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The pipeline system that conveys the individual-well production or that of a group of wells from a central facility to a central system or terminal location is a gathering pipeline. Generally, the gathering pipeline system is a series of pipelines that flow from the well production facilities in a producing field to a gathering “trunk” pipeline.
Gathering systems typically fall into one of four categories:
- Single-trunk systems with “lateral” lines from each well production facility.
- Loop systems, in which the main line is in the shape of a loop around the field.
- The multiple-trunk system, in which there are several main lines extending from a central point.
- Combinations of Categories 1 through 3.
Selection of the most desirable layout requires an economic study, which considers many variables, such as:
- The type of reservoir
- The shape of the reservoir
- The way in which the land over the reservoir is being used
- The available and permissible flow rate
- The flowing and shut-in pressure and temperature
- The climate and topography of the location
- The primary destination of the oil or gas
Gathering systems typically require small-diameter pipe that runs over relatively short distances. The branch lateral lines commonly are 2 to 8 in. Gathering systems should be designed to minimize pressure drop without having to use large-diameter pipe or require mechanical pressure-elevation equipment (pumps for liquid and compressors for gas) to move the fluid volume. For natural-gas gathering lines, the Weymouth equation can be used to size the pipe.
“Cross-country” transmission pipelines will collect the product from many “supply” sources and “deliver” to one or more end users. There are three general categories of transmission pipelines:
- Natural gas- Carry only natural gas
- Carry a number of processed or refined petroleum products such as:
- Processed natural gas liquids- butane and propane
- Refined fuel oils
Convey unrefined crude oil from producing areas to large storage areas or directly to refineries
Transmission pipelines will generally require much larger pipe than gathering systems. Transmission systems normally are designed for long distances and will require pressure-boosting equipment along the route.
Many factors must be considered when designing, building, and operating a pipeline system. Once the basic pipe ID is determined using the applicable flow formula, the other significant design parameters must be addressed.
For U.S. applications, gathering, transmission and distribution pipelines are governed by regulations and laws that are nationally administered by the U.S. Dept. of Transportation (DOT). The regulations are contained in the Code of Federal Regulations (CFR) Title 49:
- Part 190 Enforcement Procedures
- Parts 191 and 192 Natural Gas Pipelines
- Part 193 Liquefied Natural Gas Pipelines
- Part 194 Oil Pipelines Response Plans
- Part 195 Hazardous Liquid Pipelines (e.g., crude oil and products)
- Part 198 State Grants
- Part 199 Drug Testing
The regulations incorporate the industry codes, guidelines, and standards including ANSI/ASME B31.4, B31.8, and others.
Internationally, many countries have adopted the U.S. regulations and the industry codes, guidelines, and standards. Some countries have different requirements, laws, and regulations, and each should be consulted prior to designing and building a pipeline. For the most part, these regulations are similar to those in the U.S., and, thus, the comments that follow, based on U.S. standards, are generally true in other countries as well. Even pipelines not specially covered by the regulations should be designed, constructed, and operated according to industry codes, guidelines, and standards, as these are based on sound engineering and operating experience.
Pipe selection and wall thickness
The type of pipe and wall thickness must be determined for each application. Following the design requirements of Part 192 for natural gas, Part 193 for liquefied natural gas (LNG), and Part 195 for crude-oil and products pipelines, the pipe materials and wall thickness can be determined using the applicable formula. As discussed in the page on pressure drop calculations in piping and pipeline systems, the wall thickness will be determined by:
- The operating pressure (maximum and normal)
- Operating temperature
- Other design factors (depending upon the type of pipeline and applicable regulation)
- The pipe material
PVC, fiberglass, polypropylene, and other materials may be used in low-pressure and utility applications. ANSI/ASME B31.4, B31.8, and the DOT regulations allow the use of alternative materials in very restricted applications. However, steel pipe will be required in the majority of the oil and gas production and pipeline applications. ANSE/ASME A53 and A106 and API 5L seamless, ERW, and submerged arc-welded (SAW) steel pipe are commercially available and most commonly used in pipeline systems. Seamless pipe is seldom used in pipeline applications because of the higher unit cost and limited availability. From a design and regulatory perspective, pipe made with ERWs and SAW seams is equivalent to seamless pipe and is less costly. Note: this is not true for piping systems designed in accordance with the ANSI/ASME Standard B31.3.
Typically, for high-pressure pipelines, higher-grade pipe (such as API 5L, Grades X42, X52, X60, and X65) is selected because much-thinner-wall pipe can be used, which significantly reduces pipe costs. Construction-costs savings also are realized, as the welding time is reduced and material shipping/handling costs are reduced.
Pipe fittings, flanges, and valves must meet the specification and pressure class of the pipe selected for pipeline applications. The materials for pipelines commonly conform to industry codes and standards including:
- ANSI/ASME Standard B16.5
- ANSI/ASME Standard B16.9
- ANSI/ASME Standard B31.4
- ANSI/ASME Standard A105
- ANSI/ASME Standard A106
- ANSI/ASTM Standard A234
- ANSI/ASTM Standard A420
- ANSI/ASTM Standard A694
- API Standard 6D
- API Standard 6H
- MSS Spec. 44
- MSS Spec. 75
Pipe fittings can be matched to the higher grade API 5L, X Grade pipe. Detailed material information is discussed on the page on on ratings for valves, fittings and flange pressures.
Route selection and survey
Route selection is very important to successful pipeline design. This requires careful study of the:
- Natural obstacles, such as
- Manmade obstacles, such as
- Population density
Some helpful aids in the routing process include:
- Topographic maps
- Aerial photography
- Satellite imagery
- Property ownership maps
- Physical inspection
Constructability is an essential consideration when choosing the route. Typically, the minimum pipeline construction working right-of-way (ROW) for a 2-in. pipeline is 35 to 40 ft in width, and the working area should be reasonably level. Larger-diameter pipe requires wider ROW because the larger pipe requires bigger pipe-handling equipment (sidebooms), wider ditches and wider spoil piles. Eighty- to 100-ft wide construction working ROWs are typical for 4- to 12-in. pipe, and 200-ft plus construction ROW widths are common for pipe up to 30 to 36 in. The proposed route must be surveyed to:
- Determine the exact length of the proposed pipeline
- Determine the physical terrain
- Locate natural and manmade obstacles
- Verify property boundaries
Once a workable route is confirmed, the acquisition of the ROW and regulatory permits begins.
Right of way (ROW)
The acquisition of private and public ROW and associated governmental permits is a major component of the pipeline process. Oil and gas leases often have provisions that allow the producer to install wells, flowlines, production facilities, and processing and storage facilities without having to acquire additional ROW or facility properties. However, producers do not have the right to cross:
- Public roads
- Highways, railroads
- Jurisdictional creeks/streams
- Pre-existing easements or ROWs
Gathering and transmission pipelines have to purchase the ROW, or easement, that is required for the pipeline system. Typically, easements, which grant the pipeline owner the right to operate and maintain the pipeline and appurtenant facilities, are purchased. In some instances, the ROW may be purchased “in fee” where the easement is acquired as a property.
Permits and special considerations
Permits are required to install pipelines across public highways, roads, streets, and any other public conveyance. The permits must be acquired from the federal, state, or local authority that has jurisdictional authority. Special easements or permits must be acquired from railroads and other pipelines as well.
There are special design requirements for pipe installed across the highways, roads, streets, and railroads, which are stipulated in ANSI B31.4, B31.8, and the DOT regulations. Heavier-wall pipe (required because of lower design derating factors), casing, hydrostatic and nondestructive testing and other special requirements are stipulated in the applicable regulations, codes, and industry standards.
Special installation requirements are common, as few highways, public roads, or streets, if any, can be open-cut and ditched. Railroads will not allow conventional, open-cut ditch installation. The pipeline must be installed by wet or dry boring methods, tunneling, or horizontal-directional-drilling (HDD) methods. These methods are described later.
Environmental requirements have a major impact upon the pipeline industry. Pipelines can not be constructed in certain defined wetlands, marshes, swamps, rivers, creeks, or streams where the pipeline installation and operation could affect sensitive ecologies and environments. In the U.S., the U.S. Army Corps of Engineers (COE) has the primary jurisdictional authority over these areas, and other federal agencies, such as the U.S. Fish and Wildlife Service, have secondary jurisdiction. All states now have environmental or similar agencies that also have jurisdiction in many of these areas. Internationally, many countries now have laws and regulations that protect the natural resources. Several issues require investigation before finalizing the route selection, including, but not limited to:
- Historically significant sites
- Archeological sites
- Endangered species
Special permits must be acquired to work in and around sensitive areas. In the U.S., permits from COE are required for crossing of rivers, navigable streams/creeks, wetlands, and other regulated waters.
The environmental and natural resource regulations and requirements not only apply to regulated gathering, transmission, and distribution pipelines but also apply to flowlines and production facilities constructed within oil and gas leases. The potential cost impacts of these issues must be given serious consideration in the pipeline design process.
Steel pipe and pipeline facilities must be protected from the effects of external and internal corrosion. Nonferrous piping materials, such as fiberglass, PVC, and polypropylene, do not undergo the same corrosive effects and require little attention. Industry codes and standards and the DOT regulations require that pipelines, appurtenances, and facilities be protected from the effects of corrosion. NACE has standards prescribing the corrosion protection required for pipelines—NACE Standard MR01-76, RP200, and RP572.
Internal corrosion may be caused by the presence of CO2, water, H2S, chlorides (salt water), bacteria, completion fluids, or other substances in the produced hydrocarbon. When CO2 or H2S is mixed with oxygen and/or water, acids are formed that attack and destroy the steel. When CO2 or H2S is mixed with oxygen and/or saltwater, extreme corrosion occurs. Certain types of bacteria often found in producing formations can also attack and destroy the steel. Any of the internal corrosives, separately or in combination, can cause leaks and severe blowouts.
The potential corrosives usually can be identified from a chemical analysis of the produced hydrocarbons. In instances where high concentrations of CO2, H2S, or other highly corrosive chemicals are present, additional pipe wall thickness may be added in the pipe design to allow for the potential corrosive effects. This is not normally recommended, as corrosion could be localized and the rate difficult to predict. In most cases, the removal of oxygen and water from the fluid is sufficient to combat potential corrosion. Where this is not practical, corrosion-inhibition chemicals, internal coatings, and corrosion-resistant materials are used.
Internal corrosion also can be caused by erosion or wear. Excessively high velocities in liquid and multiphase fluid systems can erode or wear the internal pipe wall as well as fittings and valves. The conditions that cause mechanical erosion can be mitigated through proper pipe sizing and design.
The corrosive effects of the hydrocarbon fluid may change over time as the chemistry of the produced fluid changes or as bacteria develop that were not present earlier. Where unknown corrosives develop after operations have commenced, chemical treatment may be the best solution.
External corrosion - underground piping
External corrosion affects buried pipe and above-ground pipe. Buried pipe is subjected to cathodic actions and galvanic actions. Above-ground pipe is subjected to atmospheric corrosion and galvanic actions.
Cathodic actions occur when steel pipe is buried below ground. Ferric and other materials, such as soils, have small electrical potentials. In the natural process of converting metals back to their elemental or native state, electrolytic conduction takes place. Unprotected, the steel pipe becomes an anode (positively charged) and transfers material, by means of electrons, to the cathode (negatively charged) material, which is the soil or surrounding medium. The pipe metal literally flows away by means of the electric current between the anode and cathode. Water contained in the soils and other media serves as the electrolyte to help promote the electron transfer.
To counteract cathodic actions, pipe is coated with anticorrosive materials and cathodic protection systems are placed on the pipeline. The coating must provide an effective “insulation” against the environment but must be tough enough to withstand the operating temperatures, be resistant to the soil, and withstand physical handling.
There are a number of coating systems that are economical and commercially available, which include:
- Extruded systems (polyethylene or polypropylene over asphalt mastic or butyl adhesives)
- Tape coats (polyethylene, polyvinyl, or coal tar over butylmastic adhesive)
- Fusion bonded epoxy (thin film)
- Coal-tar epoxy
Fusion bonded epoxy (FBE) coatings are the most popular coating systems because they:
- Are excellent insulators
- Are hydrocarbon, acid, and alkali resistant
- Are unaffected by temperature
- Do not require a primer
- Can be applied over finished welds (field joint)
Tape-coating systems and coal-tar enamel systems are becoming less and less popular. Tape coating is difficult to apply and is especially difficult to use on large-diameter pipe. A number of tape-coated systems have experienced failures over relatively short spans of time because of improper application. Coal-tar epoxy is becoming less desirable because of some health and environmental concerns caused during application.
In addition to the anticorrosion pipe-coating systems, cathodic protection systems are added to the pipeline to protect the pipe where breaks in the coating system occur. The cathodic protection system employs either an impressed current or sacrificial anode to protect the underground pipe. The cathodic protection system reverses the electrolytic conduction process and uses an impressed electrical current or another metal object (sacrificial anode) to make the pipe a cathode. In simplified terms, the impressed current reverses the natural flow of electrons from the pipe to the surrounding medium to prevent the loss of metal ions. The sacrificial anode made of a higher potential metal, such as magnesium, is in contact with the pipe and the surrounding medium. The anode gives up its electrons (metal) in place of the steel pipe.
Sacrificial-anode systems are simpler and less expensive than impressed current systems. Onshore pipelines generally use magnesium, and offshore pipelines use zinc or aluminum anodes. Impressed current systems are much more complex and require external power sources and AC/DC power inverters or rectifiers to provide the current to the pipe.
The design of cathodic protection systems requires specialized training and can be very complicated. Detailed soil surveys must be conducted to determine the electrical potential and resistivity of the soils or surrounding medium, pipe-to-soil potentials, and a number of other criteria. System design should be done by a cathodic protection expert.
Another important facet of the anticorrosion system is prevention of galvanic corrosion. Galvanic corrosion is caused by the interface of dissimilar metals with different electrolytic potentials. The dissimilar metals will gain or lose electrons from or to each other resulting in one of the metals effectively flowing away and losing material. Steel pipe that undergoes abrupt changes in the medium will behave somewhat as dissimilar metals and cause galvanic actions. Pipe transitioning from below ground to above ground may experience galvanic-like corrosion. Mating materials such as carbon steel with stainless steel will cause the carbon steel to corrode.
Insulating flanges or joints can be used to counteract the effects of galvanic actions. Efforts should be made to avoid the interface of the dissimilar materials in the system design.
The effects of atmospheric corrosion are readily apparent. Bare steel will corrode rapidly when exposed to:
- Chemicals (pollution)
- Air (oxygen)
Piping and equipment exposed daily to the elements must be protected with anticorrosion coatings. Good paint coating systems, such as epoxies, and regular maintenance will normally provide adequate protection to the above-ground facilities.
Facilities exposed to severe service, such as offshore, may require more-extensive protection systems. There are a number of alternative coating systems that are discussed in the offshore pipeline section.
Welding and pipe joining
The methods used to connect the joints or pipe segments are very important and are critical to the pipeline design. ANSI/ASME Standards B31.3, B31.4, and B31.8, as well as the DOT regulations, specify welding and joining methods for pipe. Each type of pipe material has joining or coupling methods designed to ensure that the joint is as strong as, or stronger than, pipe joint. Fiberglass, PVC, and other types of plastic pipe may have bell- and spigot-type joints that are mechanical, threaded, or glued. Polypropylene and polyethylene pipe, which is used frequently in very-low-pressure hydrocarbon applications, use a fusion-welded joint. However, the majority of the hydrocarbon pipeline applications require steel pipe.
For the majority of steel pipeline applications, welding is the preferred method of joining the pipe. API Standard 1104 and ASME Sec. IX of the boiler and pressure vessel codes specify the requirements for the welding of steel pipe. Manual and automatic welding processes are used on pipelines both onshore and offshore. Shielded metal-arc welding (SMAW), or “stick” welding, is the most common manual process used on carbon-steel pipelines, but the development and use of higher-grade carbon-steel pipe (e.g., API 5L X65 and X70) have required the development of welding processes and metallurgy compatible with the high-carbon alloys. Stainless steels and other alloys may require special welding processes.
The development of reliable and economical automatic welding machines has had a significant impact on the pipeline industry as well. The automatic welders may be external or internal for large-diameter pipe.
Each weld joint must be designed and a welding procedure specification (WPS) developed for the pipe. Each WPS specifies:
- The type of pipe to be welded (specification, grade, etc.)
- The type and specification the of the pipe joint [e.g., specify bevel(s), angle, shoulder, and spacing/alignment]
- The material thickness or range of thickness applicable
- The type and size of welding rods
- The position and direction of the weld
- The voltage/amperage
- Stress relieving
The WPS must be physically proved by actually welding a test “nipple” and conducting destructive testing in accordance with the API and/or ASME requirements. Once the specification is proven, a procedure qualification record (PQR) is recorded verifying the WPS. Welders must be qualified to perform the welds in accordance with either API Standard 1104 or ASME Sec. IX. Each welder will perform a test weld using the WPS for the pipe and will qualify under the procedure. API Standard 1104, ASME Sec. IX, and DOT specify and define welder qualifications.
There are other acceptable methods for joining pipe. Steel pipe may be threaded and coupled or may have various mechanical joints. Threaded-steel-pipe application is generally limited to small diameters, 4 in. and less. Larger pipe is difficult to properly couple, and threaded line pipe in large diameter is not readily available. Fiberglass pipe used in the industry may be threaded or have solvent-welded joints. PVC may have solvent-welded joints or may have bell-and-spigot mechanical joints. Industry codes and standards, as well as DOT regulations, recognize the other joining methods but limit the use of pipe other than steel.
Pipeline construction process
Conventional, onshore pipeline construction process is described next.
Before initiation of construction activities, any sedimentation, erosion control, construction fencing, and other preparation is completed. All vegetation is cleared and grubbed, topsoil is removed (if required), and the working ROW is graded.
Once the ROW has been prepared, the pipe is loaded on flatbed trucks. Before unloading, pipeline skids (typically 4-in. × 6-in. × 4-ft hardwood timbers) are dropped along the ROW to be placed under the pipe. The trucks are driven down the ROW, and the pipe is unloaded, joint by joint/end to end, by sidebooms or cranes.
The ditch is excavated along the pipeline centerline using ditching machines, excavators, backhoes, and other excavation equipment. Pipelines are normally buried with a minimum of 36 in. of cover (DOT regulatory requirement). In consolidated rock, the minimum cover varies between 18 and 24 in. The cover for Class 1 locations is 18 in.; the cover for Classes 2 to 4 (railroads, highways, and public roads) is 24 in.
The pipe strung along the ROW is welded in a progressive manner. Sidebooms will work along the ROW lifting the pipe while a crew aligns the pipe in preparation for the “stringer bead” weld. Generally, a welder or welders (depending upon the size of the pipe) will work with the alignment crew, align the pipe, and apply the initial weld “bead.” A group of welders will follow immediately behind the stringer welder(s) and apply the “hot pass” bead or seal weld. Additional welders will follow to apply the final passes of weld material.
Field joint and anticorrosion coating and inspection
When the welding is completed, field joint crews clean the weld areas and the short, adjacent bare steel on either side of the weld, and apply the field joint coating. Any nondestructive testing of the welds, such as X -ray, will be completed before application of the field joint coating. Following the completion of the field joint coating, the pipe is inspected with “holiday” detection equipment (low-voltage DC equipment that shows where the pipe coating and field joints have failures or breaches), and anomalies and breaches in the coating are repaired.
Upon completion of the field joint application and coating inspection, the pipe is lowered and placed into the ditch by sidebooms or other lowering equipment.
Backfill, cleanup, and restoration
Following completion of the pipe lowering, the ditch is backfilled, and the ROW is cleaned and dressed. The ROW is finely dressed, grass and vegetation replanted, and any special remediation measures or cleanup requirements are completed.
Highway, road, railroad, and river Crossings
Highway, road crossings are seldom installed using conventional, open trench methods. Typically, these crossings are installed using a wet bore or dry bore method. The boring is done by rigs that are similar to very small drilling rigs, laid horizontally, and placed in pre-excavated boring level “pits.” The boring rig drills underneath the crossing area, and the pipe or casing is installed. The wet method uses a boring rig and circulates water or drilling fluid through a drill stem to open a small pilot hole, then pulls a pipe or casing-sized cutting head back to the rig, cutting a hole large enough to place the pipe or casing. The dry bore method is similar, but the casing or carrier pipe is fitted with a cutting head and is used to drill the hole and is left in place when the drill is completed. The hole is drilled dry and does not use any water or fluid to assist the drilling operation. Railroad crossings are never open cut and are always bored. Typically, railroads require that the borings be made with the dry bore method. Both wet and dry bore methods are limited on the distance that they are effective and practical.
River crossings are now typically installed using the HDD method. Open-cut trenching of rivers may be allowed by the U.S. Corps of Engineers, but HDD installations have become more economical. The HDD method uses a computer-controlled rig that controls a directional wet-bore pilot drill that can be accurately steered from the rig. The directional drill can bore a pilot hole up to a mile or more and ream a hole back to the rig large enough to install the carrier pipe. The “drill” string or pull section of pipe is welded together on the drill exit side, pretested, then pulled back to the rig side following the backreamer.
The HDD method may be used to install long highway and road crossings, such as interstate highways and freeways. The wet- and dry-bore methods are limited to several hundred feet in length, which requires multiple borings to cross the distances typically required to cross interstate highways and freeways.
A crew, or crews, is typically deployed that makes all pipeline tie-ins along the construction corridor. The tie-in crew makes the final welds at junctures where the progressive welding cannot make the final welds. Tie-ins are made at locations such as highway, road, railroad, and river and creek crossings and at drag sections, etc. The tie-in crew typically has excavation and pipe handling equipment and dedicated welders.
Fig. 1 through Fig. 11 illustrate typical construction details. The Occupational Safety and Health Admin. (OSHA) is an agency under the DOT and provides additional federal rules and regulations concerning the design, construction, and testing of pipelines.,
Offshore pipeline design differs primarily in the requirements of the environment and the installation process. Pipe used in offshore applications is subjected to high bending stresses—potential crushing forces on pipe installed in deep water and a low-density environment. Until recently, the pipeline size was severely limited, but technological developments and improved construction methods have enabled offshore pipelines to continue to increase in size and capacity. Pipelines are being constructed in deeper and deeper waters. Pipelines up to 28-in. diameter are now being installed in the deepwater applications up to 7,000 ft of water.
The piping materials used in the offshore pipelines are essentially the same as those used in onshore pipelines. When a pipeline is designed according to ANSI/ASME Standard B31.8, a 0.72 design factor is used for most of the pipeline wall-thickness calculation, and a 0.50 design factor is used in the riser pipe and often the first 300 ft of pipe adjacent to the riser. Pipe greater than 10-in. nominal size installed in low-density saltwater will generally tend to float. Sometimes this can be overcome by using more wall thickness than otherwise necessary to make the pipe heavier. It is normally more economical to use a concrete weight coating or to lay the line wet to get the required on-bottom stability. Generally, pipe is designed to have a specific gravity of 1.35.
The pipe has to be designed with enough wall thickness to handle the internal operating pressure, the bending stresses, and the external crushing forces. High-strength, high-grade pipe, such as API 5L Grade X65 and greater, is often used for construction, structural, operational, and economical considerations.
The minimum bending radius calculation for concrete coated pipe is expressed in Eq. 9.36.
|R||=||bending radius, in.,|
|E||=||modulus of elasticity for concrete = 3,000,000 psi,|
|C||=||pipe radius + enamel thickness + concrete thickness, in.,|
The minimum bending radius for steel is expressed as
|SY||=||pipe specified minimum yield strength, psi,|
|P||=||design pressure, psi|
|D||=||pipe OD, in.|
|t||=||pipe wall thickness, in.|
|R||=||bending radius, in.|
|E||=||modulus of elasticity for steel = 30,000,000 psi|
|C||=||pipe radius, in.|
|f||=||stress factor: use 75 to 85% for offshore design.|
In deep water, computer programs are available to calculate the tension that must be kept on the pipe to maintain an acceptable bending radius. This is a complex calculation and must take into account the specific capabilities of the lay barge. In deep water, laying stresses and collapse stresses may determine the wall thickness. In addition, buckle arrestors may be required to restrict the length of a buckle, should one be caused by an installation problem (e.g., loss of adequate tension).
Offshore pipelines are constructed using lay barges or special ships. Each operation of the pipeline construction process, with the exception of pipe burial, takes place on the lay barge. Pipe is stored, prepared, welded, field joint coated, inspected, and lowered from the lay vessel. The pipe is lowered from the rear of the barge using a sophisticated system of dynamic positioners, rollers, cable tensioners, floats, and a long, adjustable boom or stinger. The pipe is strung out behind and below the lay barge and assumes an S-shape or J-shape. In an S-lay, the pipe is made up horizontally on the barge allowing for several welding stations. The pipe leaves the barge over a stinger that controls the curvature of the “overbend.” Tension in the barge anchors controls the radius of curvature of the “sag bend”, which returns the pipe to horizontal on the seafloor. In very deep water, it is no long possible to control the overbend with a stinger and, thus, a J-lay is used where the pipe leaves the barge vertically. A J-lay requires a tower on the barge to hold a length of pipe while all the welding is done at one location.
No matter which system is used, the pipe experiences tremendous bending forces caused by the weight of the pipe, the motion of the vessel, and the radius of the bends. The radius is controlled by tensioner systems. The pipe must be designed so that stress, caused by axial tension and bending moment, is within allowable limits.
The rate of progress of the lay, the roughness of the sea, and other factors can cause the pipe to buckle. The deeper the lay, the greater is the potential to buckle the pipe. Pipe can be laid in shallow water, 50 ft or less, with a spud barge or jack-up barge. The spud and jack-up barges operate in a fashion similar to the lay barge.
Pipe burial is performed with a plow or a jet. Plows are used in deep water and denser clays and can be used concurrently with the lay barge. Jet systems can be used in water up to depths of approximately 300 ft. Divers can hand jet a pipe in shallower waters, but more often, a jetting machine is used to bury the pipe after it is laid. In shallow waters (50 ft or less), a dredge can be used to excavate the pipe trench.
In the U.S., the minimum cover required over the pipeline, in depths up to 200 ft, is 36 in. There is no requirement for pipe burial in water deeper than 200 ft. Typically, pipe is buried with 5 ft of cover for the first 300 ft outward from the platform riser, 16 1/2 ft in anchorage areas, and 10 ft in fairways. Foreign pipelines are generally crossed over, and it may be necessary to lower the foreign line. A minimum of 18-in. separation must be maintained, and often rubber coated, articulated concrete mats are placed between the lines.
The same corrosion protection and cathodic protection principles that apply to onshore pipelines also apply to offshore pipelines. The line pipe is typically coated with an FBE or similar system, and if additional weight is needed, it will have an overcoat of concrete.
Above-water piping is typically coated with a multicoat epoxy paint system. A special section of pipe with a vulcanized rubber coating bonded to the pipe, “Splashtron,” is often used in the highly corrosive splash zone at the water/air interface.
Sacrificial zinc or aluminum anodes are mounted to the pipe in a bracelet configuration. The anodes are typically designed for a minimum 20-year service life. It is very difficult to design and maintain an impressed current system on a long offshore pipeline.
Hydrostatic testing and nondestructive testing and inspection
Each pipeline system must be tested and inspected to ensure that the system can be operated safely. DOT regulations specify testing and inspection requirements as well as ANSI/ASME Standard B31.3, B31.4, and B31.8 and API Standard 1104, 571, and 574.
The DOT regulations, Part 192, Subpart J, paragraph 192.501 to 192.517; Part 193, Subpart D, paragraph 193.2319 and 193.2323; and Part 195, Subpart E prescribe the pressure-testing and strength-testing requirements for natural-gas, LNG, and hazardous-liquids pipelines, respectively. The ANSI/ASME and API standards also prescribe testing requirements. Pneumatic testing is allowed for certain low-pressure pipeline systems, but the majority of pipelines are tested with water.
Before conducting the hydrostatic testing, a profile of the test section should be developed showing the maximum and minimum elevations, the maximum allowable working pressure (MAWP) determined at the lowest elevation point, the location of the fill and pressure pump, minimum pressure required at the pressure pump determined by the:
- Maximum pressure at the lowest elevation
- Water-source quality
- Discharge/disposal point
The profile of the test segment provides a graphical representation of the test segment, which helps the testing engineer determine the location of air bleed vents and the fill rate and pig velocity required to prevent air entrapment, and verify that the test will not overpressure or underpressure the pipe in the segment. The elevation differential can become a major consideration. When radical changes in elevation occur over short distances, it may be necessary to subdivide the original segment into shorter test segments. Each 100 ft of elevation difference represents approximately 43.3 psi of pressure differential, which can result in high points being underpressured and low points being overpressured during the test. The test profile is also used to document the location of the fill pump, the test pump, the dead-weight gauge, and the pressure/temperature recording equipment. Fig. 12 illustrates is a typical test profile segment.
The typical testing equipment that is needed to conduct the hydrostatic test is:
- A temporary fill manifold complete with valves (pressure rated at a minimum of 1.5 times the maximum test pressure)
- Dewatering manifold complete with valves (also pressure rated at a minimum of 1.5 times the maximum test pressure)
- Foam or urethane pigs
- Low-pressure/high-volume fill pump with filtration equipment, high-pressure positive-displacement pump
- Certified dead-weight gauge(s)
- Chart-type pressure recorder
- Chart-type temperature recorder for the water
- Chart-type temperature recorder for ambient air
- Pressure gauges rated at 50 to 75% of the maximum test pressure
- Compressed air or nitrogen source for dewatering
- Discharge water filtration equipment
In addition, temporary water-storage or holding tanks may be needed to supply reserve test water or serve as holding or settlement devices for dewatering.
Nondestructive testing and inspection of the welds is required by the DOT regulations Part 192, Subpart E, paragraph 192.243 for natural-gas pipelines; Part 193, Subpart D, paragraph 193.2321 for LNG lines; and Part 195, Subpart D, paragraph 195.234 for hazardous-liquid lines. ANSI/ASME Standards B31.3, B31.4, and B31.8 also prescribe nondestructive requirements.
Each of the regulations and industry codes requires visual inspection of welds and construction process.
Instrumentation and control
Pipeline control systems may consist of simple devices such as automatic pressure-control valves to the sophisticated total supervisory-control-and-data acquisition (SCADA) control system. The SCADA system can monitor and control, on a real-time basis, an entire pipeline system. The SCADA system can open and close valves, start and stop pumps/compressors, monitor and control flow, sample the product, monitor and regulate pressures and temperatures, and perform many other functions. SCADA systems are typically neither needed nor practical for small, gathering pipeline systems.
Compressor stations, pump stations, and related facilities may require emergency isolation equipment to protect the pipeline. Emergency-shutdown (ESD) systems consist of automatic shutoff isolation valves located at the main inlet and outlet to the stations/facilities and coordinated pressure-relief systems between the isolation valves. The ESD system protects both the pipeline and facility by stopping the flow into and out of the facility and limits the feed source in the event of fire, explosion, or other emergency.
Basic pipeline instrumentation includes strategically located pressure gauges and pressure-monitoring instruments, temperature gauges and monitoring instruments, and pressure control/limitation and relief equipment.
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