The oldest method of drilling is to drill a vertical well. In this method,
a wellbore is drilled with as little deviance as possible directly towards
the reservoir; once it penetrates and goes through the reservoir, the well
is stopped and the drill string removed. At this point cement is poured down
the well to prevent hydrocarbons from flowing down the well once it is perforated.
Then the well is perforated, and the pressure in the formation forces the
oil out of the rock and up the pipe.
Directional drilling is a relatively new technology which allows a well to
be drilled along a predetermined path which is not vertical. A directional
well has the added benefits of being able to thread through a horizontal
strata, in order to obtain the most pipe-to-formation surface area. Directional
drilling is useful for a number of reasons, including
•sidetracking •offshore development drilling
•drilling to avoid geological problems •horizontal drilling
•controlling vertical holes •increasing oil pressure due to penetration
•drilling beneath inacessible locations
•drilling to reach oil in reservoirs which would be unreachable by vertical
Directional drilling must be approached carefully. It is not as risky as
it used to be due to special tools to help the well deviate in a controlled
manner and new technology to keep track of the directional of the well once
it has deviated. Often the target of the well is very precise and must not
be missed. There is a possibility of drilling many different wells from the
same well bore, which dramatically decreases pad size and increases possible
production from the well.
Horizontal drilling has the added advantage of being able to thread back
and forth through a horizontal reservoir to increase the formation penetration.
The horizontal technique combined with multilateral wells allow several formations
to be penetrated horizontally at once.
Recommendation: Directional Drilling with other necessary components added
Drill rigs vary dramatically depending on the depth and the type of formation
they are drilling through. Since this information is not offered in the absolute
for the ANWR region, it is only possible to speculate on the best rigs for
the job. Companies being looked at to supply possible rigs include Anadarko
After seismic exploration has taken place, one must go in and drill to to
find the the true dimensions of the well. Directional drilling with coring
is the best way to do this, making a minimum of holes and still determining
the dimensions of the well. This can be drilled from a fairly mobile, lightweight
rig. We are still researching exploration drilling techniques.
Drill Bits break down into categories:
Roller cone bits have one, two or three cones that have teeth sticking out
of them. The cones roll across the bottom of the hole and the teeth press
against the formation with enough pressure to exceed the compressive strength
of the rock. They’re made for rougher drilling conditions and less expensive;
they aren’t ideal for small holes, but they are very sensitive to the porosity
of the rock they are drilling through (drilling faster or slower depending
on the pore pressure) giving the drilling crew a good idea of changes in
pressure in the wellbore. Roller cone bits with steel teeth are called mill
tooth bits; they withstand high drilling stresses while tungsten carbide
bits can drill for long distances without wearing out. Tungsten bits are
more expensive; tungsten carbide insert bits have teeth coated with diamond,
which give them an even longer life.
Fixed cutter bits have no moving parts, and therefore only the cutting surfaces
become dull. Diamond fixed cutter drill bits produce small rock cuttings
called rock flour; they drill through the hardest formations, though slowly,
and are also extremely expensive. These bits are only used in formations
which have high compressive strength or are very abrasive and would destroy
other bits before they made much progress. PDC bits drill with a diamond
disk mounted on a tungsten carbide stud; they have the capability to drill
very fast (100 feet an hour) and are very costly. They can be built with
either steel or molded tungsten carbide bodies (matrix body). These bits
are made in many different shapes and can be made to drill directionally;
the shape also affects how many cutters can be mounted on the bit. Fishtail
bits are of very old design and only suitable for drilling in very soft formations.
The drill bits will need to be replaced as they become dull. The drill will
be equipped with a jet to direct the flow of drilling fluid to clean cuttings
from the bottom of the hole and allow them to rise to the top of the well
bore. There is an optimal speed for the bit, which allows it to clear away
the most rock and still maintain a high RPM).
There are many different types of drill bits to choose from and since the
exact type of strata to be drilled through in ANWR is unknown, it is almost
impossible to select drill bits. Instead, drill bits have been listed to
accommodate as many different types of strata as possible. Roller cone bits
would be good for exploration drilling; because they are so attentive to
the porosity of the hole, it is a good indicator to the drilling crew if
there is danger of a blowout. For longer drilling operations in harder formations,
PDC bits appear to clearly be the best choice.
The torque needed to drill the bit may be given by a top drive motor, suspended
by the traveling block above the drill pipe in the derrick; it turns the
drill string. This motor is electrical. New technology includes instead downhole
equipment, where the torque provided to turn the bit is initiated at the
bottom of the hole. The drill bit can be driven by a mud motor, which rotates
the bit through the pressure of the drilling mud. This has obvious benefits,
like not needing an additional outside power source. The drill collar is
placed behind the drill bit in order to give it enough weight to be pressed
against the formation while drilling. Drilling fluid is forced down the drill
string and is expelled out the jets, lubricating and cooling the drill bit
while at the same time carrying the rock cuttings away from the bit, exposing
fresh formation to be drilled. The drilling mud performs many crucial functions
and also has substantial environmental impact.
The drilling mud is essential to safe, efficient and economic oil well drilling.
Drilling mud is depended upon for:
•Control formation pore pressures to assure proper well control
Minimize drilling damage to the reservoir
•Stabilize the wellbore so that the hole diameter remains equal to bit diameter,
or at least minimizes hole enlargement
•Remove cuttings from under the bit while drilling
•Carry drilled cuttings to the surface while circulating
•Suspend the cuttings to prevent them falling back down the hole when pumping
•Release the drilled solids at the surface so that clean mud can be returned
•Keep bit cool
•Provide necessary lubrication to the bit and drill string
• Allow circulation and pipe movement without causing formations to fracture
•Absorb contaminants from downhole formations and handle the difference between
surface and downhole temperatures, all without causing serious degradation
of mud properties.
(Drilling Tech, 146)
There are approximately six types of mud: dispersed mud, non-dispersed mud,
solids free brines, oil mud and invert oil emulsion mud, air mud, and aerated
and foamed mud. Dispersed mud means that the clay (cuttings from the well)
is dispersed throughout the fluid. This is achieved by adding alkalis to
water which increase its polarity; the more polar the water, the more reactive
clays will disperse throughout the mud. Montmorillonite may be added to the
mud to give it useful properties; this is commercially known as bentonite.
The addition of this causes the mud to become viscous, and may help maintain
hole stability. Non-dispersed muds rely on the opposite of this effect by
using little water and attracting many clay particles to the same electrical
charge, enabling the polymer to wrap itself around the clay cuttings, essentially
dissolving the cuttings with the mud as the solvent. These are described
as encapsulating polymer muds. It is now possible to tailor synthetic muds
to specific drilling situations, depending on variables such as: increasing
the viscosity of the fluid, increasing the gellation properties, decreasing
fluid loss into the formation, and acting as a surfactant, to allow oil and
water to mix together in an emulsion. Solid free brines are used when working
within the reservoir to minimize damage to the formation. They can be formulated
with densities of up to 1.07psi/foot. The brine is unlikely to damage the
formation because it won’t plug the reservoir with irremovable solids or
by causing reactions with formation fluids or solids. This makes solids-free
brines useful during completion or workover operations.
Oil mud and oil emulsion mud, water is present less then 10% by volume; the
continuous phase is the oil. These are mostly no longer used as some of them
are toxic, carcinogenic, and flammable, which are undesirable for safety,
environmental and health reasons. It is possible to use compressed air instead
of mud, but requires specific conditions, namely a formation which can remain
stable without hydrostatic mud pressure to support it and there can be no
danger of a fluid influx into the well. Aerated and foamed mud is essentially
drilling mud injected with air, which in turn lightens the fluid column.
This mud is restricted to about 2800 feet as the pressure below these depths
cannot be sustained by the mud density. Its lifting capacity is greater than
that of regular drilling mud, but will not survive immersions in oil or salt
The basic physical properties of mud which should be monitored by the drilling
crew are densities, fluid loss, and sand content. As of yet it is hard to
make an estimate of how much mud will be needed in order to maintain the
wells, because there is still a vary vague idea of how many wells need to
be drilled. However, the mud can be reused many times and we are currently
working on a way to dispose of it efficiently and safely.
Once an area has been picked and appropriately cleared, the well is spudded
by driving a conductor pipe into the ground with a pile driver. This pipe
must then be cleaned of rubble using a small drill head which breaks up the
rubble and forces it to the surface. The initial size may vary, but the pilot
hole may be approximately 12-1/4” in diameter; this may get bigger. Our team
is currently researching how to drill to great depths using the smallest
holes possible. This pilot hole will later be re-drilled with a larger bit.
Slowly a drill bit of approximately 24” inches in diameter (again, we are
still researching this and believe it is possible to achieve much smaller
hole diameters) will be forced into the ground by the pressure of the drill
collars, which weigh approximately 6,000 lbs each. Mud is pumped down the
drillstring to clear the the cuttings as the bit begins to cut into the rock;
it needs to be moving at an annular velocity of approximately 100 feet per
minute to efficiently clean the well pipe (minimum 50 fpm). The amount of
mud needed may be calculated by initially subtracting (D2-d2) and multiplying
by 0.0408 where D equals the diameter of the hole and d equals the diameter
of the drill pipe yielding the gallons per foot. Multiply this quantity by
the minimum annular velocity, 50 fpm, and it yields the number of gallons
of mud needed per minute. It is as yet undecided how big the hole needs to
be and how many holes need to be drilled, so only rough estimates may be
made. The mud may be reused.
The drainpipe, held up by the derrick or mast, lowers the bit into the ground.
When enough drill collars have been applied to give the bit the weight it
needs, a crossover pipe is added to the end and then the drill string is
solely added to the drainpipe. During this initial phase there may be much
mud loss. When the drill reaches the required depth, the cuttings are cleaned
out and the the first casing is installed and cemented into the well bore.
It is important to cement the pipes in formations which are strong enough
to withstand the pressures of drilling. The process is again repeated until
the bit reaches the desired depth. There is instrumentation for determining
how much the well deviated from its path and it is still being looked into.
If a directional well is being drilled, a whipstock or a jet will be used
to create the deviation in the desired direction.
Jetting is when a particularly pressurized stream of mud is shot out in the
direction the bit should go, essentially eroding the rock in the needed direction.
However, this only works in soft formations. The whipstock is tool which
is attached to the end of the drillstring and fed into the wellbore head
of the drill bit. Its wide, flat edge prevents the bit from following the
path it normally would have taken and instead forces the bit to deviate to
Another essential part of equipment for the drilling process is the blow
out preventer, which monitors the downhole pressures and uses a system of
valves to close access to the hole incase a pocket of natural gas or highly
pressurized fluid is hit. It is important to pick a blow out preventer which
will be able to handle the pressures which may be encountered along the drilling
Once the hole has been drilled, perhaps with several deviated wells traveling
horizontally through reservoirs, it becomes necessary to complete the well.
First, tubing is run down the well so that the hydrocarbons are not flowing
directly up the casing. We will used coiled tubing in the well completion,
and we are looking into using it more instrumentally in drilling as well.
Coiled tubing is faster and less expensive because unlike regular tubing,
it can be fed into the hole faster and does not need to be connected through
joints, which takes time to complete. Once each ending of the wellbore is
left open or blocked off with cement. When it is left open, it is called
and open-ended perforation and the pressure in the formation must be such
that the oil will rise in the hole and not sink into the formation below
it. Sometimes the pressure is not enough and in order to prevent the loss
of hydrocarbons, the finished well will be sealed with cement. When the company
is ready to start producing, it will send a few charges down the well, and
detonate them, perforating the tubing and allowing the hydrocarbons to flow
into the tube.
Once the drill has been perforated and starts producing, a Christmas tree
is installed on top. This device allows the operator to control the amount
of production or shut down the well entirely if needful, or to direct the
flow of the oil once it reaches the surface. Usually, once the Christmas
tree is installed the well is complete.
The initial drilling process will only allow as much oil out of the well
as the pressure forces out. The easiest way to stimulate a flagging pressure
is by means of pumps to keep the tubing pressure less than the formation
pressure. However, soon this no longer becomes feasible and at this point
only 5-10% of the oil may have been recovered. Therefore secondary methods
have been developed to increase the oil production from reservoirs; these
usually involve flooding the reservoir with water and using the water to
create pressure, driving the oil before it and up the pipe. This water flooding
method may increase oil production by approximately 45% of the original oil
concentration. In order to make the well extract the greatest amount of oil,
tertiary (enhanced recovery methods) may be used. If the viscosity of the
crude oil could be reduced, it would not need high pressures to push it up
the drill pipe; therefore by adding solvents or by forcing steam into the
well, the now “thinned” oil will flow up the pipe. This method may remove
approximately 60% of the reservoir’s initial concentration. Technology is
being developed which would utilize microbial recovery systems, limiting
the amount of chemicals used.