Introduction

Directional drilling has been an integral part of the oil and gas industry since the 1920s. While the technology has improved over the years, the concept of directional drilling remains the same: drilling wells at multiple angles, not just vertically, to better reach and produce oil and gas reserves. Additionally, directional drilling allows for multiple wells from the same vertical well bore, minimizing the wells' environmental impact. Improvements in drilling sensors and global positioning technology have helped to make vast improvements in directional drilling technology. Today, the drill bit is controlled with intense accuracy through real-time technologies, providing the industry with multiple solutions to drilling challenges, increasing efficiency and decreasing costs.

Tools utilized in achieving directional drills include whipstock, bottom hole assembly (BHA) configurations, three-dimensional measuring devices, mud motors and specialized drill bits.

Now, from a single location, various wells can be drilled at myriad angles, tapping reserves miles away and more than a mile below the surface Many times, a non-vertical well is drilled by simply pointing the drill in the direction it needs to drill. A more complex way of directional drilling utilizes a bend near the bit, as well as a down hole steerable mud motor. In this case, the bend directs the bit in a different direction from the well bore axis when the entire drill string is not rotating, which is achieved by pumping drilling fluid through the mud motor which in turn rotates the Bit. Then, once the planned angle is achieved, the complete drill string is rotated, including the bent motor, ensuring the drill bit does not drill in a different direction from the planned curve.

One type of directional drilling, horizontal drilling, is used to drastically increase production. Here, a horizontal well is drilled across an oil and gas formation, increasing production by as much as 20 times more than that of its vertical counterpart. Horizontal drilling is any wellbore that exceeds 80 degrees, and it can even include more than a 90-degree angle (drilling upward).

Directional Drilling Well

Directional Drilling – 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.

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 is running from the vertical), however, was more difficult. In certain circumstances, magnetic fields could be used, but could 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 wellbore 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 wellbore. Many of the earliest innovations such as photographic single shot technology and crow's feet baffle plates for landing survey tools were developed by Robert Richardson, an independent directional driller who first drilled in the 1940s and was still working in 2012.

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 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. (E&P, "Making a hole was hard work," Kris Wells, American Oil & Gas Historical Society Contributing Editor, 1 Nov. 2006 and "Technology and the Conroe Crater"). 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 Whip stock, 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 down hole drilling motors (aka mud motors, driven by the hydraulic power of drilling mud circulated down the drill string) became common. These allowed the bit to be rotated on the 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 whip stock. 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 could not be drilled without the drill string rotating at all times. Drilling directionally with a motor requires occasionally "sliding" the drill pipe, which means stopping the pipe rotation and pushing the pipe in the hole as the motor cuts a curved section of hole in the desired direction. "Sliding" can be difficult in some formations, and it is almost always slower and therefore more expensive than drilling while rotating and also hole cleaning during sliding is poorer, so the ability to control wellbore direction while rotating is desirable. Several companies have developed tools which allow directional control while rotating. These tools are referred to as Rotary Steerable systems, or RSS. RSS technology has allowed access to and/or directional control in previously inaccessible or uncontrollable formations. Robert Zilles pioneered many of the RSS drilling procedures for Baker Hughes Inteq and is considered the Grandfather of RSS technology. In 2010 he became the first BHI directional driller to drill a well in each of the last 7 decades.

Advantages of Directional drilling

There are many purposes and advantages of directional drilling which includes.

1.   Increasing the area of contact with the reservoir by drilling at an angle

2.   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

3.   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.

4.   Drilling along the underside of a reservoir-constraining fault allows multiple productive sands to be completed at the highest stratigraphic points.

5.   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 wellbore to suppress the high pressure in the original wellbore causing the blowout. 

Disadvantages of directional drilling

1.   It meant that more footage than necessary had to be drilled in order to reach the producing zone. Deviated drill therefore take more time to be drilled and more expensive than a straight vertical well.

2.   The TVD of the producing zone can’t be determined accurately in a deviated wellbore, and so it makes planning of future well more difficult and increase the level of uncertainty in the well.

3.   Deviated well increase the wear of the drilling string and bottom-hole assembly (BHA), making failure more likely to happen, the deviated well also make any subsequent fishing job difficult.

Until the arrival of modern down hole 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 down hole 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.

Applications of directional drilling

For the oil and gas industry there are many applications for directional drilling which includes the followings:-

a)   Sidetracking

b)  Drilling to avoid geological problems

A.  Fault formation

B.   Salt dome formations

c)    Controlling vertical well

d)  Inaccessible locations

e)   Multiple wells from single location

f)     Relief well drilling

g)   Multilateral well

Extended reach (ERD) wells

Extended reach (ERD) wells are defined as wells that have a horizontal departure (HD) at least twice the true vertical depth (TVD) of the well. ERD wells are kicked off from vertical near the surface and built to an inclination angle that allows sufficient horizontal displacement from the surface to the desired target. This inclination is held constant until the wellbore reaches the zone of interest and is then kicked off to near horizontal and extended into reservoir. This technology enables optimization of field development through the reduction of drilling sites and structures, and allows the operator to reach portions of the reservoir at a much greater distance than possible with a conventionally drilled directional well. These efficiencies increase profit margins on viable projects and can make the difference whether or not the project is financially viable. It is well known that ERD introduces factors that can compromise well delivery, and the first challenge prior to drilling an ERD well is to identify and minimize risk.

Technologies that have been found to be critical to the success of ERD are torque and drag, drillstring design, wellbore stability, hole cleaning, casing design, directional drilling optimization, drilling dynamics and rig sizing.  Other technologies of vital importance are the use of rotary steerable systems (RSS) together with measurement while drilling (MWD) and logging while drilling (LWD) to geosteer the well into the geological target. Many of the wells drilled at Wytch Farm would not have been possible to drill without RSS, because steering beyond 8,500 m was not possible as axial drags were too high to allow the orientated steerable motor and bit to slide.

Drilling ERD wells in deep waters is the next step, even though there are some experiences offshore, they are related to wells drilled on shallow waters from fixed platforms. In Brazil, where the major oil fields are located in deep waters, ERD wells might be, in some cases, the only economically viable solution

Sidetracking

When we drill for oil and gas in different formation structures, the drilling string and the down-hole assembly (BHA) equipment goes through a differential pressure down the hole which can cause it stuck or fail. No further progress in the same well bore can be made in the same well if the fish can’t be removed from the well bore. Drilling a new well is not an option at all.

A cement plug is placed on top of the fish and allow it to set firmly. This forms a good foundations for which the new section of the can be kicked off. Now we can start drilling a new direction well from the kick off point on top of the fish. As in the figure (1).

Sidetracking

 RELIEF WELL DRILLING   

   The objective of a directional relief well is to intercept the bore hole of a well which is blowing out and allow a tap into it to be able to kill the blowing well. The bore hole causing the problem is the size of the target. To locate and intercept the blowing well at a certain depth, a carefully planned directional well must be drilled with great precision

RELIEF WELL

DRILLING TO AVOID GEOLOGICAL PROBLEMS

Drilling for petroleum is not always a clear path with no geological problems. Petroleum reservoirs are sometimes associated with salt dome and faults structures. A salt dome may be directly on the above the oil reservoir, so it no possible to drill a vertical well through the salt dome formation. Drilling through it will introduce many problems such as large washout, lost circulations and corrosion. Now in this situation we can avoid drilling a vertical well and drill a directional well as show in the figure (2).

Considering an oil reservoir under a fault formation, drilling a vertical well will also introduce many problems as drilling through salt dome. In that case we have to drill a directional well to avoid the fault as in the figure (2)

Directional Drilling (Salt Dome and Fault)

CONTROLLING STRAIGHT WELLS

When we drill for oil and gas there are different problems that risers like the vertical well drifting and straying across lease boundaries and move away from the target, for that directional drilling techniques have to be used. Small deviations from the planned course can be corrected by altering certain drilling parameters or changing the bottom hole-assembly (BHA). More serious deviation may require the use of a down-hole motor and bent sub to make a correction run or drill a sidetrack.

 INACCESSIBLE LOCATIONS

Petroleum reservoir are often located directly beneath natural or man-made obstructions. Which can’t be destroyed for various reasons which can also be economical or environmental. In this case it may be possible to used directional drilling methods. As shown in the figure blow.

When a blowout destroys or damages the rig in such a way that capping operations are impossible, relief wells are drilled to bring the blowout safely under control. Improved directional drilling techniques have enabled relief wells or reach target less than 10 ft from the blowout. Often two relief wells are drilled simultaneously from different surface locations to ensure that the blowout is killed.

   

 MULTIPLE WELLS FROM SINGLE LOCATION

In oil and gas industry the wells are designed and drilled based on some budgets from the operating company. Directional drilling changed the oil and gas industry be enabling drilling multiple wells from a single platform which is more economical, as we don’t have to build a platform for every discovered reservoir. We can drill multiple wells from a single location and produce from different reservoirs from a single platform as in the figure blow.

 

NON-PETROLEUM APPLICATIONS

Mining Industry

The drilling of small-diameter boreholes in rock to measure thickness of the strata and to obtain core samples is well established. Indeed, some of the techniques used in the oil industry were adopted from earlier techniques used in mining (e.g. borehole surveying to measure inclination and direction). Directional wells are used to produce methane gas that is contained in coal seams. The methane presents a safety hazard and must be drained off before mining operations can begin. In deep coal seams that are beyond the reach of conventional mining techniques, directional wells have been drilled for in situ gasification projects.

CBM Directional Drilling

Construction Industry

 An unusual application of directional drilling is the installation of pipelines beneath river bed. A small-diameter pilot hole is drilled in a smooth are beneath the river until it emerges on the other side. This acts as a guide for the larger- diameter pipe that forms the conduit. The pilot hole is drilled using a down-hole motor and bent sub.

Construction of tunnel

Geothermal Energy

In certain areas of the world the high geothermal gradient found in some rocks can be harnessed to provide energy. The source rock (e.g. granite) is generally impermeable except for vertical fractures. Extracting the heat from this rock requires the drilling of injection and production wells. The wells are directionally drilled to take advantage of the orientation of the fractures. The high temperature and hardness of the rock cause some major drilling problem

  

Jet deflection

Jet deflection is a technique best suited to soft-medium formations in which the compressive strength is relatively low. The hydraulic power of the drilling fluid is used to wash away a pocket of the formation and initiate deflection. A specially modified bit must be used that has one nozzle much larger than the other two. A two-cone bit with a large "eye" may also be used. The bit is run on an assembly which includes an orienting sub and a full-gauge stabilizer near the bit once on bottom, the large nozzle is oriented in the required direction. Maximum circulation rate is used to begin washing without rotating the drill string. The pipe is worked up and down while jetting continues, until a pocket is washed away. At this stage the drill string can be rotated to ream out the pocket and continue building angle as more WOB is applied. Surveys must be taken frequently to ensure the inclination and direction are correct. If it is found that the deflected section of the well is not following the planned trajectory, the large nozzle can be re-oriented and jetting can be repeated.

ASSEMBLY IN JETTING

ü Conventional jet bit with one large nozzle and two blinds

ü Full gauge near bit stabilizer

ü Mule shoe sub (UBHO sub)

ü Non-magnetic drill collar

ü Spiral drill collars

ü Heavy weight drill pipes

Jet Deflection Advantages

ü A full gauge hole can be drilled from the beginning (although a pilot hole may be necessary in some cases).

ü Several attempts can be made to initiate deflection without pulling out of the hole

Jet Deflection disadvantages

ü The technique is limited to soft-medium formations (in very soft rocks too much erosion will cause problems).

ü Severe dog-legs can occur if the jetting is not carefully controlled (if the drilling is fast, surveys must be taken at close intervals).

ü On smaller rigs there may not be enough pump capacity to wash away the formation.

Measurement While Drilling

Measurement While Drilling (MWD) system allows the driller to gather and transmit information from the bottom of the hole back to the surface, without interrupting normal drilling operations. This information can include directional deviation data, data related to the petrophysical properties of the formations and drilling data, such as WOB and torque. The information is gathered and transmitted to surface by the relevant sensors and transmission equipment, which is housed in a non-magnetic drill collar in the bottom hole-assembly (BHA). This tool is known as a Measurement While Drilling Tool (MWD). The data is transmitted through the mud column in the drill-string, to surface. At surface the signal is then decoded and presented to the driller in an appropriate format. The transmission system is known as mud pulse telemetry, and does not involve any wireline operations. Commercial MWD systems were first introduced as a more cost effective method of taking directional surveys. To take a directional survey using conventional wireline methods may take 1-2 hours. Using an MWD system a survey takes less than 4 minutes. Although MWD operations are more expensive than wireline surveying an operating company can save valuable rig time, which is usually more significant in terms of cost. More recently MWD companies have developed more complicated tools which will provide not only directional information and drilling parameters (e.g. torque, WOB), but also geological data (e.g. gamma ray, resistivity logs). The latter tools are generally referred to as Logging While Drilling (LWD) tools. As more sensors are added the transmission system must be improved, therefore MWD tools are becoming much more sophisticated. Great improvements have been made over the past few years, and MWD tools are now becoming a standard tool for drilling operations.

Measurement While Drilling (MWD)

·       All MWD systems have certain basic similarities

    1.            A downhole system which consists of a power source, sensors, transmitter and control system.

    2.            A telemetry channel (mud column) through which pulses are sent to surface.

    3.            A surface system which detects pulses, decodes the signal and presents results (numerical display, geological log, etc.).

The main difference between MWD systems is the method by which the information is transmitted to surface. All encode the data to be transmitted into a binary code, and transmit this data as a series of pressure pulses up the inside of the drill-string. The process of coding and decoding the data will be described below. The only difference between systems is the way in which the pressure pulses are generated.

Features of MWD

MWD can include the following features

ü It provides directional drilling data for example (azimuth, inclination, tool face – magnetic a gravity).

ü It can detect gamma ray in the formation and measure it and give type of formation we are drilling through.

ü It contain thermal and pressure instruments which can measure the annular temperature and annular pressure.

ü Real-time telemetry for logging while drilling (LWD) data.

MWD System

  

TYPES OF MWD :- 

MWD can be classified by retrievability or telemetry method

v Retrievable and non-retrievable

Ø Retrievable

Advantages:  limited “lost-in-hole” charge; light, easily
transported lower cost and can be run or replaced on slick
line when needed

Disadvantages: limited sensors (i.e. usually no resistivity,
caliper, etc.).

Non-retrievable

Advantages: typically multi-sensor.

Disadvantages: high “lost-in-hole” charges and must trip to
change.

Ø Telemetry method (data transmission modes)

ü Mud pulse telemetry

ü Electromagnetic (EM) telemetry

ü Wired drill pipe (direct wire telemetry and induction coupling at tool joints)

MWD Telemetry Methods (or Data Transmission

Methods:

Mud pulse:-

ü Positive, negative or continuous pulse

ü Transmission through mud column 0.5 – 6bps common

Mud Pulse System

Electromagnetic (EM):-

ü Uses a gap sub & UBHO

ü EM transmission through formation and independent of drilling fluid Up to10bps common

Wired drill pipe:-

ü Inductive coupling at tool joint

ü Independent of drilling fluid

ü High data band width – 56 kbps versus 6bps for mud pulse telemetry

Wired drill pipe

Mud pulse telemetry types:

– Positive pulse

– Negative pulse

– Continuous wave pulse

Negative mud pulse telemetry:-

In negative pulse system a valve inside the MWD tool opens and allows a small volume of mud to escape from the drillstring to the annulus. The opening and closing of this valve creates a small drop in standpipe pressure, which can be detected by a transducer on surface.

Positive mud pulse:-

In the positive mud pulse system a valve inside the MWD tool partially closes, creating a temporary increase in standpipe pressure.

Continuous wave pulse:-

In continuous wave pulse system a standing wave is setup in the mud column by a rotating slotted disc. The phase of this continuous wave can be reversed. The data is transmitted as a series of phase shift.

Directional MWD Sensors:

MWD directional sensors use 3 axis accelerometer and 3 axis magnetometer devices.
– The 3-axis accelerometer measures:
– The earth’s gravitational vector relative to the tool axis and a
point along the circumference of the tool called a scribe line.
– Inclination and tool face are determined from this sensor
– The 3-axis magnetometer measures
– The components of the earth’s magnetic field relative to the tool face.
– From this measurement combined with the accelerometer
readings, the azimuth is determined

ADVANTAGES OF MWD:-

§ Use for controlling the direction of the well
§ Can be used to monitor drilling operations
§ Can be used to optimize hydraulics (i.e. hole cleaning).
§ Provides real time (RT) data stream for LWD data

DISADVANTAGES OF MWD:-

§ Cost of a lost tool
§ Difficult to use in thin reservoirs
§ Does not provide formation evaluation data compared with LWD

Created By 

Kon A. Deng Awan

Petroleum Technologist (DPOC)

MBA-Project Management 2021

Petroleum Engineering 2013-17

University of Petroleum & Energy Studies, Dehradun