WHAT IS HOT TAP AND WHY IS IT 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:

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

o   Isolation Valve like gate or Ball Valve.

o   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.

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

o   A hot tap shall not be considered a routine procedure, but shall be used only when there is no practical alternative.

o   Hot Taps shall be installed by trained and experienced crews.

o   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.

o   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.

o   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 (see image above).

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: http://www.wermac.org/specials/hottap.html

Flow assurance is an engineering analysis process to assure hydrocarbon fluids are transported through pipelines in an economical manner from the source to the destination in a given environment over the life time of the project.

Flow assurance covers the whole range of possible flow problems in pipelines such as hydrate formation, wax & asphaltene deposition, corrosion, erosion, scaling, emulsions, foaming, and severe slugging.

The avoidance or remediation of these problems is the key aspect of flow assurance that enables the design engineer to optimize the pipeline system for the complete operating envelope including start-up, shutdown & turndown scenarios.

Flow assurance is a recognized critical part in the design & operation of both onshore & offshore oil/gas systems. 

Following are the flow assurance concerns that need to be examined:

o   Pipeline rupture from corrosion

o   Pipeline blockage from hydrates or wax

o   Severe slugging can damage separator

o   Large pressure drop in pipelines can cause lower flow than should be

Following are the flow assurance strategies that need to be adopted:

o   Hydraulic Analysis : acceptable pressure drops, pipeline size, erosion & corrosion limits

o   Thermal Analysis : temperature distribution, heat loss

o   Inhibition Analysis : hydrate inhibitors, wax inhibitors, corrosion inhibitors, scale inhibitors

When is flow assurance required?

The bulk of the flow assurance analysis is done during the Front End Engineering & Design (FEED) stage.

During detail engineering phase a verification process may be undertaken based on the following:

o   Changed product specifications including composition, phase change (GOR, water cut)

o   Change in pipeline routing

o   Changed operating procedures

o   Change in local health, safety & environmental regulation

Why modeling of pipeline systems is required for flow assurance? 

Modeling is a cost effective & tested tool for flow assurance. Some benefits are:

o   Ease of studying & optimizing new and existing pipeline systems

o   Facilitates rigorous screening of various options in existing and potential systems

o   Reduce uncertainty in design & operation

o   Reduce downtime by giving a realistic picture of how the system will be

How is modeling of pipeline systems done? 

Steady State Modeling:

o   Software such as PIPESIM & HYSYS can be utilized for steady state modeling

o   Objectives of Steady State Modeling

o   Determine the relationship between flow rate and pressure drop along the pipeline and decide the size based on the maximum allowable flow rate & the minimum allowable flow rate.

o   Check temperature and pressure distributions along pipeline in steady condition to ensure that the pipeline never enters the hydrate region during steady state operation.

o   Determine the maximum flow rate in the system to assure that the arrival temperatures do not exceed any upper by the separation and dehydration processes or by the equipment design

Transient Modeling:

o   Software such as OLGA and ProFES can be utilized for transient modeling

o   Transient Cases or Scenarios:

o   Start-up and Shut-down

o   Emergency shut-down

o   Blow-down and warm-up

o   Ramp up or down

o   Pigging / slugging

Objective of transient analysis is to ensure that the pipeline conditions are maintained to prevent dangerous surge conditions and to prevent conditions (pressure and temperature) for hydrate formation.

Source: http://www.cheresources.com/invision/blog/4/entry-73-flow-assurance-in-pipelines-an-introduction/

Temperature and pressure effects create expansion effective forces which may cause a pipeline to buckle globally. Pipelines installed on the seabed and left exposed have a potential to buckle globally and change configuration while a buried pipeline is designed to stay in place being restricted by the surrounding soil reaction forces.

The driving force for global buckling of the pipeline is the effective axial force, S, which represents the combined action of pipe wall force, N, and internal and external pressures, see Sec.5.2.2.The effective force for a restraint straight pipe, S0, constitute an upper bound axial load and is discussed in Sec.5.3.1.

For a certain expansion force, the pipeline will buckle globally. For a partially displacement controlled condition, this implies that it will find a new equilibrium by moving perpendicular to the pipe axis at the same time as the pipe will move axially, feed-in, from both sides towards the buckle. The level of axial force to initiate this global buckling depends on:

• ·         pipe cross section properties
• ·         lateral resistance
• ·         out-of-straightness in the pipeline
• ·         lateral triggering force (e.g. trawling)

A straight column will buckle according to the classical Euler buckling formulation. As the out-of-straightness in the column increases, the level of axial force required to buckle it will be reduces. This effect, away from the buckle, is illustrated in Figure 2-1.

The out-of-straightness may be caused by:

• ·         small imperfections on the seabed like the pipeline resting on rocks
• ·         global imperfections as uneven seabed

• ·         curvature in the horizontal plane purposely made or random from installation

To illustrate the global buckling of a section in a pipeline, the following idealised sequence of a pipeline with free end expansion can be used :

1.       Prior to applying pressure and temperature, the effective force will be limited to the residual lay tension. The effective force variation will be tri-linear; from zero at the pipeline ends with a linear increase proportional to the axial resistance to the soil, until it reach the residual lay tension H. It will then be constant until it reaches the decay from the other side, see lower curve of Figure 2-2.

2.       When the temperature or pressure increase the compressive effective force will increase to maximum S0, This will vary along the pipeline as the temperature and pressure decrease along the line. At the pipe ends, the load will still be zero, see upper curve of Figure 2-2. A snap shot from a short section is now selected for closer examination in Figure 2-3.

The buckling development is described in Figure 2-3.

Note also that the post-buckling load, point B above, may not be reached directly but through a continuous development. This may imply that higher force close to the buckle is achieved prior to reaching B, that may trigger another buckle.

Source: Recommended Practice DNV-RP-F110 October 2007

Pipeline welding plays an important part in both the onshore and offshore pipeline industry. Throughout the years there have been significant advancements to help ensure a pipelines durability and reliability. Here, Bob Teale takes us through the history and what’s to come.

Pipeline welding, as we know it today, started in 1927 with the introduction of Lincoln’s Fleetweld 5 cellulosic electrode. While there is no doubt that cellulosic electrodes have proven to be very effective and will remain so for years to come, they are technically limited in terms of strength, toughness, and production rates.

Once offshore pipeline construction started, there was a drive to increase production rates due to the cost of lay-barges and narrow weather windows. Initially this demand turned to using a semi-automatic CO2 gas metal arc welding (GMAW) process, but the high incidence of lack-of-fusion defects forced equipment developers to mechanise the process. While many tried, it was not until 1969 that CRC-Evans produced the first viable mechanised pipeline welding system.

The CRC mechanised system used a narrow 5° bevel, with the root deposited from the inside using a combination internal multi-head welder/clamp. The hot, fill, and cap passes were deposited externally using an orbital bug and guide band.

Despite efforts to build alternative systems, CRC dominated the landline industry for almost 25 years. This monopoly, however, was much shorter lived offshore. Within six years of the first mechanised welded offshore pipeline, Saipem introduced its PASSO system. which used a copper backing-clamp; with the root pass made, the remaining passes were deposited externally using an orbital bug.

Since Brown & Root had the offshore rights to CRC, neither this nor the PASSO system were available to other offshore contractors, and further mechanised GMAW systems were developed by ETPM (Serima-Dasa), J Ray McDermott (H.C. Price), and Allseas—Phoenix. ETPM and J Ray McDermott initially built large multi-head rack systems, and while they worked, they were not flexible and were unsuitable for land use. Eventually both companies also developed band-and-bug systems. The last major offshore contractor to build a system was Allseas, who built the automated Phoenix bug welding system.

Until 1995, all the various welding systems were owned exclusively by offshore contractors or were rented by CRC to contractors; at that time, Serimer started to rent equipment, and Vermaat Technic BV started to sell both single and dual-

head units. These were state-of-the-art automated systems and are now widely used worldwide.

Current welding technology

Most mechanised systems have now given way to computer controls and can be classed as automated systems. Today, pipeline contractors have the choice of using internal roots, external roots with copper backing, and external roots without backing. All of these root techniques are proven and have pros and cons. Internal roots produce the highest rates on land; they can also handle more alignment high/low, and do not need welders. Copper back-up clamps are cheaper than internal welders but have some risk of copper contamination and are 33–50 per cent slower.

The third-root pass option, external without backing, is based upon using a special short-arc transfer power supply. The first of these was developed by Lincoln Electric—STT (Surface Tension Transfer). The advantages of this process is that it is a much lower capital/rental cost, although on large diameter pipes, it is much slower. For example, on a 48 inch internal diameter girth weld, an internal root pass is almost twice as fast as an external copper root pass, and an external copper root pass is four times faster than no-backing root passes. Depending upon the diameter and length of the pipeline, as well as the schedule and the terrain, each root option may be cost-effective for the appropriate circumstances.

Fill-and-cap pass welding can now be accomplished using single or dual head bugs, or a combination of both. After the initial development of the band and bug single head machines, many efforts were made to build a dual head bug (PASSO, Evans Pipeline, CRC, B&R, and Astro-Arc), but it was Serimer-Dasa (now Serimax) who first produced a successful working dual head band and bug system. The impact of its dual head bug provided Serimer the opportunity to significantly increase production rates offshore where the number of weld stations is limited. While dual heads do not double production, they will increase deposition by 40–50 per cent – dual head-bugs require fewer weld stations, fewer welders, and fewer side booms.

The latest developments

Current automated pipeline welding developments tend to be centred on improved seam tracking, data logging and stronger line-up clamps. Most equipment suppliers are taking advantage of increased computing power to improve through-the-arc tracking, contact-to-work distance and arc voltage controls, and laser tracking is also available. Advanced tracking technology improves weld quality, and consistency, and improves production rates by allowing faster travel speeds. In addition to the major automated welding equipment suppliers/users, there are now many alternative suppliers of single head orbital machines. Some are still mechanised units but work well with flux-cored arc welding wires.

Future welding developments

Most alternative welding process options for pipeline welding have been examined and evaluated over the past 30 years. Some of these welding processes were pursued, such as laser/electron beam, flash butt, homopolar, SAG, MIAB, explosion, and radial friction, but all ultimately failed. While some are working on hybrid laser/GMAW bugs, it is the opinion of this author that the industry will not see a quantum leap in welding technology.

The industry also has the option to use tandem arc GMAW technology to increase welding speeds for major large diameter pipelines. Automated GMAW is tried and tested, and future developments will tend to be in more computer control and a progression to robotic automation.

The following is a timeline for major offshore GMAW welding system developments:

1969 CRC Band & Bug P-100 used on first land line

1970 CRC Band & Bug P-100 first used offshore

1978 Saipem—PASSO Band & Bug used offshore

1981 ETPM—Serimer T-2 Rack used offshore

1981 Saipem—PASSO Band & Bug used on land

1982 J. Ray McDermott—HC Price Rack S used offshore

1988 ETPM—Serimer Dual head bug: Saturnax 8 used offshore

1989 ETPM—Serimer T-4 Rack used offshore

1991 CRC Computer control Band & Bug P-200 first used

1993 Allseas Develop Automated Phoenix Band & Bug

1994 Serimer Dual head band & bug: Saturnax 8 first used on land

1995 J. Ray McDermott—Add laser tracking & computer controls to Rack

1995 Vermaat Band & Bug System single & dual head units

1995 Lincoln Electric STT power supply, no-backing root passes

1998 J. Ray McDermott—Utilise Dual head JBBS/Vermaat bugs offshore

2001 CRC P-450 Tandem Head Bug first used on X100

2002 Saipem Develop PRESTO Dual head bug for J-Lay

Source: http://pipelinesinternational.com/news/the_long_and_welding_road_to_pipelines/63321

What is Risk Assessment?

Risk assessment is a process used to evaluate unwanted consequences and the likelihood of those consequences occurring. The purpose of risk assessment is to develop information that allows organizations to make decisions that reduce or eliminate unwanted consequences by changing their likelihood, their adverse impacts, or both.

For instance, aircraft manufacturers analyze the performance effects of different aircraft designs to minimize the likelihood of crashes. Government agencies evaluate the effects of emissions from industrial plants, or motor vehicles, in order to develop regulations that limit emissions and minimize adverse impacts to the public and the environment.

The terms “risk analysis” and “risk evaluation” are often used interchangeably with “risk assessment”.

What is risk?

Risk is a concept that describes and measures the combination of the likelihood of a negative outcome and the severity of consequences that result from that outcome. The higher the risk number, the more “risky” is the combined likelihood and severity of a particular event.

Likelihood is measured as probability ( a number between 0 and 1 that represents the chance of some consequence occurring) or asfrequency (a number that represents how many times a consequence occurs during a fixed time period).

Consequence is measured in a variety of ways, depending on the nature of the consequences being considered. For example, if the consequences involve human health or safety, then consequences may be measured by fatalities or injuries. If consequences involve environmental damage, they may be measured by the cost required to repair the damage and restore the affected environment.

How do pipeline operators use risk assessment to enhance pipeline safety?

Risk assessment is used to address issues pertaining to safety, environmental protection, financial management, project or product development, and many other areas of business performance. In the pipeline industry, risk assessments are utilized for many of these same reasons. For the purposes of this fact sheet, however, we are addressing risk assessment related to pipeline safety – that is, protecting the public, property, and the environment from pipeline failures.

Risk assessments of this kind begins by looking at the different ways a pipeline can fail and release its contents – such as oil or natural gas – into the environment. Factors that can lead to pipeline failure are referred to as pipeline failure threats . For example, a pipeline can leak because corrosion weakens the steel in the pipe. Failures also occur as a result of excavation equipment striking the pipe. Identifying potential threats to a pipeline requires looking at the factors that cause failures as well as looking for unique factors that could lead to failure at a particular location, whether or not that particular failure has occurred or been observed before.

The next step in risk assessment is to assess the likelihood that each threat could lead to a failure at a particular location on the pipeline. This assessment is performed by looking at the specific characteristics of the pipeline at any given location, along with the unique characteristics of the area around the pipeline. For example, the susceptibility of the pipeline to failure due to corrosion is dependent on numerous characteristics, such as the type and condition of the pipe’s coating, the effectiveness and operability of the operator’s corrosion control equipment, and the soil conditions surrounding the pipe.

As another example, the susceptibility of a pipeline to third-party excavation damage is dependent on characteristics such as the extent and type of excavation or agricultural activity along the pipeline right-of-way, the effectiveness of the One-Call System in the area, the amount of patrolling of the pipeline by the operator, the placement and quality of right-of-way markers, and the depth of cover over the pipeline. In all cases, different threats will exist at different locations along the pipeline.

The next step is to assess the types of consequences that could result from a pipeline release at a specific location, along with the potential severity of those consequences. For example, failures of pipelines in remote areas, where people do not live or congregate, will likely result in lower impacts than failures in areas of dense residential or commercial development. Similarly, failures in areas sensitive to environmental damage, such as the locations of drinking water sources or endangered species’ habitats, have higher environmental consequences than areas without these features.

The final step in risk assessment for a pipeline is to use the results of the likelihood and consequence assessments to determine the overall risk at each pipeline location. This allows the operator to ensure that sections identified as having the highest risk are assigned top priority for actions that will reduce the likelihood of a release, reduce its potential consequences, or both.

The results of the likelihood assessment also provide the operator with information on the significance of different pipeline threats at different locations, allowing them to carry out actions that reduce the likelihood of a pipeline failure. For example, an operator may choose to conduct internal inspections on those pipeline sections that are shown to be most susceptible to corrosion, to identify where corrosion might be occurring, and to repair any damage before the pipe fails.

The results of the consequence assessment provide the operator with information on the significance of consequences of accidents at different locations, so that operators can carry out steps to reduce or eliminate those consequences. For example, an operator may place specialized emergency response equipment at an environmentally sensitive site to allow for quick response should a pipeline release occur.

What are the requirements for risk assessment by pipeline operators?

It is important for pipeline operators to be keenly aware of threats and potential consequences of accidents along the entire length of their pipelines, and to employ rigorous assessment as a tool to manage those risks.

The federal pipeline integrity management regulations for hazardous liquid pipelines ( §195.452) and natural gas pipelines ( §192.901- §192.951) require operators to perform risk assessments of their pipelines to:

o    Ensure that integrity assessment methods (internal inspection, pressure testing, direct assessment, etc.) are employed to address significant threats on pipeline segments.

o    Ensure that integrity assessments of the highest risk segments are scheduled with priority over lower risk segments.

o    Ensure that assessments of threats and potential consequences are conducted to define, evaluate, and implement additional measures that address significant threats to the pipeline (e.g., conducting depth-of-cover surveys and correcting any deficiencies), or reduce potential consequences of failures (e.g., installing additional valves on the pipeline to reduce the amount of liquid or gas that might be released should a failure occur).

Source: https://primis.phmsa.dot.gov/comm/FactSheets/FSRiskAssessment.htm

Conduits to transfer materials from the seafloor to production and drilling facilities atop the water's surface, as well as from the facility to the seafloor, subsea risers are a type of pipeline developed for this type of vertical transportation. Whether serving as production or import/export vehicles, risers are the connection between the subsea field developments and production and drilling facilities.

Multiple Riser ConfigurationsSource: www.atlantia.com

Similar to pipelines or flowlines, risers transport produced hydrocarbons, as well as production materials, such as injection fluids, control fluids and gas lift. Usually insulated to withstand seafloor temperatures, risers can be either rigid or flexible.

Types Of Risers

There are a number of types of risers, including attached risers, pull tube risers, steel catenary risers, top-tensioned risers, riser towers and flexible riser configurations, as well as drilling risers.

The first type of riser to be developed, attached risers are deployed on fixed platforms, compliant towers and concrete gravity structures. Attached risers are clamped to the side of the fixed facilities, connecting the seabed to the production facility above. Usually fabricated in sections, the riser section closest to the seafloor is joined with a flowline or export pipeline, and clamped to the side of the facility. The next sections rise up the side of the facility, until the top riser section is joined with the processing equipment atop the facility.

Also used on fixed structures, pull tube risers are pipelines or flowlines that are threaded up the center of the facility. For pull tube risers, a pull tube with a diameter wider than the riser is preinstalled on the facility. Then, a wire rope is attached to a pipeline or flowline on the seafloor. The line is then pulled through the pull tube to the topsides, bringing the pipe along with it.

Building on the catenary equation that has helped to create bridges across the world, steel catenary risers use this curve theory, as well. Used to connect the seafloor to production facilities above, as well as connect two floating production platforms, steel catenary risers are common on TLPs, FPSOs and spars, as well as fixed structures, compliant towers and gravity structures. While this curved riser can withstand some motion, excessive movement can cause problems.

Top-Tensioned RisersSource: www.atlantia.com

Used on TLPs and spars, top-tensioned risers are a completely vertical riser system that terminates directly below the facility. Although moored, these floating facilities are able to move laterally with the wind and waves. Because the rigid risers are also fixed to the seafloor, vertical displacement occurs between the top of the riser and its connection point on the facility. There are two solutions for this issue. A motion compensator can be included in the top-tensioning riser system that keeps constant tension on the riser by expanding and contracting with the movements of the facility. Also, buoyancy cans, can be deployed around the outside of the riser to keep it afloat. Then the top of the rigid vertical top-tensioned riser is connected to the facility by flexible pipe, which is better able to accommodate the movements of the facility.

First used offshore Angola at Total's Girassol project, riser towers were built to lift the risers the considerable height to reach the FPSO on the water's surface. Ideal for ultra-deepwater environments, this riser design incorporates a steel column tower that reaches almost to the surface of the water, and this tower is topped with a massive buoyancy tank. The risers are located inside the tower, spanning the distance from the seafloor to the top of the tower and the buoyancy tanks. The buoyancy of the tanks keeps the risers tensioned in place. Flexible risers are then connected to the vertical risers and ultimately to the facility above.

Hybrid Riser SystemSource: www.2hoffshore.com

A hybrid that can accommodate a number of different situations, flexible risers can withstand both vertical and horizontal movement, making them ideal for use with floating facilities. This flexible pipe was originally used to connect production equipment aboard a floating facility to production and export risers, but now it is found as a primary riser solution as well. There are a number of configurations for flexible risers, including the steep S and lazy S that utilize anchored buoyancy modules, as well as the steep wave and lazy wave that incorporates buoyancy modules.

While production and import/export risers transfer hydrocarbons and production materials during the production phase of development; drilling risers transfer mud to the surface during drilling activities. Connected to the subsea BOP stack at the bottom and the rig at the top, drilling risers temporarily connect the wellbore to the surface to ensure drilling fluids to not leak into the water.

Source: http://www.rigzone.com/training/insight.asp?insight_id=308&c_id=17#sthash.PYmiHAxn.dpuf

Used on offshore oil and gas fields, a subsea tree monitors and controls the production of a subsea well. Fixed to the wellhead of a completed well, subsea trees can also manage fluids or gas injected into the well.

Source: Cameron

Since the 1950s, subsea trees have been topping underwater wellheads to control flow. A design taken from their above-ground cousins, subsea trees are sometimes called xmas trees because the devices can resemble a tree with decorations.

Subsea trees are used in offshore field developments worldwide, from shallow to ultra-deepwaters. The deepest subsea trees have been installed in the waters offshore Brazil and in the US Gulf of Mexico, and many are rated for waters measuring up to 10,000 feet deep.

Types Of Subsea Trees

There are various kinds of subsea trees, many times rated for a certain water depth, temperatures, pressure and expected flow.

The Dual Bore Subsea Tree was the first tree to include an annulus bore for troubleshooting, well servicing and well conversion operations. Although popular, especially in the North Sea, dual bore subsea trees have been improved over the years.

These trees can now be specified with guideline or guideline-less position elements for production or injection well applications.

Standard Configurable Trees (SCTs) are specifically tailored for company's various projects. A general SCT is normally used in shallower waters measuring up to 1,000 meters deep.

High Pressure High Temperature Trees (HPHT) are able to survive in rough environments, such as the North Sea. HPHT trees are designed for pressures up to 16,500 psi and temperatures ranging from -33 C to 175 C.

Other subsea trees include horizontal trees, mudline suspension trees, monobore trees and large bore trees. Companies that manufacture subsea trees are Aker Solutions, Cameron, FMC Technologies and Schlumberger.

Source: http://www.rigzone.com/training/insight.asp?insight_id=302&c_id=17#sthash.99VqcicH.dpuf