empty annular space.
The present invention provides the joint section of an underwater pipeline with mechanical protection and abrasion resistance that is not subject to corrosion problems, will not damage fishing nets, and will not be damaged by water jets used for pipeline burial.
A better understanding of the invention can be obtained when the detail description set forth below is reviewed in conjunction with the accompanying drawings, in which: Figure 1 is a depiction of two sections of weight coated pipe which have been joined by welding;
Figure 2 is a pliable sheet of cover material formed in a cylinder which is used to enclose the exposed joint section;
Figure 3 is a longitudinal view, showing the pliable sheet of cover material wrapped and sealed around the exposed joint section;
Figure 4 is a longitudinal cross section showing the joint section after the joint protection system has been applied.
Fig. 1 shows a pipeline 10 formed by welding together two pipe sections 12 & 12A each of which are covered by a weight coat 14 & 14 A, respectively. The weight coat 14 & 14A, which is formed from concrete or other suitable materials, completely covers the pipe sections 16 & 16A circumferentially and longitudinally except for a portion of each pipe end 18 & 18A of the pipe section 16 & 16A. The pipe ends 18 & 18A are left exposed to facilitate welding of the two pipe sections 12 & 12A together as sections of a pipeline. However, these exposed pipe ends 18 & 18A leave gaps of pipe not coated with weight coat in the pipeline 10, which are covered only by a corrosion coating 24.
The method of the present invention begins with installing a cover material 30 which is used to enclose and provide structural protection for the exposed corrosion coating 24 on the pipe end 18 & 18 A. As shown in Fig. 2, the preferred method uses a cover material 30 which is pliable, but strong, and can be formed into a cylindrical shape. The preferred cover material 30 is formed from high density polyethylene, however, other thermoplastic materials may be used. The pliable cover material 30 should be at least
-->about 0.02 inches thick and may be considerably thicker if a stronger support and impact resistance is desired. Water depth, pipe size, pipe weight and other factors may dictate the use of a cover material 30 which is up to about 1/2 inch in thickness. The cover material 30 may be a flat sheet or may be preformed into a cylindrical shape. The pliable sheet of cover material 30 is wrapped into a cylindrical shape around the exposed pipe ends 18 & 18A such that the inside diameter of the cylinder of cover material 30 is about the same as the outside diameter of the weight coat 14 & 14A on the pipeline 10. The cover material 30 should be long enough to overlap the adjacent edges 22 & 22 A of both sides of the weight coating 14 & 14A by several inches to allow the weight coating 14 & 14A to act as a structural support for the cover material 30. Once the cover material 30 is fitted over the adjacent edges 22 & 22A of the weight coat 14 & 14A, the side edges 34 and 36 of cover material 30 are tightly pushed together such that the side edges 34 & 36 overlap. The cover material 30 can be tightened down and held in place with cinch belts. The outside edge 34 is then sealed to the surface of the cover material 30 and a sealed sleeve 40 is formed.
The cover material 30 can be sealed by plastic welding the outside edge 34 onto the surface of the cover material 30, forming a longitudinally extending plastic weld the entire length of the cover material 30 as shown in Fig 3. Other means of sealing such as heat fusion, riveting, gluing, taping, or banding can also be used to seal the cover material 30.
The sealed cover material sleeve 40 forms a protective barrier around the exposed portion of pipe 18 & 18A which remains as a permanent part of the pipeline 10. An annular space 44 is formed around the pipe 18 & 18A by installing the cover material sleeve 40. This annular space 44 is filled by first cutting a hole 38 in the sealed cover material sleeve 40 and thereafter injecting fluid joint filler system components through the hole 38 and into the annular space 44.
The hole 38 may be drilled or cut or otherwise made in the sealed cover material sleeve 40 to thereafter allow unreacted joint filler system components to be injected into the annular space 44. The hole 38 may be precut into the cover material 30 prior to installation on the weight coated pipeline 10 or may be cut after the sealed cover material sleeve 40 is in place. The diameter of the hole 38 to be drilled is dependent upon the
-->particular type of mixing head used to inject the joint filler system components. Industry standard or conventional injection heads are acceptable.
In the preferred method, the annular space 44 is filled with a high density foam by injecting components for a rapid setting polyurethane system through the hole 38 with a mixing head. The polyurethane foam 52 serves as a shock absorber and protects the corrosion coating on the pipe 18 & 18A. Also, because the foam 52 is open celled, it can absorb water and increase the ballast effect for the pipeline 10. Alternatively, other polymerizing or hard setting compounds such as marine mastics, quick setting concretes, polymers, or elastomeric compounds may be used to fill the empty annular space. Preferably, any alternative filler material is quick hardening, such that the process of laying the pipeline is not inhibited.
The preferred polyurethane system used to form the protective high density foam 52 in this process is a combination of a isocyanate and a polyol system which when reacted rapidly cures and forms high density open celled polyurethane foam which resists degradation in sea water. The preferred isocyanate is a polymeric form of diphenylmethane diisocyanate as manufactured by Bayer Corp. The preferred polyol system is a mixture of multifunctional polyether and/or polyester polyols, catalysts for controlling the reaction rate, surfactants for enhancing cell formation, and water for a blowing agent. Acceptable blended polyol system are manufactured by Dow Chemical Co., Bayer Corp., and others.
The preferred polyurethane system produces a foam with a density of about 8 to 10 pounds per cubic foot and has about eighty percent or greater open cells. The compressive strength of the preferred polyurethane foam is approximately 150 psi or greater at 10 percent deflection and 1500 psi or greater at 90 percent deflection. Reaction of the preferred polyurethane system components can be characterized by a 15 to 20 second cream time, the time between discharge from the mixing head and the beginning of the foam rise, a 40 to 50 second rise time, the time between discharge from the mixing head and the complete foam rise, and a 180 to 240 second cure time, the time required to develop the polymer strength and dimensional stability. The cover material sleeve 40 acts as a mold and holds the foam 52 in place until it is completely cured. As shown in Figure 4, this polyurethane foam 52 completely fills
-->the annular space 44 without leaving significant void areas. No additional filler materials are needed to be used in conjunction with the polyurethane foam 52. The polyurethane foam 52 should completely fill the annular space 44 and protrude to some extent upward through the hole 38 on the sealed cover material sleeve 40. Fig. 4 shows the completed protective covering of the joint protection system according to the present invention. The sealed cover material sleeve 40 together with the polyurethane foam 52 provide a protective system which protects the exposed pipe 18 & 18A and the corrosion coating 24 during handling and laying of d e pipeline 10 and continues to provide protection from damage due to drag lines or trawler boards attached to fishing trawler nets. Further, the sealed cover material sleeve 40 is not subject to the corrosion problems of prior art systems and therefore does not create a underwater hazard or a danger to fishing nets. Additionally, die protective system provided by the present invention acts to deflect the high pressure water jets used to bury pipelines in shallow waters which have resulted in damage to the corrosion coating on pipe joints protected by prior art systems.
From the foregoing, it can be seen that the present invention provides a method and apparatus for protecting the corrosion coating 24 on exposed pipeline joints such as 12 & 12A on weight coated pipelines 10 used in offshore applications. The method allows quick installation on a lay barge where pipeline sections are being welded together for offshore installation. The corrosion coating 24 on the pipeline joint connections 18 & 18A which have no weight coating is protected by forming a pliable sheet of polyethylene into a cylindrical cover material sleeve 40 over the pipeline joint connection. Polyurethane chemicals are used to react and form a high density foam 52 which fills the annular space 44 between the pipe 18 & 18A and the cover material sleeve 40. The cover material sleeve 40 and the foam 52 work together to protect the joint connection.
It should be understood that there can be improvements and modifications made of the embodiments of the invention described in detail above without departing from the spirit or scope of the invention as set forth in the accompanying claims.
CATHODIC PROTECTION OF SUB SEA PIPELINES