Pipeline Construction Step

Pipeline Construction

A pipeline construction project looks much like a moving assembly line. A large project typically is broken into manageable lengths called “spreads,” and utilizes highly specialized and qualified workgroups. Each spread is composed of various crews, each with its own responsibilities. As one crew completes its work, the next crew moves into position to complete its piece of the construction process.

These tasks include:

1. Pre-construction survey
Before construction begins, Williams surveys environmental features along proposed pipeline segments. Utility lines and agricultural drainages are located and marked to prevent accidental damage during pipeline construction. Next, the pipeline’s centerline and the exterior right of way boundaries are staked.

2. Clearing and grading
The pipeline right of way is cleared of vegetation. Temporary erosion control measures are installed prior to any earth-moving activities.

3. Trenching
Topsoil is removed from the work area and stockpiled separately in agricultural areas. Williams then uses backhoes or trenching machines to excavate a pipeline trench. The soil that is excavated during ditching operations is temporarily stockpiled on the non-working side of the trench.

4. Pipe stringing
Individual joints of pipe are strung along the right of way adjacent to the excavated ditch and arranged so they are accessible to construction personnel. A mechanical pipe-bending machine bends individual joints of pipe to the desired angle at locations where there are significant changes in the natural ground contours or where the pipeline route changes direction.

5. Welding and coating pipe
After the stringing and bending are complete, the pipe sections are aligned, welded together, and placed on temporary supports along the edge of the trench. All welds are then visually and radio graphically inspected. Line pipe, normally mill-coated or yard-coated prior to stringing, requires a coating at the welded joints. Prior to the final inspection, the entire pipeline coating is electronically inspected to locate and repair any coating faults or voids.

6. Lowering pipe in and backfilling
The pipe assembly is lowered into the trench by side-boom tractors. The trench is backfilled using a backfilling or bladed equipment; no foreign materials are permitted in the trench.

7. Testing
After backfilling, the pipeline is hydrostatically tested following federal regulations. Test water is obtained and disposed of in accordance with applicable federal, state and local regulations.

8. Restoration
Williams policy is to clean up and restore the work area as soon as possible. After the pipeline is backfilled and tested, disturbed areas are restored as close as possible to their original contours. Restoration measures are maintained until the area is restored, as closely as possible, to its original condition.

SUmber : http://co.williams.com/williams/operations/gas-pipeline/pipeline-construction/

Bending Stresses From External Loading On Buried Pipe

The pipeline industry has long been interested in evaluating the effects of external loading due to fill and surface loads, such as excavation equipment, on buried pipes. This interest stems not only from the initial design of pipeline systems, but also from the need to evaluate changing loading conditions over the life of the pipeline. Variations in loading conditions can arise due to the construction of roads and railroads over the pipeline and one-time events in which, for example, heavy equipment must cross the pipeline.

The pipeline may also suffer corrosion or damage that requires excavation and repair. Heavy excavation equipment is often placed directly over a pipeline during repair work, as shown in Figure 1. Safety while excavating pressurized pipelines is a serious concern for operating companies. Both gas and liquid pipeline companies often specify reduced pressures while excavating and repairing in-service pipelines.

A common issue is determining what pressures are safe during excavation and repair procedures. Design codes, regulations and industry publications offer little guidance on what factors should be considered to determine safe pressures during in-service excavation activities. Surface-loading conditions and soil overburden result in stresses that should be evaluated in determining safe excavation pressures near areas of damage or corrosion. Large concentrated loads, like truck wheel loads, are of primary concern.

The ALA Guideline for the Design of Buried Steel Pipe presents design provisions for use in evaluating the integrity of buried pipelines for a range of applied loads. (ref: “Guideline for the Design of Buried Steel Pipe,” American Lifelines Alliance/ASCE/FEMA, 2001.) Its methodology offers an approach for evaluating the fill and surface-loading effects on buried pipelines. This approach utilizes the deflection of the pipe, calculated using a version of the classic Iowa Formula, in estimating the wall-bending stresses in the pipe. The wall-bending stress is then combined with other calculated stresses to calculate the overall stress in the pipe.

Figure 2: Schematic of the deflection of a buried pipe due to vertical loading.

Smith and Watkins pointed out that the Iowa Formula was derived to predict the ring deflection of flexible culverts, and not as a design equation to determine the wall thicknesses of pipes. (ref: Smith, G., and Watkins, R., “The Iowa Formula: Its Use and Misuse when Designing Flexible Pipe,” Proc. of Pipelines 2004 Int’l Conf., ASCE, 2004.) It is often used to estimate wall stresses, however, and determination of the total stress is important to safety calculations. In this article, the wall-bending stress calculation and some quirks in its behavior will be discussed.

Pipe materials are classified as being either flexible or rigid. A flexible pipe has been defined as being able to deflect at least 2% without structural distress. (ref: Moser, A.P. and Folkman, S., “Buried Pipe Design, 3rd Ed.,” McGraw Hill, 2008.) Materials such as steel and most plastics are considered flexible pipe. Concrete and clay pipes are considered rigid. The Iowa Formula was developed for use with flexible pipes.

Flexible pipes derive much of their load-carrying capacity from pressure induced at the sides of the pipe as they deform horizontally outward under vertical loading. Analysis of the effect of fill weight and surface loading is therefore a problem of interaction between the pipe and the soil. The Iowa Formula describes the interaction of the pipe and soil and the deflection that results from vertical loading.

Figure 3: Effect of wall thickness ratio on the normalized wall-bending stress

In his research of the performance of buried flexible pipes, M. G. Spangler observed that, compared to rigid pipes, flexible pipes provide little inherent stiffness and perform poorly in 3-edge bearing tests. However, flexible pipes performed better than predicted by these tests when buried. He reasoned that the source of strength of the flexible pipe is not the pipe itself, but is primarily the soil beside the pipe. (ref: “Insight into Pipe Deflection Predictions: An Interview with M.G. Spangler,” Sewer Sense No. 17, National Clay Pipe Association, 2004.) 

Sumber : http://www.pipelineandgasjournal.com/bending-stresses-external-loading-buried-pipe?page=show

Drilling Direction

Directional casing drilling

A number of different casing drilling systems have been used both onshore and offshore. However, there are no known cases where an offshore directional well has been drilled with the expectation that the directional BHA would be pulled with a wireline and replaced while drilling the section.

The mature North Sea field application requires a fully retrievable casing drilling system to replace the directional assembly in the event of a component failure, to provide flexibility in BHA selection, and to recover the drilling assembly once the casing point is reached. The system must provide circulation, pipe movement, and full well control while running/retrieving the BHA.

These requirements are met with Tesco’s wireline retrievable directional casing drilling system. A conventional RSS directional assembly is run below the casing shoe to drill a pilot hole that simultaneously is underreamed to a diameter large enough to accept the casing. Use of this system on a conventional offshore rig may require modification to the surface equipment to allow effective deployment of the wireline system to run and retrieve the drilling assembly.

The surface system selected for the Norway well requires a wireline unit and crown sheave, wireline BOP system, split traveling block, and casing drive tool. All this equipment requires certification to Norway regulatory specifications. The portable casing drive system used for connecting the top drive to the casing without needing to make a threaded connection is used routinely for offshore casing running jobs and already was certified.

On the other hand, providing the wireline unit is somewhat problematic in that only a single wireline unit has been built that is appropriate for pulling the directional assemblies in typical Norway well profiles. This prototype traction winch was used for the testing described below, but a new unit was designed and built in Norway to facilitate obtaining the required certification. This unit has the capability to pull up to 40,000 lbf with a 7/8-in. braided cable while meeting the required design factors.

The casing drilling directional BHA includes a RSS and MWD run between the pilot bit and underreamer. The rotary steerable tools are run immediately above the pilot bit so a standard Schlumberger PowerDrive RSS can be used without modification. That would not be possible if the rotary steerable tools were run in the larger hole provided above the underreamer.

The BHA is released and pulled out of the casing in a single trip for vertical and low angle wells by using a releasing and pulling tool run on wireline. These tools must include the capability of being pumped into the well because of the high inclination in the Norway wells. Tool manipulations during setting and retrieval are performed with a combination of wireline tension and hydraulic operations that can be performed effectively in a horizontal well.

Test site

The cost of offshore operations and the inefficiencies (learning curve) associated with the introduction of a new drilling technology drive most first-time applications to being tested at land operations. Unfortunately for this purpose, most land wells are vertical. Furthermore, in using commercial wells for testing new technology, the well must be drilled to completion. This could be an expensive proposition if unexpected problems are encountered with the new technology.

These limitations led to the decision to test both the 7 5/8-in. and 10 3/4-in. systems at a Schlumberger facility. The facility has a large land drilling rig on rails that can access 11 slots and drill wells with displacements up to 5,000 ft.

7 5/8-in. drill test

The 7 5/8-in. casing directional drilling test was performed in July 2005. The tests were conducted from an existing horizontal well built at about 3.0 deg/100 ft at a TVD of 2,200 ft. It was cased with 13 3/8-in. casing and included 600 ft of horizontal section. The well and BHA set/retrieval tests were planned at 0, 45, and 90 degrees inside the existing casing before drilling began. After these tests were completed, 850 ft of new hole was drilled horizontally to test the complete system under actual drilling conditions.

The directional BHA incorporated a 4 3/4-in. RSS and PDC bit to drill a 6 1/2-in. pilot hole that was underreamed to 9 7/8-in. The directional plan provided for first turning the well to the right at 1.0 deg/100 ft and then to the left at 3.0 deg/100 ft while maintaining the borehole horizontal to test the directional performance of the BHA. The drilling assemblies were run and retrieved with a pump-down wireline (5/8-in. braided cable) system.

More detail of the 7-5/8-in. testing was provided by Borland, but the major conclusions were:

• The rotary steerable system in the pilot hole section of the BHA, coupled with the straight hole motor run above the underreamer, provided effective directional performance
• BHA vibrations were observed, but did not impact the performance of the drilling system
• Real-time monitoring of vibration and surface parameters allowed the BHA shocks to be reduced
• Testing in an actual drilling situation provides insight into tool design and performance that is essential before using the tools in a critical, expensive offshore operation.

10 3/4-in. drill test

The 10 3/4-in. test was in November 2005 at the test facility in a well with 13 3/8-in. casing set vertically at 2,003 ft. After establishing the cement plug at the 13 3/8-in. shoe for sidetracking, the well was sidetracked with casing and directionally drilled with first a low build rate of 0.5 deg/100 ft and then a higher 3.0 deg/100 ft.

The BHA design was similar to those in the 7 5/8-in. test in July. An RSS and MWD were used for directional control in the pilot section of the BHA. A straight motor was placed above the underreamer to supply downhole RPMs. Downhole shock counts were transmitted up hole in real-time from the MWD tool. Shock counts were also recorded downhole in the rotary steerable system. Additionally, three drilling research sensor packages were placed in the BHA; one above the underreamer and two below it, between the MWD and RSS. Downhole recorded measurements included annular pressure, lateral, axial and torsional acceleration, axial speed, torque, and weight-on-bit.

Lessons learned

• The two drilling tests at the Schlumberger facility have provided a cost-effective dress rehearsal for casing directional drilling in the Eldfisk field offshore Norway
• Casing drilling technology with retrievable BHAs, can be transferred to different hole sizes, in this case to 10 3/4-in., 7 5/8-in., and 7 3/4-in.
• Improvements to the setting and retrieval tools have resolved problems in high angle casing directional drilling operations
• Traction winch operations with a split block and derrick sheave system allow efficient and safe BHA handling on wireline for longer and larger BHA’s
• A rotary steerable system in the pilot section of the BHA coupled with a straight motor run above the underreamer is effective in directional performance
• External BHA vibration problems still exist but their effects have been reduced with an increased robustness in downhole tools and real-time monitoring of shocks
• Real-time monitoring of downhole shocks and vibrations and surface torque, weight and delta pressure allows for an actual reduction in these shocks on the BHA.

Plans for Eldfisk

Two Eldfisk oil-producing directional wells are planned for 2006 using RSS with the casing drilling system. Both wells will start from a 13 3/8-in. surface casing set at +/- 1,200 ft. Plans include drilling with 10 3/4-in. to approximately 4,850 ft TVD (5,100 ft MD) and 7 3/4-in. to approximately 9,600 ft TVD (10,800 ft MD). These two wells will be drilled back to back and will share a common wellhead. These field trials are expected to demonstrate a learning curve similar to that observed in the Lobo field. Further implementation of this technology will be depend on the field trial outcome; however, plans are being made for casing directional drilling to become the preferred drilling method for future Eldfisk work. In the short term, additional Eldfisk drilling will be done through recovered slots and will require the 10 3/4-in. casing to be drilled out of a pre-milled window off of a 13 3/8-in. whipstock.

Sumber : 

http://www.offshore-mag.com/articles/print/volume-66/issue-9/drilling-completion/preparations-for-offshore-casing-directional-drilling.html

Thermal Insulation on Pipe

Assets such as offshore pipelines, risers, spools and subsea structures which transport liquid products may be required to maintain a minimum temperature while the product is being transported within the asset, particularly offshore. Some liquids such as oil and gas can leave wax or hydrate deposits if a minimum temperature is not maintained. These deposits can, over time, build up and block the asset/pipeline either reducing or completely stopping flow/production. External wet insulation can be designed and applied to ensure the reduction in product temperature is kept within a range so the risk of deposits during production is acceptable. Insulation can also reduce the frequency of pigging operations during the life of the asset.

During other operational events, such as pipeline shutdowns, the product is contained in a stationary state within the asset/pipeline while the process facility has other operations performed. Similarly, to avoid deposits during these shutdown periods external insulation can be designed and applied to ensure the reduction in product temperature is kept within a range so the risk of deposits during shutdowns is acceptable.

Injected Molded Polyurethane Applications provide thermal insulation and are commonly used offshore on flowline and riser field joints, spools and subsea structures. It is used less often onshore to thermally insulate pipelines and spools. The asset will require to have been pre-coated with an anti-corrosion layer prior to the thermal insulation application.

The preparation for IMPU requires that the anti-corrosion layer is in good condition and the bevel faces of the parent coating (usually PP) are cleaned, abraded and then pre-heated to build bond strength between the PP and IMPU. Once this preparation is completed a mold is placed over the area to be treated and Solid Polyurethane is injected into the annulus and often overlapping the parent coating bevel faces and onto the OD surface of the PP. Once the material cures the mold is removed and inspected.

OJS can apply all Solid Polyurethanes available on the market however we recommend our own formulated solid polyurethane material called Densiflex for IMPU coatings. Densiflex is mercury free and fast curing – which is suitable for the offshore market.

 

 

Injected Molded Polypropylene Applications provide thermal insulation on pipeline and riser field joints and spools. The asset will require to have been pre-coated with an anti-corrosion layer prior to this thermal insulation application.

The preparation for IMPP requires that the anti-corrosion layer is in good condition and the bevel faces of the parent coating (usually PP) are cleaned, abraded and then pre-heated to build bond strength between the PP and IMPP. Once this preparation is completed a mold is placed over the area to be treated and Solid Polypropylene is injected into the annulus. Once the material cures the mold is removed and inspected.

Sumber :http://www.f-e-t.com/our_products_technologies/subsea-solutions/pipeline-field-joint-coatings/thermal-insulation-for-pipelines-risers-spools-and-subsea-structures/

Bottom Roughness Analysis

Depending on the seabed profile, seabed type, loads (self weight and axial loads) and environmental conditions (wave and current induced forces) an on bottom roughness assessment and span analysis is possibly required to identify if any problem areas exist, where spans do not meet the allowable maximum free span criteria.

Maximum static and dynamic allowable free span lengths may be provided to GeoLine for the on-bottom roughness assessment or alternatively we can determine the maximum allowable free spans lengths.

The maximum allowable free span lengths are used as screening criteria to determine areas of critical spans. SAGE Profile finite element software is used to compute the pipeline profile, which is compared with the seabed elevation to determine the span height and span lengths. The computed span lengths are compared with allowable free span length criteria. Environmental loads are taken into account in the analysis.

Modelling Seabed Stiffness

Modeling the seabed stiffness (bearing capacity)
is of great importance for results of on-bottom roughness analysis. Non-linear soil springs are
used to model the vertical soil reactions. The soil springs are calculated according to recommended practices  BS 8010, DNV-RP-F105 “Free Spanning Pipelines”.
A sensitivity analysis should be carried out to investigate the affect of varying seabed stiffness on the span lengths.

Sumber : http://www.geoline.dk/pipepg7.shtml

Inovation in deep water pipeline pre-com

Deepwater pipeline pre-commissioning and in-line inspections are logistical and technical challenges, and vessel time is typically a major expense. The Tamar gas field project in the Mediterranean Sea met these challenges using specialized subsea commissioning technology to mechanically displace and introduce pipeline fluids, and ultrasonic in-line inspection tools to assure pipeline integrity.

The long-distance, deepwater pipeline project for Noble Energy involved a subsea gas production and transportation system connecting the Tamar gas field to an offshore receiving and processing platform linked to the existing Mari-B platform. The system produces gas from five high-flow-rate subsea wells through separate infield flowlines to a subsea manifold. Dual subsea pipelines transport production from the subsea manifold approximately 149 km (92.5 mi) to the Tamar offshore receiving and processing platform. The processed gas goes to the existing Ashdod Onshore Terminal (AOT) for sales into the Israel Natural Gas Line (INGL).

Weatherford's Pipeline and Specialty Services (P&SS) group was contracted to provide the pipeline pre-commissioning and inspection, including tieback pipelines, monoethylene glycol (MEG) pipelines, infield flowlines, gas and condensate injection pipelines, Tamar sales gas export pipeline, and utility pipelines. Integration of these services through a single contractor was one key to reducing logistical and scheduling constraints for overall project success.

Infield flowline operations

Challenges and solutions engaged in the project revolved around subsea flooding, testing, and MEG injection; dewatering, MEG conditioning, and nitrogen purging; and ultrasonic wall measurement base line inspection.

A key aspect of the pre-commissioning involved flooding, cleaning, gauging, and hydrotesting the 5 x 10-in. deepwater (1,600 m to 1,800 m/5,248 ft to 5,904 ft) infield flowlines of 4-km to 6-km (2.5-mi to 3.7-mi) lengths. These operations were performed from the seabed using Weatherford's Denizen subsea pre-commissioning system.

The Tamar gas field presented many logistical and technical challenges to pre-commissioning and inspection.

Flowline operations were independent of the tieback lines and jumper installation. Schedule flexibility increased as a result, and the remote subsea operations avoided the use of a large, vessel-based pumping spread or deepwater downline. Subsea pumps for the flood and hydrotest operations were driven by high ambient hydrostatic pressure during the pipeline free-flood phase and by ROV hydraulic power.

The Denizen pigging pump launched the dewatering pig train with slugs of MEG. A custom, high-volume MEG skid was deployed subsea and connected to the flooding skid to avoid the cost of downline intervention to inject the MEG.

Pre-launching the pigs allowed dewatering of the 10-in. infield lines via a jumper from the 16-in. tieback lines. As a result, all dewatering nitrogen injection was performed from the shallow end of the tieback lines.

Another novel subsea operation used multiple remote subsea data-logging skid packages during hydro-testing. Typically, the ROV and pumping skid hold station at the end of the pipeline for the full 12- or 24-hr pressure test. This was unworkable with five pipelines requiring testing and hold periods.

The solution was to deploy multiple independent hydro-test logging skids. The system's pumping skid has a built-in hydro-test data logging system that displays pipeline pressure, temperature, and pump flow rate. A high-pressure triplex pump, powered by the ROV's hydraulic system, elevated pipeline pressure by injecting chemically treated and filtered seawater.

The logging skids were stabbed into the pipeline and the pressure test was conducted through them. Instead of remaining on station during the hold period, the pump skid was freed to pressurize the next pipeline.

Twin 16-in. pipelines

Flooding, cleaning, and gauging the twin 147-km (91.3-mi) x 16-in. pipelines was done from a vessel at the shallow end of the 240-m to 1,700-m (782-ft to 5,576-ft) water depth run. In-line inspection surveys were conducted during flooding. A caliper tool was pumped to verify minimum bore followed by a UTMW tool to acquire the wall thickness baseline survey.

The inspection was followed by dewatering operations for all 5 km (3 mi) of the Tamar infield and tieback pipelines. Pipeline diameter and water depth required a pressure range of 170 to 235 bar (3,465 psi/17 MPa to 3,408 psi/23.5 MPa), which required specialized compression equipment. Weatherford's Temporary Air Compression Station (TACS) fleet provided sufficient compression power to complete the dewatering, MEG conditioning, and nitrogen purging in a single pigging operation.

The procedure eliminated additional post-dewatering pigging/purging, and left the pipelines ready to accept hydrocarbons. MEG batches between pigs in the dewatering train conditioned the post-dewatering residual water and prevented the formation of hydrates. Additional MEG was included for pipe wall desalination.

Denizen pumping skid with ROV reduced vessel time for subsea operations.

A novel approach was also used to dewater the 10-in. infield lines via the 16-in. tieback lines without using a downline or a second vessel. The tieback lines were packed to a higher gas pressure (232 bar/3,365 psi/23.2 MPa) than required for dewatering (170 bar). Later, the nitrogen in from these lines was directed through a manifold and set of jumpers to drive the pig trains in the 10-in. infield lines. Because the pig trains were launched earlier, no deepwater downline was required for MEG injection.

Dewatering efficiency was achieved by regulating pig speed using a stab-mounted orifice plate installed at the discharge end of each 10-in. infield line. Days of vessel time were saved by dewatering all five infield lines using the pressurized nitrogen contained in the long tieback lines.

UTWM line inspection

The cost of deepwater repair makes inspection accuracy critical to pipeline integrity assessment. An ultrasonic wall measurement (UTWM) baseline survey was performed on the 16-in. tieback using Weatherford's latest ultrasonic in-line inspection (ILI) tools.

Ultrasound non-destructive testing has been used for in-line inspection since the 1980s. The technology measures wall thickness based on ultrasound compression waves directed into the pipe wall. Ultrasonic transducers positioned 90° to the pipe wall use an impulse-echo mode to transmit an acoustic wave and to receive return echoes. The echoes represent the locations of the internal and external pipe wall, and metallurgical anomalies such as laminations. A UTWM baseline inspection identifies and classifies non-injurious signals such as mid-wall laminations and other mill-related anomalies.

Baseline corrosion survey

Accurate anomaly classification and sizing is valuable when comparing the baseline to future inspection data. Accuracy also enhances future integrity efforts such as engineering assessments and growth rates. It is important for deepwater subsea lines where normal onshore non-destructive examination validation practices are cost prohibitive. A higher level of accuracy is also important when assessing anomalies, assigning risk, and prioritizing maintenance and expenses.

Advanced ultrasonic inspection tool was used to examine pipeline integrity.

Compared to magnetic flux leakage (MFL) tools, ultrasonic technology results in better sizing accuracy in determining wall loss and pipe wall thickness. This is because ultrasonic pulse echo physics are a more direct measurement of wall loss. In some cases, however, MFL is a better solution because it can be more forgiving of dirt, debris, rough internal pipe surfaces, and waxy liquids. This necessitates a comprehensive pre-inspection assessment prior to selection of the appropriate technology.

Accurate measurement of wall thickness has a direct influence in calculating the failure pressure of a corrosion feature. Typical MFL tools do not measure wall thickness but infer it from API pipe specification, pipeline construction data, and/or estimated variations in the magnetic field. This provides a relative assessment due to pipeline data inaccuracies or difficultly obtaining data because of asset ownership transfers, unavailable data, or unrecorded pipeline reroutes and modifications.

In addition, inferred measurements do not consider wall thickness tolerances from the pipe mill. As a result, an MFL corrosion wall loss depth measurement depends on a relative measurement of the pipe wall. This decreases the sizing accuracy beyond the normal ILI tool sizing tolerance because, in addition to tolerances associated with the ILI tool anomaly sizing, there are also tolerances associated with the actual pipe spool wall thickness from the mill.

Acceptable tolerances from the mill can be as high as ± 10% for pipe wall thicknesses between 5 mm (0.2 in.) and 15 mm (0.6 in.) in welded pipeline. Tolerances for pipe walls greater than or equal to 15 mm are ± 15% in welded pipe. These pipe mill tolerances and the high corrosion-anomaly sizing tolerances of an MFL tool mean the calculated failure pressure from an ILI survey can be significantly over or under as the result of sizing inaccuracies caused by quantifying depths as a percentage of the assumed wall thickness.

More accurate corrosion sizing also provides better data to feed an assessment standard such as B31G, modified B31G, or RSTRENG effective area assessment, the preferred method for determining the remaining strength of the pipe. Of the three, RSTRENG effective area assessment is the most accurate, based on actual versus predicted burst pressure tests.

Experience demonstrates the occurrence of echo loss due to adverse pipeline conditions. New sensor technology in current UTWM devices helps enhance detection and accuracy. API 11636 engineering tests and field data analysis show improved sensitivity and reduced signal degradation, which is critical to a successful deepwater subsea baseline survey. The same sensor technology is used for in-line crack inspection with accurate sizing results that can be used for integrity assessments methodologies such as API 5797.

16-in. tieback inspection

In the Mediterranean operation, tight scheduling for the subsea launch presented a challenge for the 16-in. UTWM ILI inspections. Normally, there would have been sufficient battery life for the inspection tool run. However, in this case a delayed activation was needed because of the time needed for a subsea launch.

The ILI tool first had to be inserted into the pipeline launcher receiver (PLR) onboard the vessel. A vessel crane moved the launcher with the ILI tool to the pipeline end manifold (PLEM). A hydraulic lock secured the pipeline end termination (PLET) to the pipeline, and an ROV was used to turn the subsea valves and launch the pig.

The time-consuming process increased the risk of delays that could drain battery life and cause a failed run. As a result, a two-hour window was included for unforeseen delays. This safety factor led to programing a 12-hour delayed activation from the time the tool was inserted into the PLR onboard the vessel.

Sumber : 

http://www.offshore-mag.com/articles/print/volume-73/issue-12/flowlines-and-pipelines/innovation-enhances-deepwater-pipeline-pre-commissioning-and-inspection.html

Integrity Management of Pipline by DNV

A joint industry project led by DNV Energy is formulating guidelines for submarine pipeline system integrity monitoring. The resultant document of recommended practice, DNV RP-F116, will provide the oil and gas industry with a useful tool in an area where no such formal guidance currently exists, according to project manager Bente Helen Leinum.

The need to keep pipelines operating safely and efficiently is paramount in times of high oil prices, when financial losses resulting from downtime can mount rapidly. However, taking action can be a challenge. Many pipelines are aging but may be required to remain in operation, often beyond their design lifetime. Increased use of optimized design also implies the need for close monitoring.

Additionally, there is increasing pressure at the regulatory level. Authorities around the world are adopting a more proactive approach as they seek to minimize the risk of environmental harm resulting from pipeline leaks. This leads to stricter regulation and standards of integrity monitoring, and operators must be able to document compliance.

For companies operating internationally, the situation is not made easier by the fact that the regulatory situation can differ widely. In many countries there are few or no requirements, while in others the regulations can vary from prescriptive to functionally based, or combinations of the two.

Pipeline integrity management processes, taken from the updated code of pipeline design issued by DNV last year. Click here to enlarge image

However, while the need for integrity management is becoming stronger, there are often implementation difficulties. Many pipelines, especially older ones, were not designed to facilitate today’s proper monitoring and inspection. Moreover, many pipelines are unpiggable, making them impossible to inspect with an intelligent pig.

In practice, operators have had to come up with their own solutions for pipeline integrity monitoring. Many companies use API and/or ASME codes developed for onshore pipelines, combined with their own, often project-specific, pipeline integrity management systems.

DNV RP-F116 will therefore provide a reliable point of reference for both industry and authorities, helping to raise the standard of subsea pipeline integrity management. Companies also will be able to use their adherence to it when documenting their compliance with regulations. For authorities the document will hopefully provide a useful tool when they review their regulatory regimes.

The project grew out of the updated code for pipeline design, DNV OS-F101, which DNV issued last year, Leinum says. As part of this work, a small joint industry project (JIP) examined issues of pipeline integrity management and formulated minimum requirements for the safe and reliable operation of subsea pipelines. In the process, the participants became aware of the need for more detailed guidance.

When the current JIP was proposed, the number of interested participants soon made it a viable proposition. The sponsors include oil companies CNOOC, DONG Energy, Eni, Gaz de France, StatoilHydro, Norwegian pipeline operator Gassco, Norwegian research institute Sintef, to which some of the project tasks have been assigned, and DNV itself. The budget is NOK 2.8 million ($545,000).

In parallel, DNV’s Houston office is managing another JIP covering submarine pipeline integrity management in the Gulf of Mexico. The results from this work, for which the project manager is Dan Powell, also will be used as input to the development of DNV-RP-F116.

At present there are no regulatory requirements in the GoM. But in parallel with this industry initiative, the Minerals Management System (MMS) has declared its intention of introducing requirements, publishing draft proposals last fall.

The GoM JIP was prompted by one of DNV’s earlier studies for MMS in which it assessed the integrity practices of GoM operators. Among the findings was that only 5% of pipelines can accommodate inspection pigs, obliging operators to rely on informal risk-based approaches to integrity management, coupled with monitoring and preventive measures.

Oil companies should be involved in such projects, Leinum says – they are an important source of current practice, which will be reflected in the recommended practice (RP). DNV also has a wealth of experience to contribute from its own activities, much of it distilled in the many RP documents it has published with respect to pipelines.

Three main areas of integrity management have been identified:

• The establishment of integrity in the design-manufacturing-installation phase – there is growing awareness of this need within the industry, and it is becoming more common for oil companies to involve integrity personnel at the design phase
• The transfer of vital information from design to operation to ensure integrity of the pipeline during operation
• The maintenance of integrity in the operational phase – which is the main scope of the recommended practice.

Following the launch of the DNV RP-F116 project, a workshop staged in December 2007 resulted in an agreed framework for the RP. The first draft is due to be discussed at a workshop this month. Another workshop will follow in September, and a fourth this December to put its seal on the final draft.

This will be taken over as a formal DNV document, translated into the DNV template and sent out for external consultation. Depending on the number and complexity of comments which need to be accommodated, the final document should be published by May 2009.

Sumber : 

http://www.offshore-mag.com/articles/print/volume-68/issue-4/norway/dnv-promoting-improved-integrity-management-of-pipelines.html