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  • Member Since: December 21, 2014

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MWD Kit For Sale

Here at MWD Rentals & Sales we have multiple clients that span the globe. Clients who are selling MWD and Directional equipment. Clients that are […]

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Geolink SEA2

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(7) Geolink (SEA) Survey Electronics Assembly FOR SALE

On behalf of our Client, MWD Rentals & Sales is offering (7) Geolink Survey Electronics Assemblies for individual sale. Contact us for a quote on […]

1241 total views, 0 today

Geolink Negative Pulse Transmitter

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(3) – Geolink Negative Pulse Transmitters! FOR SALE!

MWD Rentals & Sales is selling, on behalf of our client, (3) Geolink Negative Pulse Transmitters.  These transmitters are in fantastic condition. They were some […]

1075 total views, 0 today

KeyDrill KDU

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KeyDrill (KDU) Surface Decoding Units FOR SALE

KeyDrill (KDU) Surface Decoding Units FOR SALE My Client has 14 sparingly used KeyDrill (KDU) Surface Decoding Units for immediate sale. Here is the description from […]

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Applied Physics 851

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Applied Physics MWD 850 Directional Unit/ 851 Gamma Combo Units FOR IMMEDIA...

Applied Physics MWD 850 Directional Unit/ 851 Gamma Combo Units FOR IMMEDIATE SALE MWD Rentals & Sales (www.mwdrentals.ca) is selling (11) Applied Physics 850/851 Directional […]

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2014-09-02 08.58.51

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Orienteer Pressure Housings

New Manufactured Negative Pulse Pressure Housings For Sale Download our order form on the “Orienteer Wear Parts” page. Direct inquiries to sales@mwdrentals.ca

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clamp bolt

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Negative Pulse Clamp Bolts

– 4.75″ Clamp Bolt – 6.25 – 7.25″ Clamp Bolt – 8″-9.5″ Clamp Bolt Shipping Exworks Calgary

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IMG_0289

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Half Shells – Set of Two

– Negative Pulse OR1 Half Shells (Alloy, Nitronic 50) Buyer pays for shipping. EXWORKS Calgary, Ab, Canada *photo is a half shell OR2 size, byrillium […]

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A new listing site to check out!

MWDRS BLOG October 2, 2017

We here at MWD Rentals & Sales are always looking for new, innovative ways to advertise what we have for sale.

We recently found a great site to list our inventory for free.

Check out www.oilpatchhub.com if you are looking to sell your new or used oil & gas equipment, products or services.

You can also list all your oil field jobs for free.

It doesn’t end there, you can also list your company details in the business directory section of OilPatchHub.

It’s totally FREE. How cool is that?

You shouldn’t have to pay to advertise on the internet.

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Need Directional Drilling expertise in Western Canada? Fox River Tools is the answer.

MWDRS BLOG April 18, 2017

Need Directional Drilling expertise in Western Canada? Fox River Tools is the answer.

Fox River Tools is a privately owned Canadian based directional and horizontal drilling company currently operating in the Western Canadian Sedimentary Basin and pursuing beyond.

Fox River Tools is built on a strong foundation and it is reflected in their service. As a leader, our goal is to continually pursue the highest quality directional drilling services throughout the industry by focusing and increasing our performance safely and maintaining exceptional customer service. We do this with the combination of our experienced, professional staff and our latest technological equipment.

​     By maintaining strong relationships with industry leaders and vendors, Fox River Tools is continually pursuing, acquiring, implementing and maintaining the latest, innovative, premium quality and reliable directional drilling service tools available in the drilling industry. Because of this, we can introduce products in a safe and timely manor as well as adapt and adjust accordingly to the ever-changing needs of our clients.

Fox River Tools is an industry leader and constantly striving to improve our industry’s optimum performance across the country with our proven professional, efficient, and safe approach to business. Our experienced optimization engineer, well planner and directional drilling teams all conform to these leading standards. Our diverse range of directional drilling expertise is paramount to the success of all our projects. Our customized approach to every client allows us to design thoughtful, efficient and safe wells. We do everything possible to ensure that we deliver the best service and products in the industry at competitive rates.

Check them out right now.

http://www.foxrivertools.ca/

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What are your MWD Tools Worth?

MWDRS BLOG December 28, 2014

“Well, what do you think you can get me for it?

This is usually the first question that I get asked when someone calls me up and is inquiring about selling their MWD or DD equipment. Rightfully so, this should be the first question that is asked.  Who wouldn’t want to know what their equipment is worth if they wanted to sell it?

Just like anything, whether its a car, house, bicycle, etc, there are a lot of factors to take into consideration when selling your gear and the price you want to place on it…but there is one factor that I have found that gives you a good starting point.

In my experience, it doesn’t seem to matter how old your gear is, your starting price point is half the price of buying it new. It’s a tough pill to swallow but I have sold lots and lots of kits and down hole modules and surface gear, etc, over the years, and I have never once had a selling price over half the price of the new price. It seems that if the price is anything over that point a buyer will go with new and get the little bit of warranty that comes with it.

So, if you bought a MWD kit for $500K, start with 250K, and then add in all these other factors:

1) How quickly do you want to sell? If you are looking for a quick sale, lower the price.

2) Do you have all the service records? Are the  firmware versions (if any) up to date?  For MWD tools this is vitally important.

3) Are you looking to negotiate on price or is your price the rock bottom price you will take.

 

My suggestion is always this,  “Price your assets to sell quickly.”

Especially MWD tools. When it comes down to it, MWD tools fall into the technology category. Think about that TV you bought 5 years ago and what you paid for it. What’s it worth today? Price your assets for a quick sale and put that cash into new assets. Most likely, the assets you’re selling have made you a lot of money, and if they are now sitting they are not making you anything, so get what you can for them and put the cash into new assets that will make you money.

If you would like to sell your MWD tools, Mud Motors, etc, contact MWD Rentals & Sales and we will help you out the best we can.

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What info does a MWD tool provide?

MWDRS BLOG December 21, 2014

Directional information

MWD tools are generally capable of taking directional surveys in real time. The tool uses accelerometers and magnetometers to measure the inclination and azimuth of the wellbore at that location, and they then transmit that information to the surface. With a series of surveys; measurements of inclination, azimuth, and tool face, at appropriate intervals (anywhere from every 30 ft (i.e., 10m) to every 500 ft), the location of the wellbore can be calculated.

By itself, this information allows operators to prove that their well does not cross into areas that they are not authorized to drill. However, due to the cost of MWD systems, they are not generally used on wells intended to be vertical. Instead, the wells are surveyed after drilling through the use of multi-shot surveying tools lowered into the drillstring on slickline or wireline.

The primary use of real-time surveys is in directional drilling. For the directional driller to steer the well towards a target zone, he must know where the well is going, and what the effects of his steering efforts are.

MWD tools also generally provide toolface measurements to aid in directional drilling using downhole mud motors with bent subs or bent housings. For more information on the use of toolface measurements, see Directional drilling.

Drilling mechanics information

MWD tools can also provide information about the conditions at the drill bit. This may include:

  • Rotational speed of the drillstring
  • Smoothness of that rotation
  • Type and severity of any vibration downhole
  • Downhole temperature
  • Torque and weight on bit, measured near the drill bit
  • Mud flow volume

Mud Motor and MWD

Use of this information can allow the operator to drill the well more efficiently, and to ensure that the MWD tool and any other downhole tools, such as a mud motor, rotary steerable systems, and LWD tools, are operated within their technical specifications to prevent tool failure. This information is also valuable to Geologists responsible for the well information about the formation which is being drilled.

Formation properties

Many MWD tools, either on their own, or in conjunction with separate LWD tools, can take measurements of formation properties. At the surface, these measurements are assembled into a log, similar to one obtained by wireline logging.

LWD tools are able to measure a suite of geological characteristics including density, porosity, resistivity, acoustic-caliper, inclination at the drill bit (NBI), magnetic resonance and formation pressure.

The MWD tool allows these measurements to be taken and evaluated while the well is being drilled. This makes it possible to perform geosteering, or directional drilling based on measured formation properties, rather than simply drilling into a preset target.

Most MWD tools contain an internal gamma ray sensor to measure natural gamma ray values. This is because these sensors are compact, inexpensive, reliable, and can take measurements through unmodified drill collars. Other measurements often require separate LWD tools, which communicate with the MWD tools downhole through internal wires.

Measurement while drilling can be cost-effective in exploration wells, particularly in areas of the Gulf of Mexico where wells are drilled in areas of salt diapirs. The resistivity log will detect penetration into salt, and early detection prevents salt damage to bentonite drilling mud.

Data transmission methods

Mud-pulse telemetry

This is the most common method of data transmission used by MWD tools. Downhole, a valve is operated to restrict the flow of the drilling mud (slurry) according to the digital information to be transmitted. This creates pressure fluctuations representing the information. The pressure fluctuations propagate within the drilling fluid towards the surface where they are received from pressure sensors. On the surface, the received pressure signals are processed by computers to reconstruct the information. The technology is available in three varieties: positive pulse, negative pulse, and/;,.,/ continuous wave.

Positive pulse
Positive-pulse tools briefly close and open the valve to restrict the mud flow within the drill pipe. This produces an increase in pressure that can be seen at surface. Line codes are used to represent the digital information in form of pulses.

Diagram showing the MWD

Negative pulse
Negative pulse tools briefly open and close the valve to release mud from inside the drillpipe out to the annulus. This produces a decrease in pressure that can be seen at surface. Line codes are used to represent the digital information in form of pulses.
Continuous wave (by wawan)
Continuous wave tools gradually close and open the valve to generate sinusoidal pressure fluctuations within the drilling fluid. Any digital modulation scheme with a continuous phase can be used to impose the information on a carrier signal. The most widely used modulation scheme is continuous phase modulation.

When underbalanced drilling is used, mud pulse telemetry can become unusable. This is usually because, in order to reduce the equivalent density of the drilling mud, a compressible gas is injected into the mud. This causes high signal attenuation which drastically reduces the ability of the mud to transmit pulsed data. In this case, it is necessary to use methods different from mud pulse telemetry, such as electromagnetic waves propagating through the formation or wired drill pipe telemetry.

Current mud-pulse telemetry technology offers a bandwidths of up to 40 bit/s.[1] The data rate drops with increasing length of the wellbore and is typically as low as 1.5 bit/s[2] – 3.0 bit/s.[1] (bits per second) at a depth of 35,000 ft – 40,000 ft (10668 m – 12192 m).

Surface to down hole communication is typically done via changes to drilling parameters, i.e., change of the rotation speed of the drill string or change of the mud flow rate. Making changes to the drilling parameters in order to send information can require interruption of the drilling process, which is unfavorable due to the fact that it causes non-productive time.

Electromagnetic telemetry (EM tool)

These tools incorporate an electrical insulator in the drillstring. To transmit data, the tool generates an altered voltage difference between the top part (the main drillstring, above the insulator), and the bottom part (the drill bit, and other tools located below the insulator of the MWD tool). On surface, a wire is attached to the wellhead, which makes contact with the drillpipe at the surface. A second wire is attached to a rod driven into the ground some distance away. The wellhead and the ground rod form the two electrodes of a dipole antenna. The voltage difference between the two electrodes is the receive signal that is decoded by a computer.

The EM tool generates voltage differences between the drillstring sections in the pattern of very low frequency (2–12 Hz) waves. The data is imposed on the waves through digital modulation.

This system generally offers data rates of up to 10 bits per second. In addition, many of these tools are also capable of receiving data from the surface in the same way, while mud-pulse-based tools rely on changes in the drilling parameters, such as rotation speed of the drillstring or the mud flow rate, to send information from the surface to downhole tools. Making changes to the drilling parameters in order to send information to the tools generally interrupts the drilling process, causing lost time.

Compared to mud-pulse telemetry, electronic pulse telemetry is more effective in certain specialized situations, such as underbalanced drilling or when using air as drilling fluid. However, it generally falls short when drilling exceptionally deep wells, and the signal can lose strength rapidly in certain types of formations, becoming undetectable at only a few thousand feet of depth.

Wired drill pipe

Several oilfield service companies are currently developing wired drill pipe systems. These systems use electrical wires built into every component of the drillstring, which carry electrical signals directly to the surface. These systems promise data transmission rates orders of magnitude greater than anything possible with mud-pulse or electromagnetic telemetry, both from the downhole tool to the surface and from the surface to the downhole tool. The IntelliServ[3] wired pipe network, offering data rates upwards of 1 megabit per second, became commercial in 2006. Representatives from BP America, StatoilHydro, Baker Hughes INTEQ, and Schlumberger presented three success stories using this system, both onshore and offshore, at the March 2008 SPE/IADC Drilling Conference in Orlando, Florida.[4]

Retrievable tools

MWD tools may be semi-permanently mounted in a drill collar (only removable at servicing facilities), or they may be self-contained and wireline retrievable.

Retrievable tools, sometimes known as Slim Tools, can be retrieved and replaced using wireline through the drill string. This generally allows the tool to be replaced much faster in case of failure, and it allows the tool to be recovered if the drillstring becomes stuck. Retrievable tools must be much smaller, usually about 2 inches or less in diameter, though their length may be 20 ft (6.1 m) or more. The small size is necessary for the tool to fit through the drillstring; however, it also limits the tool’s capabilities. For example, slim tools are not capable of sending data at the same rates as collar-mounted tools, and they are also more limited in their ability to communicate with, and supply electrical power to, other LWD tools.

Collar-mounted tools, also known as fat tools, cannot generally be removed from their drill collar at the wellsite. If the tool fails, the entire drillstring must be pulled out of the hole to replace it. However, without the need to fit through the drillstring, the tool can be larger and more capable.

The ability to retrieve the tool via wireline is often useful. For example, if the drillstring becomes stuck in the hole, then retrieving the tool via wireline will save a substantial amount of money compared to leaving it in the hole with the stuck portion of the drillstring. However, there are some limitations on the process.

Limitations

Retrieving a tool using wireline is not necessarily faster than pulling the tool out of the hole. For example, if the tool fails at 1,500 ft (460 m) while drilling with a triple rig (able to trip 3 joints of pipe, or about 90 ft (30 m) feet, at a time), then it would generally be faster to pull the tool out of the hole than it would be to rig up wireline and retrieve the tool, especially if the wireline unit must be transported to the rig.

Wireline retrievals also introduce additional risk. If the tool becomes detached from the wireline, then it will fall back down the drillstring. This will generally cause severe damage to the tool and the drillstring components in which it seats, and will require the drillstring to be pulled out of the hole to replace the failed components; this results in a greater total cost than pulling out of the hole in the first place. The wireline gear might also fail to latch onto the tool, or, in the case of a severe failure, might bring only a portion of the tool to the surface. This would require the drillstring to be pulled out of the hole to replace the failed components, thus making the wireline operation a waste of time.

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What is Measurement While Drilling?

MWDRS BLOG December 21, 2014

Measurement While Drilling (MWD), also known as Logging While Drilling (LWD), is a measurement taken of the wellbore (the hole) inclination from vertical, and also magnetic direction from north. Using basic trigonometry, a three-dimensional plot of the path of the well can be produced.

Essentially, a MWD Operator measures the trajectory of the hole as it is drilled (for example, data updates arrive and are processed every few seconds or faster). This information is then used to drill in a pre-planned direction into the formation which contains the oil, gas, water or condensate. Additional measurements can also be taken of natural gamma ray emissions from the rock; this helps broadly to determine what type of rock formation is being drilled, which in turn helps confirm the real-time location of the wellbore in relation to the presence of different types of known formations (by comparison with existing seismic data).

Density and porosity, rock fluid pressures and other measurements are taken, some using radioactive sources, some using sound, some using electricity, etc.; this can then be used to calculate how freely oil and other fluids can flow through the formation, as well as the volume of hydrocarbons present in the rock and, with other data, the value of the whole reservoir and reservoir reserves.

An MWD downhole tool is also “lined-up” with the bottom hole drilling assembly, enabling the wellbore to be steered in a chosen direction in 3D space known as directional drilling. Directional drillers rely on receiving accurate, quality tested data from the MWD engineer to allow them to keep the well safely on the planned trajectory.

Directional survey measurements are taken by three orthogonally mounted accelerometers to measure inclination, and three orthogonally mounted magnetometers which measure direction (azimuth). Gyroscopic tools may be used to measure Azimuth where the survey is measured in a location with disruptive external magnetic influences, inside “casing”, for example, where the hole is lined with steel tubulars (tubes). These sensors, as well as any additional sensors to measure rock formation density, porosity, pressure or other data, are connected, physically and digitally, to a logic unit which converts the information into binary digits which are then transmitted to surface using “mud pulse telemetry” (MPT, a binary coding transmission system used with fluids, such as, combinatorial, Manchester encoding, split-phase, among others).

This is done by using a downhole “pulser” unit which varies the drilling fluid (mud) pressure inside the drill-string according to the chosen MPT: these pressure fluctuations are decoded and displayed on the surface system computers as wave-forms; voltage outputs from the sensors (raw data); specific measurements of gravity or directions from magnetic north, or in other forms, such as sound waves, nuclear wave-forms, etc.

Surface (mud) pressure transducers measure these pressure fluctuations (pulses) and pass an analogue voltage signal to surface computers which digitize the signal. Disruptive frequencies are filtered out and the signal is decoded back into its original data form. For example, a pressure fluctuation of 20psi (or less) can be “picked out” of a total mud system pressure of 3,500psi or more.

Downhole electrical and mechanical power is provided by downhole turbine systems, which use the energy of the “mud” flow, battery units (lithium), or a combination of both.

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What is Directional Drilling?

MWDRS BLOG December 21, 2014

Directional drilling is the practice for drilling non-vertical wells. It can be broken down into three main groups: oilfield directional drilling, utility installation directional drilling (horizontal directional drilling), directional boring, and surface in seam (SIS), which horizontally intersects a vertical well target to extract coal bed methane.

History

Many prerequisites enabled this suite of technologies to become productive. Probably, the first requirement was the realization that oil wells, or water wells, are not necessarily vertical. This realization was quite slow, and did not really grasp the attention of the oil industry until the late 1920s when there were several lawsuits alleging that wells drilled from a rig on one property had crossed the boundary and were penetrating a reservoir on an adjacent property. Initially, proxy evidence such as production changes in other wells was accepted, but such cases fueled the development of small diameter tools capable of surveying wells during drilling. Horizontal directional drill rigs are developing towards large-scale, micro-miniaturization, mechanical automation, hard stratum working, exceeding length and depth oriented monitored drilling.

Measuring the inclination of a wellbore (its deviation from the vertical) is comparatively simple, requiring only a pendulum. Measuring the azimuth (direction with respect to the geographic grid in which the wellbore was running from the vertical), however, was more difficult. In certain circumstances, magnetic fields could be used, but would be influenced by metalwork used inside wellbores, as well as the metalwork used in drilling equipment. The next advance was in the modification of small gyroscopic compasses by the Sperry Corporation, which was making similar compasses for aeronautical navigation. Sperry did this under contract to Sun Oil (which was involved in a lawsuit as described above), and a spin-off company “Sperry Sun” was formed, which brand continues to this day, absorbed into Halliburton. Three components are measured at any given point in a well bore in order to determine its position: the depth of the point along the course of the borehole (measured depth), the inclination at the point, and the magnetic azimuth at the point. These three components combined are referred to as a “survey”. A series of consecutive surveys are needed to track the progress and location of a well bore.

Prior experience with rotary drilling had established several principles for the configuration of drilling equipment down hole (“Bottom Hole Assembly” or “BHA”) that would be prone to “drilling crooked hole” (i.e., initial accidental deviations from the vertical would be increased). Counter-experience had also given early directional drillers (“DD’s”) principles of BHA design and drilling practice that would help bring a crooked hole nearer the vertical.

In 1934, H. John Eastman & Roman W. Hines of Long Beach, California, became a pioneer in directional drilling when he and George Failing of Enid, Oklahoma, saved the Conroe, Texas, oil field. Failing had recently patented a portable drilling truck. He had started his company in 1931 when he mated a drilling rig to a truck and a power take-off assembly. The innovation allowed rapid drilling of a series of slanted wells. This capacity to quickly drill multiple relief wells and relieve the enormous gas pressure was critical to extinguishing the Conroe fire. In a May, 1934, Popular Science Monthly article, it was stated that “Only a handful of men in the world have the strange power to make a bit, rotating a mile below ground at the end of a steel drill pipe, snake its way in a curve or around a dog-leg angle, to reach a desired objective.” Eastman Whipstock, Inc., would become the world’s largest directional company in 1973.

Combined, these survey tools and BHA designs made directional drilling possible, but it was perceived as arcane. The next major advance was in the 1970s, when downhole drilling motors (aka mud motors, driven by the hydraulic power of drilling mud circulated down the drill string) became common. These allowed the drill bit to continue rotating at the cutting face at bottom of the hole, while most of the drill pipe was held stationary. A piece of bent pipe (a “bent sub”) between the stationary drill pipe and the top of the motor allowed the direction of the wellbore to be changed without needing to pull all the drill pipe out and place another whipstock. Coupled with the development of measurement while drilling tools (using mud pulse telemetry, networked or wired pipe or EM telemetry, which allows tools down hole to send directional data back to the surface without disturbing drilling operations), directional drilling became easier.

Certain profiles cannot be drilled while the drill pipe is rotating. Drilling directionally with a downhole motor requires occasionally stopping rotation of the drill pipe and “sliding” the pipe through the channel as the motor cuts a curved path. “Sliding” can be difficult in some formations, and it is almost always slower and therefore more expensive than drilling while the pipe is rotating, so the ability to steer the bit while the drill pipe is rotating is desirable. Several companies have developed tools which allow directional control while rotating. These tools are referred to as rotary steerable systems (RSS). RSS technology has made access and directional control possible in previously inaccessible or uncontrollable formations.

Directiona Drilling image

Benefits

Wells are drilled directionally for several purposes:

  • Increasing the exposed section length through the reservoir by drilling through the reservoir at an angle
  • Drilling into the reservoir where vertical access is difficult or not possible. For instance an oilfield under a town, under a lake, or underneath a difficult-to-drill formation
  • Allowing more wellheads to be grouped together on one surface location can allow fewer rig moves, less surface area disturbance, and make it easier and cheaper to complete and produce the wells. For instance, on an oil platform or jacket offshore, 40 or more wells can be grouped together. The wells will fan out from the platform into the reservoir(s) below. This concept is being applied to land wells, allowing multiple subsurface locations to be reached from one pad, reducing costs.
  • Drilling along the underside of a reservoir-constraining fault allows multiple productive sands to be completed at the highest stratigraphic points.
  • Drilling a “relief well” to relieve the pressure of a well producing without restraint (a “blowout“). In this scenario, another well could be drilled starting at a safe distance away from the blowout, but intersecting the troubled wellbore. Then, heavy fluid (kill fluid) is pumped into the relief well bore to suppress the high pressure in the original wellbore causing the blowout.

Most directional drillers are given a blue well path to follow that is predetermined by engineers and geologists before the drilling commences. When the directional driller starts the drilling process, periodic surveys are taken with a downhole instrument to provide survey data (inclination and azimuth) of the well bore. These pictures are typically taken at intervals between 10–150 meters (30–500 feet), with 30 meters (90 feet) common during active changes of angle or direction, and distances of 60–100 meters (200–300 feet) being typical while “drilling ahead” (not making active changes to angle and direction). During critical angle and direction changes, especially while using a downhole motor, an MWD (Measurement while drilling) tool will be added to the drill string to provide continuously updated measurements that may be used for (near) real-time adjustments.

These data indicate if the well is following the planned path and whether the orientation of the drilling assembly is causing the well to deviate as planned. Corrections are regularly made by techniques as simple as adjusting rotation speed or the drill string weight (weight on bottom) and stiffness, as well as more complicated and time consuming methods, such as introducing a downhole motor. Such pictures, or surveys, are plotted and maintained as an engineering and legal record describing the path of the well bore. The survey pictures taken while drilling are typically confirmed by a later survey in full of the borehole, typically using a “multi-shot camera” device.

The multi-shot camera advances the film at time intervals so that by dropping the camera instrument in a sealed tubular housing inside the drilling string (down to just above the drilling bit) and then withdrawing the drill string at time intervals, the well may be fully surveyed at regular depth intervals (approximately every 30 meters (90 feet) being common, the typical length of 2 or 3 joints of drill pipe, known as a stand, since most drilling rigs “stand back” the pipe withdrawn from the hole at such increments, known as “stands”).

Drilling to targets far laterally from the surface location requires careful planning and design. The current record holders manage wells over 10 km (6.2 mi) away from the surface location at a true vertical depth (TVD) of only 1,600–2,600 m (5,200–8,500 ft).

This form of drilling can also reduce the environmental cost and scarring of the landscape. Previously, long lengths of landscape where required to be removed from the surface which is no longer required with this form of drilling.

Disadvantages

Until the arrival of modern downhole motors and better tools to measure inclination and azimuth of the hole, directional drilling and horizontal drilling was much slower than vertical drilling due to the need to stop regularly and take time-consuming surveys, and due to slower progress in drilling itself (lower rate of penetration). These disadvantages have shrunk over time as downhole motors became more efficient and semi-continuous surveying became possible.

What remains is a difference in operating costs: for wells with an inclination of less than 40 degrees, tools to carry out adjustments or repair work can be lowered by gravity on cable into the hole. For higher inclinations, more expensive equipment has to be mobilized to push tools down the hole.

Another disadvantage of wells with a high inclination was that prevention of sand influx into the well was less reliable and needed higher effort. Again, this disadvantage has diminished such that, provided sand control is adequately planned, it is possible to carry it out reliably.

Stealing oil

In 1990, Iraq accused Kuwait of stealing Iraq’s oil through slant drilling.[5] The United Nations redrew the border after the 1991 Gulf war that ended the seven-month Iraqi occupation of Kuwait. As part of the reconstruction, 11 new oil wells were placed among the existing 600. Some farms and an old naval base that used to be in the Iraqi side, became part of Kuwait.[6]

In the mid-twentieth century, a slant-drilling scandal occurred in the huge East Texas Oil Field.

New technologies

Between 1985 and 1993, NCEL (now the NFESC) of Pt Hueneme, California developed controllable horizontal drilling technologies. These technologies are capable of reaching 10 000–15 000 ft (3000–4500 m) and may reach 25 000 ft (7500 m) when used under favorable conditions.

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MWD Rentals & Sales Announces the ability for Users to Buy and Sell their own equipment!

MWDRS BLOG December 21, 2014

MWD Rentals & Sales is proud to announce that customers can now list their own equipment for sale on the World’s leading online MWD/LWD DD equipment brokerage, MWDRentals.ca.

Don’t worry! Brokerage services are still available!!!! Call +1(306) 209-2252 for more information on that service.

Take advantage of the world’s most popular destination for used directional drilling equipment.

“When you have Cash, You have options!”

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