Spiral Welded Pipes for Offshore Pipeline

Spiral welded pipes market, though encountering overcapacity conditions particularly in North America, is expected to witness steady growth in the upcoming years driven by the implementation of new pipeline projects. Investments in oil and gas exploration and production, which are influenced by prevailing crude oil & gas prices, have a considerable impact on the demand for spiral welded pipes and tubes. Resurgent world economy and consequent increase in the demand for industrial natural gas is expected to drive up momentum of the spiral welded pipes market.

Global demand for spiral welded pipes, which are primarily used in the transportation of oil and gas and in water transportation projects, is closely linked to the investments in the energy sector. The energy sector makes use of spiral welded pipes with diameters of up to 60” and up to 80 feet in length. Another factor that is expected to fuel demand for spiral pipes and tubes is new pipeline construction activity due to the shift of population from traditional centers that would necessitate development of infrastructure for delivering oil and natural gas to the new locations. Demand for spiral welded pipes is also expected from the replacement market, as most of the existing pipeline infrastructure, particularly in developed regions, has reached their end of useful life. Structural applications of spiral welded pipes are also gaining momentum, specifically with additional activity occurring in port, offshore loading and infrastructure improvement sectors.

As stated by the new market research report on Spiral Welded Pipes and Tubes, Asia-Pacific represents the largest market worldwide, driven primarily by increased use in transporting natural gas. Besides Asia-Pacific, Latin America ranks among the fastest growing regional markets with compounded annual growth rate ranging between 7.5% and 9.0% over the review period. North American market, on the other hand, is encountering testing times owing to weak demand and overcapacity conditions. Oversupply is the major concern for spiral welded pipes market particularly with regard to large diameter double submerged arc welded or DSAW line pipes, which finds use in transmitting oil, natural gas liquids, and natural gas to consumers from drilling locations.

Despite the prevailing conditions, potential opportunities are expected primarily from the implementation of new pipeline projects in the upcoming years, resurgent growth of the US economy, and increased demand from natural gas exploration operations. Also, overcapacity conditions are expected to fade away in the coming years, as several megaprojects are set to be taken up across the world, particularly in regions such as Southeast Asia, Australia, Middle East, Africa, and West Asia.

Replacement of aging infrastructure offers huge potential for pipe manufacturers. The need to replace old pipelines is particular high in the US and Russia, where pipeline networks were mostly installed during the 60s and 70s. With the average lifespan of oil and gas transportation pipes ranging between 25 and 30 years, opportunities in the replacement market are huge, particularly for HSAW pipes. In the US, replacement demand holds enormous potential as a result of the recent enactment of the legislation that necessitates more inspections to be carried out, which could increase the likelihood of pipeline replacements. The Act is likely to play a critical role in enabling manufacturers of large diameter line pipes to survive the tough economic and overcapacity conditions.

Major players profiled in the report include American SpiralWeld Pipe Company LLC, ArcelorMittal SA, Borusan Mannesmann Boru Sanayi ve Ticaret A.S., Europipe GmbH, EVRAZ North America, JFE Steel Corporation, Jindal SAW Ltd., Man Industries Ltd., National Pipe Company Ltd., Nippon Steel & Sumitomo Metal Corporation, PSL Limited, Shengli Oil & Gas Pipe Holdings Limited, Stupp Corporation, Volzhsky Pipe Plant, UMW Group, and Welspun Corp Ltd.

The research report titled “Spiral Welded Pipes and Tubes: A Global Strategic Business Report” announced by Global Industry Analysts Inc., provides a comprehensive review of market trends, issues, drivers, company profiles, mergers, acquisitions and other strategic industry activities. The report provides market estimates and projections for all major geographic markets including the US, Canada, Japan, Europe (France, Germany, Italy, UK, Spain, Russia and Rest of Europe), Asia-Pacific (China and Rest of Asia-Pacific), Middle East, and Latin America.

Source:

http://www.prweb.com/releases/spiral_welded_pipes_tubes/DSAW_HSAW_pipes/prweb10402550.htm

Horizontal Directional Drilling

Directional drilling has been an integral part of the oil and gas industry since the 1920s. While the technology has improved over the years, the concept of directional drilling remains the same: drilling wells at multiple angles, not just vertically, to better reach and produce oil and gas reserves. Additionally, directional drilling allows for multiple wells from the same vertical well bore, minimizing the wells' environmental impact.

Directional Drilling

Source: Amerex Co.

Improvements in drilling sensors and global positioning technology have helped to make vast improvements in directional drilling technology. Today, the angle of a drillbit is controlled with intense accuracy through real-time technologies, providing the industry with multiple solutions to drilling challenges, increasing effi-ciency and decreasing costs.

Tools utilized in achieving directional drills include whipstocks, bottomhole assembly (BHA) config-urations, three dimensional measuring devices, mud motors and specialized drillbits.

Now, from a single location, various wells can be drilled at myriad angles, tapping reserves miles away and more than a mile below the surface.

Directional Drilling

Source: Mackenzie Gas Project

Many times, a non-vertical well is drilled by simply pointing the drill in the direction it needs to drill. A more complex way of directional drilling utilizes a bend near the bit, as well as a downhole steerable mud motor. In this case, the bend directs the bit in a different direction from the wellbore axis when the entire drillstring is not rotating, which is achieved by pumping drilling fluid through the mud motor. Then, once the angle is reached, the complete drillstring is rotated, including the bend, ensuring the drillbit does not drill in a different direction from the wellbore axis.

One type of directional drilling, horizontal drilling, is used to drastically increase production. Here, a horizontal well is drilled across an oil and gas formation, increasing production by as much as 20 times more than that of its vertical counterpart. Horizontal drilling is any wellbore that exceeds 80 degrees, and it can even include more than a 90-degree angle (drilling upward).

Source:

http://www.rigzone.com/training/insight.asp?insight_id=295&c_id=1#sthash.ssejQCFt.dpuf

Fitness For Service: Important Basis for Oil and Gas Industry

Fitness for Service (FFS) is a well known and important concept in the oil & gas, chemical, petrochemical, and other process industries. Fitness for service is the ability to demonstrate the structural integrity of an in-service component even though it contains a flaw. It serves as a rational basis for defining flaw acceptance limits, and allows engineers to distinguish between benign and dangerous flaws.

The FFS of any particular material is determined by performing a fitness for service assessment. Performing accurate FFS evaluations is an integral aspect of fixed equipment asset integrity management. On the other hand, failing to perform evaluations can lead to equipment failures which can further result in injury, loss of life, and severe financial and economic consequences.

The reason these examinations are performed is because even if a piece of equipment has a crack or other defect, this doesn’t necessarily mean that it’s unfit for service. Most equipment can continue in service despite small flaws, and to repair or replace equipment that can still be used would be an unnecessary and costly expense. Not only that, but unnecessary weld repairs can actually do more harm than good, as the quality of the new weld can often be less than the original one.

There are several ways to see if a flaw can cause a piece of equipment to be no longer fit for service. For cracks, fracture mechanics provides the mathematical framework for the examination by quantifying combinations of stress, flaw size, and fracture toughness.

While cracks tend to be the most dangerous, they’re not the only flaw that might warrant evaluation. Volumetric flaws such as corrosion pits, porosity, and slag may reduce the load-bearing capacity of a structure. Likewise, structural integrity may also be compromised by locally thinned areas which come grinding out cracks, thus FFS methodologies have been developed to evaluate local thinning. In these cases, acceptance criteria are based on limit load analyses rather than fracture mechanics models. Some examples of these different FFS methodologies are the BS 7910 method, API RP 579-1/ASME FFS-1 method, and the MPC/AP method.

It is important to note though that FFS evaluation can’t provide an absolute delineation between safe and unsafe operating conditions. Uncertainties in input parameters such as stress, flaw size, and toughness often lead to a large uncertainty in the prediction of the critical conditions for failure. In general there are two ways to address this uncertainty. The more traditional approach has been to use conservative input values in a deterministic analysis. The result of such an analysis is a pessimistic prediction of critical flaw size or remaining life.

An alternative approach, one which is becoming more common, entails performing a probabilistic analysis that incorporates the uncertainties in the input data. The latter type of analysis does not result in an absolute yes/no answer as to whether or not a structure is safe for continued operation. Rather, a probabilistic analysis estimates the relative likelihood of failure, given all of the incorporated uncertainties. Probabilistic FFS analysis can be an integral part of a risk-based inspection (RBI) protocol, where inspection is prioritized according to the risk of significant injury or economic loss.

Source:

https://inspectioneering.com/tag/fitness+for+service

Soil and Pipeline Interaction Analysis Using Finite Element Method

Offshore pipelines laid on the seabed are exposed to hydrodynamic and cyclic operational loading. As a result, they may experience on-bottom instabilities, walking and lateral buckling. Finite element simulations are required at different stages of the pipeline design to check the different loading cases. Pipeline design depends on accurately modelling axial and lateral soil resistances. 

 

Conventional pipeline design practice is to model the interaction between the pipe and the seabed with simple “spring-slider” elements at intervals along the pipe, as finite element methods with elaborated contact and interface elements between the pipeline and the foundation do not allow for comprehensive modeling of long pipeline systems with current computational power (Tian et al, 2008). These “spring-slider” elements provide a bi-linear, linear-elastic, perfectly plastic response in the axial and lateral directions. The limiting axial and lateral forces are based on empirical friction models, which relate axial and lateral resistance to the vertical soil reaction by using a “friction factor”. In the vertical direction, a non-linear elastic load embedment response derived from bearing capacity theory is usually assumed, the pipeline being treated as a surface strip foundation of width equal to the chord length of pipe-soil contact at the assumed embedment.

These simple models can be adequate for sand but are too simplistic for clay, especially soft clay. Due to the slow rate of consolidation of clay, a total stress approach using an undrained shear strength s_u should be employed. In this case, the axial and lateral resistances do not directly depend on the vertical soil reaction but on the contact area between the pipe and the seabed. As a result, an accurate prediction of the pipeline embedment, which can be large in very soft cay, becomes of primary importance. 

 

These simple models were improved to better predict pipeline embedment and axial and lateral resistances and were implemented in a Finite Element software program for pipeline analysis to better simulate the pipe-soil interaction of surface laid pipelines in soft clay and to more accurately simulate full routes. The new features are briefly explained in this paper. A more recent pipe-soil vertical reaction law that models plastic unloading is built into the program. It considers lay and dynamic installation effects to compute a more representative pipeline embedment. Axial and lateral resistance is now linked to pipeline embedment. 

Finally, peak-residual axial and lateral reaction laws are implemented.

Vertical reaction law 

 

Solutions for estimating the resistance profile have been provided by Murff et al. (1989), Aubeny et al. (2005) and Randolph & White (2008). The pipeline penetration z may be estimated from the conventional bearing capacity equation, modified for the curved shape of a pipeline:

where V is the vertical load per unit length, D is the pipeline diameter, s_u the undrained shear strength at the pipeline invert and A_s the nominal submerged area of the pipeline crosssection. For design, the bearing capacity factor N_c can be estimated using rounded values of the power law coefficients a and b, for example a = 6 and b = 0.25 (Randolph & White, 2008). Buoyancy has an influence in extremely soft soil conditions. This is captured by the buoyancy factor Nb. The factor f_b should be taken equal to 1.5 because of heave (Randolph

& White, 2008).

The accuracy of this calculation approach, of the order of +/- 10%, is sufficient given the other uncertainties such as the installation effects, which influence the vertical load V (see below) (White & Randolph, 2007).

Installation effects 

During installation of a pipeline, the vertical and horizontal motion of the lay barge and the load concentration at pipe touch-down will yield larger penetration than calculated based on the pipe submerged unit weight. The load concentration can be taken into account by multiplying the pipe weight by an amplification factor flay as proposed by Bruton (2006). In order to take into account the effect of pipe motion during installation, a partially remoulded shear strength can be used to compute the pipe embedment, as proposed by Dendani & Jaeck (2007), instead of the intact strength. These features combined with the vertical reaction law described above allow predicting a more realistic pipeline embedment, which is of primary importance to compute a realistic axial and lateral resistance.

Plastic unloading

A non-linear elastic load embedment response is conventionally assumed for the vertical soil spring. However, it is essential to model a spring as behaving plastically to avoid predicting an unrealistic rebound when the pipe is unloaded. In practice, a pipe is often overpenetrated, meaning that its operating weight is lower than the maximum vertical force that had been applied to it. In effect, it has been unloaded. It is important to model a spring with plastic behaviour and “memory” to calculate the appropriate vertical soil stiffness. The behaviour of an over-penetrated pipe can be described by the stiff unload-reload line. When reloaded to its normally-penetrated range, the pipe’s behaviour can be described as following the virgin load embedment curve. This is illustrated in the example below and in Figure 1. Let us first consider an elastic spring. During installation, the pipe moves to A1 due to load concentration and then rebounds to A2, to a vertical displacement corresponding to its submerged empty weight. During the hydrotest, the vertical force increases and the pipe moves to B. During operational conditions, if the content is lighter than water, the pipe is unloaded to point C. The pipe embedment and the tangent stiffness at this point are not realistic. In the case of an elasto-plastic spring, the pipe goes to A1 during installation and then to A2* following an unload-reload line. During the hydrotest, the vertical force increases to B* along the unload-reload line. Finally, the pipe is unloaded to C*. At this point, the pipeline embedment and the tangent stiffness are more realistic. 

An accurate pipe embedment is especially important when it is coupled to axial and lateral resistance (see next Section).

Figure 1 – Behaviour of non-Linear Elasto-Plastic Vertical Springs

Coupling of axial and lateral resistance with pipeline embedment

The axial and lateral resistances depend on the contact area between the pipe and the seabed and thus the pipe embedment, when a total stress approach is followed. The formula used to compute peak axial and lateral resistances Fpa and Fpl are in the form:

where αs_u is the unit interface shear resistance, Ac is the area of contact between the pipe and the seabed which is a function of the pipe embedment z, μ is a “friction factor” in the range 0.2-0.8 (Randolph & White, 2007) and λ a coefficient typically in the range 0.5-2. The axial and lateral resistances have been linked to the pipeline embedment so that they are automatically calculated and can change during the analysis.

Tri-linear axial and lateral model

Models of the simple bi-linear frictional axial and lateral springs were improved so they can use peak and residual resistances to model the softening of the axial and lateral response often observed in clay. As explained earlier, pipelines are often over-penetrated in practice. When this occurs in soft clay, lateral breakout resistance Fpl, is high and drops sharply when suction at the rear face of the pipe is lost, then decreases further to a residual value Frl as the pipe rises to a shallower embedment. When the residual resistance is reached, the lateral resistance may increase again because a soil berm forms in front of the pipe (see Figure 2). The axial resistance may experience strain softening as well due to suction release and clay remoulding.

Figure 2 – Tri-linear Lateral Resistance Model

Conclusions

Simple soil models conventionally used in pipeline design practice have been improved and implemented in a Finite Element software program for pipeline analysis. There are several improvements. A more recent pipe-soil vertical reaction law that models plastic unloading is built into the program. It considers lay and dynamic installation effects to compute a more representative pipeline embedment. Axial and lateral resistance is now linked to pipeline embedment. Finally, peak-residual axial and lateral reaction laws have been implemented.

The new features are basic but important first steps towards more accurate full route simulations, especially those in soft clay.

Source:

Ballard, Jean-Christophe, Hendrik Falepin, Jean-François Wintgens. 2009. “Towards More Advanced Pipe-Soil Interaction Models in Finite Element Pipeline Analysis”. Belgium: Fugro.

Pipeline Hydro Test Pressure Determination

Hydrostatic testing has long been used to determine and verify pipeline integrity. Several types of information can be obtained through this verification process.

However, it is essential to identify the limits of the test process and obtainable results. There are several types of flaws that can be detected by hydrostatic testing, such as:

• Existing flaws in the material,
• Stress Corrosion Cracking (SCC) and actual mechanical properties of the pipe,
• Active corrosion cells, and
• Localized hard spots that may cause failure in the presence of hydrogen.

There are some other flaws that cannot be detected by hydrostatic testing. For example, the sub-critical material flaws cannot be detected by hydro testing, but the test has profound impact on the post test behavior of these flaws.

Given that the test will play a significant role in the nondestructive evaluation of pipeline, it is important to determine the correct test pressure and then utilize that test pressure judiciously, to get the desired results.

When a pipeline is designed to operate at a certain maximum operating pressure (MOP), it must be tested to ensure that it is structurally sound and can withstand the internal pressure before being put into service. Generally, gas pipelines are hydrotested by filling the test section of pipe with water and pumping the pressure up to a value that is higher than maximum allowable operating pressure (MAOP) and holding the pressure for a period of four to eight hours.

ASME B 31.8 specifies the test pressure factors for pipelines operating at hoop stress of ? 30% of SMYS. This code also limits the maximum hoop stress permitted during tests for various class locations if the test medium is air or gas. There are different factors associated with different pipeline class and division locations. For example, the hydrotest pressure for a class 3 or 4 location is 1.4 times the MOP. The magnitude of test pressure for class 1 division 1 gas pipeline transportation is usually limited to 125% of the design pressure, if the design pressure is known. The allowed stress in the pipe material is limited to 72% of SMYS. In some cases it is extended to 80% of SMYS. The position of Pipeline and Hazardous Material Safety Administration (PHMSA) is similar. Thus, a pipeline designed to operate continuously at 1,000 psig will be hydrostatically tested to a minimum pressure of 1,250 psig.

Based on the above information, let us consider API 5L X70 pipeline of 32-inch NPS, that has a 0.500-inch wall thickness. Using a temperature de-rating factor of 1.00, we calculate the MOP of this pipeline from following:

P= {2x t x SMYS x1x factor (class1) x 1} / D (ASME B 31.8 Section, 841.11)

Substituting the values:

P= 2x 0.5 x 70,000 x1 x0.72 x1/32 = 1,575 psig

For the same pipeline, if designed to a factor of 0.8, the MOP will be computed to be 1750 psig.

• If the fittings were the limiting factors of the test pressure, then the following situation would arise.
• If the fittings used in the system are of ANSI 600 then the maximum test pressure will be (1.25 x 1,440) 1,800 psig. This test pressure will support the requirements of both factor 0.72 and 0.8.
• If, however, ANSI 900 fittings were chosen for the same pipeline system, the test pressure (1.25 x 2,220) 2,775 psig would test the pipeline but would not test the fittings to their full potential.

Let us first discuss the design factor of 0.72 (class1). In this case the test would result in the hoop reaching to 72% of the SMYS of the pipe material. Testing at 125% of MOP will result in the stress in the pipe reaching a value of 1.25 x 0.72 = 0.90 or 90% of SMYS. Thus, by hydrotesting the pipe at 1.25 times the operating pressure, we are stressing the pipe material to 90% of its yield strength that is 50,400 psi (factor 0.72).

However, if we use a design factor of 0.8 – as is now often used – testing at 125% of MOP will result in the stress in the pipe to 1.25 x 0.8 =1. The stress would reach 100% of the yield strength (SMYS). So, at the test pressure of 1800 psig the stress will be 56,000 psi (for factor 0.8). This will be acceptable in case of class 600 fittings. But, if class 900 fittings were taken into account, the maximum test pressure would be (1.25 x 2,220) 2,775 psig and the resulting stress would be 88,800 psi which will be very near the maximum yield stress (90,000 psi) of API 5L X 70 PSL-2 material.

Test Pressure And Materials SMYS

Though codes and regulatory directives are specific about setting test pressure to below 72% or in some cases up to 80% of the SMYS of the material, there is a strong argument on testing a constructed pipeline to “above 100% of SMYS,” and as high as 120% of SMYS is also mentioned. Such views are often driven by the desire to reduce the number of hydrotest sections, which translates in reduction in cost of construction. In this context, it is often noted that there is some confusion even among experienced engineers on the use of term SMYS and MOP/MAOP in reference to the hydrotest pressure.

It may be pointed out that the stress in material (test pressure) is limited by the SMYS. This is the law of physics, and is not to be broken for monetary gains at the peril of pipeline failure either immediate or in the future.

In this regard, section 32 of directive No. 66 of the Alberta Energy and Utilities Board in 2005 is of importance. The guidance is specific about the situation. It directs that if the test pressure causes hoop stress in the material exceeding 100% of the material SMYS, then the calculation and the entire hydro test procedure needs to be submitted to the board for review and approval.

Stress Relieving And Strength

Often there is argument presented that higher test pressures exceeding 100% of the SMYS will increase the “strength” of the material and will “stress relieve” the material. Both arguments have no technical basis to the point they are made. We will briefly discuss both these arguments here:

1. Higher test pressure will “increase the strength.” As the material is stressed beyond its yield point, the material is in plastic deformation stage, which is a ductile stage, and hence it is in the constant process of losing its ability to withstand any further stress. So, it is not increasing in strength but progressively losing its strength.

2. The second argument of “stress reliving” is linked with the “increase the strength” argument. The stress relief of material is carried out to reduce the locked-in stresses. The process reorients the grains disturbed often by cold working or welding. The stress relief process effectively reduces the yield strength. Thus, it does not “strengthen” the material. Note: It may be pointed out that a limited relaxation of stresses does occur by hydro testing, but the test pressure should be less than the material’s yield point.

Another point to note here is that there is a stage in the stressing of the material where strain hardening occurs and the material certainly gains some (relative) hardness, and thereby, strength. This happens as necking begins but, at that point, unit area stress is so low that the strength of the material is lost and it remains of no practical use, especially in context with the pipe material we are discussing.

Returning to the subject of pressure testing and its objectives. One of the key objectives of the testing is to find the possible flaws in the constructed pipeline. The test develops a certain amount of stress for a given time to allow these possible flaws to open out as leakages. In the following section we shall discuss the relation of these flaws to the test pressure and duration.

Critical Flaw Size

The maximum test pressure should be so designed that it provides a sufficient gap between itself and the operating pressure. In other worlds, the maximum test pressure should be > MOP.

This also presupposes that after the test the surviving flaws in the pipeline shall not grow when the line is placed in service at the maintained operating pressure. For setting the maximum test pressure, it is important to know the effect of pressure on defect growth during the testing on the one hand and on the other flaws whose growth will be affected by pressure over the time.

The defects that would not fail during a one-time, high test pressure are often referred as sub-critical defects. However these sub-critical defects would fail at lower pressure if held for longer time. But the size of discontinuity that would be in the sub-critical group would fail-independent of time-at about 105% of the “hold” pressure. This implies that maximum test pressure would have to be set at 5-10% above the maximum operating pressure (MOP) in order to find such defects during the test and also to avoid growth of sub-critical discontinuities after the hydro test pressure is released and during the operation life of pipeline. This is should be the main objective of the hydro test.

If test pressure reaching 100% (design factor of 0.80) of the SMYS is considered, then one must also consider some important pre conditions attached to the procurement of the steel and pipe. Especially important to consider is the level of flaw size that was accepted in the plate/coil used to manufacture the pipe. The test pressure of such magnitude would require that the acceptable defect size be re-assessed. This is because all else being equal, a higher design factor, resulting in a thinner wall, will lead to a reduction in the critical dimensions of both surface and through-wall defects.

Where such conditions are likely it may be prudent to reconsider the level of accepted flaws in the material. The current recommendations in API 5L 44th edition for acceptance level B2 as per ISO 12094 (for SAW pipes) may not be acceptable because it has limited coverage of body and edges and the acceptance criteria is far too liberal, in terms of acceptable size and area of flaws. More stringent criteria must be specified more in line with EN 10160 where level S2 for body and level E2 for edges may be more appropriate to meet the demands of the higher test pressures.

Sub-critical surface flaw sizes at design factors of 0.80 and 0.72 are susceptible to growth at low stress and are time dependent. These flaws are also dependent on the acceptable limits of impact absorbing energy of the material and weld (not part of the discussion in this article).

This increase in depth-to-thickness (d/t) ratio in effect reduces the ligament of the adjoining defects that reduce the required stress to propagate the discontinuity. Critical through-wall flaw lengths are also factors to be assessed. While there is a modest reduction in critical flaw length, it still indicates very acceptable flaw tolerance for any practical depth and the reduction will have negligible influence in the context of integrity management. Note that flaws deeper than about 70% of wall thickness will fail as stable leaks in both cases. This statement implies that mere radiography of the pipe welds (both field and mill welds) may not suffice. Automatic ultrasonic testing (AUT) of the welds will be better suited to properly determine the size of the planer defects in the welds. Similarly the use of AUT for assessing the flaws in the pipe body will be more stringent than usual.

Pressure Reversal

The phenomenon of pressure reversal occurs when a defect survives a higher hydrostatic test pressure but fails at a lower pressure in a subsequent repressurization. One of the several factors that work to bring on this phenomenon is the creep-like growth of sub-critical discontinuities over time and at lower pressure. The reduction in the wall thickness, caused by corrosion, external damages, is also responsible for a reduction in puncture resistance in the pipe. The reduction in the wall thickness, in effect reduces the discontinuity depth to the material thickness.

This increase in d/t ratio reduces the ligament between the adjoining defects. This effectively reduces the stress required to propagate the discontinuity. The other factor affecting the pressure reversal is the damage to the Crack Tip Opening (CTO). The CTO is subject to some compressive force leading the crack tip to force-close during the initial test. On subsequent pressurization to significantly lower pressure this “force-close” tip starts to open-up and facilitates the growth of the crack. Hence, if such a pressure cycle is part of the design, then the point of pressure reversal should be considered.

Puncture Resistance

• It may also be noted that there is a modest reduction in puncture resistance with both increasing SMYS and increasing design factor. Note that the maximum design factor is, in some instances, constrained by practical limits on D/t.
• In any event, it should be noted that only a small proportion of large excavators are capable of generating a puncture force exceeding 300 kN and that the reductions in puncture resistance noted would have to be assessed for the integrated approaches to the management of mechanical damage threats.

Author

Ramesh Singh is Senior Principal Engineer (Materials, Welding and Corrosion) for Gulf Interstate Engineering, 16010 Barkers Point Lane, Houston, Texas.

Source:

http://pgjonline.com/2009/12/17/pipeline-hydro-test-pressure-determination/

Pipeline Inspection

External scanning of pipelines traditionally is undertaken by divers who require support vessels. AGR Group’s Neptune system, however, provides inspection without diver intervention and associated availability issues and depth limitations.

Neptune combines an external state-of- the-art ultrasound scanner with a small ROV. The system can be mobilized anywhere in the world to examine and predict the remaining life of subsea tubulars. The system delivers high-resolution ultrasonic data in real time, which is used to underpin the detailed finite element analysis (FEA) calculations used in industry-standard, fitness-for-service (FFS) determinations.

 

Figure 1: AGR’s Neptune pipe inspection tool undergoing deployment

The neutral buoyant Neptune system, weighing 150 kg (331 lb) in air but neutrally buoyant in water, is deployed via an inspection class ROV to the work site. The scanner comprises a hydraulically opening and closing twin collar, 600-mm (23.6-in) wide construction containing a fully automated X-Y scanner. This clamshell construction is self-aligning to allow rapid installation by the ROV.

Self-centering rams within the clamshell hold the scanner firmly on the pipe, creating a stable platform for the X-Y probe carriage. The probe carriage has an axial range of 500 mm (20 in.) and a circumferential movement of over 360º. It is configured to deploy Time of Flight Diffraction (TOFD) transducers for volumetric weld inspection, and compression wave transducers to perform color graphic material mapping.

The historic restriction of analogue data transmission has been removed by locating the AGR Technology Design ultrasonic digital flaw detector on the Neptune scanner. This allows the inspection data to be digitized and processed at the subsea worksite, then sent through the ROV umbilical to be viewed in real time on the surface.

Currently, the Neptune system is configured to operate in water depths of up to 1,000 m (3,280 ft), but this could be extended. The system’s ultimate working or depth range is equivalent to the ROV umbilical length: some ROVs today operate to a range of 6,000 m (19,685 ft).

The ROV pilot and Neptune operator sit together during operations to ensure optimum operational interface. The objective of any examination performed with the Neptune system is to obtain high quality graphical images of parent material, welds, and adjacent HAZ material.

As the probe carriage rasters around the pipe, the data is stored and viewed in real time for both mapping and weld inspection. In TOFD mode, the two transducers straddle the weld at a pre-set standoff to allow volumetric imaging of the weld in one pass.

There are a multitude of ROVs in service around the world, hence the importance of being able to interface mechanically and electronically with any type of inspection class ROV. The size and weight of the self-contained Neptune system allow deployment from, small supply vessels or fixed offshore installations to monitor risers and caissons.

The system also can check pipeline areas following subsea impact, anomaly verification and quantification following IP runs, and to assess potential hot-tap locations. In its current configuration the double-collar scanner is ideal to examine straight pipe and upstream and downstream of bends.

 

Figure 2: Close-up of Neptune system

The examination is performed on production pipelines from the external surface. The cleaner the surface, the higher quality the resulting images. Thanks to an existing range of cleaning, excavation, and dredging options, some residing within the AGR group, each proposed inspection site can be addressed individually to optimize the data quality.

Gaining direct access to the pipeline wall may be difficult if the line is concrete-coated, buried, or rock-dumped. In such cases, internal inspection techniques may offer a more cost-effective solution, which AGR again can address via its suite of inspection tools.

Neptune’s current inspection diameter range is 12-18-in. (30-46 cm), with plans to build both smaller and larger diameter collars deploying the same techniques. There are further plans to use the system’s scanner as a platform for other techniques such as ACFM, eddy current, and phased array.

AGR embarked on the development of this technology in the mid 1990s aiming to inspect pipelines not designed for pigging. There are a number of reasons why such services may be required. Many non-piggable lines have reached the limit of their design life, so their integrity needs to be demonstrated if they are to remain in operation.

Again, operators in general are giving greater priority to ensuring the integrity of their pipelines, of any age. Production downtime resulting from loss of a pipeline due to corrosion or a defective weld more than outweighs the cost of regular inspection. And operators also find themselves facing more stringent regulations as authorities seek to avoid environmental damage from pipeline leaks.

Crack detection

Demand has grown for internal and external inspection of pipelines and welds the past year. Last fall, AGR introduced Claycutter X, a technology to excavate the sea bottom and to remove soil from old pipelines. AGR plans to provide the Neptune Subsea Inspection system and Claycutter X as a package to combine excavation, examination, and recovering.

Another development is the WeldScan tool, which the AGR PipeTech division says it aims to promote in the Gulf of Mexico and West Africa. To date the system has been applied only in the Norwegian sector of the North Sea.

 

Figure 3: A pipeline inspection train is readied, with AGR’s pipe Intruder, which supplies the motive force, at the front.

Like its predecessor PipeScan, WeldScan is equipped with ultrasonics to measure wall thickness and to detect weld defects. However, using TOFD takes accuracy to new levels, capable of detecting cracks in welds of less than a millimeter for both width and depth. In other words, cracks can be identified much earlier.

This meets the needs of increasing application of exotic and high-grade steels in pipelines and risers to cope with multiphase flows and corrosive wellstreams. These materials are often difficult to weld, so regular monitoring of welds is required.

The move into deeper waters also places a premium on reliable integrity monitoring techniques, i.e. for inspecting steel catenary risers which are exposed to severe loadings.

WeldScan has proved its worth in examining pipelines made of high-grade steel – in this case 13% chrome – in a number of assignments carried out for an operator in the Norwegian sector.

AGR also has developed a method to transport its inspection tools through the pipeline. This is self-propelled pig, known as PipeIntruder, incorporates a seal disc with an internal bypass. Water is pushed through the seal disc by a pump at the front, creating back-pressure to push the tool forward. Pumping can be reversed, sending the tool backwards.

An odometer wheel tracks PipeIntruder’s position in the pipeline. The tool also has axial and circumferential motors to position WeldScan alongside a weld with ±1mm (0.04 in.) axial accuracy. Video cameras monitor this operation. Data from WeldScan is transmitted to the surface via fiber-optic cable in real time.

The PipeIntruder is available for pipe diameters from 8-30 in. (20.3-76.2 cm). Above 30 in. (76 cm), electro-hydraulic tractors are available. The pig hauls all combinations of inspection tools, and can travel up to 10 km (6.2 mi), the maximum range of the umbilical winch.

The string made up of the PipeIntruder and inspection tools is inserted into the pipeline at the host platform. The tools can be used to inspect other tubular structures such as risers, J-tubes, and loading lines.

Source :

http://www.offshore-mag.com/articles/2008/04/new-depth-independent-high-resolution-subsea-pipeline-inspection-tool-released.html

Flexible Pipeline

Upstream oil industry bias has always favored use of steel pipe. Despite some disadvantages, it can be manufactured to meet almost any pressure requirement at almost any size. And, more importantly, steel is considerably less expensive than its composite material rival known as flexible pipe. As a result, particularly on land installations, flexible pipe until recently has usually used only been used in low-pressure or temporary installations.

But in the 1980s, the oil industry began to look at doing business in extreme water depths and at using floating production platforms to process and store oil in areas where there was no pipeline infrastructure. Within this new environment, flexible pipe became a high demand item as floating production, storage and offloading (FPSO) ships and semisubmersibles quickly became the deepwater industry production installation of choice, first in Brazil and Southeast Asia and later off the coast of West Africa.

Flexible pipe holds two very strong attractions as risers for floaters. First it is considerably lighter than rigid pipe and is neutrally buoyant. That means the vessel's limited space and buoyancy capabilities can be used for storage capacity or topsides processing facilities rather than to support thousands of feet of heavy steel pipe.

But even more attractive for floating vessels subject to considerable vertical movement, or heave, is flexible pipe's bending capabilities. Without that defining characteristic of the pipe the vessel would be unable to move more than minimally and few if any days in a given year would be sufficiently calm to allow production.

Flexible pipe also became a deepwater staple because since it is installed from a reel on the back of a ship with connections made in advance on the deck, the need for divers or remotely operated vehicles to perform that task is eliminated. Consequently it can be installed in substantially less time than traditional rigid pipe and in deep water, time is big money. According to the literature of one leading vendor, installation rates for flexible pipelines often exceed 1500-ft per hour.

As a consequence of these technical advantages, by the end of the 1980s, flexible pipe was being qualified and installed in more than 3,000-ft waters, mostly as FPSO risers. Today, manufacturers of flexible pipe, essentially a composite of two or more different materials working in concert to provide specific characteristics, are preparing to install their wares in water depths of greater than 6,000 ft.

And as with nearly all technologies, the ultra deepwater presents challenges to flexible pipe that are yet to be met, among them pipe lightening and flow assurance.

Lightening the pipe(Return to Contents)

For the most part, the industry has engaged in two approaches to reducing the weight of flexible pipe. The first is to simply optimize pipe design for the service and water depth environment in which it will work. Simply put that means installing the lightest pipe possible within carefully calculated safety margins. But that is, at most, a short-term approach.

The second, more general method is to replace the traditional steel exterior known as "tensile armor" whose function is to supply collapse resistance, with one made of much lighter composite material in the upper sections of the pipe (where it will be subject to less water-induced collapse pressure).

"At the moment we are seeking industry participation in that effort," said one flexible pipe expert whose company is currently testing operator interest in such a joint interest project. "Right now the cost of composites is much higher than steel but as the cost of composite manufacturing goes down it will probably become competitive."

But, he says, even when composites become competitively priced, due to their inability to handle compression, they will not likely be used near the seabed where wave action would subject them to considerable compressive loads.

Flow assurance

In many areas of the world, increasing depth means increasing pipeline distance from seafloor wellhead to production riser. This means produced oil, gas and water must travel considerable distances through pipes run along the ocean floor bathed in near-freezing water.

As the production flows, it cools and at some point crosses that pressure-temperature point known as the "cloud point" where asphaltines, or wax, forms on the pipe walls. Likewise when water and gas are present in the flow stream, hydrates can form. In either case, the ensuing blockage can and often does stop fluid flow altogether.

Click Here to See Flexible Pipe Advances

In shallower waters this problem, known in the industry as "flow assurance", is fairly well under control through the use of chemicals injected into the flow line at the well head and through the use of insulated pipe. But such measures are not likely to work over the many miles of pipeline running from wellheads located in up to 12,000-ft waters as are now being contemplated.

Flexible pipe manufacturers are now working on flow assurance problems via several avenues, including re-circulating fluid to heat the pipe and by introducing electric current to the pipe in a process called direct resistance heating. Each, still in the development stage, has drawbacks and advantages.

The key advantage to sending currents of electricity down the flexible pipe is efficiency. Since it is comprised of composite and steel fibers, it will act as a resistor and convert electrical energy to heat.

"I think [direct resistance heating] is more desirable for a couple of reasons," said Halliburton's Mark Kalman, whose company, Wellstream, came to Halliburton via the Dresser merger. "When you use electricity the heating is uniform. That is how resistors work.

"A definite disadvantage when you are circulating fluid is as you give up heat you give up temperature and so the temperature difference goes down and so your heat input is going to be reduced."

But there are considerable problems with providing a constant electrical charge to long sections of pipe. "One of the drawbacks to electrical heating is you are talking about a substantial consumption of power," Kalman said. "You would have to have facilities to provide that. You can't just plug in the wall when you are offshore."

One other avenue of research, receiving less attention from flexible pipe manufacturers than from other researchers engaged in general composite materials development, is to develop better-performing insulation materials. But though they hold promise, say the experts, to date those materials that might meet the requirement of such a harsh environment are still prohibitively expensive.

Underbalanced drilling

Flexible pipe today may hold the key to overcoming one of offshore drilling's greatest ultra deepwater hurdles caused by the close proximity of fracture gradient and pore pressure in deepwater. Beyond about 7,500-ft waters, this phenomenon makes traditional well control all but impossible because, simply put, mud sufficiently heavy to contain formation pore pressure is also very nearly sufficiently heavy to fracture it and one fluctuation will indeed do that.

One solution to the problem may lie in underbalanced drilling, a practice not yet possible from floating drilling units because the slip joint on the riser that allows for rig heave cannot handle any pressure at all. And when drilling underbalanced pressure is always present on the riser annulus.

A joint interest project being field tested now in Brazil is using flexible pipe to run from a rotating control head placed on top of the drilling riser to the rig. That way the flexible pipe performs the same duties as the top joint of an annulus return line while its flexibility allows the rig to move vertically without a slip joint.

"One of the great things about this system is it can be put in place and removed within a matter of hours," said Weatherford underbalanced drilling expert, Don Hannegan, whose company is part of the JIP along with Petrobras and others. "That means when you are drilling a section that doesn't have that small frac gradient-pore pressure window, you can just return to traditional drilling."

While flexible pipe usage has spread in the oil industry during recent years, upstream petroleum engineers generally view it as a tool that in some few instances can save time or money. With recent advances in composite materials and the extreme requirements of ultra deepwater, however, flexible pipe may soon be recognized as an enabling technology rather than a convenient innovation.

Source:

http://www.oilandgasonline.com/doc/flexible-pipe-becoming-deepwater-staple-0001