drilling systems and operations

Shell Special Intensive Training Programme

Oyeneyin, M.B. of 28 ©Univation

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



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



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



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



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.



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



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.



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



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.



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



2. Drilling Estimated Formation Pressure

3. Verification 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



The techniques include


2. Drilling Estimated Formation Pressure

3. Verification 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



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.



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



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



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-



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)



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



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



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



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



4.11 WELL OPERATION PROCESS

The step-by-step procedure involved in well planning are presented are

presented in Fig 4.4.



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.



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



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.

drilling systems and operations

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