S-lay method is the oldest and the most commonly used method for offshore pipeline installation. This is named as “S-lay” because the shape of the pipe line while being installed looks like S-shape (Figure 1).

Figure 1 – S-Lay Method (Courtesy of Allseas) 

While installing pipe line using S-lay method, the pipe line is eased off the stern of a pipeline installation boat as the vessel moves forward. The pipe line is transferred into the sea until it reaches the sea bed which is called the “Touch down poin.t. Each joint of pipe line is welded on the installation vessel and eased off the boat. A stringer located at the stern, whose length can be up to 300 ft., helps supports the pipeline when it is transferred into the sea. Some installation barges can be equipped with an adjustable stringer which is used to control the length of a stringer. This stinger is vulnerable to damage in bad weather.

Figure 2 – S-Lay Diagram

The S-lay method can handle the full range of pipe sizes and it is considered most suited to water depth around 2,000 ft (600 m) of water depth. The pipe line is welded horizontally in a fire line (Figure 3). Depending on the vessel capacity, speed of laying the pipe can be up 6 – 8 km per day and the pipe size can be up to 60” in diameter.

Figure 3 – Pipeline Welding on the S-Lay Barge

This method requires high longitudinal tension in order to avoid excessive bending at the touchdown point (sag-bend) and the departure point (over bend). Two ways that restrict ability to quickly change a route direction are high tension and long lay-back distance.

These are some examples of installation barges.

 S-Lay Barge – Allseas vessel 

S-Lay Barge – Allseas vessel

S-Lay Barge – SEMAC-1 

S-Lay Barge – SEMAC-1

One of the most critical pieces of equipment is the pipe tension, which will keep the pipe in the required tension while laying pipe with the S-lay method (Figure 4).

Figure 4 – Pipe Tension System

Departure angle at a stinger is typically about 30- 40 degree reference to the horizontal plan. However, the angle can be increased to 60- 70 degree in deep water operation.

Over-bend radius is proportional to the departure angle and inversely proportional to lay tension. The over-bend is controlled by a stinger. Sag-bend radius is inversely proportional to lay tension and proportional to suspended weight of pipeline. Proper tension must be maintained while laying the pipeline, otherwise risk of buckling will drastically increase.

When tension is not sufficient, the sag bend will increase. Hence, the chance of buckling is higher in the sag bending area. Even though longitudinal tension is minimum, hydrostatic pressure at this point reaches almost maximum.

References

OMBugge, (2009), Barges [ONLINE]. Available at: http://i566.photobucket.com/albums/ss102/OMBugge/Offshore%20Vessels/Barges/P1010044.jpg [Accessed 16 July 2016].

James G. Speight, 2014. Handbook of Offshore Oil and Gas Operations. 1 Edition. Gulf Professional Publishing.

Trond Bendiksen, 2015. Commissioning of Offshore Oil and Gas Projects: The manager’s handbook. Edition. AuthorHouse.

Joseph A. Pratt, 1997. Offshore Pioneers: Brown & Root and the History of Offshore Oil and Gas. Edition. Gulf Professional Publishing.

Offshoreenergytoday.com, (2014), S-Lay Barge – SEMAC-1 [ONLINE]. Available at: http://www.offshoreenergytoday.com/wp-content/uploads/2014/06/Pipeline-installation-begins-at-Ichthys-project.jpg [Accessed 16 July 2016].

OMBugge, (2014), S-Lay Barge – Allseas vessel [ONLINE]. Available at: http://i566.photobucket.com/albums/ss102/OMBugge/Offshore%20Vessels/Misc%20Offshore%20vessels/Audacia/Audacia_01.jpg [Accessed 16 July 2016].

Allseas, (2014), Allseas vessel [ONLINE]. Available at: http://allseas.com/wp-content/uploads/2015/07/01-Pipeline-installation_00-S-lay-1024×648.jpg [Accessed 16 July 2016].

J-Lay pipeline installation method is frequently used in deep water pipeline installation. The curvature of pipe line is similar to J shape (Figure 1) while the subsea pipeline is being installed. J-Lay method can handle a full range of pipeline size and it is particularly suitable for deep water pipeline installation up to 2,000 m (6,560 ft).  Furthermore, the J-Lay method can withstand higher underwater current and sea state than the S-Lay method.

The J-lay method puts less stress on the pipe line because the pipeline is installed in an almost vertical position. Whereas the S-lay method puts on more stress due to two curvatures at the sag bend and over-bend region. The pipeline is sent into water at a small angle reference to a vertical line and continues at a steep angle until a sag bend is formed.

Figure 1- J-Lay pipeline vessel

This works very well in deep water environment where distance from a vessel to a touchdown point is quite far because sag bend is not too much. If the short distance from a vessel to a touchdown point.

This video demonstrates how J-Lay method works.

Example of a J-Lay Pipe Vessel

Saipem 7000 Lay Barge

J-Lay tower handles quadruple jointed pipe

Laid Blue Stream twin pipeline across Black Sea:

− Maximum water depth 2,150 m BMSL.

− Pipeline OD = 24”. WT 1.25”

Heavy lift cranes rated at 14,000 mT.

Saipem 7000 Lay Barge

References

James G. Speight, 2014. Handbook of Offshore Oil and Gas Operations. 1 Edition. Gulf Professional Publishing.

Trond Bendiksen, 2015. Commissioning of Offshore Oil and Gas Projects: The manager’s handbook. Edition. AuthorHouse.

Joseph A. Pratt, 1997. Offshore Pioneers: Brown & Root and the History of Offshore Oil and Gas. Edition. Gulf Professional Publishing.

Gazprom.com, (2012), Saipem 7000 Lay Barge [ONLINE]. Available at: http://www.gazprom.com/f/posts/14/420254/04881_005.jpg [Accessed 24 July 2016].

Reel lay method installs offshore pipeline by sending the pipeline from a reel mounted on a special pipeline installation vessel. Instead of connecting each joint of pipe line at an offshore location like other methods (S-lay and J-lay method), the pipeline is pre-assembled in a spool which is mounted on the deck of the reel barge. This method can lay pipe up to 16” diameter and water depth capacity for 16” pipeline is about 800 m (2,600 ft). This method cannot lay such a big size pipe because the big pipeline is not flexible enough to be rolled into a reel.

The reels can be installed either horizontal or vertical. Horizontal reel barges can do only S-lay installation; however, vertical reel barges can perform both J-lay and S-lay pipeline installation.

The reel lay method is considered to be the fastest laying method because the majority of welding and inspections are performed onshore in order to minimize time for installation. Once all pipe on the reel is laid, the barge either head back to shore of another reel or lift a new reel from a supply boat. This is dependent of each vessel.

Some of the images of reel lay barges are shown below;

Figure 1 – Vertical reel-lay barge in S-lay configuration

Figure 2 – Vertical reel-lay barge in J-lay configuration

References

James G. Speight, 2014. Handbook of Offshore Oil and Gas Operations. 1 Edition. Gulf Professional Publishing.

Trond Bendiksen, 2015. Commissioning of Offshore Oil and Gas Projects: The manager’s handbook. Edition. AuthorHouse.

Joseph A. Pratt, 1997. Offshore Pioneers: Brown & Root and the History of Offshore Oil and Gas. Edition. Gulf Professional Publishing.

You need to watch and see till almost the end. You will see what wrong.

The object is accidentally dropped into the wellbore. This would cause a lot of time and money to fish it. 

These are some comments from people.

Brennon Larose – All a person has to do is close blind Rams break the bit hoist up put the hole cover on then screw the bit off by hand then if it ever did fall in the hole the bit would be sitting on the blind Rams

John Osborne –  People saying close blind Rams are in my opinion wrong Rams only supposed to be closed in an emergency closing Rams to stop things falling down hole is bad practice there is always another way lifting cap tugger ensure dog collar was secure this could have been avoided easily.

You don’t close blind Rams to protect hole this is bad practice dog collar should be properly maintained and to lift bit out of hole like this is wrong as soon as bit sub disconnected lifting cap should have been installed no matter how small bit it and then tugger attached closing Rams for this is wrong.

If you closely watch video it’s clear that this was not a bit in hole they had side door casing elevators on bales which appear to be sized for approx 3 1/2 to 4 1/2 so they had probably just pulled out hole old casing which historically is when things start to go wrong crew fatigue excitement of job nearly complete a time when driller and crew should be more vigilant human error yes but totally avoidable.

Jason Abel – This what fast tracking & little experience results in, oh and a driller with his head up his arse. Why wasn’t it screwed onto bit sub first while hole was covered.

Venus Houde – How are you supposed to monitor for returns with closed blind rams? Always monitor open hole. Always cover the hole on the rig floor. They should have made up the bit to the sub and the motor or collar before ever putting it in the hole.

Mickey Turner – Well bit breaker latch was in need of repair. So keep your equipment in good shape. And don’t just through it when thru with it (which I have done). Make sure your on same page with anyone on a lift. No matter how small or big. As for as blinds being closed that’s day 1 stuff.

How can we prevent this issue?

Please feel free to share your thought in the comment below.

You can imagine that you can travel to the Troll A platform in the North Sea without working in the oil and gas industry.  It cost you quite a lot of money

This is the news below.

Bored with palm-fringed beaches and turquoise seas? Then the gigantic oil platforms of the North Sea beckon. The first ever “rig-spotting” cruise just ended off the coast of Norway, and those onboard the four-day trip said it was jawdropping.

“I couldn’t believe that these big buildings could be made,” said passenger Kari Somme, 86, after seeing Statoil’s (STL.OL) Troll A platform – the heaviest structure ever moved by mankind – towering 200 meters (650 feet) above the surface of the sea.

“It’s just wonderful, just wonderful. I was so excited because I didn’t know much about it. So when I came here and we went from rig to rig, or platform to platform, I was amazed,” she said.

The North Sea is usually known for its cold and storms.

The group of 120 tourists, all Norwegians except for a German and a Swedish couple, paid between 6,000 crowns and 30,000 crowns ($700-$3,500) for four days on board the high tech offshore vessel Edda Fides.

The trip was organized by Edda Accommodation, a firm that provides housing for oil workers working offshore. It was looking for new ways to drum up business: oil firms are cutting costs to cope with a 60-percent drop in the price of oil since mid-2014.

“There was little activity, so we used our creativity to come up with ideas. We organized this trip in six weeks,” Bjoern Erik Julseth, the hotel manager on board, told Reuters by phone.

The group toured oil installations at the Troll, Balder or Ringhorn fields. Right after this ended, a second tour departed for a trip further north to the fields of the Norwegian Sea.

Many were curious to see Norway’s oil production first hand. Oil brought wealth to a once-poor country of 4.2 million within a generation, and is still its top industry. But the bulk of the work is unseen as it takes place offshore.

“Every Norwegian knows that the oil has brought us wealth and welfare that can’t be compared to nothing or to no one,” said passenger Arnt Even Boe, a journalist.

The tourists were not allowed to board the rigs for security reasons, but the offshore workers seemed thrilled to get visitors.

“Some of them fired flares or used water canons to welcome us … We even had a rescue helicopter, with one worker dangling above us,” said Julseth, adding that the company would now evaluate whether to do another cruise tour again.

Passenger Nils Olav Nergaard brought his drone on the trip and said it had been “a real adventure”.

“To be a part of a high-tech offshore vessel, almost as a crew, and get the experience to go to the oil platforms and see them for real, that was very amazing,” Nergaard said.

Ref: http://www.reuters.com/article/us-norway-oil-cruise-idUSKCN1070SW

Pipeline towing method is useful for bundled pipelines where several pipelines with different functions are packed together inside a large carrier pipe. The pipeline is constructed in a designed length onshore and towed into the sea.

Figure 1 – Bundled Pipeline Ref: https://anthropologyinthewind.files.wordpress.com

Since there are many pipelines bundled together inside a big carrier pipe, it is imperative to get everything right prior to installation.  Due to this reason, this installation technique allows the bundled pipeline to be welded, inspected and tested onshore prior to installation in order to minimize failure.

Four categories for the pipeline towing method are as follows;

Surface and Near Surface Tow

For the surface tow, buoyancy modules are installed at designed intervals so that the pipeline is floated and the top of the pipe just breaks the surface. For the near surface tow, this is similar to the surface tow. The only different is the pipeline is usually suspended below buoyancy modules. Two towing vessels are used to tow the pipeline. One is used to pull and the another one is used to hold back, therefore the pipeline can be transported in a controlled manner. Once the pipeline is towed to the desired location, the pipeline is properly flooded by a specific procedure in order to safely lower the pipeline onto the seabed. This technique is vulnerable to weather deterioration. Strong weather conditions can damage the pipeline while it is being transported. Additionally, in a strong current condition, it is extremely difficult to accurately position the pipeline.

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Figure 2 – Surface Tow

Controlled Depth Tow (Mid Depth Tow or Catenary Tow)

The pipeline is not floated with this technique and it submerses due to its weight or hanging chains on the pipeline at particular intervals. While the pipeline is being towed, the pipeline is suspended in a flat catenary between two vessels and proper tension to the pipeline must be maintained. One of the most critical parts is control of the submersed weight of the pipeline, which is roughly inversely proportional to the square of length of pipeline. Maximum length is about 5 km.

Figure 3 – Controlled Depth Tow (Mid Depth Tow or Catenary Tow)

Off-bottom Tow

The off-bottom tow method has a similar configuration to the controlled depth tow; however, the pipeline is held down to float about 1 – 2 meters off sea bed by chains hanging from the pipeline and dragging on the sea bed. The risk of pipe damage due to abrasion is eliminated because the pipeline does not contact with the sea bed.

Bottom Tow

The pipeline is dragged on the bottom of sea so the pipeline is not affected by currents. If the sea state is too bad for the tow vessel to operate, the pipeline can be simply left on the bottom and retrieved later when the weather permits. Before selecting this towing method, the sea bed must be seriously surveyed in order to confirm the bottom area is suitable for towing. During the tow, it is very important to have survey as precisely as possible. Since the bottom part of the pipe will touch the seabed all the time, the outer protection of the pipeline can be damaged in some extent. Therefore, buoyancy modules can be installed in order to reduce submerged weight and friction force acting on the body of the pipeline.

Figure 4 – On Bottom Tow

On the other hand, if the over-bend is excessive, localized transverse buckle can be occurred. This will result in reduction of collapse resistance of pipe in the buckled zones. When the pipe is lowering down into the sea, hydrostatic pressure increases as it gets deeper. If collapse resistance at the buckle is exceeded, transverse buckle can quickly propagate along the pipeline. Therefore, a large area of pipe can be buckled and damaged.

It is imperative that in some areas where high potential buckling can be seen, it is recommended to install buckle arrestors at optimum points in the pipeline where water depth imposes high collapse pressures.

References

James G. Speight, 2014. Handbook of Offshore Oil and Gas Operations. 1 Edition. Gulf Professional Publishing.

Trond Bendiksen, 2015. Commissioning of Offshore Oil and Gas Projects: The manager’s handbook. Edition. AuthorHouse.

Joseph A. Pratt, 1997. Offshore Pioneers: Brown & Root and the History of Offshore Oil and Gas. Edition. Gulf Professional Publishing.

Lusilier, (2013), File:SubmarinePipelinesConstruction PullTowSystems.svg [ONLINE]. Available at:https://upload.wikimedia.org/wikipedia/commons/thumb/7/7d/SubmarinePipelinesConstruction_PullTowSystems.svg/744px-SubmarinePipelinesConstruction_PullTowSystems.svg.png [Accessed 29 July 2016].

2016 Osprey Shipping Ltd, (2013), Osprey Shipping [ONLINE]. Available at:http://www.ospreyltd.com/images/user/Knarr%20Launch%201.jpg [Accessed 29 July 2016].

Suction anchor or suction caisson is an offshore foundation which is quite popular for offshore installation. It utilizes a negative pressure concept to drive the suction anchors down. This article will demonstrate some simple calculations used for the suction anchor.

Figure 1 – Suction Anchor

Example:

A suction anchor, 40” OD x36” ID, is deployed as part of a mooring anchor for a floating production platform in 900 ft of water. The initial penetration due to its weight is 5 feet into the sea.  Soil resistance is 450 lb/ft² by average.  Based on the given information, determine values from these two questions below;

• What is the volume evacuated for each foot of penetration?
• How long of a suction anchor will be needed so that the top of the suction anchor is 5 ft above the seabed at the end of the operation?

Figure 2 – Suction Anchor Submerse by Its Weight

Important Information

The sea water density = 64.0 lb/cu-ft (8.6 ppg)

Steel specific gravity = 785

What is the volume evacuated for each foot of penetration?

Assumption: Impermeable formation

Volume (ft³) = 7.07

How long of a suction anchor will be needed so that the top of the suction anchor is 5 ft above the seabed at the end of the operation?

Figure 3 – Suction Anchor Diagram (Before and After)

The initial penetration support weight of the suction anchor therefore is only the frictional force between soil at the seabed and the hydrostatic pressure from the water column will be taken into account.

L = the length of the suction anchor resisting the force from hydrostatic pressure applied at the top of the suction anchor.

This is assumed that the friction generated by initial penetration continues to oppose and equal the buoyed weight of the suction anchor.

Based on the assumption, the force from soil resistance is equal to force from the hydrostatic pressure acting against the top of the suction anchor.

450 × surface area = Hydrostatic pressure × area of top of the suction anchor

L = 176.5 ft

Total length of the suction anchor = 5+ 176.5 + 5 = 186.5 ft

Figure 4 demonstrate the final condition compared to the initial condition.

Figure 4 -Final Diagram

References

James G. Speight, 2014. Handbook of Offshore Oil and Gas Operations. 1 Edition. Gulf Professional Publishing.

Trond Bendiksen, 2015. Commissioning of Offshore Oil and Gas Projects: The manager’s handbook. Edition. AuthorHouse.

Joseph A. Pratt, 1997. Offshore Pioneers: Brown & Root and the History of Offshore Oil and Gas. Edition. Gulf Professional Publishing.

SEMAR AS, (2013), Shelley Field [ONLINE]. Available at: http://www.semar.no/semar/bilder/Shelley-field.jpg [Accessed 29 July 2016].

In the oil and gas industry, a Christmas tree is referred to as a series of valve & spool assembly fitted on top of the well.  A Christmas tree is installed on top of the last casing spool on a surface well or the high pressure wellhead housing for a subsea well. Figure 1 demonstrates the diagram of a Christmas tree and wellhead of a surface wellhead. The Christmas part is located at the top part (a blue box) and the wellhead part is the lower section (a red box). Many people get confused about what a Christmas tree and a wellhead are and many times they think of them as the same thing.

Its functions are as follows;

• Allow reservoir fluid to flow from the well to the surface safely in a controlled manner.
• Allow safe access to the wellbore in order to perform well intervention procedures.
• Allow injections as water or gas injection.
• Provide access to hydraulic line for a surface control sub surface safety valve (SCSSSV)
• Provide electrical interface for instrumentation and electrical equipment for electrical submersible pump (ESP)

In this section, it will describe about a surface Christmas tree (Dry Tree) which is referred to as any Christmas tree used above water level. A Christmas Tree consists of a series of valves and the components are shown and described below;

Mater Valve

A master valve is located above the tubing hanger and its function is to allow the well to flow or shut the well in. Typically, there are two master valves. One is called a lower master valve and another is an upper master valve. Two valves are often used because they provide redundancy. If one master valve cannot function properly, another valve can perform the function. Figure 2 and Figure 3 shows a simple diagram of a single and two master valves, respectively.

Figure 1 – Christmas Tree and Well Head Diagram

Figure 2 – Single Master Valve

Figure 3 – Upper and Lower Master Valve

T type fitting (T-Block)

T type fitting (T-Block) allows diversion of flow stream from vertical to a horizontal flow line.

Figure 4 – T type fitting

Wing Valve (Flowing Wing)

A wing valve is located on the side of a Christmas tree and it is used to control or isolate production from the well into surface facilities. Depending on each design of a Christmas tree, it can be equipped with one or two wing valves.  Some operators require two production wing valves, one as a main production and another one as a backup (Figure 5). In many cases, one wing valve is used for production and another wing valve is used as a kill wing valve (Figure 6).

Figure 5 – Wing Valve

Figure 6 – Production and Kill Wing Valve

Choke

Choke is the smallest restriction in a Christmas tree, and its function is to control the production rate of a well. It is also use to control sand production in some cases. A choke restricts areas for production flow through a bean or an orifice inserted into a choke body. The smaller diameter of the beam results in the lower the production rate. Two types of chokes are 1) positive choke with interchangeable beans 2) adjustable choke which allows adjusting the choke size easily.

Figure 7 – Choke Valve

Swab Valve

On a Christmas tree, a swab valve is the topmost valve providing vertical access to the well for well intervention operations conducted by wireline, slickline, coiled tubing or a snubbing unit.

Figure 8 – Swab Valve

T-Cap and Pressure Gauge

T-Cap is a flange located on top of the swab valve which allows a wireline lubricator or a coiled tubing/ snubbing unit BOP to connect to a well in order to perform well intervention programs. A pressure gauge is used to monitor the pressure of the well. Nowadays, most of the operators often use electronic gauges so pressure and/or temperature data can be transmitted via an electronic system for better well monitoring.

Figure 9 – T-Cap and Pressure Gauge

Unitized Christmas Tree

A unitized Christmas tree is an integrated Christmas tree which consists of a lower and upper master valve, and a swab valve in one body. This will allow an operator to save operational time for installation.

Figure 10- Unitized Christmas Tree

References

Jr. Adam T. Bourgoyne, 1986. Applied Drilling Engineering (Spe Textbook Series, Vol 2). Edition. Society of Petroleum Engineers.

J.J. Azar, 2007. Drilling Engineering. Edition. PennWell Corp.

The Australian Drilling, 1997. Drilling: The Manual of Methods, Applications, and Management. 4 Edition. CRC Press.

Steve Devereux, 1999. Drilling Technology in Nontechnical Language. Edition. Pennwell Pub.

The heavy lift crane vessel ‘Saipem 7000’ has completed the installation of all ‘Ivar Aasen’ topside modules at the Ivar Aasen oil field in the Norwegian sector of the North Sea.For the lift, the crane vessel used its dual 7,000t cranes to lift the combined 15,000t modules from a Cosco heavy lift vessel onto a steel jacket attached to the seafloor.

The main part of the topside was built in Singapore and transported through the Suez Canal to the North Sea aboard the MV Xiang Rui Kou. The living quarters along with the flare boom and other modules were picked up along the way. Ivar Aasen field operator Detnorske says first oil is expected in December 2016.

Source: https://vimeo.com/167425991
http://www.offshorevisie.nl/2016/07/27/ivar-aasen-topside-installation-in-north-sea/

Subsea tree (wet trees) is a system of valves, flow paths, piping, and connectors installed on a subsea wellhead to contain and control the flow of fluid from a reservoir or from the surface by injection. A control pod mounted on a subsea tree assembly provides a receptacle for an umbilical and contains the electronic and hydraulic components that control tree functions.

Two type of subsea Christmas tree are vertical Christmas trees and horizontal Christmas trees. They are different because of valves arrangement. The vertical trees have all valves arranged vertically; whereas, the valves in the horizontal tree are positioned horizontally.

In this part, it emphasizes on vertical subsea Christmas trees (conventional subsea trees). Vertical trees are manufactured in single bore and dual-bore configurations and pressure ratings are between 5,000 and 15,000 psi. The body of a Christmas tree can be made of carbon steel, low-alloy steel, or stainless steel depending on the operating environment. Figure 1 show the conventional single-bore subsea tree from DrillQuip.

Figure 1 – Conventional single-bore subsea tree. Courtesy of DrilQuip

Vertical trees can have dual bore configurations because this allows operators to monitor annulus pressure (Figure 2).

Figure 2 – Dual Bore Subsea Tree

Figure 3 illustrates a simple diagram of a vertical dual bore subsea tree.

Figure 3 – Diagram of Vertical Tree

A typical vertical subsea tree consists of the following valves:

Production lower and upper master valve – Its function is to open or close the main bore containing hydrocarbons. Typically, a subsea tree has two master valves for a safety reason. The lower production master valve is designed for ROV operation.

Production wing valve – Its function is to control the flow of hydrocarbons into a subsea flow line.

Production swab valve – Its function is to provide access to the production bore during well intervention.

Crossover valve – Its function is to control flow between the production tubing and annulus.

Annulus master valve – Its function is to open or close the annulus bore.

Annulus wing valve – Its function is to control flow from the production flow line or control umbilical to the annulus.

Annulus swab valve – Its function is to provide access to the annulus bore during workover reentry.

Important Features of Dual Vertical Subsea Trees

• The completion tubing is landed in the high pressure wellhead housing.

• Two vertical bores allow access to the tubing and tubing/production casing annulus.

• Workover can be performed with a dual bore lower riser package, emergency disconnect package and riser.

• Each bore has a swab valve and a master valve; therefore, these provide two independent barriers to flow.\

• Most trees can be run and recovered with ROV intervention.

• It requires the BOP to be nippled down only one time after landing a completion string.

Brief Operational Sequences for Installing a Vertical Subsea Tree

• Spud the well riserless
• Run conductor with low pressure wellhead housing
• Cement conductor casing
• Drill and run surface casing with high pressure wellhead housing (wellhead)
• Cement surface casing
• Nipple up a subsea BOP on the high pressure wellhead housing
• Complete drilling and cementing program
• Run completion
• Set tubing hanger into the wellhead
• Set wireline plugs through tubing hanger running tool and test.
• Retrieve tubing hanger running tool.
• Nipple down BOP
• Pull BOP and marine riser to surface.
• Install vertical tree either from the rig or an alternative vessel and perform test on the tree
• Rig up intervention package
• Remove wireline plugs
• Recover intervention package
• Install a tree cap

This video from Expro group demonstrates how a subsea vertical sea system is installed in deep water operation. This can give you some ideas on how the tool works.  The video may be slightly different from the sequences stated above because each operator can perform the operation differently. However, the overall concept is similar to the sequences.

References

2012. Subsea Engineering Handbook. 1 Edition. Gulf Professional Publishing.
Add to My References

William L. Leffler, 2011. Deepwater Petroleum Exploration & Production: A Nontechnical Guide, 2nd Edition. 2 Edition. PennWell Corp.

Jr. Adam T. Bourgoyne, 1986. Applied Drilling Engineering (Spe Textbook Series, Vol 2). Edition. Society of Petroleum Engineers.

J.J. Azar, 2007. Drilling Engineering. Edition. PennWell Corp.

The Australian Drilling, 1997. Drilling: The Manual of Methods, Applications, and Management. 4 Edition. CRC Press.

Steve Devereux, 1999. Drilling Technology in Nontechnical Language. Edition. Pennwell Pub.

OneSubsea, (2014), OneSubsea reaches subsea trees milestone [ONLINE]. Available at: http://www.offshoreenergytoday.com/wp-content/uploads/2014/03/OneSubsea-reaches-subsea-trees-milestone2.jpg [Accessed 6 August 2016].

http://www.dril-quip.com/resources/catalogs/11.%20SingleBore%20Subsea%20Completion%20System.pdf

A subsea horizontal tree is designed so that all flow control valves are outside the central wellbore. A tubing hanger is located inside of a subsea horizontal tree body. A horizontal tree is well known as a workover friendly tree because it offers easy access for tubing retrieval because the valves are not located at the centre of the wellbore. Figure 1 shows an image of a horizontal subsea tree from GE oil and gas.

Figure 1 – Horizontal Subsea Tree Model VetcoGray M-Series MVXT and MHXT (Courtesy of GE Oil & Gas)

Figure 2 illustrates a simple diagram of a horizontal subsea tree.

Figure 2 – Horizontal Subsea Tree Diagram

A typical horizontal subsea tree consists of the following valves:

Production master valve – Its function is to open or close the main bore containing hydrocarbons.

Production wing valve – Its function is to control the flow of hydrocarbons into a subsea flow line.

Production isolation valve – Its function is to isolate production from a well and a flow line.

Crossover valve – Its function is to control flow between the production tubing and annulus.

Annulus master valve – Its function is to open or close the annulus bore.

Annulus isolation valve – Its function is to isolate the annulus side.

Annulus workover valve – Its function is to provide monitoring and bleed off pressure between a tubing hanger and a tree cap

Important Features of Subsea Horizontal Trees

• A tubing hanger is landed in the tree body.
• All valves located externally provide a clear path for well bore access.
•  An internal tree cap is run on top of the tubing hanger in which crown plugs can be set by wireline.
• The large through-bore design of a horizontal tree allows installation and retrieval of a completion string, downhole equipment, artificial lift completions, etc through a tree body without having to nipple down the tree or disconnect flow lines.
• Height of a horizontal tree is less than a vertical tree; therefore, risk of damage due to trawl boards is smaller than a vertical tree.

Brief Operational Sequences for Installing a Horizontal Subsea Tree

• Spud the well riserless
• Run conductor with low pressure wellhead housing
• Cement conductor casing
• Drill and run surface casing with high pressure wellhead housing (wellhead)
• Cement surface casing
• Nipple up a subsea BOP on the high pressure wellhead housing
• Complete drilling and cementing program
• Once a production casing/liner is cemented, a well must be temporarily suspended by installing temporary barriers
• Nipple down BOP
• Recover marine riser and BOP
• Run a horizontal tree from the rig and test the tree
• Recover a running tool to surface
• Run BOP and marine riser on top of the tree
• Remove temporary barriers from the well
• Run completion and tubing hanger.
• Set tubing hanger inside the tree and test
• Retrieve the running tool to surface
• Install plugs inside the tree to allow the safe removal of the BOP.
• Nipple down BOP
• Recover marine riser and BOP
• Install a tree cap

This video from Expro group demonstrates how a horizontal subsea tree system is installed in deepwater operation. The video may be slightly different from the sequences stated above because each operator can perform operation differently. However, the overall concept is similar to the sequences.

References

2012. Subsea Engineering Handbook. 1 Edition. Gulf Professional Publishing.
Add to My References

William L. Leffler, 2011. Deepwater Petroleum Exploration & Production: A Nontechnical Guide, 2nd Edition. 2 Edition. PennWell Corp.

Jr. Adam T. Bourgoyne, 1986. Applied Drilling Engineering (Spe Textbook Series, Vol 2). Edition. Society of Petroleum Engineers.

J.J. Azar, 2007. Drilling Engineering. Edition. PennWell Corp.

The Australian Drilling, 1997. Drilling: The Manual of Methods, Applications, and Management. 4 Edition. CRC Press.

Steve Devereux, 1999. Drilling Technology in Nontechnical Language. Edition. Pennwell Pub.

This section will compare the pros and cons of both vertical subsea trees and horizontal subsea trees and list the criteria to select a subsea tree.

Vertical Subsea Christmas Trees

Advantages

• Vertical trees require only one time BOP nipple down.
• No wireline plug to be removed from a tree for a well intervention program.
• Better for fields that don’t expect to do workover or have small chance of doing the workover
• Simpler and cheaper to change a vertical tree when compared to a horizontal tree

Disadvantages

• If the workover operations such as recompletion, changing tubing, installing extra downhole tools, etc. are required, a vertical tree must be removed in order to install BOP on top of the well.

Horizontal Subsea Christmas Trees

Advantages

• Better for fields that expect to do workover quite often because a tree does not need to be removed.
• Can have a larger bore tubing for a horizontal tree than a vertical tree
• Lower total height of a tree

Disadvantages

• Less flexibility for operation if the delivery of a tree is delayed.
• Two runs for subsea BOP and riser are required
• Completion string must be removed if replacement of a tree is needed.
• Two wireline plugs (crown plugs) must be removed before starting any well intervention program. There have been several cases when people have faced a lot of difficulty for removing the plugs. This can lead to extra time and cost for the operation.

Subsea Tree Considerations (Vertical vs Horizontal)

• The cost of a vertical tree is similar to a horizontal tree based on similar specification.

• Changing out horizontal trees is more cost and time consuming than replacing a vertical tree because whole completion string must be removed. Vertical subsea trees can be replaced by using rig or specially equipped light well intervention vessels. However, horizontal subsea trees are required only rig to replace the trees. This results in big expenditure. Therefore, horizontal trees should be used when there is very low possibility that a tree must be changed out. It is very imperative to do extensive probabilistic study prior to selecting the horizontal trees.

• Two BOP and riser runs are required for a horizontal tree, whereas only one time of BOP and riser run is needed for a vertical tree.

• For wells requiring several completion changes during the life cycle of a well, a horizontal subsea tree will save time and cost since there is no need to remove a tree or flow lines. Modern vertical trees are connected to a flow base which allows the flowlines to remain connected when removing the tree.

References

2012. Subsea Engineering Handbook. 1 Edition. Gulf Professional Publishing.
Add to My References

William L. Leffler, 2011. Deepwater Petroleum Exploration & Production: A Nontechnical Guide, 2nd Edition. 2 Edition. PennWell Corp.

Jr. Adam T. Bourgoyne, 1986. Applied Drilling Engineering (Spe Textbook Series, Vol 2). Edition. Society of Petroleum Engineers.

J.J. Azar, 2007. Drilling Engineering. Edition. PennWell Corp.

The Australian Drilling, 1997. Drilling: The Manual of Methods, Applications, and Management. 4 Edition. CRC Press.

Steve Devereux, 1999. Drilling Technology in Nontechnical Language. Edition. Pennwell Pub.

International Well Control Forum (IWCF) has provided useful learning material, which is IWCF Drilling Calculation Part 1 – 3, to drilling people. We will review all of them and see the content inside. Additionally, these ebooks are available to download from IWCF website. Thanks for their contribution to drilling industry.

IWCF Drilling Calculation Part 1 – Introduction to Calculations

The part 1 consist of basic mathematics that you need to know in order to work out any mathematical questions. This cover from very beginning for people who don not have a strong background in mathematics before. The content is very well written and easy to understand.  There is also the answer section which you need to use to check the anwer. The content of the first part are listed below;

Section 1 Whole Numbers
Section 2 Estimating and Rounding
Section 3 Basic mathematical calculations and the use of the calculator
Section 4 Fractions, decimals, percentages and ratios
Section 5 Units of measurement
Section 6 Mathematical symbols, equations and arithmetical operations
Section 7 Introduction to solving equations and the use of formulae
Section 8 Converting and conversion tables

A Screen Capture of Drilling Calculation Part 1 (Ref: http://www.iwcf.org/)

IWCF Drilling Calculation Part 2 – Areas and Volume

The second part is about areas and volume. For the area calculation, you will learn how to determine area and estimate area with various shapes and there are discussion about units related in areas calculation. For the volume calculation part, you will learn how to define volume and capacity, how to calculate volumes of various shapes and the application on the rig. Moreover, you will learn about pump output, stroke, time which are very important to the well control calculation. The solution of this part is also provided. The details of this section is shown below;

Section 1 Calculating areas
Section 2 Calculating volumes
Section 3 Oilfield volumes
Section 4 Borehole geometry – Surface BOP operations
Section 5 Borehole geometry – Subsea BOP operations
Section 6 Pump output, strokes, time
Section 7 Volume and pump strokes – kill sheet calculations
Section 8 Trip monitoring calculations

A Screen Capture of Drilling Calculation Part 2 (Ref: http://www.iwcf.org/)

IWCF Drilling Calculation Part 3 – Well Control

The third part will cover various concepts of well control so learner must have good basic calculation background. You will learn about hydrostatic pressure and related oilfield terminology in well control. The next part is about the circulating system on the rig. The last two parts are about introduction to well control relating to kick prevention and detection, primary well control and secondary well control. There are many examples which will help you understand the key concepts and you need to practice the calculations as well.

The details of the third part is shown below;

Section 1 Hydrostatic pressure
Section 2 Primary well control
Section 3 The Circulating System
Section 4 Introduction to well control (kick prevention and detection)
Section 5 Secondary well control – An introduction to kill methods

A Screen Capture of Drilling Calculation Part 3 (Ref: http://www.iwcf.org/)

Download The IWCF Distance Learning Materials

IWCF Drilling Calculation Part 1 

IWCF Drilling Calculation Part 1 – Solution

IWCF Drilling Calculation Part 2

IWCF Drilling Calculation Part 2 – Solution

IWCF Drilling Calculation Part 3 

IWCF Drilling Calculation Part 3 – Solution

Development of the coiled tubing like we know it today started in early 1960’s. Now it is an important component of various workover and service applications. While still the use of Coil Tubing is about 75% in workover/service applications, the technical advancements have resulted in an increase in utilization of Coil tubing in drilling as well as completion applications.

Ability of performing remedial work on live well was an important driver associated with development of Coil Tubing. In order to achieve this feat, there was a need to overcome three different technical challenges: These were:

• Continuous conduit that is capable of being inserted in to wellbore (the CT string).
• Means of running the CT string and retrieving it in to or out of wellbore when under pressure (the injector head).
• Device that is capable of giving a dynamic seal around tubing string (packoff or stripper device)

Coiled Tubing Unit (Credit: ShutterStock)

The Origin of Coiled Tubing

Before the invasion of allies in the year 1944, very long and continuous pipelines were developed and produced by the British Engineers for transporting the fuel from England to European Continent in order to supply Allied armies. This project was named as operation “Pluto” which meant “Pipe Lines under the Ocean”. This operation involved fabrication and laying of a number of pipelines throughout the English Channel. Successful fabrication and the spooling of the continuous flexible pipeline gave the foundation for more technical developments which eventually resulted in the tubing strings that are used today by CT industry.

In the year 1962, Bowen Tools and California Oil Company developed first fully functional Coil Tubing unit. The purpose of this unit was washing the out sand bridges in the wells.

Early Coiled Tubing Equipment

Earlier injector heads worked on principle of 2 vertical chains having contra-rotating chains. Even today this design is used in majority of Coil Tubing units today. Striper was simple sealing device of annular-type which could be activated hydraulically to seal around tubing at relatively lower wellhead pressures. Tubing string which was used for initial trials was fabricated by the butt-welding 50 feet sections of 1 3/8 in. OD pipe in to 15,000 feet string and spooling it on to a reel with core of 9 feet diameter.

Evolution of Coiled Tubing Equipment:

During late 1960’s and in to 1970’s, both Brown Oil Tools and Bowen Tools continued improving their designs in order to accommodate the CT up to 1 in. OD. By mid-1970’s, more than two hundred of original-design Coil Tubing units were in service. By late 1970’s, a number of different new manufacturing companies (Otis Engineering, Hydra Rig Inc., and Uni-Flex Inc.) also started influencing the improved design of injector heads.

The CT strings also went through significant improvements in this period. Through late 1960’s, the CT services were dominated by the tubing sizes of 1 in. and less. And the string lengths were relatively short. The tubing length and diameter were limited by tubing mechanical properties and the available manufacturing processes of that time.

The early CT operations suffered a number of failures because of inconsistent quality of tubing and various butt welds required for producing suitable string length. However, by late 1960’s, the tubing strings were being milled in longer lengths and the butt welds were fewer for each string. The properties of steel also saw major improvements during the time. These changes and associated improvements in the reliability of CT string contributed a great deal to the continuous growth of CT industry.

Today it is common for the CT strings to be constructed from the continuously milled tubing which can be manufactured without any butt welds. Additionally, the CT diameters have continued growing to keep up the pace with requirements of strength associated with the new market applications. It is not unusual for the CT diameters of up to 2 7/8 in. to be available readily for the routine use.

Coiled Tubing Can Perform Various Tasks

Coiled Tubing Applications

Nowadays, coiled tubing is widely used in several operation and these are operations conducted by coiled tubing units.

Work String

− Fluid placement

• Nitrogen Lift
• Cement Plugs
• Cement Squeeze
• Acid Wash
• Fracture Stimulation
• Water Shut-off
• Scale Squeeze

− Tool Conveyance /Tool Manipulation

• Perforating Guns
• Plugs
• Production Logging
• Video cameras
• Fishing

− Wellbore Cleanout

• Jetting
• Milling
• Scale removal

Completion String

− Velocity String

− Gas Lift String

− ESP deployment

− Rod pump deployment

− Straddle repair

• Sand Control

Drill String

− Coiled tubing drilling using mud motors

• Side track and wellbore deepening

− Under-balanced Drilling

References

Jr. Adam T. Bourgoyne, 1986. Applied Drilling Engineering (Spe Textbook Series, Vol 2). Edition. Society of Petroleum Engineers.

J.J. Azar, 2007. Drilling Engineering. Edition. PennWell Corp.

George E. King. 2009. Coiled Tubing Introduction. [ONLINE] Available at: http://gekengineering.com/Downloads/Free_Downloads/Coiled_Tubing_Surface_Equipment.pdf. [Accessed 14 August 2016].

Worl Oil , 2005. Coiled Tubing Handbook. 1st ed. Texas: World Oil.

Coiled tubing was developed in 1970s and is one of the most important pieces of well intervention equipment in the oil and gas industry. There are several different types of it available in the industry market with several different designs of a coiled tubing unit; however, the components of a coiled tubing unit are very similar. The main differences are performance capabilities and hydraulic power control systems. This article will give an overview of the essential components of a coiled tubing unit. (Read about the history of coiled tubing here – Introduction to Coiled Tubing (CT) in Oil and Gas)

Figure 1 shows the mounted truck coiled tubing unit, which is normally used for the land operation and Figure 2 is the coiled tubing unit used for operating in an offshore environment.

Figure 1 – Coiled Tubing Unit on a Truck (Courtesy of Stewart & Stevenson)

Figure 2 – Offshore Coiled Tubing Unit (Courtesy of NOV)

The main components of a coiled tubing unit are;

• Power Pack
• Control Cabin
• Injector Head
• Pressure Control System
•  Coiled Tubing Reel

Power Pack Unit

A power pack unit provides hydraulic power to control and operate a coiled tubing unit and pressure control equipment. Generally, the power pack units have an independent electric or diesel power source which is designed to operate in Zone 1 and Zone 2 areas.

Figure 3 – Coiled Tubing Power Pack Unit

Coiled Tubing Control Unit

The control unit contains all of the necessary controls for operating a coiled tubing unit from this location. Typically, a control unit is located behind a coiled tubing reel. However, there may be a situation where the location does not permit rigging this up, so a control unit may be relocated to another place where operators will also feel safe when operating the unit. Figure 4 demonstrates the controls inside the unit and it is clearly seen that there are many instrumentations for the unit control and gauges. The level of control and instrumentation are dependent on the type of operation being performed. For example, a normal well intervention coiled tubing until will have less instrumentation than a highly sophisticated coiled tubing drilling unit.

Figure 4 – Coiled Tubing Control Unit

Injector Head

An injector head is one of the critical parts in a coiled tubing unit and it consists of several hydraulic systems that allow a coiled tubing unit to operate with a high degree of operational variability.  Its function is to supply pulling and pushing capacity required for running and retrieving a coiled turning in and out of a well. When working a live well, it is important to ensure that chain gripper blocks have adequate gripping power to overcome well head pressure force and the injector hydraulic pressure must initiate sufficient force to push a coiled tubing into a well against well bore pressure.

Figure 5 – Coiled Tubing Injector Head Drawing

Pressure Control Equipment

In order to safely operate in a live well, coiled tubing units must have pressure control systems in place for well control. Three classification of pressure control equipment for a coiled tubing unit are as follows;

Primary Barrier

A primary barrier is an initial barrier for pressure containment which is normally closed.

Stripper/Packer

Stripper/packer is a primary barrier in a coiled tubing unit and the stripper is designed to provide a pressure seal around a coiled tubing unit when it is being run into or pulled out of a live well. The sealing mechanism is activated by hydraulic pressure controlled by an operator.

Figure 6 – Stripper/Packer (Courtesy of NOV)

Tandem Stripper

Tandem stripper assemblies, which are used together with a fixed stripper, provide a backup for a stripper when the primary stripper fails or wears out during a coiled tubing operation.

Figure 7 – Tandem Stripper

Secondary Barrier

A secondary barrier is a mechanical normally open system and it is used when the primary barrier fails or becomes impaired.

Tertiary Barrier

A tertiary barrier is a mechanical normally open system and it will be used when a primary and a secondary barrier fails and the well integrity is badly impaired.

Coiled Tubing Blowout Preventer

A coiled tubing blowout preventer provides secondary and tertiary barriers to back up the primary barrier system. The BOP is used to secure the coiled tubing and isolate the wellbore pressure during normal and emergency situations. The typical arrangement of a coiled tubing BOP consists of blind rams, shear rams, slip rams and pipe rams and the diagram for the BOP is shown in Figure 8.

Figure 8 – Quad Blowout Preventer

From top to bottom, the BOP has the following rams:

Blind Rams

Blind rams are designed to close and seal off a wellbore with no coiled tubing or any tools across the BOP.

Shear rams

Shear rams are designed to cut the coiled tubing in an emergency situation, but they don’t seal rams.

Slip rams

Slip rams are designed to close around the coiled tubing and hold the tubing string whether the well forces are acting up or down, but they don’t seal rams.

Pipe rams

Pipe rams are designed to close around the coiled tubing and seal around an annulus area.

Coiled Tubing Reel

The primary function of a coiled tubing reel is to store a coiled tubing. Typically, the coiled tubing reel is hydraulically driven, whether by a chain or a direct drive. A reel driven system is designed to keep the coiled tubing in a dynamic tension between the gooseneck and the reel, while the coiled tubing is un-spooled and re-spooled.

Capacity of coiled tubing is dependent on several factors, such as the size of coiled tubing, weight and length of coiled tubing, footprint availability, etc. It is imperative to select coiled tubing which is suitable for the expected operation. Over capacity coiled tubing can lead to excessive cost and space issues for some offshore locations. However, insufficient capacity of a coiled tubing unit can result in an unsuccessful job.

Figure 9 – Coiled Tubing Reel (Courtesy of GOES GmbH)

References

Jr. Adam T. Bourgoyne, 1986. Applied Drilling Engineering (Spe Textbook Series, Vol 2). Edition. Society of Petroleum Engineers.

J.J. Azar, 2007. Drilling Engineering. Edition. PennWell Corp.

George E. King. 2009. Coiled Tubing Introduction. [ONLINE] Available at: http://gekengineering.com/Downloads/Free_Downloads/Coiled_Tubing_Surface_Equipment.pdf. [Accessed 14 August 2016].

Worl Oil , 2005. Coiled Tubing Handbook. 1st ed. Texas: World Oil.

Oil and Gas Employees in Aberdeen have been placed on gardening leave by oil giant Schlumberger for up to a year on 20% of their annual salary, however during this period they are not allowed to work for any other employer.

Perro Negro 6 Incident – Jack up rig capsized and sank was happen few year ago but we would like to share this case as a case study. You can watch what happen in the video below.

It is clearly seen that the rig capsized and sank in just few minutes. Jack up rig move is one of the most hazardous operation. Before a rig is moved, total number of people on board will be kept at minimum for operating the operation and non essential personnel will not be allowed on the rig.   There are several considerations that rig contractors and operators must be agreed before commencing any rig move operation. For this case, we would like to emphasize that even though all safety is in place, the bad thing can be happened.

Story from News

Saipem S.p.A. reported Tuesday that its jack-up drilling rig, the Perro Negro 6, capsized and sank offshore Angola after the seabed beneath one of its three legs collapsed.

The incident occurred Monday night during rig positioning on location near the mouth of the Congo River, between the coasts of Angola and the Democratic Republic of Congo, Saipem said in a statement. The rig had not yet commenced drilling when it collapsed, the statement added.

Saipem says that the Perro Negro 6 tilted suddenly Monday night after the seabed collapsed beneath it, causing hull damage and the rig to take on water. It later capsized and sank in approximately 40 meters of water at 10.30 AM CEST Tuesday after all personnel had been evacuated, Saipem said.

Of the 103 crew members on board at the time of the collapse, 6 incurred minor injuries and one is reported missing.

So far no environmental impacts have been reported.

Saipem emergency response team is mobilised and is working closely with the Angolan Authorities and the Client’s operational team.

The Perro Negro is under contract with Chevron Corporation through early 2015.

The rig was built by Labroy Shipyard in Batam, Indonesia in 2009 and can drill to a depth of 30,000 feet in 350 feet of water.

Ref – http://gcaptain.com/saipem-jack-up-perro-negro-6-sinks-offshore-angola/

When operating in a subsea environment with long subsea pipelines and risers, one of challenges is to keep up a sufficient production rate and the right amount of pressure to flow fluid from the wellheads to the production facilities. Due to this reason, multiphase pumps are widely used in subsea operations in order to overcome these issues.

Benefits of Multiphase Pumps

Multiphase pumps add hydraulic energy to production streams so produced fluid can be efficiently transported in the subsea pipelines. The benefits of multiphase pumps are as follows;

• Increase production rate in an existing export pipe-line
• Add extra energy to transport multiphase fluid and solids which may not be possible to efficiently flow in the pipelines.
• Reduce well-head flow pressure to increase oil and gas recover.
• Help produce hydrocarbon from marginal fields without installing new production facilities.
• Reduce cost of surface facility modification by installing the multiphase pumps on the seabed.

Main Issues of Multiphase Pumps

Some issues normally seen when using multiphase pumps are listed below;

• Change of flow conditions, fluid and solid content from the wellbore over the life of the well.
• Pump fluid with gas. Gas compressibility and thermodynamic behavior must be taken into account when designing multiphase pumps because this property can be drastically changed due to the operational condition of the pipeline.
• Operate with various fluid compositions. Over the production life, there are possibilities for the presence of sand production, scale & wax formation, as well as corrosive and toxic components (H2S and CO2). These issues can badly affect the efficiency of multiphase pumps.

Challenges of Subsea Multiphase Pump

Typically, a pump is designed to operation at or close to its optimum point so a pump can deliver fluid in the most efficient way. However, in oil and gas production, it is very difficult to specify an optimum condition for the pump because fluid production will change over a period of time due to the nature of reservoirs.

Multiphase pumps used in oil and gas industry must offer a broad operating envelope because of the uncertainty of the produced reservoir fluid.  Typically, oil will flow at a high rate at the beginning of the well. When the well has been producing for a longer period of time, water and gas production will increase and sometimes sand production can be seen. In order to implement the required operating envelope, a variable speed drive is required. In some situations, changing out the anew multiphase mud may be planned after a certain period because it can be more economical than having a very large multiphase pump in the beginning.

Flow Fluctuations and Slugs

Flow fluctuations can occur at any time while producing the well. Medium and short-term fluctuations can also be seen under transient operations, for example well tests, well start-up or shut-down, pipeline pigging, etc., therefore, this will result in hydraulic instability in the pipelines. Furthermore, wells that produce multiphase fluid can lead to slug flow, which can cause an issue with a multiphase pump. The most effective method to manage slug is to use a liquid recycling process. The concept is to recycle liquid into a mixer located before a multiphase pump so that the gas liquid ratio will not fluctuate much.

Two types of multiphase pumps used in the oil and gas industry are twin-screw pumps and helicon-axis pumps.

Twin-Screw Pumps (Positive Displacement Pump)

A twin-screw pump is a double ended positive displacement pump with external gears and bearings and it is composed of two parallel helical screws engaging with each other. Helical channels formed by each screw are periodically obstructed by the other screw while they are rotating. The chambers move continuously along the axes when the screws rotate and the fluid is transferred from the suction side to the discharge side. Figure 1 shows the cut away of the pump.

Figure 1 – General Configuration of a Twin Screw Pump

The theoretical volumetric flow rate of the twin-screw pump is controlled by the rotation speed, the size and pitch of the screws and the chamber volume. One shaft is directly coupled to the main drive and the second shaft is driven through a helical gear which transfers the torque and synchronizes rotation. The typical rotational speed of the screws is between 1,500 and 2,400 rpm.

A screw pump casing has an inlet capacity which can smooth out small gas slugs coming into a pump. However, if high volume gas slugs with average gas volume fraction higher than 95% enter into a pump, a pump cannot operate efficiently, Hence, an external liquid recycle system must be added. If a well produces sand, the inlet casing may also become a disadvantage because it can become a sand trap and feed screws with fluid that has a high sand content. Selecting a proper screw profile and a special hard coating for a pump will increase resistance to wear in the present of sand production.

Depending on the size of pumps, twin-screw pumps can cover total volumetric flow rates (oil, water and gas) at suction conditions from 10,000 bbl/day up to 300,000 bbl/day. Additionally, pumps can accept differential pressures of up to 1000 psi (70 bar).

The main advantages of twin-screw pumps are listed below;

• Low sensitivity to variations in Advantages of twin-screw pumpsflow conditions

• Suitable for high viscosity liquids and low suction pressure

• Relatively low rotational speed

• Low noise level

• Self-priming

• Pump capacity proportional to speed

Limitations of twin-screw pumps

The limitations of twin-screw pumps are as follows:

• Higher number of seals with limited shaft clearance
• Large size
• More suitable for land operation than offshore operation
• Shaft deflection under hydraulic load

This video below show how a twin-screw works.

Helico-axial Pumps (Centrifugal Displacement Pump)

 Helico-axial Rotodynamic pumps are multiphase centrifugal pumps used in subsea pumping. Centrifugal pumps use a different concept of fluid transfer from positive displacement pumps. Centrifugal pumps continuously transfer  energy from the prime mover to the fluid, however, positive displacement pumps impose displacement on a finite volume of fluid. During this process, mechanical work is firstly transferred to the fluid in a rotating part of the machine and then converted into pressure in a static part.

Typical centrifugal pumps do not work very well with multiphase fluid, especially with gas present in the fluid because pump performance will dramatically drop with a low percentage of gas (5-8%). A special pump concept, called “helicon-axial” is designed to overcome the present of gas in the fluid stream.

A multiphase helicon-axial pump is a multi-stage rotodynamic pump and each pump stage consists of an impeller, a static diffuser, and a rotating part mounted on a shaft. Figure 2 shows a drawing of a helico-axial pump.

Figure 2 – Helico-axial pump

One important feature of this pump is that it has free open hydraulic channels which accommodate solid particles in the flow. When a helico-axial pump is operated, it must ensure that sand will not accumulate in the pump gaps between the casing and internal parts.

Advantages of Helico-axial Pumps

Advantages of helicon-axial pumps are listed below;

• Ability to pump fluid at any gas volume fraction from 100 % liquid to 93% gas
• More compact than a twin screw pump, therefore it is suitable for offshore operation
• Mechanical simplicity and reliability
• Self-adaptation to flow changes
• High possible pressure rise up to 2,200 psi and

References

Subsea Engineering Handbook by Bai, Yong Published by Gulf Professional Publishing 1st (first) edition (2012) Hardcover. Edition. Gulf Professional Publishing.

Andrew C. Palmer, 2008. Subsea Pipeline Engineering, 2nd Edition. 2 Edition. PennWell Corp.

Qiang Bai, 2014. Subsea Pipeline Design, Analysis, and Installation. 1 Edition. Gulf Professional Publishing.

Charles Sparks, 2007. Fundamentals of Marine Riser Mechanics: Basic Principles and Simplified Analysis. Edition. PennWell Corp.

We have updated the well control equations ebook. In this ebook, it covers important well control equations in oilfield unit. The file is in pdf format and it is free to download.

These are well control formulas in this well control equation ebook 2016 version.

– Pressure (P) – psi
– Pressure Gradient (G) – psi/ft
– Hydrostatic Pressure (HP) – psi
– Bottom Hole Pressure (BHP) – psi
– Formation Pressure (FP) – psi
– Equivalent Circulating Density (ECD) , ppg
– Leak-off Test Equivalent Mud Weight (LOT), ppg
– Maximum Initial Shut-In Casing Pressure (MISICP), psi
– Kill Mud Weight to Balance Formation (KMW), ppg
– Slow Circulation Rate (SCR), psi
– Annulus Capacity Factor (ACF),bbl/ft
– Final Circulating Pressure (FCP), psi
– Surface To Bit Strokes, strokes
– Circulating Time, minutes
– Capacity Factor (CF), bbl/ft
– Opened End Pipe Displacement, bbl/ft
– Closed end pipe displacement, bbl/ft
– Height of Influx, ft
– Approximate gas migration rate, ft/hr
– Sacks of Barite Required For Weight-up, sx
– Volume Gain From Slug, bbl
– Triplex Pump Output (volume), bbl/stroke
– Pump Output, bbl/min
– New Pump Pressure With New Pump Strokes, psi
– Boyle’s Law – Gas Pressure and Volume Relationship
– Mud Increment for Volumetric Method (MI), bbl
– Lube Increment for Lubricate and Bleed Method (LI), bbl
– Bottle Capacity Required, gal
– Volume of Usable Fluid, gal
– Snubbing force for snubbing operation
– Buoyed Weight of Open Ended Tubular (Wb),lb
– Buoyed Weight of Closed Ended Tubular without fluid in the pipe (Wb),lb
– Buoyed Weight of Closed Ended Tubular after filling the pipe (Wb),lb -> in this case, there is different fluid weight in pipe and annular
– The Balance Point for closed ended and unfilled pipe is the point where the weight of pipe in the fluid equates to force created by wellhead pressure.
– This is the second case for balance point calculation. The Balance Point for closed ended pipe and the pipe is filled with fluid.
– Maximum Down Force on Jacks
– Effective Area of Snubbing Jacks, square inch

Download here – Well Control Euqations Drilling Formulas 2016

Do you dream of an employment in the oil and gas sector but you are clueless as to how to accomplish it?

You need not stress anymore. This article is just what you need to guide you to attaining that goal.

Making the decision of working in the oil and gas industry is a great one, the industry is very lucrative. However, you may face the challenge of being inexperienced and being clueless about how and where to begin from. Actually, the fact that you don’t have any initial experience is not the issue, you still have the opportunity of breaking into the industry if you plan well. A good plan, good networking and initiative will help you achieve the goal easily.

The truth is that you will work hard for it, however, if you are tenacious, it will be achieved.

This industry is very challenging though, it is also very rewarding financially and has prospect for young people especially. If you really desire to have an employment in the industry, digest the guide and you are just a hair away from getting that job of your dreams:

1. Learn vastly about the role

Even before the urgent need arises, make deep research and findings. You must be able to show your prospective employer that your are relevant to the position which is vacant and that you have perfect understanding of what the job entails. Find out about other job descriptions related to this role and the activities and the duties involved.

Also, learn about the current and past trend of the sector, the company you are applying to, its competitors and even the name of the person who will be receiving your application and resume as this will make you appear serious and will make your application stand out.

2. Your key skills should be highlighted

Have a full comprehension of the skills specifically required by the company and the ones which will be needed for the particular role you wish to apply for. Try to create a link between these skills and your own skills, experience and education. Make sure your key skills are highlighted and strategically placed at the beginning of your resume and not the end as this will be one of the first things your recruiter will look out for. This will make it easy for the recruiter to to feel you are perfect for the job as you have researched well. This would also make the company known that transferable skills can be benefited.

3. Gather the experience you don’t have

Most people are always held back by the lack of experience barrier. Every company wants someone who is well acquainted with the job roles through a prior experience to be sure you will not have teething problems in fitting in to fill the lacuna hitherto present. Instead of always facing this setback, why not invest into gaining experience. If you are not financially capable of enrolling for the necessary courses, you can do volunteer/non-paid works, or take up roles with transferable skills and which many people don’t pay attention to, that are very closely related to the one in question. You can also try getting into the industry by coming through the entry level which you may desire less, but it will get you to the position of your dream. Never despise little beginnings. With this, you will have the opportunity of meeting people, make new and beneficial friends and learn a lot, you are now in-house, it is now easier, just a step more.

4. Follow up on your application

It is very crucial to do a close follow-up of your ‘outstanding’ resume within a couple of days after applying. This a chance to make a very good first impression. There are many CVs to be attended to, in fact, a pile of them lay on the recruiter’s and he confused as to how to deal with all. Making your noticeable all the way helps him to reach a decision. He notices your enthusiasm and just thinks you are perfect after seeing your outstanding resume.

Also, this will make the recruiter search for your own resume and go through it. Following up via email or call also helps you to build a Persian relationship and make the recruiter realise you are most suitable for the job.

5. Networking is very Crucial

Knowing someone on the inside to champion your cause and accentuate your suitability may just be what you need sometimes to get that job. When you know someone who is already in that company, it greatly increases your chances of being chosen for the job as the recruiting officer, hiring manager, or Human Resource personnel is more convinced that you are good to go. This called networking and it is about building personal relationships and building positive value which is usually reciprocated. It is actually not about begging for little favours from people. Get into the circle by looking for organisations or groups that are related and relevant to the sector. Find an oil field related organisation in your locality, or a club or an allied association. For example, the Society of Petroleum Engineers (SPE), which holds various events to foster their cause, build relationships among them and interact with new members. Attend seminars, conferences, lunch meetings and training courses as these will give you the plenty chances to meet people who can become friends and associates and may help you in the future.

6. Learn the process of interview

An interview with the recruiter is good opportunity for you to sell yourself and convince the company about your worth and why your are the best for the job.

Preparing for an interview

-Know yourself

Being able to talk about your strenght, skills, career goals and accomplishments is very important. Give specific examples of your skills, experience and background to convince the c!company that it matches it own needs.

-Make research about the employer

After going through the company’s website, you can also search for useful information in recent news and articles relating to the company from the Career Exploration Websites which recommend such as Business Source Complete, Glassdoor and Hoover’s online. Thses are available to everyone through the online databases of the ZSR Library. Having a deep knowledge of the employer will stand you out among all applicants during the interview.

Learn about the personal information of the employer, such as age, size, products and/or services, the structure of the organization, division and subdivisions, branches and subsidiaries, affiliates, competitors, workforce, new products and services, successes and accomplishments, these will give you a clear edge if you can research about them.

-Practice your interview skills

Practice by engaging in a mock at the Office of Personal and Career Development and also use Interview Stream to do practices before the actual  interview.

Additional Resources for Oilfield Success