abu rudeis – drilling engineering

Drilling Engineering

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B.SC. PROJECT 2009 – ABU RUDEIS – SIDRI FIELD

Introduction

Methods of drilling wells

Dilling is the process of making wellbores in the earth crust.

Many methods can be used for drilling wells.

Drilling methods can be classified in accordance with various

principles. Any methods of drilling involves formation disintegration,

machine (which can be used for drilling, disintegrate and excavate

rock ) by four basic mechanism :-

AA.. By mechanically induced stresses.

BB.. By thermally induced stresses.

CC.. By fusion and vaporization.

DD.. By chemical reactions.

EE.. By explosion, erosion, electrohydraulic, and ultrasonic drilling.

From all the principles mentioned only mechanical drillings widely

used for drilling oil and gas wells. Drilling methods based on other

mechanism of formation disintegration were tested in laboratories and

in the field but not used in the industry.

Industrial methods of mechanical drilling can be further subdivided

according to the character or rock design tools motion.

AA.. Drilling methods with reciprocating motion of the tool.

BB.. Drilling methods with rotary motions of the tool.


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Mechanical methods of drilling with rotary motion of the working

tool are the most widely used methods in the oil and gas industry.

These methods can be classified in accordance with the position of a

mover that drives the tool :-

AA.. Drilling methods with the mover on the earth surface (rotary table

or top drive system).

BB.. Drilling methods with the mover situated near the bottom of the

hole (sliding mode).


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Casing and Tubing Design

1- Casing:

Casing is the major structural component of a well. Casing is

needed to maintain borehole stability& prevent contamination&

isolate water from producing formation

In addition, control well pressures during drilling, production, and

work over operations. Casing provides locations for the installation of

blowout preventers (BOP’s), wellhead equipment production packers.

CASING TYPE:

1 - Conductor.

2 – Surface casing

3 – Intermediate casing

4 – Production casing

5 - Liner.

1) Conductor casing:

is set below the drive pipe or marine

conductor that is run to

protect loose, near surface formations

and enable circulation of drilling fluid,

it Prevents Washing-Out around the

base of the rig. The conductor isolates unconsolidated formations and

water sands and protects against shallow gas. Normal depth for

Conductor pipe is from 30 to 250 feet. It is often driven with a pile driver

until it will not go any further.


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2) Surface casing:

The surface casing is the first string of any sequence to be

run into a well, after a hole has been drilled. It ranges from (7 5/8)" to

20" commonly (13 3/8)". Attached to the surface Casing, after it has

been cemented, is the following pieces of equipment:

1 - Casing head from which part of the suspended weight of subsequent

strings are hang.

2 – Blowout preventors: This will control any formation gas or fluid

pressures, which might be encountered. The casing must be strong

enough to support this weight and to contain any possible pressures. For

this reason, it is always cemented to surface.

The surface casing is also designed to seal off fresh water aquifers and

prevent them from being contaminated by hydrocarbons or salt water,

which may be encountered in deeper drilling.

3) Intermediate casing:

Isolates unstable hole sections, lost circulation zones, low pressure

zones, and production zones.

It called protective casing The size ranges from (6 5/8)" to 20 "and

Commonly (9 5/8)".

Problems that Might Necessitate Intermediate Casing are:

1 - Weak formations, which break down and cause loss of circulation

of the drilling fluid.

2 - Abnormally high pressure zones (usually geo-pressured gas) So

that drilling cannot then continue with a lighter mud.

3 –“Heaving Shales" that swell when in contact with water or drilling

sand fall into the hole


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4)A Liner:

Is a casing string that does not extend back to the wellhead, extending

from the bottom of a well to a point 100 feet-or more the lower end of

the intermediate string. Liners are used to reduce cost, improve

hydraulic performance during deep drilling, and allow the use of larger

tubing above the liner top.

Number of casing string and setting

depth

4) Plot Hydrostatic, formation, and fracture pressure gradient against depth. 5) Plot another curve equal fracture pressure -0.5 ppg for safety. 6) from plotting we can find the number and setting depth of the casing

string.

ft / psi 1 stress overburden verticalis

388.0 ratiopoisson is

where,

psi ,P P1

P

:pressure fracture theDetermine 3)

psi ,200PP

:pressureformation theDetermine 2)

ft depth, ish

ppg density, mud is

wher,

psih * * 052.0P

:pressure chydrostati theDetermine 1)

v

fffr

hf

m

mh

v


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Depth,m Depth,ft Formation

pressure,psi

Formation

gradient,(psi/ft)

Trip

margin

gradient

,(psi/ft)

934 3064 1180 0.385 0.411

1390 4560 1914 0.42 0.446

1432 4698 1998 0.425 0.451

1710 5610 3931 0.701 0.727

2199 7215 5113 0.709 0.735

2486 8156 5806 0.712 0.738

2660 8727 3202 0.367 0.393

Depth,m Fracture

pressure,psi

Fracture

pressure

Gradient,psi

kick

margin

gradient

,(psi/ft)

mud

(ppg)

934 2375 0.775 0.7489 8.6632

1390 3591 0.788 0.7615 8.9131

1432 3710 0.79 0.7636 8.9964

1710 4995 0.89 0.8644 14.161

2199 6445 0.893 0.8673 14.161

2486 7295 0.894 0.8684 14.161

2660 6704 0.768 0.7422 7.497


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Casing Depth, ft

Casing Length, ft From To

7 " linar 7956 8727 771

9 5/8" csg 0 8157 8157

13 3/8" csg 0 4698 4698

20" Conductor 0 115 115


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Casing string design:

Steps of design

The process of casing string design is divided into three stages

For collapse resistance:

Minimum collapse resistance for the bottom section is

Where,

fc = collapse safety factor ~ 1.125

= mud wt., ppg

H = total depth, ft

The length of the bottom section is determined as follows;

Pc2 = 0.052 (H – L1) fc, psi

Where :

Pc2 = collapse resistance of selected second section.

L1 = length of the bottom section, ft

From tables select suitable grade with stand collapse

pressure

psi , f H 0.052 P cminc


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for tensile strength ( upper part ):

Wt. Of every section is determined from table

Wi = Wi x Li, lbs

The top end is checked for tensile strength

- Stronger casing should be used for the next upper sec. and its length

is determined as follows

ni

i cf

ncP

iLH

cf

cPLH

cf

cPH

1 052.0

)1(nL

generally,

ft ,052.0

312L

ft ,052.0

21L

(1.8). efor tensilfactor design ,f

lbs. table,from sec. topofstrength tensile,

,

t

1

in

tn

ii

in

P

where

f

LW

P


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Checking for internal ( bursting ) pressure:

The weakest section is checked of internal pressure as follows

At first calculate Maximum formation pressure (Pf ) and then find

the minimum allowable internal pressure (Pi ) = Pf * 1.1

From tables, and by using the value of Pcmin , and minimum internal

pressure, thesuitable casing grade wt. required is selected.

Design of 7 " liner:

1- Pc min = 0.052 * 1.125 * 0.9*8.33* 8727 = 3827 psi .

2- Maximum formation pressure expected Pf = 3403.4 psi.

So, minimum internal pressure Pi must be > 1.1 * 3403.4

Pi > 4118 psi

From Rabia page 210,

To From

771 8727 7956.17 7 "

CasingCasing Length, M Depth ,ft

kt

n

itik

i

n

kLiitik

Wf

LiWfP

L

where

WLWfPk

1k

ik

1

L

Pstrength tensileofK sec. theoflength ,

,


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Checks:

1- For tensile strength:

2- For internal bursting pressure:

Design of 9 5/8 “ casing:

1) Pcmin = 0.052*1.7*8.33*1.125*8157= 6757 psi .

2) From tables selection of suitable grade &nominal weight .

3) Determine length of each grade,or nominal weight ,by

L1=H-PC2/(FC*MUD GR.*0.052)

4) Maximum formation pressure expected Pf =6007 psi.

So, minimum internal pressure Pi must be > 1.1 * 6007

Pi > 6607psi

From Rabia page 203

Use Grade MW-C-95 # 47lb, MW-C-95 # 44lb, MW-C-95 # 40lb,

have collapse resistance and we calculate their length

case Tensile.S.F Tensile.Strength WT ,lb N.WT ,lb/ft Length ,ft GRADE

SAFE 36 566000 15700 23 727 L-80

case PI/Pf PI N.WT GRADE

SAFE 2.33 7930 23 L-80

Collapse

s.f .

safe 1.18 6006.6 7100 6760 -8157 1397 47 MW-C-95 9.625

safe 1.125 4977.8 5600 5106 -6760 1654 44 MW-C-95 9.625

safe 1.125 3760 4230 0 - 5106 5106 40 MW-C-95 9.625

Casingcase formation Pressure collapse resistance Casing Depth ft Casing Length ft N.W GRADE


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Checks:


Case T.S.F T.strength CUM.WT Wt. N.Wt Length Grade

safe 22.17 1289000 58*103

58137 47 1397 MW-C-95

safe 9.734 1193000 122.6*103

64423 44 1654 MW-C-95

safe 3.6 1088000 303*103

180828 40 5106 MW-C-95

2-For internal bursting pressure:

Case Pi/Pf Pi N.WT Grade

safe 1.357 8150 47 MW-C-95

safe 1.509 7510 44 MW-C-95

safe 1.184 6820 40 MW-C-95

Design of 13 3/8 “ casing:

Pcmin =0.0.052*1.08*8.33*4699 *1.125=2473 psi .

2- Maximum formation pressure expected Pf =2199 psi.

So, minimum internal pressure Pi must be > 1.1 * 2199

Pi > 2418.9 psi

From Rabia page 198

Use Grade C-75 # 72lb , C-75 # 68lb C-75 # 61lb have collapse

resistance


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Collapse Pc Pf Casing depth Length N.W Grade

s.f. psi psi ft ft lb

2.29 2590 2199 4218 - 4699 481 72 C-75

2.39 2220 1974 3154 - 4218 1064 68 C-75

2.86 1660 1476 0 -3154 3154 61 C-75

Checks:


Case S.F. T.strength Cum.Wt. Wt Length N.W Grade

safe 50.84 1558000 30648 30648 481 72 C-75

safe 15.39 1458000 94708 64060 1064 68 C-75

safe 4.95 1312000 265044 170336 3154 61 C-75

2-For internal bursting pressure:

Case pi/pf pi Pf N.W Length Grade

safe 2.29 5040 2198.25 72 481 C-75

safe 2.39 4710 1973.33 68 1064 C-75

safe 2.86 4220 1475.55 61 3154 C-75

Design of conductor pipe:

Choose low grade for conductor design because the collapse

resistance is very low at surface.

Select grade J-55 or H-40, and is set at the refusal point from

115 ft conductor 20 "


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Cement

Function of cement:

1) Restriction of fluid movement between permeable zones within

the well.

2) Provide mechanical support for the casing string.

3) Protection of casing against corrosion by sulphate rich

formation waters.

4) Support for the well-bore walls to prevent collapse of

formations.

Classes and types of cement:

The API has classified nine types of cement, depending on depth,

and conditions of hole to be cemented these are as follows;

1 - Class A:

Intended for use from surface to 6000 ft. depth when special

properties are not required. Available only in ordinary type.

2- Class B:

Intended for use from surface to 6000 ft. depth when conditions

require moderate to high sulphate resistance. Available in both

moderately and highly sulphate resistance type.

3- Class C:

Intended for use from surface to 6000 ft. depth when conditions

require high early strength. Available in moderately and highly sulfate

resistance type.


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4 - Class D:

Intended for use from 6000 ft. to 10,000 ft. depth, under

conditions of moderately high temperatures and pressures.

5- Class E:

Intended in use from 10,000 ft. to 14,000 ft. depth under

conditions of high temperatures and pressures. Available in both

moderately and highly sulfate resistance types.

6 - Class F:

Intended for Use from 10,000 ft. to 16,000 depth, under

conditions of moderately high temperatures and pressure. Available

in both moderately and high sulfate resistance types.

7 - Class G:

Intended for use as basic cement from surface to 8,000 ft. depth

, as manufactured, or can be used with accelerators and retarders to

cover a wide range of well depths and temperature.

8 - Class H:

Intended for use as basic cement from surface to 8,000 ft; depth as

manufactured, and can be used with accelerators and retarders to

cover a wide range of well depths and temperatures.

9 - Class J:

Intended for use as manufactured, from 12,000 ft. to 16,000 ft.

depth under conditions of extremely high temperature and pressure,

or can be used with accelerators and retarders to cover a wide range

of well depths and temperatures.


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Production casing cementing program:

1 - Slurry volume calculations:-

- Annular cross-sectional area between casing string and bore-

hole

where D = bore-hole diameter , inch

O.D = casing out side' diameter, inch

- Slurry volume = A * H * excess "safety' factor"

- Excess volume of slurry = 25%

2 - No. of sacks of cement:

-Yield of slurry means the, No. of cu. ft of slurry that is produced by

using one sack of dry cement.

Methods of Cementing :

1)Single Stage Cementing

Is normally to cement conductor and surface pipes. A single

batch of cement. is prepared and pumped down the casing. it should

be noted that all The internal parts of the casing tools including

the float shoe, wipe plugs, etc are easily drillable.

2in ,2.2

4 A

cDOD

sack)ft / (cu.slurry of yield

ft) (cu. umeslurry vol


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2)Multi stage Cementing

It is employed in cementing long casing string in order to reduce

the total pumping pressure, reduce the total hydrostatic Pressure on

weak formations& using retardard . There preventing Their fracture,

allow of selective cementing of formations and ensure effective

Cementing around the shoe of the previous casing string.

In multistage cementing a stage cementer is installed at a

selected position in the casing string, the position of the stage

cementer is indictated by the total length of the cement column and

the strength of formations.

Cement calculations for well SIDRI 13

Casings setting depths:

Casing

Measure Depth, ft Casing Length, ft

To From

20" Conductor 115 0 115

13 3/8 " 4698 0 4698

9 5/8 " 8156 0 8156

7 " linar 8727 7956 771

As shown from this table all setting depths in the range of (8000 ft)

So; we can select cement class (G).


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Cement (class “ G”) description

component Weight Lb sp.gr Volume ,gal

Cement 94 3.14 3.6

2% bentonite 1.88 2.65 0.086

mix water for cement 41.36 1 4.97

Mix water for bentonite 9.4 1 1.13

Slurry weight =94+1.88+41.36+9.4 =146.6 lb

Slurry volume = 3.598+.0853+4.971+1.1298 = 9.78gal

Slurry density =146.64/9.7841 = 15 ppg

Slurry yield =9.7841*5.615/42 = 1.308 ft3/sack

For 13 3/8 “ casing string:

Determine no. of cement stage

At casing shoe string

P slurry = 0.052*slurry density*setting depth

= 3665.87 psi

P f = 0.052*sp.Gr of brine water*setting depth=0.052*1.08*8.33*4698

=2197 psi


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P frac = (2/3)*(4698-2197)+2197

=3864.35 psi

Note that: Pfrac > Pslurry > Pf

So ,one stage will be used

Volume of slurry :

v1(cement annulus volume between13 3/8 “ and 22 “ )

=3.14/(144*4)*(162-13 3/8 2) *115

=164.3 ft3

v2( cement annulus volume betweeen csg.v& open hole)

=3.14/(4*144)*1.25*( 4698.2-115)

=2409 ft3

v3 (cement volume in casing below floating collar)

=3.14/(144*4)( 12.47516)^2*40=40 ft3

Total slurry volume = 2608 ft3

No. of cement sacks =slurry vol. /slurry yield

= 2299 sacks

Mixing water =water for cement +water for Bentonite

= 334 bbl

total water = 354 bbl

Volume of Bentonite =.0853*2299 =196 gal


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Assume mixing rate = 2.5 bbl/min.

Mixing time =water volume / mixing rate

=133.6 min.

Average inside diameter for 13 3/8 =12.47516 in

Displacement volume =V(inside casing)-V(shoe)

=3.14/(4*144)*( 12.47516)^2(4698-42))

= 3950 ft3

Assume displacing rate = 8 ft3/min

Displacement time = 494 min.

Put drop of plug time =10 min.

Safety Time =30 min

Total time =mixing time +displacement time +drop of plug time +

Safety Time

Total time =133.6 + 494+30+10 =668 min.

For 9 5/8 “ casing string:

At casing shoe :

P slurry = 0.052*15*4698

= 6364 psi

P formation = 0.052*1.7*8.33*8157

=3814 psi


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P fructure =(2/3)*(8157-3814)+ 3814

=6709 psi

Volume of slurry

v1(cement annulus volume between13 3/8 “ and 9 5/8 “ )

= 1613 ft3

V2 (annulus cement volume at open hole ) = 1354 ft3

V3(cment volume below floating collar) = 35.4 ft3

Total cment volume = 3002 ft3

No. of cement sacks = 2298 sucks

Volume of mixing water = water for cement +water for Bentonite

= 334 bbl

Total water volume =334+20

Total water volume = 354 bbl

Volume of Bentonite = 196 gal.

Mixing time = 133.6 min.

Setting of plug time = 10 min.

Displacement volume = 3401.7 ft3

Displacing time = 425.2 min.

Safety time = 30 min

Total time = 599 min.

For 7 “ liner:

At casing shoe string


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P slurry = 0.052*slurry density*setting depth = 6810 psi

P f = 0.052*sp.Gr of brine water*setting depth=0.052*1.08*8.33*8727

= 4081 psi

P frac= (2/3)*(8727-7956)+ 4081

=7178 psi

Note that: Pfrac > Pslurry > Pf

So ,one stage will be used

Volume of slurry :

v1(cement annulus volume between7 “ and 9 5/8 “ )

=3.14/(144*4)*( 8.79242-7 2)*200=30.9 ft3

v2( cement annulus volume betweeen casing and

open hole )

=3.14/(4*144)*1.25*(12.5^2-7^2)( 8727-8157)

=90.5 ft3

v3 (cement volume in casing below floating collar

=3.14/(144*4)( 6.366)^2*40 = 18.6 ft3

Total slurry volume = 140 ft3

No. of cement sacks =slurry vol. /slurry yield

= 108 sucks

Mixing water =water for cement +water for Bentonite

= 16 bbl

total water = 16+20 = 36 bbl


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Volume of Bentonite=.0853*2299 =196 gal

Assume mixing rate = 2.5 bbl/min.

Mixing time =water volume / mixing rate

= 6.4 min.

Displacement volume =V(inside casing)-V(shoe)

= 945 ft3

Assume displacing rate = 8 ft3/min

Displacement time = 118 min.

Put drop of plug time = 10 min.

Safety Time = 30 min

Total time =mixing time +displacement time +drop of plug time +

Safety Time

Total time =6.4 + 118 +30+10 = 165 min.


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Drill String Design

The design of drill string involves the design of drill collar and

drill pipe.

Drill collar design

By using drilling data handbook and according to the size of

the borehole, (outside diameter, inside diameter and nominal

weight of the drill string )can be selected.

The Calculations are as follows:

Where,

B.f : is the buoyancy factor = (1- γm / γs)

γm , γs : is the density of drilling fluid and steal

respectively.

WB : is the weight on bit, lbs.

Wc : is the nominal weight of drill colar, lb/ft

Lc : is the length of d/c, ft

Drill pipe design:

The diameter of the drill pipe is selected according to the

borehole size from the handbook

ft ,c W* B.f

BW *

3

4cL

ft) (31joint oflength

L joints) of (no.N c

c


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Lp = L - Lc

Where,

Lp : is the length of drill pipe, ft

L : is the depth , ft

From Oil Well drilling Engineering out side and in side diameter of

the drill pipe can be selected.

Selection Of Drill Pipe Grade

Where,

Ymin : min. yield strength, psi

Wp : Weight of d/p, lb/ft

Wc : Weight of d/c, lb/ft

ft : Safety factor ( 1.5)

D : out side diameter of d/p,inch.

d : inside diameter of d/p , inch.

From table of Petrolum Enginnnering H.B., select the drill pipe

grade where,

ft) (93 stand oflength

L stands) of (no.N

p

p

psi ,

22785.0

tf * .pW minY

dD

fBcLcWpL

5.1min.Y

selectedY


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Check for collapse:

Where,

Pcmin : Hydrostatic pressure, psi

γm : d/f density, ppg

H : total length of d/s, ft

From Petrolum Engineering H.B., determine the collapse

pressure of the selected grade ;

Then repeated the previous procedure for every bit size run

in the hole.

Drill String Design

For firist bit run:

Bouncy

B=1-(1.04*62.4/489.5)=0.8674

Drill collar

From Rabiaa page (34 )

OD = 14" ; ID = 3" ; WC = 361 lb/ft

psi , H m 0.052 mincP

safe isdesign 5.1

.mincf If

cP

selectedcP


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Length of D/C (LC CAL.)

LC=4/3*(22046/(361*0.8674)) = 93.84 ft

No. of joints

N=93.84/31

= 3.03

LC=4*31= 124 ft

Drill pipe

From Rabiaa page (26 ,27 )

OD = 5" ; ID = 4.276" ; WC = 19.5 lb/ft

Length of drill pipe

LD/P =3064 -124 = 2940 ft

No. of drill pipe joits

N=2940./93=31.6 = 31

D/p actual length

L d/p =31*93 = 2883 ft

Check on tensile

Min. yield force applied on drill pipe

Y min= ((19.5*2883) + (361*124)) *0.8675

= 87604 lb

From Rabiaa page (26) class 2

Y =311540 lb

F=311540 /87604 = 3.56 >1.5 safe

Check on collapse

Pc=.052*8.33*1.04*3064 = 1381 psi


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From Rabiaa page (27 ) class 2

Pc select =4760 psi

Fc=4760/1381 =3.5 >1.5 safe

By the same method the other bit run will be as following

From Rabiaa page (34 ) table 2.9

Drill Collar Design

W.O.B W.O.B

(ton) Bit run Depth ft Depth m

size of

hole, in (lb)

22046.2 10 1 0 - 3064 0 - 934 16

39683.2 18 2 3064 - 4560 934 -1390 16

26455.5 12 3 4560 - 4698 1390 - 1432 16

30864.7 14 4 4698 - 5610 1432 -1710 12.25

26455.5 12 5 5610 - 7214.5 1710 - 2199 12.25

26455.5 12 6 7214.5 - 8156 2199 - 2486 12.25

22046.2 10 7 8156 - 8727 2486 - 2660 8.5


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Drill collar specification

N.W.,LB/FT I.D.,in O.D.,in size of hole, in

361 3 12 16

246 2.8125 10 12.25

114 2.5 7 8.5

From Rabia page(26,27) oil well drilling engineering

Drill Collar Design Continued

N D/C

D/C length Calc. ft

size of

hole, in Act. ft

N D/C

calc..

Bit

run Depth , ft

124 4 3.03 93.86 1 0 - 3064 16

186 6 5.47 169.7 2 3064 - 4560 16

124 4 3.65 113.3 3 4560 - 4698 16

217 7 6.89 213.53 4 4698 - 5610 12.25

186 6 5.9 183.03 5 5610 - 214.5 12.25

186 6 5.9 183.03 6 7214.5 -8156 12.25

310 10 9.39 291.24 7 8156 - 8727 8.5


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Drill Pipe Design

D/P Length NO.D/P N .D/P D/P Length Bit run Depth , ft Hole

Act. ft Stands. stands CaL. CaL. ft size in

2883 31 31.61 2940 1 0 - 3064 16

4371 47 47.03 4374 2 3064 - 4560 16

4557 49 49.18 4574 3 4560 - 4698 16

5301 57 57.99 5393 4 4698 - 5610 12.25

6975 75 75.58 7028.5 5 5610 - 214.5 12.25

7905 85 85.7 7970 6 7214.5 -8156 12.25

8370 90 90.51 8417 7 8156 - 8727 8.5

Bit

run

Grade

Ymin ,lb Ygrade ,lb Ygrade/Ymin PCmin ,psi PCgrade ,psi PCmin/ PCgrade

class (2)

1 E 87603.9 311540 3.56 1380.29 4760 3.449

2 E 131610 311540 2.37 2113.47 4760 2.252

3 E 115241 311540 2.7 2197.78 4760 2.166

4 E 148139 414690 2.8 4131.05 9420 2.28

5 E 175738 414690 2.36 5312.56 9420 1.773

6 E 194390 414690 2.13 6005.85 9420 1.568

7 S135 175791 560760 3.19 3402.17 5970 1.755


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Drill pipe specification

N.W.,LB/FT Grade I.D.,in O.D.,in size of hole, in

19.5 E 4.276 5 16

25.6 E 4 5 12.25

19.5 S135 4.276 5 8.5

Directional drilling

The most common applications of directional drilling are illustrated in and

discussed briefly below:

Multiple wells from artificial structures.

Today's most common application of directional techniques is an offshore

drilling where an optimum number of wells can be drilled from a single

platform. This operation greatly simplifies production techniques and

gathering systems, a governing factor in the economic feasibility of the

offshore industry.

Fault drilling

Another application is in fault control where the wellbore deflected across

or parallel to the fault for better production. This eliminates the hazard of

drilling a vertical well through a steeply inclined fault plane, which could slip

and shear the casing.

Inaccessible locations

The same basic techniques are applied when an inaccessible location in a

producing zone dictales remote rig location, as in production located under

riverbeds, mountains, cities, etc.


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Sidetracking and straightening

This is used as a remedial operation, either to sidetrack an obstruction by

decimating the wellbore around and away from the obstruction, or to bring

the wellbore back to vertical by straightening out cooked holes.

Salt dome drilling

Directional drilling programs are also used to overcome the problems of salt

dome drilling, to reach the producing formations, which often lie

underneath the overhanging cap of the dome.

Relief wells

Directional drilling, was first applied to this type of well so that mud and

water could be pumped in to kill a wild and cratered well.

Basic hole patterns:

A carefully conceived directional drilling program on geological information,

knowledge of mud and casing program, target etc., is used to select a hole

Pattern suitable for the operation.

Type I

Is planned so that the initial deflection is obtained at a shallow depth

pproximately 1000 ft), and the angle is maintained as a "locked in," straight

approach to the target. This pattern is mainly used for moderate drilling in

areas where the producing formation is located in a single zone location and

where no intermediate casing is required. It is also used to drill deeper wells

requiring a larger internal displacement.


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Type II

Called the "S" curve pattern, is also deflected neat the surface. The drift is

maintained, as with type I, until most of the desired lateral displacement is

obtained. The hole angle is then reduced and/or returned to vertical in order

to reach the target.

Type III

Is planned such that the initial deflection is started well below the surface

and the hole angle is maintained to buttonhole target. This pattern is suited

to special situations, such as fault or salt dome drilling, or to any situation

requiring redrilling or repositioning of the bottom part of the hole.


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Deflection tools

are

- Down hole hydraulic motors (with a "bent sub").

- Jet bits.

- Whip stocks.

Deflection tools

are

- Down hole hydraulic motors (with a "bent sub").

- Jet bits.

- Whip stocks.

Design Of Directional Trajectory

The given data is:

Well head co-ordinates: X= 828750 m = 2718996 ft E

Y= 683900 m = 2243766 ft N


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Target co-ordinates: X=828660 m = 2718700 ft E

Y=684160 m = 2244619 ft N

Well Type :Type III

Kick Of Point(K.O.P) : 4698 ft

Build Up Rate(B.U.R) :2o/100 ft

Vertical Depth @ Target: 8120 ft

Displacement @ Target : 903 ft

The Design:

1-Radius Of Curvature:

R1=(180/3.14) * (1/q )

=(180/3.14) * (100/2 o )

=2865 ft

2-Angles

Tan ℓ = BA/AO

=(r1-X3)/(D3-D1)

ℓ =29.84 º

Sin Ω =r1/OB

Ω =46.55 º


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3-Maximum inclination:

= Ω - ℓ

= 16.71º

4-Length of A.R.C:

DC = /q

=16.71 º /(2 º /100)

=835.5 ft

5-Length of trajectory path at constant inclination angle:

CB = r1/(tan Ω)

= 2865/tan(46.55 ))

= 2714 ft

5-Total Measured depth at end of build

Dm = D1 + DC

= 4698 + 835.5

= 5533.5 ft

6-Horizontal depature at end of build:

X2 = r1 (1- CoS ) = 2865 (1- CoS16.71º) = 1932.25 ft 7-T.V.D at end of build:

T.V.D = D1 + (R* SIN = 4698 + (2865 * SIN 16.71º) = 5521.8 ft


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5-Total Measured depth at target:

T.M.D= Dm = D1 + DC + CB

= 4698+ 835.5+ 2714 = 8247.5 ft

Design of a horizontal trajectory

Note:

Well will be inclind dowd word as reservoir is under-saturated.

In accordance with the horizontal well drilling, there are three

sections namely:

1) Vertical section:

It is drilled from seabed (mud line) until kick-off point (KOP).

Point M . D Ft

T.V . D ft

KOP 4698 4698

End of build 5533.5 5521.8

Target 8247.5 8120


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2) Turning or curved or angle build section:

It is drilled from kick-off point (KOP) to the end-of-curve

(EOC). This section includes the first build arc, the straight

tangent, and the second build arc.

3)Tanget section:

It is drilled from the end of second build arc (EOC) to the end

of proposed distance to be drilled horizontally in the pay zone, in

accordance with the type of horizontal well to be drilled.

Design of horizontal well trajectory for S/D 13

By using Dr. Farahat's research

Assume Surface location co-ordinates:

X = 828750 m =2718996 ft E

Y =683836 m =2243556 ft N


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Target co-ordinates :

X =828660 m =2718700 ft E

Y =684160 m =2244619 ft N

Assume B.U.R = 8.5 o /100

Assume Tanget angle “I2” = 45 o

Assume Tanget angle “I3” = 90 o

assume length of straight tangent =150 ft

Vertical Depth @ Target : 8120 ft

Horizontal Displacement @ Target = 781 ft

The three sections may be designed as follows:

1) The build radius of the build arc:

R = 5730/Β

R = 5730/8.5

= 674 ft

2) The height of the first build arc:

D1 = R (Sin I2 - Sin I1)

D1 = 674*(Sin 45 - Sin 0)

= 477 ft

3) The height of the straight tangent:

D2 = L2 Cos I2

D2=150*Cos 45

=106 ft


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4)The height of the second build arc

D3 = R (Sin I3 - Sin I2)

D3 = 674(Sin 90- Sin 45)

= 198 ft

5) The length of the first section of horizontal well KOP:

KOP = TVD –( D1 + D2+D3 )

KOP = 8120 – ( 477+ 106 + 198 )

= 7340 ft

6) The displacement of the first build arc:

H1 = R (Cos I1 - Cos I2)

H1 = 674 (Cos 0 - Cos 45)

= 198 ft

7) The displacement of the straight tangent:

H2 = L2 Sin I2

H2 = 150*sin45

= 106 ft

8 )The displacement of the second build arc

H3 = R (Cos I2 - Cos I3)

H3 = 674(Cos 45 - Cos 90)

= 477 ft


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9) The length of the first build arc:

L1 = 100 (I2 - I1) / B

L1 = 100 (45 - 0) / 8.5

= 530 ft

10)The length of the second build arc

L3 = 100 (I3 – I2) / B

=100 (90 – 45) / 8.5

= 530 ft

11)the measured depth at end of the first build arc

MD1= KOP+L1

= 7340 +530

= 7870 ft

12)The measured depth at end of straight tangent

MD2 = MD1+L2

= 7870+150

= 8020 ft

13) The measured depth at the end of the second build arc:

MD3 = MD2 + L3

= 8020+530

= 8558 ft

14) The length of horizontal section or third section

H = 3000*674/800

= 2528 ft

15) The total measured depth of horizontal well

= MD3 + H

= 8558 + 2528

= 11086 ft


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Intelligent Well Completion

The Intelligent Well Completion of tomorrow will have significantly enhanced capabilities such as the following namely:

1. Sensors and flow control devices in the laterals branches 2. Downhole separation of water from oil. Also, the ability to reinject the water

downhole 3. Detection of water encroachment 4. Detection and / or prevention / removal of sand , scale , or corrosion 5. Three- phase flow measurement 6. Infinitely variable choke 7. Fiber optics developments for various uses including communication as well as

distributed measurement of temperature and pressure 8. Higher temperature capability 9. Downhole power source

10. Downhole seismic sources and / or receivers to provide in-well vertical seismic profiles (VSP) or cross-well tomography


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Drilling Problems During Drilling SID-13 and

Remedy

1. Mud losses:

Are expected while drilling 16`` hole, through the unconsolidated

sand of Post Miocene and Zeit formation.

Conventional plugging materials or suitable LCM can successfully

control this kind of losses. It is recommended for this matter to

extend circulation time and spot high viscous pill to keep the hole

clean and avoid overcharging to the formation.

Some mud losses are expected in 8 ½ `` phase while drilling in

Belayim sand, in this case non damaging plugging material are

recommended in addition to the conventional fin plugging materials.

2. Over pressure:

Is expected while drilling 12 ¼ `` hole in bottom Zeit and top

South Gharib formation. especially if high-pressure water flow


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encountered reaching value 1.8 to 1.9 kg/lit., it is recommended that

to control well with mud weight 1.82 to 1.92 kg/lit.

3. Differential sticking:

Might be encountered while drilling depleted sand zones

through 8 ½ `` of Belayim fm., this type of problem can be avoided by

keeping string always in motion and reducing as low as possible the

number of drill collar in the BHA. In addition, it is suggested to reduce

filter cake thickness and cake permeability to minimize this problem.

Mechanical sticking is expected while drilling the salt zone of South

Gharib, this type of problem can be avoided by keeping the mud salinity

little bit under saturation and also keeping string always in motion, in

case of stuck against salt zones, fresh mud batches have to be pumped

coupled with jamming action to solve this kind of problem.

Drilling problems associated with direction

well drilling and remedy

There are five main problems during drilling horizontal wells and

drain holes, namely :

1. Delivering weight to the bit.

2. Reducing torque and drag forces.

3. Hole cleaning.

4. Protection of water sensitive shale.

5. Directional control.

1- Delivering weight to the bit:-

Applying sufficient bit weight for optimum drilling rate that is


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often a problem , especially at higher angles and while drilling a

horizontal section. Conventional bit weight for efficient drilling is a

bout 2000-5000 lbf. Per inch of bit diameter. Motor assemblies drill

efficiency with less bit weight then rotary assemblies, they

compensate for bit weight with higher rotational speed of turbines

and motors.

Remedy:

Bit weight may be increased by reducing drag and torque by

using the split assembly, including the bit, motor, directional control

tools, and the non-magnetic collars, which left at the bottom of the

drill string.

And by using slick assembly (drill collars be in vertical section)

2- Reducing torque and drag forces:-

Drag is a force restricting the movement of the drill tools in

directions parallel to the well path . Torque is the force resisting

rotational movement. Drag and torque are measurements of this

frictional resistance to the movement of the drill tools .

Excess drag and torque cause directional drilling problems ,

especially in the turning and horizontal sections of horizontal well

often very severe in this well.

The drill string can be failed from tension due to excess

drag or twist off duo to excess torque.

Remedy:

Reduction of torqe & drage that by :

-Reduction of weight of BHA.

-Reducing build up rate

-Oil base or water base mud with good lubricating qualities .


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3- Hole cleaning or cutting removal:-

A particular problem that arises in the drilling horizontal wells is

the difficulty of removing rock cuttings from the horizontal section of

the well .

The source of the problem is that cuttings tend to settle in the bottom

of the hole and increase the friction in the hole , produce poor cement

Remedy:

A great improvement in removing cuttings has been an achieved by

using top drive drilling rigs . in these rigs, the drill string is rotated by a

large , geared electric or hydraulic drive motor rather than by the

conventional rotary table and Kelly.

With this arrangement , it is possible to rotate the drill string and to

circulate mud as removed from the hole . this tends to keep the drill

cutting in suspension and to provide a cleaner hole , the removal of

cuttings reduces friction between the drill pipe and the hole and reduces

the tendency for sticking .


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4- Protection of water sensitive shale:-

Shale layer frequently tend to collapse in contact with fresh water.

Remedy:

Water -base mud can be inhibited to reduce the attack on water-

sensitive shale by addition of NaCl or CaCl2 .

Or,by using of oil-base mud.

5- Directional control:-

Overcoming the force of gravity is a fundamental problem in

directional and horizontal drilling. The bottom hole assembly (BHA) is a

heavy weight hanging on the bottom of the drill string .

Remedy:

A adjustable assemblies “the steerable versions” are more flexible

for use in various situations , the steerable BHA consists of bit, down hole

motor with build in dog-leg tendency , measurement-while drilling

(MWD) .


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Average penetration rate “ R ”

Each formation is drilled by using one bit or more.

The average penetration rate can be calculated from the

following equation:

R = ∑RI *HI / Ht

Where :

RI is the penetration rate in the I-th formation.

HI is the meters drilled in the I-th formation.


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Lithology Depth OF

Formation

Depth

In

Depth

Out

Avg.

Depth

ROP Avg.Penetration

Rate

Post

Miocene

1315 35 934 899 15.91 13.41

934 1315 381 7.54

Zeit 1492 1315 1390 75 7.54 5.62

1390 1432 42 3.23

1432 1492 60 4.88

South

Gharib

1580 1492 1580 88 4.88 4.88

Belayim 1692 1580 1692 112 4.88 4.88

Kareem 1788 1692 1710 18 4.88 7.33

1710 1788 78 7.89

Rudies 2457 1788 2199 411 7.89 8.06

2199 2457 258 8.32

Nukhul

2620 2457 2486 29 8.32 3.99

2486 2620 134 3.05

Abu

Zenima

2640 2620 2640 20 3.05 3.05

Depth vs. rotating time

For every depth interval, the bit rotating time is determined,

Then :

j

iicj tT

1

Where,

Tcj : cumulative rotating time at depth, hrs

Ti : Rotating time in i-th interval, hrs


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Then,

Depth vs. cumulative rotating time is calculated as in the

following tables

Bit no. Interval (m) Depth Out,ft Rotating Time,hr Cum.Rotating Time

1 35 - 934 3064.27 56.5 56.6

1RR 934 -1390 4560.31 60.5 117.1

2RR 1390 -1432 4698.11 13 130.1

3 1432 -1710 5610.17 57 187.1

3RR 1710 - 2199 7214.48 62 249.1

3RR 2199 - 2486 8156.07 34.5 283.6

4 2486 - 2660 8726.93 57 340.6

The Trip time per trip vs. depth

Where,

Tt : Tripe time , hrs

Ts : Time for pull one stand, 4 min.

Ls : Length of stand, 93 ft.

D : Drilled footage by one

Trip time vs. depth

Depth Trip time per trip hr Rotating Time,hr

,ft

0 0 0

3064 3.11 56.5

4560 4.63 60.5

4698 4.77 13

60* 2

D

sL

sTtT


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5610 5.7 57

7214 7.33 62

8156 8.29 34.5

8727 8.87 57

Depth , ft

Total trip time, hr

0 0

3064 56.5

59.6

4560 120.1

124.7

4698 181.7

187.4

5610 249.4

256.8

7214 249.4

256.8

8156 291.3

299.6

8727 356.6

365.4

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

0 2 4 6 8 10

De

pth

(ft

)

trip time per trip (hr)


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ROTARY DRILLING RIGS

MARINE

Bottom support

barge jackup platform

Self contend tender

FLOATING

semisubmersable

Drill ship

LAND

CONVENTIONAL

MOBILE

JACKNIFE Portable mast

Drilling Rigs

The complexity of the drilling operation determines the level of

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

8000.0

9000.0

10000.0

0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 400.0

De

pth

, f

t

total trip time , hr


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under with only a few exceptions are similar and common to each.

Rigs are generally divided into two categories

1- Onshore. 2- Offshore.

Onshore (land) rigs are all similar, but offshore rigs are of five

basic types - each of which is designed to suit specific offshore

environment.

(A) LAND RIGS:

Before rig equipment is brought in, the land must be cleared

and graded, and access roads must be prepared.

Conventional platforms build in place and left over ahole after

hole completedThe most common arrangement for a land drilling

rig is the cantilever mast (sometimes called a jack-knife derrick)

(2) OFFSHORE RIGS:

1. Barge:

The barge is a shallow draft, flat-bottom vessel equipped as

an offshore drilling unit, used primarily in swampy areas. This rig

can be found operating in the swamps of river deltas , Waste

Africa or in the coastal areas of shallow lakes such as Lake

Marcaibo, Venezuela. It can be towed to the location and then

blasted to rest on the bottom.

sophistication of the various rig components. However, even with

the considerable variety of rig types, the basic components

described


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2. Jack-up:

This mobile drilling rig is designed to operate in shallow water,

generally less than 350 ft deep. Jack-up rigs, are very stable

drilling platforms because they rest on the seabed and are not

subjected to the heaving hull which may be ship-shaped,

triangular, rectangular, or irregularly shaped,When the rig is

located at a drilling location the legs(3, 4,or 5 legs) are lowered

by electric or hydraulic jacks until they rest on the seabed and the

deck is level, some 50 feet or more above the waves.

The chief disadvantages of the jack-up are its vulnerability

when being jacked up or relocated, but as a class, they are

cheaper than other mobile rigs.


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3. Fixed platforms:

There are two basic types of fixed platforms :

3. A) Piled Steel platforms:

These are conventional drilling and production platforms, and

hundreds of them are installed offshore in many parts of the

worlds. The standard configuration consists of a steal jacket

pinned to the seabed by long steel piles, surmounted by a steel

jack deck with supports equipment and accommodation buildings

or modules, one or more drilling rigs, and a helicopter deck. Piled

steel platforms have the advantage of being very stable under the

worst sea conditions, but they are virtually immobile. In shallow

waters the plied platforms is probably preferred over the jacket in

separate sections usually begins onshore.


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3. B) Gravity Structures:

This is a family of deep-water structures usually built of

reinforced concrete, but may be of steel or a combination of steel

and concrete. These structures rely on gravity to keep them stable

of the seabed. Unlike piled steel platforms, they are relatively

mobile and need no piling to hold them in place. Gravity structures

tolerate a wide range of seabed conditions. While they can be

used for development drilling and production, they also have the

advantage of being able to store oil in their structural cells. A

typical gravity structure consists of a cellular concrete or steel base

for storage or ballast, a number of vertical columns, which support

a steel deck and give access to the risers, and deck

accommodation in the form of detachable modules.


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4. Semi- Submersible rigs

These are floating drilling rigs consisting of hulls or caissons,

which carry a number of vertical stabilizing columns, support a

deck with derrick, and associated drilling equipment. Semi-

submersible drilling rigs differ principally in their displacement, hull

configuration, and the number of stabilizing columns. Most modem

type have a rectangular deck, a few are cruciform shaped, others

pentagon shaped, while some of the smaller rigs have a triangular

deck.

The semi-submersible is very stable because its center of gravity

is low in water. It can operate in deeper water than a jack-up rig.

Operational depth is limited principally by the mooring equipment

and by riser; handling problems so most semi submersibles have a

limit of abut 200 meters. However, some units have a capability of

drilling in 500 meters of water with the aid of "dynamic positioning".

This is a method of maintaining the position of a vessel with

respect to a point on the seabed by activating on-board propulsion

units in response to signals received from a position error detector.

5. Drill Ships:

These are ships or "floaters" specially constructed or converted for

deep-water drilling. Drill ships offer greater mobility than either

jack-up or semi-submersible rigs, but are not as stable when

drilling, their main advantages is an ability to drill in almost any

depth of water. Many are anchor-moored, but modem ships are

fitted with dynamic positioning equipment, which enables them to

keep on-station above the borehole. Having greater storage

capacity than other types of rigs of comparable displacement, drill


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ships are often is to drill deeper wells, operate independent of

service, and supply ships.

Drilling rig and its elements

Drilling rig is a set of mechanisms and prime movers designed for

drilling wells,

A conventional rig consists of:

a) Hoisting system, b) Rotary system,

c) Prime movers & transmissions (power system)

d) Slush pumps, e) Drilling fluid circulating system,

f) monitoring system, g) control system.

h) special marine equipment.


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A) Hoisting system consists of:

1- The derrick or the mast.

2- The draw-works.

3- The crown-block.

4- The traveling block.

5- The wire rope.

6- The hook.

The Derrick

Is a tapered tower made of steel which serves to suspend the drill

string or casing strings or place drill pipe stands during housing

operations (round trips)

The draw-works

Is the main item of any drilling rig. It serves as the power control center of the

rig. The power plant of the rig supplies motive power to the hoisting drum,

permitting reeling and unreeling of the drilling line from the hoisting


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drum,When the drilling line is wound on the hoisting, drum the travelling

block moves upward lifting the drill string. When the drilling line is unwound

from the hoisting, drum the travelling block moves downward lowering the

drill string in the borehole.

Crown block

Is mounted on the top of the derrick. it is the stationary block of the block

and tackle system.

The traveling block

Is the moving block of the system and suspended from the loops of the

wire rope which passes over all the sheaves of the two blocks one after

another


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The rotary hook

is suspended beneath the traveling block from its bail. The function of the

hook is to suspend the swivel, an elevator, while drilling, or making round

trips.

One of the ends of the wire rope is attached to the drilling rig substructure.

This end is called the dead line. The other end of the wire rope is fixed to the

hoisting drum of the draw-works. This end is called the working line or the


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drilling line.

b) Rotary system

Is intended for transmitting the rotary to the drill string to which lower

end a drilling bit is attached.

Two mechanisms constitute the rotary system of a drilling rig:

1- The rotary table or the top drive system ( TDS).

2- The swivel.

3- Kelly.

4- Drill pipe and Drill collars.

5- Bits.

The Rotary Table

Is situated in the center of the derrick floor, its function is to rotate the

drill string in the process of drilling and serve as a support for the drill


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string while round tripe are being made.

Top drive

Power swivel or power-sub installed just below aconventional

swivel can be used to replace the Kelly ,Kelly bushing & rotary

table Drilling rotation is achieved through ahydrulic motor

incorporate in the power swivel or power sub.


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The Swivel

Is probably the most ingenious element of the drilling rig. While drilling

is in progress, the swivel is suspended from the hook and suspends the

whole weight of the drill string. It permits free rotation of the drill string

and serves as the passageway for the drilling fluid from the hose lo the

drill string, which is rotated.

The Kelly

Is the first section of pipe below the swivel . the outside section of

the kelly is squared or hexagonal.

Drill pipe

Is the major portion of drill string ,it is spciefied by its outer

diameter ,weight per foot,steel grade& range length.


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Drill collar

Is the lower section of drill string . it is aheavy thick wall steel

tubular.

Bit

Is used to disintegrate the rock ,Types is(PDC bit& rock bit)

c) Slush (or Mud) pump

Usually a drilling rig is provided with two slush pumps. Their function is

to circulate drilling fluid in the process of drilling.


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d) Prime movers and transmissions:

Are necessary to provide motive power for all the mechanics of the rig,

the hoisting system, the rotary system and the mud pumps

e) Drilling fluid circulating system:

Consists of mud pits and tanks, an auxiliary pump and mechanisms for

mixing, chemical treatment and solids controls of the drilling fluid (a

mud hopper, a shaker, a hydro cyclone etc.)

f) Well control system:

Is used to prevent the uncontrolled flow of formation fluids from the wellbore .when the bit penetrate apermeable formation which is pressurized formation.


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Type of BOP's 1-Annular preventer Stop the flow from the well using aring of asynthetic rubber that contract in the fluid passage in annulus.

2-Ram preventer. Have two packing element on opposite sides that close by moving toward to each other (pipe ram,blind ram & shear ram)

g) Well monitoring system:

use devices to display :

- Penetration Rate, - pump rate,


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- Depth, - pump pressure,

- Hook load, - mud salinity,

- rotary torque, - mud density,

- gas content, - pit level

- mud temperature, - rotary speed.

Select the suitable rig type and its components

Selection of the wellhead (BOP)

The safest procedure for designing preventer pressure ratings

is to ensure that the preventer can withstand the worst pressure

condition possible. This condition occure when all drilling fluids

have been evacuated from the annulus and only low density from

fluids such as gas remain, so

a- Maximum formation pressure = 0.052*8.33*1.7*8156

= 6006 psi.

b- Determine minimum hydrostatic pressure assume only

assume gas density = 1 ppg

assume that well will be contain gas to its half section

Phmin = 0.052 * 1 * 8156 = 424 psi.

Working pressure = resultant pressure

= (Pfmax. – Phmin)

= 5582 psi

Using the API designations at 10000 psi working

pressure.


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Selection of BOP:

From data hand book page 408

1- Use Cameron ram type " U : BOP, Operating Data:

From the drilling handbook 411 page:

1-Hydril annular B.O.P.

Type GK

Size , inch 13 5/8

Working pressure , psi 10,000

Vertical bore , inch 13 5/8

Overall height flanged , inch 72 1/2

Diameter , inch 68

Volume at chamber , gal 34.53

2-Ram B.O.P. (cameron type “U”)

Nominal size , inch 13 5/8

Working pressure , psi 10,000

Vertical bore , inch 13 5/8

Overall height “Double-flanged” , inch 66 5/8

Overall length , inch Opened 173 1/2

Closed 130 1/8

Overall width , inch 29 1/4

Fluid volume to operate ram,gal To open 5.45

To close 5.8

Closing ratio 7 : 1

Top Drive Selection

Find the maximum d/s weight in mud:

d/s max. = Weight bit max. + Weight d/p max. + Weight d/c max


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Where,

Wb, Bit weight (assume: 86 lbs)

Fc , factor to compensate fraction (1.5)

d/s = (86 +194390) * 1.5 = 291714 lb

= 132 ton

From composite catalog specification of top drive are:-

specification of top drive

Type

Maximum torque

(lb/ft)

Maximum speed

(rpm)

Nominal rated load

(ton)

Maximum circulation pressure

(psi)

Approximate weight

(lb)

TD 120 P

277000

200

350

5000

10400

Hook selection

For total hook load during casing,

Determine the maximum casing capacity,

Effective weight = weight in air *bouncy factor

For 13 3/8 Wc1 = 299367*0.8675 = 259700 1b

For 9 5/8 Wc2 = 342675*.0.7834

=122 ton “The maximum”

For 7 Wc3 = 16721*0.8853

= 14804 lb


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For safety

Maximum load =1.35*122

=165 ton

So ,Hook specification

H-175

Rated load 175 tons & Weight 3170 lbs =1.4 ton

Hoisting system Design :

1-traveling block

Max. weight on T/B =Max .casing weight + weight of Hook

= 165 +1.4 =166.4 ton

From from Rotary Drilling Handbook page 140,

API working load strength 200 tons

No. of sheaves 5

Approximate weight 8210 lbs

Line size 1.125-1.25

inch

Total HL = Max .casing weight + weight of Hook +Weight of T/B

=165+1.4+3.72

= 170.12 ton

2- Hoisting cable:

Total HL = Max .casing weight + weight of Hook +Weight of T/B

=165+1.4+3.72

= 170.12 ton


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D.L =((H/L)*KN)/(E*N)

= 170.12*( 0.9615)10 / (10*0.81)

=14.2 ton

1- Consider the maximum tension in the line in tons, which

expected for the drilling operation

TF.L = H. L. / (N * E)

= 170.12 / (10*0.81) = 21 ton

2- Multiply this tension by ( 2 ) as safety factor to obtain the safe

ultimate strength of the required cable

= 42 ton

From Drilling equipment farahat book page 49 , select the

cable which has the closest ultimate strength and has the suitable

diameter for hoisting sheaves.

Select 6 * 19 classification wire rope, bright (un coated) or Drawn-

Galvanized wire independent wire rope core

Hoisting cable specification

Nominal strength

Approximate

mass, lb / ft

Nominal

diameter, in Improved plow

steel

Extra

improved

plow steel

159000 lb 138800 lb 2.89 1.25 in


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3- Crown block

Total c/ b load = Total HL + F.L.tension + D.L. tension

=170.12 +21+14.2 = 205.3 ton

From Drilling Data Handbook page 140, select the following

specification,

crown block specification

API working load strength 240 tons

No. of sheaves 6

Sheave diameter 54 inch

Approximate weight 2.1 tons

Diameter of sand line sheaves 42 inch

Drilling line 1.125- 1.25

in

4-Draw work design:

For D/W H.P input

= Brake H.P./EB

= Wm * Vmin / (33000 * EB )

where,

EB = Average efficiency factor for block and tackle system =

0.841

Vmin = Minimum expected velocity of the hook, (150 ft / min)

Wm = The total hook load, lb


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D/W H.P = 150 * 375222.92 ( 33000 *0.841 )

= 2105 hp.

From Drilling Data Hanabook page102

Draw work specification

10000 Nominal depth rating

54 " Size break rims

35 " Drum length

26 " Drum dia.

1 1/8 " Size line

35000 lb Weight

Ton miles calculations :

Drilling line is maintained in good conditions by following a

schedual Slip-and Cut program ,slipping the d/line involves loosing

the dead line anchor and placing a few feet of new line in service

from the storage reel

5- Max.Ton mile during triping:

Ton- miles during round trip @ 8156 ft =

Where , Ls : drill pipe stand length

000.640.2

)*2/1(

000.560.10

*)(* CMDWpDLsDT


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Wp = W d/p * B.F. M = total WT. of ( Hook +T/B)=21780 lb C = L * (W d/c – W d/p) *B.F. = 186 * (246 –25.6 ) *.7833 = 32116.6 lb T = 244.68 Ton-miles Max. Ton mile during casing, Is for Inter. Csg @ 8157

T = 1/2 ton mile for round trip

T = 1/2*((D(Lc+D)*Wca)/1056000)+(D*M/2640000))

Where ,

Lc :is the casing joint length (42 ft)

Wca : Wc*B.F

T = 1/2*((8156 * (42 + 8156) * 42*.7834/10560000) +

(8156 * 21780 / 2640000))

= 137.8 Ton-miles

Calculation of derrick efficiency factor :.

D.E.F. =

legloadequavelant

TNloadBC

.max*4

*)2(./.


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A-For position no.1 D.E.F. = =(N + 2) / ( N + 2) = 100 % B- For position no.2 D.E.F. = (8 + 2) / (8 + 4) = 83.33 % C- Position no.3 D.E.F. = 83.33 % , note same as position 2 D-position no.4 D.E.F.

= 71.4 %

Selection of mud pump:

Based on the last phase 8 1/2 " hole

For fast drilling in soft formation, V=180 ft/min

)4(

)2(

N

N

)224

*(

*)2(

TTTN

TN

)24

*(

*)2(

TTTN

TN

)24

*(*4

*)2(

TTN

TN


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Q = Annular area * Velocity

= (open hole diameter ^2-drill pipe diameter^2)*velocity

= (3.14/4)*(8.5^2-5^2)/144*180(ft/min) * 7.48(gal/cu ft)

= 347 gpm

For pressure loss,

∆Pt=∆Ps+∆ Pd/p+∆ Pd/c+∆P*d/p+∆ p*d/c+∆ pb

Where

∆ Pt : total pressure loss, psi

ΔPs : total pressure loss in surface connection, psi

ΔPp : total pressure loss in d/p, psi

ΔPc : total pressure loss in d/c , psi

ΔPb : total pressure loss in bit, psi

ΔPc* : total pressure loss in annulus outside d/c, psi

ΔPp*: total pressure loss in outside d/p, psi

(A) ΔPs : total pressure loss in surface connection:

From GATLIN page 99 @ Q=347 gpm & 1st system .

ΔPs =93.75 psi

(B) ΔPp : total pressure loss in d/p:

Using the following calculations

1- Calculate the critical velocity,

d

PYdV

m

mppc

2122

.3.908.108.1


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where,

Vc : critical velocity = 5.8 ft / sec.

μp : plastic viscosity = 12 c.p

ρm : mud density = 7.488 ppg

d : inside diameter d/p(ID) =4.276 in

Y.P : yield point =20

2- Calculate the actual velocity,

245.2 d

qV

where,

V : actual velocity (average velocity) ft/sec.

q: flow rate gpm

d: inside diameter of d/p inch.

V = 7.75 ft/sec

While, V >Vc

Then, turbulent flow.

3- Calculation of pressure losses

p

m dV

2970Re where; 2970(constant)

Re = 61455.7

Then,from chart Gatlin Page ( 96 )

F=0.0068 where:F;(friction factor)

So,

d

VLfP m

p8.25

2


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ΔPp = 234.285 psi

(C) ΔPc : total pressure loss in d/c:


where,

d : inside diameter of d/c (2.5")


d

PYdV

m

mppc

2122

.3.908.108.1

VC = 6.12 ft/sec.

2- Calculate the actual velocity,

245.2 d

qV

V = 22.66 ft/sec.

While, V >Vc

Then, turbulent flow.

p

m dV

2970Re

Where,

Re = 105113.8

3 - Then,from chart Gatlin Page (96 )

F=0.006

d

VLfP m

c8.25

2

where,


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L : length of d/c ,ft

P = 111psi

(D) ΔPd/p : total pressure loss in annulus outside d/p:

(at open hole section )

,Using the following calculation


d

PYdV

m

mppc

2122

.3.908.108.1

where,

d : diameter = open hole diameter – O.D of drill pipe

d = 8.5-5

= 3.5 inch

VC = 5.9 ft/sec

2-2 Calculate the actual velocity,

245.2 d

qV

Where,

D2= 8.79242-52

V = 2.71 ft/sec

While, V < Vc

Then, laminar flow.

ΔPd/p = (L*Y.P/300*d)+(up*V *L/(1500*d2))

Where ,

D2 = (8.7924-5)^2

ΔPd/p = 155.68 psi


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(F) ΔPc* : total pressure loss in annulus outside dc:


Where ,

Open hole diameter =8.5"


d

PYdV

m

mppc

2122

.3.908.108.1

Where ,

D = 8.5-7=1.5"

Vc = 6.65 ft/sec

2 -Calculate the actual velocity,

245.2 d

qV

Where ,

D2= 8.52-52

V = 6.09 ft/sec

While V < Vc “laminar flow”

ΔPd/c = (L*Y.P/300*d)+(up*V *L/(1500*d2))

Where ,

D2 = (8.5-5)^2

ΔPd/p = 20.5 psi

F- ΔPb : total pressure loss in bit:

Assume a cone bit has 3 nozzles

1-calculate the nozzle diameter as

D=((Q/n)/(2.45*V))^.5

Where,


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Q : flow rate,347 gpm

N :no. of nozzles

V : jetting velocity throught nozzle (assume 250 ft/sec)

So,d=.4345 "

For standard d= 13/32 " (From Gatlin 105)

Deq = (n*d^2)^.5

Deq = 0.704 "

Assume Bit nozzle coeff.(c) = 0.95

ΔPb = 549psi

So,

∆Pt = 1073 psi

For mud pump horsepower:

Assume

Hydraulic eff. (ŋh) = 0.9

Mechanica eff. (ŋm) = 0.85

Engine ff. (ŋe) =.87

1-Hydraulic horsepower = (Qt*Δpt)/(1714* ŋh)

=241 hp

2-Brake horsepower = (Hydraulic horsepower/ ŋm)

= 283 hp

3-Prime mover eng. Hp = (Brake horsepower *1.4)/ ŋe

=456 hp

4.*2*7430

*2

equDc

mqbP


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Derrick Desgin

For its API specification:

Determine the maximum derrick capcity

= C/B load + C/B weight

=2.1+205.3

= 207.4 ton =457234 lb

Length of derrick =1.5*93=139.5 ft

From rotary drilling handbook page (12) the derrick specifications

Derrick specifications

Derrick size No. 19

Height 140 ,ft

Base size 30 ,ft

Water table opening 7.5 , ft

Casing capacity 450,000 lbs

API capacity ,lb 950000

Pipe setback 200000 lb


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Rig selection

Using jack nife land rig with medium duty depth 4000 ft – 10000 ft

Cost for the well S/D 13

The drilling cost can be calculated from the following equation

Cf = ( Cb +( Tb + Tt)) / ΔD )

Where,

Cf = Drilling cost, $/ft

Cb = Bit cost,$

Tb = Bit rotating time, hrs

Tt =Trip time, hrs

ΔD =Footage, ft

Cr = rig rent = 833 $/hr


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Hole Tt Tb Tb+Tt, Tp,hr Cb Cost, Cum Cost

hr hr hr ,$ ,$/ft ,$

16 0 0 0 0 0 0 0

16 3.11 56.5 59.6 3.11 5000 17.8 54674.8

16 4.63 60.5 65.1 4.63 5000 39.6 113949.6

16 4.77 13 17.8 4.77 5000 143.7 133757.9

12.2 5.7 57 62.7 5.7 6000 63.9 192007.6

12.25 7.33 62 69.3 7.33 6000 39.8 255782.4

12.25 8.29 34.5 42.8 8.29 6000 44.2 297440.6

8.5 8.87 57 65.9 8.87 5000 104.9 357332.1


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0

500

1000

1500

2000

2500

3000

0 100000 200000 300000 400000

De

pth

ft

Cum cost $

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

0.0 50.0 100.0 150.0 200.0

De

pth

ft

Cost $/ft


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References:

1- Farahat, M.S., “ Horizontal well drilling technology “,

Suez Canal University, Faculty of Petroleum & Mining Eng.

2- Bourgoyne, A. T., “ Applied drilling engineering “,

Society of Petroleum engineers Rechardson, TX 1991.

3- Economides, M. J., “ Petroleum well construction “,

John wiley & Sons, 1998.

4- Gatlin C., “ Petroleum engineering “, Department of Petroleum

engineering, University of Texas, 1960.

5- Rabia, L., “ Oil well drilling engineering “,

John Wiley & Sons, 1998.

6- Rotary drilling data handbook.

7- N. J. Adams, “ Complete Well Planning Approach “.

abu rudeis – drilling engineering

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