Download - Drilling Systems and Operations
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4 DRILLING SYSTEMS AND OPERATION
This section deals with the basic drilling techniques including some basic
introduction to advanced drilling techniques.
4.1 OVERVIEW OF WELL PLANNING
4.1.1 Introduction
Drilling of an oil/gas well plays a key role 'm an overall field development the
various aspects of which include:
1. Exploration to confirm the potential presence of hydrocarbons. This would
normally include seismic exploration among other techniques.
2. Drilling a number of wells to confirm the presence of and to exploit the
possible oil gas deposits.
3. Well completions involving the installation of necessary production tools, etc
4. Production operations include the processing of the produced fluids for
consumption or export., etc.
The drilling engineer is responsible for 'making' the hole.
There are three basic types of wells. These are
♦ Exploratory wells
♦ Appraisal Wells
♦ Development Wells
With exploratory and Appraisal wells, the objectives are to confirm the present of
any hydrocarbon presence and to appraise the extent of the field in terms of
geological information - stratigraphic features and lithological configurations,
identification of likely problems and problem zones, reservoir characterisation
with respect to actual reservoir/formation rock relationships, types of
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hydrocarbon, estimates of the reserves, production versus pressure relationships
etc.
With these wells, there are little or no information about the particular block or
field and it is the objective to set up a comprehensive information data bank for
the field.
In development or infill wells, there is relatively good information about the
environment. Successful drilling of these wells therefore require careful planning.
The main objective of an effective well planning therefore is to ensure that the
entire drilling programme is carried out as fast as possible at a relatively cheap
rate and maximum safety standard. This requires that the Drilling engineer must
have projections on anticipated potential problems and should develop
appropriate preventive measures to eliminate or minimise the problem. Taken
further, he must develop appropriate strategies to cope with any potential
problems.
Safety is the overriding criterion and safe drilling practices to prevent any
catastrophic problems requires effective planning prior to spudding the well to
initiate the drilling programme.
For exploratory and appraisal wells, little or no Information is available prior to
drilling. It is therefore essential to forecast the necessary information or data
required for effective well planning. Thus the planning will be flexible and subject
to modifications as drilling progresses in line with encountered facts. For
development drilling the planning is much simpler as there are data and
experience of the particular environment.
The major areas that require well planning are essentially:
1. The sizing and trajectory of the hole
2. Casing setting Depths, Casing Design and Cement programmes
3. Design of the Optimum Mud Weight, type and properties
4. Selection of the Drilling rig and rig equipment
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5. Contingency planning against unknown eventualities.
6. Knowledge of formation/fracture pressure.
These programmes require a good knowledge of the formation pressure to be
encountered and essentially the fracture gradient as these parameters drive the
overall safe drilling programme.
4.2 KEY PRESSURE DEFINITIONS
One of the primary functions of the drilling mud is the control of subsurface
formation pressure. This it achieves in either of two ways:
1. Overbalance Drilling
This is currently the most popular technique in which the drilling mud exerts a
hydrostatic pressure on the formation which is greater than the formation
pressure.
Thus
PH = PF + POB (1)
Where
PH= Hydrostatic pressure
PF = Formation pressure
POB = Overbalance pressure or simply Overbalance,
If the formation pressure becomes greater than the hydrostatic pressure then
formation fluid will flow into the wellbore, a phenomenon known as KICK.
2. Underbalanced Drilling
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This is a specialised drilling technique in which the influx of formation fluid into
the wellbore can be deliberately controlled to minimise or avoid certain borehole
problems such a formation damage, thus the hydrostatic pressure would be
designed to be less than the formation pressure. This is a controlled kick in which
the volume of fluid flowing and Mixing with the wellbore fluid would be known.
Thus, in this case
PH = PF - POB (2)
Most conventional wells are drilled overbalance but recent developments in
drilling technology have witnessed the adoption of underbalanced drilling to
improve well productivity.
The regulation of the relationships between these pressures is crucial to a
successful drilling operation.
Pressure can be defined as the force exerted on a unit cross-sectional area.
Pressure Gradient is the pressure exerted per unit length.
3 Types of Operational Pressures
1. Hydrostatic Pressure
This is the pressure due to the unit weight and vertical height of a static column
of fluid. It is expressed mathematically as:
(a) In Field Units
PH = 0.052*ρ*D (3)
PH = Hydrostatic pressure, psi
ρ =Density, pounds per gallon(ppg)
D = Well depth , ft.
(b) In Metre Units
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PH= ρD/1 0 (4)
where
PH = Hydrostatic pressure, kg/cm2
ρ = Density, pounds per gallon, gm/cc
D = Well depth, meters
2. Overburden Pressure
This is the pressure exerted by the total weight of solids and fluids in the
formation. It can be defined mathematically as :
(a) In Metric units
σob = ρb * D/10 (5)
ρb = average bulk density for interval, gm/cc
D = depth of sediment, metres
(b) In Field Units
σob = 0.433* ρb * D (6)
ρb = Specific weight, gm/cc
D = Depth, ft.
ρb = ρg*(1-φ) + ρfl *φ
The bulk density can be obtained from the combined Density, Resistivity and
Gamma ray logs.
φ = (ρg - ρb )/( ρg - ρfl)
One of the most important aspect of well planning is the estimation of bulk
density for the various formations drilled. This can be computed from seismic
data, shale density or sonic logs.
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The Overburden gradient is defined as σob/D ( psi/ft)
Bulk density is a function of depth and as the overburden increases with depth,
porosity decreases due to compaction effect thus increasing the bulk density
3. Bottom Hole Circulating Pressure
Circulating pressure describes the pressure required to circulate the drilling fluid
through the entire circulating system from the surface lines, through the drillstem,
drillbit and back to the surface via the annulus as shown in Fig. 4. 1.
The pressure generated at the pump overcomes friction in the entire flow loop.
Thus the pump pressure is the sum of all the pressure losses in each segment of
the entire wellbore.
Pump pressure = ∆P1 + ∆P2 + ∆P3 + ∆P4 + ∆P5 + ∆P6 = Standpipe pressure
(SPP)
The SPP minus the bit pressure loss are called parasitic losses.
The annular pressure losses (∆Pann = ∆P5 + ∆P6) act as a small "back pressure"
during circulation. Therefore the bottom hole circulation pressure(BHCP) is given
as
BHCP = PH+ ∆Pan
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4. Equivalent Circulation Density (ECD)
ECD is the mud weight equivalent to the bottom hole circulation pressure. It is
given as
ρe = (BHCP)/(0.052D)
BHCP = BH circulation pressure, psi
D = Depth, ft
5. Differential Pressure
The differential pressure is the difference between the bottom hole circulating
pressure and the formation pressure. Thus.
∆P = BHCP - PF
There are three possible scenarios that can occur if the differential pressure is
negative, equal to zero or positive.
6. Formation Fracture Gradient
This is the plot of pressure versus depth necessary to break down the formation
by the creation of fractures. Deliberate fracturing is a well stimulation technique
to improve production. However there can be induced fracturing during drilling
that can result is a major problem such as lost circulation.
The fracture gradient :
• helps to define the setting depths for intermediate casing
• determine the maximum annular pressure allowed while controlling a kick
In most cases, the weakest point in the wellbore is just below the casing shoe.
The leakoff test is a way of determining the fracture gradient.
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7. Formation Pressure (Pore Pressure)
This is the pressure exerted by the fluids contained 'm the pore space of a rock.
It depends normally on the fluid column density and vertical depth. For a normal
formation, it is equivalent to the pressure supported by a column of the formation
fluid at that depth. i.e. the Hydrostatic Pressure. . For this normal formation, the
true pore pressure at a given depth is equal to the fluid column pressure plus:
1. Pressure losses from fluid movement
2. Temperature effects
The pore pressure, PF= 0.052*ρF *D
We can have normal or abnormal formations
The upper limit of the pore pressure is the overburden pressure
4.3 NORMAL FORMATION PRESSURE
As defined above, this is the pressure exerted by the pore fluids above the depth
of interest because saline water is the most common fluid in the porous rock, the
formation pressure is given as a function of the formation water density
depending on salinity, the density ranges From 0.434psi/ft to 0.465psi/ft.
Examples for different regions are
• Niger Delta = 0.433psi/ft
• North Sea (Viking Basin) = 0.442psi/ft
• Gulf Coast = 0.46'Jpsi/ft
4.4 ABNORMAL FORMATION PRESSURE.
Where the formation pressure is less than 0.434 psi/ft or greater than 0.465psi/ft
the pressure is abnormal.
For PF< 0.434psi/ft, it is SUBNORMAL
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For PF>0.465psi/ft it is GEOPRESSURED OR OVER PRESSURED.
4.5 ESTIMATION OF FORMATION PRESSURE AND FRACTURE
GRADIENT
Formation pressure and Fracture gradient are two critical parameters needed by
the drilling engineer in planning and drilling a modern well.
One of the main functions of the drilling fluid is the control of formation pressure.
Knowledge of the formation pressure Is crucial to the design of drilling fluid
density.
From equation 1, PH = 0.052*ρm*H = PF + POB.
The overbalance POB depends on company or local experience but is based on
the knowledge of the Fracture gradient.
The overbalance must be such that the hydrostatic pressure is never greater
than the maximum allowable pressure, which is less than the fracture gradient.
Thus the equivalent density must be less than the fracture equivalent density.
In well planning, the engineer must first determine whether abnormal pressures
will be present. If they will be, the depth at which the fluid pressures will depart
from normal and the magnitude of pressure must be estimated also.
Estimation of Formation pressure
Direct measurement of formation pressure is possible with Repeat Formation
Tester (PM but expensive and can only be done after drill'mg. Thus, indirect
estimates are needed for planning purposes. Most methods for detecting and
estimating abnormal formation pressure are based on the fact that formations
with abnormal pressure also tend to be less compacted and have a higher
porosity than similar formations with normal pressure at the same depth
measurements that reflect changes in porosity is therefore used to detect
abnormal pressure.
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Generally, the porosity dependent parameter is measured and plotted as a
function of depth. A distinct departure from the normal trend signals a probable
transition. Knowledge of the transition depth is crucial to the determination of the
casing shoe setting depth. Two methods are used to make a quantitative
estimate of formation pressure from plots of a porosity- dependent parameter
versus depth.
Method 1
Assumptions that similar formations having the same porosity dependent variable
are under the same effective matrix stress σz. Thus matrix 1 at depth D is σz =
σzm at depth D. which gives the same measured value of the porosity dependent
parameter.
σz = σzm = σobn - Pn
Therefore, Pn = σobn - σz
Knowledge of bulk density at depth of interest gives the overburden stress to be
= 0.052*ρb*D
Maximum overburden stress is 1psi/ft if no other information is available.
If the normal pressure to a depth D is known, then the net matrix stress for the
well can be estimated.
Thus beyond that depth the formation pressure can always be computed
1. Assume normal formation with pressure gradients as defined for that region
2. For transition to abnormal formation assume the maximum of 1psi/ft
especially for casing design.
There are however ways for the estimation/detection of Abnormal Formation
Pressure
The techniques include
1. Predictive Method
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2. Drilling Estimated Formation Pressure
3. Verification Method
1. Predictive Method
Estimates of formation pore pressure made before drilling are base on:
• Correlation from nearby or adjacent wells
• Seismic data
For development wells, emphasis is on data from previous drilling experiences in
the area.
For exploratory wells, only seismic data is available. From the seismic data, the
average acoustic velocity as a function of depth is determined. This is a special
role for Geophysicists who will provide a profile of the rock matrix transit time
versus porosity.
2. Estimation of Pore Pressure While Drilling
• When kicks occur, the shut in drillpipe pressure is indicative of formation
pressure.
• Sloughing and spalling of shale fragments as observed on the surface shaker
is another indication of transition zone to abnormal zone
• Abrupt change in bit penetration rate (ROP) or behaviour as measured at
surface is very useful.
Method 2
This is an Empirical correlation approach which depends on substantial
database.
Estimation/Detection of Abnormal Forination Pressure
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The techniques include
1. Predictive Method
2. Drilling Estimated Formation Pressure
3. Verification Method
1. Predictive Method
Estimates of formation pore pressure made before drilling are base on :
• Correlations from nearby or adjacent wells
• Seismic data
For development wells, emphasis is on data from previous drilling experiences in
the area.
For exploratory wells, only seismic data is available. From the seismic data,
the average acoustic velocity as a function of depth is determined. This is a
special role for Geophysicists who will provide a profile of matrix transit time
versus porosity. Observed transit time can be computed from the following
equation :
t = tma(1 – φ) + tflφ
KD can then be computed from the equation
-KD =ln
−
−− )()( 00 mafl
ma
mafl ttt
ttt
φφ
Estimation of Formation Pressure During Drilling
This can be achieved through the following
1. Direct measurement by DST or RFT
2. Seismic interval velocities
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3. 'd' exponent /Signalog
4. Shale density
5. Wireline or MWD logs- Resistivity, sonic, and density logs
6. Kick
THE d-EXPONENT
The "d" exponent is basically used to predict the possibility of abnormally
pressured formations. It gives a non-dimensional number, which is based upon
the relationship between the penetration rate and formation pressure. It can be
used to identify the transition from normal to abnormal formation pressure for a
given drilling fluid density.
It can also be used to calculate:
• The formation pressure
• The fracture gradient in abnormally pressured zone
Mathematically, it is defined as:
)100
12(
)60(''
bitDWLog
NRLog
d =
R = Penetration rate, ft/hr
N = Rotary speed, rpm
W = Weight on bit, kilo-lbf
Dbit = Bit diameter, inches.
In normally pressured formations, the d-exponent increases gradually as the well
depth increases. Any departure from this trend is an indication of the transition to
abnormal pressure conditions. This may be in the form of reverse trend with
negative gradient or that the trend increases less rapidly with depth.
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Shale Density
Shale density is a porosity dependent parameter that can be plotted against
depth to estimate formation pressure. The empirical equation for computing this
is:
ρshn = ρg - (ρg - ρfl )φ0e-kD
ρshn = shale density for normally pressured shale
ρg = density grain
ρfl = pore fluid density
The Boatman relationship (Fig. 4.2) can then be used to estimate formation
pressure.
Shale density analysis measures the actual bulk densities of shale and
claystones as drilling
Progresses. In normally pressured formations, shale density increases with depth
and the density increase when plotted on semilog scale forms a trend of normal
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compaction. Accurate density values make it possible to calculate the formation
pressure.
Overpressured shale contains more porosity than expected for the depth.
Therefore the bulk density in the overpressured section is lower than the density
predicted by the trend.
Calculation of Formation Pressure from Kick
PF = SIDPP + PH SIDPP = Shut-in Drillpipe Pressure, psi
PH = 0.052*ρm*D.
Fracture Gradient Estimation
This is the plot of pressure versus depth necessary to break down the formation
by the creation of fractures. Deliberate fracturing is a well stimulation technique
to improve Production. However there can be induced fracturing during drilling
that can result in a major problem such as lost circulation.
The fracture gradient :
• helps to define the setting depths for intermediate casing
• determine the maximum annular pressure allowed while controlling a kick
In most cases, the weakest point in the wellbore is just below the easing shoe.
The leakoff test is a way of determining the fracture gradient.
The Leak-off Test
The leakoff test is the ultimate method for the positive determination of the
maximum mud weight permitted in the open hole section of the well. The crew
performs the test in the first few feet of a new hole drilled after a new casing
point, which is the likely weakest point of the open hole section if no highly
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permeable formations exist further down hole. The test result when converted to
equivalent mud density determines the maximum mud weight that the section
can withstand without loss of circulation.
Leakoff tests should be run usually of a few wells in a new block. The test
consists of closure of the hole at surface, then application of pressure until mud
just begins to inject into the formation. A Leakoff Test is usually as follows:
1. After cementing easing, run in hole with bit and drillstring.
2. Pressure test casing , then drill out easing shoe and a further minimum of
10feet of new formation.
3. Pull bit up to easing shoe.
4. With bit at shoe depth, shut off pumps, wait for flow to cease then close the
kelly cock and blow out preventer.(mainly the annular preventer)
5. Then use cementing unit to pump drilling mud slowly through the choke line
into the hole annulus. While pumping, always monitor the pressure build up
and volume pumped.
6. The pressure build-up should be more or less linear until mud begins to bleed
into the formation. The pressure at which the build-up curve departs from
linearity is the Leakoff pressure (PLOT)
7. As pumping continues, the build-up curve flattens out until pressure no longer
increases. At this point, the pump is injecting mud into the formation pores
and fractures. The pressure of the mud at this point is the INJECTION
PRESSURE.
8. At injectivity point, pump should be shut off and the choke line closed.
9. Monitor the pressure. Normally at this point the shut-in pressure will fall until it
reaches an equilibrium point that is slightly above the leakoff Pressure. The
equilibrium point is the Bleedoff point-
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10. Hold bleed off pressure for several minutes to confirm that no breakdown has
taken place. If bleedoff pressure remains steady, open the choke valve to
vent the rest of the pressure
Bottom Hole Pressure at Leakoff
The leakoff pressure determines the Bottom Hole Pressure at leakoff. The
maximum mud weight or ECD permitted can then be calculated.
The equation for the BHP is as follows
BHP(at leakoff) = 0.052*ρm*D + PLOT
PLOT = Leakoff pressure(psi)
ρm = Mud Density, lb/gal
D = True Vertical Depth of well, ft.
Maximum Mud Weight Permitted is computed to be
ρmax = BHP/(O.052*D)
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4.6 FORMATION INTEGRITY TEST (FIT)
In a FIT otherwise known as Formation Intake Test, the crew tests the formation
below the newest casing shoe to a pressure slightly less than the predicted
fracture pressure. If no leakoff occurs at this pressure, then the test is success!
The disadvantage of Fit is that the true leakoff pressure is unknown. If mud
weight is raised above the maximum defined by the FIT, then lost circulation may
occur.
4.7 CALCULATION OF FRACTURE GRADIENT DURING
DRILLING
As mentioned previously, fracture gradients are essential to well planning. For
any given well, the gradient is used to:
• determine the setting depth of protective casings
• determine the maximum mud densities permitted during drilling
• determine the maximum allowable annular surface pressure(MAASP)
permitted during kick circulation.
The factors influencing the fracture gradient are
• Insitu stress conditions
• Hole geometry and orientation
• Mud density, rheology and hydraulics
• Wellbore temperatures
• Formation composition
Fracture gradient is a loose term to define three different values
1. Pressure to initiate a fracture
2. Pressure to reopen or extend an existing fracture
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3. Fracture closing, pressure.
For drilling purposes, the lowest value-the fracture closing pressure defines the
maximum pressure allowable in an open hole and is taken to be equal to the lust
principal stress.
Fracture Gradient Theoretical Calculations are based on a number of summary
models Each model is based on the following assumptions:
σ = σob - PF
σ = sx + PF in horizontal direction. =Kx σ + PF
Kx = µ/(1− µ)
4.7.1 Fracture Gradient Determination
Knowledge of fracture gradient is useful in determining the operating window for
♦ Net Overbalance required for optimum mud density
♦ Determination of casing setting depths
Two main methods are available for determining the Fracture gradient. They are
Theoretical Method - There are a number of empirical correlations being used to
predict fracture gradient. One example is the Hubert and Willis correlation who
defined fracture gradient as a function of overburden stress, formation pressure,
and a relationship between horizontal and vertical stresses. They believed these
stress relationships to be in the range of 1/3 to 1/2. The minimum and maximum
gradients were defined as:
Pfrac/D(min) =1/3(σz/D + 2PF/D)
Pfrac/D(max) =1/2(σz/D + 2PF/D)
Pfrac = fracture pressure, psi
σz = Overburden stress, psi
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PF = pore pressure, psi
D = depth, ft
Details of this will be covered in the individual sections,
4.8 HOLE SIZE/TRAJECTORY
The hole size is mainly dictated by
1. The number of casings proposed for installation
2. Subsequent downhole completion and production facilities
3. Number of multiple pay sections
4. Planned completion strategy
5. Trajectory of hole
6. Available technology
Hole trajectory is a function of
1. Expected reservoir target
2. Number of reservoirs within the block
3. Defined safe well spacing for the area
4. Completion efficiency and projected production plan
5. Location of the Drilling Platform and proximity of other Structures
6. Type of well - conventional or relief well , injection well or producer.
7. Available Technology
The decision to drill a vertical, deviated or extended reach, multilateral or
horizontal wells depend on these factors
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4.9 DETERMINATION OF OPERATING MUD WEIGHT
The operating mud weight is computed from the equation below
ρe = (PF + POB)/0.052*D
= The equivalent mud density to maintain a safe hydrostatic pressure to control
formation pressure.
4.10 CONTINGENCY PLANS
In all drilling operations, events will occur which do not follow regular mode of
operation. These events must be taken into account before they occur so that
they can be avoided or mitigated.
1. In all cases, the appropriate arrangements for all materials to be used should
be done and materials acquired before going to site especially for remote
locations
2. The programme schedule of all operations should be decided and developed.
3. Schedules should include
♦ Well control schedule
♦ Casing /Cementing schedule
♦ Mud schedule
♦ Bit schedule
♦ Bottom Hole Assembly(BRA) Schedule
♦ Testing sequence, etc.
For optimum results, the preparation of this schedule requires an integrated team
approach involving geologists, reservoir and production/completion engineers
and of course the drilling engineer
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4.11 WELL OPERATION PROCESS
The step-by-step procedure involved in well planning are presented are
presented in Fig 4.4.
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4.11.1 The Drilling Process
After spudding, the surface hole is drilled followed by the setting of surface
easing. This is followed by intermediate hole and setting of intermediate casing.
As the drilling target is reached preparation for the productive formation begins.
In addition to Mud logging, open hole logging is performed prior to setting of
casing. These are supported by core analysis and well testing
Types of Wells
There are different trajectory profiles of oil wells nowadays. For a variety of
reasons especially to cut costs and improve production, several wells are drilled
single platform especially offshore. The wells (Fig. 4.5) include:
1. Vertical wells
2. Deviated or Directional Wells
3. Horizontal Wells
4. Multilateral and Multibranch wells.
To drill a directional well to target, requires drilling an initial vertical well and then
make an initial deflection from the vertical through a build-up section.
The deviation from vertical begins when the use of a combination of tools:
1. The downhole hydraulic motor
2. The jet bit
3. The Whipstock(Fig.4.6).
The drilling and monitoring of deviated wells especially horizontal and multilateral
wells requires continuous monitoring of trajectory. This requires the use of MWD
tools to "track" the hole.
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4.12 NEW DRILLING TECHNIQUES
The relatively new drilling techniques are
1. Coil Tubing Drilling - This involves the use of coil tubing combined with
downhole motors for drilling highly deviated, extended reach, multilateral and
horizontal wells.
2. Slim Hole Drilling –This is not radically different from conventional borehole
drilling except for the size of the boreholes, which are relatively smaller with
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possible effects on the drilling fluid equivalent circulation densities and more
complex completion strategy. They appear to have a future in deep water
drilling projects.
3. Underbalanced Drilling - In this technique, the well is drilled under negative
differential pressure. The mud is designed such that the formation is drilled
with controlled level of underbalance.
This technique is currently limited to very tight sands and carbonate formations
where no formation damage can hardly be tolerated. Ideally, the technique is
applied in wells where impairment is expected to be very low. Nevertheless, it is
becoming increasingly popular for use in different formations. One approach is to
use foam-drilling fluids - The so-called aerated mud.
4.13. MWD
Measurement-While-Drilling (MVM) provides real time data to guide the driller to
the target, to view the formation while invasion is shallow and the wellbore is
smooth and to improve pore pressure evaluation.
Examples include:
1. The D&I Sensor (Direction & lnclination) Tool used to measure hole direction
(Azimuth) and inclination (Drift).
2. Tool Face (TF) - This is a measurement of the orientation of the.BHA versus
top of the hole
3. . Shocks - Dedicated accelerometers measure the number of traverse shocks
imparted on an MWD collar.