Drilling Innovations That Will Forever Change the Oil Industry

Oil drilling has now been practiced for over a century. The sector has developed by leaps and bounds as a result of several technological breakthroughs. This expansion has resulted in new advances in oil production that are altering the face of our civilization.

As early as 1880, the globe witnessed one of the earliest developments known as the rotary drill, which dramatically enhanced the oil drilling process. This rotary drill, however, was just the beginning of a lengthy line of subsequent developments that would eventually replace it in the twentieth century. In this post, we'll look at some of the most significant breakthroughs in oil production efficiency.

1. Offshore Drilling and ROVs

Oil drillers quickly discovered that wells located near seashores generated the most oil. This is why the industry needed to develop technologies for extracting oil from the seafloor. Drilling companies built oil rigs on several wharves in the 1980s, but the first oil well on land was discovered somewhere about 1947.

Remotely operated vehicles were among the early technologies that aided the establishment of these offshore drilling enterprises (ROVs). The US military was already using this technique to recover equipment that had been lost at sea. The oil sector was exploiting ROVs for their own purposes by the 1970s.

2. Hydraulic Fracturing

Fracking, or hydraulic fracturing, is another new technology that Shale Gas relies on. This approach, which was created in 1940, has grown in popularity. Fracking is based on tight reservoirs, which often contain oil-bearing rocks with small holes, implying that the flow of oil from these is limited.

Drillers utilize fracturing to stimulate these wells by putting chemicals mixed with water into the well to produce pressure. This pressure, in turn, causes fractures in the rocks that can be hundreds of feet long. After these fissures are created, oil is allowed to flow freely out of the rock. According to numerous studies, fracking has contributed to an additional seven billion dollars oil barrels from wells in the United States.

3. Seismic Imaging

Initially, looking for oil wells was based solely on where oil had bubbled to the surface. Because most oil wells are buried far beneath the earth's surface, they cannot be discovered. Digging deep wells to set up rigs only to find barren patches was also highly costly.

Geologists were brought in to devise methods for locating oil wells that were hidden. They devised numerous approaches, the most important of which was 3-D seismic imaging. This system transmits sound waves into the ground and detects signals as the waves bounce off of obstacles.

This technology not only assisted in locating the most productive locations for establishing oil production units, but it also reduced the number of holes that were drilled without success.

4.   Measurement-While-Drilling Systems

One major disadvantage of seismic technologies was that they did not provide drilling operators with precise information about the amount of oil they were working with. These concerns were resolved in the 1980s thanks to a technology known as measurement-while-drilling (MWD).

With this system and its reliance on'mud pulse telemetry,' operators were able to collect and analyse real-time data, allowing them to establish the state of the oil well. This technology, in turn, enabled operators to drive oil wells in different ways based on the data they had gathered.

5.   Horizontal Drilling

We emphasized the potential of operators to steer their oil drilling operation in multiple directions while discussing MWD technologies. This capacity to drill in directions other than straight has become one of the most significant technological achievements in the history of the oil drilling process.

Oil reservoirs tend to be spread out horizontally from time to time, making vertical wells an ineffective method of extraction. This is why these technologies enable operators to dig vertically initially and then pivot to a horizontal well at the 'kick-off point.'

This technology has not only enabled the extraction of oil from horizontal wells, but it has also assisted operators in conducting their operations in a more environmentally friendly manner. The first horizontal wells were dug in 1929, but the process was prohibitively expensive at the time. However, with the introduction of hydraulic fracturing, horizontal drilling became a more inexpensive and realistic choice. By the late 1980s, nearly all oil drilling companies across the world were adopting horizontal drilling.

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Fire and Explosion Risk in Oil Gas Drilling

There is always a risk of blowout when perforating a well, with a gas or vapour cloud release, followed by explosion and fire. Additional potential for fire and explosion exists in gas process operations.

Offshore platform and drilling rig workers should be carefully evaluated after having a thorough physical examination. The selection of offshore crew members with a history or evidence of pulmonary, cardiovascular or neurological diseases, epilepsy, diabetes, psychological disturbances and drug or alcohol addiction requires careful consideration. Because workers will be expected to use respiratory protection equipment and, in particular, those trained and equipped to fight fires, they must be physically and mentally evaluated for capability of carrying out these tasks. The medical examination should include psychological evaluation reflective of the particular job requirements.

Emergency medical services on offshore drilling rigs and production platforms should include provisions for a small dispensary or clinic, staffed by a qualified medical practitioner on board at all times. The type of medical service provided will be determined by the availability, distance and quality of the available onshore services. Evacuation may be by ship or helicopter, or a physician may travel to the platform or provide medical advice by radio to the onboard practitioner, when needed. A medical ship may be stationed where a number of large platforms operate in a small area, such as the North Sea, to be more readily available and quickly provide service to a sick or injured worker.

Persons not actually working on drilling rigs or platforms should also be given pre-employment and periodic medical examinations, particularly if they are employed to work in abnormal climates or under harsh conditions. These examinations should take into consideration the particular physical and psychological demands of the job.

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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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Compressed Natural Gas and Liquefied Hydrocarbon Gases

LNG

The composition of naturally occurring hydrocarbon gases is similar to crude oils in that they contain a mixture of different hydrocarbon molecules depending on their source. They can be extracted as natural gas (almost free of liquids) from gas fields; petroleum-associated gas which is extracted with oil from gas and oil fields; and gas from gas condensate fields, where some of the liquid components of oil convert into the gaseous state when pressure is high (10 to 70 mPa). When the pressure is decreased (to 4 to 8 mPa) condensate containing heavier hydrocarbons separates from the gas by condensation. Gas is extracted from wells reaching up to 4 miles (6.4 km) or more in depth, with seam pressures varying from 3 mPa up to as high as 70 mPa.

Natural gas contains 90 to 99% hydrocarbons, which consist predominately of methane (the simplest hydrocarbon) together with smaller amounts of ethane, propane and butane. Natural gas also contains traces of nitrogen, water vapour, carbon dioxide, hydrogen sulphide and occasional inert gases such as argon or helium. Natural gases containing more than 50 g/m3 of hydrocarbons with molecules of three or more carbon atoms (C3 or higher) are classified as “lean” gases.

Depending how it is used as a fuel, natural gas is either compressed or liquefied. Natural gas from gas and gas condensate fields is processed in the field to meet specific transportation criteria before being compressed and fed into gas pipelines. This preparation includes removal of water with driers (dehydrators, separators and heaters), oil removal using coalescing filters, and the removal of solids by filtration. Hydrogen sulphide and carbon dioxide are also removed from natural gas, so that they do not corrode pipelines and transportation and compression equipment. Propane, butane and pentane, present in natural gas, are also removed before transmission so they will not condense and form liquids in the system. (See the section “Natural gas production and processing operations.”)

Natural gas is transported by pipeline from gas fields to liquefication plants, where it is compressed and cooled to approximately –162 °C to produce liquefied natural gas (LNG). The composition of LNG is different from natural gas due to the removal of some impurities and components during the liquefaction process. LNG is primarily used to augment natural gas supplies during peak demand periods and to supply gas in remote areas away from major pipelines. It is regasified by adding nitrogen and air to make it comparable to natural gas before being fed into gas supply lines. LNG is also used as a motor-vehicle fuel as an alternative to gasoline.

Petroleum-associated gases and condensate gases are classified as “rich” gases, because they contain significant amounts of ethane, propane, butane and other saturated hydrocarbons. Petroleum-associated and condensate gases are separated and liquefied to produce liquefied petroleum gas (LPG) by compression, adsorption, absorption and cooling at oil and gas process plants. These gas plants also produce natural gasoline and other hydrocarbon fractions.

Unlike natural gas, petroleum-associated gas and condensate gas, oil processing gases (produced as by-products of refinery processing) contain considerable amounts of hydrogen and unsaturated hydrocarbons (ethylene, propylene and so on). The composition of oil processing gases depends upon each specific process and the crude oils used. For example, gases obtained as a result of thermal cracking usually contain significant amounts of olefins, while those obtained from catalytic cracking contain more isobutanes. Pyrolysis gases contain ethylene and hydrogen.

Combustible natural gas, with a calorific value of 35.7 to 41.9 MJ/m3 (8,500 to 10,000 kcal/m3), is primarily used as a fuel to produce heat in domestic, agricultural, commercial and industrial applications. The natural gas hydrocarbon also is used as feedstock for petrochemical and chemical processes. Synthesis gas (CO + H2) is processed from methane by oxygenation or water vapour conversion, and used to produce ammonia, alcohol and other organic chemicals. Compressed natural gas (CNG) and liquefied natural gas (LNG) are both used as fuel for internal combustion engines. Oil processing liquefied petroleum gases (LPG) have higher calorific values of 93.7 MJ/m3 (propane) (22,400 kcal/m3) and 122.9 MJ/m3 (butane) (29,900 kcal/m3) and are used as fuel in homes, businesses and industry as well as in motor vehicles (NFPA 1991). The unsaturated hydrocarbons (ethylene, propylene and so on) derived from oil processing gases may be converted into high-octane gasoline or used as raw materials in the petrochemical and chemical-processing industries.

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CLASSES OF LOST CIRCULATION (Mud Losses)

Lost circulation or mud losses when oil gas drilling can be grouped into four classes:

1. Seepage losses: From 1-10 bbl/hr and lost while circulating at the normal drilling circulateng rate

2. Partial losses: From 10-50 bbl/hr and lost while circulating at the normal drilling circulating rate

3. Severe losses: Greater than 50 bbl/hr and lost while circulating at the normal drilling circulating rate. In some cases, no losses may be seen if pumping stops indicating that the ECD is the cause of lost circulation.

4. Total losses: When the mud level in the annulus can not be seen or the hole can not be filled

through the annulus. Total losses usually occur in cavernous formations.

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TYPES OF DRILLING CONTRACTS

The type of Drilling Contract

1.  TURNKEY DRILLING CONTRACT:

A type of financing arrangement (contract) for the drilling of a wellbore that places considerable

risk and potential reward on the drilling contractor. Under such an arrangement, the drilling

contractor assumes full responsibility for the well to some predetermined milestone such as the successful running of logs at the end of the well, the successful cementing of casing in the well

or even the completion of the well. Until this milestone is reached, the operator owes nothing to

the contractor. The contractor bears all risk of trouble in the well, and in extreme cases, may

have to abandon the well entirely and start over. In return for assuming such risk, the price of the

well is usually a little higher than the well would cost if relatively trouble free. Therefore, if the

contractor succeeds in drilling a trouble-free well, the fee added as contingency becomes profit.

Some operators, however, have been required by regulatory agencies to remedy problem wells,

such as blowouts, if the turnkey contractor does not.

 2. FOOTAGE DRILLING CONTRACT:

In the context of Oil & Gas law, a footage drilling contract refers to a contract in which the drilling contractor is paid to drill to a specified formation or depth. The drilling contractor is paid a set amount per foot drilled, and is given broad control over how to do the work. Under this kind of contract, the risk of unexpected delays along with other liabilities is on the contractor and not on the lease operator.

3. DAYWORK DRILLING CONTRACT: 

In relation to Oil & Gas law, a daywork drilling contract is one in which the lease operator hires a drilling rig and oilfield workers and retains the right to direct drilling operations. The lease operator pays an amount based on the time spent in drilling operations. This type of contract gives the lease operator broad control over the drilling contractor. As a result, courts impose broad liability on the lease operator for any damages caused due to the drilling.

4. COMBINATION DRILLING CONTRACT: 

The basis for payment is often combined in the final agreement. An Operator may agree to pay Footage rate to a certain depth, then pay daywork for any drilling done below that depth.

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Drill String is. Points of Drill String

Drill String

• The drillstring is made up of the drillpipe, drill collars, and specialized subs through which the drilling fluid and rotational power are transmitted from the surface to the bit.
• Drill pipe and drill collar come in sections, or joints, about 30 feet long.
• The most commonly used diameters of drill pipe are 4, 4½, and 5 inches OD.
• The purpose of drill collars is to put extra weight on he bit, so they are usually larger in diameter than drill pipe and have thicker walls.
• Drill pipe and drill collars have threaded connection on each end.
• On drill pipe the threaded connection are called tool joints. Tool joints are steel rings that are welded to each end of a joint of drill pipe. One tool joints is a pin (male) connection, and the other is a box (female) connection.
• Specialized Subs: The word “sub” refers to any short length of pipe, collar, casing, etc., with a definite function.

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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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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

The Connection in Oil Gas Drilling with new Technology

As the drilling landscape changes, an upturn in land factory drilling projects drives the need for efficient, high-performance products and technologies. NOV addressed the needs of this shifting market by developing the Delta line of rotary-shouldered drillpipe connections. These connections are stronger and more fatigue-resistant than other rotary-shoulder connections, and this allows a simplified threading procedure, which excludes the need for cold rolling, reducing the cost of maintenance and therefore lowering the total cost of ownership.

Performance-wise, the connection delivers on average 4% more torque than the XT connection. Using streamlined 130,000-psi tool joints, the Delta connection improves hydraulic performance by allowing the use of a larger-than-normal pipe body size. For example, 5½-in. drillpipe can be used to drill in the size of hole in which 5-in. drillpipe was previously used. This is made possible because the outside diameter of the tool joint is identical to the industry standard for 5-in. drillpipe (65⁄8 in.).

In addition to significant reduction in pressure losses, the connection also allows better borehole cleaning since fluid circulates at a higher velocity outside of the drillpipe. The stiffer pipe allows the drilling of a better quality hole.

The modified geometry of the Delta connection engages more threads at stab-in. This minimizes stabbing damage while also evenly distributing stress.

The deeper stab-in also reduces the number of turns necessary to make up the connection, increasing efficiency and reducing wear on the threads.

Compared to similar products, the Delta connection requires 50% fewer turns from stab to makeup. The connection saves time in that it can be spun in as little as four seconds, while XT connections typically require eight seconds.

This decreased connection time translates to increased cost-effectiveness and ease of use on the rig floor. Ease of use is further improved by a reduction in the minimum required tong-gripping distance from the box face. When other connections require a 2-in. tong-free area to prevent egging of the box connection, the Delta connection only requires ½ in. of tong-free area, giving drillers more flexibility in the positioning of the iron roughneck.

Reduced cost of ownership

One of the main objectives while developing this connection was to reduce the cost of ownership. NOV determined the best way to achieve that goal is to keep the connection in service and reduce the frequency of repair. Multiple design choices contribute to maintaining the Delta connection—and the joint of drillpipe that carries it—in the field while drilling. First, wider field inspection tolerances reduce the need for frequent repairs without compromising the connection’s performance. Second, a tolerance for pitting in the root of the less critical threads was established. Besides these inspection criteria changes, the geometry of the new connection reduces the material loss by 30% for face-and-chase repair operations.

This allows more recuts using the same tool joint tong space. The reduction of the tong-free area on the tool joint results in increased room for recuts given the same tool joint length. The total refacing amount has been increased by 50%, allowing additional refacing to take place before a recut is needed.

Best practices were developed by the company for its licensees in the shop environment for these recuts. These practices will result in less than a 1-in. loss on pin or box for a full face-and-chase repair. The connection also has the lowest royalty on repair services across all of NOV’s double-shoulder connections. The Tuboscope Business Unit within NOV Wellbore Technologies further supports the connection with reduced repair rates to pipe owners and the option to include the TracID radio frequency identification-based tagging and inventory management system as part of the base configuration for the pipe connection. In support of the Delta connection NOV developed rig-ready upgrades such as the TDS-11SAH top drive, ST-80X iron roughneck and a 7,500-psi pump.

Before its introduction to market the Delta connection underwent extensive testing at NOV’s research and technology development center, with early results demonstrating that the new connection made up twice as fast as its predecessor. During testing, damage was minimal and was primarily related to handling. Generally, only refacing was required to repair the damage.

Case studies

The first string of drillpipe with the Delta connection was used to drill a well in the Permian Basin and was the subject of intense scrutiny. This initial drilling job was very successful, and the 5½-in. drillpipe with the Delta 544 connection delivered as expected. The drilling project finished ahead of schedule, and the hole quality of this longest lateral for the operator in this field was excellent, with smooth running of the casing string. A post-use visual inspection of the connections was conducted and confi rmed that the Delta string was in excellent condition after drilling the well. The rental string was retained by the operator and will be used again to drill another pad.

Two other strings with Delta 544 connections were deployed in April 2017, one in the Gulf of Mexico (GoM) and another on a land rig in West Texas. Once again, the customers found the product easy to use, and the field service personnel who were dispatched to these rig sites could see that drillers quickly became comfortable with the new connection.

In June the different sizes of the Delta connections were used on land and offshore. The Delta 425 on 4½-in. drillpipe was used in the GoM, South Texas and the Bakken Shale. Field service staff went to the rig site and saw the same pattern repeated: ease of use, low damage rates and satisfied end users. Drilling crews were at ease with the product and rapidly embraced its use. In addition, a string has been deployed to the Middle East for testing.

In all cases, the condition of the connection was visually evaluated after use, and so far none have required rethreading. This is extremely encouraging to the early users, and NOV looks forward to gathering more data once these strings have received a full visual and dimensional inspection of the Delta connections.

Read More → The Connection in Oil Gas Drilling with new Technology

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.

Read More → Expandable Liners Technology in Oil Gas Drilling

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.

Read More → Rig Automation Maximizes Value For Contractors And Operators

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

Read More → Digitalization Directional Drilling

Solids Control Innovations To North American Shale Fields

While the last year has seen a ramping up of onshore drilling in shale fields across North America, it’s clear that “caution” still remains the watchword when it comes to drilling and production budgets.

Anadarko, ConocoPhillips and Hess already have announced reductions in 2017 E&P budgets, and in the words of Anadarko CEO R.A. Walker, “We sincerely believe the volatility of the current operating market requires financial discipline.”

Such volatility and the focus from shale operators and drilling contractors on financial discipline, reduced costs and increased efficiencies is shining the spotlight on a key sector of the drilling market—solids control.

Drilling fluids play a crucial role in drilling activity in shale fields, cooling and lubricating drillbits, carrying drill cuttings to the surface, controlling pressure at the bottom of the well and ensuring that the formation retains the properties defined for that well.

The effectiveness of such fluids is highly dependent on solids control and the ability to separate the mud from rock particles and low-gravity solids so that clean mud is recycled and circulated back into the drilling system. If there are too many solids in the mud, ROP is reduced, and torque, drag and abrasion are increased as well as potential lost circulation and production.

The more capable the drilling rigs and the better the solids control technologies, the greater the drilling efficiencies and levels of potential production.

Current technology limitations

Shale shakers separate drill cuttings by passing the muds through a shale screen with separation achieved by vibrations and high G-forces. But there are limitations to these devices.

First, there is the capex and opex required for the shale shakers—not a one-off cost but a drag on finances throughout operations due to the need for the shale screens to be continually replaced.

There also is more onsite equipment, personnel, and greater costs and HSE risk.

Also, there are the inefficiencies of the shale shaker-based process itself.

The drilled solids are often broken down into fine particles that are difficult to remove, leading to an increase in solids in the drilling fluid, a decline in drilling fluid efficiency and a negative impact on penetration rates and equivalent circulating density.

Another downside of vibrating-type shale shakers is higher volumes of mud being lost and more drilling waste generated. One industry guru working for a major operator once said that 15% of all the mud used per well is lost in some form or another via the shakers.

Viable alternative

It’s with these issues in mind that Cubility’s filter beltbased MudCube technology is proving an effective alternative to shale shakers in shale fields.

The MudCube is an enclosed vacuum-based system that eliminates the traditional process of shaking fl uid and solids. Instead, drilling fl uids are vacuumed through a rotating filter belt that uses high airfl ow to separate the cuttings from the fl uid.

The cleaned drilling fl uids are then returned to the active mud system, and the drilled solids are carried forward on the filter belt for disposal. As opposed to shakers, the MudCube processes 100% of the mud, immediately increasing performance.

The system also eliminates the need for multiple shaker panels, with the solids removal efficiency also ensuring that as much as 80% more mud is recovered than competing technologies, which is a huge benefit when multiplied by several onshore rigs.

The improved separation capabilities of the MudCube also lead to better quality drilling fluid, more drilling fluid recycled back to the mud tanks to be reused for drilling, less waste and improved drilling efficiencies with stable drilling fl uid properties and a decrease in nonproductive time.

There are also the financial benefits of avoiding screen replacements on a regular basis—filter belts need replacing but not at such fast rates.

In addition, the MudCube is a much more compact alternative to shale shakers. A typical three-deck shaker weighs about 3 metric tons compared to 1 ton for the MudCube.

Deployments across North America

The MudCube’s easy installation on drilling pads is ensuring that it can impact the bottom line almost immediately.

In 2016 Cubility partnered with EQT Corp., and the MudCubes were successfully deployed to an onshore fl uid rig that was drilling Marcellus wells in western Pennsylvania. Cuttings were easily lifted out of the wellbore, leading to immediately improved solids control and waste disposal.

The MudCube also has been successfully deployed for Murphy Oil in Canada, and the company is evaluating the service for possible use in the Eagle Ford Shale as well.

New Tech Solids Inc. and the MudCube delivered dry cuttings with Murphy Oil in Canada. (Source: Cubility)

Mending the broken value chain

Cubility also is looking to contractor partnerships and offering the MudCube as a rentable system to enable contractors to embrace the latest solids control innovations and address the broken value chain where operators drive down day rates, leaving contractors with little scope for new equipment.

To this end Cubility is partnering with Houston-based Stage 3 Separation in providing a modular, easy and inexpensive installation and operation of MudCube, a system specifically designed for onshore shale operations and that can be up and running in a matter of days as an integrated part of the rig design.

It’s through exclusive distribution partnerships such as this and also with Canadian-based New Tech Solids Inc. (a recent deployment is taking place with Shell via New Tech Solids) that the next few years is likely to see more and more MudCubes deployed across North American shale fields through these service providers.

In today’s tight but ultrafast land drilling market, any solids control solution must provide immediate “wins” in terms of reduced costs and increased efficiencies. Vacuum and filter belt-based enclosed solid control systems are achieving this. 

Read More → Solids Control Innovations To North American Shale Fields