Technical Paper External Corrosion Control and Inspection of Deep Water Pipelines

by Jim Britton (2001)

Introduction

The external corrosion control of offshore pipelines has, for many years, been accomplished with pipe coatings supplemented with galvanic cathodic protection in the form of zinc or aluminum anode bracelets. This basic methodology works equally well in deep water as it does in shallow. There are however some very important differences in the way corrosion control systems operate in deep water versus shallow water. There are also other obvious differences in the way the pipelines are built and installed that have an effect on the corrosion control strategy, it is these differences which will be addressed.

The Deep Water Environment

To understand how corrosion mechanisms vary in deep water, it is necessary to appreciate how the deepwater environment differs from the shallow water areas. There is a common misconception that steel does not corrode in very deep water. “Look at the Titanic, the darn thing’s as good as new and its been down there for a hundred years.” We have all heard this at some time, in truth the Titanic is a crumbling wreck, corrosion will eventually destroy every trace of the vessel, but the initial attack is at galvanic couples, just as it would be on an unprotected pipeline. It is true that the corrosion rate is less in deep water, but it is far from being zero.

Temperature – As water depth increases temperature decreases, this decrease in temperature affects the ability of calcareous deposits to form. Calcareous deposits are the result of the cathodic protection polarization process. These deposits are critical in the cathodic protection process as they act like crude coating systems to reduce the current required from the anodes, thus it is possible to provide cathodic protection for very long life with relatively small anodes. At low temperature the deposits form much more slowly, and when formed, are generally less dense than deposits formed under equivalent conditions in shallow water. This slowed formation requires higher levels of cathodic protection current to sustain anti corrosion protection (maintenance current density), and thus, more anodes are needed.

Conductivity – The electrical conductivity of seawater increases as temperature increases, thus at depth the conductivity is lower. This means that the amount of cathodic protection current which could be expected from a conventional anode will be much lower in deep water than in shallow water. So we have a dilemma, more current is required, less is available so we need more anodes, or anodes of a different shape.

Pipe Coatings – As previously mentioned, coatings are the primary external corrosion defense. Coatings operated by simply providing an oxygen diffusion barrier between the steel and the seawater. Thus coatings reduce the surface area of exposed steel by better than 90%. From the previous paragraph, the importance of coatings in deep water can be appreciated. The majority of new pipelines are protected with fusion bonded epoxy coating (FBE). These pipeline coatings perform equally well in deep or shallow water but are subject to mechanical damage during the pipe lay operation. When formulating a corrosion control design, it will be necessary to assign a coating breakdown factor, this should be done wisely. None of the design guidelines gives a good recommendation for a number to use, and the most appropriate number will vary depending on the type of coating and the pipeline installation method. A safe number to use is 2-3% initial coating damage and 5% at the end of 20 years, beyond this it would be wise to allow an additional 1% / year final breakdown. This is a pessimistic number, pipeline survey results on old lines have typically shown that the coatings hold up very well, and the supplemental cathodic protection seems to enhance the long term integrity of the coatings by eliminating corrosion undercutting.

Thermal Sprayed Coatings – The use of sprayed metallic coatings (Aluminum and Zinc) has been gaining popularity in submerged offshore applications, including some pipelines. This coating offers the benefits of low cost with excellent corrosion protection over a wide range of temperature and conditions. While TS coatings do provide a measure of cathodic protection, they still require supplemental anodes but the quantity can be significantly reduced. These coatings are still under development for broad-based pipeline applications but expect to see continued progress.

Cathodic Protection – As previously discussed, cathodic protection requirements do vary from shallow to deep water, the following points must be borne in mind when designing a cathodic protection system for a deep water pipeline.

Anode Chemistry – Historically, zinc was the material of choice for pipelines offshore. The material was cheap, easy to cast because of its relatively low melting point, it was also easy to alloy. The material is also able to operate in either sea water or seabed sediments. Some operators still favor zinc. In the mid seventies, the use of indium activated aluminum anodes became the norm. The aluminum anodes were lighter, operated more efficiently and were also able to work in seabed sediments. The use of aluminum on platforms was also on the riser mainly due to weight saving, and thus the high demand for aluminum anodes made the price very competitive. The use of aluminum, activated with indium, carried into the deep water market again because of price and weight. In the early 90s some activation problems were observed on these anodes operating in cold water (+/- 4°C), it was found that adjusting the chemistry to tighten the ranges of critical elements eliminated the problem. The adjusted chemistry being widely used in the Gulf of Mexico is shown below (Table 1).

Table 1 (below) – Anode Chemistry Modification for Cold Water Service

Element	Typical Composition	Cold Water Composition
Iron (Fe)	0.10% max	0.07% max
Zinc (Zn)	2.8 – 7.0%	4.75 – 5.25%
Copper (Cu)	0.006% max	0.005% max
Silicon (Si)	0.20% max	0.10% max
Indium (In)	0.01 – 0.03%	0.015% – 0.025%
Cadmium (Cd)	Not Specified	0.002% max
Others (each)	0.02% max	0.02% max
Aluminum (Al)	Remainder	Remainder

Anode Inspection – We have established the fact that anode chemistry is critical. When procuring anodes is is critical to ensure that the anodes are electrochemically tested at the anticipated service temperature, not ambient seawater. It is also important to monitor the chemical composition of the anodes carefully. To assist in this endeavor, a qualified inspector should be used to monitor the anode production, EXPECT what you INSPECT. NACE International has an excellent guideline document on electrochemical testing of anodes, TM190-98.

Current Density – The amount of cathodic protection current required to achieve optimal polarization (minimize maintenance current), varies depending on the environment. It takes a lot less current to get the job done if the pipe is buried, however, the lower conductivity of the seabed sediments versus the seawater mean that the anodes cannot deliver as much current. The recommended current density for shallow water pipelines in the Gulf of Mexico is 2 mA/ft² in the mud, and 5 mA/ft² in the water (maintenance current densities), we recommend the following design approach for deep water pipelines. Continue to use 2 mA/ft² in the mud zone but increase to 7mA/ft² in the water zone. In addition, ensure that the design will still be correct if an anode is detached from the pipe, this means that the spacing should be closer than normal. In most conditions, anodes on deepwater pipelines should not exceed 250 feet spacing.

Pipeline Installation – It is important to recognize that damage can occur during pipeline installation [1]. Anodes may be detached through mechanical contact with the pipe lay equipment or coatings may be damaged. On projects employing the reel-lay method, it is not uncommon to attach both halves of the anode bracelet on the top half of the pipe (Figure 1), this minimizes the potential for damage from the stinger. Beware that the pipe may rotate 180° placing ALL the anode material in the mud, this unlikely scenario should be reflected in the design. The use of cast in place polyurethane tapers is not uncommon for pipe lay situations where the anodes can be pre-installed, the tapers provide a smooth transition and also anchor the anode grounding wire in place.

Figure 1 – Anodes on Top of Pipe on Reel Lay Barge

Electrical Isolation – The question of electrical isolation has long been a subject of debate among offshore pipe liners. Taken from the corrosion control perspective, we always recommend isolation of pipelines under the following circumstances:

1. The pipeline is connected to a bare steel structure (i.e. a platform).

2. The pipeline is connected to any structure of foreign ownership.

3. A new pipeline is tied into an old pipeline.

4. The pipeline is to be cathodically protected with impressed current.

5. The pipeline is operating at elevated temperature.

6. The pipeline is made of a corrosion resistant alloy (CRA).

Remember that it is much easier to electrically short a pipeline than to electrically isolate it when in service. Having the pipeline isolated also give far more options for troubleshooting and monitoring over the life of the equipment.

Inspection

Introduction – This paper will only discuss the inspection of the external corrosion control system on deep water pipelines; It will not address the other inspection methods for sand monitoring and internal corrosion. Some smart pigs are able to detect external corrosion pitting. This is usually too late, as the goal of monitoring is to stop corrosion, not to find it once it has already happened!

New Pipelines – When planning a new pipeline, there are many things that can and should be done up front to ensure that the corrosion control system will work trouble free over the life cycle of the pipeline. Starting with good specification writing and vendor qualification, as well as in plant inspection of coatings and cathodic protection materials. A critical phase is the installation, inspection on the pipe lay vessel is the last chance to catch problems before they become major problems. The use of stinger mounted sensors [1] to detect anode detachment of coating damage should be considered, these electrochemical sensors give instant indication of a problem which can usually be remedied just as quickly, thus expensive retrofits can be avoided [2]. The most important inspection is the post lay, usually performed by an ROV to verify that here are no spans or other anomalies, this is the perfect opportunity to verify the operational status of the cathodic protection and coating system. If this survey proves that all the anodes are attached, activated and adequately protecting the pipe, and that the coating system has not sustained serious damage, then it will not normally be necessary to re-survey the line for over 10 years. This is by far the most cost effective survey that can be performed, the incremental cost addition to the post lay survey is usually less than $300.00 / mile equivalent (cost relevant only at the time of this paper).

Existing Pipelines – Existing pipelines can be surveyed with ROV mounted survey systems, high and low resolution systems are available. The decision to use high or low resolution will depend upon the level of information required. High-resolution systems will give not only accurate potential profiles of the line but also current density, this is particularly important if a remaining life estimate is required. A typical high-resolution survey plot is shown in Figure 2. An ROV equipped with high-resolution survey equipment is shown in Figure 3. Low-resolution systems give only potential profiles. These are usually sufficient for post lay inspections. Note that any survey of a pipeline cathodic protection system which utilizes a trailing ground wire, will be erroneous, and could give dangerously optimistic (or pessimistic) results.

Figure 2 – Three Electrode Survey Plot. Red Trace (Potential), Green (Current Density)

New equipment has recently become available for cathodic protection monitoring on deep water equipment, a self contained 10,000 ft rated CP measuring system (Figure 3), requires no ROV interface. This system is useful for checking a few isolated points on a pipeline with minimum operational hassle. This system (called Deep C Meter) is ideal for checking subsea insulators, short flow line jumpers and anode bracelets.

Figure 3 – Work Class ROV with Survey Equipment – CP System and Pipe Tracker, circa 2001.

Figure 4 – Self Contained Deep Water CP Probe Pictured right (updated model of this probe – Deep C Meter)

Summary

The cost of providing cathodic protection to a deep water pipeline is typically less than 1% of the project cost, it makes no sense to compromise the long term integrity of a pipeline by under-designing the cathodic protection system. Expect to see continued improvement and development in the area of thermally sprayed aluminum and zinc coatings, and a greater use of ROV integrated inspection systems.

References

1. Offshore Magazine – April 1996 – J. Britton “Protecting Pipeline Corrosion Control Systems During Installation”
2. CORROSION 97 – Paper 470 R. Winters and A. Holk “Cathodic Protection Retrofit of an Offshore Pipeline”

Source: External Corrosion Control and Inspection of Deep Water Pipelines (Paper), diakses Februari 2014.

Deepwater pipelines – Taking the challenge to new depths

Martin Connelly – Corus Tubes

To ensure continuity of supply, E&P companies have to consider opportunities in ever increasing water depths. Assisting this are new technological advances, including pipeline manufacture and design that increase the technical feasibility of deepwater developments.

Deepwater pipeline challenges

Conventional pipeline design, although concerned with many factors, is dominated generally by the need to withstand an internal pressure. The higher the pressure that products can be passed down the line, the higher the flow rate and greater the revenue potential. However, factors critical for deepwater pipelines become dominated by the need to resist external pressure, particularly during installation.

Local infield lines, such as subsea umbilicals, risers, and flowlines (SURF) usually are modest challenges as they are small in diameter and inherently resistant to hydrostatic collapse. In smaller sizes, these lines generally are produced as seamless pipe which is readily available and generally economical.

However, deepwater trunklines and long-distance tiebacks present a greater challenge. To increase subsea production these lines tend to be larger in diameter with a thicker pipe wall to withstand the hydrostatic pressure and bending as it is laid to the seabed.

Typically these lines are often 16 in. to 20 in. (40 cm to 50 cm) in diameter, which presents a further complication as the pipe sizes lie at the top end of economical production for seamless (Pilger) pipes. The Pilger process can produce the thick walled pipe required for these developments but often the manufacturing process is slow, the cost of material high, and the pipe lengths short. As a result, the most economical method to manufacture these lines is the UOE process. The increasingly stringent industry demands have driven this design toward its practical limits of manufacture and installation.

Corus Tubes has responded by manufacturing UOE double submerged arc welded (DSAW) linepipe to the deepest pipelines in the world. This pipe overcomes significant challenges associated with deepwater developments and facilitated a number of pioneering projects such as Bluestream and Perdido.

In the UOE process, steel plate is pressed into a “U” and then into an “O” shape and then is expanded circumferentially. Wall thickness and diameter requirements for deepwater trunkline pipe continue to be challenging for manufacturing economics and installation capabilities.

Distribution curve depicting ovality of Perdido pipe (457 mm x 20.62 mm thick).

While few producers manufacture UOE pipes at 16- to 20-in. outside diameter, this manufacturing method is quicker to market and more cost-effective than seamless alternatives. Corus Tubes’ process seeks to optimize the design of the material and minimize the wall thickness to:

• Reduce material cost
• Reduce welding cost
• Reduce installation time
• Reduce pipe weight for logistics and submerged pipe weight considerations
• Increase design scope enabling a wider range of deepwater developments.

Det Norske Veritas (DNV) says the acceptability of a pipeline design for a given water depth is determined by means of standard equations that measure the relationship between OD, wall thickness, pipe shape, and material compressive strength.

Pipe shape

Finished pipe shape is optimized by balancing the manufacturing parameters, pipe compression, and expansion. The crimp, U-press, and O-press combination ensures that the pipe size is controlled, often beyond most offshore specifications. Enhanced pipe “roundness”, wall thickness, and diameter tolerance removes uncertainty in the design and production stages and allows pipe wall thickness optimization.

Compressive strength

Pipe manufactured by the UOE process undergoes various strain cycles, both tensile and compressive. The combination of these cycles affects the overall behavior of the material in compression. This is indicated in the equation given in the offshore design standard DNV OS F101 by the presence of the Fabrication Factor αfab. For standard UOE processes, the term represents a de-rating of 15% in the compressive strength as a result of the material response to the strain cycles during forming, known as the Bauschinger Effect.

This diagram represents the relationship between stress and strain when a material is placed in tension (top right quadrant) and then into compression (bottom left quadrant). When material is first placed in tension, such that it is deformed plastically, the yield stress in compression is reduced (compare this with the projected compressive strength in the bottom left quadrant had the pre-tension not been applied).

When material is first placed in tension such that it is deformed plastically, the yield stress in compression is reduced. This originally was reported by Bauschinger in 1881. It is relevant to pipe making because during the forming process the material is placed in tension during expansion. Following this, the material is dispatched for installation, where the pipe sees compressive stress from the pressure of the seawater. Conventionally, the 15% reduction in compressive strength compensates for the Bauschinger Effect.

Since the early 1990s, Corus Tubes has observed that the results it obtained from the forming process often yielded higher compressive strengths than those obtained from the standard equations. Research and process development leads to a greater understanding of the metallurgical transformations during pipe forming. It is possible to reverse the Bauschinger Effect to deliver pipe with compressive strengths higher than conventionally expected.

Three things influence the final pipe mechanical properties in compression:

1 Choice of plate feedstock. The strength of the final pipe is a function of the chemistry and grain structure of the mother plate from which it is fabricated. All aspects of plate manufacture, the chemistry, rolling schedule as well as cooling rates ensure that the final plate properties change to give the required pipe characteristics.

2 Choice of mill compression and expansion parameters. By optimizing the various compression and expansion cycles, a set of manufacturing conditions can be determined to enhance collapse performance to potentially reduce pipe wall thickness in future deepwater applications.

3 Controlled low temperature heat treatment. With the correct plate chemistry it is possible to deliver a lift in compression strength through the application of a low temperature heat treatment. This final part of the process can be measured and assured only if the correct attention has been paid to the previous manufacturing stages.

A number of groundbreaking projects have pushed the boundaries of deepwater exploration and production, and enhanced understanding of pipeline capabilities and limits. In 2000, ExxonMobil used 64 km (40 mi) of line pipe for the Hoover/Diana project which reached depths of 1,450 m (4,800 ft). This also was the first time that small diameter pipe from Corus Tubes’ UOE mill in Hartlepool, UK, was supplied to the deepwater Gulf of Mexico market.

In 2001, Corus Tubes supplied 94 km (45,000 metric tons [49,604 tons]) of three-layer polypropylene coated, high grade, sour service linepipe and bends for the technically challenging Bluestream project which supplies gas from Russia to Turkey under the Black Sea. Corus also was selected to provide pipe for the deepest section of the pipeline at 2,150 m (7,054 ft) water depth.

Corus Tubes recently supplied line pipe to the Perdido Norte project in the Gulf of Mexico. Williams commissioned the production of small diameter UOE pipe and approximately 312 km (194 mi) of uncoated steel line pipe for ultra deepwater depths from 3,500-8,300 ft (1,067-2,530 m) with a rugged seabed terrain. The pipe, manufactured to withstand a service rating equivalent to ANSI 1500, is one of the deepest pipelines in the world.

One section of the pipeline transfers hydrocarbons from the FPS host in Alaminos Canyon block 857 and terminates in East Breaks block 994 (78 mi [126 km]). The gas pipeline terminates at Williams Seahawk pipeline in East Breaks block 599 (106 mi [171 km]). The 18-in. (46-cm) diameter pipe was manufactured in wall thicknesses ranging from 19.1 mm to 27.0 mm (¾ in. to 1 in.).

Further to the experiences on Perdido, Corus has produced a thicker pipe at 18-in. diameter for the Petrobras Tupi project. The pipe has a wall thickness of 31.75 mm (1 ¼ in.) and lies in a water depth of 2,200 m (7,218 ft) offshore Brazil. While this project is not the deepest, it represents a milestone in pipe forming. This is the thickest UOE pipe ever manufactured at 18-in. diameter (note as the diameter of a pipe reduces and thickness increases, the levels of strain and power required to forming it increases).

Tupi is a testimony to the complexity of deepwater pipe design. While collapse at these water depths is a critical design state, there also were concerns about corrosion, since the Tupi production has some small amounts of contaminants in the exportation gas (about 5% CO2 and a very small amount of H2S). Even though the exported gas should be dehydrated, the CO2 raises concerns about pipe corrosion and is managed by increasing the nominal wall thickness to account for loss of material during life. At the end of the pipe life it still must withstand the pressure at the seabed even with a reduced wall thickness.

The H2S, although not expected in the exported gas, could cause cracking to occur in steels where the grain structure and cleanliness is not optimized. In addition, high levels of forming strain can exacerbate the situation. Corus Tubes applied its knowledge of steel production and pipe forming to ensure that the plate it procured from Dillinger Hutte and Voest Alpine provided ultimate resistance to H2S corrosion.

Pipelines in deepwater require the tightest dimensional tolerances to maximize resistance to collapse and to maximize girth weld fatigue resistance. Furthermore, pipelines from 16-in. to 28-in. (71-cm) are seen as the future for deepwater export pipeline systems.

About the author

Martin Connelly is responsible for ensuring Corus Tubes’ line pipe can meet the difficult technical demands. He also oversees the company’s new product and market development. Connelly joined Corus Group in 1993 after graduating with a first class honors degree in Metallurgy and Engineering Material from Strathclyde University. He worked in a number of technical, quality, and operational roles before being promoted to product development metallurgist.

Source: Deepwater Pipelines & Taking the Challenge to New Depths – Offshore, diakses Januari 2014.

Commercial Diver Riser Installation

Leak detection equipment adapted for pipeline hydrotests, rehab projects

Pipeline leaks involve transition of the fluid from the internal pressure to the lower external pressure. This generates an acoustic signal, due to the turbulence and sudden expansion of the fluid mass.

Co.L.Mar’s Acoustic Leak Detector (ALD) technology is designed to acquire and process the acoustic data and to extract the leakage from the ambient noise. The system’s main components are an underwater acoustic sensor for acquiring the data along the pipeline; a transmission line to relay data to the surface vessel; a reception unit; and PC-based, proprietary software that evaluates in real time the signal acquired and its development along the pipeline track, analyzing the data from statistical, energetic, and spectral viewpoints.

ALD sensors in towed version.

The signal generated by a leak is detectable mainly as ultrasound, which the ALD receiver converts to an audible lower frequency. Different sensors are used depending on the operational mode:

• Towed fish, in which the sensor is towed along the pipeline track by a vessel at speeds of up to 6 knots, typically in water depths of up to 100 m (328 ft). This technique is suited to line inspections, with optional use of a USBL system for greater positioning accuracy
• Diver-manipulated (ALD-DIVER), in which the diver drives the system around the flange to be inspected, with the data sent via soft cable to the surface receiver
• Vertical deployment, suitable for line and flange inspections. The sensor is lowered from the vessel’s side and kept vertical by means of a clump weight
• ROV-deployed, in which the sensor is installed on the vehicle, with the latter tracking the pipeline at a speed of around 0.5-1 knots.

Early this year, BJ Services contracted Co.L.Mar to support a pre-commissioning program for two newly installed, 48-in [1.2-m] gas pipelines in the Baltic Sea. ALD equipment and personnel were on standby during hydrotesting of the first of the 1,200-km (745-mi) lines, the equipment being supplied in both ROV and towed fish versions.

“There is an increasing need for pipeline contractors to have contingency services in case of leakage occurring during hydrotests,” said Co.L.Mar Managing Director Luigi Barbagelata. “The client will not accept a pipeline if there are any leaks.”

Pipeline inspection with ALD installed on an ROV.

For this project, Barbagelata noted, “the client asked us to adapt our towed fish system to work in water depths of up to 250 m [820 ft], which involved design and manufacture of a new ‘fish sensor’ and towing system. Data acquired by the sensor are modified and transmitted by means of a single armored coaxial cable, also used for power injection.”

During April and May, Co.L.Mar undertook a similar job in the Kazakh sector of the Caspian Sea. ALD equipment was sent offshore while personnel were on standby at the company’s headquarters in La Spezia, northern Italy, after securing visas to avoid delays in any necessary response.

Acoustic leak detection is also used for pipeline rehabilitation projects.

“With this kind of inspection,” Barbagelata explained, “it is common to encounter large leaks and low pressures, and in these cases chemical or optical sensors detecting particles in seawater can give positive results. For that reason, the ROV and diver-deployed ALD versions now feature a channel that can host an additional sensor – either a dye detector (fluorescin) or a hydrocarbon detector. Data from the extra sensor are multiplexed with acoustic information and sent to the surface via the same transmission line. In this way, it is possible to run a chemical and optical inspection of the pipeline simultaneously.”

Recently, Co.L.Mar took delivery of an underwater leak simulator which simulates liquid and gas leaks across a range of pressures (2-200 bar, or 29-2,901 psi) and leak sizes.

“The on-site conditions can be replicated and the acoustic signal generated can be measured and used as a precise target reference,” said Barbagelata. “During trials with the simulator, a signal is acquired by calibrated hydrophones and the data are processed using a proprietary software, allowing definition of each leak’s source level and spectral distribution. This information allows us to better set up the equipment prior to an inspection with knowledge of the pressure and flow conditions.”

For over a year, Co.L.Mar has also been working on a new monitoring system for leak detection on subsea structures. This would involve permanently installed sensors on critical equipment such as christmas trees, manifolds, subsea valves, and flanges.

“We are working on two types of sensors – one short range and omni-directional, which basically could detect a leak within a few meters of the subsea structure,” Barbagelata noted. “The other would be bigger, and with a much larger operating range – perhaps 50 m [164 ft] – which would in addition give information on the direction of a leak. The main challenge is ensuring long-term reliability, because maintenance costs for subsea equipment are prohibitive.”

Source: Leak detection equipment adapted for pipeline hydrotests, rehab projects – Offshore, diakses Januari 2014.

Crack detection in gas pipelines

      

 

Hartmut Goedecke, Dipl Ing., Stephan Tappert, Dipl. Ing., Mirko Smuk, Dipl. Ing., Achim Hugger, Dipl. Ing., Josef Franz, Dipl. M

The Australian Pipeliner — April 2005

Intelligent pigs, which detect geometry defects and metal loss in long distance pipelines have been around for many years. It has also been possible for several years to detect crack-like defects with the ultrasonic method in liquid pipelines. In gas lines, however, the detection of crack-like defects incurs a high additional cost because the ultrasonic method requires a coupling liquid, and ultrasonic pigs can only be run with a liquid batch. A crack detection pig for gas pipelines was therefore urgently required.

The new EmatScan® CD is capable of detecting crack-like defects in gas pipelines with the ultrasonic method without a coupling liquid. The EmatScan® CD utilises EMAT (Electro Magnetic Acoustic Transducer) technology, whereby the ultrasonic pulse is generated electro-magnetically inside the material by an electric pulse applied to a coil in the sensor. The EmatScan® CD has already successfully inspected several gas pipelines in North America and is currently available in the size of 36 inches.

Introduction

High pressure long distance pipelines transporting gas, crude oil or products are inspected by intelligent pigs for the location of defects. These inspections are an important contribution to the continued safe operation of these pipelines.

Typical defects are geometrical anomalies, metal loss and crack-like defects. Intelligent pigs are measuring robots which are propelled through the pipeline to detect defects, using appropriate measuring techniques.

In the 1970s metal loss (corrosion) was the type of anomaly that caused the development of the first intelligent pigs. For metal loss two technologies are customarily used: the ultrasonic method, which measures the wall thickness directly, or the magnetic flux leakage (MFL) method, which responds to the change of the magnetic field in the presence of metal loss.For geometrical anomalies, pigs with mechanical sensors have been used for many years. It is customary to inspect new pipelines with calliper pigs prior to commissioning.

The ultrasonic method is the more accurate method, but a coupling liquid is required to apply the ultrasonic pulse to the pipe wall. It is therefore mainly used in liquid pipelines. The MFL method, on the other hand, does not require a coupling liquid and is therefore the preferred method for gas pipelines. Both types of instrument have been operated for many years and play a central role in the upkeep and maintenance of high pressure long distance pipelines.

During the 1990s longitudinal crack like defects began to appear additionally in more and more pipelines causing serious problems. This led to the development of a new generation of crack detection pigs.

Types of Cracks

Even though isolated fatigue cracks have been seen since the 1970s, it was the increased appearance of stress corrosion cracking (SCC) defects in the 1990s that led to some spectacular pipeline failures in Russia and North America. Figure 1 shows typical SCC colony.

SCC develops in pipelines under narrowly defined conditions. These include: susceptibility of the steel, moisture of the soil, soil chemistry, quality of the coating, variable stress and highly increased temperatures. SCC first appeared in the above mentioned areas mainly in high pressure pipelines directly downstream of compressor stations and now also occurs more and more often in liquid pipelines, even though these lines do not display increased temperatures.

Apart from SCC, metal fatigue cracks are becoming increasingly common, mainly due to the increasing accumulated number of pressure cycles in the aging pipeline population.

Cracks, which influence the structural integrity of the pipeline, are mainly longitudinally orientated, caused by the predominant stress distribution in the steel. Fatigue cracks can grow both from the internal or the external surface of the wall. Because of the growth mechanism, SCC cracks are external defects.

Batching with UltraScan® CD

In the early 1990s the UltraScan® CD crack detection pig was developed by GE Energy. It uses angular beam ultrasonic technology to detect longitudinal cracks. The sensors operate in the immersion mode, the transported fluid is used as coupling liquid.

The basic principle is demonstrated in Figure 2. The angular ultrasonic beam is reflected to and fro between the two surfaces at an angle of 45°. If the signal is reflected by a crack it travels back along the same path and is received by the same sensor as the echo signal. The appearance of the echo signal along the time coordinate indicates whether the crack is located internally or externally. As the tool is designed to detect longitudinal cracks the sensors are slanted with circumferential orientation to allow the beam to travel through the wall perpendicular to the longitudinal direction. In order to scan each defect from both sides two sets of sensors are employed, one operating clockwise, the other in an anti-clockwise direction. Each ultrasonic pulse is monitored up to two and a half full reflections (skips), meaning each crack is seen by several sensors from different distances. This results in a redundancy of information which is important to guarantee a reliable detection of the cracks and to differentiate between real cracks and harmless small inclusions in the material.

The multitude of sensors are mounted on the sensor carrier so that the entire pipe circumference is scanned in one pass (Fig. 3). The effective distance between sensors in circumferential direction is about 10 mm. The individual skids of the sensor carrier are mounted in such a way that geometric irregularities of the pipe are compensated and the sensors are always locally orientated with the right angle to the wall.

During the inspection, large amounts of data are generated. During the travel of a 24 inch UltraScan® CD tool through a 100 km long pipeline, 100 terra bytes of primary data are generated. The data is screened in real time for signals relating to crack like defects and only those signals are stored in the on board solid state memory. To achieve this, the most advanced FPGA electronic components are employed in the tool.

The UltraScan® CD detects all defects of 25 mm minimum length and 1 mm minimum depth. The data is displayed as a coloured area scan (C-Scan). The colour displays the intensity of the reflected signal according to the colour code. The intensity of the signal is an indication of the depth of the defect (Figure 4). UltraScan® CD tools have inspected more than 15 000 km of pipeline since their introduction in 1994 and detected a total of 3000 SCC colonies and over 700 fatigue cracks.

The ultrasonic technology is established as the industry’s most reliable and accurate method to detect cracks. In liquid pipelines the UltraScan® CD can be applied directly in the transported medium. This is not the case in gas pipelines, because the coupling liquid is not readily available. To inspect a gas pipeline reliably for cracks the UltraScan® CD tool has been run in a liquid batch in recent years (Figure 5). Even though this batch technology is well proven, it causes interruptions in the production and additional cost. These interruptions not only lead to loss of income for the line operator, but are often simply not possible because of the dependency of the end customer on the delivery.

A solution of this dilemma is now offered with the EmatScan® CD.

EmatScan® CD

For the EmatScan® CD the EMAT technology has been employed. This technology has the advantage that no coupling liquid is required. The ultrasonic pulse is generated inside the wall by an electro magnetic effect.

Principle of operation

Figure 6 demonstrates the difference between the standard piezoelectric sensor of the UltraScan® CD and the EMAT sensor. In the case of the piezoelectric sensor, the ultrasonic pulse is generated by a crystal inside the sensor and is transferred to the wall through the coupling liquid. The EMAT sensor, on the other hand, consists of a permanent magnet and an electric coil. The pipe wall is magnetised locally by the permanent magnet and an electric pulse sent through the coil generates eddy currents inside the wall. An eddy current flowing in the magnetic field gives rise to the so called Lorentz force, causing a deflection of the crystal lattice. Through this movement of the lattice the ultrasonic wave is generated right inside the metal itself.

Based on the orientation of the magnetic field and the eddy currents, ultrasonic waves are induced which travel in different directions inside the pipe wall. This mechanism also works in the reverse for the reception of an ultrasonic pulse.

In the case of the EmatScan® CD EMAT sensor three different waves are generated: the SH (shear horizontal) wave, the RH (rayleigh high frequency) wave and the TS (thickness shear) wave.

The individual waves fulfil different tasks: The SH wave front extends over the entire thickness of the wall and travels in circumferential direction through the wall. This wave provides the basic information, responding to any crack oriented in longitudinal direction. The RH wave only oscillates close to the internal surface and also travels in circumferential direction, responding to internal cracks only. By combining the information generated by the SH and RH waves it is possible to distinguish between internal and external cracks. This combined information is also used to estimate the depth of the crack. The TS wave travels perpendicularly into the wall and is used to measure the actual wall thickness of the pipe joint.

The EmatScan® CD features three sensor heads per sensor carrier equally spaced over the circumference. The sensor acts as transmitter and receiver. Each sensor head transmits an ultrasonic pulse, which, in the case of the existence of a crack like defect, is reflected and received by the same sensor. Part of this pulse also travels on around the circumference and is received by the adjacent sensor head as a very strong transmission signal.

The relevant information for the detected crack is deducted from the strengths of the reflected echo and the transmission wave. The part of the pipe circumference located between two sensor heads respectively is divided into three zones: the near gate for crack echoes which arrive ahead of the transmission signal of the neighbouring sensor head, the far gate for echoes which arrive after the transmission signal and the transmission gate for the reception of the transmission wave itself. Additionally there is a dead zone directly in the sensor head area from which no signals are received.

Based on the fact that each EMAT sensor head is able to scan a large portion of the pipe circumference, the EmatScan® CD tool only needs a total of 12 sensor heads located on four sensor carriers. The individual sensor carriers are mounted with an angular set off to allow for covering the entire pipe circumference.

Mechanical design

The EmatScan® CD is of modular design, similar to any modern pipeline inspection tool (Figure 7). The individual modules travel inside the pipeline on cups or rollers. They are connected by universal joints to allow the passing of bends. The electronic components are housed in pressure tight bodies. Electronically the individual bodies are connected by especially designed pressure tight cables and plugs. The first module houses the batteries for the power supply of the electronic system, while the second houses the electronic components for data treatment and storage. Trailing behind these modules are the four sensor carriers with three sensor heads each.

The cups of the first module seal the tool inside the pipe to allow for the build up of the differential pressure needed to propel the tool through the pipeline.

Since the SH wave front extends over the full thickness of the wall, the frequency of this wave is dependent on the wall thickness of the pipe. For pipelines with wall thickness that differ from the range of 9 to 16 mm sensor heads with different frequencies must be employed.

Test results

Inspection results are displayed as B-Scan and C-Scan. The B-Scan displays the signals of an individual sensor with respect to time (y-coordinate), with the sensor travelling down the pipeline displayed in the x-coordinate. The intensity of the received signal is displayed as colour, with red indicating the maximum intensity.

Figure 8 shows test results of defects with the minimum depth of 1 mm. The group of defects shown in Figure 9 feature different angles with respect to the longitudinal direction – this is clearly seen in the results. Figures 10 and 11 demonstrate the capability of the system to resolve two defects in close vicinity, both in the longitudinal direction (Figure 10) and in the circumferential direction (Figure 11).

By combining the results of the individual types of wave an estimate for the depth of the crack like defect can be determined. In the inspection report the depth is reported in 3 classes:

1) less than 2 mm deep

2) 2 mm to 5 mm deep

3) more than 5 mm deep.

Using the depth and length information the influence of each defect on the safe operating pressure of the pipeline can be calculated.

Economy

The EmatScan® CD tool provides an important contribution to the safe operation of gas pipelines, in that it detects with high probability all defects relevant for the structural integrity of the pipe material. Apart from the aspects of safety and environmental protection this also has positive economical consequences, eliminating the cost a failure of a gas pipeline would generate, not to mention the loss of public opinion connected to such an incident.

Special aspects

The EmatScan® CD can be employed in gas lines only. Due to the fact that the ultrasonic pulse needs to travel over relatively long distances around the circumference of the pipe, the medium or material in direct contact with the pipe wall has a great influence on the propagation of the wave. In liquid-carrying pipelines, a lot of the ultrasonic energy is lost by part of the wave migrating into the liquid, so that the signal amplitude vanishes before the wave reaches the Far Gate or the adjacent sensor.

The coil of the test head must be within 0.5 mm of the internal pipe surface. To achieve this, the coil section of the test head is gently pressed against the wall, causing it to slide along as the tool is progressing through the pipe line. One of the challenges during the development was to find the right material for the abrasion resistant layer on top of the sensor coil that at the same time would influence the strength of the electric signal as little as possible.

Field testing

The EmatScan® CD has completed runs successfully in several gas pipelines in North America. One of the lines was of special interest, because it had already been inspected by the UltraScan® CD running in a liquid batch. As a consequence of this the locations and dimensions of several crack-like defects were known prior to the EmatScan® CD run. All defects found by the reliable UltraScan® CD tool were also found by the EmatScan® CD.

1) Yemoans M.; Ashworth B.; Strohmeier U.; Hugger A.; Wolf T.; “Development of 36” EmatScan” CD Crack Detection Tool”, International Pipeline Conference 2002, Calgary, Canada

2) Ashworth B.; Willems H.; Uzelac N.; Barbian O.A.; “Detection and Verification of SCC in a Gas Transmission Pipeline”, International Pipeline Conference 2000, Calgary, Canada.

3) Ashworth B.; Ucelac N.; Willems H.; Barbian O.A.; “Detection and Verification of SCC in a Gas Transmission Pipeline”, International Pipeline Conference 1998, Calgary, Canada.

4) Willems H.; Barbian O.A.; Stripf H.; Gemmecke H. “UltraScan” CD – A new Tool for Crack Detection in Pipelines”,International Pipeline Monitoring and Rehabilitation Seminar 1995, Houston, USA.

Appeared in issue: The Australian Pipeliner — April 2005

Source: Crack Detection in Gas Pipelines – The Australian Pipeliner – The Official Magazine of the Australian Pipeliner Association, diakses Januari 2014.

Material Selection for Offshore Use

The offshore environment is by nature a highly corrosive environment. Putting steel structures into the North Sea is therefore a demanding task that requires careful material selection to ensure that the entire installation will last at least for the designed lifetime. For the actual steel structures that are placed on the seabed and as such emerged in seawater, which is highly corrosive due to its chloride content, the selected material will typically be carbon steel. To prevent the corrosion process from damaging the carbon steel various methods are available: Protective layer (e.g. painting), cathodic protection and sacrificial an-odes. The methods are well known from other industries and as the environment does not change over the lifetime of the field protecting the structures is a relatively straight forward task.

 Seawater

When it comes to other systems that also are in contact with seawater like the cooling water system and the deluge (firewater-) system, these preventive measures are no longer efficient. Seawater systems are cha-racterised by high flow velocities that can be detrimental to protective layers because of erosion. The flow velocities are also the reason for a diminished use of Cunifer as this material is susceptible to cavitation which is often linked to high velocities. Over the recent years we have seen an increased use of exotic materials such as SMO or 6MO (6% Molybdenum) in seawater systems as it offers an increased mechanical strength as well as a superior corrosion resistance against chlorides. Because of the superior corrosion resistance the corrosion allowance can be reduced in the design phase and in combination with the increased mechanical strength using SMO will reduce the weight of the pipe to be installed. Another alternative material is Glassfibre Reinforced Pipe – GRP, which is highly corrosion resistant. GRP, however, has the disadvantage of having a fairly mechanical strength and being susceptible to vibration.

Deluge systems installed offshore were traditionally produced from galvanised carbon steel pipe with threaded connections. Galvanised pipe is typically fairly corrosion resistant but when the pipe is cut or threaded the carbon steel is left unprotected causing corrosion. In the so-called dry deluge systems that typically are used in the process areas and outdoor areas, testing of the systems will over the years often reveal that a number of nozzles are blocked by corrosion products thereby turning a corrosion problem into a safety hazard. The corrosion resistance of SMO lies in the material itself, it can therefore be cut and threaded without reducing the corrosion resistance with the obvious subsequent advantages both in respect to corrosion but certainly also in respect to safety. Also titanium is being used in an increasing number of applications especially in firewater systems. Titanium is superior to SMO in almost all aspects with respect to corrosion but the cost and availability of titanium is preventing a more widespread use of this excellent material.

Process systems

The process systems are designed on the basis of the reservoir samples available at the time of the design and the prediction of how the reservoir characteristics will change over the lifetime of the field. Fortunately one might say the operators are still getting better in increasing the recoverability of the reservoirs which in many cases will change the corrosion pattern. These changes are caused by one or more factors: changes in partial pressure, increased water production, H2S production (caused by water injection and the subsequent growth of Sulphide Reducing Bacteria, SRB). The first choice of corrosion protection in carbon steel systems will be the introduction of one or more inhibitors. Selecting an inhibitor is a complex process that requires continuous monitoring of corrosion rates in the systems affected, and nevertheless the inhibitor is not 100% efficient. Eventually it will be necessary to replace the system in question as the corrosion allowance has been “eaten away” thus rendering the system below its designed pressure bearing capabilities.

A cost effective alternative to carbon steel and corrosion inhibitor in process systems is Duplex which is steel with 22% chromium content or Super Duplex with 25% chromium. Super Duplex is particularly suitable in piping systems, pumps (where the good erosion and abrasion resistance is employed), valves, heat exchangers and various other equipment. As for SMO the mechanical properties of Super Duplex exceeds that of ordinary stainless steel thus allowing a weight reduction.

Pressure vessels are often treated the same way as steel structures, i.e. corrosion is prevented by applying a protective coating, cathodic protection or by means of sacrificial anodes. If the process system upstream of the vessel is protected by means of inhibitor the inhibitor will also protect the vessel to some degree. But the recent experience shows that the flanges on the vessel are a weak point in respect to corrosion protection. A variety of solutions to this problem have been tried out but so far the most successful method is Inconel cladding of the flow wetted parts of the flange and nozzle. Inconel 625 is a nickel-chromium-molybdenum alloy with excellent erosion and corrosion capacities and is cladded onto carbon steel through a special welding process. Further to being able to weld all of the above materials Promecon is one of the few companies in Denmark that has the capability to apply Inconel 625 to carbon steel in compliance with an approved welding procedure. At present the 3 automated cladding work stations are fully booked, most of the work is producing end bodies for flexible subsea flowlines. Recently, however, we have seen an increasing demand for Inconel cladding of vessel flanges and nozzles, and we believe that this demand will increase further as the corrosion regime changes in the flowstreams. Inconel cladding is also used widely in valves as well as wear resistance material on shafts with high wear potential.

More info about the above steels and other materials and their applications can be found on “The A to Z of Materials” – www.azom.com.

Source: Material Selection for Offshore Use, diakses Januari 2014.

How Does Offshore Pipeline Installation Work?

Laying pipe on the seafloor can pose a number of challenges, especially if the water is deep. There are three main ways that subsea pipe is laid — S-lay, J-lay and tow-in — and the pipelay vessel is integral to the success of the installation.

Buoyancy affects the pipelay process, both in positive and negative ways. In the water, the pipe weighs less if it is filled with air, which puts less stress on the pipelay barge. But once in place on the sea bed, the pipe requires a downward force to remain in place. This can be provided by the weight of the oil passing through the pipeline, but gas does not weigh enough to keep the pipe from drifting across the seafloor. In shallow-water scenarios, concrete is poured over the pipe to keep it in place, while in deepwater situations, the amount of insulation and the thickness required to ward of hydrostatic pressure is usually enough to keep the line in place.

Tow-In Pipeline Installation

While jumpers are typically short enough to be installed in sections by ROVs, flowlines and pipelines are usually long enough to require a different type of installation, whether that is tow-in, S-lay or J-lay.

Tow-in installation is just what it sounds like; here, the pipe is suspended in the water via buoyancy modules, and one or two tug boats tow the pipe into place. Once on location, the buoyancy modules are removed or flooded with water, and the pipe floats to the seafloor.

Surface Tow Pipeline Installation
Source: www.pipelife.no

There are four main forms of tow-in pipeline installation. The first, thesurface tow involves towing the pipeline on top of the water. In this method, a tug tows the pipe on top of the water, and buoyancy modules help to keep it on the water’s surface.

Using less buoyancy modules than the surface tow, the mid-depth tow uses the forward speed of the tug boat to keep the pipeline at a submerged level. Once the forward motion has stopped, the pipeline settles to the seafloor.

Off-bottom tow uses buoyancy modules and chains for added weight, working against each other to keep the pipe just above the sea bed. When on location, the buoyancy modules are removed, and the pipe settles to the seafloor.

Lastly, the bottom tow drags the pipe along the sea bed, using no buoyancy modules. Only performed in shallow-water installations, the sea floor must be soft and flat for this type of installation.

S-Lay Pipeline Installation

When performing S-lay pipeline installation, pipe is eased off the stern of the vessel as the boat moves forward. The pipe curves downward from the stern through the water until it reaches the “touchdown point,” or its final destination on the seafloor. As more pipe is welded in the line and eased off the boat, the pipe forms the shape of an “S” in the water.

S-Lay Pipeline Installation
Source: www.pbjv.com.my

Stingers, measuring up to 300 feet (91 meters) long, extend from the stern to support the pipe as it is moved into the water, as well as control the curvature of the installation. Some pipelay barges have adjustable stingers, which can be shortened or lengthened according to the water depth.

Pipe being lowered into the water via a stinger for S-lay installation
Source: www.nord-stream.com

Proper tension is integral during the S-lay process, which is maintained via tensioning rollers and a controlled forward thrust, keeping the pipe from buckling. S-lay can be performed in waters up to 6,500 feet (1,981 meters) deep, and as many as 4 miles (6 kilometers) a day of pipe can be installed in this manner.

J-Lay Pipeline Installation

Overcoming some of the obstacles of S-lay installation, J-lay pipeline installation puts less stress on the pipeline by inserting the pipeline in an almost vertical position. Here, pipe is lifted via a tall tower on the boat, and inserted into the sea. Unlike the double curvature obtained in S-lay, the pipe only curves once in J-lay installation, taking on the shape of a “J” under the water.

J-Lay Pipeline Installation
Source: www.technip.com

The reduced stress on the pipe allows J-lay to work in deeper water depths. Additionally, the J-lay pipeline can withstand more motion and underwater currents than pipe being installed in the S-lay fashion.

J-Lay Pipelay Vessel S7000
Source: www.hydro.com

Types Of Pipelay Vessels

There are three main types of pipelay vessels. There are J-lay and S-lay barges that include a welding station and lifting crane on board. The 40- or 80-foot (12- or 24-meter) pipe sections are welded away from wind and water, in an enclosed environment. On these types of vessels, the pipe is laid one section at a time, in an assembly-line method.

On the other hand, reel barges contain a vertical or horizontal reel that the pipe is wrapped around. Reel barges are able to install both smaller diameter pipe and flexible pipe. Horizontal reel barges perform S-lay installation, while vertical reel barges can perform both S-lay and J-lay pipeline installation.

Vertical Reel Barge
Source: www.jee.co.uk

When using reel barges, the welding together of pipe sections is done onshore, reducing installation costs. Reeled pipe is lifted from the dock to the vessel, and the pipe is simply rolled out as installation is performed. Once all of the pipe on the reel has been installed, the vessel either returns to shore for another, or some reel barges are outfitted with cranes that can lift a new reel from a transport vessel and return the spent reel, which saves time and money.

Source: Rigzone: How Does Offshore Pipeline Installation Work?, diakses Januari 2014.

TAP Project: Route

ROUTE

The Trans Adriatic Pipeline will start near Kipoi on the border of Turkey and Greece, where it will seamlessly connect with the Trans Anatolian Pipeline (TANAP).  From there TAP will continue onshore crossing the entire territory of Greece and Albania from east to west all the way to the Adriatic Sea coast. The offshore part of the pipeline begins near the Albanian city of Fier and crosses the Adriatic Sea to tie into Italy’s gas transportation grid operated by SNAM ReteGas.

The TAP route will be approximately 870 kilometres in length (Approx.: Greece 550 km; Albania 210 km; offshore Adriatic Sea 105km; Italy 5 km). TAP’s highest elevation point will be 1800 meters in Albania’s mountains, while its lowest part offshore will be at 810 meters of depth.

Please, note that the above mentioned figures are estimations and can change as the project develops.

 

 

“Fly over” the TAP pipeline and see main sections and associated pipeline infrastructure along the route.Watch here >>

 

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ROUTE SURVEYS IN 2009 – 2012

In 2009-2012 TAP conducted onshore and offshore surveys to identify potential obstacles on the route. As a result of these studies, optimal routing has been identified, which avoids densely populated and sensitive areas, such as National Hotova park in Albania and protected Natura 2000 habitat in Italy.

The comprehensive Environmental and Social Impact Assessment of the selected pipeline routing is described in ESIA reports.

 

Source: Trans Adiatic Pipeline, diakses: Januari 2014.

Introduction to Hot Tapping &Line Stopping

What is a Hot Tap and why it is made?

Hot Taps or Hot Tapping is the ability to safely tie into a pressurized system, by drilling or cutting, while it is on stream and under pressure.

Typical connections consist:

• Tapping fittings like Weldolet®, Reinforced Branch or Split Tee. Split Tees often to be used as branch and main pipe has the same diameters.

• Isolation Valve like gate or Ball Valve.
• Hot tapping machine which includes the cutter, and housing.

Mechanical fittings may be used for making hot taps on pipelines and mains provided they are designed for the operating pressure of the pipeline or main, and are suitable for the purpose.

• Design: ANSI B31.1, B31.3, ANSI B31.4 & B31.8, ASME Sec. VIII Div.1 & 2
• Fabrication: ASME Sec. VIII Div.1
• Welding: ASME Sec. IX
• NDT: ASME Sec. V

There are many reasons to made a Hot Tap. While is preferred to install nozzles during a turnaround, installing a nozzle with equipment in operation is sometimes advantageous, especially if it averts a costly shut down.

Remarks before made a Hot Tap

• A hot tap shall not be considered a routine procedure, but shall be used only when there is no practical alternative.
• Hot Taps shall be installed by trained and experienced crews.
• It should be noted that hot tapping of sour gas lines presents special health and metallurgical concerns and shall be done only to written operating company approved plans.
• For each hottap shall be ensured that the pipe that is drilled or sawed has sufficient wall thickness, which can be measured with ultrasonic thickness gauges. The existing pipe wall thickness (actual) needs to be at least equal to the required thickness for pressure plus a reasonable thickness allowance for welding. If the actual thickness is barely more than that required for pressure, then loss of containment at the weld pool is a risk.
• Welding on in-service pipelines requires weld procedure development and qualification, as well as a highly trained workforce to ensure integrity of welds when pipelines are operating at full pressure and under full flow conditions.

Hot Tap setup

For a hot tap, there are three key components necessary to safely drill into a pipe; the fitting, the Valve, and the hot tap machine. The fitting is attached to the pipe, mostly by welding.

In many cases, the fitting is a Weldolet® where a flange is welded, or a split tee with a flanged outlet.

Onto this fitting, a Valve is attached, and the hot tap machine is attached to the Valve (see images on the right). For hot taps, new Stud Bolts, gaskets and a new Valve should always be used when that components will become part of the permanent facilities and equipment. The fitting/Valve combination, is attached to the pipe, and is normally pressure tested. The pressure test is very important, so as to make sure that there are no structural problems with the fitting, and so that there are no leaks in the welds.

The hot tap cutter, is a specialized type of hole saw, with a pilot bit in the middle, mounted inside of a hot tap adapter housing.

The hot tap cutter is attached to a cutter holder, with the pilot bit, and is attached to the working end of the hot tap machine, so that it fits into the inside of the tapping adapter. The tapping adapter will contain the pressure of the pipe system, while the pipe is being cut, it houses the cutter, and cutter holder, and bolts to the Valve.

Hot Tap operation

The Hot Tap is made in one continuous process, the machine is started, and the cut continues, until the cutter passes through the pipe wall, resulting in the removal of a section of pipe, known as the “coupon”.

The coupon is normally retained on one or more u-wires, which are attached to the pilot bit.

Once the cutter has cut through the pipe, the hot tap machine is stopped, the cutter is retracted into the hot tap adapter, and the Valve is closed.

Pressure is bled off from the inside of the Tapping Adapter, so that the hot tap machine can be removed from the line. The machine is removed from the line, and the new service is established.

Hot Tap Coupon

The Coupon, is the section of pipe that is removed, to establish service. It is very highly desirable to “retain” the coupon, and remove it from the pipe, and in the vast majority of hot taps, this is the case.

Please note, short of not performing the hot tap, there is no way to absolutely guarantee that the coupon will not be “dropped”.

Coupon retention is mostly the “job” of the u-wires. These are wires which run through the pilot bit, and are cut and bent, so that they can fold back against the bit, into a relief area milled into the bit, and then fold out, when the pilot bit has cut through the pipe. In almost all cases, multiple u-wires are used, to act as insurance against losing the coupon.

Line Stopping

Line Stops, sometimes called Stopples (Stopple® is a trademark of TD Williamson Company) start with a hot tap, but are intended to stop the flow in the pipe.

Line Stops are of necessity, somewhat more complicated than normal hot taps, but they start out in much the same way. A fitting is attached to the pipe, a hot tap is performed as previously detailed. Once the hot tap has been completed, the Valve is closed, then another machine, known as a line stop actuator is installed on the pipe.

The line stop actuator is used to insert a plugging head into the pipe, the most common type being a pivot head mechanism. Line stops are used to replace Valves, fittings and other equipment. Once the job is done, pressure is equalized, and the line stop head is removed.

The Line Stop Fitting has a specially modified flange, which includes a special plug, that allows for removal of the Valve. There are several different designs for these flanges, but they all work pretty much the same, the plug is inserted into the flange through the Valve, it is securely locked in place, with the result that the pressure can be bled off of the housing and Valve, the Valve can then be removed, and the flange blinded off.

Line Stop setup

The Line Stop Setup includes the hot tap machine, plus an additional piece of equipment, a line stop actuator. The Line Stop Actuator can be either mechanical (screw type), or hydraulic, it is used, to place the line stop head into the line, therefore stopping the flow in the line.

The Line Stop Actuator is bolted to a Line Stop Housing, which has to be long enough to include the line stop head (pivot head, or folding head), so that the Line Stop Actuator, and Housing, can be bolted to the line stop Valve.

Line stops often utilize special Valves, called Sandwich Valves.

Line Stops are normally performed through rental Valves, owned by the service company who performs the work, once the work is completed, the fitting will remain on the pipe, but the Valve and all other equipment is removed.

Line Stop operation

A Line Stop starts out the same way as does a Hot Tap, but a larger cutter is used,.

The larger hole in the pipe, allows the line stop head to fit into the pipe.

Once the cut is made, the Valve is closed the hot tap machine is removed from the line, and a line stop actuator is bolted into place.

New gaskets are always to be used for every setup, but “used” studs and nuts are often used, because this operation is a temporary operation, the Valve, machine, and actuator are removed at the end of the job.

New studs, nuts, and gaskets should be used on the final completion, when a blind flange is installed outside of the completion plug.

The line stop actuator is operated, to push the plugging head (line stop head), down, into the pipe, the common pivot head, will pivot in the direction of the flow, and form a stop, thus stopping the flow in the pipe.

Completion Plug

In order to remove the Valve used for line stop operations, a completion plug is set into the line stop fitting flange (Completion Flange).

There are several different types of completion flange/plug sets, but they all operate in basically the same manner, the completion plug and flange are manufactured, so as to allow the flange, to accept and lock into place, a completion plug.

This completion plug is set below the Valve, once set, pressure above the plug can be bled off, and the Valve can then be removed.

Once the plug has been properly positioned, it is locked into place with the lock ring segments, this prevents plug movement, with the o-ring becoming the primary seal. Several different types of completion plugs have been developed with metal to metal seals, in addition to the o-ring seal.

 Source: (What is a Hot Tap, why it is made and how to make a Hot Tap in pipe line, http://www.wermac.org/specials/hottap.html, Jan 2014)

Directional and Horizontal Drilling in Oil and Gas Wells

Methods used to increase production and hit targets that can not be reached with a vertical well.

What is Directional Drilling?

Most wells drilled for water, oil, natural gas, information or other subsurface objectives are vertical wells – drilled straight down into the earth. However, drilling at an angle other than vertical can obtain information, hit targets and stimulate reservoirs in ways that can not be achieved with a vertical well. In these cases, an ability to accurately steer the well in directions and angles that depart from the vertical is a valuable ability. 

When directional drilling is combined with hydraulic fracturing some rock units which were unproductive when drilled vertically can become fantastic producers of oil or natural gas. Examples are the Marcellus Shale of the Appalachian Basin and the Bakken Formationof North Dakota. 

Why Drill Wells That Are Non-Vertical?

Directional and horizontal drilling have been used to reach targets beneath adjacent lands, reduce the footprint of gas field development, increase the length of the “pay zone” in a well, deliberately intersect fractures, construct relief wells and install utility service beneath lands where excavation is impossible or extremely expensive.

Below is a list of six reasons for drilling non-vertical wells. They are graphically illustrated by the six drawings in the right column of this page.

• Hit targets that can not be reached by vertical drilling.

Sometimes a reservoir is located under a city or a park where drilling is impossible or forbidden. This reservoir might still be tapped if the drilling pad is located on the edge of the city or park and the well is drilled at an angle that will intersect the reservoir.

• Drain a broad area from a single drilling pad.

This method has been used to reduce the surface footprint of a drilling operation. In 2010, the University of Texas at Arlington was featured in the news for drilling 22 wells on a single drill pad that will drain natural gas from 1100 acres beneath the campus. Over a 25 year life-time the wells are expected to produce a total of 110 billion cubic feet of gas. This method significantly reduced the footprint of natural gas development within the campus area. 

• Increase the length of the “pay zone” within the target rock unit.

If a rock unit is fifty feet thick, a vertical well drilled through it would have a pay zone that is fifty feet in length. However if the well is turned and drilled horizontally through the rock unit for five thousand feet then that single well will have a pay zone that is five thousand feet long – this will usually result in a significant productivity increase for the well. When combined with hydraulic fracturing, horizontal drilling can convert unproductive shales into fantastic reservoir rocks. 

• Improve the productivity of wells in a fractured reservoir.

This is done by drilling in a direction that intersects a maximum number of fractures. The drilling direction will normally be at right angles to the dominant fracture direction. Geothermal fields in granite bedrock usually get nearly all of their water exchange from fractures. Drilling at right angles to the dominant fracture direction will drive the well through a maximum number of fractures. 

• Seal or relieve pressure in an “out-of-control” well.

If a well is out-of-control a “relief well” can be drilled to intersect it. The intersecting well can be used to seal the original well or to relieve pressure in the out-of-control well. 

• Install underground utilities where excavation is not possible.

Horizontal drilling has been used to install gas and electric lines that must cross a river, cross a road, or travel under a city.

 

Rock Units that Benefit Most from Horizontal Drilling

Vertical wells can effectively drain rock units that have a very high permeability. Fluids in those rock units can flow quickly and efficiently into a well over long distances.

However, where permeability is very low fluids move very slowly through the rock and do not travel long distances to reach a well bore. Horizontal drilling can increase the productivity in low permeability rocks by bring the well bore much closer to the source of the fluid.

 

Horizontal Drilling and Hydraulic Fracturing in Shales

Perhaps the most important role that horizontal drilling has played is in development of the natural gas shale plays. These low permeability rock units contain significant amounts of gas and are present beneath very large parts of North America. 

The Barnett Shale of Texas, the Fayetteville Shale of Arkansas, the Haynesville Shale of Louisiana and Texas and the Marcellus Shale of the Appalachian Basin are examples. In these rock units the challenge is not “finding” the reservoir, the challenge is recovering the gas from very tiny pore spaces in a low permeability rock unit. 

To stimulate the productivity of wells in organic-rich shales, companies drill horizontally through the rock unit and then use hydraulic fracturing to produce artificial permeability that is propped open by frac sand. Done together, horizontal drilling and hydraulic fracturing can make a productive well where a vertical well would have produced only a small amount of gas. 

 

Drilling Methodology

Most horizontal wells begin at the surface as a vertical well. Drilling progresses until the drill bit is a few hundred feet above the target rock unit. At that point the pipe is pulled from the well and a hydraulic motor is attached between the drill bit and the drill pipe.

The hydraulic motor is powered by a flow of drilling mud down the drill pipe. It can rotate the drill bit without rotating the entire length of drill pipe between the bit and the surface. This allows the bit to drill a path that deviates from the orientation of the drill pipe.

After the motor is installed the bit and pipe are lowered back down the well and the bit drills a path that steers the well bore from vertical to horizontal over a distance of a few hundred feet. Once the well has been steered to the proper angle, straight-ahead drilling resumes and the well follows the target rock unit. Keeping the well in a thin rock unit requires careful navigation. Downhole instruments are used determine the azimuth and orientation of the drilling. This information is used to steer the drill bit.

Horizontal drilling is expensive. When combined with hydraulic fracturing a well can cost up to three times as much per foot as drilling a vertical well. The extra cost is usually recovered by increased production from the well. These methods can multiply the yield of natural gas or oil from a well. Many profitable wells would be failures without these methods.

A New Lease and Royalty Philosophy

In the production of gas from a vertical well the gas is produced beneath a single parcel of property. Most states have long-established mineral rights rules that govern the ownership of gas produced from vertical wells. The gas is often shared by all landowners in a block of land or a radius distance from the producing well.

Horizontal wells introduce a new variable: a single well can penetrate and produce gas from multiple parcels with different owners. How can the royalties from this gas be fairly shared? This question is normally answered prior to drilling through a combination of government rules and private royalty-sharing agreements. How royalties are divided and how “hold-out” landowners are treated can be more complex than with a vertical well.

Source: http://geology.com/articles/horizontal-drilling/ (Jan 2014)