Working Conditions, Health and Safety in Oil Gas Frilling

Work on drilling rigs usually involves a minimum crew of 6 people (primary and secondary drillers, three assistant drillers or helpers (roughnecks) and a cat-head person) reporting to a site supervisor or foreman (tool pusher) who is responsible for the drilling progression. The primary and secondary drillers have overall responsibility for drilling operations and supervision of the drilling crew during their respective shifts. Drillers should be familiar with the capabilities and limitations of their crews, as work can progress only as fast as the slowest crew member.

Assistant drillers are stationed on the platform to operate equipment, read instruments and perform routine maintenance and repair work. The cathead person is required to climb up near the top of the derrick when drill pipe is being fed into or drawn out of the well hole and assist in moving the sections of pipe into and out of the stack. During drilling, the cathead person also operates the mud pump and provides general assistance to the drilling crew.

Persons who assemble, place, discharge and retrieve perforating guns should be trained, familiar with the hazards of explosives and qualified to handle explosives, primer cord and blasting caps. Other personnel working in and around oil fields include geologists, engineers, mechanics, drivers, maintenance personnel, electricians, pipeline operators and laborers.

Wells are drilled around the clock, on either 8- or 12-hour shifts, and workers require considerable experience, skill and stamina to meet the rigorous physical and mental demands of the job. Overextending a crew may result in a serious accident or injury. Drilling requires close teamwork and coordination in order to accomplish the tasks in a safe and timely fashion. Because of these and other requirements, consideration must be given to the morale and health and safety of workers. Adequate periods of rest and relaxation, nutritious food and appropriate hygiene and living quarters, including air conditioning in hot, humid climates and heating in cold-weather areas, are essential.

The primary occupational hazards associated with exploration and production operations include illnesses from exposure to geographical and climatic elements, stress from travelling long distances over water or harsh terrain and personal injury. Psychological problems may result from the physical isolation of exploratory sites and their remoteness from base camps and the extended work periods required on offshore drilling platforms and at remote onshore sites. Many other hazards particular to offshore operations, such as underwater diving, are covered elsewhere in this Encyclopedia.

Offshore work is dangerous at all times, both when on and off the job. Some workers cannot handle the stress of working offshore at a demanding pace, for extended periods of time, under relative confinement and subject to ever changing environmental conditions. The signs of stress in workers include unusual irritability, other signs of mental distress, excessive drinking or smoking and use of drugs. Problems of insomnia, which may be aggravated by high levels of vibration and noise, have been reported by workers on platforms. Fraternization among workers and frequent shore leave may reduce stress. Seasickness and drowning, as well as exposure to severe weather conditions, are other hazards in offshore work.

Illnesses such as respiratory tract diseases result from exposure to harsh climates, infections or parasitic diseases in areas where these are endemic. Although many of these diseases are still in need of epidemiological study in drilling workers, it is known that oil workers have experienced periarthritis of the shoulder and shoulder blade, humeral epicondylitis, arthrosis of the cervical spine and polyneuritis of the upper limbs. The potential for illnesses as a result of exposure to noise and vibration is also present in drilling operations. The severity and frequency of these drilling-related illnesses appears to be proportional to the length of service and exposure to adverse working conditions (Duck 1983; Ghosh 1983; Montillier 1983).

Injuries while working in drilling and production activities may result from many causes, including slips and falls, pipe handling, lifting pipe and equipment, misuse of tools and mishandling explosives. Burns may be caused by steam, fire, acid or mud containing chemicals such as sodium hydroxide. Dermatitis and skin injuries may result from exposure to crude oil and chemicals.

The possibility exists for acute and chronic exposure to a wide variety of unhealthful materials and chemicals which are present in oil and gas drilling and production. Some chemicals and materials which may be present in potentially hazardous amounts are listed in and include:

• Crude oil, natural gas and hydrogen sulfide gas during drilling and blowouts
• Heavy metals, benzene and other contaminants present in crude
• Asbestos, formaldehyde, hydrochloric acid and other hazardous chemicals and materials

·     Normally occurring radioactive materials (NORMs) and equipment with radioactive sources.

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Survey for Searching Oil and Gas

Sesmic Survey

The search for oil and gas requires a knowledge of geography, geology and geophysics. Crude oil is usually found in certain types of geological structures, such as anticlines, fault traps and salt domes, which lie under various terrains and in a wide range of climates. After selecting an area of interest, many different types of geophysical surveys are conducted and measurements performed in order to obtain a precise evaluation of the subsurface formations, including:

• Magnetometric surveys. Magnetometers hung from airplanes measure variations in the earth’s magnetic field in order to locate sedimentary rock formations which generally have low magnetic properties when compared to other rocks.

• Aerial photogrammetric surveys. Photographs taken with special cameras in airplanes, provide three-dimensional views of the earth which are used to determine land formations with potential oil and gas deposits.

• Gravimetric surveys. Because large masses of dense rock increase the pull of gravity, gravimeters are used to provide information regarding underlying formations by measuring minute differences in gravity.

• Seismic surveys. Seismic studies provide information on the general characteristics of the subsurface structure. Measurements are obtained from shock waves generated by setting off explosive charges in small-diameter holes, from the use of vibrating or percussion devices on both land and in water, and from underwater blasts of compressed air. The elapsed time between the beginning of the shock wave and the return of the echo is used to determine the depth of the reflecting substrata. The recent use of super-computers to generate three-dimensional images greatly improves evaluation of seismic test results.
• Radiographic surveys. Radiography is the use of radio waves to provide information similar to that obtained from seismic surveys.

• Stratigraphic surveys. Stratigraphic sampling is the analysis of cores of subsurface rock strata for traces of gas and oil. A cylindrical length of rock, called a core, is cut by a hollow bit and pushed up into a tube (core barrel) attached to the bit. The core barrel is brought to the surface and the core is removed for analysis.

When the surveys and measurements indicate the presence of formations or strata which may contain petroleum, exploratory wells are drilled to determine whether or not oil or gas is actually present and, if so, whether it is available and obtainable in commercially viable quantities.

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Reduce Cost North Sea Operation

The pressure to reduce the cost of new developments has never been greater for North Sea operators. The combination of low oil prices, decreased North Sea development opportunities and increased competition from the U.S. shale industry means the industry is being forced to adapt to new ideas.

One development concept that is starting to gain traction is the use of low-cost wellhead platforms for the development of small satellite fields. These are typically newly discovered fields close to an established host platform, which can provide control and power and also carry out fluid processing. Although wellhead platforms have long been a favorite in the shallow waters of the southern North Sea, up until now the preferred option for the development of satellite fields in deeper water has been to use a subsea manifold with a tieback to the host facility. Subsea manifolds are tried, tested and trusted, but WorleyParsons has carried out several studies showing that subsea manifolds don’t necessarily provide the best value solution for a multiple well development. The difficulties and additional costs associated with maintenance and future well intervention operations can all contribute to increased costs over the lifetime of a project.

WorleyParsons has accumulated a reference list of more than 500 installations that are currently operating throughout the world, and its team has combined its experience with ideas borrowed from the shale industry—where standardization and modularization of equipment is the key to low-cost field development. The company has come up with a new concept in wellhead platforms suitable for installation in deeper water and able to withstand North Sea conditions.

The new design uses piled foundations, can be deployed in water depths of up to 120 m (394 ft) and provides space for a maximum of 12 well slots. No accommodation has been provided for personnel, who will gain access for four monthly maintenance visits by vessels equipped with a “walk-to-work” gangway. The platform design includes a 5-tonne crane and sufficient deck space to allow full access for future well intervention. WorleyParsons also has designed the new platform for construction in its covered yard near Stavanger, Norway, with one flat side to permit installation by either barge launch or jackup platform to widen the choice of installation contractor.

The platform is designed with a “design once, build many” approach to capture economies of scale and efficiencies more closely associated with a production line than a North Sea construction yard. The design borrows from the philosophies that WorleyParsons has previously followed in the Persian Gulf and Gulf of Thailand and uses a minimum number of different profiles to reduce procurement and stockholding costs.

Topsides and jacket weights are comparable to more traditional North Sea designs at about 650 tonnes and 3,500 tonnes, respectively, for a 100-m (328-ft) water depth platform, with almost all of the topsides and much of the jacket being identical for any platform regardless of water depth. However, there is scope for significant savings in project schedule by both reducing setup times and by allowing construction to start in parallel with detailed design. The design is so standardized that water depth, seabed conditions and well slot arrangement are the only pieces of information required to completely define an individual platform, further reducing project schedule and minimizing construction risk.

WorleyParsons sees an immediate market for at least 20 lowcost modularized platforms in the Norwegian sector of the North Sea alone and is talking to several operators who have been carrying out studies to assess their viability. They also see applications in U.K. waters, where the upcoming 30th licensing round will be targeting small pool discoveries that will require especially low-cost development schemes.

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Cellar Purpose in Oil Gas Drilling Onshore

Before We talk about what is Cellar or Cellar purpose, I will mention from rig located in new well location.

Once the site has been selected, scientists survey the area to determine its boundaries, and conduct environmental impact studies if necessary. The oil company may need lease agreements, titles and right-of way accesses before drilling the land. For off-shore sites, legal jurisdiction must be determined.

After the legal issues are settled, the crew goes about preparing the land:

The land must be cleared and leveled, and access roads may be built.

Because water is used in drilling, there must be a source of water nearby. If there is no natural source, the crew drills a water well.

The crew digs a reserve pit, which is used to dispose of rock cuttings and drilling mud during the drilling process, and lines it with plastic to protect the environment. If the site is an ecologically sensitive area, such as a marsh or wilderness, then the cuttings and mud must be disposed of offsite -- trucked away instead of placed in a pit.

Once the land has been prepared, the crew digs several holes to make way for the rig and the main hole. A rectangular pit called a CELLAR is dug around the location of the actual drilling hole. The CELLAR provides a work space around the hole for the workers and drilling accessories. The crew then begins drilling the main hole, often with a small drill truck rather than the main rig. The first part of the hole is larger and shallower than the main portion, and is lined with a large-diameter conductor pipe. The crew digs additional holes off to the side to temporarily store equipment -- when these holes are finished, the rig equipment can be brought in and set up.

Depending upon the remoteness of the drill site and its access, it may be necessary to bring in equipment by truck, helicopter or barge. Some rigs are built on ships or barges for work on inland water where there is no foundation to support a rig (as in marshes or lakes).

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General Step and Procedure Oil Gas Drilling in Onshore

To find oil, you cannot simply punch a hole in the ground. Perhaps, this is what many people believe.

There are many complexities involving multiple service companies and two complete teams of crews. With so much happening (and with so many difficulties regarding scheduling, safety, and environmental practices) drilling for oil is not for the faint of heart.

This is a general 51 steps for drilling in the USA, for example. 

The following steps are necessary in order to produce oil or gas from a well:

1. 10-30 different service companies are required.
2. Each company working on a well must adhere to around-the-clock scheduling, safety and environmental practices.
3. Build a new road to access the rig location.
4. Clear the area for the new rig.
5. Build infrastructure for water and electricity around the rig site.
6. Dig an earthen pit to prevent soil or water table contamination.
7. Dig a pilot hole at the precise location marked by the survey crew.
8. Dig two other holes (the “mouse” hole and the “rat” hole) nearby to hold pieces of equipment and pipe during drilling.
9. A rig that can dig a 10,000 ft. well requires 50-75 people and 35-45 semi-trucks to move and assemble the rig.
10. Assembly of the rig takes around 3 and a half days.
11. A strict inspection of the rig must take place once built.
12. Operations of the rig go on 24/7, typically ceasing only one day each year for Christmas.
13. Two shifts of two complete crews must work the rig every day.
14. There are two stages of drilling: 1. running and cementing of cases and 2. drilling until the bit reaches the depth of the targeted zone.
15. Each drill bit typically lasts 4,500 – 6,500 feet of drilling.
16. Replacing the bit requires the removal of the entire string of drill pipe in a process called “tripping out”.
17. “Tripping out” takes several hours and requires crews to cool the bit and keep the soil and hole intact.
18. To help keep cuttings from plugging the hole, the mud must be sent through shakers to send the cuttings into a separated area.
19. Additional mug system equipment: de-sanders, de-silters and de-gassers, remove smaller particles and gas from the mud.
20. Clean mud is then recirculated back down into the hole.
21. The Blow-Out Preventer (or “BOP”) is installed on top of the casing head before drilling takes place.
22. The BOP must have high-pressure safetly valves designed to seal off the well and block any escaping gases or liquids from the hole beneath in order to prevent a blow-out from occuring.
23. Drilling must begin with a designated surface depth, usually around 50-100 feet below the water table.
24. Special care must be taken to prevent contamination of the water in the water table while drilling by isolating the water table and the wall with concrete and steel encasing.
25. New sections of pipe must be added to the string as the bit drills deeper.
26. When the hole reaches a designated depth, the derrickhands secrete fluid through the hole to condition it for logging.
27. A “logging tool” measures the depth and condition of the hole for the oil company.
28. The tool gives the information of whether or not the well can indeed produce oil or gas.
29. At this point, it must be determined whether the well is to be complete or plugged and abandoned.
30. If the well is designated as a producer, the crew must re-insert the pipe back into the hole to ensure the hole is still intact.
31. To test the hole, mud must be re-circulated.
32. Once everything tests positively, the drill pipe is removed.
33. At this point, the crew must insert the last string of production casing running the entire depth of the hole.
34. Then, the casing is cemented in the hole.
35. The production crew then brings in the work-over unit and rigs it up to prepare the hole for production.
36. The crew runs small diameter tubing into the hole as a conduit for oil or gas to flow through and up the well.
37. Next, the work over unit trips out of the hole and picks up a perforating gun.
38. The perforating gun is lowered into the hole to production depth using a thin metal cable called a “wireline”.
39. An electrical signal is sent down the wireline, firing the gun and igniting explosive charges.
40. These charges create holes through the cement encasing and formation connecting the well bore to the reservoir.
41. To stimulate the flow of hydrocarbons (or oil), sometimes it’s necessary to “frack” the well.
42. “Fracking” involves pumping air, sand and fluids under extreme pressure down the hole and out through the perforations.
43. This fractures or forces cracks into the formation.
44. The remaining particles will hold the cracks open, releasing the flow of oil or gas.
45. Monitoring the flow allows the crew to determine the best location for the “choke”.
46. The “choke” controls the flow of the oil or gas.
47. Once pressure is released, the hydrocarbons are allowed the escape through the fractured zone and flow into the well bore.
48. The oil or gas can now travel up the well casing string.
49. The well bore is isolated from the surrounding formations with casing and cement, preventing any contamination.
50. The final step is to install a pump jack or production well-head, or what’s called the “Christmas Tree”.
51. It’s the time to produce the well and plan for any future field development.

Watch the Video : 

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What worker doing during Drilling Operation?

During drilling, the personnel and equipment must be protected against unexpected pressure surges in the wellbore. In oil and gas drilling, these surges can come from hydrocarbon fluids trapped under impermeable rock which holds them at pressures higher than the static head of the fluid column in the wellbore, and in geothermal operations the surges come from hot formations which heat the pore or wellbore fluids above the saturation temperature at the static wellbore pressure. In either case, the first line of control is the weight of the fluid column in the wellbore. 

With a gas column, this weight is negligible, but with mud the liquid density will range from slightly greater than water (-8.5 pounds per gallon) to almost three times that. In addition to the clays and additives which raise the viscosity of the mud to improve hole cleaning, weighting materials such as barite are often added to increase the mud's density and enable it to control higher downhole pressures.

The pressure surge cannot immediately be controlled with fluid weight, the wellbore can be mechanically sealed at the surface with BOPS, or blow-out preventers. There are three principal types of BOP: blind rams, which are sliding plates that come together across the wellbore when the drill string is not in the hole; pipe rams, which are like blind rams except that the sliding plates are cut out in the center so the rams can seal around the drill pipe; and an annular preventer, which is an inflatable bladder that seals around drill collars, stabilizers, or other off-size or irregularly shaped tools.

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Geothermal Drilling with Kelly Rig

To make the hole or drilling well with kelly rig, energy must be transmitted from the surface to the rock face at the end of the wellbore. Power supply for drilling has evolved from the early days of steam-driven,mechanically coupled rigs to the current standard of diesel-electric drive. In this configuration, two to four diesel engines (up to 2,000 horsepower each) drive electric generators, which supply power to individual electric motors driving the rotary table, drawworks, mua pumps, and other equipment. The rotary table is a mechanism, usually inset into the rig floor, which turns the drill string to break rock and advance the hole. (A "drill string" comprises the drill pipe plus the bottom-hole-assembly, or BHA. The BHA includes drill collars, stabilizers, bit, and any other specialized tools below the drill pipe).

Hole diameters in oil and gas drilling usually range fiom 4 to 26 inches, while geothermal holes generally have a minimum production size of 8-112 inches. To drill these holes, torque is applied to the kelly, which is at the top of the drill string. The kelly is a section of pipe with a square or hexagonal outside cross-section which engages a matching bushing in the rotary table. This bushing lets the rotary table continuously turn the kelly and drill string while they slide downward as the hole advances.

The upper end of the kelly is attached to a 'hvivel", which is a rotating pressure fitting that allows the drilling fluid to flow fiom the mud pumps, up the standpipe, through the kelly hose, into the swivel, and finally down the drill pipe as it rotates. The swivel is carried by the hook on the traveling block and it suspends most of the weight of the drill string while drilling.

Moving the drill string or the casing into and out of the hole is called tripping. Trips are usually required because the bit or some other piece of downhole equipment must be replaced, or because of some activity such as logging, testing, or running casing, and of course trips take longer as the hole grows deeper. Raising or lowering the drill string for a trip is done by the drawworks, which is basically a large winch. (The swivel and kelly are almost always handled as a unit, and are set aside in the "rat hole" while tripping.) The drawworks reels in or pays out a wire rope (drilling line) which passes over the crown block at the top of the rig's mast and then down to the traveling block which carries the hook, which in turn suspends the drill string or casing. Depending on what mechanical advantage is required, the drilling line is reeved several times between the crown and traveling blocks, as in a block and tackle.

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Preperation Drilling Operation

In the baseline system, all of the equipment necessary for the drilling operation is organized around the derrick, or mast. This is a steel tower , ranging from 50' to 180' in height, which supports the drill pipe with the bit and all the other downhole equipment, and which provides a platform for much of the other equipment necessary to drill the hole. 

Every rig, except for the smallest ones, has a floor just above ground level where most activity required to operate the rig takes place. The driller, who has minute-by-minute control of the rig's operation, has a console here and most pipe handling (adding a new piece of pipe, making and breaking drill string connections, changing bits, etc.) takes place on the floor. In smaller rigs, the mast and the floor are a unit and are simply raised into position in preparation for drilling. 

Bigger rigs, which may require 50 to 60 large truck loads for transportation, are usually assembled at the drill site, a job which may take s e v d days, even in accessible locations on land. offshore, or in locations with difficult access, this assembly is much more complex and time-consuming. Eventually the mast will be erected, the power generation system on-line, the fluidhandling equipment plumbed together, and the myriad other smaller components in place; only then is the rig ready to begin drilling a hole 

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Drilling with Coiled Tubing for Multilateral Wells

The petroleum industry is constantly driving to reduce capex and increase economic recoverability while minimizing environmental impact and surface footprint. By combining the three advanced drilling techniques of multilateral drilling, underbalanced drilling (UBD) and directional coiled tubing drilling (CTD), an operator can capture significant value out of known reserves.

The highest well productivity is achieved through maximizing reservoir contact per well/surface slot and minimizing reservoir damage. Multilateral drilling reduces capex through drilling multiple reservoir sections per surface slot while also increasing reservoir contact per surface slot. UBD minimizes reservoir damage, which maximizes the productivity of each lateral. CTD is inherently set up for underbalanced operations (UBCTD), and CTD bottomhole assemblies (BHAs) can achieve high build rates of up to 50 degrees per 30 m (100 ft) to allow multiple targets to be accessed from the mother wellbore.

Selecting a BHA

A directional CTD BHA consists of a coil connector, cablehead, electric or mechanical disconnect, downhole orienter, sensor package, motor or turbine with a bent housing, and a drillbit. Drilling directionally on coiled tubing (CT) is similar to conventional slide-and-rotate drilling on a rotary. As CT cannot be rotated from surface, all the rotation needs to be carried out downhole through the orienter. The rotating orienter allows the toolface to be set from surface or for the motor to be rotated to drill a straight hole.

Service companies also can provide additional BHA modules such as a gyro module for orienting a whipstock and for drilling in the presence of magnetic interference immediately after exiting the casing.

CT drilling faces two fundamental challenges: transferring weight to the bit and length limitations of the lateral sections. If the well trajectory plans for high doglegs, then it can be difficult to transfer weight to the bit. This is accentuated by the inability to rotate the whole drillstring as in conventional drilling. It is essential to have a weight-on-bit (WOB) sensor in the BHA so the driller can see that the weight is actually being transferred to the bit and react accordingly. The length of laterals that can be drilled with CT also are affected by the tortuosity, but this is particularly true in horizontal sections. The more tortuous the wellbore, the shorter the lateral length will be. CTD BHAs that have a continuous rotating orienter prevent this tortuosity from occurring and therefore maximize the available WOB and lateral length (Figure 1).

FIGURE 1. A straight wellbore increases the potential length of a lateral section compared to a wavy wellbore. (Source: AnTech)

Designing a multilateral well

All well designs require a multidisciplinary team to be successful. When designing a multilateral well, an integrated team of subsurface specialists and directional drilling specialists is even more essential to successfully drill the well. The well design and completion strategy is heavily affected by the reservoir characteristics, horizontal and vertical permeability, the geological structure, and geosteering requirements. The first step is to clarify if significant productivity gains can be made from utilizing multilaterals over other techniques. Once established, it is an iterative process between the directional drilling contractor and the operator’s engineering and subsurface teams to find the best way to design the well.

There are a near-infinite number of wellbore paths for multilateral wells. The two most common are stacked laterals and forked laterals (Figure 2). Stacked laterals can access different layers of a laminated reservoir. Forked laterals are all at a similar depth and are most commonly used to increase reservoir contact in a specific formation. Clarifying the objective for the multilaterals early on helps reduce the number of iterations required of the trajectory.

FIGURE 2. Stacked laterals offer access to different layers of a laminated reservoir, while forked laterals are at a similar depth and help increase reservoir contact in a specific formation. (Source: AnTech)

Once the trajectories are drafted, the wells must be modeled to ensure drillability and to specify surface equipment. For the CTD section the main areas for analysis are the available WOB, CT lock-up limit, borehole cleaning and surface pressures. The CT can be specified from these models. Production and geomechanics models also must be run to ensure the separation equipment is suitably specified and the amount of the underbalance applied to the wellbore does not cause wellbore stability issues.

Sidetracking techniques

To create the additional well path from the mother wellbore, a sidetrack must be initiated. There are two main categories of sidetracking a well: cased-hole sidetracks and openhole sidetracks. The cheapest and fastest way to carry out a cased-hole sidetrack is to use a whipstock and a window milled in the casing rather than section milling.

Multiple whipstocks can be set in the mother wellbore and retrieved if required. For openhole sidetracks the drilling BHA is used to create a trough in an inclined section of the wellbore. Once the trough is initiated, the WOB can be increased to carry on the borehole section. An openhole sidetrack also can be initiated off a cement plug with special procedures.

Since CTD BHAs operate on wireline, this allows significant amounts of real-time data to be received from the BHA. This helps to speed up the sidetracking process because rather than relying completely on time drilling, the directional driller can see the WOB and torque-on-bit responses to each operation and optimize on the fly. This is the case with both openhole and cased-hole sidetracks. A special module is required to monitor the casing milling operations since the vibration levels are so high.

Geosteering

A multilateral will not provide a good return on investment if the laterals are not drilled into the target zones. The options for geosteering on UBCTD are relatively limited compared to a conventional LWD service. Gamma ray and resistivity are available on certain CTD BHAs. A biostratigraphy service also can be used to identify changing formations. The UBD package can provide a significant amount of data that can be used for geosteering and reservoir characterization while drilling. The large amount of additional information that can be gathered from the real-time downhole sensors and the UBD package, if used correctly as part of an integrated data acquisition and reservoir evaluation strategy, can remove the need for expensive LWD tools or wireline logs.

Drilling practices

Drilling on CT has been avoided in the past due to concerns over stuck pipe and borehole cleaning issues. When drilling reentry wells using CTD, the borehole size is usually closer to the BHA size than in conventional drilling. In addition, since the pipe is not rotated, a greater focus needs to be placed on good borehole cleaning practices. Every CTD project must be modeled and analyzed to ensure the well can be drilled successfully. When drilling the borehole sections, the real-time drilling parameters must be monitored to identify any indications of borehole problems. Drilling practices also are adapted to ensure the borehole is clean and free of ledges. For example, a short trip must be made at every 46 m (150 ft) to ream the borehole, and at every 91 m to 137 m (300 ft to 450 ft) a long trip back to the casing window must be made. Because the driller is able to see these changes in downhole conditions at surface, there is an opportunity to prevent these issues and optimize the uptime of the operation.

Read More → Drilling with Coiled Tubing for Multilateral Wells

Expandable Liners Technology in Oil Gas Drilling

The first hanger designs specifically developed to run liners were true to their descriptive name. The weight of the liner set mechanical slips in a vertical well, and cement was used to seal the liner top. These were mechanical devices that lacked reliability, particularly in deviated wellbores.

As wells were drilled to greater depths, more reliability was needed and eventually obtained through the use of hydraulically set hangers. Once directional drilling and horizontal completions became more prevalent, many equipment suppliers adapted existing technology to the changes in well construction, with more focus on the running tools. 

More robust running tools ensure liners can be deployed in deviated wellbores that require torque, washing and reaming. However, the basic concept of using slips with a cone remains at the heart of all conventional systems, and options are added to this basic offering to aid in functionality and reliability such as dual cones, liner top packers and high-strength running tools.

Trends in liner hangers

The latest developments in running liners include metal-formed liner hangers. Expandable systems have dominated development in liner hanger technology for the past 10 years. These systems are popular because of increased setting and deployment reliability. The advances in technology are apparent through the popularity of the expandable systems and the enhanced applications in different well profiles around the world. Still, expandable systems using hydraulic pressure to set the liner top come with their own risks (e.g., high hydraulic pressure on the rig floor). Other limitations include continued complexity, potential leaks in connections and incompatibility with some rig operations.

To combat these challenges, Seminole Services developed the Powerscrew Liner System, a tool utilizing a metal-forming process that does not require high hydraulic pressures and eliminates the risks associated with reaming to setting depth. The Powerscrew is a torsionally set metal-formed liner hanger that works by converting torque from the top drive into linear force to set and seal a liner top.

The assembly is deployed on drillpipe and conveys the liner to total depth (TD) with a unique running tool. In many cases, running a liner to TD requires compression, rotation and circulation. This is especially true for longer laterals, so special design emphasis has been placed on the running tool, which can take higher compressional loads associated with reaming.

The Powerscrew Liner System is tested at the Catoosa Testing Facility in Hallett, Okla. (Source: Seminole Services)

The Powerscrew’s running tool is designed for both torque and compression while setting the liner top. As a result, these loads transfer more easily through the running tool during liner deployment.

The system includes a patented helical stretch method of metal-forming using a multi-lead rifling (MLR) mandrel. The MLR mandrel provides micro-upsets, increasing the post-formed collapse, and it counter-rotates to eliminate residual torque. In addition, helical stretch forming has less friction and therefore requires less force to forge a metallic tubular downhole. The tool incorporates a high-strength clutch that disengages the running tool from the liner upon reaching setting depth and initiates the metal-forming process with the application of torque. The wellsite operator monitors the torque gauge and weight indicator to ensure proper operation.

Liner hanger market trends

A deep dive into the liner hanger market gives credence to the idea that liner size and weights matter tremendously. With the trend in U.S. drilling focused on shale plays along with the downturn in offshore activity, there has been a shift in demand from larger tools to smaller ones. Increases in demand for liner hanger tools such as the 4½-in.-by-7-in. and the 5-in.-by-7-in. stem from the increased use of liners in horizontal sections common in U.S. shale production. The continuing increase in drilling longer lateral sections also will provide more meaningful savings to those operators choosing to run liners.

Operators drilling more complex wells have facilitated alternatives in well construction that allowed metal-formed liner systems an entry path while also providing multiple options to conventional system offerings. Liner hangers no longer, these well construction tools were built to withstand tortuous well paths and high loads, adding complexity. The tradition of hydraulic setting methodology transferred to the newer expandable systems can still suffer from difficulties souring hydraulic horsepower from the rig. Given that longer laterals will continue to be the trend in producing from shale, less complex tools that can withstand the rigors of deployment in horizontal wells will offer a viable solution to operators. Since rotary drilling rigs are readily available to deliver torsional power through drillpipe, the Powerscrew offers an alternative in metal-forming methodology.

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Rig Automation Maximizes Value For Contractors And Operators

Drilling a well is a complex mix of overwhelming data and tasks in need of constant attention. To address the challenge of repetitive complexities of machine and process control, the NOVOS process automation platform was launched by NOV after an extensive development period.

The system provides a common platform for the control, monitoring, scheduling and optimization of drilling operations. This enables drillers to focus on what is important while they consistently execute repetitive drilling activities to achieve the well program by integrating the best of human and equipment capabilities.

The NOVOS process automation platform manages rig equipment to execute drilling programs, allowing the driller to focus on safety and process execution. (Source: NOV)

Compatibility

The structuring of data and defining activities through process automation enables engineers to develop lessons learned and apply best practices across regions and rig fleets, regardless of rig specifications or location. The system is scalable, not custom-built, so it does not require extensive R&D for it to work with each new deployment.

NOVOS is simply dropped on top of the existing NOV control system, creating a quick and rapid deployment. The scalable installation enables the system to be easily placed on rig fleets, which increases overall consistency, enhances the performance of the entire fleet and gives the end user the ability to plan ahead.

The system is equipped with applications that immediately allow the rig to drill faster, safer and more effectively. It also has the capability to incorporate customized applications for specific drilling requirements.

A software development kit allows developers to create and deploy their own optimization applications that use sensor data to control rig machines. Third parties are provided with safe access to a wide variety of functions within the system and encouraged to develop applications that address their unique challenges. Those applications can then be layered, prioritized and partitioned to provide simple flexibility of control and monitoring in ways that were previously unachievable.

There are five major operators and service companies working to develop applications compatible with the platform, with development pending with nine more companies.

The platform today

Years of development were spent to ensure NOVOS was built with a foundation of stability, flexibility and ease of scalability to be valuable in bringing practical automation to the drilling process.

In the years since its launch the platform has successfully been installed and commissioned on 19 land rigs. There are five additional installs scheduled but pending rig availability. The system is installed on rigs in Oklahoma, Pennsylvania, Texas and Canada. Precision Drilling currently has the system installed on 18 land rigs. In second-quarter 2017 a system was purchased by Beaver Drilling for installation on its Rig 15.

The NOVOS team is actively training drillers on rig location depending on rig and resource availability. During the training process drillers are easily picking up the system and becoming even more proficient over time.

Value in the numbers

NOVOS was recently deployed during a rig move for Precision Drilling. The early results showed the company’s drillers achieved consistent bottom-to-bottom time savings—a 10% improvement bottom-to-slips, 18% faster add-stand and a 67% improvement slips-to-bottom—yielding overall time savings of 41% per connection.

To evaluate connection time improvements, NOV compared the five best consecutive bottom-to-bottom cycles for conventional drilling against five consecutive cycles of NOVOS-enabled drilling. There was a reduction in average bottom-to-bottom time from 7.91 minutes to 4.67 minutes using NOVOS, demonstrating a significant improvement in Precision’s performance. The increased consistency created by automating repetitive tasks resulted in an increased awareness of safety and successful delivery of the overall drilling operation.

Assuming six wells per pad and 20 total days of drilling time per well, connection time savings translated to nine hours saved per well and 2.25 days saved per pad on average, enabling the drilling contractor to better plan service delivery, allocate resources and move quickly to the next pad. The total savings added up over time yielded higher profits and rates of return on the customer’s initial investment.

Precision Drilling saw a savings in overall connection-to-connection time and delivered a consistent drilling process with its use of NOVOS. (Source: NOV)

Next steps

As NOVOS begins to make its way on to several rigs, the surface is just being scratched on how the automation can be used. There are many repetitive functions that are still performed manually that can be brought into the control system. Right now, consistent and repetitive tasks are automated on the drill floor, but there are other areas on the rig where repetitive tasks could be automated.

Features added since the release of NOVOS include, but are not limited to, reaming, rocking, torque and drag, and a downlinking interface. The ease of updates and enhancements further shows the flexibility of the NOVOS platform. As for next steps, an improved user interface based on driller feedback also is being developed. The additional features and new user interface are scheduled to be released in third-quarter 2017, and work toward finalizing offshore capabilities for gel breaking and envelope protection are underway.

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Digitalization Directional Drilling

Super-specification pad-optimal Swiss Army-style walking rigs may generate headlines when it comes to evolution in land drilling, but directional drilling is fast becoming a more accurate indicator of how the sector is evolving as tight formation development enters full field development.

Companies like Baker Hughes, a GE company, have offered sophisticated geo-steering suites combining bits, motors, downhole evaluation and software control to improve ROP for some time. But quietly, and without fanfare, the largest domestic land drilling contractors and their Canadian peers are integrating digital directional drilling capabilities into rig offerings.

The trend accelerated over the last six months when land contractors began purchasing digital directional drilling providers. Acquisitions include Helmerich & Payne IDC’s $100 million purchase of Motive Drilling Technologies Inc. in May, Patterson-UTI Energy Inc.’s $215 million cash and stock purchase of MS Energy Services and Trinidad Drilling Ltd.’s $40 million cash and stock acquisition in August of RigMinder Inc. and its electronic data recorder and bit guidance systems, which integrate the rig and directional drilling tools.

Other drillers, including Nabors Industries Ltd. and Ensign Energy Services Inc., offer directional drilling services and supporting downhole packages that include proprietary mud motors and MWD tools integrated with software to improve directional drilling performance. Nabors, for example, is commercializing a multiple package software suite that includes its recently developed ROCKit directional steering control system.

Meanwhile, Canada’s Precision Drilling aims to “de-man” the directional drilling process via a proprietary directional guidance system that coordinates workflow between the rig’s driller on location and a remote directional driller who oversees several directional drilling projects simultaneously. Precision is using algorithms to convert 14 process and 20 decision points in directional drilling into seven processes and 10 decisions, reducing support crew, time and cost. The system will be fully deployed across Precision’s fleet in 2018.

What’s going on? At the simplest level, it is an opportunity for drilling contractors to capture more revenue per rig in a flat pricing environment. Beyond that, larger drillers are bringing in-house a service that is integral to today’s best practices where precise lateral landing in extended wellbores is as important for boosting hydrocarbon recovery as greater proppant loading.

Digitally enhanced directional drilling integrates software suites, sensors and downhole tools to reduce wellbore tortuosity and generate higher ROP. Digital directional drillers  point to field-tested savings in time and direct costs that are measured in tens of thousands of dollars per well.

Digitalization of directional drilling is disruptive technology. The question is whether it will supplant both personnel and the community of independent service providers.

One other factor promoting the spread of digital directional drilling is that the software is often independent of the rig, allowing smaller contractors to integrate the service into their own rig offerings via third-party access.

Like all wellsite technology, digital directional drilling may require an evolutionary step in perception at the well site that also incorporates specialized human input and flexibility as the best solution for sophisticated problem-solving in a dynamic environment.

Source:Shutterstock.com

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New Plug Technology Advancements in Oil Gas Drilling

Operators are challenged with maintaining well integrity and service quality in an industry heavily affected by fluctuations in the market. Well integrity is concerned with the safe and reliable containment of all well fluids throughout the life of a well, including after decommissioning. In turn, service companies are constantly challenged by operators to provide safe and efficient ways of abandoning wells at a lower cost and in less time.

Historically, the deployment of mechanical plugs has been a standard and common way of securing wells for both temporary and permanent plugging and abandonment (P&A). In light of new solutions and methods that are being developed, mechanical plugs will continue to be a major contributor to P&A going forward. Requirements set for barrier plugs vary depending on local regulations and company-specific requirements.

Mandates such as ISO 14310 by the International Organization for Standardization (ISO) and API 11 D1 by the American Petroleum Institute (API) define well integrity and list requirements for design, documentation, testing and validation of plugs and packers in the market. In many cases, operators need solutions and equipment that at a minimum are approved according to these regulations.

Operators are searching beyond conventional solutions and require more technologically advanced tools and technologies that meet their expectations of cost and time savings without compromising the requirements for well integrity and service quality.

Conventional plug operations face limitations linked to conveyance and the options for downhole manipulation to operate a plug. Time spent tripping in and out of a wellbore is often the most time-consuming part of well suspension. Limitations related to plugs being deployed, such as tripping speed, circulation, weight requirements, torque and rotation, are often much more restrictive than what the rig equipment can handle and can be a limiting factor in an operation.

Plug technology advancements

Archer’s series of LOCK (V0-rated) and SPARTAN plugs have been optimized to deliver high performance and reliability, combatting harsh well conditions and resulting in cost efficiency and time savings. These plugs have been specially engineered to eliminate the need for weight to be hung off below to set as well as handle high tripping speeds, high circulation rates and minimum weight required above to set.

Developed to be simple and cost-effective, SPARTAN plugs offer the same benefits as the LOCK family of plugs. This type of plug, which meets the requirements of ISO 14310 (V3 to V6) certification, is designed for well suspension periods of days to months, ensuring easy deployment, a secure seal and safe removal on task completion. In other words, this plug is rapidly deployable, easy to set and easy to retrieve.

The company has further developed three new plug tools based on LOCK and SPARTAN plugs.

P&A casing retrieval plug system

The SPEARHEAD is applied where extensive hangoff weights or pull forces are required. With its heavy hangoff and pulling capability, the SPEARHEAD pulls the tieback or casing during the P&A of wells. It can therefore be used as an alternative to an original spear.

The SPEARHEAD also can be installed as an emergency hangoff together with a selective set valve that is installed below the plug. The ball valve, which is easy to operate, can check for gas in the drillpipe and annulus below before retrieving the plug. If necessary, mud can be bullheaded inside the drillpipe and then in the annulus by operating the selective set valve below the plug.

Case history

An operator in the North Sea recently planned a six-well P&A campaign. The original plan was to cut, pull and lay down more than 4,000 m (13,123 ft) of 7-in. tubing from each well. The operator intended to continue setting a bridge plug at 2,000 m (6,561 ft), then cut the 95⁄8-in. casing above the plug and finally displace the well to water-based mud. The process of retrieving and handling the tubing is time-consuming and costly. The operator asked for a plug that could avoid pulling the entire tubing string and save rig time.

Archer’s integrated P&A technology was to retrieve about 2,000 m of tubing and suspend permanently the remaining 2,000 m of tubing below the SPEARHEAD plug. When the plug and tubing were run in hole, a casing cutter was installed above the SPEARHEAD running tool. The SPEARHEAD, with the tubing below, was set at about 2,000 m and pressure- tested. The 95⁄8-in. casing was then cut above the plug, all of which was achieved in one run. The P&A operation continued with the retrieval of the 95⁄8-in. casing above the cut.

As a result, about 18 hours of operation time was saved for each well. The total saving for this operation was 54 hours for three wells as well as cost savings associated with rig time. The overall safety and risk profile of the operation also was reduced along with the time and costs associated with logistics, transport and handling.

Dual-plug system

The company’s VAULT is a dual-plug system that enables two plugs to be set and retrieved in one run, saving a considerable amount of time in a well operation. The company recently installed two barrier plugs and retrieved the wear bushing in the same run for a major operator in the North Sea. A standard TIMELOCK was used as the deep barrier plug, while the VAULT plug was installed as a shallow barrier. When both plugs were set and tested, the wear bushing was retrieved in the same run. To save even more hours of operational rig time, the two plugs can be retrieved in the same run. This can be achieved since the retrieving tool of the TIMELOCK plug is hanging off either just below or spaced out below the shallow VAULT plug.

Tandem plug system

The HUNTER plug system was developed with the goal of being run in combination with other tools and equipment such as wellbore cleaning equipment while having the ability to withstand high rotation and loads without the plug being set until activated.

The HUNTER plug allows the string to be rotated without unintentionally setting the plug. The ability to combine operations in the same run as setting the plug will save operators several hours of rig time.

Remote operations

Archer’s Integrated Operations center has played a part in delivering swifter and safer plug operations in the North Sea. It uses real-time data and new technology to enable cooperation between onshore support and offshore teams. Real-time data can be transferred over long distances, removing the physical barrier between expert onshore support teams and offshore execution. Integrated operation reduces offshore persons onboard, therefore ensuring smooth, flexible and cost-effective operations.

Source : Archer

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DRILLMEC PRESENTS HOD, NEW SYSTEM FOR CONTINUOUS FLUID CIRCULATION

Continuous flow of drilling fluids offers many advantages, including well-bottom well pressure control combined with improved blade cleanliness and stability. In the current scenario of the oil market, these features become key requirements for personnel safety, operational efficiency and cost reduction, particularly in drilling environments with very narrow margins with ever-increasing water depths , and well situations characterized by high pressure and high temperature.

HoD (Heart of Drilling) technology is an advanced system for continuous circulation, developed and patented by Drillmec, where an automated control system provides for switching of sludge circulation between the drive head (top drive ) and a lateral opening integrated into each valve (sub) mounted at the top of the drilling lengths before starting the drilling step. A completely self- locking, remote-controlled key locks the opening and closing of the integrated side door with an operation that does not involve any manual action.

When a new length is added to the drill string, a sub mounted on the perforated length, and in the well, is positioned at the rotary table and the automatic key, which links a lateral flow line, is engagement with the sub. Once the key lock hydraulic clamps are securely connected to the sub, the probe staff can move away from the most vulnerable area, delimited by a red perimeter, and handle the rest of the operating sequence by a control panel remote. Acting on the key controls from the control panel, the operator opens the outer cover of the sub side opening, which remains inside the key throughout the operating sequence. When the control system confirms the opening state of the outer cap, the drilling mud stream can be directed by the top drive to the side opening in the sub before unscrewing the top drive from the drill string; after adding a new drilling length, the mudflow can be redirected to the top drive. The flow rate of drilling sludge to the shaft remains constant throughout the entire connection sequence, thus maintaining a dynamic shaft condition characterized by a constant bottom well pressure and continuous drilling of the BHA (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases. the drilling mud stream can be directed by the top drive to the side opening in the sub before unscrewing the top drive from the drill string; after adding a new drilling length, the mudflow can be redirected to the top drive. The flow rate of drilling sludge to the shaft remains constant throughout the entire connection sequence, thus maintaining a dynamic shaft condition characterized by a constant bottom well pressure and continuous drilling of the BHA (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases. the drilling mud stream can be directed by the top drive to the side opening in the sub before unscrewing the top drive from the drill string; after adding a new drilling length, the mudflow can be redirected to the top drive. The flow rate of drilling sludge to the shaft remains constant throughout the entire connection sequence, thus maintaining a dynamic shaft condition characterized by a constant bottom well pressure and continuous drilling of the BHA (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases. after adding a new drilling length, the mudflow can be redirected to the top drive. The flow rate of drilling sludge to the shaft remains constant throughout the entire connection sequence, thus maintaining a dynamic shaft condition characterized by a constant bottom well pressure and continuous drilling of the BHA (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases. after adding a new drilling length, the mudflow can be redirected to the top drive. The flow rate of drilling sludge to the shaft remains constant throughout the entire connection sequence, thus maintaining a dynamic shaft condition characterized by a constant bottom well pressure and continuous drilling of the BHA (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases. thus maintaining a dynamic shaft condition characterized by a constant bottom drain pressure and continuous BHA drilling (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases. thus maintaining a dynamic shaft condition characterized by a constant bottom drain pressure and continuous BHA drilling (Bottom Hole Assembly). The continuous circulation system HoD can be used both during the drilling phases and in the maneuvering phases.

Some important considerations during the design process have given rise to high safety standards for staff and equipment, ease of integration into the drilling rigs in operation, and the ability to minimize downtime by integrating a maintenance management system in control systems.

All components of the HoD system are designed according to applicable APIs for a working pressure of 7500 psi and a maximum flow rate of 1000 gpm during connection. The side side opening design guarantees a double safety barrier between the pressure inside the drill and the outside during connection to the probe and in the well. Both barriers are independent and have been tested at one and a half times the exercise pressure.

The system is designed to be integrated into ground and sea systems, with the manifold running the sludge flow, the hydraulic unit and the control system integrated in the same frame with a small footprint. This feature provides complete flexibility during installation, safe and fast assembly operations without the need for expensive modifications to the sludge circuit of the drilling rig. The typical installation layout isolates the manifold from the pumping system during the drilling phases. Consequently, the load losses added to the mud circuit are minimized and the duration of the valves in the sludge manifold can be drastically increased. In addition, with the non-pressurized sludge manifold during drilling,

Operations during connection are completely controlled through a secure area on the probe plane or directly from the perforator cabin. Human intervention is only required to engage and remove the automatic key, but the key itself and the associated hinge are not pressurized during such operations. For newly conceived Drillmec systems, where the HoD Continuous Circulating System can be integrated directly into the mud system, a fully automated keypad handling system has also been developed.

Management software provides complete remote control of operating sequences, as well as providing real-time status of each component of the system on the remote control panel. The connection sequence can be performed with a fully automated or semi-automatic routine. In both cases, the control system acquires and processes signals from integrated sensors into the main components of the system, reducing human errors with text messages and alarms. The software also includes a Computerized Maintenance Management System (CMMS) that helps maintain a historical database of operating parameters for each component of the system, plan and monitor maintenance activities, and manage transaction reports.

After successfully completing rigorous hydrostatic and functional testing programs, the HoD Continuous Circuit System has recently completed field application in a deep pit for the confinement of a ground field in Europe. In particular, the HoD® Continuous Circulating System has been used to perform 12-inch and 1/4 phase drilling with the objective of maintaining constant ECD ("equivalent circulation density") density during connections, improve drill and hole battery cleaning and stability during drilling and drum extraction from the well. For this application, "ad hoc" designed and built for acid environments containing H2S,

The entire HoD package showed excellent results in terms of functionality and reliability of components in extreme working conditions and characterized by high specific weight sludges and high hydraulic parameters. Continuous circular connections were carried out in complete safety with a maximum pressure of the plant probe manifold of 4,200 psi and a maximum flow rate of 750 gpm.

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Kelly Tube

A kelly tube is a piece of drilling equipment. In particular, it refers to a device used in the extraction of liquid or semi-liquid resources such as oil and natural gas. The main purpose of a kelly tube is to allow the drilling battery to be raised and lowered at the same time as the drum fluid is pumped through it. This is important, as drilling fluid is essential for the extraction process.

In most cases, a kelly tube is classified as a large diameter tube. This means that the inside diameter is usually between 3 and 5 inches (about 7.6 cm and 12.7 centimeters). This wide diameter allows flow rate and reduces the probability of a block occurring in the tube.

The kelly tube must also be able to withstand large amounts of pressure. This is especially true for the pressure of the fluid flowing through the tube. For this reason, it is often made of very durable material and is generally reinforced with steel.

In a drilling or perforating tower, the kelly tube connects the pipe, which is the rigid metal shaft carrying the mining fluid to the rotating part, which is the piece supporting the weight and commands the rotation of the drilling battery. Its purpose is to provide a flexible drilling fluid conduit as a rigid conduit would be able to move with the rotation and therefore prevent the drum battery movement and, subsequently, the bit.

Drilling fluid, sometimes referred to as drilling mud, carried by a kelly tube is essential for operations in several ways. It keeps the cold a little, which helps to reduce friction and failure. It also cleans the bit and removes drilling debris so that it can not damage the drill unit. Some varieties are used for additional purposes, such as corrosion and hydrostatic pressure. Drilling fluid is not necessarily fluid, but can be a solid, liquid, gas or other combined form.

The kelly tube is so called because its connection to kelly, the actual mechanical piece that expels the drilling fluid on the drill. Alternatively it can be called a mud tube or rotary tube. Failure may occur, despite the robust construction of the tube. This failure can cause damage to the rig or failure. Unsuccessful kelly tubes must be repaired or replaced before extraction operations can safely and effectively resume.

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Drill String

A drilling battery is a tool that is used to drill deep hole holes in the ground in order to locate and extract oil or other resources. The construction of this device allows for rapid drilling and at the same time to extract large amounts of rock and mineral from a digging site. Mud is also injected down through the drilling battery to cool the tip while it is moving and to soften the surface that is boring through, reducing the likelihood of an improper cutting and increasing the overall bit time. A medium drilling string extends 15,000 feet (4,572 m) into the ground once mounted on the ground and up to 30,000 feet (9,144 m) or more when built offshore,

Within the drill battery assembly, there are four main components: lower hole mounting (BHA), transition tube, drilling rods and drill bit subs. The BHA is the stabilizing system that consists of the same tip and massive heavy rods that apply enormous amount of force down to facilitate drilling. A passage pipe connects the heavy rods to the actual drill pipe, and together these two components provide the necessary stability to ensure that the tip remains solid at such drastic depths. Drilling rods are also the majority of the length inside a drilling column, so they must be constructed using specific chemical compositions and forged at extreme temperatures.

Most components within a drill column are constructed at 31 or 46 feet (9.4 or 14 m) intervals, and two to four of them are combined to do what is termed a stand. Each substrate is then lowered into the ground before drilling initiated, in order to ensure that the drill always stays within perfect alignment. Similarly, they are removed from the ground before the drill is extracted.

Sometimes, the stands can get stuck and become difficult to remove, and specialized recovery tools called drill string jars and resonant vibrators are used to remedy this otherwise difficult situation. These methods are normally implemented by experienced oil companies. Technological advances discovered during the mid-20th century have made drilling strings much easier to handle.

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