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
transported lower cost and can be run or replaced on slick
line when needed
Disadvantages: limited sensors (i.e. usually no resistivity,
caliper, etc.).
caliper, etc.).
Non-retrievable
Advantages: typically multi-sensor.
Disadvantages: high “lost-in-hole” charges and must trip to
change.
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
– 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
§ 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