Cased and perforated completion is the most common type of completion which is selected my many companies. For this completion, a production casing or a liner is cemented through reservoir zone(s) and subsequently, a well is perforated in order to provide communication between the formation and wellbore.

Perforation should ideally penetrate deeper rather than nearer a wellbore damage zone around a wellbore so fluid from a reservoir can effectively flow into a wellbore. Additionally, several depth control methods help to accurately select which section of reservoir to be perforated. Hence, undesired zones, such as gas, water or weak formation can be avoided and this will improve well production efficiency.

Cementing around the wellbore is one of the critical parts for this completion because good cement will effectively isolate all zones and allows a wellbore to produce from several zones without communication between reservoirs. Moreover, packers are run into a wellbore to isolate reservoir fluid when it flows into a wellbore.

Another important feature of this completion is the ability to selectively produce or inject into any reservoir. A sliding sleeve on each zone can be opened and closed to allow selective production or injection operation. Figure 1 illustrates the diagram of cased and perforated completion.

Figure 1- Example of Cased and Perforated Schematic

Advantages of cased and perforated completions

• Safer operations
• Better zonal isolation
• Facilitation of selective perforation and stimulation
• Effective way to complete multiple zones in one well
• Better reservoir management
• Ability to shut off any undesirable productions such as water, gas, or sand
• Long term cost effective
• Ability to work over and recomplete the well
• Better well integrity
• Less sand production than open hole completion

Disadvantages of cased and perforated completions

• Extra cost for casing, cementing, perforation and completion equipment.
• Lower reservoir exposure than open hole completion

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Single zone completion is one of the types of upper completion which allows producing only one zone. Production tubing is a flow path for fluid from a reservoir to flow to the surface so it protects the casing from corrosion and maximizes the efficiency of the flow.

In a single tubing string completion, typically a packer is set on top of a reservoir so the reservoir fluid can flow up into the production tubing. Types of packers are based on several factors as temperature, pressure, reservoir fluid, etc. Additionally, complexity of tubing and packer installation is driven by objectives.

Features of a Single String Completion are listed below;

• Through tubing perforation can be performed.
• Packer can be set with x-mas tree in place.
• Reservoir can be isolated and workover operation can be done.
• Downhole measurements can be effectively conducted.

Figure 1 and Figure 2 show a simple diagram of a single zone completion. In single zone completion, artificial lift methods as gas lift, ESP, etc. can be deployed.

Figure 1 – Single Zone Completion

Figure 2 – Single Zone Completion with Gas Lift

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Multiple zone completion is one type of completion which allows operators to selectively produce or comingle reservoir fluid from different zones into one well.  It is also possible to workover the upper part of completion string without removing the next interval completion.  Additionally, through tubing perforation is can  performed at the bottom zone.  A multiple zone completion can be divided into two parts, which are single string completion and multiple string completion.

Single String Configuration

In a single string completion, a packer will be set above  each zone in order to isolate fluid from each zone. What’s more, a packer will prevent corrosion in the production casing due to the flow of reservoir fluid.  Figure 1 demonstrates an example of a single string configuration

Figure 1 – Completion Equipment Arrangement for a Single String Configuration

Multiple-String Configuration

A multiple-string configuration consists of two or more completion strings in one well. This is more expensive and complicated to install than a single-string configuration. However, it has some advantages such as the ability to simultaneous produce and injec into different zones and has a more accurate production allocation than a single string type.

Figure 2 – Completion Equipment Arrangement for a Dual String Configuration

Nowadays, single string completions are preferred to multiple string completions because of several issues as listed below;

• Less expensive
• Easier to install and workover
• Size of a production string in a single string is typically bigger than a multiple string at the same production casing size.
• Less complications for well control equipment

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Sand control is a method to control sand production into a wellbore. This is common requirement for several oil and gas producing wells around the world. There are two situations which cause sand production. The first cause is rock mechanical failure near wellbore and the second one is dragging force from producing or injection fluid. Sand production can lead to several issues such as production impairment due to sand plugging, erosion to completion string and down hole tool, damage surface facilities as separator, piping, etc.

In order to avoid sand production, there are two main methods as listed below;

Passive sand control – This method uses non-intrusive measures to control, mitigate or avoid sand production from the reservoir. The following techniques are passive sand control methods.

• Oriented perforation
• Selective perforation
• Sand management

Active sand control – This method relies on the use of filters to control sand production and it is known as intrusive measure. The following techniques are active sand control methods.

• Stand alone screens (slotted liner, wire-wrapped screen, prepacked screen and premium screen)
• Expandable sand screen
• Gravel pack & Frack Pack
• Chemical consolidation

Stand alone screens

This type of sand control is to put a screen to stop sand production into a wellbore. Initially, fine sand and silts will pass through the screen. Once sand packs are developed around the screen, they will be like a filtration media which prevents sand to flowing into a wellbore. There are several types of screens used in oil and gas industry, such as slotted liner, wire-wrapped screen, prepacked screen and premium screen. This is suitable for well-sorted, clean with large grain size formation.

Slotted Liner

Slotted liner, which is one of the oldest sand control methods, is tubing with series of slots cut through a wall of tubular in an axial orientation (Figure 1). Width of slots is design to create inter-particle bridging across the slots. This is the least expensive way of making a standalone screen and it is very simple. The flow area is average about 3%, but it can go up to 6% of total area of pipe. However, flow areas over 6% will be detrimental to pipe tensile strength.

Figure 1 – Slotted Liner

(Ref -http://image.ec21.com/image/tjpowerful/oimg_GC02070430_CA07710645/Slotted_Casing_Pipe_Slotted_Liner_Slotted_Pipes_Tubing.jpg)

There are two types of slots which are straight and keystone slots (Figure 2). Keystone slots are considered to be a better choice than straight slots because of their self-flush ability. However, keystone slots are generally more expensive than straight slots. In general, slots are 1.5 to 2.5 inches long and width varies from 0.012 to 0.250 inches.

Figure 2 – Type of slotted liner

Wire-Wrapped Screen

 Wire wrapped screen is a perforated pipe with a wire-wrapped jacket welded around. Wires wrapped around the vertical ribs are keystone shaped, which is designed for decreasing the chances of sand plugging the screen because it has a self-cleaning action. It has a bigger flow area in comparison to a slotted liner and it provides good strength and accurate slot opening area.

There are three main types of wire-wrap screens as listed below;

• Rod-based screens
• Pipe-based slip-on
• Pipe-based direct build screens.

Figure 3 shows a drawing of wire-wrapped screen configuration.

Figure 3 – Wire-Wrapped Screen

(Ref – http://www.sand-screen.com/img/wire-wrapped-screen-structure.jpg)

The wire-wrapped screen can be used as a standalone screen or used with a gravel pack. The critical part of having successful sand control with wire-wrapped screen is to have well-sorted formations. Poorly sorted formation will not be effective because fine particles will pass through the screen, whereas the big particles are blocked. Fine particles in a wellbore will flow with producing fluid and cause damage to downhole and surface equipment. In a poorly sorted reservoir, the wire-wrapped screens are typically used behind a gravel pack because a gravel pack is well-sorted grain size that people can control.

Pre-Packed Screen

 Pre-packed screen is similar to a wire-wrapped screen but it has different filtering media. A media gravel layer with or without resin coating is placed around the internal screen component and is supported by an external screen (Figure 4). Thickness and size of medium layer depends on well requirements, such as formation size, flow rate, hole size, etc.

Figure 4 – Pre-Packed Screen

(Ref Image- http://www.variperm.com/themes/variperm/img/landing-page/pre-pack-screen.jpg)

The main concern about the pre-packed screen is a chance of plugging it with completion fluid, drilling mud, etc. Therefore, in order to mitigate this issue, Carbolite proppant can be utilized as the main pack media rather than re-sieved gravel. There are several advantageous about Carbolite such as bigger pore throats, precise sorting grain size, and better permeability than normal re-sieved sand.

Premium Screens

 Premium screens are an all metal design with a protective outer metal shroud and a metal mesh filtration. The main advantages of premium screens over other screens are screen plugging resistance and ability to flow back drilling fluid through the screens. The metal mesh can be specially designed depending on each service providers or customer requirements. Pore throat can vary from 60 micron to 300 micron and the ideas it that the mesh will prevent large particles and allow fine particles to flow through at the initial stage. Then large particles will form a permeable sand filter cake layer on the surface of screen, which will prevent fine and large particle from flowing though. Premium screens are normally run behind gravel pack and they are famous for running in long horizontal wells.

Figure 5 – Premium Sand Screen

(Ref- http://www.offshore-mag.com/content/dam/offshore/print-articles/volume-74/01/sandfacecompposter_off1401.pdf)

Expandable Sand Screen

 Expandable screen is the latest screen technology. It includes perforated pip, a filter media and an outer shroud. The screen is run in to a wellbore and the expansion insert is used to expand the screen to the production hole diameter.

The advantages of setting expandable screens against formation are as follows;

• Effective sand control
• Provides wellbore support
• Gives maximum hole diameter
• Gives a high inflow area

Typical expandable screen is consisted of four main parts:

• Base pipe
• Filtration media
• Outer protection shroud
• Integral expandable connector

The video below shows the Weatherford expandable sand screen system.

There are several systems on the market so you may need to do technical and operational comparison among service provides to find the best solution  to match with requirements.

 Gravel Pack (Cased Hole and Open Hole) and Frack Pack

 Gravel pack is one of sand control methods and it uses sized sands as a filter media to prevent sand production. Annulus between wellbore and a sand control screen (wire wrapped or premium screen) is filled with sized gravels which prevent formation sand to flow into a wellbore.

Open hole gravel pack (external gravel pack) is useful for controlling sand in heterogeneous formations. However, cased hole gravel pack (internal gravel pack) is utilized for controlling sand and protecting sand screens from erosion flow.  Frack pack is a combined gravel pack with fracturing technique which creates wide and long conductive fractures. This technique will control sand production and improve productivity of wellbore.

Figure 6 – Open Hole and Cased Hole Gravel Pack

(Ref Image – http://www.dunefront.com/images/Open_and_Cased_Hole_Gravel_Packs.png)

Advantages of gravel pack are as follows;

• Productivity impairment can be minimized by proper design
• It can be used in heterogeneous sands.

 Disadvantages of gravel pack are as follows;

• Complex operation to install equipment and place gravel in place
• Risk of incomplete gravel pack
• Chemical compatibility of drilling fluid
• Difficult to use in deviated and horizontal wells
• Complex flow control and isolation

Chemical Consolidation

Chemical consolidation is an alternative way to the mechanical method to control sand production in unconsolidated formation by injecting chemical into formation in order to strengthen or consolidate sands. The main goal is to cement sand grains together to provide stable compressive strength while maintaining initial permeability as much as possible. This is the most complex sand control method which involves significant risks of damaging reservoirs and/or ineffective chemical placement. This technique involves muti-stage injection of several chemicals into a reservoir.

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Obviously this isn’t the best time to graduate in Geophysics, Geology or Engineering if you have a plan to make a career in oil & gas at this time 2016. However, it isn’t the first time that such precipitous fall in the oil prices has taken place, and many people in the industry today graduated when the prices of oil previously hit low levels, quite similar to the present situation. So what are the things that new graduates should do in order to position themselves for the time when oil prices finally begins rising again and “recovery” starts in the oil industry.

Keep your options open

It might be that you have tailored the degree carefully in order to have a career in oil & gas, but there are some associated disciplines that are worth consideration. These include:

 Mining Environmental geology

• Hydrogeology
• Mechanical engineering
• Civil engineering

Almost any job is going to be relevant in one way or the other – it might provide you with practice and training in presenting, help you improve computer skills, or at very least it will help you interact with other people and you will get to learn from their experiences. Later on you can parlay it in to relevant experience on the CV. Moreover it will also provide you with salary to keep your bread and butter going.

Build Your Network

 Get in touch with other engineers and geologists to attend the conferences (take advantage of the student rates or see the suggestion 4 below about volunteering). Ask to connect with as many oil & gas professionals as possible. Obviously meeting face to face will be most beneficial. When you go to any event, be straight forward and introduce yourself. Do some research on the speaker and their field of research so that you can ask intelligent questions. Politely ask any questions that you have and they will hopefully remember you.

 Consider Traveling

This will certainly give you with very valuable life experience and the employers will be more interested as it will demonstrate that you are an independent person. You can also visit the areas that have close proximity to the oil & gas operations, as it might result in you getting the roles that are not advertised, like joining rig crew.

 Postgraduate Studies

It is a wise decision to sign up for the Master’s degree. It is like entering into a holding pattern while waiting for the prices of oil to rise, at the same time gaining valuable qualification. I can’t recommend either thesis or course based Masters programs but you will get valuable knowledge and tools that are relevant to oil industry in both cases. Personally, I would recommend the thesis-based Masters as it demonstrates resilience to complete one. It also demonstrates the ability of closing out projects, ability of collecting, collating, evaluating, integrating and interpreting data and then sharing your results with other people. And of course there is a great opportunity of leveraging your project through presenting at the technical conferences or for the special interest groups. This will help you get in public eye and it will help you to build your network.

Regarding the PhDs, the key attributes are a project that’s somewhat relevant to the industry (that is preferably funded by oil companies, a single company or a consortium). In addition the project should be of your interest, as you would be spending a minimum of 3 years working on the project. It would be better, if the project is field based.

Commonly, the graduate students are looking for the field assistants. You might just be able to grab a great travel opportunity with great learning and good field experience thrown in. Usually, room and board are included. You can visit engineering or geology departments at the universities and tell them that you are interested in helping. You might also get the opportunity to help with the labs and as demonstrator. It is guaranteed that you’ll learn a lot if you take on such a role.

Volunteer

Another great thing that you can do is to join relevant organizations and attend the conferences and meetings. Usually you can volunteer to receptions, man booths, etc. at the conferences. You will get to attend free of cost. Such events provide great chances of networking. Many organizations like SPE, IADC, AAPG and CSPG, have reduced rates for the students. A number of other volunteer opportunities for different organizations are also there.

 Be Imaginative

A number of other ways of practicing your skills are there. Read papers, Do some off the cuff fieldwork. Take some free online courses. Learn the terminology of oil field. Go to the schools to give presentations. Go to the museums and ask them if you can be of any help. Set up some field trips looking at the stones of buildings in your area and you can do online advertisement of such a trip. Just go wild with your imagination.

At the end of the day, it is suggested by the history that the oil prices are going to rise again in future, and at that point you can start applying for the new opportunities. The important thing is that you should not let this waiting period go to waste.

This article will explain the overview of slips and elevator which are very important tool on the rig.

Slips

Slips are wedge-shaped gripping devices which are used to suspend the drill string in the hole. They fit around the body of drill pipe and wedge in the taper of the rotary table’s opening. Slips have serrated inserts or dies that will grip the outside diameter of the tubular when it is set on the rotary table. To set the slips, rig crews place them around the pipe and the driller then slowly lowers the pipe until the slips can take up the load. The dies in the slips will firmly hold the pipe. In order to remove the slips, rig crew grasp the slip handles and as the driller picks up the pipe, they lift them out of the rotary table opening and set them aside.

You can watch this video to see how the rig crew set and remove the slips

Figure 1 – Slips are set on the rotary table.

Figure 2 – Slips are on the rotary table

When using drill collars and other tubulars that do not have an elevator shoulder, a safety clamp (dog collar) is installed above the slips. If the gripping elements on the slips fail, the drill collar would slide down. Before the collars can slide all of the way out of the slips into a well, the safety clamp would hold the collars against the top of the slips.

Figure 3 – A safety clamp is installed.

There are several types of slips and spiders that are normally used in drilling and running a casing operation. A spider, like slips, suspends the pipe in the hole, but a spider does not fit inside the rotary table’s opening. Instead, they rest on top of it. Spiders are used instead of slips when the rotary tables bushing size is not compatible with the tubular being run. Another case for using a spider elevator (Figure 4) is when flush joint casing is run. Because flush joint casings don’t have the collar, the spiders will grip the body of pipe while running in or pulling out of a hole.

Figure 4 – Spider Elevator (500 Ton air-controlled casing spider).

Power slips (Figure 5) are powered by a heavy duty high-strength coil spring or by air and they are used instead of manual handing slip by a human. A driller or rig crew can operate the power slips remotely by a remote control.

Figure 5 – Power Slip (Courtesy of NOV)

Elevator

The elevator is used to latch around the top of pipe joints in the drill string. Once latched, the driller can raise and lower pipe in and out of the hole. Rig crews attach the elevator to the hook or Top Drive with two forged high-grade steel rods called links or bails. One end of the link fits into the link ears on the hook or Top Drive. Link locking arms secure the links into the ears. Crew members then attach the elevator to the other end of the links. Most elevators are hinged and rig crews open and close them by operating the latch with two handles on each side.

Figure 6 – Elevator and Bails

A drill pipe elevator has a tapered seat (Figure 7). This taper matches the taper on the tool joint of the length of drill pipe. When properly latched, the tool joint taper rests in the elevator taper and makes a firm and positive grip without damaging the drill pipe.

Figure 7 – Elevator has a tapered profile (Courtesy of NOV).

Some drill strings or drill collar don’t have a shoulder so a lifting sub is screwed into the end of the joint to aid in the lifting of the drill strings. They latch the elevator onto the taper on the lifting sub to raise or lower drill collars into and out of the hole.

Figure 8 – Drill Collar and Lifting Sub

For a top drive system, the links holding the elevator have an air operated or pneumatic tilt mechanism (Figure 9). The driller activates the tilt mechanism when the pipe is being pulled from the hole. When the top of the drill string reaches the derrick man’s position at the monkey board, the driller can tilt the top of the stand of the pipe toward the derrick man. The derrick man can then unlatch the elevator and set the stand back in the fingerboard.

Figure 9 – Link Tilt

One of the advantages of wireline tool is to be used as a part of finishing operation. This video provided by Weatherford will guide you to understand about wireline tools and their functions in the fishing operation. We also include the full vdo transcript in order to assist learning of people in our industry as usual.

Wireline Tool for Fishing Operation Transcript

Fishing services are frequently used to retrieve unwanted objects from a wellbore such as tools or equipment; and twisted or broken sections of pipe or tubing. Fishing also includes the recovery of stuck drilling or production strings. Stuck drill pipe or tubing results in costly downtime and occurs all too often both in open hole and cased hole situations. The causes of string sticking are numerous. Sand or heavy mud in the wellbore can build up in the annulus to create sticking. During drilling in tripping, the string can wear a groove into the high side of an open hole. This group called a key seat can lead to sticking and all types of wells. Differential sticking can occur when the hydrostatic pressure of the mud column exceeds the pressure exerted by porous underground formation. As the mud filter cake increases in thickness, the likelihood of differential or wall stuck drill collars also increases. There are other reasons for strings sticking but whatever the cause, the object in all cases is to determine at what point the string of stuck and at what point it is free.

The free-point can be determined with a special electronic free-point tool running on wireline. The free-point tool is securely attached to the wireline; and both are small enough to be run inside the stuck drill pipe or tubing. As the drill applies torque or stretch to the string, this free-point tool measures the difference in pipe stress in the section between the two fixed points. The stress in the section of pipes is sensed by the down hole detector and electronically transmitted via the wireless to the surface panel where it is displayed on a readout meter. The down-hole free-point reading is directly proportional to the amount of torque or stretch being applied to the string from the surface. After making a calculation to estimate the stuck point, experienced wireline operators begin taking readings slightly above the calculated stuck point. As the stuck point is approached, readings will decline until the detector is in the totally stuck section of the string indicating no pipe movement. Through this method of data interpretation, a skilled wireline operator determines the free-point precisely, only by combining all available wellbore information with specialized training and experience. Can expert operator compensate for various down-hole conditions to determine the actual free point.  Whether for its unique three point detector, the Home Co stresstector has several advantages over other free-point detection systems. The stresstector is extremely sensitive to torque and stretch. It can detect even subtle movement including tension, compression, and right or left hand torque.

The ability to read left hand torque is essential in certain fishing situations. Another advantage of this stresstector design is its durability. It can be run in combination with stringshot explosives which reduces the time involved in freeing the stuck string.  A new version of the Home Co stresstector, the stresstector II is being introduced for slim hole, coiled tubing and high temperatures situations. The smallest size stresstector II at 5/8 inch diameter has been developed to handle pressures up to 20,000 psi and over 400 degrees Fahrenheit.

Regardless of which detector is used, once the actual free-point is determined, the free pipe can be removed from the wellbore after backing off from the stuck section of pipe below it. A backoff is made by applying left hand torque and holding torque toward the controlled explosive charge  placed across a connection is detonated. The explosion allows the connection to be unscrewed without damaging the threads. The freed pipe is then removed from the wellbore.

It is often necessary to cut a section of pipe or tubing to remove it. Among the cutting tools available to Weatherford wireline operators is the chemical cutter which uses hydrofluoric acid to cut pipes. The chemical cutter servers the cutting without leaving a flare or debris. This eliminates the need to mill or dress the top of the top of the fish making it easier to recover with an overshot fishing tool.

Another cutting device the jet cutter, severs the pipe with a shaped explosive jars. Like the chemical cutter, the jet is matched to the size of tubing being cut. The jet cutter is also used to cut drill pipe casing and corroded or rusted pipe. The jet cutter leave a a flared fish top which must be milled or dressed off with a mill guide before the fish can be caught.

Still another tool used in fishing is the severing tool. The severing tool utilizes a powerful explosive charge run on wireline which violently severs, heavy weight drill pipe, and drill collars when conventional backoff techniques are not possible. The severing tool is recommended only as a last resort in expensive open hole situations such as offshore drilling operations.

In open hole operations situations, special wireline tools are used to perforate multiple shots per foot in a string of stuck pipe. Perforations are sometimes necessary to establish circulation to the annulus or spot lubricating fluid to help free the stuck pipe. Other specialized wireline tools are employed by Weatherford operators to aid in the removal of casing, drill pipe or tubing. Wireline caliper tools are used to measure the inside diameter of downhole pipe.

Occasionally in open hole fishing, junk may be too large and must be broken up into small pieces to be more easily retrieved. In these instances of powerful explosive charge run on drill pipe is placed directly on top of the junk downhole. With the shot in position and go double electronic charge carrier is dropped inside the drill pipe. When it strikes to charge, it safely fires down-hole. The smaller debris is then recovered. This first module in Weatherford series on fishing operations has reviewed the techniques and common tools used in wireline pipe recovery operation.

Open hole fishing is one of the most time consumed operation  because it involves a lot of unknown down hole conditions. In order to have successful fishing operation, it is imperative to fully understand about the open hole fishing tool. The video training below provided by Weatherfor is considered as one of the best fishing operation video training. Additionally, the full video transcription is provided to help people understand this topic.

Open Hole Fishing Transcription

Open hole fishing involves the removal of unwanted objects from the wellbore. The objects can be tools, equipment, and broken pieces of drill, pipe, bits or tribunals. Open hole fishing begins following a backoff and a drill string at or above the stock point of the fish in the wellbore leaving an accessible fish top. The fish can be removed using special tools and techniques.

A screw-in sub is one of the most common fishing tools. Its modified pin can be used to catch an undamaged fish. The overshot tool because of its versatility is frequently used in fish recoveries. Its simple design included circulating and releasing action as well as a 360 degree catch of the fish.

Normally, the overshot or screw in sub is connected to the bottom of the bumper sub and fishing jars on the fishing assembly. As the tool is lowered over the fish, the top of the fish passes through the tool into the ball. When the assembly is raised, grapples engage the fish at a lower point and it is worked free and pulled upward. If the top of the fish is bad, twisted or broken, it should be dressed off to provided clean top so grapple can insecurity firmly. Dressing off is achieved with a skirted or hollow food mill. Several types of mills are available for this purpose and other jobs.

In a washed-out hole, use of a hydraulic knuckle joint located above the overshot kicks out under pump pressure to increase the sweep of the overshot to facilitate capture of an elusive fish. With a severe washout, a wall hook guide run on the bottom of the overshot, further improves the search and capture of the fish. When the fish cannot be dislodged by pulling with the overshot, a jarring assembly run in the fishing strain can be activated to strike heavy blows either up or down on a stock fish to freak. The down action is achieved with a bumper jar, essentially a slip joint with a sliding stroke. The impact, enhanced by the weight of drill collars above the bumper jar results in a sharp blow with the fishing string. Dropping the string quickly produces a sharp downward blow on the fish. This jarring action is especially effective in free e-seated pipe or a string that is stuck as a result of an upward blow.

In many cases are stuck fish will require a powerful upward jar to free. Hydraulic fishing jars permit an impact.

The impact produced by hydraulic jar depends on the amount of pulled taken on the tour before it drips. As indicated earlier, the impact of a hydraulic jar is enhanced by the weight of drill collars placed above the tool. A jar accelerator further intensifies the effect of a jar at any depth. It is especially effective in shallow fishing operations where elasticity present in longer drill strings is not in any way. The use of an accelerator also keeps the energy of the jar impact from being lost up hole.

When a fish is stocked in and cannot be jarred or work free, a widely used practice called washover is employed. The washover operation is the most successful way of freed of fish and requires expert judgment both in pipe selection and in its proper running applications. As modern whole conditions are critical, in many cases of bit drip may be necessary to condition the hole prior to running the washpipe.

Essentially, washover operations involve a pipe string that slips over a stuck fish allowing fluid to circulate in the annulus between the fish in the inner wall of washover pipe. Fluid under pressure flushes out debris cut loos by the rotary shoe run on the bottom of the washover pipe. The washed over fish secured by an overshot or screw in sub and then he backed off and removed to the surface. The washover pipe selected requires an inside diameter large enough to accommodate the fish and an outside diameter they can rotate without sticking in the open hole and still allow circulation.

Various types of weatherford rotary shoes are available. Each shoe is custom designed for a particular procedure. Tooth-type shoes for example, are recommended when the formation to be cut is relatively soft. When metals such as tool joints or stabilizer blades must be cut, the rotary shoe is dressed with tungsten carbide or diamonds internally, externally or both, tailored specifically. And improper choice could severely damage the fish, complicating the recovery operation. Occasionally with drill pipe maybe plug usually by mud. Cutting the free drill pipe with a mechanical outside cutter run on the washpipe will remove the obstruction and establish a clean, workable top. Following the washover, the washpipe is pulled up and the shoe removed and replaced by a mechanical outside cutter. Run into the well and over the freed fish, the cutter is engaged. With a slight upward string, cutter knives are fed through the wall of the drill piped fish and the fish is parted. Rotation has then stopped and the cut piece of fish is recovered and pulled to the surface. When the fish  is stock off bottom, washpipe spear maybe run in conjunction with the wash wipe and screwed into the fish prior to the washover procedure. This prevents the fish freed by the washover operation from dropping to the well bottom and damaging the well board, drilling string or drilling bit.

Open hole fishing also involves the retrieval of the junk at the well bottom. Junk is defined as any unwanted material in the hole that hampers operations such as accidentally dropped tools, metal debris and parts of equipment including cones from drill bits. A commonly used retrieval tool is the fishing magnet. Fishing magnets are especially cost effective for retrieving smaller ferrous objects such as bitcones, slips and mill cuttings. Permanent magnets have circulating ports around the outer edge so that fill and cuttings can be washed away exposing the junk for proper magnetic contact. Magnets are furnished with plush guides, lipped guides or mill guides which help in washing and securing the junk. The magnet is lowered to the well bottom while circulating and then pulled to the surface. This activity may be repeated until wellbore is cleared of all junks

Where junk pieces cannot be caught by a magnet consists of nonferrous metals, Weatherford employs specialized to junk baskets depending on the type of formation encountered. These retrieval tools consist of three basic types. The simplest to use is called a boot basket. It is run directly above junk mill or a junk bit the cuts the junk into small pieces. Fluid circulation deposits these pieces into the basket which is raised to the surface. In soft to medium formations, according-type basket commonly known as a globe basket can be run to cut a short core in the bottom of the well. This core as well as any junk contained is held in place by retaining fingers and removed to the surface. In hard formations, a jar powered or reverse circulating basket is a highly effective tool. Lowered to the bottom, it rotates slowly with circulation to flush samplings from the junk. A ball is dropped into the drill pipe and pump down until the ball sits in the retriever. The flow of the fluid is diverted to outside the tool which causes two things to occur and establishes reverse circulation and venture effect which then creates a partial vacuum inside the junk basket. These two forces propel the junk into the basket. Captured junk is secured by hymns retaining fingers. This action continues until all junk is removed from the hole.

Cased hole finishing is quite different in term of operation, tools and techniques so people need to fully understand about this topic. The cased hole fishing video training by Weatherford is the last video training for the fishing operation series. This will help you understand about overall about cased hole fishing in many aspects.

Cased Hole Fishing Video Transcription

Many of the tools and techniques common in open hole fishing cannot be used in cased hole operations due to the restrictive nature of the casing. Sidetracking for example, an easy option and open hole was not widely used in cased hole situations until recently. The most common case whole fishing projects involve removal of stock production strains. Stock production tubing can result from collapsed casing when used tubing or tubing in casing leaks that allows sand and other debris to enter the casing annulus. Dehydrated mud in the casing annulus can also stick to the string.

With stuck pipe or tubing, the first step is to determine the free point or stuck point of the fish. Using a three-point indicator run on wireline, the start point can be determined and a free tubing removed to this point. In single completions with one string of production tubing and casing, sanded up or much stuck to being can be freed by a conventional wash over operation. A shoe run on washed pipe is lowered over the fish. And sand or mud is circulated back to the surface for removal from the wellbore. Unlike shoes used in open hole operations, cased hole wash over  shoes have smooth exteriors to prevent damage to the casing.

Next, the trip is made with an overshot and jarring assembly to engage the fish. When the washer over has freed all of the remaining fish, it is pulled from the hole. If only part of the fish is free following washing over, the freed portion is cut or backed off and pulled so another washover can begin. If the inside of the fish is plugged preventing entry of wireline tools, the tubing can be recovered with an outside cutter. Following washover, the shoe is removed and replaced by an outside cutter on the bottom of the washover string. The cutter is run over the top of the fish to the desired depth and the tubing is mechanically cut by rotating the string.the cutter then acts as a retriever and the plug tubing can now be brought to the surface inside the wash pipe.

Removal of permanent packers from the well also calls for unique fishing tools and techniques. Several different types of packer retrievers are used depending on packer accessories used during completion. A proven method to retrieve a permanent packer in one trip and list the use of a packer retriever soundly. Its custom-made tungsten carbide faced shoe is dressed to near casing id so it cuts only the slip section of the packer. Adding above the shoe prevents damage to the casing wall. The retrieving assembly with the correctly selected grapple for the packer bore is run below hydraulic jars, colors and a boot basket which collects metal debris cut loose by the shoe. The spear and extension in the assembly is lowered through the packer. Milling over proceeds until the packer is milled free. The spear engages the packer body and it is removed from the well. This standard method of packer retrieval works only if there is no tailpipe below the packer or if a mill out extension has been installed when the packer was running the hole.

If sealed bore extensions are located below the packers without a mill out extension, another type of packer retriever assembly is run for one trip recovery. It incorporates a top bushing that crosses over from a boot basket to the washpipe extension. A j-latch assembly with washpipe connections at the top and bottom and a burning shoe connected to the inside of the j-latch assembly is a man rule: spear extensions, spear stop sub and spear. The assembly is lowered into the well until the spear stabs into the packer manrule.  A gentle pull on the spear confirms that the packer is engaged. J-latches are released, the shoe is lowered, and rotation begins to mill over the packer. With the packer milled free, the string is picked up until the j-latches are secured into the assembly and the packer engaged by the spear is removed from the well.

Multiple completions where more than one string of tubing is placed side by side in the casing. Present another challenge. Wahsover is not an option here because of the limited space in the casing. Instead, the repirator will use a specialized washed down mill run on the end of a small tubing string. Debris is washed from the casing annulus and circulated from the well.

in sandy environments, a gravel pack assembly may be located below the packer. Its removal is accomplished using conventional washover, milling and retrieval tools. However, when rapid sand backfilling is likely and where the gravel pack assembly may become restart while tripping the by foreign overshot, a trip saver tool is recommended. The trip saver is run in place of the top bushing of the washpipe. It provides a mandrel on which an overshot can be placed inside the washpipe. After wash over has completed, the well as circulated clean. The manrole with the overshot is released from the washpipe top and lowered until the overshot latches to the gravel pack assembly ensuring efficient one trip retrieval.

Another major area requiring cased hole fishing focuses on casing problems themselves. When leaks are located in free pipe above the cemented level of the casing, the casing is cut or backed off below the problem area and replaced with new pipe. If the casing was backed off, the new casing is run back in the well and the string is screwed back together. If the casing was cut, it is dressed off to remove birders and external casing badges then screwed onto a string of new casing and running the hole. The patches engaged on to the or gazing in a manner similar to an overshot and the gentle upward pull collapses the seal assembly made of lead or rubber around the casing. The entire string is pressure-tested to ensure a good seal.

When casing leaks are located below the cemented level making them inaccessible to retrieve and repair and all other repair attempts have failed such as squeeze cementing, home co internal casing patches are recommended. Originally designed to seal unwanted perforations, they have proven to be very effective in sealing most types of casing leaks. The home co internal casing patch is made of corrugated steel covered with a fiberglass mat and coated with an epoxy resin prior to running. The patch is positioned over the leak area and is set by hydraulically pulling up collitic expander through the corrugated patch flattening it against the casing wall. The resin extrudes in and around the fiberglass mat serving as a secondary sealing agent. The setting too is then retrieved while the epoxy sats. The standard home co steel liner patch has a 1/8 inch steel wall thickness leaving a total casing id reduction of 3/8 of an inch.

In special situations where higher pressure is a concern, a heavier 3/16 inch patch is available. Also supplies led wrapped patches for high-temperature situations. If the weather operator finds the casing problem is more severe such as collapsed or parted casing, more aggressive measures must be undertaken. With slightly collapsed casing, the common tool  used is a casing roller. In this procedure, a set of hydraulic jars, bumper jars, and drill collars are run above the roller. When the desired depth is reached, right hand rotation and the eccentric action of the roller will return the casing to its original shape and id.

More severely collapsed casing can be repaired with the casing swedge. A bumper jar, hydraulic jar, and drill collars are located above the swedge. The swedges driven through the damaged section by hitting down with the bumper jar and drill collars, opening the casing to its original shape and id. The hydraulic jar allows the swedge to be retrieved if it becomes stuck during this procedure.

When the problem is parted casing, bringing the two sections into correct alignment requires still other more specialized rather for remedial tools. The most effective of these is a guide assembly and watermelon mill called a lace joint. The lace joint is lowered down drill collars into the bottom casing. And the milling section is worked back and forth through the parted area until the separated casings are realigned.

To cement the joint sections together, the operator uses a casing alignment tool. The od of this tool is built to drift the id of the casing and it is run by the lower cement retainer. The casing alignment tool is placed across the separated casing and the retainer is set. Cement is pumped through the casing alignment tool throught the casing wall and into the formation sealing the casing joint 360 degrees around the external casing wall. After the cement sets, the cement retainer and alignment too are completely drilled out, achieving proper id size and integrity.

When all casing repair methods fail, it becomes necessary to sidetrack if the well as to be saved. Although a sidetrack can be accomplished by cutting or milling a section through the casing and then drilling out using a directional assembly using up whipstock to mill a window is usually the most effective and least costly procedure to establish a sidetrack.

Weatherford whipback back is one of the most popular whipstocks in use today. The whipback is a bottom trip whipstock which can function as a permanent whipstock or can be removedafter the sidetrack whole has been drilled. A solid bottom is required to set the whipstock. A bridge plug is frequently used for this purpose. The bridge plug should be set approximately five feet above a casing collar. This will allow the window to be milled through the tube portion of the casing avoiding the thicker coupling area.

The whipstock is connected to a starter mill with the shear bolt and lowered into the well on the workstring. One joined of drill pipe and a mule shoes sub if the face of the whipstock has to be oriented are placed above the starter mill and below the drill collars. If this is a blind sidetrack and the woodstock face or concave, does not have to be oriented in a particular direction. The whipstock is lowered until the bottom trip assembly of the whipback rests on the bridge plug.

2,000 to 4,000 pounds of weight are applied to the whipback, shearing the bottom trip assembly and setting the whipstock. Additional weight is slacked off until the shear bolt attaching the starter mill to the whip stock shears. The whipstock is now seven milling can begin. If the concave has to be oriented in a particular direction, the assembly is lowered to approximately twenty feet above the bridge plug. At this point, a wireline with a gyro is run in the works string until the mule shoes sub has been reached.

Readings are taken to determine which way the concave is facing. After setting that whipback, rotation and circulation are established. The string is slowly lowered until there is some indication that the starter mill has reached the top of the area to be mill. Pile should be marked at this time and milling continued until about 24 inches have been made. All cuttings are circulated out and the work string is pulled out. The starter middle and mule shoes sub are replaced by a window mill and rough od the watermelon mill. This assembly is tripped in the hole to approximately five feet above the whipback.

Circulation and rotation are re-established. The window milling assembly is lower than till the 24-inch section previously milled is reach. Milling proceeds until the window is completed and the milling assembly has penetrated four to six feet of open hole. After the window is established, milling continues back and forth through the window area until the assembly can do so without any torque or dry.

In medium radius horizontal wells, it is sometimes a good idea to make one additional mill run if a long horizontal area is to be drilled. This run will lengthen the window making it easier for the drilling assembly to pass through the window when horizontal reaches long and dragged become severe. Once the new radius or sidetrack is complete, the whipback can be recovered using a special retrieval hook or a threaded die collar. This is particularly useful in producing wells where multilateral boards are added to an existing productive interval.

There are offers of complete line of whipstocks. In addition to the popular whipback, packer-type, hinged open hole whipstocks are also available. Weatherford employees the industry’s widest range of milling tools. Among the most common are junk mills used to mill packers, bridge plugs, cement, perforating guns, drill pipe, tool joints and other obstructions. Junk mills can incorporate a concave, convex or flat bottom depending on the application.

Other models include the cone buster used for milling up rock bitcones. The taper mill used to dress liner tops and clean out tight spots in casings. And the pilot mill, designed to mill casing, liners, rotary shoes and large id tubing. Additionally, Weatherford now features advanced quick cut technology. This alternative incorporates innovative square cut, tungsten carbide inserts which improved chip control and maximize casing penetration. The advantages are faster, more efficient milling performance.

It is imperative to understand mechanical properties of tubular because it involves the safety structure of the well. Failure in completion can cause major catastrophic problems in people safety, major loss of expenditure and loss of production from a well.

This article will describe the basic mechanical properties which are very essential to understand.

Stress

Stress is an applied force per unit area.

Figure 1 – Stress Diagram

Strain

When a tubular is subjected to a tensile load, the tubular becomes longer and the amount of elongation is called “strain.” Strain can be described as per the equation below;

Where;
ΔL = change in length of tubular
L = original length of tubular

Figure 2 – Strain Diagram

Hooke’s Law and the Modulus of Elasticity

Steel, which is a ductile material, exhibits elastic behavior. Elasticity is a material property which allows the material to come back to its original shape when the load is released. According to the Hooke’s Law, stress is proportional to strain up to an elastic limit. Therefore, stress and strain under the elastic limit can be described as the equation below;

σ = E × ɛ

Where;

σ = stress of material
ɛ = strain of material
E = Young’s modulus (Modulus of elasticity)

Note: Young’s modulus of elasticity of steel is about 30×106 psi.

Stress and Strain Curve

When forced is applied into a material, stress and strain can be plotted like this (Figure 3). It is important to understand the meanings of several points on the stress-strain plot.

Figure 3 – Stress and Strain Curve

Elastic region (green shaded area) – Under the elastic region, material will go back to its original shape once the forced is released.

Plastic region (red shaded area) – Under the plastic region, material will be plastically deformed therefore it will not be able to reverse back to its original shape.

Proportional Limit – Under the elastic limit, stress is a proportional limit to strain and the relationship between stress and strain is under the Hooke’s law.

Elastic Limit – The elastic limit is the maximum stress which material behaves under the Hooke’s law (stress and strain have a liner relationship). Beyond the elastic limit to the yield point, the material still behaves elastically.

Yield Point (Yield Stress) – This is the maximum stress that material can withstand before it is plastically deformed. Beyond the yield point, material will not be able to come back to its original shape. If the stress is applied over the elastic limit, but below the yield point, the material will be able to recover back to its original shape since it is still within the elastic limit. However, the Hooke’s law does not apply.

API defines the yield stress as the minimum tensile stress required to elongate the pipe 0.5% or 0.65% depending on the tubing grade.

Ultimate Tensile Stress – This is the maximum stress that material can withstand and it is shown as the top of the engineering stress-strain curve. Beyond this point, the cross sectional area of material begins to reduce rapidly over a relatively small length of material and this is called “neck.”

Failure – This is the point where the material will be parted.

Poisson’s Ratio (μ)

Experiments have shown that when the material is under tension, both axial and radial strain will occur. In the elastic region, these two strains are proportional to each other. This is called poisson’s ratio (μ) and the relationship is shown below;

Figure 4 –Illustrate of Poisson’s Ratio

Ductile and Brittle Material

Ductile material as carbon steel is material which has a large degree of plastic deformation before being fractured. On the other hand, brittle material such as grass has a very low degree of plastic deformation. It indicates that after yield strength is exceeded, the brittle material will break apart very quickly, but the ductile material will be able to elongate further before parted.

Figure 5 – Comparison between Ductile and Brittle Material

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Oil field tubular is typically designed to work under its minimum yield strength so it means that the tubular will work with tensile load within the elastic limit. This article will discuss about tensile properties and how to determine tensile of oilfield tubular.

Tensile strength of tubular can be calculated by this following equation.

Tensile strength = Minimum Yield Strength × Cross Sectional Area

Where;

Tensile strength in lb

Minimum yield strength in psi

Cross sectional area in in²

Figure 1 – Tensile Diagram

Minimum yield strength of pipe can be found in the grade of the string. For example, the pipe grade if J-55 has minimum yield strength of 55,000 psi. The number after alphabet represents the minimum yield strength in 1,000 psi. A few examples are shown in the Figure 2.

Figure 2 – Numbers represents pipe minimum yield strength

API5CT specifies pipe specification as shown in the Figure 3.

Figure 3 – API Steel Grade Table

Example: Calculate the tensile strength of the following pipe.

4-1/2” casing, weight 9.5 ppf,  grade J-55

Pipe ID = 4.09”

Cross sectional area (in²) = (π÷4) × (OD² – ID²)

Cross sectional area (in²) = (π÷4) × (4.5² – 4.09²)

Cross sectional area (in²) = 2.77 in²

Minimum Tensile Strength (lb) = 55,000 × 2.77 = 152 Klb

This number can be found in the API pipe specification.

Figure 4 – API Tubular Specification

Download the API tubular data sheet here

http://www.drillingformulas.com/oilfield-casing-data-sheet-free-download/

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Burst is a condition where internal pressure exceeds pressure loading. Burst can happen in several situations, such as well control, pressure test casing/tubing, pumping operation, etc.

Figure 1 – Burst Pressure Diagram

Minimum burst rating pressure (internal yield pressure) can be calculated by the following equation.

Where;

P_B – Minimum internal yield pressure (psi)

Yp – Minimum yield strength (psi)

t – Nominal wall thickness (in)

D -Nominal outside diameter of the pipe (in)

This image shows when tubular is exposed to a differential internal pressure over its burst pressure rating.

(Ref: http://gekengineering.com/Downloads/Free_Downloads/Casing_Design_Hand_Calculation_Design_Example.pdf)

Some interesting points about burst pressure

• This equation (Barlow’s Equation) determines the internal pressure at which the tangential stress at the inner wall of the tubular reaches the minimum yield strength (YS) of the pipe.
• Factor 0.875 in the equation represents allowance of manufacturing tolerance of -12.5% on wall thickness specified in API 5CT.
• Burst will be occurred when stress is over ultimate tensile strength of material. However, the equation uses the Yield Stress of material, which is a conservative assumption.

Example: Calculate the tensile strength of the following pipe.

4-1/2” casing, weight 9.5 ppf,  grade J-55

Pipe ID = 4.09”

Wall thickness 0.205 “

Yp = 55,000 psi

P_B = 4,385 psi

This figure can be seen in the API specification.

Figure 2 – API Burst Rating Pressure

Download the API tubular data sheet here – http://www.drillingformulas.com/oilfield-casing-data-sheet-free-download/

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

PEH:Casing Design. 2015. Casing Design. [ONLINE] Available at: http://petrowiki.org/PEH%3ACasing_Design. [Accessed 1 June 2016].

Collapse happens when differential between external and internal pressure exceeds a collapse rating pressure of material. This situation can happen due to several cases, such as pressure testing in annulus, trapped pressure in the annulus or well fully evacuated with gas, etc.

Figure 1 – Collapse Pressure Diagram

Collapse pressure equations come from experiments from test specimens and the full details can be found in API Bulleting 5C3, Formulas and Calculations for Casing, Tubing, Drillpipe, and Line Pipe Properties. From the experimental results, there are 4 collapse regimes based on Diameter of pipe/Wall thickness (D/t) and yield strength of material which are yield strength collapse, plastic collapse, transitional collapse and elastic collapse.

Yield Strength Collapse

Yield strength is based on yield at the inner wall by applying the Lamé thick wall elastic solution.

• D/t < ± 15
• Tangential stress is over the yield strength of material before a collapse instability failure occurs.
• The formula for yield strength collapse is shown below;

• The applicable D/t ratios for yield strength collapse are illustrated in Table 1.

Table 1: Yield Strength Collapse

(Ref: http://petrowiki.org/File%3ADevol2_1102final_Page_291_Image_0001.png)

Plastic Collapse

Plastic collapse equation is derived from empirical data of K-55, N-80, and P-110 seamless casing.

• The formula for plastic collapse is shown below;

The factors A, B, and C and applicable D/t range for the plastic collapse formula are shown in Table 2.

Table 2: Plastic Collapse

(Ref: http://petrowiki.org/File%3ADevol2_1102final_Page_292_Image_0001.png)

Transitional Collapse

Transitional collapse is derived from a curve fitting between the plastic and elastic regions.

• The formula for transitional collapse is shown below;

The factors F and G and applicable D/t range for the transition collapse pressure formula, are shown in Table 3.

Table 3 – Transitional Collapse

(Ref: http://petrowiki.org/File%3ADevol2_1102final_Page_293_Image_0001.png)

Elastic Collapse

The elastic collapse is applicable for thin wall pipe (D/t> ±25).

• The formula for elastic collapse is shown below;

The applicable D/t range for elastic collapse is shown in Table 4.

Table 4 – Elastic Collapse

(Ref: http://petrowiki.org/File%3ADevol2_1102final_Page_294_Image_0001.png)

Nomenclatures

D         = nominal outside pipe diameter, in.

D/t      = slenderness ratio, dimensionless

Most of oilfield tubing and casing are within the plastic and elastic region and the simple way to find the collapse pressure of each pipe is to look at a casing specification table.

Example: Determine the tensile strength of the following pipe.

4-1/2” casing, weight 9.5 ppf, grade J-55

Pipe ID = 4.09”, Wall thickness 0.205 “

Collapse pressure (psi) =3,310 psi.

Download the API tubular data sheet here – http://www.drillingformulas.com/oilfield-casing-data-sheet-free-download/

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

PEH:Casing Design. 2015. Casing Design. [ONLINE] Available at: http://petrowiki.org/PEH%3ACasing_Design. [Accessed 1 June 2016].

Tubular must be properly deigned to cover all anticipated load cases during the life of the well.  Engineers must select the appropriate tubular grade and weight, which will withstand the loads and be economic for the project. High grade to tubular can lead to excessive cost, which may not be economic viable. However, if the selected tubular is very close to the anticipated load, it might not be safe to operate the well. Therefore, engineers must fully understand the concept about design factors in tubular design.

Design Factor

Design factors represent the design degree to ensure that tubular will have the extra load to cover all load cases. The design factor can be described in the equation below;

Design factor of 1 is what the tubular can withstand before it starts to yield.

Anticipated load cases can be categorized into several categories as shown below;

• Tensile loads
• Burst loads
• Collapse loads
• Tri Axial loads
• Drilling loads
• Production loads
• Axial loads
• Running and cementing loads
• Service loads as injection/stimulation load

Safety Factor

Safety factor has a similar meaning as a design factor, but safety factor can be more than or equal to the design factor. Only minimum safety factor will be equal to the design factor. The relationship between the design factor and the safety factor is described below;

Each company may have their own standard to meet a company standard. The table below shows general design factors for design factors.

The design factor will account for uncertainty in all cases, which can happen, such as uncertainty of pipe manufacture, assumptions, etc.

Figure 1 demonstrates tri axial load with a design factor of 1.25. The red circle is 80K psi strength and the green dotted line is 64K psi strength (80/1.25).

Figure 1 – Design Factor Load Diagram

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

When a tubular submerses into drilling fluid or completion fluid, it will affect how the force distribution works on the tubular. This article will describe how buoyancy will affect tubular weight and a location of neutral axial load (zero axial load).

Weight of Tubing in Air

When tubing is hung in the air, the string weight is equal to linear weight per foot multiplied by the total length of the string. The maximum tensile load is on surface and the zero axial load point is at the bottom.

Tubing Detail

• 5” Tubing
• Weight per length = 17.7 lb/ft
• Total Length = 10,000 ft

Total weight = 17.7 x 10,000 = 177,000 lb

Weight at the bottom of tubing is 0 and weight on top is 177,000 lb in tensile.

Figure 1 demonstrates force distribution of tubing hanging in air.

Figure 1 – Weight of Tubing in Air

Weight of Tubing When Submersed in Fluid

When tubing is submersed in fluid, buoyancy force from fluid, which acts upwards against the cross sectional area of the tubular, generates compression force. This will change the force distribution on the pipe.

Force from buoyancy is based on the equation below;

F_B = P_H x (Ao-Ai)

P_H = 0.052 x M x TVD

Where;

F_B = Buoyancy force in lb

P_H = Hydrostatic pressure in psi

Ao = Cross sectional area of outer diameter in in²

Ai = Cross sectional area of inner diameter in in²

MW = weight of fluid (mud weight) in pound per gallon (ppg)

TVD = True vertical depth of the well in ft

Figure 2 shows how the buoyancy force acts against the cross sectional area of tubing.

Figure 2 – Buoyancy Force Diagram

Tubing Detail

• 5” Tubing
• ID of tubing = 3.696”
• Weight per length = 17.7 lb/ft
• Total Length = 10,000 ft
• Fluid density = 10 ppg

P_H = 0.052 x 10 x 10,000 = 5,200 psi

F_B = 5,200 x (15.9 – 10.73) = 26,884 lb (compression ⇑(+))

At the bottom of tubing submersed in 10.0 ppg mud, 26,884 lb compression force pushes up against the pipe. This force will reduce tensile force due to the weight of the pipe in the air. The force at the top of tubing is equal to a summation of tensile force caused by tubing weight and compression force acting on the cross sectional area of pipe.

Weight of pipe (lb) = Weight of pipe in air (tensile force) + Compression force due to buoyancy

Weight of pipe (lb) = (-177,000) + (26,884) = -150,116 lb (tensile force ⇓ (-))

Figure 3 demonstrates how force acts against the pipe when it is in fluid. Additionally, it indicates that the zero axial force point is moved up from the bottom to somewhere in the pipe. Below the zero axial force, the pipe is under compression and above this point the pipe is under tension.

Figure 3 – Weight of tubing in fluid

Note: for this calculation, the assigned signs and directions of force and pressure are as follows;

Compression force = ⇑(+)

Tensile force = ⇓(-)

Shorten in Length = (-)

Elongate in length = (+)

The signs are based on the Lubinski study.

Lubinski, A., & Althouse, W. S. (1962, June 1). Helical Buckling of Tubing Sealed in Packers. Society of Petroleum Engineers. doi:10.2118/178-PA

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Lubinski, A., & Althouse, W. S. (1962, June 1). Helical Buckling of Tubing Sealed in Packers. Society of Petroleum Engineers. doi:10.2118/178-PA

Shell is one of major oil companies which always share basic knowledge in oil and gas industry to people. In this posting, there are series of upstream knowledge that you can learn from them.

Shell’s Carbon Capture and Storage project

You can watch more videos from Shell Channel https://www.youtube.com/channel/UCRLOjeT82M_8CyLj0BqvRaQ

Thanks Shell for great contribution.

When tubing is freely suspended, it can be buckled by an upward force applied at the bottom of tubing. A section of tubing exposed to compression force will have a chance of being buckled. However, a part which is under tension will not face a buckle issue.

The neutral point is the boundary below which buckling can possibly be occurred and above which buckling will not happen.

Figure 1 – Wellbore Diagram with Tubing Buckling Due to Compression Force

Bulking Calculations

Location of a neutral point

If n < L, this indicates a partially buckled and the length change due to buckling is calculated by this formula below;

If n > L, this indicates a completely buckled and the length change due to buckling is calculated by this formula below;

W = Ws + Wi – Wo

Wi = ρi × Ai

Wo = ρo × Ao

Ff = Ap × (Pi – Po)

Where;

Ff = fictitious force or effective buckling force (lb)

Ap = cross section area of packer seal bore (in2)

Pi = Pressure at the packer inside tubing (psi)

Po = Pressure at tubing in the annulus (psi)

I = moment of inertia of tubing cross section (in4)

OD = outside diameter of tubing (in)

ID = inside diameter of tubing (in)

r = radial clearance between tubing OD and casing ID (in)

L = length of tubular (in)

E = Young’ modulus of material (psi)

Ws = weight per unit weight of steel (lb./in)

Wi = weight per unit weight of fluid inside tubing (lb./in)

Wo = weight per unit weight of fluid outside tubing (lb./in)

ρi = density of fluid in the tubing (lb/in3)

ρo = density of fluid in the annulus (lb/in3)

W = weight per unit length of tubular in the presence of fluid (lb/in)

Ff (fictitious force) is a combination of forces from internal pressure, external pressure and piston force. This is not the actual force acting at the bottom of tubing. The Ff (fictitious force) is used to indicate if the pipe is buckled or not. Tubing will be buckled if Ff is positive. If Ff is zero or less than zero, tubing will not be buckled because tubing is in tension (ΔLbuckling = 0).

Example

Packer is set at 10,000 ft.

Tubing and packer are free to move.

The well is vertical.

4.5” Tubing (15.1 lb/ft.)

ID of tubing = 3.826”

Packer seal bore outside diameter = 5.0”

Weight per length = 17.7 lb/ft.

E (Young’s modulus) = 30 × 106

µ (Poisson’s ratio) = 0.3

Production casing size = 7”

Production casing ID = 6.049”

Initial Condition

Fluid in annulus = 10.0 ppg

Fluid in tubing = 10.0 ppg

Tubing pressure = 0 psi

Annulus pressure = 0 psi

Final Condition

Fluid in annulus = 10.0 ppg

Fluid in tubing = 8.0 ppg

Tubing pressure = 1,500 psi

Annulus pressure = 0 psi

Figure 2 – Initial and Final Condition

Solution

For bulking calculation, the final condition of the tubing is considered.

For the analysis, Lubinski’s sign conventions are used. Please see at the reference section to get a full paper.

Compression force = ⇑(+)

Tensile force = ⇓(-)

Shorten in Length = (-)

Elongate in length = (+)

Calculate Areas

Ai = Tubing ID area (in²)

Ai= (π÷4) × 3.826² = 11.497 in²

Ao = Tubing OD area (in²)

Ao= (π÷4) × 4.5² = 15.904 in²

Ap = Packer sealbore area (in²)

Ap= (π÷4) × 5² = 19.635 in²

Calculate Pressure

Pressure at the packer inside tubing (Pi)

Pi = surface pressure + hydrostatic pressure

Pi = 1,500 + (0.052 ×8 ×10,000) = 5,660 psi

Pressure at the packer in the annulus (P0)

P0 = surface pressure + hydrostatic pressure

P0 = 0 + (0.052 ×10 ×10,000) = 5,200 psi

Calculate Ff (Fictitious Force)

 Ff = Ap × (Pi – Po)

Ff = 19.635 × (5,660 – 5,200)

Ff= 9,032 lb

Calculate W

 W = Ws + Wi – Wo

W_i = ρ_i × A_i

W_o = ρ_o × A_o

 ρ_i = 8 ppg = 8×4.329 ×10^-3 = 0.034632 lb/in³

ρ_o = 10 ppg = 10×4.329 ×10^-3 = 0.04329 lb/in³

Ws = 15.5÷12 = 1.292 lb/in

W_i = 0.034632 ×11.497 = 0.3982 lb/in

W_o = 0.04329 × 15.904 = 0.6885 lb/in

W = 1.292 + 0.3982 – 0.6885= 1.0013 lb/in

Calculate n

n = 9,093÷1.0013= 9,020.1 inch

 Compare n and L

 n = 9,020.1 inch

L = 10,000 × 12 = 120,000 inch

n<L

If n < L, this indicates a partially buckled and the length change due to buckling is calculated by this formula below;

r = (6.049 – 4.5) ÷ 2 = 0.7745  inch

I = 9.61 in⁴

Conclusion

The tubing is shorten 0.0212 inch.

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

Lubinski, A., & Althouse, W. S. (1962, June 1). Helical Buckling of Tubing Sealed in Packers. Society of Petroleum Engineers. doi:10.2118/178-PA

This article demonstrates how to select material that will be suitable for high pressure, high pressure and corrosive environment. The material chart is based on the Sumitomo tubular chart.

Well conditions are as follows;

Reservoir: High pressure & high temperature gas reservoir

Reservoir Temperature: 420 F (216 C)

CO₂ content: 2.9% mol

H₂S:40 ppm

Chloride Ion Content in Produced Water: 150,000 ppm

Fluid saturation pressure: 10,000 psig

Solution

1. Determine Partial Pressure

 Partial pressure = fraction of gas × fluid saturation pressure (psia)

 Fluid saturation pressure (psia) = Fluid saturation pressure (psig) + 14.7 psi

Fluid saturation pressure (psia) = 10,000 + 14.7 =10,014.7 psia

CO₂ partial pressure (psia) = 10,014.7 × (2.9/100) = 290 psia

CO₂ partial pressure (atm) = 290 ÷ 14.7 = 19.8 atm

H₂S content = 100ppm = 40 ÷ 1,000,000 = 0.00004

H₂S partial pressure (psia) = 10,014.7 × 0.00005 = 0.4 psia

H₂S partial pressure (atm) = 0.5 ÷ 14.7 = 0.027 atm

2. Check with the tubular chart. For this exercise, Sumitomo steel is used.

Look up at the chart to check.

The chart suggests SM 13CSR-80, 90.

For the corrosion stand point, SM 13CSR-80, 90 will work, but this material will safely operate under temperature below 175 C and chloride content below 50,000 ppm.

The given reservoir conditions are too harsh for this material.

Reservoir Temperature: 420 F (216 C)

Chloride Ion Content in Produced Water: 150,000 ppm

Fluid saturation pressure: 10,000 psig

The better grade must be selected for this reservoir environment. Some pipe grades that can be chosen are as follows;

• SM 25CRW-110, 125
• SM 25CR-110, 125
• SM 25CR-110, 125

References

Jonathan Bellarby, 2009. Well Completion Design, Volume 56 (Developments in Petroleum Science). 1 Edition. Elsevier Science.

Wan Renpu, 2011. Advanced Well Completion Engineering, Third Edition. 3 Edition. Gulf Professional Publishing.

Ted G. Byrom, 2014. Casing and Liners for Drilling and Completion, Second Edition: Design and Application (Gulf Drilling Guides). 2 Edition. Gulf Professional Publishing.

This post will give you the guideline about the useful oilfield ebook that you can download it for free. There are variety of subjects which you may have a look in the following details;

Project Management for the Oil and Gas Industry

Project Management for the Oil and Gas Industry A World System Approach written by Adedeji B. Badiru and Samuel O. Osisanya is one of the best project management books/e-books in oil and gas industry.

Upstream Oil & Gas Overview Slides

IOM3 (The Institute of Materials, Minerals and Mining) share another good presentation about upstream oil and gas overview. This is an excellent document which will help people understand more about oil and gas industry.

An Introduction to Oil & Gas Drilling and Well Operations

This document shows all the basic of drilling and well operation in very simple language term. Additionally, there are several images which help explain content in this document clearly. This is a very good document when you try to explain overall drilling and well operation to new team members who don’t have much oilfield experience.

Shell Offshore 101 – One of the best ebooks in oil and gas industry 

Shell Offshore 101 is one of the excellent educational documents which help educate people to understand about the upstream business. All documents are written in simple English with a lot of images which are extremely useful for everyone, especially new people.

Offshore Book 2014 – an overview of the offshore oil & gas industry

This book is an introduction to offshore oil and gas industry and it is written in a simple language in order to educate people about offshore industry. This book is a very good start for new engineers, university students, non-technical personnel; however, there are some topics that is still excellent for experience workforces.

Fracking Primer EBook by API

Hydraulic Fracturing Primer is published by American Petroleum Institute (API) to help people understand about fracking correctly. In this ebook, it contains a technical detail about Fracking for non-technical people to understand the content. Additionally, there are tons of images, diagrams, charts, and illustrations in order to educate people.

Oil and Gas Production Handbook

This ebook, there are several of topics covered in both upstream and downstream business. You will learn about oilfield from start (exploration) to finish (refinery) and it has an interesting topic about unconventional resource.

Oil – An Introduction for New Zealanders 

This book was written by Ralph D. Samuelson to promote the right information to New Zealand people. Not only is this book good for new Zealanders but also it is very useful for anybody. It is an excellent book because it covers a lot of aspects of oil industry with a non-technical language therefore everybody can understand the contents from the book easily.

Introduction to Wellbore Position 

Introduction to Wellbore Positioning by Prof Angus Jamieson at University of the Highlands & Islands. This is one of the best books regarding wellbore positioning. In the book, only does it have the text, but also contains tons of picture which will help learners to get more understanding of this topic.

Perforation is a special operation to crease an efficient communication path between a wellbore and a reservoir by creating tunnels. The effective paths allow reservoir fluid to flow into the well with minimum pressure loss (less skin as much as possible).

Perforation (Courtesy of Dimension Bid)

The process of perforation involves lowering a perforating gun into a wellbore to a planned depth and energizing the gun to be safely fired. When perforating a well, shape charges are fired and then energy from the explosion will create tunnels through casing, and cement and then into a reservoir. Length and diameter of perforation hole are dependent on the objectives which will be discussed later. Figure 1 shows the cross sectional of perforation.

Figure 1 – Perforation Cross Section Ref:http://www.angelfire.com/wy/lisadenke/pictures/assorted_facts_pics/HES_perfs.gif

Several factors influencing perforation performance are as follows;

• Rock properties – compressive strength, fracture pressure
• Mineral content of the rock metric
• Tectonic stress and overburden pressure of the reservoir
• Reservoir pressure and temperature
• Reservoir fluid
• Completion fluid
• Wellbore configurations such as size and grade of casing, wellbore deviation and orientation

Types of Perforation Systems

Three perforation systems which are used in oil and gas industry are casing guns, tubing conveyed guns and through tubing guns.

Casing Gun System (Wireline Convey)

The casing gun system is the oldest perforation technique and it involves running perforation in order to perforate a well before running a completion. Wellbore conditions can be either overbalanced or underbalanced when perforating. Additionally, a wellbore should be neutralized before running the completion because it will minimize formation damage.

Some advantages of a casing gun are listed below;

• Perforation guns can be run with wireline or electric line in order to get an accurate depth control
• Larger diameter guns can be utilized.
• Effective well control
• Operations are mechanically simple and reliable

Some disadvantages of casing gun are listed below;

• Takes rig time for perforation
• Requires rig up equipment on the rig floor

Tubing Conveyed Perforation System (TCP)

For this system, the perforation gun is attached and run with a completion string. This system requires drilling an additional hole called a “sump” in order to accommodate a perforated gun to be dropped and left in the well after a gun is fired.

Some advantages of tubing conveyed technique are listed below;

• Long reservoir interval can be perforated by one run
• Larger explosion charges than through tubing system
• Perforation can be done within the underbalanced condition so formation damage can be minimized.
• Significant reduction in rig time

Disadvantage of tubing conveyed technique are listed below;

• Take a long time before perforation charges will be fired

Through Tubing System

 Through tubing perforation allows perforation to be performed with the existing completion string. This system has limitations on size of charge and perforation gun because the guns must be small enough to run into a completion string. Typically, the gun size is smaller than 2-1/8.”

Advantages of through tubing system are as follows;

• Perforate a well with a completion string
• Rapid deployment and retrieval by using wireline or electric line units
• Minimizes loss of production
• Accurate depth control
• Reduced cost because no completion retrieval is required

Disadvantages of through tubing system are as follows;

• Smaller diameter of perforation charges can be used when compared to other perforation system. Therefore, deep of penetration is shallower than others.
• Length of perforation in one run is limited by surface equipment.

References

Michael J. Economides, 1998. Petroleum Well Construction. 1 Edition. Wiley.

Perforating. SPE Monograph No. 16, Bell W., Sukup R. and Tariqu S., SPE, 1995.