curs foraj engleza definitiv

236
1 Drilling architecture In a wide meaning, drilling represents a complex of works necessary for the well`s execution: drilling, consolidation, investigation, testing the productive layers a.o. Drilling architecture depends on its depth (from a few dozens meters to over 13 000 m) and its objective (geological research wells, exploitation wells, special destination wells). This architecture is resumed in the well`s drilling and tubing program (acc. fig. 1.1), which details the characteristics of the different successive drilling stages among which the whole is cased, in other words, consolidated through a steel casing column. Most of the cases (for small depths), oil and gas drillings develop 2 or 3 stages, which allow the “putting together” of these casings: The surface casing (anchor casing), designed to retain the surface grounds, weakly consolidated (its length is, most frequently, from 100 to 1 000 m). This casing serves, among other things, as a support for the other casings and the eruption prevention installation. The intermediary casing (casings), necessary for the isolation of the layers and the fluids from these layers, suspected to delay and stop the normal course of the drilling. For example: the presence in the well profile of some low stability rocks, or the presence of some layers that contain abnormal pressure fluids (big or small).

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Page 1: Curs Foraj Engleza Definitiv

1

Drilling architecture

In a wide meaning, drilling represents a complex of works necessary

for the well`s execution: drilling, consolidation, investigation, testing the

productive layers a.o.

Drilling architecture depends on its depth (from a few dozens meters

to over 13 000 m) and its objective (geological research wells, exploitation

wells, special destination wells). This architecture is resumed in the well`s

drilling and tubing program (acc. fig. 1.1), which details the characteristics

of the different successive drilling stages among which the whole is cased, in

other words, consolidated through a steel casing column. Most of the cases

(for small depths), oil and gas drillings develop 2 or 3 stages, which allow

the “putting together” of these casings:

The surface casing (anchor casing), designed to retain the surface

grounds, weakly consolidated (its length is, most frequently, from 100 to

1 000 m). This casing serves, among other things, as a support for the other

casings and the eruption prevention installation.

The intermediary casing (casings), necessary for the isolation of the

layers and the fluids from these layers, suspected to delay and stop the

normal course of the drilling. For example: the presence in the well profile

of some low stability rocks, or the presence of some layers that contain

abnormal pressure fluids (big or small).

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2

Fig. 1.1. Possible architecture of a drilling (scheme)

The exploitation casing allows the isolation of the oil-bearing (gas-

bearing) zone; inside this zone an oil flowing tube will be lowered, called

extraction casing (tubing).

All these casings are cemented with a paste placed between the well

wall and the casing.

Before the proper well bore drilling begins, at its entrance is placed:

- a guiding casing, for onshore drilling;

- a conductor casing (pipe), for offshore drilling.

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3

The tubes that contain these casings are made from high resistance

steel, of lengths between 9 and 14 m (for the guiding casing), equipped on

both ends with special threads.

The wall thickness value is usually from 5,2 to 16,1 mm, and its

diameter can vary between 114 mm (4 ½ in) and 500 mm.

The lengths and diameters of different drilling phases are decided

based on the geological information and the results from the nearby wells (if

any), giving into consideration the soil nature and the fluids that could be

met during drilling.

Knowing the drilling architecture allows you to foresee: choosing the

drilling rig; duration of the operations; necessary supply; material

consumption; total duration and the final cost of the drilling.

The deepest well worldwide has reached 9 583 m. Presently, the

deepest drilling well is situated in Murmansk (Russia), with over 12 390 m

and a projected depth of 15,000 m. In our country, the record is set at 7001

Tufeni well (Baicoi) with over 7 025 m depth.

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4

2

Short history

When “colonel” Drake dig up the first oil well in 1 859, at 23 m

depth, nearby Titusville (Pennsylvania), he used the cable striking drilling

system.

This procedure, whose principle was known from the ancient times

(with 3 000 years b.C., the Chinese where digging small diameter holes to

extract salt through this procedure; the Egyptians were using tubes for

prospecting the land beneath the future pyramids: “O, those huge, but silent

pyramids/ That stand like white centuries, in stoned emptiness/ How many

things they`ve seen/ what they would say, if they only could talk” etc., etc.)

has served, in the second half of the XIX-th century, to drill the quasi-

totality of the oil wells in Pennsylvania. It remained unchallenged, as long as

well consolidated layers were crossed.

When it came to more difficult lands, the cable striking drilling

method wasn`t giving the expected results. So it appeared the hydraulic–

rotary drilling, which imposed especially after a captain J.F. Lucas realized,

through this method, a drilling at 330 m depth, in the Spindletop field, near

Beaumont (Texas), in the year 1901.

In our country, the first manual-striking drilled wells, with ash tree

drill pipe, are realized in 1861-1862, by a French company, at Mosoare, near

Târgu-Ocna, at 120-130 m. It is the first foreign concession in Romania,

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5

supported by the Lord of Unification, Alexandru Ioan Cuza, which had the

main purpose the industry development.

The hydraulic-rotary drilling is tried for the first time at Tecsani

(Moinesti) and then at Tuicani (Moreni), in 1906. But the first productive

well is drilled in 1911, at Filipestii-de-Padure, at 1 170m depth.

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3

The principle of rotary drilling and turbo-drilling

The rotary drilling method consists of using some bits (with cutters,

insertions, cone or with diamonds) on which it is operated with a weight and

a certain rotation speed. The combined action of the weight Gs and the

rotation n allows the bits with roller cone shattering the rock by crushing and

splintering (most of the times), and the bits with diamonds, by splintering

and washout (more precisely: the bits with inserted diamonds bit shatter the

rock by crushing and washout, and the ones with soaked diamonds, by

washout).

The equipment for drilling this holes is the drilling rig. Most rigs work

on the rotary system (fig. 3.1).

A bit rotates at the end of a pipe. As the bit rotates, it cuts and crushes

the rock at the bottom of the hole. The bit rotation is obtained through the

turning of the drill string (an assembly to “singles” or “joints”: drill pipes,

drill collars, joints, reduction junctions e.o.), which makes the connection

between the bit and the surface. Each joint or single is a hollow section of

pipe. By help to the Kelly (square or hexagonal), which is situated in a seal

bore with the same form in the small walls of the rotary table, the rotation of

this assembly is obtained. So: the rotary table turns the Kelly, the Kelly turns

the string, and the string turns the rotary bit.

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7

The weight on the bit is obtained by around 100 - 200 m of tubes with

high wall thickness, called drill collars, with the unitary weight of

100 - 300 daN/m and placed above the bit. These pipes, having the diameter

close to the bit`s, will maintain the verticality of the borehole.

Fig. 3.1. Rotary drilling rig: 1 – crown block; 2 – derrick; 3 – traveling block; 4 – hook; 5 – swivel; 6 – Kelly; 7 – rotary table;

8 – drawworks; 9 – mud tanks; 10 – shale shaker; 11 – annulus; 12 – joint / single; 13 – bit;

14 – Kelly hose; 15 – stand pipe; 16 - string

To eliminate detritus (the cuttings obtained when the bit shattered

rocks) from the downhole, the technique of drilling fluid circulation is being

used, invented by the French engineer M. Fauvelle, in 1845. This fluid is

called “mud”. Mud is a mixture of clay, water and chemicals. This method

consists in pumping the mud, through the interior of the drill string. The

mud passes through the bit`s ports and ascends through the annulus between

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the borehole and the drill rod and stimulates the detritus, during ascension,

towards surface (fig. 3.2).

It is often enough, before re-sending the fluid back to the circuit, to

eliminate detritus (a part is recovered by geologists, for analysis) by using

some cleaning devices, frequently represented by shale shakers, mud settlers

and hoppers.

But the mud is not only used for carrying the cuttings up to the

surface. It is also used for keeping the bit cool. The mud engineer or “mud

man” is in charge of the mud. For example, he tells the floormen how to mix

the mud at the mud tanks.

Fig. 3.2. The mud system: 1 – mud pumps; 2 – shale shaker; 3 – mud tank; 4 – Kelly hose; 5 – standpipe; 6 – annulus; 7 – bit; 8 - nozzles

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It is often necessary to pull the string out of the hole. There are

different reasons for this. Perhaps, for example, the drill bit is dull. If the bit

is dull, it must be changed. To do this, the driller and the floormen must trip

the pipe (fig. 3.3). They must pull the string out (fig. 3.3, a), change the bit

(fig. 3.3, b), and then run the string back into the hole (fig. 3.3, c). Tripping

the pipe is also called “making a round trip”. Round trips are expensive.

Oilmen make them only if they must.

a. b. c. Fig. 3.3. Trip of the string (after Sandler P.L., 1980)

A variant of this technique assures the bit rotation by using a

submersible hydraulic motor (hydrostatic or kinetic motor), placed right

above the bit (fig. 3.4).

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Fig. 3.4. The scheme of the turbodrill: 1- stator; 2- axis; 3- thrust bearing; 4- bit

In this case, the drill string stops rotating, and the power is directly

transmitted to the bit. The turbodrills (kinetic motors) conduct 100 - 250

floors, each one of them being made from a mobile and a fix element. They

have the powers of 150 HP and can provide rotary speeds of between 700

and 1000 rot/min, for pressure drops of 60 ÷ 100 bar.

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4

The drill string. Bits

4.1. The drill string

The drill string represents the connection assembly between the

shatter element (the bit) and the surface installation. It is composed of

(fig. 4.1): drill pipes 1; reductions and joints 2; drill collars 3; heavy weight

drill pipes; kelly; bottom accessories: stabilizers 4, reamer, vibration

dampeners, jars etc.

Fig. 4.1. Drill string assembly

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To project a drill string means to establish: the nominal diameter, wall

thickness, steel quality, tear and wear class etc.

Drill pipes

The outside diameter is established according to bit`s and borehole`s

diameters. Approximate values are:

Ds = 135-175 mm; Dp = 3 ½ in;

Ds = 175-200 mm; Dp = 4 or 4 ½ in;

Ds = 200-250 mm; Dp = 4 ½ or 5 in;

Ds ≥ mm; Dp = 5 or 5 ½ in.

Note: The 6 5/8 in drill pipes are rarely used, and the 2 ⅜ and 2 ⅞ in

are mostly used on instrumentation, in reduced spaces. The most used drill

pipes are the ones with the nominal diameter of 5 in and 3 ½ in.

Drill collars

The optimum diameter of the drill collars is about 75 % of the bit`s

diameter. For example: for Ds = 12 ¼ in, Dg = 0,75 · 12,25 = 9,187 in; let`s

take Dg = 9 ½ in. The drill collars diameters are:

4 ⅛; 4 ¾; 5 ¼; 6; 6 ¼; 6 ½; 6 ¾; 7; 7 ¼;

7 ½; 7 ¾; 8; 9; 9 ½; 9 ¾; 10; 11 in.

The drill collars assembly length is determined from the condition that

the thrust Gs should be realized with approximately 75 % of the drill collars

weight:

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⎟⎟⎠

⎞⎜⎜⎝

⎛−

o

fg

sg

ρρ

gqc

G=l1

, (4.1)

where:

qg is the unitary mass of drill collars;

ρf – fluid density;

ρ0 – steel density from which the drill pipes are made;

c – coefficient (c ≈ 0,75).

To increase the weight and the rigidity of the drill collars, without

reducing the flowing space of the drilling fluid (which would lead to high

pressure drops and the walls washout), there are being used drill collars with

other sections then the circular one: square, triangular or helical.

Heavy weight drill pipes

The heavy weight drill pipes have the nominal diameter identical with

the one of the normal drilling pipes, but with much thicker walls (up to

25 mm). For the usual drilling conditions, 2 or 3 pieces of heavy weight drill

pipes are inserted (or thick walls drill pipes) between the drill pipes and the

drill collars; these realize a graduate passing from the high rigidity of the

drill collars to the small rigidity of the drill pipes (for difficult drilling

conditions there can be used up to 20 pieces of heavy weight drill pipes).

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The Kelly

The Kelly is used to transmit the rotation movement from the rotary

mass to the rest of the drill string. In the oil industry are used Kellies with

hexagonal or transversal section.

The usual dimensions of the nominal diameter:

2 ½ (64); 3 (76,2); 3 ½ (88,9);

4 ¼ (108); 5 ¼ (133,3); 6 in (152,4 mm).

Stabilizers

Stabilizers are elements placed in the drill collars assembly, with the

purpose of centralizing and stabilizing the drill string in the borehole. There

are being built stabilizers with cutters, with sheaves and with diamonds.

As a general idea, the first stabilizer is placed above the bit, the

second 10 m from the first, the third 25 m and so on.

The drill string solicitations

The main solicitations the different drill string`s elements are put to

refer to:

- tension;

- torsion;

- internal pressure;

- external pressure;

- combined solicitations: - tension – torsion;

- tension – pressure.

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Simplified, we take into account the main solicitations (for a given

work situation), then the different safety coefficients are being calculated.

Solicitations have a static and a dynamic character. At the submerged motor

drilling, the drill string`s solicitation conditions are lighter; the static

character of the many solicitations mentioned is mainly manifested.

Tension

When the drill string (fig. 4.2) is suspended in a borehole filled with

drilling fluid, the effective tension

( ) ⎟⎟⎠

⎞⎜⎜⎝

⎛−

o

fggppg ρ

ρgql+gql=G 1 , (4.2)

or

( )

p

o

fggpp

t Aρρ

gql+gql=σ

⎟⎟⎠

⎞⎜⎜⎝

⎛−1

max , (4.3)

where Ap is the area of the transversal section of the drill pipes body in the

most solicited section (acc. fig. 4.2).

It is imposed that:

F t =Gg +F R ≤ F a , (4.4)

where:

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FR represents the reserve of traction (margin of over pull); regularly,

FR = 45 000 daN;

Fa – the admissible traction force:

F a=F max

cs, (4.5)

where the safety coefficient cs = 1,1.

Fig. 4.2. Drill string tension solicitation

In other words, from combining the relations (4.2) … (4.5) the

maximum drilling length results:

fp

fggRt

p fgqfgqlF

cF=l 1max

⎟⎟⎠

⎞⎜⎜⎝

⎛−− (4.6)

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Torsion

Usually, it is taken into consideration the torsion solicitation (fig. 4.3)

combined with the tension one.

The used formula to determine the torsion moment results from the

relation (API RP 7 G):

12

max

2

max

≤⎟⎟⎠

⎞⎜⎜⎝

⎛⎟⎟⎠

⎞⎜⎜⎝

⎛MM+

FF tt , (4.7)

From where

2

maxmax 1 ⎟⎟

⎞⎜⎜⎝

⎛−≤

FFMM t

t . (4.8)

Fig. 4.3. The torsion drill rod solicitation

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The external pressure (fig. 4.4)

Fig. 4.4. The external pressure drill string solicitation

In the disadvantageous situation (the drill string has the empty

interior), it is imposed that:

t

cradf c

p=pHgρ ≤ , (4.9)

where: pad is the admissible drill string collapse pressure;

pcr – the drill rod critical collapse pressure;

ct – safety collapse coefficient (ct = 1,15).

Equiresistant drill strings

For the optimum use of the available drill strings and to grow the

working depth, there are sometimes used combined drill strings.

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In this way it is calculated the traction reserve in the head of each drill

strings reach and it is imposed that the two reserves should be equal.

For example, if we have E grade drill strings and X95 grade one, then

it is calculated:

( )( ) ( )( ) fggEpEp

s

ERE fgql+gql

cF

=F −max , (4.10)

respectively,

( )( ) ( ) ( ) ( )( ) fggEpEpXpXp

s

XRX fgql+gql+gql

cF

=F −max , (4.11)

and, imposing the equality FRE = FRX, results:

( )( ) ( )

( )( ) ( ) ( ) ( )

,fgql+fgql

fgqlfgqlc

F=fgql

cF

fggfgg

fEpEpfXpXps

XfEpEp

s

E −−−− maxmax

, (4.12)

from where:

( )( ) ( )

( ) fXps

EXXp fgqc

FF=l 1maxmax ⋅

− . (4.13)

Mixed drill strings in the nominal diameter plane

In case of an existent intermediary liner, above it can be used drill

pipes of a bigger diameter. For example, for a 7 in intermediary liner, there

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can be used 3 ½ in drill pipes; properly to the precedent 9 ⅝ in casing, there

can be used 5 in drill pipes and so on.

Exercise 4.1. The conception and the calculation of a drill string

The 12 ¼ in drilling phase has to be executed from 2 000 m to

3 000 m (fig. 4.5).

Fig. 4.5. Drilling phase (scheme)

The phase is preceded by mounting a 13 ⅜ in casing at 2 000 m which

will be consolidated by a 9 ⅝ in casing.

The geological section contains:

- from 2 000 to 2 500 m, consolidated clay;

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21

- from 2 500 m to 3 000 m clay and intercalations of quartz sandstones

(gas presence!).

Tests from neighbor wells have indicated a 325 bar pressure at

2 750 m (relative pressure).

Propose, for the realization of 12 ¼ in phase, a composition of the

drill string.

Indications to ease the exercise solving:

● begin by determining the minimum necessary density of the drilling

fluid;

● choose a bit weight Gs;

● choose an adequate nominal diameter for the drill collars and

calculate their length;

● choose an adequate diameter for the drill pipes and estimate their

length, according to the main requirements.

Solution

a. The density of the drilling fluid

The drill string weight in the drilling fluid must be calculated, that`s

why we begin with calculating it`s density.

The equivalent density of the bottom pressure (Z = 2 750 m), in the

gas area, results from:

p f =ρech g Z ,

Page 22: Curs Foraj Engleza Definitiv

22

from where

./1,21/12059,81275010325 3

53f

ech dmkg=mkg==gZ

p=ρ

⋅⋅

To find out the minimum density of the drilling fluid it is applied the

“plus 5 points” rule or the “plus 10 bar” rule (in the end, the smallest value is

chosen).

Through applying the “plus 5 points” rule,

3echf dmkg=+=+ρ=ρ /1,260,051,210,05 ,

and through applying the “plus 10 bar” rule,

( ) 3f dmkg=mkg=+=ρ /1,24/1242

9,8127501010325 3

5

⋅⋅ ,

so we will choose 3/1260 mkg=ρ f .

Observation. A minimum density has been calculated, for the layer–

well equilibrium condition, written in static conditions. For the most

disadvantageous dynamic case (the extraction of the drill string), to avoid

the risk of an eruption, a higher density of the drilling fluid will be

determined 3f dmkg÷=ρ /1,3)1,28( .

Page 23: Curs Foraj Engleza Definitiv

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b. The bit weight Gs

The described terrain, starting with 2 500 m, is a part of rough and

abrasive formations category. In this case, most frequently, are being used

rotary bits with tungsten carbide insertions, for which shatter adequate

specific weight is being chosen, respectively:

Gsp = (1 ÷ 3) tf/in (from the bit diameter).

Related, for the diamond bits

Gsp = (0,6 ÷ 1,5) tf/in,

and for the ones with Stratapax

Gsp = (0,4 ÷ 1) tf/in.

In the given example, for Gsp = 3 tf/in,

Results

Gs = 3 · 12,125 = 36 tf.

c. Choosing the drill collars

Regularly, the optimum diameter of the drill collars is considered

about 75 % of the bit diameter. In our case,

Page 24: Curs Foraj Engleza Definitiv

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Dg = 0,75 · 12,125 = 9,187 in,

so we choose Dg = 9 ½ in (if the deviation tendency is reduced, drill collars

with 7 ¾ in diameter can be used), dg = 2 13/16 in (71,4 mm), qg = 327,5

kg/m.

According to relation (4.1), the drill collars necessary length

m==

ρρ

gq

G=l

o

fg

sg 175

7850126019,81327,50,75

9,813600

10,75 ⎟⎠⎞

⎜⎝⎛ −⋅⋅

⎟⎟⎠

⎞⎜⎜⎝

⎛−

,

meaning 175 : 9,15 = 19,12 (round off 19 pieces), meaning 6 steps and a

piece.

d. Choosing the drill pipes

Keeping into consideration the well diameter Ds = 12 ¼ in =

307,975 mm (so Ds > 250 mm), we choose [7] Dp = 5 in, grade E, type IEU

(internal and external upset), the connection type (tool – joint) NC – 50

(XH), unitary mass (junctions are included) qp = 31,06 kg/m, class

PREMIUM.

Characteristics: elastic limit tension: Fmax(E) = 138 600 daN; torsion

moment Mmax(E) = 4380 daN m; critical crush pressure pcr = 48,7 MPa = 487

bar.

The length lp = 3 000 – 175 = 2 825 m.

The 5 in drill pipes allow drilling of the 12 ¼ in phase, as well as the

phases before that, of the borehole (normally 17 ½ in and 8 ½ in).

Page 25: Curs Foraj Engleza Definitiv

25

e. The Kelly

We take the kelly with a 6 in nominal diameter, 5 ½ FH connection.

f. Stabilizers

We consider that 2 stabilizers of 12 ¼ in are enough (one above the

bit and the other 10 m above it).

g. The drill string more important solicitations

Tension

According to relation (4.5), for a tension reserve of FR = 45 000 daN,

cs = 1,1, ff = 0,84,

.1298

0,849,81063110,849,81327,51751045

1,110000138

1

4

max

m=,

=fgq

fgqlFc

F=lfp

fggRt

p

⋅⋅⎟⎠

⎞⎜⎝

⎛ ⋅⋅⋅−⋅−⋅

⎟⎟⎠

⎞⎜⎜⎝

⎛−−

In other words, the maximum reached depth will be

H = 1 298 + 175 = 1 473 m (in reality we need 2 825 m).

Another kind of steel, with different characteristics, will be chosen

(first of all a superior Fmax value).

Be it: class PREMIUM, X 95 grade, qp = 31,83 kg/m with Fmax(X) =

175 600 daN, Mmax(X) = 5 540 daN m, pcr = 567 bar.

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26

In this case,

.30003178,6

0,849,81833110,849,81327,51751045

1,110175,6 4

4

m>,

=lp ⋅⋅⎟⎟⎠

⎞⎜⎜⎝

⎛⋅⋅⋅−⋅−⋅

In the case of a mixed equiresistant drill string:

( ) .1451303

9,8183310,841

1,110138175,6

11,1

4

maxmax

buc)(m=,

=gqf

FF=l

p(X)f

(E)(X)p(X)

≈⋅⋅

⋅⋅−

⋅⋅⋅

lp(E) = H – lp(X) – lg = 3 000 – 1 303 – 175 = 1 522 m (≈169 pieces).

The collapse verification

For the E grade drill pipes,

bar==cp=p

t

crca 423,6

1,15487 .

For the disadvantageous situation (empty drill string), results:

pc = ρf g H = 1 260 · 9,81 · 3 000 = 370,8 bar < pca (O.K.).

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27

The appliance of torsion and tensile stress combination

At the superior side of the E grade drill pipes,

mdaN==FFMM t

t ⋅⎟⎠⎞

⎜⎝⎛−⎟⎟

⎞⎜⎜⎝

⎛−≤ 3421

13880086183143801

22

maxmax ,

the limitation in the torsion torque for the X grade drill pipes,

2

max

1 ⎟⎟⎠

⎞⎜⎜⎝

⎛−≤

FFMM t

tg ,

Ft = (lp(X) qp(X) g + lp(E) qp(E) g + lg qg g) ff =

= (1 303 · 31,83 · 9,81 + 1 522 · 31,06 · 9,81 + 175 · 327,5 · 9,81) 0,84

= 120 359 daN.

So:

mdaN=M g ⋅⎟⎠⎞

⎜⎝⎛−≤ 4033,917560012035915540

2

(the surface torsion

limitation).

4.2. Bits

The main bits types used in the hydrocarbons drilling are the ones

with roller cone and diamonds.

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28

The bits with roller cone (Sandler) are mainly constituted from 3

teethed roller cone, mounted through the roller bearings on the axes of three

bars joined by welding. A threading allows the bit spin-up with the drill

collars (fig. 4.6).

Fig. 4.6. Roller cone bit (scheme): 1- roller cone; 2 – teeth; 3 – nozzle; 4 - threads

In the case of liquid fluid circulation, for the bits with roller cone there

are two options: with internal washing (central) and, respectively, with

external washing (with steam) (the external washing is characteristic to the

modern bits).

The number and the size of the bits` heel teeth depend on the working

terrain nature. The drilling system parameters are also chosen according to

the terrain`s nature: orientative, the roller cone bits rotation speed varies

between 50 and 300 rot/min, and the specific weight comes to the order of

25 ÷ 1 000 daN/cm of bit diameter.

For example: a rough soil bit, with 311 mm diameter, could use

100 rot/min and a weight of 900 31,1 = 28 000 daN (28 tf).

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29

The advance speed of the roller cone bits is also dependent on the soil

nature and varies from 1 ÷ 2 m/h, for rough formations, at about 30 m/h, at

moist formation. The work period of the roller cone bits rarely exceeds more

than 24 hours and the extraction cause can be (most often):

- heel teeth wear (it can go up to their disappearance);

- bearings wear (sometimes can train the loss of a roller cone at the

bottom hole);

- a loss of diameter in the abrasive formations.

In rough formations, the diamond bits are mostly used.

A diamond bit is composed, mainly, of four elements: bit body 1, bit

core 2, the matrix 3 and the circulation channels 4 (fig. 4.7).

From the point of view of diamond – matrix report, there are 2 types

of bits:

- with inserted diamonds;

- with soaked diamonds.

Considering the rocks nature, big diamonds are used for weak rocks

and small diamonds for rough rocks. Orientative, there are being used

12 stones/carat for weak rocks (clays, weak marls etc.) and

12 - 15 stones/carat for hard and abrasive rocks. At the diamond bits with

soaked diamonds are used 80 - 1 000 stones/carat.

New types of diamond bits – Stratapax – require diamonds installation

on a tungsten carbide support. With these kinds of bits 700 – 800 m can be

reached, in a hundred hours. On the other side, the cost of these bits is very

high: about 25 times bigger than the cone cons bits.

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30

Fig. 4.7. Diamond bit: 1 – bit body; 2 – matrix core;

3 – matrix; 4 – circulation channel

The drilling operation, especially choosing the bit and the drilling

system parameters (thrust, rotation, flow) which will give the minimum cost,

constitutes a delicate operation. Mostly, the rocks met during drilling are

extremely heterogeneous, and the means to know them before, still limited.

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5

Wells pressure and around them

Under tectonic aspect, in a rock massif there are three main tensions:

- a vertical one σ1 = σv;

- two tensions situated in a horizontal plan, σ2 and σ3.

For homogeneous and isotropic rocks,

σ 2=σ3=σo=μ

1− μσV (5.1)

where μ is Poisson coefficient. Practical cases:

σ o

σV= 0,7. . .0,8

σ o

σV= 0,9 (5.2)

σ o

σV= 1

Because the three tensions are in compression, they are often called

pressures.

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32

So, we have:

1) Geostatic pressure (overburden):

p1 = σ1 =ρr g H, (5.3)

where: ρr is the apparent rock density;

H – the rocks string height.

It is also accepted an apparent medium density ρr = 2 300 kg/m3.

2) Sideway pushing pressure:

pc = σ2 = σ3 . (5.4)

3) Pore pressure (formation pressure) pp represents the pressure

from the rocks pores.

4) Hydrostatic pressure ph is the pressure of a water “column” which

rises from the given point to the surface:

ph = ρa g H, (5.5)

where ρa is the water field density (ρa ≈ 1,02 ÷ 1,18 kg/dm3).

Often, there are considered with normal pressure the layers whose

hydrostatic pressure belongs to a density of the mineralized water of

1,07 kg/dm3 (technological, there are considered with normal pressure the

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33

layers which can be crossed with non-weighted muds, with densities of

1 200 – 1 250 kg/m3). There are supra-normal and under-normal pressures.

5) Fissure (split) pressure:

pfis = pp + k1 (p1 – pp) + σt, (5.6)

where:

k1 is the contact pressure coefficient;

σt – rock tension resistance.

Practical situations:

k1 = 0,5 – 0,7; H < 1 500 m;

k1 = 0,75; H > 1 500 m;

k1 = 1; σt ≈ 0 for impermeable rocks and so on.

6) Pressure gradients represent the pressure variation with depth:

Γ= pH . (5.7)

During the drilling process this condition must be respected:

Γp < Γf < Γfis, (5.8)

where Γf represents the drilling fluid gradient for dynamic conditions.

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34

Abnormal pressures

The clay porosity and density measurements constitute the

compaction base.

There are different ways of abnormal pressures detection:

a. Clay density diminish

This belongs to:

- an abnormal water containment;

- an abnormal porosity.

b. Advance speed growth

Differential pressure reduction on the well sleeper is a sign of

abnormal pressures (fig. 5.1).

Fig. 5.1. Differential pressure reduction on the well sleeper

Speed vo corresponds to a Δp = pf – pp, null.

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35

c) Gas exponent variation

The importance and the composition of gas exponents (the report

C2/C3+) can vary near the abnormal pressure area.

d) Drilling fluid temperature

The sub-compaction formations and the porosity levels have thermic

conductivity and caloric capacity contrasts.

e) Drilling fluid variations properties

The rheologic properties, fluid salinity and so on can vary near a sub-

compaction area.

f) Drilling difficulties

These difficulties can be due to plastic, swelling clay.

Abnormal pressure is quantity evaluated after the deviations value

towards the normal compaction line, through two methods:

- equivalent depth method;

- correlation curbs method.

Equivalent depth method

Premise: It is considered that, excluding the temperature effect, the

marls, which have equivalent physics properties, have the same vertical

pressure value from the solid matrix psv:

psv = p1 – pp. (5.9)

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36

We consider a certain property variation, followed along the depth

(fig. 5.2).

Fig. 5.2. Depth property variation

In point A, the vertical pressure from the solid matrix

pSV(A) = ρr g H – pp. (5.10)

In point B,

pSV(B) = Hech g ρr – Hech g ρa. ` (5.11)

The equality pSV(A) = pSV(B) leads us to

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37

pp = ρr g (H – Hech) + ρa g Hech. (5.12)

Correlation curves method

After a big number of experimental dates have been processed, many

correlation curbs have been established between the pores pressure gradient

and the x/xn rapport. One of these is the ratio method, according to whom

p p=phDcn

Dco (5.13)

where: ph is the normal hydrostatic pressure;

Dcn – normal “d” exponent;

Dco – observed “d” exponent.

Note: “d “ exponent reflects the rock hardness.

Exercise 5.1. Sub-compaction areas interpretation

Being given a “chart review of pore pressure” (fig. 5.3), it is required

(asked for):

1. Select the 100 % clay areas and trace the normal compaction line on

the “d” exponent curve;

2. Determine the sub-compaction area roof;

3. At what quotation the abnormal pressure zone seems to be detected,

keeping in mind the “d” exponent and other dates presented in the

chart?

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38

4. In the 1 900 – 2 000 m interval, how is characterized the pressure

differential between the formation and the drilling fluid?

5. What is your estimate pressure at 2 050 m? (ρa = 1,02 kg/dm3).

6. Is it good a mud density of 1,39 kg/dm3 at 2 170 m? Why?

Solution

1. The normal compaction clay line:

Z = 1 100 m, “d” = 1,00,

Z = 2 150 m, “d” = 1,5.

2. Sub-compaction area roof: Z = 1 800 m.

3. BAT appearance (gases) between 1 810 and 1 830 m. Then, “d”

exponent values stabilization starting with 1 800 m; possible estimation of

the sub-compaction area roof, during drilling, around 1 800 m value.

4. The progressive growth of the gas fund. It is imposed a growth of

the drilling fluid density ρf.

5. According to (5.13),

p p=phDcn

Dco,

where:

bar,==p

,=D,=D

bar,==Hgρ=p

p

co

cn

ah

256,21,21,5205

1,21,5

20520509,811020 ⋅⋅

which belongs to an equivalent density

3pech dmkg==

Hgp

=ρ /1,2720509,81

10256,2 5

⋅⋅ .

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39

Fig. 5.3. Chart review of pore pressure

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40

A drilling fluid density ρf = 1,3 kg/dm3, can ensure the pressure

balance (equilibrium).

6. Pore pressure estimation at 2 170 m (in equivalent density units):

- the ratio method:

p = 1,02 · (1,55/1) = 1,58 kg/dm3 (equivalent density value);

- equivalent depths method:

( )nlB

Alp ΓΓ

HHΓ=Γ −− , (5.14)

( ) 3p dmkg==p /1,551,022,1

217011002,10 −− (equivalent density

value).

So: all the conditions are made so that, in this area, we have an

eruptive manifestation (sub-compaction state, progression gas fund a.o.).

Exercise 5.2. It is wanted the making of a drilling at 1 825 m depth.

From the proximity wells, are known (fig. 5.4): the limit G/T → 1 625 m;

the limit T/A → 1 750 m. At 1 750 m, the fluid pressures from the rocks

pores is 180 bar; hydrodynamic pressure phd = 7 bar. Other information:

ρt = 735 kg/dm3; ρg = 105 kg/dm3; ρa = 1 075 kg/dm3. For not producing

total losses of fluid in the layer, the overpressure must not exceed 27 bar.

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41

Questions:

1. What fluid pressure will be take to respect the “+5 points rule”?

2. What fluid density must be taken to respect the “+ 10 bar” rule?

3. If the reservoir roof starts at 1 425 m, what will be the chosen density

for the drilling fluid?

4. What is the minimum value of overpressure and at what depth?

(phd = 7 bar).

5. What is the maximum value of overpressure and at what depth?

6. What orders will be given for the reservoir traceability?

Fig. 5.4. Correlation data (scheme)

Answers:

1. The pressure gradient or the equivalent density are maximum in the

reservoir roof, due to the hydro-carbides minimum density.

Pressure at 1 500 m,

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42

pp = 180 · 105 – (1 750 – 1 625) · 9,81 · 735 – (1 625 – 1 500) · 9,81 · 105 =

169,7 bar.

The equivalent density

3pech dmkg==

Hgp

=ρ /1,1615009,81

10169,7 5

⋅⋅ .

The chosen fluid density to respect the “+5 points” rule is:

ρf = 1,16 + 0,05 = 1,12 kg/dm3.

2. When applying the “+ 10 bar” rule,

3f

f

dmkg==ρ

bar,=+=p

/1,2315009,81

10179,7

179,710169,75

⋅⋅

3. If the productive layer roof is at 1 425 m, then the layer pressure

pp = 180 · 105 – (1 750 – 1 625) · 9,81 · 735 – (1 625 – 1 425) · 9,81 · 105 =

168,92 bar,

and, in the case of the “+ 10 bar rule”,

./1,28

14259,811092178

9217810921685

3f

f

dmkg=,=ρ

bar,,=+,=p

⋅⋅

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43

4. The overpressure will be minimum in the reservoir roof (1 425 m),

in the beginning of the ascendant maneuver of the tubular material.

The borehole pressure will be

pgs = ph – phd = 1,28 · 103 · 9,81 · 1 425 – 7 · 105 = 171,92 bar,

and the layer pressure

pp = 168,92 bar,

so the minimum overpressure

S = pgs – pp = 171,92 – 168,92 = 3 bar.

5. The overpressure will be maximum in the underlayer

(H = 1 825 m), or in the descendant maneuver of the tubular material, or at

the circulation start.

The layer pressure at 1 825 m,

pp = 180 · 105 + 1 075 (1 825 – 1 750) · 9,81 = 187,94 bar;

the borehole pressure, in dynamic conditions,

pgs = ph + phd = 1 280 · 9,81 · 1 825 + 7 · 105 = 136,16 bar,

so the maximum overpressure

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44

S = pgs – pp = 48,22 bar.

6. When the overpressure exceeds 27 bar, there can be total fluid

losses in the layer (most probably at 1 825 m).

On the other side, total losses can make the necessary overpressure

not assured at 1 425 m => eruption risk.

Theoretically, a liner placed to 1 700 m is good news.

Notes:

1) Small depth is an aggravating circumstance.

2) The risk of gas appearance will be seriously analyzed.

3) The diagram p = f(H) will be traced.

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6

Drilling fluids

The main functions of the drilling fluids are:

- the bit cooling;

- bit detritus cleaning;

- detritus evacuation;

- maintaining a layer back pressure.

The important drilling fluid properties are shortly presented next.

a. Density:

ρ f =MV (6.1)

where: M is the mass;

V – drilling fluid volume.

The density is established depending on the fluid pressure from the

rocks pores and the borehole walls stability. It is accepted, generally, the “+

5 points” rule, either the “+ 10 bar” rule.

Finally,

HgΔp+p=ρ h

f . (6.2)

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46

The drilling fluid density determination is made through weighting.

b. Rheologic properties: characterize the flowing behavior of the

drilling fluid.

These are:

- viscosity (apparent, dynamic and plastic);

- shearing tension (dynamic and static);

- thixotropy.

Generally, viscosity characterizes the friction forces value between the

moving fluids particles:

pηdrdvA=F , (6.3)

η p=

F

A dvdr

, (6.4)

with ηp in [Ns/m2]

As a practical unit is used cP:

1 cP = 10-3 Ns/m2.

The shearing tension: τ = f (dv/dr),

where dv/dr is the speed gradient or the so called buckle speed.

So, there are varied rheologic flowing models.

Simplified, in figure 6.1 are presented the variations τ = f (dv/dr) for

Newtonian and Binghamian fluids.

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47

Fig. 6.1. Flowing models τ = f (dv/dr): 1 - for Newtonian fluids; 2 - Binghamian fluids.

Meanings: θ is the static shearing tension; τo – dynamic shearing tension.

The plastic viscosity and the dynamic shear tension are determined

with the help of some viscosimeters and shearometers.

Usually, is used the FANN type viscosimeter.

In the site, there is used the conventional or relative viscosity notion

(or March): it expresses the fluid flowing time from a funnel of a

standardized construction (VM – [s]).

The thixotropy is a specific drilling fluid property. Left at rest, it

gellies: through agitation, the structure is destroyed and it becomes fluid

again and s.o.

c. The filtration and clogging capacity

Filtration means the entering of a part from the liquid phase that

composes the drilling fluid, in the layer, as a result of a pressure difference.

In the same time with the entering, there takes place the solid particles

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48

deposit in the rock superficial pores and on the well walls, deposit known as

clogging (or mudding, or plugging).

The determination of the filtration and clogging capacity is made,

currently, with devices called filter presses (a large utilization has the Baroid

type filter press).

d. The sand containment: represents the percentage concentration,

expressed in volume, of solid particles in the drilling fluid, with diameters

between 0,074 mm and 3 mm, which could not be separated through the

cleaning system present at the well. The sand containment is made through

washing (elutriation) with the help of an elutriator apparatus.

e. Stability represents the drilling fluid property of not separating

itself in its component phases.

f. pH index shows the drilling fluid acidity or alkalinity degree. The

natural muds has pH = 7 … 8, and the treated ones have pH = 8 … 13.

pH measuring is made through the colorimetric or the electrometric

method.

The natural drilling mud is made out of water, to which is added a

5 ÷ 10 percent of special clay. Diverse add-ons can adjust drilling fluid

characteristics to the desired values.

So:

- poli-phosphates and tannins reduce viscosity;

- starch reduces filtrate;

- barite adjusts density etc.

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Observation:

The diverse types of drilling fluids are used depending on the crossed

soil nature.

So, for the crossing of a salt layer, there are being used salty–saturate

drilling fluids. In the case of consolidate and no water soils, air drilling can

be used. For details regarding pressure losses in the drilling fluid circuit,

fluid recipes and s.o. are recommended the papers Carnet tehnic – Forajul

sondelor [4] and Fluide de foraj si cimenturi de sonda. [12].

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7

Wells cementing and casing-off

The construction program of a well contains data referring to:

- the borehole diameter;

- the casings number and the casing-off interval;

- diameter, wall thickness, steel quality and jointing type of the tubing

casings;

- the used bits–types and diameters;

- drilling rods used–types and diameters of the composing elements;

- submerged drilling motors (if the case) – intervals and applied

methods;

- filters diameter, length and nature;

- spatial profile in the case of directional wells etc.

7.1. Casings types

Before the proper drilling begins, it is realized (manually or

mechanically) a circular or square section opening of 0,8 - 1 m with the

depth of 3 - 6 m, in which a steel casing with the diameter of 500 - 700 m is

introduced (for very deep wells more casings are used). This casing

(casings) constitutes the guiding casing. At offshore drilling a conductor

pipe exists.

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51

The anchor string (surface). Its fixing depth vary from a few tens

meters (for less deep wells) to 1 500 – 2 000 m (for very deep wells).

Main functions:

- it consolidates the borehole at the surface zone;

- it constitutes a support for the next casings (in the case that they

aren`t consolidated to the surface);

- it constitutes a support for the eruption prevention installation.

They are cemented throughout the whole length.

Their diameter varies, usually, between 10 ¾ and 16 ¾ in; at some big

depth wells, the anchor string has the diameter bigger than 20 in.

Intermediate casing string (strings) (technical). Such casings are

introduced for:

- layers isolation where drilling fluid losses occur;

- isolation of layers with high (abnormal) pressures;

- salt massifs isolation;

- isolation of layers that contain low stability rocks;

- safety, when the opened interval is too big etc.

The typical case of intermediate casings usage is the one where two

incompatible drilling fluids point of view appear: a layer with high pressure,

followed by one with low pressure or with the low fissure pressure.

The exploitation casing. It has the main functions:

- allows the movement of the exploited fluids from the productive

layer level to the surface;

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52

- allows the selective exploitation of the layers (they will be put into

communication with the casing interior, through perforations, only the layers

that interest the extraction);

- assure the realization of operations regarding the improvement of the

exploitation process: fissures, acidizings, interventions etc.

The diameter of this casing is conditioned by the fluid debit which

will be extracted and the extraction methods used. It is placed between 4 ½

and 6 5/8 in (114,3 mm and 268,27 mm).

7.2. Construction program establishment

The following factors are taking into consideration when establishing

the construction program:

The projected depth: deep wells necessitate a more complex

construction program.

Drilling purpose: at the geological research wells, the construction

program is more complex. Usually, the geological research wells will have

the research casing diameter small; casing diameter at the exploitation wells

is established, as said before, depending on the extracted fluid flow and the

extraction method.

Geological conditions: nature and physical-mechanic properties of the

well crossed rocks; the presence and the fluids nature from the rocks pores;

the pores pressure and the fissure pressure; the tectonic disturbances etc.

Spatial well profile (the borehole trajectory).

Technological factors: the method and the duration of the crossing of

a certain interval; the used drilling fluids; the new applied technology a.o.

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53

Technical factors: casings availabilities, bits, drill rods, installation

capacity etc.

Well placement: at offshore wells or the onshore ones executed

nearby more important social or economic objectives, a more safe

construction program will be adopted.

Economical factors: number, length, diameter and the casing joints

thickness; the cement quantities afferent etc.

The construction program establishment begins with establishing the

casings number and their insertion depth.

A first rule that must be respected over the non-cased intervals:

Γp < Γn < Γfis, (7.1)

where:

Γp is the pore pressure gradient;

Γn – drilling fluid pressure gradient (Γn = ρf g);

Γfis – fissure pressure gradient.

Through the graphical representation of the three parameters, results o

possible variant of the casings and casing-off intervals number (fig. 7.1).

A special attention must be given to the anchor string.

Let`s assume that:

- the weakest rocks, with the fissure gradient Γfis, are situated at the

casing shoe at Hc depth;

- casing fluid density is ρf;

- control pressure, at surface, is ps at the fissure moment.

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54

Fig. 7.1. Casings number and the casing-off interval (scheme)

In this case,

pfis = Γfis Hc = ps + ρf g H, (7.2)

from where

fis

fsc Γ

Hgρ+p=H . (7.3)

The most disadvantageous case is the complete filling of the well with

gases (fig. 7.2). In this case, the surface pressure will be:

ps = pp + ρp g H. (7.4)

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55

Fig. 7.2. Well filling with gas (scheme)

By replacing the pressure value ps from relation (7.4) in relation (7.3),

the casing tubing depth is obtained

fis

fggp

ΓHgρ+Hgρp

=H−

, (7.5)

where H is the depth of the layer that manifests.

Practically, to find out the minimum casing-off depths in the case of

gas bearing layers, the graphical method is applied.

In this case:

• the curves pp, pfis and p1 are traced;

• the so called “straight” of gases is traced (the value pp is united with

H, with ps from the surface, given by relation (7.4);

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56

• intersection between gases “straight” and the pfis line gives us the

minimum casing-off depth, which will allow the safe drilling until the depth

H.

Exercise 7.1. We want to realize a drilling at depth H = 4 000m.

There is a permanent gas danger (sandstone formation).

Also known: Γp = 0,103 bar/m; Γfis = 0,158 bar/m; relative gas

density, at the surface, is dr = 0,5 (ρair = 1,293 kg/m3). Determine the casings

number and their casing-off depths, for a good drilling realization.

Solution

a. Cashing drive shoe level “N” which will allow a safe drilling up

to the depth of 4 000 m.

The layer pressure (of the pore fluids) at depth H = 4 000 m is

pp = Γp H = 0,103 · 4 000 = 412 bar.

In the disadvantageous situation (casing is filled with gases), the

surface pressure (relation (7.4),

pv = pp - ρp g H.

The surface gas density

ρp(s) = dr ρair = 0,5 ·1,293 = 0,65 g/l,

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57

and at depth H = 4 000 m,

ρg = ρg(s) pp = 0,65 · 10-3 · 412 = 0,267 kg/l.

So,

ps = 412 – 0,267 · 9,82 · 4 000 · 10-2 = 307 bar.

Intersection of gases “straight line” with the fissure pressure line leads

to a value Z = 2 320 m.

Note. This is, as mentioned before, the minimum level for placing the

cashing drive shoe N, to execute a drilling at the depth of 4 000 m.

b. Cashing drive shoe level “N-1” which will allow a safe drilling

up to the depth of 2 320 m.

Proceeding accordingly to the precedent case, results:

pp = 2 320 · 0,103 = 239 bar, ps = 239 – 0,155 · 10-1 · 9,81 · 2 320 =

204 bar

(ρg = ρg(s) pp = 0,65 · 239 = 0,155 kg/l).

The minimum casing placing level “N-1” is Z2 = 1 430 m (acc. to

fig. 7.3).

Proceeding accordingly to the precedent case, for the casing “N-3” is

obtained Z3 = 580 m etc.

Of course, the casings number afferent to low depths (“N-4” is found

near 400 m and “N-5” near 200 m) seems somehow exaggerated. There are

special situations though, especially at offshore drilling, when the low litho-

static pressures can put serious problems concerning the fissure risk, internal

eruption etc.

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58

Fig. 7.3. The minimum casing placing level (scheme)

Observation: In the gas fields exploitation the so called CASING

POINT theory is applied. For a shut well, if a slug of gas reaches the surface

(the moving speed is about 300 m/h), the surface pressure can exceed the

preventers working pressure, and the fissure danger appears at the cashing

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59

drive shoe. For example, at 3 000 m, pp = 400 bar, then at shoe ps = 400 bar,

then at surface ps = 400 bar and s.o.

Note. Preferentially, a casing shoe is placed alongside marls or clays.

7.3. Casings and bits diameters

It is imposed the nominal diameter of the exploitation casing or, if the

reservoir is not cased, the well diameter in this area, according to the

expected flow size and the ulterior extraction method. In table 7.1 are given,

directionally, the exploitation casing nominal diameter for oil wells,

respectively gas wells.

Table 7.1. Exploitation casings diameters (approximatively)

Q, m3/24 h

40 40 - 100 100 - 150 > 150 For oil wells

Dc, mm (in)

114,3 (4 ½)

127 – 141,3 (5 – 5 ½)

141,3 – 146 (5 ½ - 5 ¾)

152, 4 – 168,3

(6 – 6 5/8) Q,

103 m3/24 h 75 75 - 250 250 - 500 > 500 For gas

wells Dc, mm

(in) 114,3 (4 ½)

114,3 – 146 (4 1/2 – 5

3/4)

146 – 177,8 (5 3/4– 7)

168 (6 5/8)

In our country it is commonly used the exploitation casing of 5 ½ in.

Further on, the other casings diameters and the afferent bits are

established, in an unique process, through the method “from toe to top”.

Between the well`s walls and the casings column`s, a radial clearance

δ must exist, respectively a casing ratio R, big enough for introducing the

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60

casing without difficulties and an efficient cementing of the annular space

(acc. to fig. 7.4). So, δ and R are expressed through the relations:

- radial play

δ=Ds− Dm

2 , (7.6)

casing ratio

s

ms

s

DD=Dδ=R

D2− , (7.7)

where: Ds is the well diameter (bit`s);

Dm – casing diameter over female union.

Fig. 7.4. Establishing the bit`s and casing`s diameters

In table 7.2 are presented, directionally, the values of δ and R for

different parameters.

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Table 7.2. Orientation values for δ and R

Normal conditions Complicated conditionsCasings` diameters,

in (mm) δ, mm R δ, mm R

Dc < 8 5/8 (219,1) 8 - 18 0,05 – 0,065 10 - 25 0,06 – 0,09

Dc > 8 5/8 (219,1) 20 - 40 0,06 – 0,09 25 - 50 0,08 – 0,10

Sometimes larger limits are permitted [1] (acc. to table 7.3).

Table 7.3. Orientation values for δ

Dc, in 4 ½ - 5 5 ½ -

6 5/8

7 – 7 5/8 8 5/8 –

9 5/8

10 ¾ -

11 ¾

12 ¾ -

14 ¾

16 – 20

δ, mm 7 – 10 10 – 15 15 – 20 20 – 25 25 – 35 35 – 40 40 – 60

So,

Ds = Dm + 2δ. (7.8)

The internal diameter of the precedent casing is established with the

formula

2a+D=D 'si , (7.9)

where a is the radial clearance between the bit and the casing`s interior:

a = 3 … 5 mm (bits with sheaves and diamonds);

a = 5 … 8 mm (bits with cutters).

After [1], a = 2 … 4 mm.

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It is wanted like Dd < Di, where Dd is the drift diameter (the internal

guaranteed passing diameter) of the casings made with the fabrication laws

(fig. 7.5).

Fig. 7.5. Respecting the condition Dd < Di (scheme)

The wall thickness, steel quality and the joints type will be established

depending on the nature and size of the solicitations that act upon the

casings.

Cemented intervals

The nature and composition of the cementing paste and of cement

stone are established depending on the nature of the rocks that must be

isolated, pressure and nature of fluids from the pores, the fissure pressure,

geostatic temperature etc.

Concerning the cemented intervals length, as a general idea, it is

followed the isolation of the permeable layers where sludge losses occur,

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63

casings` anticorrosive protection, increasing their resistance, avoiding

dangerous solicitations during exploitation etc.

The anchor string is cemented on all its length, with the purpose of:

− consolidating the unstable surface formations;

− isolating the phreatic water;

− ensuring a stable and safe support for the eruption preventing

installation and the following casings.

The other casings are cemented with at least 200 m above the last

permeable layer.

At the gas wells, it is recommended cementing of all the casings, on

all the length.

At the exploitation wells, in areas poorly known, it is used to cement

about 100 m in the interior of the precedent casing.

Exercise 7.2. The risk of localized gases presence

It is wanted the setting of the construction program bases for a

research vertical well, whose objective is Meotianul 2 (towards 4 000 m gas

appearance is possible). It is about, mainly, an clay series from 0 to 4 200 m,

passing through sand–sandstone or carbonatic reservoirs:

− drinkable water reservoir between 100 and 150 m;

− secondary reservoir: gases risk between 1 100 m and 1 400 m in a

sand-sandstone intercalation;

− main reservoir: gases appearance after 3 900 m, in a carbonatic series.

Pressures system in the pores:

− 0,098 bar/m in Levantin + Dacian (0 ÷1 000 m);

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− 0,108 bar in Pontian (1 000 ÷ 3 000 m);

− 0,118 bar/m in Meotian (3 000 ÷4 000 m).

Fissure pressure system (LOT):

− 0,128 bar/m (0 ÷750 m);

− 0,142 bar/m (750 ÷1 500 m);

− 0,156 – 0,176 bar/m (1 500 ÷2 500 m) (grows from 0,156 to

0,176 bar/m from 1 500 to 2 000 m);

− 0,176 bar/m (2 500 ÷4 000 m);

Requirements:

1. Propose and justify the levels for different casings.

2. Establish the drilling diameters and those of casings knowing that the

main tank will be drilled with a borehole of 6 in.

Solution.

1. It is traced, depending on the problem`s data, the variations of the

layer pressure pp, of the fissure pressure pfis and the lithostatic ones p1

depending on the depth.

The gases “lines” for the depths of 4 000 m and 1 400 m lead to the

following minimum placing casing shoe levels (fig. 7.6): 2 420 respectively

1 040 m.

So, it is imposed:

a. The anchor casing shoe should be between 150 and 200 m;

preferential drilling stop in an clay section.

b. The intermediate casing shoe 1 between 1 050 m and 1 075 m:

− minimum level resulted from the gases “line” for H = 1 400 m;

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− maximum level, imposed by the head (roof) of the gas zone is

1 100 m;

− preferential drilling stop in an clay section.

c. The intermediate casing shoe 2 towards 1 600 m:

- shutting down the gases and the sandy – sandstone formations;

- drilling will be stopped after we ensured that the clay zone was

penetrated.

d. The intermediate casing shoe 3 (or exploitation one) will be at

about 50 – 75 m under the first carbonic geological pointer,

approximately at 3 965 m:

- minimum level, imposed by the gases “line” accordingly to the

4 000 m depth, is 2 420 m;

- maximum level, imposed by the gases zone body is 4 000 m;

- drilling shutting down after the reasonable crossing of the carbonatic

pointers.

e. Liner between 3 865 m and 4 200 m(of course, an option is a free

borehole, in the case of consolidated formations).

Possible variants in the case of not confirming the gases presence in

the 1 100 – 1 400 m interval:

− the intermediate casing shoe 2 can attain towards 2 500 m, and the

reservoir tracing will be made without the proper placing of the

intermediate casing 3;

− the placing of the intermediate casing shoe 2 at 3 965 m;

− attacking the drilling phase for the zone of after casing the

intermediate casing in reduced diameter (afterwards enlargement, if

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gases presence is confirmed, or remaining in reduced diameter,

otherwise).

Fig. 7.6. The levels for different casings

The presented variants have, each of them, advantages and

disadvantages regarding:

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− the stability of the phases crossed by drilling;

− the casings number and weight;

− the detritus circulation and surface bringing;

− the production capacity evaluation etc.

Still, the initial program remains… interesting.

Casings and bits diameters are established through the “downside

up” method.

So, if the liner nominal diameter is 4 ½ in, then:

Dse = Dm + 2δ = 123,8 + 2 · 8 = 139,8 mm (acc. [7], pg 145).

For casings with Buttress SC joints:

Di3 = Dse + 2a = 139,8 + 2 · 3 = 145,8 mm;

D3 = 145,8 + 2 · 13,7 = 173,2 mm;

Be it D3 = 177,8 mm (7 in).

Proceeding like the last time, it results:

1. F 26 in + T 18 5/8 in (or 20 in) at 175 m;

2. F 17 1/2 in + T 13 3/8 in at 1 060 m;

3. F 12 1/4 in + T 9 5/8 in at 1 600 m;

4. F 8 1/2 in + T 7 in at 3 965 m;

5. F 6 in + T 4 1/2 in (liner) from 3 865 to 4 200 m.

To increase the breaking resistance (from the internal pressure) the

liner can be extended to the surface.

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7.4. Making the casings

In the making of a casing the following elements must exist: the shoe,

the baffle collar, the casings and, eventually, centralizers and wall

scratchers. The main elements are, obviously, the casings.

The casing columns. Are made of steels with qualities of a large

value range. Important characteristics (besides the nature and the steel

quality): nominal diameter D; wall thickness t; length l (appreciated with or

without jointing); the unitary weight q (unitary mass); jointing type; fabric

procedure.

From the making of point of view, the casing columns can be welded

or laminated (hot drawing). The majority belongs to the last category. They

are made of carbide steel or allied steel (steel from electric furnace,

Siemens-Martin, Bessemer etc.); with the purpose of obtaining bigger

resistances, after making they must pass different thermic treatments:

quenching and comeback, normalization or normalization and comeback etc.

In different standards or norms, steel quality is expressed through its

degree or brand. In table 7.4 are presented the main characteristics of casings

steels [2] (acc. also to [7]).

More precisely, the main used steel types at the present time are those

of degrees K – 55, C – 75, L – 80, N – 80, C – 90, C – 95, P – 110, Q – 125.

The letter after the symbol means the elastic flowing limit (yield

point) in 103 psi. For example, for the steel J – 55, the yiel point is 55 000

psi = 3 870 bar (1 psi ≈ 0,07 bar).

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Table 7.4. Main characteristics of casings steels [2]

Minimum resistance

10-5 N/m2 Minimum stretch, %

Country Steel degree

(brand) At flowing σc At breaking σr δ5

I 55 3 900 5 300 16 II 75 5 600 7 100 12

ROMANIA

III 75 7 800 8 800 12

H – 40 2 810 4 220 27 J – 55 3 870 5 270 2,5 K – 55 3 780 6 680 18 C – 75 5 70 6 680 18 N – 80 5 60 7 030 17 C – 95 6 680 7 590 16 P – 110 7 730 8 790 14

SUA

V – 150 10 550 11 250 11,5

C 3 200 5 500 18 D 3 800 6 500 16 K 5 000 7 000 12 E 5 500 7 500 12 L 6 500 8 000 12 M 7 500 9 000 12

RUSIA

P 9 500 11 000 12

In the case of H2S presence (embrittlement through H2S), there is the

danger of breaking for stress values, inferior to theoretical limits. The

embrittlement appears mostly for values of the yiear point higher than 80

000 psi and reduced temperature (for temperatures T > 150o C there are no

problems, indifferent the steel type). In this situation, steels with inferior

degrees have a higher embrittlement through H2S resistance. At the same

time, the best steels are the ones that posses a smooth and homogenous

structure. Special steels: L – 80 VH, C – 90 VHS, C – 95 VHS (after

Vallourec documentation).

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70

In the case of corrosion due to CO2 presence, it is recommended the

use of special steels, like: C – 75 VC, L – 80 VC, N – 80 VC (13 % Cr),

L – 80 VCM (9 % Cr + 1 % Mo) or VS 22; VS 28; VS 42 N. There are 14

nominal diameters of the casings columns: 4 ½; 5; 5 ½; 6 5/8; 7; 7 5/8;

9 5/8; 10 ¾; 11 ¾; 13 3/8; 16; 18 5/8; and 20 in.

The casings jointing to form columns is realized through screwing on

(in very rare cases is used the screw on by welding).

The main joints types are:

− triangular screwed connection (short or long);

− Buttress;

− Extreme Line;

− screwed connection in two levels (in ladder);

− screwed connections for high diameter casings;

− non-screwed connection.

The triangular screwed connection can be short (STC) or long

(LTC). The first has a reduced mechanical resistance and is used only for the

low depths wells.

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71

The Butress joint has four types:

• normal:

• special-special clearance OD (outside diameter is more reduced):

• superior steel connection:

• VAM joint: metal on metal leak proof, very good.

The screwed connection to this jointing type is trapezium.

Extreme Line joint has no screwed connection. The thread

(trapezoidal type) is made directly in the shouldered heads. The leak proof is

metal on metal.

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Screwed connection with a 2 level thread (ladder) is of 2 types:

− NCT – K – casing connection Hydrill;

− FJ – P – with threads realized directly from the body.

Screwed connection for high diameters casings: VETCO (from 16 to

30 in).

Non- screwed connections. Are fast connections for high diamters.

Types:

− ALT – the highest performance;

− ATD;

− ST – the most economic.

7.5. Casing accessories

The shoe is positioned on the inferior side of the casing and, by its

rounded form, ensures the casing introduction. There are simple shoes and

shoes with retaining valve. The best ones are the shoes with retaining valve,

with a special construction, which opens when the pressure difference

between the upside and the downside areas exceeds a certain pre-established

value.

The baffle collar is placed 10 - 30 m above the shoe, inside a casings

connection female union. It is made out of a light milling material. The

collar`s role is a double one:

− safety, at introduction;

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73

− stopping the cement plug above the shoe.

The centralizers are mounted on the exterior of the casing column, in

its inferior zone or on the entire future cemented area. Their purpose is to

maintain the concentric casing with the borehole. There are different

centralizers types: with straight cutters, with undulate cutters, with curved

cutters etc.

The wall scratchers are mounted on the casing`s exterior, in its

inferior area. The purpose: removing, by scraping, the filter cake from the

well`s walls.

The hanger and the casing launcher are used to suspend the liner

(of the lost casing) in the interior of the precedent casing.

7.6. Casing columns solicitations

The most important solicitations that the casing columns are subject to

are: external pressure, the tension and the internal pressure. To these must be

added the solicitations that accidentally appear: bending (in deviate

boreholes), compression (buckling), torsion, time degradation, corrosion,

improper use of the maneuver tools etc.

The external pressure. It appears due to a specific weight difference

of the fluids from the casing`s interior and the exterior, or due to a rock`s

buckle crossed by the well.

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If the value of the external pressure exceeds the casing`s resistance on this

solicitation, the immediate consequence is its collapse (or ovalisation). So it

is determined a critical collapse pressure for vary situations:

a. in the plastic domain:

22

1

11

2

⎟⎠⎞

⎜⎝⎛ −

⋅−

tD

tDμ

E=pcr (7.10)

where: μ is Poisson coefficient (μ = 0,3);

E – the longitudinal elasticity module of the casing`s material;

D – external diameter;

t – casing wall thickness.

D/t values, for which the formula (7.10) stands, are given in table 7.5.

Table 7.5. D/t values Steel type H – 40 J – 55 (D) C – 75 (E) N – 80 P – 110

D/t > 42,70 37,20 32,05 31,05 26,20

b. in the transition domain, from plastic to elastic

⎟⎠⎞

⎜⎝⎛ − B

tDAσ=p ccr /

(7.11)

where σc is the minimum flowing limit for collapse.

In table 7.6 are presented the application limits for D/t values and for

A, B and σc values.

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Table 7.6. Values D/t, A, B, σc for the transition domain [2]

Steel

brand

H – 40 J – 55 (D) C – 75 (E) N – 80 P – 110

D/t 26,62 …

42,70

24,90 …

37,20

22,46 …

31,05

22,46 …

31,05

22,20 …

26,20

A 2,047 1,990 1,987 1,098 2,075

B · 102 3,125 3,600 4,170 4,340 5,350

σc · 10-5,

N/m2

2 810 3 870 5 270 5 620 7 730

c. in the plastic domain,

CBtD

Aσ=p ''

ccr −⎟⎟⎠

⎞⎜⎜⎝

⎛−

/ (7.12)

The values for D/t, A`, B` and C are given in table 7.7.

Table 7.7. Values D/t, A, B, σc for the plastic domain [2]

Steel brand H – 40 J – 55 (D) C – 75 (E) N – 80 P – 110

D/t 14,44 …

26,62

14,80 …

24,90

13,67 … 23 13,38 …

22,46

12,42 …

22,20

A 2,950 2,990 3,060 3,070 3,180

B` · 102 4,63 5,41 6,42 6,67 8,20

C · 10-5,

N/m2

53 86 127 137 201

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76

d. in the pure plastic domain,

CBtD

Aσ=p ''

ccr −⎟⎟⎠

⎞⎜⎜⎝

⎛−

/ (7.13)

The values for D/t are given in table 7.8.

Table 7.8. Values D/t for the pure plastic domain [2] Steel brand H – 40 J – 55 (D) C – 75 (E) N – 80 P – 110

D/t < 14,44 14,80 13,67 13,38 12,42

Most of the casings used in the drilling domain (over 70 %) integrate

in the transition domain limits. There are, in the speciality literature, also

calculus formulas of the critical collapse pressure available for all domains

(for example, Sarkisov relation).

The traction. It appears due to: own casings weight, pressure and

temperature variation, bending, accidental causes.

a. The traction force due to its own weight

⎟⎟⎠

⎞⎜⎜⎝

⎛−∑

o

fiiq ρ

ρql=F 1 , (7.13)

where: li represents the casings lengths that form the column (i = 1 … n);

qi – corresponding unitary weights;

ρf, ρo – drilling fluid densities, respectively the steel`s from which the

casings are made of.

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In the case of casing introducing maneuver, the traction force

becomes

⎟⎟⎠

⎞⎜⎜⎝

⎛− f

gtv+F=Fi

iqq1 1 (7.14)

where: vi represents the introduction speed;

ti – acceleration time at introduction;

f – the friction coefficient of casing with the borehole`s walls;

g – gravitational acceleration.

If, for certain reasons, the casing must be extracted on a certain

portion, relation (7.14) becomes:

⎟⎟⎠

⎞⎜⎜⎝

⎛f+

gtv+F=Fe

eqq2 1 (7.15)

where index e refers to the extraction maneuver.

In the case of sudden casing falls,

( ) ⎥⎥⎦

⎢⎢⎣

− 2fo

qq3 LgρρhE++F=F 611 , (7.16)

where: h represents the casing falling height;

L – casing length.

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b. The traction force due to temperature variation appears in case

of casings considered with the heads trapped (in cement – lower part; in the

leak proof installation – surface).

By definition, the force due to temperature variation

Aσ=F tt (7.17)

where A represents the casing`s transversal section area, and the unitary

stress

σt = ε E, (7.18)

in which the specific buckle

LΔL=ε . (7.19)

The linear stretch due to temperature variation, according to the linear

thermic dilatation theory,

ΔL = L α ΔT, (7.20)

where: α represents the linear thermic dilatation coefficient

(α = 1,23 ·10-5 1/oC);

ΔT – temperature variation.

Replacing the relations (7.20), (7.19) and (7.18) in (7.17) leads to

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Ft = E A α ΔT. (7.21)

Note. In reality, the phenomenon is much more complex.

Unexpectedly high values appear at the specific circumferential buckles

[13].

c. The traction force due to internal pressure appears as an effect

of the framed position of the casing ends. Under the action of the internal

pressure pi, in the casing wall appears an unitary loading

t2Dpμ=σ i , (7.22)

from where the traction force due to internal pressure

t2

ADpμ=Aσ=F ip ⋅ (7.23)

The internal pressure. It is spoken about the solicitation at internal

pressure when the pressure from the casing`s interior exceeds the one from

the exterior (putting in production of some high pressures layers; creating

some high pressures inside the casing from technical or technological

reasons – f.e. layer samples etc.).

When the internal pressures exceeds the resistance value at this

solicitation, its breaking or twist-off occurs. The limit pressure value for all

casings type is determined with Barlow`s relation:

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80

Dt=p ci σ2 , (7.24)

where σc is the yield point of casing.

Other solicitations

The compression solicitation is produced in case of shouldering the

casing on the bottom hole or in areas with thresholds, increasing the pressure

behind the casing etc. Thus are produced longitudinal creations or joints

destructions.

The longitudinal bending solicitation is produced in case of deviate

wells or directional wells. The bending unitary stress, that is produced in the

casing, is given by relation

R2DE=σinc (7.25)

where R is the curved radius of the directional borehole.

7.7. Establishing the casings columns profile

As mentioned before, the main solicitations to which the casing

columns are submissive to are: external pressure, traction force and internal

pressure.

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81

One of the methods to form the casings profile is building the pressure

difference curves

Δpe = pe – pi , (7.26)

Respectively

Δpi = pi – pe, (7.27)

for the most disadvantageous conditions.

Thus, it is built the pressure difference curve Δpe (fig 7.7), for total

scavenging (the anchor casing and the exploitation casing), respectively

partial scavenging. Or it is considered that, in the interior, we have sea water

(for intermediate casings). Of course, there must be analyzed very well the

crossing conditions of the divers drilling phases and, for difficult situations,

total scavenging can be accepted in the intermediate casings situation too.

Also, the well type must be taken into consideration: exploration well

or production well. In the first case, it can be accepted for all casings the

most difficult situation: the casing is empty inside.

Note. It can be accepted, as a general rule, empty inside casing (the

case of exploration wells) or partial scavenging (the case of production wells

– intermediate casings).

The casings used and the reaches lengths are determined through the

intersection of the afferent lines of the admissible collapse pressures with the

pressure curve Δpe.

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Fig. 7.7. The curve of the pressures difference Δpe and Δpi

In every profile section must be respected the condition

Δpe ≤ Δpea, (7.28)

where

t

tea c

p=p , (7.29)

where pt is the critical collapse pressure.

It is accepted ct = 1,125 for non-cemented areas and ct = 0,85 for

cemented ones.

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83

Now is build the curve Δpi for the most disadvantageous situations

(acc. to fig. 7.7, 7.8 and 7.9):

- the casing is filled with gases;

- it is taking into account the maximum pressure during the pressure

tests (samples) time.

In exterior it is considered that we have water with the density ρa = 1

000 kg/m3.

In the case when the casing is filled with gases, the surface pressure

(fig. 7.8)

ps = pp – ρg g H. (7.30)

Fig. 7.8. The curve of the pressure difference Δpi (column filled with gases)

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84

Analogous, for the case when the pressure is maximum at the surface,

when the pressure tests are taken (fig. 7.9).

Fig. 7.9. Differential pressure curve Δpi (pressure samples)

In every section must be respected the condition

Δpi ≤ Δpia, (7.31)

where

pia=psp

csp, (7.32)

where psp is the critical buckle pressure, and csp – the safety coefficient

(csp = 1,1).

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85

Afterwards, it verifies if the established profile resists to traction. The

imposed condition:

Fq ≤ Fad, (7.33)

where

F ad=F max

cs, (7.34)

where: Fad is the admissible snatching? or breaking force in the dangerous

section (casing body or jointing);

Fmax – maximum snatching or breaking force (casing body or

jointing);

cs - the safety coefficient (cs = 1,6 for H ≤ 3 500 m; cs = 1,75 for

H > 3 500 m).

At the jointed casings with standard thread, Fad represents (usually)

the admissible snatching force from the thread, and at the casings with

special threads - admissible breaking force (body, female union or male

union; more precisely, the smallest of them).

Note. Is to be verified if the resistance reduction at buckling, due to

compression, or, at collapse, due to traction, is not becoming dangerous.

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86

Simplified calculus

Are taken into consideration separately the external pressure and the

traction. Is to be verified at internal pressure, for dangerous section

(sections).

The calculation starts from toe to top. As, at the casing`s shoe, the

external pressure is maximum (we consider the case of total scavenging),

then

pef = ρf g H1 ≤ pad, (7.35)

from where results the maximum depth up to which it can be cased with a

casing of wall thickness t1 chosen depending on pad1.

For the next wall thickness from STANDARD,

H 2=pad 2

ρ f g (7.36)

so, the length of the first reach

l1 = H – H2, (7.37)

and of reach i,

li = Hi – Hi+1 and so on. (7.38)

Results a profile according to figure 7.10.

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87

Fig. 7.10. Casing profile (external pressure solicitation)

This calculus methodology applies especially to liners and

exploitation (production) columns. Concerning the traction, the calculation

begins from toe to top. Initially, there are picked the casings with the

admissible traction force Fad1 the lowest. The maximum length of the first

reach will be

gq

F=l ad

1

11 , (7.39)

where q1 is the unitary casings mass.

For the second reach,

l1 q1 g + l2 q2 g ≤ Fad2 (7.40)

from where, at the limit,

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88

l2=F ad 2− l1q1 g

q2 g , (7.41)

and for reach i,

( )

gqFF

=gq

gqlF=l

i

iadadi

i

iiadii

1−−−∑ . (7.42)

The casing`s profile in according to figure 7.11.

Fig. 7.11. Casing profile (traction solicitation)

This calculus methodology applies especially to the anchor string and

some intermediate casings.

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89

Next is the internal pressure checking for the most disadvantageous

situation: the casing is full of gases or the maximum pressure is taken, at

surface, during the pressures tests.

The easiest way would be the graphical one.

It is traced pef = f(H), picking a safety coefficient cs = 1,125 for non-

cemented portions, or “cs” = 0,85 for the cemented ones (but only for the

production wells!) – acc. to fig. 7.12.

Fig. 7.12. Establishing the casing profile through the graphical way

For different values of the available admissible pressure, results the

divers casing depths, respectively the reaches lengths (acc. to fig. 7.12).

Next is the checking at traction and internal pressure (or the traction

calculus is being made, followed by accepting the steel type, the wall

thickness and so on, for the most disadvantageous situations).

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90

Casings calculus at composed solicitations

It supposes the simultaneous taking into consideration, of the traction

and external pressure solicitations, based on the specific maximum buckle

mechanical work theory.

It results the relation

σ c2=σ t

2 +σz2− σ tσ z , (7.43)

where: σt is the normal tension on the radius direction (external pressure

component);

σz - the normal tension on the vertical direction (traction component);

σc – the yield point of the casing`s material.

By dividing with σc2 and replacing σt : σc = y, results

y2 + z2 – yz = 1, (7.44)

which, in a yOz plane, represents the plasticity ellipse equation, with the

axes inclined at 45o (acc. to fig. 7.13).

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91

Fig. 7.13. The plasticity ellipse

Interesting is domain IV (tension and external pressure), where

ad

eff

ad

ef

c

t

pHgρ

=pp

=σσ=y , (7.45)

c

q

c

z

σAF

=σσ=z . (7.46)

The calculation can be made directly, or iterative. There exists, in this

case too, casing diagrams (fig. 7.14).

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92

Fig. 7.14. Casing diagram [2]

7.8. Casing operation execution

Before realizing the introduction of a casings column, some

preparatory works are made both at the surface, as well as in the borehole.

At the surface, a drilling rig control is being made (derrick,

substructure, compressors, eruption preventers etc.), are brought and

prepared the tools used for casing-off – coupling tongs, elevators,

breakdown etc. They are transported to the well and the casings columns are

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93

prepared, depending of wall thickness and material qualities, keeping into

consideration the introduction order in the well.

The well is controlled on all its depth and is corrected (after the bit

reached the bottom hole, a more prolonged circulation is made).

For the proper casing operation, the following will be known:

− keeping the casing introduction order;

− controlling each casing`s interior, with the help of a drift mandrel;

− making the welding, in points, at the first joints, to prevent their break

out;

− the carefully execution of each casing`s screwing on;

− the thread lubrication at the surface of the hole;

− launching the casing with such a speed, therefore not producing

dangerous hydrodynamic pressures, which could affect the layer –

well equilibrium;

− making circulations at certain intervals, to evacuate the filter cake of

the well;

− maneuvering the casing column at the end of the operation, with the

purpose of removing filter cake by the wall scratchers; in the same

time, the drilling fluid circulation is made.

Application 7.3. The conception and calculus of a casing column, at solicitations

A vertical drilling is made at the depth of 3 655 m.

The construction program contains:

● F 24 in + T 16 in at 500 m (anchor casing);

● F 14 ¾ in + T 10 ¾ in at 2 200 m (intermediate casing);

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94

● F 9 5/8 in + T 7 5/8 in at 3 500 m (exploitation column); gas

presence !

It is asked making a simplified casing calculation.

Solution.

1) Phase: drilling 24 in – casing 16 in

This casing will be object to some “easy” drillings: the risk of gas

presence doesn`t exist in the next phase, nor of the sulfured hydrogen and so

on. It will be cemented on all its length.

So, we will take the following safety coefficients:

− at collapse: “ct” = 0,85;

− at breaking: csp = 1,1;

− at traction: cs = 1,6.

a. External pressure calculation

We consider that on the casing exterior we have sea water with the

density ρa = 1 020 kg/m3, and in the interior the casing is empty.

In these conditions, the pressure is determined

pe = ρf g H cs = 1 020 · 9,81 · 500 · 0,85 = 42,5 bar = 4,25 MPa.

It is found [7] the minimum collapse resistance of the 16 in casings as

being 4,4 MPa; we further decide the utilization of steel 94,9 # K 55

(94,9 daN/m represents the unitary casing weight).

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95

b. Internal pressure verifying

We consider, at the exterior of the casing, sea water with density ρa =

1 020 kg/m3, and at the interior the maximum pressure from the casing head

from the time LOT (Leak of Test), executed with a mud with density

ρf = 1 100 kg/m3.

The maximum value inside the casing, during the pressure test, was

120 bar (12 MPa). As, for steel K 55, the maximum breaking pressure is

15,5 MPa, the verifying in the wanted sense is obvious.

c. Traction verifying

For q1 = 94,9 daN/m,

daN=F<daN==cρρ

ql=F maxso

f1t 000450652911,6

78501100194,950011 ⎟

⎠⎞

⎜⎝⎛ −⋅⋅⎟⎟

⎞⎜⎜⎝

⎛− .

In conclusion: for casing-off the anchor casing of 16 in, we will use a

steel of degree K 55, unitary weight q = 94,9 daN/m, wall thickness

t = 9,5 mm, connector API – STC.

2) Phase: drilling 14 ¾ in – casing 10 ¾ in

This casing will be cemented on a length of about 450 m. The

following safety coefficients will be taken:

- collapse: ct = 1,125 (non-cemented area),

“ct” = 0,85 (cemented area);

- breaking: csp = 1,1;

- traction: cs = 1,75.

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96

a. External pressure calculation

We will consider the casing empty inside, and at its exterior a drilling

fluid with density ρf = 1 200 kg/m3.

Thus

pe = ρf g H cs = 1 200 · 9,81 · 2 200 · 0,85 = 220 bar = 22 MPa.

We pick a tube of 10 ¾ in, 51 # N 80. (of course, next, there can still

be chosen other wall thicknesses or steel qualities; it seems that the cost

prices are not changing substantially, so, for commodity, it can be accepted

only steel with the degree N-80).

b. Internal pressure verifying

We consider, at the exterior of the casing, sea water with density

ρa = 1 020 kg/m3, and at the interior, due to gas presence,

ps = pp – ρg g H = 310 bar = 31 MPa.

As the admissible breaking resistance for steel N – 80 # 51 is

pcr

1,1= 40,4

1,1= 36,7 ,

so ps < pad => O.K.

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97

c. Traction verifying

For the dangerous section, from the surface, the maximum traction

force is about 159 331 daN, so way inferior to the maximum traction

resistance value Fmax = 518 000 daN (Fad = 296 000 daN).

We will propose then, for the upper part, a tube with the wall

thickness smaller. Be it 10 ¾ in, 40,5 # N 80 which could be cased up to the

depth (according to the solicitation at external pressure) which results from:

s

crf c

pHgρ ≤ (now cs = 1,25), pcr

cs= 119

1,25= 95,2bar ,

so

m=H 8099,8112001092,5 5

⋅⋅≤ .

In conclusion, the casing of 10 ¾ in will have the following

composition:

● from 0 – 1 000 m: 10 ¾ in; 40,5 # N 80;

● from 1 000 – 2 200 m: 10 ¾ in; 51 # N 80;

● connectors VAM, because of the gas presence.

3) Phase: drilling 9 5/8 in – casing 7 5/8 in

Considering the gas presence, this casing will be cemented on a height

of approximately 200 m inside the last casing.

Safety coefficients:

- collapse: ct = 1,125 from 0 to 2 030 m;

“ct” = 0,85 from 2 030 to 3 500 m;

- breaking: csp = 1,1;

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98

- traction: cs = 1,75.

a. External pressure calculation

Talking about exploitation casing, we will consider it, for calculation

at this solicitation, as being empty inside; at the exterior we have a drilling

fluid with density ρf = 1 550 kg/m3.

For H = 2 030 m, pef = 2 030 · 1 550 · 9,81 = 308,7 bar, and for H = 3

500 m, pef = 532,2 bar; knowing that ct = 1,125 (0 ÷ 2 030 m) and “ct” = 0,85

(2 030 ÷ 3 500 m), it is proposed:

● from 0 – 1 300 m: 7 5/8 in; 26,4 # N 80;

● from 1 300 – 2 300 m: 7 5/8 in; 29,7 # C 90;

● from 2 300 – 3 500 m: 7 5/8 in; 33,7 # N 80.

It is verified for internal pressure and traction (O.K).

7.9. Wells cementing

The wells cementing is made in the following purposes: consolidation

improvement through casing; stop the unwanted fluid circulation in the back

of the casing; sending the axial casing loads towards the rocks massif,

following the casing-cement-layer adherence etc.

In other words, a good cementing means a good mechanical cement

rock resistance and a good leak proof made by it, of the annular space.

The cementings made right after the casing-off are called primary

cementings, and the remedy ones secondary cementings. At those, it must

be added some special cementing and cement plug.

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99

7.9.1. Cementing methods

According to the casing situation and the realization mode of the

proper operation, more primary cementing methods distinguish.

a. One stage cementing

Is the most used cementing method. It is used in the case of entire

casings cementing, on all their length or only on a certain interval (from the

inferior side, to the surface).

The method presumes the use of two plugs: one is launched before,

and the second, after pumping the cement slurry. The first is a plug with

membrane, and the second, massive plug. They are made of an easy milling

material. In figure 7.15 is presented, simplified, the scheme of cementing

with two plugs.

To prevent the contamination of the cement paste with drilling fluid

and for a much better removal, in the annular space, of the mud by the

cement paste, after launching the first plug, between the cement paste and

the well fluid is placed an overflush (the volume of this plug belongs to a

height, in the annular space, of 150 … 200 m).

As overflushes, are used: simple water, saline solutions, acid or basic

solutions, water with detergents and spreaders, oil based overflushes,

suspensions, tampon fluids etc. In the case of some layers with gases, it is

often recommended a delayed cementation (original Romanian method).

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100

Fig. 7.15. The scheme of cementing with 2 plugs [2]

Basically, it is about a cementation with 2 plugs, leaded in such a way

that the operation length to be the same with the admissible time of plug-in

beginning. After the pumping shutdown, the cement paste catches very fast,

forming an homogenous mass that does not allow the gas migration.

b. Stage cementing (in steps)

It presumes pumping the cement paste in two or more turns. Situations

when the stage cementing is useful:

− in case of casings with high lengths, that will be cemented on their

entire length or on a very big interval;

− when layers with abnormally big pressures alternate with low pressure

layers;

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101

− at the exploitation casings, through which will be separated more

productive areas in which impermeable rocks exist;

− in case of high volumes of cement paste, and discharge fluid, that

would lead to a great number of aggregates, self-containers etc., with

a big placement space etc.

In figure 7.16 is presented the principle scheme in the case of stage

cementing (2 stages).

Fig. 7.16. The scheme of cementing in 2 stages [2]: a – finishing pumping the cement paste for the inferior stage; b – pumping the cement paste for the superior stage; c – finalizing cementing the inferior stage (by moving the cementing nipple,

the lateral ports of the special female union open); d – the end of the cementing the superior stage

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102

The first installment is made analogous with the method earlier

presented.

For cementing the other installments, at certain heights, the casing has

a special female union with ports that close and open with the help of some

plugs (balls) or “keys” (the guiding marks 1 … 4 from figure 7.16). The

staged cementing can be continuous (case above) or with interruptions (in

stages).

c. Cementing of lost casing (liner)

Launching the liners is made with the help of the drill string. Between

the lost casing and the string is placed the hanger and the casing launcher

(fig. 7.17). After cementing the liner (always, this is cemented on its entire

length), the drill pipes are withdrawing with the prolonging pipe above the

liner and the paste excess is eliminated, usually by reverse circulation.

d. Cementing with drill pipes

In the case of high diameter casings (16 – 30 in), is used, most often,

cementing with drill pipes (fig. 7.18).

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103

Fig. 7.17. Scheme Fig. 7.18. Scheme of casings of liner cementing [1]. cementing through drill pipes

d. Cementing the casing with perforations

It is the case of some exploitation casings perforated before the

cementing. So the cementing will be done, obviously, above the

perforations. In this sense, above the perforated casing zone is installed a

cementing nipple, which has lateral ports. Under the nipple is installed a

plate, and above it a retaining valve. Then, the cementing goes analogous the

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104

two plugs cementing. To avoid the cement paste entering the perforated

zone, the nipple has, on its exterior, a membrane.

From the secondary cementings, the most frequent case is the

cementing through perforations.

f. Cemented the casing through perforations

In the purpose of fixing a primary cementing, the cementing through

perforations is used. In this case, the casing is perforated on the superior and

inferior side of the zone that will be cemented (fig. 7.19).

Fig. 7.19. Cementing through perforations [5]: 1 – casing; 2 – drill pipe; 3 – packer;

4 – inferior perforations; 5 – superior perforations

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105

g. Cement plugs

They meant the cement filling of the well on a length of 100 ÷ 200 m,

at the shoe or above, for:

− temporary or permanent isolation of some inferior layers, for testing

or exploiting the superior ones;

− changing the direction of the borehole at a certain depth;

− preserving or abandoning the well;

− isolating some zones with circulation losses and so on.

In this purpose it is used:

− equilibrium cementing;

− retaining plug cementing;

− bailer cementing.

The equilibrium cementing is the most used methodology. The cement

paste, placed between two plugs, is inserted through the drill pipes or the

extraction pipes (fig. 7.20).

h. Cementing under pressure

This method can be included in the category of special cementing (for

example, for some rocks impermeability). Can be realized with, or without

retainer (first case presumes packers utilization).

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106

Fig. 7.20. Equilibrium cementing [1]

7.9.2. Factors that determine the success of a cementing

The cementing success is complete if the cement collar from the

annular space is leak proof, resistant and rocks and casings adherent.

The factors on which a cementing success depends are: natural

(geological); technical; technological.

From the natural factors we quote: the nature of the fluids stacked in

the crossed formations; mineralization of the underground waters;

temperature and pressure conditions. Regarding the exothermic effect of

cement, must be specified the fact that, in the connection time, takes place a

process of the casing`s dilatation-contraction, expressed quantitative by

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107

ΔV = V αv ΔT, (7.47)

where: ΔV represents the volume dilatation of the casings material;

αv – the thermic volume dilatation coefficient: αv = f(εc;εa);

ΔT – temperature variation.

The temperature variation in time is according to figure 7.21.

The technical factors refer to the annular space geometry (the size of

the radial play casing - well, the casing eccentricity, presence of the key

holes, well bending) as well as at the casings column equipping (centralizers

utilization, wall scratchers, turbulizers, exterior casing packers etc.)

As there are no casing holes perfectly vertical, the casings will be

forced to curve and there will appear contact points with the borehole walls.

These contact zones casing-wall cannot be, obviously, eliminated through

secondary cementing.

Fig. 7.21. Variation ΔT = f(t)

According to Halliburton (World Oil, march 1989), a secondary

successful cementing is the one that should never be made.

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108

A few conditions that must be respected, in order to obtain a good

cementing:

− realization of some boreholes that would admit tubing ratios

(r = (Ds –D)/2) of 20 – 40 mm;

− cleaning and degreasing the casings exterior;

− equipping the casing with distant centralizers, in conformity with the

well caliper and the diagram of the lateral forces born in the casing.

The technological factors refer to: nature and properties of the drilling

fluid displaced and of the cement paste; the nature of the overflush; the

flowing in the annular space, the method and the cementing technology etc.

As a general idea, it is admitted the fact that a good mud displacement by the

cement paste, in the annular space, is obtained with the help of the turbulent

flowing.

7.9.3. The calculus of cementing with plugs

On an usual casing cementing are determined: the cement paste

volume; the material quantities; the fluid discharge (press through) volume;

the aggregates working pressure; cementing operation duration; cementing

aggregates number. To establish these elements the final cementing moment

is taken into consideration (fig. 7.22).

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109

Fig. 7.22. The final cementing moment (scheme)

a. The cement paste volume (acc. to fig. 7.22):

( ) hdπ+HkDDπ=V icespc2

122

44− , (7.48)

where k1 is a coefficient that considers the borehole irregularities. It is

determined from the well caliper measurements. Usually k1 = 1,1 - 1,2.

b. Material quantities. For a cement paste volume unit (1 m3), the

cement and water quantities result from

va + vc = 1 (7.49) va ρa + vc ρc = ρpc,

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110

from where, then,

Gc = ρc Vpc k2, (7.50)

Va = va Vpc k2, (7.51)

where k2 is a preparation losses coefficient (k2 = 1,01 – 1,1) (this, assuming

that the cement paste density ρpc is known; analogous other relations are

found when we have, for example, water-cement factor m).

If the cement paste is prepared from a mixture of solid materials

(cement and sand, cement and diatomite, cement and bentonite, cement and

ash etc.) and water, then the calculation of a cement paste volume unit is

made with the relations:

- for cement quantity

⎟⎟⎠

⎞⎜⎜⎝

⎛−−

s

a

c

a

apcc

ρρ

k+

ρρ

ρρ=q

111; (7.52)

- for solid material, added to cement, material

qs=qc

k ; (7.53)

- for water quantity

⎥⎦

⎤⎢⎣

⎡⎟⎠⎞

⎜⎝⎛−

k+qρ

ρ=v cpc

aa

111 , (7.54)

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111

where k represents the rapport, in weight, between the cement quantities and

the added material, and ρs – added material density.

c. Discharge fluid volume (acc. to fig. 7.22),

( )hHdπ=V ir −2

4. (7.55)

d. Aggregates working pressures pa

The possible variation of the working pressure depending on the

pumped fluid volume in the well is represented in figure 7.23.

Fig. 7.23. Variation pa = f(V) [2]

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112

In the main points 1, 2, 3 and 4, the aggregates working pressure will

be:

p1 = pθ + pc1, (7.56)

p2 = pc2 = pc1, (7.57)

p3 = pc3 – pdif3, (7.58)

p4 = pc4 = pdif4, (7.59)

where the necessary pressure for the friction beating from the circulation

system pc can be calculated, simplified, with the help of the following semi-

empirical relations:

pc = 0,01 H + 8, [bar] (7.60)

in case of pumping with one or two cementing aggregates, respectively

pc = 0,02 H + 16, [bar] (7.61)

in the case of pumping with mare cementing aggregates (the depth H will be

taken in meters).

Note. In reality, for calculating the pressure pc the following relation

must be taken into consideration

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113

pc = pce + pci + pm, (7.62)

where: pce is the necessary pressure for beating the frictions in the annular

space;

pci - the necessary pressure for beating the frictions inside the casing;

pm - the necessary pressure for beating the frictions in the cementing

manifold.

There are different calculus relations for pc [1-4].

Then, the necessary pressure for beating the gel resistance in the

annular space

DD

=ps

θe −θH4 , (7.63)

respectively in the casing interior

i

θi d=p θH4 , (7.64)

θ being the fluid static friction tension.

At the end of the cementing operation the aggregates pressure is

maximum:

pmax = p4 = pc4 + (Hc – h)( ρpc – ρf) g. (7.65)

Depending on this pressure pmax is chosen the type of cementing

aggregate that will be next used. It is necessary that the aggregate maximum

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114

pressure at the lowest speed (the 1st speed) is higher then the cementing

maximum pressure, which means

paI > pmax. (7.66)

In the same time,

pext < pfis. (7.67)

In table 7.9 are presented the main characteristics of some cementing-

fissure aggregates in Romania.

Table 7.9. Cementing and fissure aggregates range

pa, bar Qa, 1/min Plunger diameter, mm Plunger diameter, mm

Aggregate

type 90 100 115 127 90 100 115 127

AC – 350 - 350 250 200 - 686 935 1 158

AC – 400 B 400 320 240 - 717 855 1 171 -

AC - 500 500 400 300 - 722 892 1 178 -

ACF – 700 A* - 700 550 - - 1 220 1 620

ACF – 700 B** - 700 550 - - 1 220 1 620

* Autosasiu Tatra ** Autosasiu Roman

e. Cementing operation duration

In the assumption that the flow is constantly maintained for the divers

pumped fluids, then the cementing duration

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115

( )∑ min1510 ÷+QV=t

i

ic , (7.68)

where Vi is the fluid volume pumped with the flow Qi. There have been

added 10 ÷ 15 minutes for the lines washing, connections changing,

launching the second plug etc.

Note: To determine the times Vi/Qi, the graphic from figure 7.23 will

be taken into consideration.

f. Cementing aggregates number

They are determined from the condition of realizing the operation in a

certain time limit, or from the condition of realizing the operation with

certain cement paste pumping speeds in the annular space.

In the first case,

1+tt=nap

ca , (7.69)

where tap represents the time limit of the crisis beginning.

In the second case, it is considered that the turbulent flowing ensures a

good displacement of the mud by the cement paste.

If the cement paste is taken as binghamian fluid, then the generalized

Reynolds number at flowing through the annular space

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116

( )( )

⎥⎥⎦

⎢⎢⎣

⎡ −

−×

pcsi

spc

ssipce

ηDDτ+η

DDvρ=R

v61 0

. (7.70)

When at limit, for Re* = 2 300, the flowing becomes turbulent; it

results a critical flowing speed

( ) ( ) pc

ecr

spc

ecrpc

spc

ecrpccr

Rτ+DD

Rη+

DDRη

vρ6ρ2ρ2

0

2

⎥⎥⎦

⎢⎢⎣

−−≥ . (7.71)

Usually,

vcr = 1,5 m/s (the case of anchor columns and the intermediate ones);

vcr = 1,8 … 3 m/s (exploitation casing).

7.9.4. Cementing efficiency evaluation

Is made through:

− temperature logging (thermometry);

− acoustic logging;

− radioactive logging;

− leak proof samples (tightness tests).

For example, regarding the temperature logging, there are being made

recordings of the temperature before and after the cementing (fig. 7.24).

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117

Fig. 7.24. Cementing efficiency evaluation through thermometry [1]

Application 7.4. Cementing calculation example

Be it a casing of 9 5/8 in, with the casings medium thickness of

10 mm, cased in a well with the depth of 2 500 m and the diameter

Ds = 311 mm. The cementing depth is Hc = 1 500 m. The baffle nipple of the

cementing plugs is placed at h = 20 m above the shoe. The well mud

characteristics: density ρf = 1 400 kg/m3, plastic viscosity ηp = 20 cP =

20 · 10-3 N·s/m2, dynamic shearing tension τo = 5 N/m2.

Solution. The cement paste minimum density ρpc = 1 400 + 200 =

1 600 kg/m3. The admitted density ρpc = 1 800 kg/m3. Then the plastic

viscosity ηpc = 46 cP and the dynamic shearing tension τopc = 14 N/m2.

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118

a. Cement paste volume:

( )

( ) .6348200,24454

15000,24450,3111,14

443222

2221

m,=π+π

=hdπ+HDDkπ=V icspc

⋅⋅⋅−⋅

b. Unitary material quantities, admitting ρc = 3 150 kg/m3:

qc= 31501800− 10003150− 1000

= 1172kg /m3 pc ,

v a=3150− 18003150− 1000

= 0,628 m3 /m3 pc .

The total powder cement quantity, with k2 = 1,05,

Mc = k2 ρc Vpc = 1,05 · 1 172 · 48,63 = 59 840 kg;

the total water volume,

Va = k2 ρc Vpc = 1,05 · 0,628 · 48,63 = 32,07 m3.

c. Discharge fluid volume,

( ) ( ) 322 169982025000,224544

m,=π=hHdπ=V ir −⋅− .

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119

Notes.

• If a separation plug is placed, with a height in the annular space of hs

= 200 m,. then its volume is

( ) ( ) 32222 5,82000,24450,31144

m=π=hDDπ=V sss ⋅−− .

Its density must be intermediate, so ρs = 1 600 kg/m3.

• The self-containment number, of 12 t,

54,981200059840

12000≈==M=n c

nc .

• In the paste pumping period, it is usually taken an aggregate for 2

containers. So, to round off we would need 3 aggregates.

• The paste pumping period from the cement found in a self-

containment is 17 – 20 min. We presume the use of an aggregate,

successively, for 2 containers. There will work three preparation mixers. So

the paste preparing period will be about 35 min.

The medium pumping flow

sl=l==t

V=Q

c

pcp /23/min1389,4

3548630 .

d. Aggregates working pressure

At the end of the cementing operation,

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120

pmax = pc4 + (Hc – h) (ρpc – ρf) g.

Simplified,

pc4 = 0,02 H + 16 = 0,02 · 2 500 +16 = 66 bar,

so

pmax = 66 · 105 + (1 500 – 20) (1 800 – 1400) 9,81 = 124,07 bar.

We propose the aggregate AC – 350, with the plunger diameter of 127

mm, for which

pa = 200 bar > pmax.

e. Let`s assume that we want to determine the aggregates number

from the condition of turbulence realization in the annular space.

The critical flowing speed, according to relation (7.71), when at limit,

( ) ( )./2,221,780,442

18006230014

0,24450,3111800223001046

0,24450,3111800223001046

233

sm=+

=++=vcr ⋅⋅

⎥⎦

⎤⎢⎣

⎡−⋅

⋅⋅−⋅

⋅⋅ −−

The critical flow

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121

( ) ( )/min,3864/64,4/0,0644

0,24450,3114

2,24

3

2222

l=sl=sm

=π=DDπv=Av=Q scrsicrcr

=

−⋅−

and the aggregates number

)3504(1115838641

max

−ACagregate+=+QQ=n cr

a .

f. Cementing duration

We admit a volumetric aggregate efficiency ηv = 80 %.

So, in the case of 127 mm plungers, the real flow

Qr = Qt ηv = 1 158 · 0,8 = 926,4 l/min = 15, 44 l/s.

The approximate cementing duration,

( )

min,7615263515926,44

101699835

min1510

3

=++=+,+

=÷+Qn

V+QV

=Taa

r

a

pcc

⋅⋅=

,

with 15 minutes for the intermediate operations.

g. The paste pumping time:

Tmin = 1,5 Tc = 1,5 · 76 = 114 min,

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Tmax = 1,5 Tmin = 1,5 · 114 = 171 min.

Note: In every operation moment the conditions must be verified:

pp < pag,

pint ≤ pia,

pext < pfis,

where: pp is the pumping pressure;

pag – aggregate maximum pressure at pumping flow;

pint – effective pressure in the casing interior;

pia – casing admissible internal pressure;

pext – effective pressure in the casing exterior.

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8

Drilling system

8.1. Efficiency drilling indexes

There are quantitative and qualitative efficiency indexes. The

qualitative indexes refer to:

− realization of the geophysical and geological investigation program;

− ensuring the projected trajectory;

− opening the productive layers without affecting the characteristics and

their productivity;

− accomplishing the objective without any complications and so on.

Quantitative indexes are:

− the bit effective working duration ts;

− the advance of the tool hs;

− the drilling speeds;

− the drilling cost etc.

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8.1.2. Drilling speeds

a. Mechanical speed (advance) of the tool:

− instantaneous:

]/[, hmdtdh=vm (8.1)

− medium (on the bit or on an interval H):

]/[, hmth=v

s

sm (8.2)

respectively

]/[, hmTH=v

sm (8.3)

where: h represents the depth;

t – time;

hs – drilling interval made by a bit;

ts – effective work duration of the bit on the bottom .

b. Drilling rate:

− bit run:

ms t+t

h=th=v0

0 , [m/h] (8.4)

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125

− on an interval H:

ms T+T

H=v 240 , [m/I day] (8.5)

c. Technical speed:

p

t TH=v 720 , [m/IMP] (8.6)

where:

Tp = Ts + Tm +Ta represents the productive time, respectively:

Ts – drilling time;

Tm – maneuver time;

Ta – the necessary time for measuring the deviation, casing-off,

cementing, layers testing etc.;

I day - installation – day (specific index);

IMP – installation – month – productive (specific index).

d. Working rate (commercial)

c

c TH=v 720 , [m/IMW] (8.7)

where:

Tc is the calendar time;

Tn – not productive time (technical and organizer stops);

IMW – installation - month - in work.

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126

e. Cyclic speed: the time for installing and taking to pieces is also

taken into consideration.

f. Drilling cost. Most often it matters the cost of drilled meter

calculated on the run:

,h

)t+(t+cc+c=c msiffs

m [lei/m] (8.8)

where: cs is the bit cost, lei;

cff – mud drilling cost;

ci – installation schedule cost, lei/hour.

The expression (8.8) can be write

o

fsm vC+a+a=c , (8.9)

where: as is the unitary bit cost, lei;

af – unitary mud drilling cost;

C – work installation day cost, lei/I day

Drilling system means a correlation of the drilling parameters to

obtain an efficient drilling program. The drilling system parameters are:

− mechanical: weight on bit and rotation speed;

− hydraulics: flow, jet speed, impact force, drilling fluid qualities etc.

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8.2. Mechanical parameters determination

8.2.1. Roller (cone) bit

Simplified, the bit weight

Gs = Gsp Ds, (8.10)

where Gsp is the specific weight, tf/in (Gsp = 0,6 … 2,5 tf/in).

Rotation speed. Orientatively, n = 50 ÷ 100 rot/min, in the case of

hard and very hard rocks, respectively n = 90 ÷ 250 rot/min, for weak rocks.

There are also correlations like

bs na=G , (8.11)

where the constants a and b have the values from table 8.1 [2].

Table 8.1. Correlation Gs – n for roller cone bits (milled teeth)

Bit type S SM M and MA MT and

MTA

T and TA

a 36,1 362,6 287,0 148,4 158,9

b 0,593 0,771 0,756 1,170 1,000

n, rot/min 90 … 250 60 … 80 40 … 100 40 … 80 35 … 70

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128

There are different optimization methods of the mechanical

parameters of the drilling system, like: Gale –Woods, Preston – Moore,

Young – Don Murphy, Bourgoyne – Young etc.

8.2.2. Diamond bits:

3

8min

pC=Gs ; 3

18max

pC=Gs , [daN] (8.12)

sD

=n 66810min ;

sD=n 44828

max , [rot/min] (8.13)

where: C is the total karats number afferent the bit;

p – number of stones per karat;

Ds – bit diameter, mm.

8.3. Determining the hydraulic parameters of the drilling system

Drilling fluid type and composition. Are chosen depending on the

specific requirements of the well, first of all the nature and situation the

rocks that will be crossed, are in. As a general idea:

− for clay rocks a fluid will be used which, through his filtrate, will not

produce swelling out phenomenon;

− for gypsum, anhydrites and coal, a fluid with the filtrate as small as

possible: inhibitive or emulsion type;

− for soluble rocks, a fluid insensitive to contamination;

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129

− for productive rocks, a fluid that, through his filtrate will not affect the

rocks permeability (for example, oil based fluids).

Fluid flow. We remind the drilling fluid role:

1 – cooling the bit;

2 – cleaning the bit of detritus;

3 – evacuating the detritus;

4 – maintaining an overpressure on the layer and so on.

The answer to requirements 2 and 3 (implicit condition 1 will be

solved) supposes to calculate a pick up of bottom flow Qdeg and an

evacuation flow Qev, and the minimum technological flow

Qmin = max (Qdeg, Qev). (8.14)

The pick up of bottom hole flow

Qdeg = Qsp At, (8.15)

where At is the well sleeper area:

2

4 st D=A π , (8.16)

and the specific flow Qsp = 0,045 - 0,060 dm3/s·cm2.

The evacuation flow

Qev = vsi Asi, (8.17)

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130

where Asi is the annular space area in the biggest section (right next to the

drill pipes):

)(4

22pssi DD=A −π , (8.18)

and vsi is the minimum flowing speed in the annular space. Orientatively,

vsi = 0,4 - 1,3 m/s.

More precisely, in the case of binghamin fluid, it imposes that the

flowing system in the annular space to be turbulent, so at limit,

( )( )

⎥⎥⎦

⎢⎢⎣

⎡ −

−×

pcsi

spc

ssife

ηDDτ+η

DDvρ=R

v61 0

= 2 300, (8.19)

from where results the minimum flowing speed in the annular space vsi.

Fluid jets speed. In the case of jet drilling it is considered that a

good drilling efficiency supposes jet speeds between 70 and 130 m/s, and the

distance between the jet orifice and the bottom hole,

l0 ≤ 6 d0, (8.20)

where d0 is the chokes diameter.

When establishing the hydraulic system it is proceeded like this:

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131

− it is chosen, from the pump flows, a flow Qp bigger or equal to the

minimum technological flow (the corresponding pressure of this flow

is pp);

− it is chosen the jet speed for which, at the wells drilled in similar

conditions, good advancing speeds (most often between

80 – 100 m/s);

− the jet orifices?(bottom-hole choke) area is calculated

j

pd v

Q=A , (8.21)

and then the orifice diameter

i

A=d dd π

4 , (8.22)

where i represents the bottom-hole chokes number (normally, i = 3);

− from the existent chokes are chosen those with the closest diameter to

the calculated one (it is necessary that the chokes to be of the same

diameter or close diameters);

− for the chosen chokes it is re-calculated area Ad and the jets speed;

− if the values are in that domain, the bit will be equipped with the

established chokes;

− are then calculated the pressure break-downs in the circulation system

(exclusively the bit) pci` and in the bit orifices psi, with the help of the

relations:

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132

2'21

' )( pnpci QgL=p ραα + , (8.23)

2

2

2ϕρ jf

si

v=p , (8.24)

where: Lp represents the drill pipes length:

Lp = H – lg; (8.25)

lg – drill collars weight;

α1 – pressure break-downs? coefficient in the circulation system

elements depending on depth (interior and exterior of the drill pipes and the

special joints);

α2` - pressure break-downs coefficient the circulation system elements

independent of the depth: pumps manifold, charger, hose, hydraulic head,

the kelly and also interior and exterior of the drill collars;

φ – flowing coefficient through the bit chokes (for modern chokes

φ = 0,95);

Then it is compared the pressure break-downs sum with the working

pressure of the pumps at the respective flow; if

'cip + psi < pp , (8.26)

results that the established system corresponds to these conditions; in

contrary case, are chosen chokes of higher diameters; at the speeds vj < 10

m/s the jet drilling is no longer realized, but conventional drilling.

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133

Note. In the case of diamond bits, the circulation channels afferent

diamonds cooling, can be assimilated with some chokes, realizing pressure

break-downs of 50 - 80 bar.

For realizing an efficient drilling it is recommended that at the bottom

hole? to ensure a minimum specific power Phsp = 368 W/cm2 (0,5 HP/cm2).

So, the total hydraulic power will be

Phs = Phsp At . (8.27)

If a pressure drop ps is admitted, to which a bit cooling is obtained,

then the necessary flow for realizing the mentioned hydraulic power will be

given by the relation

s

hsps

s

thsp

s

hs

pP

Dp

APp

P=Q 2

4π== (8.28)

Obviously, Q must be at least equal with the minimum technological

flow Qmin.

Application 8.1. Determining the hydraulic parameters

Establish the drilling system, hydraulic parameters for the interval

corresponding to the anchor casing Ha = 1 000 m (the final well depth is

5 500 m; the well is equipped with an installation F – 320 - 3DH, equipped

with two pumps 2 PN – 1 250).

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134

There are also known: α1 = 23 s2/m6; α2 = 60 · 103 s2/m5; lg = 150 m;

Lp = 850 m; Ds = 444.5 mm; Dp = 168,3 mm; ρf = 1 200 kg/m3.

Solution.

a. Fluid flow (technological minimum flow Qmin)

To determine the bottom hole washing flow, it is accepted

Qsp = 0,045 dm3/s·cm2, so

Qdeg = Qsp At = 0,045 · π/4 D2s = 0,045 · π/4 · 44,452 =

69,8 dm3/s.

To determine the evacuation flow, it is accepted va = 0,6 m/s, from

where

Qev = va Asi = va · π/4 (Ds2 – Dp

2) = 0,6 π/4 (0,44452 – 0,16832)

= 0,083 m3/s = 83 dm3/s.

So the minimum technological flow

Qmin = max (Qev, Qdeg) = 83 dm3/s.

It will be working with 2 pumps 2PN – 1 250 (acc. to table 8.2) with

covers of 7¾ in, at a frequency of 65 cd/min, realizing a flow

Q = 2 · 43,1 = 86,2 dm3/s.

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135

Table 8.2. Characteristics of the pump 2 PN – 1 250

in 8 7 ¾ 7 ½ 7 ¼ 7 6 ¾ 6 ½ 6 ¼ 6Covers diameter mm 203,

2 197 190,

5 184,

1 177,

8 171,

5 165 158,

7 152,

4 Pressure bar 156 166 179 193 209 27 247 271 300

Frequency, cd/min

Training power,

CP

Effective hydraulic power, CP

The flow, dm3/s

65 1250 955 46,2 43,1 40,0 37,0 34,3 31,6 29,0 26,4 23,9 60 1155 883 42,6 39,7 37,3 34,3 31,4 29,2 26,8 24,4 22,2 55 1058 810 39,1 36,4 33,9 31,4 29,0 25,8 24,3 22,4 20,2 50 963 736 35,6 34,0 30,8 28,6 26,4 24,3 22,3 20,4 18,4 45 866 663 32,3 29,8 27,6 25,6 23,8 21,9 20,0 18,4 16,6540 770 590 28,4 26,4 24,6 22,8 21,0 19,4 17,8 16,4 14,7535 675 517 24,8 23,2 21,7 20,0 18,5 17,0 15,6 14,3 12,9

b. Jet speed. There are accepted as optimum speeds values between

80 and 100 m/s. Be it vj = 90 m/s.

c. Chokes area:

10090102,86 3

⋅⋅==

jd v

QA = 9,58 cm2;

are chosen 3 chokes with dd = 20 mm, for which

224

3 π=dA = 9,42 cm2, and 4

3

1042,9102,86

⋅⋅=jv = 91,5 m/s

which is in the afferent optimum limits of the jet speeds.

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136

d. Pressure break-downs in the circulation system

In the bit orifices,

2

2

2

2

95,025,912001

2 ⋅⋅==

ϕρ jf

si

vp = 55,66 bar.

In the circulation system, excluding the bit,

2'

21' )( QgL=p npci ραα + =

= (23 · 850 + 60 · 103) 1 200 · 9,81 · (86,2 · 10-3)2 = 69,58 bar.

So the pressure break-down in the circulation system,

pc = 'cip + psi = 69,58 + 55,66 = 125,24 bar,

and the pumps pressure, for the covers of 7 ¾ in and the frequency of

65 cd/min is pp = 166 bar, so

pc < pp (OK)

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137

9

Technical accidents and difficulties in drilling (fishing jobs)

9.1. General aspects

The difficulties as well as the technical accidents interrupt the normal

going of the drilling process. In case of difficulties, the sleeper access is

possible, but not in case of technical accidents. Sometimes, items of drilling

equipment get lost in the borehole. When an item of equipment is lost in the

hole, it's called a fish. A lost item is also called junk (fig. 9.1).

Fig. 9.1. Item lost in the borehole: 1 - borehole; 2 - fish or junk

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138

Drilling cannot continue until the fish or the junk is recovered from

the hole. To recover the lost item, a fishing job is necessary. Special fishing

tools are used for latching on to the fish and hoisting it up to the surface.

There are many types of fishing tools. For example, there is a type of fishing

tool called a junk basket (fig. 9.2), and there is another type called a spear

(fig. 9.3). The junk basket is used for latching on to smaller pieces of junk

(it's used for recovering lost bit cutter, for example). The bottom part of the

basket is a shoe with hard-faced teeth. The shoe has a hole in its centre. The

fish is forced through the hole and enters the barrel of the basket. Spring-

loaded fingers (fig. 9.2) prevent the fish from dropping out of the barrel and

falling back into the well.

Fig. 9.2. Junk basket: 1 – tool joint box; 2 – hollow barrel; 3 – spring-loaded fingers;

4 – shoe with hard-faced teeth

The spear is used for recovering lost casings. The spear enters the

bore of the lost pipe. The diameter of the spear, therefore, must be smaller

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139

than the diameter of the pipe in the hole. When the spear enters the pipe, its

teeth push out and grip the inner sides of the pipe tightly. Then it is usually

possible to hoist the fish out of the borehole.

Fig. 9.3. Spear (scheme)

Before a fishing job can begin, the string must be tripped out of the

hole. First, the Kelly is broken out and is set in the rathole. Then the string is

broken out in stands and the stands are stood back on the rig floor. When all

of the stands are stood back, the fishing can begin. The toolpusher usually

takes charge of the fishing operation.

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140

9.2. Drilling difficulties

In general, the drilling difficulties are of geological nature, sometimes

geological – technical. But there must be said that the subjective factor has a

decisive role in provoking their solving. Here are the most important.

a. The rocks slougning from the borehole walls

By its nature, the borehole disrupts the rocks natural equilibrium. So

there appear traction and shearing tensions which, when exceed certain

limits, provoke the breaking of fragments from the rocks` walls. The

existence of the slougning is signaled by the detritus volume increase on site,

the nature, the form and the size of rock particles etc.

The main danger is the sticking of drilling tool. Obviously, the most

slogned formations are the ones that miss the cohesion: for example, the

sands and the rubbles, when the pressure made by the drilling fluid from the

borehole upon them is not enough.

b. The borehole walls gathering

After their crossing, some rocks manifest considerable radial

deformations. Thus, the borehole diameter is shrinking, the walls gather. The

radial deformations have 2 aspects:

− a mechanical one, provoked by the viscosity-plastic rocks flow when

exceeding the flowing limit;

− a physical-chemical one, associated with the interaction between the

drilling fluid and the crossed rocks.

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141

The rocks with a viscosity-plastic pronounced character are: the clays,

the marls and the salt. It is well known the fact that the lignite, anhydrites,

clays and marls, in contact with the water are swelling and tighten the

borehole walls.

Measurements:

− reducing the free water containment;

− using inhibitive drilling fluid, or drilling fluids based on oil products.

c. Dissolving the rocks from the borehole walls

The layers formed from sodium chloride NaCl, calcium chloride

CaCl2, potassium chloride KCl or magnesium chloride MgCl2, in contact

with sweet water from the drilling fluid are dissolving, and the borehole is

enlarging or shrinking. The respective layers will be crossed by saturated

alkaline mud or with reverse emulsions.

d. The bit and drill string (rod) bushing

The viscosity clays and some hydratable argyle clays, crossed with

water fluids, stitch to the bit surfaces, provoking its bushing. It is tried the bit

unloading through shaking, vigorous lifting and lowering maneuvers,

rotation speed increase, circulation intensification.

The best results are obtained by using some drilling fluids type

reverse–emulsion.

e. Unwanted deviations. Key seats

The key seat represents a longitudinal bell nipple formed in the wall

from the curving center of the well where the drill string can be stuck.

Generally, the key seats are created by the special joints through a process of

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142

friction, gnawing and shattering during the tubular material maneuver (acc.

to fig. 9.4).

Fig. 9.4. Forming of key seats

For prevention is recommended:

− utilization of an assembly of drill collars, rigid enough;

− placing, above the drill collars, a corrector with spiraled cutters and

free spinning etc.

f. Eruptive manifestations (acc. to chapter 10)

g. Circulation losses

In certain situations, the drilling fluid enters the natural or provoked

fissures, in the crossed rocks pores and hollows, provoking the so called

circulation losses.

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143

There have been underlined three channels where the drilling fluid

losses appear:

− the thickened formation pores: gravel, sands, moraines;

− natural or artificial fissures;

− dissolving hollows (the case of carbide rocks: limestone,

dolomite etc.).

In principle, drilling fluid losses can occur when the condition

pp < pgs < pfis, (9.1)

is not accomplished.

But, in the case of subnormal pressures layers, even the layer-well

condition must be re-seen.

It will be written like this:

pgs = ph + phd = paf . (9.2)

Circulation losses preventing must have accomplished the following:

− drilling fluid density must be minimum;

− rheologic properties (viscosity, dynamic friction tension, gel

resistance) are adjusted at the minimum values;

− the pumping flow is reduced to minimum: to ensure the well washing

as well as the bit cooling;

− the turbulent material introducing speed must be limited;

− are pre-encountered the forming of the bushes on the bit etc.

Circulation losses controlling is made, in general, by three ways:

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144

− methods based on the drilling fluid conditioning;

− methods of blocking the rocks channels and leak proofing? the influx

area;

− special drilling methods.

One of the most used methods to block the losses areas is the

cementing. There are, usually, used cement paste with a fast catch, with

different add-ons (cemented clay, blocking materials etc.). In case of some

cavernous areas, there is no longer possible the blocking by placing the

cement paste or other materials that catch or are hardening. In this case, it is

proceeded differently (fig. 9.5). At the inferior part of the string, between

two concentric tubes 1 and 2 a plied sac 3 is introduced, made out of

polyetilenic foliation or from a textile resistant material. When the cement

paste has reached the string`s inferior part, it open the “valve” afferent to the

annular space from its superior side, so that, at a pre-established pressure,

the two tubes will be released.

At the operation`s end, the sac is plied on the borehole wall, releasing

from the drill string, which sets back. The pieces remained in the well are

made from an easy milling material. After the necessary break for

strengthening the cement paste it passes to the milling operation, at an equal

diameter with the borehole diameter. In the case of total losses (catastrophe),

in case of some big caverns, it`s necessary filling the hollows with backfills

with cement or sand balls.

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145

Fig. 9.5. Blocking the losses zone by cementing with textile sac [2]:

a – before cementing; b – after cementing

In the zones where the fluid losses are a catastrophe, the drilling

technology on that respective interval is changed, and, after its crossing, a

casings column is cased. Are being used: lost circulation drilling, air drilling,

aerated fluids drilling, mousse drilling, air-lift drilling, local circulation

drilling.

9.2. Technical drilling accidents

9.2.1. Borehole stucks

Borehole stucks are the most frequent technical drilling accidents. The

elements that can be stuck are: the bit, the drill string, the casing column,

geological-geophysical investigation instruments and devices.

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146

The causes for getting stuck are (the majority we have presented

during drilling difficulties):

− walls breaking (especially in the case of rocks with low natural

cohesion);

− walls shrinking (clays, marls, salt);

− detritus and weighted drilling fluid depositing;

− the bit and rod bushing;

− the bit or rod stuck up: it is produced in case of crossing some rocks

with a high abrasion (during the bit ascending, its diameter is

reducing; so it is formed a tronconic borehole and, when introducing a

new bit, the stuck danger is imminent) or in the deviate zones of the

hole (especially in case of the key seats);

− cement stuck up (in case of forming some cement plugs or liners

cementing);

− soldering the drill string and the casing. Two are the causes in this

case: existence of a big differential pressure borehole – layer and

existence of a filter cake on the well walls with high stickness.

The sided pushing force of the tubular material on the borehole walls

(because the borehole pressure pgs is bigger than the formation pressure pp)

is given by the relation (acc. to fig. 9.6)

F1 = Ac (pgs – pp) e μ , (9.3)

where: Ac is the contact area between the tubular material and the well walls:

Ac = φ π D lc ; (9.4)

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147

lc – contact length;

D – exterior diameter of the tubular material;

φ – percent from the surface of the tube in contact with the rock;

e – filter cake efficiency;

μ - friction coefficient.

Fig. 9.6. Tubular material stucking (scheme)

To prevent stucking due to differential pressure and filter cake

stickness it is recommended using a reduced density drilling fluid, low

filtration and treated with substances that reduce stickness and friction (an

add-on of 8 - 10 % diesel oil and 1 - 2 % powder grafit).

Solving the stucking

It is possible to obtain the string`s pick up by pulling, but only when it

is actioned immediately after the stucking begins. This method gives results

only from time to time. Most of the times, through pulling unwanted effects

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148

occur: accentuation of the stucking, breakings or tear out of the thread from

the string etc.

The first thing that must be done, in case a stucking occurred, is the

circulation control. If it exists, its maintaining is tried; if it misses, is tried

obtaining it (through direct or reverse circulation).

It is established the stucking depth.

The fastest and the easiest procedure is measuring the stretch

produced by a traction force or the twist produced by a known torsion

moment (the last procedure is applicable only in case of the drill string, but

not in casing column).

In the first case, according to the law of Hooke, the specific buckle

pLL= Δε , (9.5)

from where the stucking depth

εL=Lp

Δ . (9.6)

On the other side,

E

= σε , (9.7)

AF=σ , (9.8)

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149

so

LF

AE=Lt

p Δ , (9.9)

where: A is the transversal section area of the string body;

ΔL – specific stretch under the action of the traction force Ft.

With the purpose of increasing the precision, the operation is repeated

for more values of the traction force Fti, obtaining more stretches ΔLi, and

the medium stretch ΔLm and the medium traction force Ftm are introduced in

relation (9.9). Most often are calculated 2 stretches ΔL1 and ΔL2, obtaining

21

21

ttp FF

LLAE=L−

Δ−Δ . (9.10)

Similar, if the twisting angles Δφ1 and Δφ2 are measured at two

torsion moments Mt1 and Mt2, the free portion length (the stucking length)

21

21

ttpp MM

IG=L−

Δ−Δ ϕϕ , (9.11)

where: G is the transversal elasticity module;

Ip – polar inertia module.

With a way higher precision it is determined the stucking depth when

using stucking indicating devices, inserted through the drill string with cable

(stress indicating device, the measuring device of the drill string`s

mechanical properties etc.).

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150

It is often used the stress indicating device (fig. 9.7).

Fig. 9.7. Stress indicating device [2]: 1 – drill string; 2 – measurement device;

3 – inferior blocking; 4 – superior blocking; 5 – cable; 6 – borehole wall

After the blocking is done, the drill string is supplementary solicited.

If the device is situated above the stucking zone, it will acknowledge the

string? buckling between the blocking elements: distance – traction case,

close range – compression case, spinning – twisting moment appliance case.

These buckles change the electric characteristics of the device, change that

will be transmitted to the surface recording devices.

The stucking solving method, depending on the existence situation in

the borehole can divide in:

− detaches in case of circulation existence;

− detaches in case of circulation inexistence;

− detaches from holes – key.

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151

Detaches in case of circulation existence

If through the careful maneuvering upside down or through rotation

the detach is not obtained, then one of the next methods can be applied:

− petroleum bath;

− producing vibrations in the stucking zone;

− producing longitudinal shocks by striking;

− reducing the borehole pressure (reducing and even reversing the

differential pressure).

Petroleum bath (oil)

For realizing the petroleum bath, with the help of some cementing

aggregates it is pumped in the borehole a petroleum volume

( )22

4 psp DD=V −π , (9.12)

where

h = L – Lp + (50 - 100) m . (9.13)

(Or is considered that the pumped oil volume is with 30 - 50 % higher

the annular space volume between the drill string inferior side ant the

stucking superior side).

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The pumping pressure during the operation has the maximum value

when the oil reaches the well sleeper:

pmax = pc + lt (ρf – ρp) g, (9.14)

where: pc is the necessary pressure for beating the frictions from the

circulation system;

lt – oil column length inside the drill string;

ρp – petroleum density (oil).

The pressure – volume diagram is according to figure 9.8.

Fig. 9.8. The diagram p–V for a petroleum bath

After the petroleum press through in the annular space, the drill string

is kept in tension, at a force with 10 - 20 tf bigger than the force came from

its own weight. At intervals of about 30 min the petroleum package is

“moving” through slow pumping, through the string, of a reduced drilling

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fluid quantity. The beginning of the pick up is marked by the stretching load

showed by the weight index. If after 12 - 18 h the pick was not

accomplished, the petroleum bath can be repeated two or three times.

Note. Besides the petroleum there can be used, with good results,

other products like: oil based fluids, sweet water – with or without tension -

active substances, acid solutions (hydrochloric acid or hydrofluoric acid) etc.

Producing vibrations in the stuck up zone (without applying an oil

bath or in the same time with it) is realized by explosion. Right next to the

stuck up zone one or more missiles will be detonated (attention on the

resistance reducing!).

Producing longitudinal shocks (applicable with or without a

bathroom). In this case, in the drill string, above the stuck up zone is

installed a mechanical or hydraulic jar (in this way it will proceed to

screwing off the strings as close as possible to the stuck up zone). The

device (the jar) will be inserted with some pieces of drill collars.

Detaches in case of circulation inexistence

The method is also valid in the case when we have circulation, but the

methods previously presented were without results. In this case it will be

made like this:

− the free part of the drill string is detached;

− the space inside the drill string is picked up;

− from the picked up string the parts are picked up and detached.

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Detaching the free part of the drill string can be made through screw

off, cutting or twist-off.

To ensure a screw-off as safe as possible, the drill string is stretched

with a force equal to the free portion weight. Also, it is recommended the

detonation of a small explosive quantity inside the string, right next to the

joint that will be screwed off.

The rods cutting is made with a circular knife, that actions through the

small diameter extraction pipes or the depth pumping rods.

The twist-off is made through a concentrated explosion (less safe

method).

The pick up off the space behind the strings? is made with a spear or a

washing casing. This is made from many assembled casings (120 ÷ 150 m),

having on the inferior part a pick up head, with the form of a teethed mill,

armed with rough material. When detaching the detached drill string portion,

the spear is re-introduced together with a tap (the drill rod will have in this

case threads left).

Note. The so described procedure is hard and expensive. There is also

the possibility of clothing and recovering the detached portion in a single

run. In this way, in the superior spear part it will be installed a male union or

a completing tap. The detonator must pass right through them.

9.2.2. Solving the strings breaking and tear offs

To precisely establish the end`s state as well as its position in the

borehole it is used a leaded model. To solve this technical accident non-

detachable (fixed) or detachable (mobile) instruments are being used.

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From the non-detachable instruments category belongs the tap (cuts

thread on the interior) and bell socket (cuts thread on the exterior). The tap is

recommended in case of breaking in the jointing area and in case of drill

collars breaking.

The bell socket is recommended in the case of breaking the drill rods

body.

Between the tap and the bell socket is inserted a safety joint (in case

the extraction is not possible, this gives the possibility of detaching the rod

from the instrumentation).

If, after the made investigation, it is found that the strings existence

outside the hole`s nominal perimeter (the salted borehole or the drill string

pushed in the well wall) is necessary bringing the string`s end coaxial with

the borehole. In this way, it is used straighten hook.

Some instrumentation devices are presented in figure 9.9.

Fig. 9.9. Instrumentation devices [1;2]: a, b, c – taps (a – normal; b – jointed stuck up; c – female union stuck up); d- bell socket

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9.2.3. Solving the technical accidents of the casings columns

In case of a stuck up casing column, it is tried the pick through

circulation and maneuver (attention! Ft < Fad). When tearing off the casing

from the thread and slipped in the well it is tried completing by screw on.

In the case of a transversally buckled casing, before the solving, it is

necessary to determine the casing`s form in the respective area. For this a

tubular drift mandrel is used.

If it`s about a casing`s ovalization or collapse it is tried the casing

removal with a beating drift mandrel (fig. 9.10) or with a rotation drift

mandrel that are inserted with the help of the drill string.

Fig.9.10. Beating drift mandrel: Fig. 9.11. Rodger`s grab 1 – body; 2 – circulation channel; 3 – external ditch

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9.2.4. Extracting metallic pieces from the well sleeper

In case the bit remains at the sleeper, as a screw off result, it is tried

completion through screw on, followed by extraction. If the bit is broken

from the joint, it is tried the pick up with a short tap. In the situations where

the bit can`t be extracted in complete from, it is destroyed through milling.

The metallic pieces found on the well sleeper (bit sheaves, bearings,

pieces escaped from the surface etc.) can be pushed in the well walls with a

fishtail bit, in case of weaker consolidated rocks. If the operation is not

possible, these pieces are extracted.

From the extraction devices category, the most used are the Rodger`s

grab and the magnetic mill. The Rodger`s grab is made out of a casing

portion which has high teeth at the inferior end, with the peaks narrowed al

little bit to the interior (fig. 9.11).

The magnetic mill has a teethed mill at the inferior side, and in the

interior a permanent magnet.

9.2.5. Differential pressure sticking. Case study

A drill string had been stuck up at the depth of 1 900 m (dimensions

afferent to figures 9.12, 9.13 and 9.14 are given in meters).

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Fig. 9.12. Differential pressure sticking (application)

Other data (acc. to fig. 9.9): H = 2 000 m; h0 = 10 m; lg = 120 m;

lp = 1 870 m; Dg = 241,3 mm (9 ½ in);

● between 1 450 – 1 500 m – the risk of gas apparition in the

sandstone reservoir;

● the pressure of the formation measured at 1 900 m was 190 bar, and

at the depth of 1 500 m of 148 bar;

● the mud density, respectively the salt water from the deposit are

equal:

ρf = ρas = 1 150 kg/m3.

● the drill collars surface percent in contact with the rock φ = 0,2;

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● filter cake efficiency e = 0,25;

● hydrodynamic pressure during circulation phd = 7 bar;

● friction coefficient μ = 0,5;

● the force from the drill rod weight Fg = 90 tf;

● the force from the drill collars weight from under the pick up point

Fgg = 15 tf (so the force from the free portion weight Fp = 90 – 15 =

= 75 tf);

● the tension admissible force Fad = 190 tf;

● petroleum density ρp = 890 kg/m3;

● gas density at depth, ρg = 105 kg/m3;

● unitary internal volume of the drill pipes Vip = 9,27 l/m;

● unitary internal volume of the drill collars Vig = 4,56 l/m;

● unitary volume of the annular space alongside drill pipes

Vsip = 62,7 l/m;

● unitary volume of the annular space alongside drill collars

Vsig = 30,3 l/m;

● unitary volume of the annular space alongside the anchor casing

Vsia = 66,1 l/m.

Questions:

1. What traction (compression) must be applied towards 1 925 m to

move the drill string towards the surface (or towards the sleeper)?

2. What immediate measurement can be taken to reduce the drill

string stick up?

3. Will there be a pick up procedure towards the sleeper or towards

the surface? Why?

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4. What traction, respectively compression will be realized at the

depth of 1 925 m?

5. Determine the necessary petroleum volume for applying a bath.

6. Fluid press through volume.

7. What will happen when the oil volume will reach above the

sandstone reservoir roof? (sandstone reservoir: 1 450 – 1 500 m).

Solution

1. The contact area between the drill collars and the well wall,

according to relation 9.4 (acc. also to fig. 9.9)

Ac = φ π Dg lc = 0,2 · π · 0,241 · 50 = 7,571 m2.

The sided pushing force of the tubular material on the borehole wall is

given by relation (9.3):

F1 = Ac (pgs – pp) e μ.

The borehole pressure in dynamic conditions, at the depth

Hp = 1 900 m:

pgs = ρf g Hp + phd = 1 150 · 9,81 · 1 900 + 7 · 105 = 221,34 bar

(here it is precisely known pp = 190 bar).

So

Δp = pgs – pp = 221,34 – 190 = 31,34 bar.

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In these conditions

F1 = 7,571 · 31,34 · 105 ·0,25 ·0,5 = 296,59 · 104 N = 296,59 tf.

As the force from the free portion weight of the drill rod Fp = 75 tf,

results that the necessary traction force to move the rod towards the surface

would be

Ft = Fp + F1 = 75 + 296,59 = 371,59 tf > Fad = 190 tf (?)

To realize a compression, the force came from the free portion weight

of the drill string

Fp = 75 tf << F1 (??)

2. As an immediate measure (theoretical) of reducing the stick up

would be the temporary stop of the drilling fluid circulation. In this case, the

stick up reduction would be 7 bar, which would mean 22,3 %.

3. Pick up to the surface attempt. As it was deduced from point 1), the

available force for pick up towards the surface is stranger than the one

available towards the sleeper; plus, a compression appliance is voided from

the point of view of the drill string resistance. Actually, stabilizers lifting

towards the stick up zone represent a favorable factor.

Remark. As specified before, in the case of the “key” holes or a

detritus plug stuck on, it will proceed to the pick up towards “the toe”

(towards the well sleeper).

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4. The admissible traction force, at the surface, in case of the drill

pipes, is 190 tf. The effective traction in the stick up area will be 190 – 75 =

115 tf (On the other side, as specified before, the theoretical compression

force would be only 75 tf).

5. It will be keeping into consideration that the pumped oil volume to

lead at such a petroleum height in the annular space, that the differential

pressure pdif = pgs – pp = 0.

The layer pressure at depth H = 1 925 m is

pp = 190 · 105 + 1 150 · 9,81 · 25 = 192,8 bar.

So it is needed for the borehole pressure at this depth (acc. to

fig. 9.10)

pgs = ρf g (1 925 – x) + x · ρp g = pp,

which means

1 150 · 9,81 (1 925 – x) + x · 890 · 9,81 = 192,8 · 105,

from where results x = 949 m.

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Fig. 9.13. Necessary petroleum volume for applying the bath

So the petroleum volume will be

Vt = (1 925 – 1870) · 31,3 + 894 · 62,7 = 57 720 ≈ 58 m3.

Discharge fluid volume:

Vr = Vip + Vig + Vsi(1990÷1925) =

= 9,27 · 1 870 + 4,56 · 120 + 30,3 (1 990 – 1 925) = 19,852 m3.

Obviously, creating an unbalance between the string`s interior and the

annular space, the annular space afferent valve must be shut, when the oil

reached its destination.

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To avoid this unbalance, a supplementary oil volume must be injected (acc.

to fig. 9.10):

Vsupl = (1 990 – 1 925) · 30,3 + 120 · 4,56 + 894 · 9,27 = 10 804 l =

10,8 m3.

So, in this case, the total oil volume will be

V = Vt + Vsupl = 58 + 10,8 = 68,8 m3,

and the press through fluid volume

Vr = 976 · 9,27 = 9,05 m3.

Observations.

The unbalance created between the string`s interior and the annular

space, in case of using an oil volume of only 58m3, would be

949 (1 150 – 890) 9,81 = 24,2 bar.

The light fluids are applied, as mentioned before, to reduce the

stickness and the frictions between the strings and the filter cake (through

physical and chemical actions it reduces the lateral force F1). As light fluids

are recommended: petroleum, reverse emulsions, gas-oil with lubricants etc.

The borehole situation, when the oil casing reached above the

sandstone reservoir roof, is presented in figure 9.14.

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Fig. 9.14. The oil volume above the sandstone reservoir (scheme)

The formation pressure at the depth of 1 450 m is

pp = 148 · 105 – (1 500 – 1450) · 105 · 9,81 = 147,48 bar.

When the oil column reaches above the sandstone gas layer, it can be

written:

68,8 · 103 = (1 450 – 1 000) · 62,7 + (x` - 450) 66,1 ,

from where x` = 1 064 m.

For the static case, the borehole pressure will be

pgs = 1 064 · 890 ·9,81 + 386 · 1 150 · 9,81 = 136,44 bar,

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so pgs < pp = 147,48 bar (Δp = 11 bar).

For the dynamic case, corresponding to the ascending maneuver, for

phd = 7 bar, results an unbalance layer-well of 11 + 7 = 18 bar, so the

immediate danger for an eruptive manifestation.

What will we do?

We must use, first of all, an oil volume less “ambitious”. For example,

for the static case

147,48 · 105 = 890 · 9,81 x” + (1 450 – x”) 9,81 · 1 150,

from where results x” = 631,22 m.

In other words, the oil column height must be reduced from 1 064 m

to 631 m; for the dynamic case, it must be determined, first of all, the exact

value of the hydrodynamic supplementary pressure phd.

With a certain approximate, an oil volume of 30 – 40 m3, which

means a height of its column in the annular space of 300 – 400 m, is good

news.

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10

Blowout control

1. General aspects

Hydrocarbon accumulations are becoming more and more difficult to

find, and oilmen are drilling deeper and deeper in their search for them. An

eruptive manifestation corresponds to a well breach of a fluid volume from

the formation which, if it`s not controlled, will result in an eruption. A well

which blows out of control is known as a 'gusher' or 'wild well'.

To prevent a well from blowing out, the mud weight carefully

controlled. By itself, bentonite will not make a mud which is heavier than

about 0,823 kg/dm3. The most common material for weighting a drilling

fluid is ground barite (BaSO4).

If the bit suddenly enters a high-pressure formation, the weight of the

mud column may not be great enough to hold back the pressure og the gas,

oil or water in the borehole. Then, there will be a kick; and if the BOP rams

cannot be closed quickly enough, the well will blow out. The flow must then

be brought under control, so that heavy mud can be pumped to the well

through the kill line (fig. 10.1).

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Fig. 10.1. Blowout control (P.L. Sandler, 1980)

In the case of a gas-well blowout, it may be necessary first to divert

the gas into a flare pit (fig. 10.2). The gas is set ablaze in the flare pit in

order to prevent an explosion.

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Fig. 10.2. Gas-well blowout (scheme)

Logging the well can provide information which may help to avoid

dangerous situations down hole. Before the logging tools can be run in, the

hole must be clean. If there are any tight spots, for example, it may be

necessary to make a dummy trip before the drill string is pulled out. In a

dummy trip, the string is hoisted only a quarter or a third of the way up; then

it is run back to the bottom again. In this way the bottom hole assembly can

be used to clean up the well and prepare it for logging.

10.2. Warning signs of an eruptive manifestation

a. During drilling:

− increasing the advancing speed;

− increasing the exit flow;

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− increasing the mud tank level;

− reducing the pumping pressure, simultaneously with increasing the

pumps courses frequency (due to the annular space fluid density

reduction);

− gasified drilling fluid;

− diminishing the drilling fluid density and so on.

b. During maneuver:

− filling anomalies at extraction;

− anomalies at return, when descending;

− the mud`s exit at derivation when the pumps are shut down etc.

c. Drilling fluid gasification

The gas enters the drilling fluid in the following situations:

− diffusion (concentration difference);

− drilling in a permeable formation that contains gases (even if ph > pp);

− drilling in a clay formation that contains gases at high pressure;

− swabbing;

− drilling in a low permeable formation that contains gases in conditions

of ph < pp);

− the presence of H2S and CO2 as a result of the degradation of some

drilling fluid additives etc.

It is imposed, of course, the natural question: with how much is the

bottom pressure reduced in case of drilling fluid gasification?

Simplified, it can be accepted the fact that the gas expansion can be

represented by the law (fig. 10.3)

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p V = ct. (10.1)

Fig. 10.3. The gas expansion law (scheme)

For the extreme points – bottom hole and surface –

p1 V1 = p2 V2 . (10.2)

The pressure reduction upon the bottom hole is given by Strong`s

relation:

hf

fi p=p log3,2ρ

ρρ −Δ , (10.3)

where: ρi, ρf represent the drilling fluid densities at entering, respectively at

exiting from the borehole;

ph – the hydrostatic pressure of the drilling fluid without gases.

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In table 10.1 are presented values of the bottom pressure reduction Δp

for different densities: ρi and ρf respectively different drilling depths Hi:

Table 10.1. Values of the bottom pressure reduction (different densities and depths)

ρi = 1,2 kg/l ρi = 1,6 ρi = 2 Δp Δp

Δp reduction for

an exiting

drilling fluid

Depth,

Hi ph,

bar

1 0,80 0,60

ph,

bar 1,40 1,20 1,00 ph,

bar 1,80 1,50 1,2

0500 60 0,82 2 4,1 80 0,62 1,4 2,6 100 0,51 1,5 3

1 000 120 0,96 2,4 4,8 160 0,72 1,7 3 200 0,59 1,8 3,5

2 000 240 1,1 2,7 5,5 320 0,82 1,9 3,45 400 0,66 2 4

3 000 360 1,2 2,9 5,9 480 0,88 2,1 3,7 600 0,71 2,1 4,3

4 000 480 1,23 3,1 6,2 640 0,92 2,15 3,9 800 0,74 2,2 4,4

5 000 600 1,28 3,2 6,4 800 0,95 2,2 4 1000 0,76 2,3 4,6

6 000 720 1,31 3,3 6,6 960 0,98 2,3 4,1 1200 0,79 2,36 4,7

7 000 840 1,34 3,36 6,7 1120 1,00 2,34 4,2 1400 0,8 2,4 4,8

10.3. Eruptive manifestations prevention

The eruptive manifestations prevention methods result from analyzing

the causes that produce them. Thus, the following must be kept in mind: the

drilling fluid density is adjusted in such a way that the rules “+ 5 points” or

“+ 10 bar” must be respected:

ρf = ρp + 0,05 (“+ 5 points” rule) respectively

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Hg

pp= hf

Δ+ρ (“+ 10 bar” rule) .

The rheologic properties are maintained at minimum values,

reclaimed by the detritus evacuation. At the maneuver of inserting the string

RIH (running in the hole), the fluid volume spilled is compared with the

displaced rods` one.

At the maneuver of extracting the string, the borehole is permanently

filled with a volume equal to the displaced volume of the respective tubular

material.

The circulation losses must be prevented and remediated. To

minimize the supplementary hydrodynamic pressures afferent to ascending

maneuver it will be minimized, first of all, the extraction rate of the tubular

material.

The bit bushing will be avoided. It is permanently supervised the

containment and the nature of the gases in the pores, as well as their salinity.

If a gas bearing formation has been encountered before the bit extraction, the

mud is circulated until the evacuation of the gases inside it.

In case of prolonged interruptions, the drill string will be equped with

intermediate circulations, thus eliminating the gas bearing drilling fluid.

10.4. Blow out preventing installations (BOP)

Simplified, such an installation has two or more preventers, a

manifold (with valves and adjustable choke), an action system and diverse

manometers.

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In a minimum endowment, it is needed a total shutdown preventer

(“on nothing”) and a preventer for shutting down on drill strings and casings.

Usually, to these two is added a so called universal preventer, that can

shutdown the borehole on any drill string, joint, casing, rope and so on – in

the same time allowing the maneuvering and the rotation of the drill string,

thus avoiding its losing. In the case of combined drill string, there will be

used two preventers for shutdown on drill strings. In the case of offshore

drilling, there is an extra preventer with blind rams for rods shearing and

well shutdown.

The eruption through the rod interior is prevented with:

− a superior or inferior kelly cock;

− a safety valve between the rotary swivel and the boring hose;

− a retaining valve, with an unique circulation way, installed alongside

the drill string, most often above the bit.

In figure 10.4 is presented, simplified, a classical scheme: two simple

horizontal preventers, a vertical preventer with sided annular blind ram

(universal) and the eruption manifold.

The preventers are classified on the following criteria:

● after the moving direction of the shutdown elements: horizontal

(with sliders) and vertical (with annular blind ram);

● after the number of shutdowns on a preventer: simple, double and

triple;

● after the blind rams form: plate, oval, cylindrical, annular, tubular;

● after the blind rams action mode: manual, mechanical, hydraulic,

automated (actioned by the well`s fluid pressure) and combined;

● after the blind rams destination: for drill strings or casings, for total

shutdown, for shearing, with sustaining wedges.

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Fig. 10.4. The scheme of an blow out preventing installation: I.C. – command installation (accumulator + oil tank + pumps); P.V. – vertical preventer; P.O. – horizontal preventer

Plus, the eruption preventers are different also through a series of

constructive or functional parameters: nominal diameter, working pressure,

the internal crossing section diameter etc. For details regarding this subject,

the work “Prevenirea eruptiilor intre exercitiu si reflectie” (Editura Prorep,

1996, autori: L. Avram and C. Popa) can be consulted.

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11

Directional wells

11. 1. General aspects

It is often undesirable or impossible to drill all of a hole vertically. For

environmental reasons, for example, it may be necessary to spud in (to drill

the first few feet of a new hole) a well some distance from the target

(fig. 11.1).

Fig. 11.1. Directional well (scheme)

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A borehole such as this drilled strait down to a certain depth and is

then deviated away from the vertical in the direction of the target.

A well may also have to be deviated if its direct vertical progress is

blocked (for example, by a fish which cannot be recovered. In a case such as

this, the fish will first be cemented over. Then, by directional drilling, the

fish will be sidetracked and the new section of hole will be continued

parallel to the original (fig. 11.2). At the kick-off point, the hole which is

drilled through the casing is called the 'window'.

Fig. 11.2. Sidetrack case

Directional drilling is essential in deep offshore operations such as

those in North Sea or Black Sea (fig. 11.3). If each well in an offshore field

had its own production platform, the oil and/or gas would be much too

expensive to produce commercially.

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Fig. 11.3. Production by directional wells

The cost of recovering as much as possible of the oil a whole offshore

field can run into billions of euro. By means of directional drilling, twenty-

five or thirty wells can be sunk from a single location. Offshore rigs are of

two general types: fixed and floating. On fixed rigs (eg. jack-up rig) (fig.

11.4), the rig floor is connected to the hole by a rigid conductor pipe.

Fig. 11.4. Conductor pipe connection (jack-up rig)

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On floating rigs, in relatively deep water, the rig floor and the hole are

connected by a flexible riser pipe (fig. 11.5).

Fig. 11.5. Rise connection: a – drill ship; b – semi-submersible rig.

The rise column has a sleeve joint in the superior part, and a ball joint

in the inferior part (fig. 11.6).

Fig. 11.6. Rise connection: sleeve joint and ball joint

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When kicking off, the bottom hole assembly usually consists of a

turbodrill and a bent sub (fig. 11.7). The angle is carefully built up about 1°

to 2° for every 100 meters of hole. During build-up, to make sure that the

angle and direction are correct, the hole is regularly surveyed.

Fig. 11.7. Turbodrill with bent sub

An inclinometer and a camera are run in, through the drill pipe, to

take the required measurements and recordings. For this reason, the collars

above the bent sub are non-magnetic. The survey tools are run on a wire

line. (v. Drilling data handbook).

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12. Typical setup offshore drilling

12.1. Making the connection between the platform and the borehole

The simplest system is the direct connection which means

bringing the casing in front of the platform. The sealing devices and

the BOPs will be assembled in this case according to traditional

procedures. This system has a big disadvantage: after shutting in the

well, the casing brought above the sea level cannot be taken away (or

taking it away is difficult), so that it can only be applied to fixed

platforms, which are supposed to work for a long time. The modern

systems aim at building some well heads down to the level of the silt

(obviously, the most serious case is that of mobile platforms; due to

the alternation of waves there is a risk that the vertical movement is

transmitted to the drill string and the drill bit which will hit the down-

hole). The Cameron system of making the connection between the platform

and the borehole is shown below.

Once the platform is transported on site (the bottom of the sea, which

has to be as flat as possible, has to be previously analyzed) a template 1 will

be brought as well (fig. 12.1), having a parallelipipedic form, made of

steel concrete (in order to resist the corrosive action of the sea water); in

the central part it has either a hexagonal or octagonal excavation.

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While excavating, a reduction 2 is assembled on the surface, which is

connected with the template by means of a bayonet system 3, and with the

drill string by threading.

The connection between the template and the platform is made by

the drill string 4 and the temporary cables 5. Before placing the template, a

mobile frame 6 is fitted up, also called temporary frame (actually the

guiding frame), which can be slided along the temporary cables 5, being

actuated by the cables 7. The temporary cables 5, (usually four) are tied by

the template by means of nails 8, that are dimensioned in such a way that

they all stand the weight of the template and in case one of them has to

sustain the template alone they should be able to shear. The whole assembly

is launched until the template reaches the mud level; the reduction 2 is fitted

with nozzles so that, when necessary, the silt is mixed, in order to place the

template on the massive rock MR.

Fig. 12.1. The scheme of the template launch

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Then the drill string is brought to the surface (the reduction 2 is

disconnected from the template just by spinning it) as well as the temporary

metallic frame used for guiding the drilling string so that it does not buckle

under the marine currents’ action (it is brought up to the surface by means of

temporary cables 7). The template is tied to the platform at this time only

with the temporary cables 5.

12.2. Drilling the borehole for the conductor pipe

Usually the diameter of the borehole for the conductor pipe measures 36

in and the depth is of maximum 60 m. The bit has 3 or 4 blades; sometimes the

drilling is started with a 17 ½ in or 26 in bit, then the borehole is extended

until it reaches the desired diameter. The drill string, beginning with the bit’s

insertion, is made by using the temporary mobile frame 6 (cf. fig. 12.2).

Fig. 12.2. The scheme of drilling the borehole for the conductor pipe

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When the bit penetrates the rock for 2 ... 3 m, the temporary metallic

frame is brought up to the surface. The drilling fluid used is sea water; the

cuttings get out over the template and distributes on the bottom of the sea.

12.3. Casing-off the conductor pipe

Usually, the conductor pipe has a nominal diameter of 30 in and the

walls of 20 - 30 mm. The connection between the casings is made by

means of thread joints (the most frequent screws are Buttress type, with a

big stroke) (fig. 12.3).

A guiding frame which directs the conductor pipe is assembled on the

bottom part of the casing, more precisely on its first piece. This stands on

support assembled on the conductor pipe; when it gets into contact with the

template, the guiding frame stops. After inserting the casing and fixing it, the

temporary frame can be taken out. In shallow water it is not necessary to use a

temporary guiding frame. In order to launch the conductor pipe 1, the drill

string 2 is used, which has a special type of reduction R on the bottom, that

makes the connection with the conductor pipe (the reduction R contains the

cementing nipples; the diameter difference between the drill string and the

conductor pipe should be firmly taken into account).

The permanent metallic frame 3 is assembled on the conductor pipe;

its permanent cables 4 slot inside the guiding cylinders 6, fitted with

windows cut on the generators (acc. fig. 12.4).

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Fig. 12.3. The scheme of the conductor pipe casing-off

Fig. 12.4. Guiding system when inserting the conductor pipe

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At the same time, the connection between the permanent metallic

frame 3 and the conductor pipe 1, is made by a sustaining ring 7, fitted on

its bottom side with a inclined plane that allows the cementing of the

conductor pipe (the inclined plane has several grooves which allow the

circulation of the cement). After cementing, by spinning to the left the drill

string, it unscrews from the reduction R and is taken out in a guided manner

by means of the supplementary guiding frame 8 on the temporary cable 5

(cf. fig. 12.3).

12.4. Cementing the conductor pipe The conductor pipe is cemented to the surface.

When the diameter of the conductor pipe is big, in order to avoid

mixing the cement with the pressing through fluid (discharge fluid), several

cementing methods are used.

a. In the casing shoe a row of concentric pipes are installed with the

drill string and the casing. The disadvantage: when run casing, the

cementing pipes and the tubing casing joints have to be handled

simultaneously.

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b. The cementing method using two plugs (according to the

Halliburton procedure)

Two plugs, d1 and d2 (fig. 12.5), are fixed in the last part of the casing

joint; the plugs are empty inside and have different passing diameters

(D1 < D2). They are tied with the casing joint by means of catch pins

which resist shearing.

The cementing head, assembled on the upper part of the drill pipes 1 is

fitted with a ball b1, that passes the plug d2 but stops in plug d1, and another

ball (plug) b2, that doesn`t pass by plug d1.

Let us follow the diagram pressure – volume when cementing the

conductor pipe using this method (fig. 12.6).

When starting the circulation the aggregate pressure is

11 cppp += θ , (12.1)

where: pe represents the pressure needed for overcoming gel strength;

pc1 – the pressure needed for overcoming the frictions in the circulation

system.

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Fig. 12.5. The scheme of cementing the conductor pipe according

to the Halliburton procedure: a) when starting the circulation; b) ball b1 laps over d1 plug;

c) before breaking the catch pins s3; d) after breaking the catch pins s3 After overcoming gel strength,

122 cc ppp == . (12.2)

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The ball b1 is set free (fig. 12.5, a), then the cement is pumped. As,

usually, the density of the cement is higher than that of the drilling mud,

there occurs a differential pressure that „helps” the aggregate.

Fig. 12.6. Diagram pressure-volume when cementing the conductor pipe

When the ball b1 reaches plug d1, the aggregate pressure is

p3 = pc3 + pdif3, (12.3)

where the differential pressure

pdif3 = (ρpc - ρf) l1 g, (12.4)

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l1 being seen in figure 12.5, a.

When ball b1 reaches plug d1 the aggregate pressure increases

until the catch pins s1 shears:

p4 = p3 + psupl4 , (12.5)

where psupl4 represents the pressure supplement needed for breaking the catch

pins. When the catch pins are broken, the aggregate pressure becomes

p5 = p3 + pfr5, (12.6)

where pfr5 is the pressure resulted from the remanent pressure between the

plug d1 and the inside of the pipe.

The aggregate pressure decreases continuously until all the cement

has been pumped, when

p6 = pc6 – pdif6, (12.7)

where pdif6 is the differential pressure corresponding to the respective

moment.

Now (fig.12.5, b) the plug b2 is launched (it is supposed that the inside

of the pipe is big enough so that all the cement needed for cementing the

annular space fits inside it). Until it reaches plug d2, the aggregate pressure can

be considered to be steady:

p7 ≈ p6. (12.8)

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When putting "plug" b2 over plug d2, the aggregate pressure becomes

p8 = p7 + psupl8, (12.9)

where psupl8 is the supplementary pressure needed for breaking the catch pins s2.

Then the aggregate pressure becomes

p9 = p7 + pfr9, (12.10)

where pfr9 represents the pressure due to remanent frictions between plug d2

and the inner part of the casing.

In addition,

p10 ≈ p9 = ct, (12.11)

until plug d1 and ball b1 reach the retaining ring.

Plug d1 is sliding type (cf. fig. 12.5, c, d).

For a pre-set value of the pressure, the catch pins s3 shear, so the

pinholes of the chair of the plug and those of the inner cover reach the

face to face position; the aggregate pressure is

p11 = p10 + psupl11, (12.12)

psupl11 being the supplementary pressure needed for breaking the catch pins s3.

The cement paste is then passed in the joint pinholes found under ball

b1, to the tubular shoe, in the annular space.

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When the cementing operation is done, the aggregate pressure is

p13 = p12 + pdif13, (12.13)

where

pdif13 = (ρpc - ρf) h g, (12.14)

h = L –l1. (12.15)

c. For small diameter casing, the cementing is made by means of the

usual method, with two plugs, without any special changes.

12.5. Drilling the borehole for the anchor casing (string)

The following instance should be taken into consideration: the

conductor pipe 1 is cased and cemented on its whole length (fig. 12.7).

A tension, which causes the breaking of the catch pins when

connected to the base coat, is induced in the temporary cables 5 (acc. fig.

12.3) so that these cables are brought to the surface. The permanent metallic

frame 3, the permanent cables 4 and the sustaining ring 7 of the conductor

pipe remain on the base coat (the notations from figure 12.3 are kept for

figure 12.7 as well).

The normal drilling is started over gain. The drill string is equipped

according to the classic procedure, except the fact that for guiding it the

guiding frame 8 is used; when the drill string 2 has been inserted into the

conductor pipe, it is taken out by means of cables 9.

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Fig. 12.7. The scheme of drilling the borehole for the casing string

12.6. Casing-off and cementing of the anchor casing (string) For casing-off, the anchor casing 10 (usually of 20 in) needs at the

bottom a guiding frame, which can be taken out when its tubular shoe is

inserted into the conductor pipe 1 (fig. 12.8). Launch head of the anchor

casing contains a female union which is equipped with a suspending device,

in the proper support of the sustaining ring of the conductor casing. The

head launching plug is usually equipped with a guiding frame 12,

controlled by cable 13.

The cementing procedure is the same as that of the conductor pipe;

exit of the cement paste is made through some grooves existing in the

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suspension device. After the cement paste has reached the surface,

reduction male union R is unthreaded, using the left rotation.

The guiding frame 12 is brought to the surface using the cables 13.

Fig. 12.8. The scheme of the casing corresponding to the anchor string

Note. In figures 12.3, 12.5, 12.7 and 12.8 the guiding marks are

maintained.

12.7. Drilling through the anchor string In order to start the drilling, by means of a frame, the following rigid

assembly is inserted into the coupling of the anchor string 1; the assembly is

made up of (fig. 12.9):

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- two connectors: inferior connector 2 is binded to the casing male union

while the superior connector 3 is binded to the montant casing (riser) 4, casing

that connects with the platform (in which case the conductor casing has been

brought to the surface, the riser is no longer necessary, but only a normal

casing);

- above the inferior connector the BOPs are assembled: three BOPs

5 with preventers 5 provided with pipe rams, a preventer 6 (also equipped

with rams), for overall shut down and a vertical Hydrill preventer 7 (some

other times, the usual drilling order is used).

Fig. 12.9. The scheme of Drilling through the casing string

Due to the preventing system rigidity, the link between the superior

connector 3 and the montant casing 4 is made through a spherical

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articulation 8, that gives the possibility of changing the montant casing`s

position with 100 - 120 degrees. For the same reasons, the link between

montant casing 4 and platform 9 is also made using a spherical articulation

10.

At the surface drilling wells, the shutting of the drilling pipe is

usually found above the overall shutting. The offshore drilling situation is

quite the opposite. The preventers are turned on hydraulically, through

some pressure lines.

The overall shutting preventer is equipped with blind rams which,

in case of necessity, can cut the drill string. In this case, the drilling pipe

preventer is closed, the drill string is cut through the preventer overall

shutting and, for improved (double) security, the vertical Hydril preventer

is also closed, a preventer that can also be an overall shutting one.

If there is time, the drill string is not cut, but we proceed differently.

The drill string is extracted until the combining of the two steps, next to the

preventer 5a, reaches the platform. This link is weakened then the drill string

is re-introduced until the weakened link reaches next to the shutting preventer

5a. The horizontal preventer 5a is then closed on the drill strings, under the

weakened female union (more precisely, which has in it the male union) and

now the drill string from the weakened male union can be screwed off (the

screw off is made in the whole string screwing off direction; the link being

weakened, the loosening will be made, of course, from the afferent zone).

For safety reasons, the vertical Hydril preventer is also closed and, at

this time, the platform can leave the location. There is an important

advantage: the drill string re-completion can be made very easy.

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12.8. Specific elements to drilling in deep and very deep waters

An important volume of petroleum resources can be found in the

regions situated in deep and very deep waters, at the limit of depth of the

current activities (the experience in the last 10 years show us that once the

record of operating in deep waters was scored, this is continuously broken-

just like in sports!).

By deep waters from the point of view of petroleum activities we

mean the waters with a depth bigger than 400 m, and by very deep waters

we mean the ones that are bigger than 1 500 m (over 1 600 m according to

MMS [19]).

The operators in the petroleum industry orientate more and more

towards the deep waters as here we can find important petroleum resources

that ensure big productions. Some wells in these regions can produce

8 000 m3 crude oil/day, and this justifies the supplementary expenses and the

risks that investors assume.

The exploitation projects for the locations situated at a depth bigger

than 2 000 m in The Gulf of Mexico, Offshore Brazil and Western Africa

were hard to imagine 15 … 20 years ago. Lately more wells at big depth

were drilled, and the record of 3 050 m was broken at the end of the year

2 003, in the Gulf of Mexico.

The new technologies allow the exploitation of petroleum in regions

which are situated far away from the shore, sometimes over 200 marine

miles (about 370,6 km). This presupposes, of course, the construction of big

and complex structures, the change of the existent drilling and the appliance

of new environment rules.

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As a consequence of a big number of geological and geophysical

prospects, economically attractive in very deep water regions, most of the

drilling rigs are contracted on long term grounds by different operators in the

complex field of exploration and exploitation of gas and petroleum

reservoirs. The growth of the water depth led to the re-technologization of a

big number of drilling rigs as well as the construction of others. The most

important changes in the construction programs of these wells are related to

both the big depth of waters, as well as the conditions at the bottom of the

well, a hostile environment etc., in which activities are deployed: waves

whose height is over 30 m height; winds that reach 80 knots (148,2 km/h);

air temperatures of -15 °C; the temperature of the sea water under 0 °C;

marine currents of 3 knots (5,5 km/h); the presence of icebergs (in some

regions of Canada, Iceland etc.); the frequent presence of snow, rain or

fog i.e.

In the deep water regions, the drilling activity can be deployed only

by the help of dynamically positioned marine semi-submersible rigs, and by

the help of the drilling ships. As previously mentioned, by the help of

conventional, anchored rigs, drilling in regions deeper than 1836 m was

possible in the Gulf of Mexico. Yet in other parts of the world, the

conditions may be different from the ones in the Gulf of Mexico, and the

presence of bottom currents made the management of riser systems difficult.

In order to maintain the position under the effect of the bottom currents,

more precisely in order to stock the supplementary mud volume, as well as

the supplementary risers that are necessary for the construction of the well,

more and more often large rigs, with a supplementary available power are

demanded.

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As the operations and the equipment are different from the ones used

in the case of shallow waters, the related regulations, standards and

procedures cannot be directly applied to most of the part of operations

specific to deep waters. The safety of the well and of the operations, as well

as the testing of formations are fundamentally different from the bottom

equipment that is used in deep waters.

Some of the most important activities that need taking into account for

deep water drilling refer to [20-22]:

procedures to prevent and fight against blowout during drilling;

research concerning the growth of material resistance and the

reduction of their weight;

methods of control of hydrates that can appear during the operations

at wells that drill in deep water regions;

methods of control of paraffines for the operations at wells that drill

in deep water regions;

research concerning the integrity of pipes that work in deep water

regions;

modeling the forces that act upon deep water structures and pipes;

behavioral analysis in the case of crude oil pollution and the

assessment measures of bottom blowouts etc.

Most of deep water wells are drilled vertically. At the same time, few

exploitations were developed starting from one single drilling. Due to

economic reasons, the exploitation is expected to be achieved through

directional or horizontal drilling or by means of multiple wells.

Designing drilling in deep water regions cannot be considered a

routine procedure. Many operators consider that drilling in deep waters is

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more complicated when associated to pressures at high temperatures, as well

as when drilling in equilibrium is required.

This involved employing large teams of specialists, from the planning

stage to the final post-constructive stage, in order to review and re-analyze

the future construction programs.

Designing more wells starts with the activity of geologists and

geophysicians, once they start processing the geo-seismic investigation.

Thus, regions with a good potential are picked up and the future location for

exploration and possible exploitation is chosen.

A big volume of information is acquired in the exploratory stage. This

is related both to the geologic criterion, the drilling itself and the production

cores, and to the information concerning the environment-currents, waves,

wind speed etc. Collecting the data in the exploratory stage leads to saving

important costs in the exploitation stage, even when the future drillings are

placed in faraway regions from the exploration drilling (for most projects,

the cost of exploration drilling represents about 50-60% from the total cost

of the project). The evolution in time of the maximum depths of water for

exploration and production drillings is presented in figure 12.10.

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Fig. 12.10.The evolution in time of maximum depths of water for exploration and production drilling [20]

An important element for designing wells in deep waters is

represented by the environment factors. Quite often, these can be easily

missed, and the attempt to remediate them afterwards is always very

expensive.

Environment factors, related to drilling in deep water region mainly

refer to: the depth of water; the bottom conditions (visibility, relief, the

formation hardness, the presence of surface gas etc.); the action of winds,

waves and marine currents; the ecosystem (birds, whales, corals etc.).

The water depth represents the most important factor that is taken into

account when wells are designed. Not all equipment and technologies are

assorted for all the types of water depths. The anchor technologies depend

on the depth of the water. If the depth of the water is too big, a rig with

dynamic position (DP Rig) will be used instead of the anchored one. For

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other limits, given by the depth of operation we will have to take into

account the remote operated vehicle ROV and the types of risers.

At the same time, once the location is established, we need to analyze

the bottom conditions. Mapping the bottom of the sea and the sediment

measurement are usual for most of the wells. Often, we pick up sediment

cores to design the mooring system and the conductor pipe.

Over years, the formations which are not well consolidated at the

bottom of the sea generated many problems for drilling operators. The

presence of shallow gas must be avoided, although it is not considered as

dangerous as the one for shallow waters.

Another thing that needs to be taken into account is the visibility for

ROV, taking into account the fact that this plays an important role in the

initial drilling stage (open water). The relief of the bottom of the sea must be

inspected also in order to ensure the stability of the wellhead and template.

For depths bigger than 1 100 m, taking cores from the bottom of the

sea through conventional geophysical methods, may be applied, but the risk

of losing different devices is higher.

At the same time, collecting cores from the bottom of the sea in waters

deeper than 1 300 m necessitate using drilling ships for geophysical

measurements.

Especially in the Atlantic Ocean, weather conditions play an

extremely important role in well drilling. In other regions of the world,

weather conditions may be taken into account. For instance, hurricanes and

tropical storms must be taken into account before starting drilling (in the

design stage, supplementary plans for unexpected events are taken into

account).

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The measurements of the marine currents are necessary in more

drilling operations in deep water regions. Before starting drilling, currents at

different levels are analyzed in order to choose the equipment well.

Monitoring the currents will continue during drilling in order to make the

optimum decisions during drilling operations. At the same time, a complete

profile of the currents must be projected in order to anticipate the stress on

the riser casing and the surface joint casing.

Once the new location for drilling is chosen, the marine life must be

taken into account too. Once [20], an operator consciously delayed the

construction program of the well for 12 months, in order to properly

establish the whale migration in the region where the well was going to be

placed. Of course, these pieces of information must be known before the

drilling rig arrives in its location.

Choosing the rig for offshore drilling is above all time consuming.

The drilling rig must correspond to environment conditions. The costs of

operations on drilling rigs increased a lot, and the re-technologized drilling

rigs do not always represent the best solution.

Well known is the situation [20] in which a drilling rig with dynamic

position was re-technologized in 1996 in order to operate in regions with

depths of water between 900 m and 1500 m. Then, in 1998 the second re-

technologization took place in order to operate at a depth of 1800 m.

Afterwards, other problems appeared, meaning: in order to maintain the

position for the new depths, they needed more supplementary pieces of

equipment. They needed to create the possibility to stock risers at bigger

lengths, to increase the work capacity of tensioning devices, supplementary

power required by the system of dynamic positioning etc. The

supplementary power implies installation of several engines in the room that

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is destined to them where the space is not enough. Placing the engines in

other spaces implies reducing the space allocated to the temporary

depositing of other pieces of equipment necessary for the development of the

project, as well as changing the characteristics of rig stability.

Consequently, it is recommended that these situations are surpassed

by the help of building semi-submersible rigs or drilling ships with complete

dynamic positioning. The new drilling equipment combines the drilling

technology with testing and reservoir exploitation technologies. The

platforms were equipped with dual drilling rigs, improved riser systems,

performance blowout preventers and equipment, efficient systems to

maneuver the pipes and casing pipes, complex systems to test the wells,

ensuring new possibilities concerning the production, stocking and transfer

of the produced crude etc.

The right choice of the drilling rig implies also the understanding of

its operation limits: maximum limits, operation limits in safety conditions,

de-connecting operations, the limits of operation of the bottom equipment,

anchoring, the work duties on the platform, the limits to launch and recover

the ROV etc.

The operation limits actually indicate the moment in which operations

will be suspended in order to avoid dangerous issues. Once the operation

limits and the data relating to weather conditions are known, we can estimate

the time that is necessary in order to operate. This indicates whether we can

or cannot operate during rough weather conditions.

The operation limits in emergency situations will not be, of course,

surpassed, as long as the safety limits are reached. If the drilling rig reaches

a certain distance from the well center (a declivity of 5° in relation to the

vertical) then the risers are de-connected from the well. Due to safety

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reasons, the operation limits that require the de-connection of risers from the

well must be known.

The operation limits of the bottom equipment are generally

determined by the depth of the water and the marine currents. It is of course

understood that the equipment projected for water depths of 300 m cannot

operate in regions with water depths of 1 600 m. All limits of equipment

must be known and taken into account during the design stage of the well.

For depths of water of less than 1500 m there is a large number of

drilled wells, therefore a volume of information large enough to design wells

afterwards. Water depths of over 2000 m are taken into account for future

projects. At the same time, designing wells for big depths cannot be

separated from choosing the drilling rig.

The geologic and geophysical conditions are to be taken into account

all over the design stage. The exploration wells necessitate obtaining a

maximum number of information, out of which mechanical coring,

geophysical operations and testing the well are prior.

For the production of wells it is important that the target reservoirs are

carefully selected in order to optimize them. Modeling the reservoir is also

important. Once the target reservoirs and the future location are known, the

borehole trajectory is established. The geologic formations that are situated

at big depths are generally normally pressurized.

Yet reduced fracture gradients can be encountered in deep waters and

they must of course be taken into account.

In different regions, cementing the conductor pipe often generated

problems due to the values of these gradients. The decreased temperatures at

the bottom of the sea (normally, they vary between 1 and 2°C) have an

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important influence not only on the mud viscosity, but also on the hydrate

formation during blowouts. The cementing networks must be set according

to the temperature at the bottom of the sea or of the conductor pipe.

Some dangerous elements, such as shallow gas or potential water falls

must be taken into account too in the case of designing the well. At the same

time sediments in the stones at the bottom of the sea, result of the last ice

age, generated several problems in the West of Scotland.

The iceberg formation could be met in the polar regions and the

offshore exploitation from Canada etc.

Once all these details are established, the design of the tubing

program starts. Most projects obey the conventional casing-off schemes.

Designing starts from upwards downwards (starting with the conductor

pipe) for the exploration wells and from downwards upwards for the

production wells. Most exploration and evaluation wells are vertical wells. If

these become production wells, it will be necessary to transform the vertical

exploitation well in a horizontal one, aspect which must be taken into

account in the design stage.

Of course, exploitation of deep water wells must be designed in such a

way as to ensure the maximum production. The tubing dimension

determines the dimension of the casing. Maximizing production and

minimizing the cost may imply making developed horizontal drillings or

multiple wells through a central hole. Most of the drillings done in deep

water regions are based on a common casing-off system.

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The casing string of 30 in (conductor). Casing-off this casing, made

up of singles with thick walls, in the hole which was drilled at 36 in,

represents the later solution adopted by the majority of operators. A series of

troubles at wellheads, respectively at shallow casings were registered

predominantly in the case of the first drillings in the Atlantic Ocean. The

conductor pipes related to deep waters will take over the bending tasks and

the deformation in the case of deviations from the geometric center of the

well. The conductor pipe, having the maximum length of 150 m, is often

fixed in very soft formations.

The casing string of 20 in (surface casing or anchor casing). This

casing which is generally placed 650 m deep at the bottom of the sea is fixed

according to the fracture pressure, the pore fracture and the bending

generated by the marine currents. Choosing the connectors (at the wellhead)

depends also on the proper covering of the bending stress. Establishing the

depth of fixation of the casing shoe must take into account its resistance as

well as the weight of the mud casing at the level of the drilling platform. In

the case of reduced fracture gradients, this casing must be fixed at a higher

depth than in normal conditions.

The casing string of 13 3/8 in (intermediary). As the analysis of

different casing-off programs show, choosing this casing depends on the

geologic conditions, the pore pressure gradients, the fracture gradients etc.

The casing string of 9 5/8 in (intermediary). This casing is usually

fixed above the reservoir, with the precautions to properly cross it.

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Eliminating this casing from the well construction program necessitates a

careful evaluation. The reduced fracture gradients can lead to underground

blowouts. For instance, continuing drilling to the final depth with a bit of

12 1/4 in can be an economically convenient option as far as the

investigation and the drilling itself are concerned, yet in the case of a high

pressure reservoir there is a big open hole under the casing shoe of 13 3/8 in,

and this leads to the appearance of underground blowouts.

The casing string of 7 in (liner). This casing is introduced near the

reservoir and represents a part of the preparation of the well for production.

If an alternative (supplementary) casing of 4 1/2 in is needed, this will be

taken into account in the casing-off program.

The fluids used for drilling the upper sections of the borehole are

water-based muds, with return at the bottom of the sea. Once the riser casing

is connected, the return is made at the surface, respectively a proper drilling

fluid for the formation that is crossed, is picked up. In order to avoid the

formation of hydrates in the case of blowouts, a glycol-based system can be

used.

Most of the drilling rigs used to drill wells in deep waters are

equipped with three or four mud pumps (two - three mud pumps for the

drilling itself and another to clean the riser casing).

At the same time, the cementing program of the well must take into

account the reduced fracture gradients of the crossed formations (here we

refer to cementing the conductor pipe and the surface casing as well). The

cementing networks must take into account the reduced temperatures at the

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bottom of the sea. Pumping the cement along the water sections may lead to

complications during cementing the casing for deep water wells.

For the control of blowout preventers, the most systems used are the

complex multiplex systems. A panel fixed on the BOP stack, acted upon by

the ROV (remote operated vehicle) allows operating the BOP system in the

case of emergency situations.

Most of the wellheads have 18 3/4 in (or 16 3/4 in from the older

systems, that are equipped with a passing reductions assembly). Optionally,

systems of prevention and fighting against hydrate formation can also be

taken into consideration.

The booster lines, placed on the exterior of the riser casing are used in

order to increase the circulation speed of the drilling fluid in the annular

space of the drill string near the risers.

For exploitation, X-mas trees and production lines are used. If high

tensions appear on the production lines, the resistance to additional stress are

checked, for both the conductor pipes as well as the surface casings. In order

to ensure the precise localization of the wellhead, especially in the case of

using ROV, acoustic transmitters are placed.

Preventing and fighting against blowouts refer, among others, to the

following aspects: using bottom valves (bottom adjustable chokes);

eliminating the gas inside the BOP, after the blowout is over; detecting the

blowout at the moment of the gas presence inside the BOP (this confers the

possibility to shut the well when gas is detected inside the BOP); the time

and pumping rates for the killing of the well etc.

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Evaluating the reservoirs placed at the level of deep water regions

represents the main objective for the exploration and appraisal wells. In this

sense, all standard methods to collect cores and to make geophysical

investigations may be applied. The procedure to disconnect the risers must

always be taken into account, even while measuring the geophysical data

inside the well. The loggings connected to the drilling fluid must be

correlated with the lag time, which is generated by the reduction of the

circulation speed of the mud inside the riser casing, as well as the possibility

to pump through the booster lines in order to make the respective

correlations.

Testing the wells may be done in special safety conditions only when

we take into account disconnecting in emergency situations. Burning the

produced crude oil and the gas is not always possible, stocking hydrocarbons

and the presence of some pieces of testing equipment must be solved before

starting production tests. The reduced temperatures at the bottom of the sea

may lead to the formation of paraffine or hydrates during testing operations.

At the same time, a complete analysis of the operation that requires

supplementary safety measure must be done.

The technology to equip wells drilled in deep water regions for

production must be taken into account at the same time very cautiously. The

workovers must be minimized, and the equipment of the well must be

achieved in such a way so that the well exploitation must be done in

optimum conditions to the final stage.

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The intervention at an exploitation well implies bringing the drilling

rig in the location and reconnecting the BOP. A workover program, which

usually takes one or two days for a common platform, may last 14 days in

the case of a well situated in deep water regions [20].

The fluids produced by the well must be continuously checked in

order to detect the corrosion products, the solids, the paraffine etc, in order

to minimally reduce the well interventions. Introducing intelligent systems

(smart completions type) was done with the purpose to reduce the

interventions at the well. These systems allow isolating some of the well

sections when the water produced by the reservoir becomes a problem.

At the same time, using some permanent bottom indicators eliminates

the necessity to introduce measurement devices in the well. There are

specialized companies that offer permanent bottom indicators, that allow

workers to monitor the well continuously, by means of permanent recorders.

Using coil tubing in the case of wells drilled in deep water regions is

restricted especially for the wells that are drilled horizontally, near the

productive stratum, due to friction and coil tubing buckling.

On the other hand, the new legislation adopted by some countries (for

instance Great Britain and Brazil), as well as the API standards impose

establishing a special program of abounding these types of wells at the very

beginning, meaning in the design stage of drilling. Recovering the wellhead

and the template needs to be taken into account in the design stage. The

conductor pipe of 30 in can be also cut and recovered.

A management system of the drilling rig, respectively of the drilling

platform must be implemented before the drilling operations. For instance,

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212

in the hostile environment of the Atlantic Ocean, the minimum material

stocks must be ensured even before starting drilling. The procedures to

prevent and fight against blowouts, disconnecting them in emergency

conditions, the BOP equipment and the entire riser casing must be available

even before drilling. The special operations that imply cooperation of several

working teams presuppose a careful analysis of the operations for each stage

and taking account all the necessary precautions.

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213

13. Preliminary Test

1. A two-cylinder drilling motion compensator, illustrated below

(fig. 13.1), is supporting a drill string load of 300 000 lb on the hook. The

outside diameter OD of each motion compensator piston is 10 inches and the

piston rods are 5 inches OD. The density of steel is 65,5 ppg (pounds per

gallon, or lb per gallon).

a. What regulated air pressure is needed for the compensator to

support the given drill string load?

b. If the mud weight in the well is 10,0 ppg, what is the length (L) of

the drill string hanging on the hook if its weight in air is 24,6 lb/ft?

Assume that the well is vertical and ignore frictional effects.

Fig. 13.1. Passive drill string motion compensator

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214

2. When drilling from a floating rig in an area where shallow gas may

be encountered, many operators prefer to drill the surface hole below the

conductor casing without a drilling riser and diverter being connected to the

subsea low pressure wellhead. Explain the reasoning behind this preference.

3. Describe the main functions of a conductor string of casing

installed in a subsea well.

4. a. Explain briefly why a semi-submersible rig is inherently more

stable in a severe met ocean conditions than a drill ship of similar size and

drilling capacity.

b. Sketch a typical floating drilling rig riser system and identify each

of the main components. Explain the function of the telescopic joint.

5. Discuss the relative merits of rotary steerable systems versus

conventional “sliding” directional assemblies of improving hole cleaning

efficiency and minimizing well bore tortuosity.

6. On an onshore vertical well, 9 5/8 in casing been set at 7 000 ft

BRT. The fracture gradient at the 9 5/8 in shoe is 0,7 psi/ft. It is planned to

drill the 8 ½ in hole to a depth of 9 000 ft with a mud weight of 11,5 ppg and

a circulation rate of 500 gpm (gallon per minute). With these parameters, the

anticipated APL at the 9 5/8 in shoe is 350 psi.

Hole cleaning considerations may require the circulation rate to be

increased towards the TD of the 8 ½ in hole section. The operator`s drilling

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215

policy states that “the pressure exerted by the circulation drilling fluid at the

shoe shall not exceed fracture pressure minus 250 psi”.

The annular pressure loss in psi (APL) is governed by the

relationship:

21

22

1

2

QQ

APLAPL

= , (13.1)

where:

Q1, Q2 are initial and final circulating rates in gallons per

minute (gpm);

APL1, APL2 – the annular pressure losses corresponding to Q1 and Q2

respectively.

Calculate the maximum permissible circulating rate while drilling the

8 ½ in hole, assuming that the mud weight and mud reology remain

constant.

7. Explain briefly why a subsea vertical production tree may be

preferred to a subsea horizontal production tree when deployed in very deep

water. You may assume that there are no significant differences in the

purchase cost and availability of each type of tree.

8. In deep water, the expected fracture gradient of the rock column is

usually much less than the equivalent fracture gradient encountered in rocks

onshore. Explain why.

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216

9. A final well report states that a “Whizbore” 12 ¼ in PDC (Poly

Cristalline Diamond) bit drilled from 6 000 ft to 8 500 ft at a cost of US$

300 per foot. The total drilling time was 42 hours and the round trip time to

run and pull of the bit at the beginning and end of the bit run was 12 hours.

If the cost of the bit was US$ 75000, what was the day rate cost of the rig

used to drill the well?

10. On inspection, a used joint of API 5 in, 19,5 lb/ft, grade S135 drill

pipe was found to have an outside diameter of 4,85 in and an internal

diameter of 4,276 in. What is the maximum tensile load that can be placed

on this joint of pipe if the minimum yield stress of 135 000 psi is not to be

exceeded? Assume that the pipe joint is not subject to any applied torque.

11. a. What is the function of the ball bearing race in a roller cone bit

design?

b. A “button” bit may be used to drill very hard rock. How is the rock

failure achieved with this type of bit what is the typical cone offset?

c. Why should API 8- round and buttress threaded connections not be

used for gas or high pressure oil service?

d. Briefly explain the function of a float shoe used in a string of

casing to be cemented in the hole.

12. A vertical well is to be drilled to a TD of 10 000 ft into a gas

bearing sandstone. After running and cementing 9 5/8 in casing at 10 000 ft,

a leak-off test (LOT) was conducted immediately below the casing shoe.

The surface pressure at leak-off was 1 600 psi with 11,4 ppg test mud in the

hole. The 8 ½ in hole will be drilled to TD with a mud weight of 12,0 ppg.

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217

a. What is the leak-off pressure in psi at the shoe?

b. With the well closed in, what would be the maximum length of gas

column that could be tolerated below the 9 5/8 in shoe without the leak-off

pressure being exceeded?

Please assume that:

● Any gas influx emanates from the formation at 14 000 ft.

● The formation pressure at 14 000 ft is equal to the mud weight in

the hole plus 0,2 ppg.

● The gas hydrostatic gradient is 0,1 psi/ft.

13. Describe the meaning of the following terms and write a few

sentences on what they are and how they are used, or how they affect the

operation of the related equipment used in surface facilities:

1. Sour oil

2. BS&W

3. Cavitation

4. Gravity structures

5. FPSO

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14. Key to the exercises

1. a. Regulated air pressure needed for the compensator to support the

given drill string load is:

( )22

422

tp DD

GA

Gp−⋅

=⋅

= π, (14.1)

where:

G is the drill string load on the hook (300 000 lb);

Dp - outside diameter of each motion compensator piston (we have

two pistons with 10 in each);

Dt - the piston rods diameter (5 in).

So:

( ) ( )barpsi

DD

GA

Gptp

175479,2547510

42

000300

422 2222

==−⋅

=−⋅

=⋅

= ππ .

(1 bar = 0,068948 psi).

1.b. The length L of the drill string hanging on the hook results by

relationship:

fqLG = , (14.2)

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219

where:

G is the drill string load (300 000 lb);

q – the weight in air (24,6 lb/ft);

f – the flotability (buoyancy) factor:

s

ffρρ

−= 1 , (14.3)

ρf – the fluid density (10,0 ppg);

ρs – the steel density (65,5 ppg).

So: mftq

GL

s

f

8,38644,39214

5,651016,24

000300

1==

⎟⎠

⎞⎜⎝

⎛ −=

⎟⎟⎠

⎞⎜⎜⎝

⎛−

=

ρρ .

2. The primary function of a diverter is to divert shallow gas through

overboard pipelines before the installation of the BOP stack. After the BOP

is installed, the diverter is used to vent gas in the riser above the BOP. In

case of using riser system, the slip joint is especially vulnerable to leaks and

damage under diverter flow condition, jeopardizing the rig and personnel.

Premises (fig. 14.1):

• in this case, the casings can be brought to the platform or at an

inferior level, and the detaching and suspension devices can be assembled

above water level;

• the riser is no longer necessary;

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220

• depending on the water depth, one can renounce the base plate;

automatically, the links between the platform and the base plate

disappear and therefore the process simplifies.

Fig. 14.1. Runing in the conductor pipe (scheme)

In order to facilitate the penetration in the massive rock, the first

casing joint is sharp in its lower part. Generally, at the upper exterior part of

this casing pipe a device called mud - line ML is fixed, device which will

constitute the support for the other columns.

The mud – line will be kept at the mud level (ML).

In the upper part of the casing a device 1 will be assembled, device

which produces vibrations and percutions (a cylinder fitted with a heavy weight

piston which receives vertical movements by causing blow-ups in the upper

part of the cylinder).

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221

A particular problem which appears when runing in the conductor pipe

is represented by its guidance, handling (rotary table RT and inferior working

bridge IWB). If, while penetrating the massive rock, the conductor pipe

presents a deviation tendency, a device 1 is fixed on the inferior working

bridge, device which will bring the column back to a vertical position.

3. Conductors are usually either jetted into place or cemented in a

predrilled hole. They support the guide base or template which carries and

aligns all future wellhead installation for both and production phases. They

directly carry both the axial and bending loads imposed from the wellhead,

but are rigidly connected and minimize the resulting stresses. The conductor

shall have an internal diameter sufficient to accommodate the surface casing

and still give sufficient annular space for efficient return of well fluids

during cementing.

The conductor string of 30 in (usualy) made up of singles with thick

walls, in the hole which was drilled at 36 in, represents the later solution

adopted by the majority of operators. A series of troubles at wellheads,

respectively at shallow casings were registered predominantly in the case of

the first drillings in the Atlantic Ocean. The conductor pipes related to deep

waters will take over the bending tasks and the deformation in the case of

deviations from the geometric center of the well. The conductor pipe, having

the maximum length of 150 m, is often fixed in very soft formations.

4.a. A semi-submersible drilling rig is normally a self-propelled

working platform supported by vertical columns on submerged pontoons. By

varying the amount of ballast water in the pontoons, the unit can be raised or

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222

lowered in the water. The lower the pontoons lie beneath the surface of the

water, the less they are affected by wave action. This reduces vertical

movement and allows drilling to continue in moderately rough seas.

Drill ships have a broadly conventional ship's hull, but also feature a

large aperture, known as a "moon pool", through which drilling takes place.

Drill ships can be moved easily between locations. They can carry large

stocks of supplies, but are not as stable as semi-submersibles. The surface

exposes to action of wave and currents are higher.

4.b. The risers are designed according to the requirement included in

API standards RP2R and API 16Q, as well as within some specific norms

developed by different companies. They are made of steel X-80, with

flanges capable to resist at axial loads of 1 587 tf. In figure 14.2 is presented

a typical floating drilling rig riser system with the main components.

The riser casing is represented by a pillar connected to spherical

articulations in the lower part (lower flexible riser mounted above the LMRP

stack) and in the upper part (upper flexible riser mounted immediately under

the Diverter). The relative movement, due both to the raising and descending

of waves, as well as the relative displacement of some components is

compensated by the movement of the telescopic riser, mounted in the upper

part. The flexible risers, by construction, have different angles: 10° for the

lower flexible coupling and 15° for the upper flexible coupling. An

intermediary flexible coupling, mounted immediately under the kill riser has

the role to diminish the stress of the telescopic riser in the case of a major

deviation from the vertical position. The best way to follow the riser system

of the displacement of the platform from the vertical and the value of the

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223

tension that appears at the upper part is done by the management riser

system.

Mo details: The telescopic, or slip-joint is used at the top of a

marine riser and functions as follows:

compensates for vertical movement (heave) of the vessel while

drilling;

provides a means of connecting a bell-nipple, or diverter, assembly to

the riser;

provides fittings for rigid conduit, mud booster, choke and kill-line

hoses to the drilling vessel;

provides attachment of the riser-tensioner system.

A telescopic joint is comprised of an outer barrel attached to the marine

riser assembly and an inner barrel attached to the drilling vessel. The bell-

nipple, diverter, assembly is attached to the inner barrel, which in turn is

suspended from the rotary beams of the rig.

The outer barrel is connected to the top joint of the marine riser and has

connections, either fixed pad eyes or a support ring, for attachment of the

riser-tensioning lines. The stroke length of the inner barrel inside the outer

barrel is usually in the order of 40 to 55 feet, newer systems are up to 65

feet. Tie-downs are provided for holding the telescopic joint in the closed

position, particularly for shipping and when being picked up on the rig.

The inner barrel of a telescopic joint is connected to the riser pipe and

remains fixed with respect to the ocean floor. It is suspended from the

floating vessel by means of the tensioning system. It provides connections

for the rigid conduit, mud booster and kill and choke lines. The upper end of

the outer barrel contains one or two resilient packing elements to provide a

pressure seal around the outside diameter of the inner barrel.

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224

Fig. 14.2. The riser stack with the length of 3 050 m: LMRP-Lower Marine Riser

Package (upper BOP stack); LBOP-Lower BOP (lower BOP stack)

LMRP

LBOP 18 in. Wellhead

Datum

Rotative table

Diverter assembly Upper flexible riser

Inner tube for telescopic riser

Tensioning ring

Simple risers: t= 13/16 in

Riser for auxilliary lines connections

Riser for casing filling

Short risers

Risers with floats for 610 m depth

Riser for devices installations

8.7

16.2

22.2

7,5m

6m

49.6 1 x 27,4m

186.8

598.315 x 27,4m

1201.822 x27,4m

1805.322 x 27,4m

2354.020 x27,4m

2875.2 19 x 27,4m

2896.5 1 x 12,2m 1x 4,6m

3 x 27,4m 2984.9

1 x 6m

2991.9

1 x 4,57m 2989.5

1 x 2,43m

2998.0

Medium trip

3044,8

1 x 46,8m

3048 m 1 x ~ 3,2m

Killing riser

2903.6 1 x 6m.

8,7m

23,5m

5 x 27,4m

Upper tube for telescopic riser

Intermediary flexible riser

Risers with floats for 1220 m depth

Risers with floats for 1830 m depth

Risers with floats for 2438 m depth

Risers with floats for 3048 m depth

Simple risers: t = 13/16 in

Simple risers: t = 1 in

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225

Where two resilient seals are provided, one can be held in reserve to

be actuated if it becomes necessary to use the diverter system or in case of

failure of the other seal.

5. A rotary steerable system is a new form of drilling technology used

in directional drilling. It employs the use of specialized downhole equipment

to replace conventional directional tools such as mud motors. They are

generally programmed by the MWD engineer or directional driller who

transmits commands using surface equipment (typically using either

pressure fluctuations in the mud column or variations in the drill string

rotation) which the tool understands and gradually steers into the desired

direction. In other words, a tool designed to drill directionally with

continuous rotation from the surface, eliminating the need to slide a

steerable motor.

The advantages of this technology are many for both main groups of

users: geoscientists & drillers. Continuous rotation of the drill string allows

for improved transportation of drilled cuttings to the surface resulting in

better hydraulic performance, better weight transfer for the same reason

allows a more complex bore to be drilled, and reduced well bore tortuosity

due to utilizing a more steady steering model. The well geometry therefore is

less aggressive and the wellbore (wall of the well) is smoother than those

drilled with motor. This last benefit concerns to geoscientist because the

measurements taken of the properties of the formation can be obtained with

a higher quality.

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226

6. Normaly, we have need of many data about the mud weight,

mud reology etc. for the “rigorous”results…

Simplify:

• The fracture pressure at the 9 5/8 in shoe is:

pfrac = Γf ⋅ H, (14.4)

where = Γf is the fracture gradient and H – the depth of the 9 5/8 in shoe.

So: pfrac = 0,7 ⋅ 7000 = 4900 psi.

• “The pressure exerted by the circulation drilling fluid at the shoe

shall not exceed fracture pressure minus 250 psi”:

pfrc,lim = pfrac – 250 = 4900 – 250 = 4650 psi = 320,6 bar.

• In theses conditions

APL2 = pfrac,lim – ph, (14.5)

where ph is the hydrostatic pressure at the 9 5/8 in shoe:

ph = ρf g Hs. (14.6)

For: Hs = 7 000 ft = 2 133,6 m; ρf = 11,5 ppg = 1377,7 kg/m3;

g = 9,81 m/s2,

ph = 1377,7 ⋅ 9,81 ⋅ 2133,6 = 288,36 ⋅ 105 Pa = 288,36 bar =

4182,2 psi, and

APL2 = 4650 – 4182,2 = 467,8 psi = 32,25 bar.

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227

• The maximum permissible circulating rate while drilling the 8 ½ in

hole result by relation

21

22

1

2

QQ

APLAPL

= , (14.7)

where APL1 = 350 psi, APL2 = 467,8 psi and Q1 = 500 gpm:

sllgpmAPL

APLQQ /46,36min/9,2187578

3508,4675002

1

22

12 ===⋅=

⋅= .

(1 US gal = 3,7853 litres)

7. The primary function of a tree is to control the flow into or out of

the well, usually oil or gas. A tree often provides numerous additional

functions including chemical injection points, well intervention means,

pressure relief means (eg. annulus vent), tree and well monitoring points

(such as pressure, temperature, corrosion, erosion, sand detection, flow rate,

flow composition, valve and choke position feedback, connection points for

devices such as down hole pressure and temperature transducer (DHPT) etc.

The key advantage of the vertical tree is the ability for the tubing

hanger to either be installed directly in the subsea wellhead or in a tubing

head spool. This permits a well to be drilled and completed without having

to retrieve the subsea BOP back to the surface to install either the tubing

spool or horizontal tree spool.

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228

8. The fracture gradient resulting from the overburden of the

sediments is generated by sediment densities greater than seawater

hydrostatic only below the mudline. This results in the fracture gradient, in

equivalent mud weigh terms, being much less than for corresponding depth

below the mudline in shallower water and of course onshore where instead

the column of sea water it is only rock formation.

9. Interval drilled: h = 8 500 – 6 000 = 1500 ft.

The cost for drilling: Cd = h ⋅ c = 1500 ⋅ 300 = 450 000 US$.

The total time (drilling + round trip): T = Td + Trt = 42 + 12 = 54

hours = 2,25 days.

Total cost (drilling + bit): C = Cd + Cb = 450 000 + 75 000 = 525 000

US$.

The day rate cost of the rig: cd = C/T = 525 000 : 2,25 = 233 333,3

US$/day.

10. Transversal section area:

( ) ( ) 22222 11417,4276,485,444

indDA =−=−= ππ .

The maximum tensile load that can be placed on this joint of pipe is:

Ft = σcmin ⋅ A, where σcmin is the minimum yield stress for grade S135

(135 000 psi). So: Ft = 135 000 ⋅ 4,11417 = 555 412,95 lb = 555 412,95 ⋅

0,4448 = 247 047,67 daN.

11.a. Hardened steel ring in which the balls of a ball bearing run

(fig. 14.3). The outer and inner bearings support only the radial load. The

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229

ball bearings which retain the cutters on the legs and the thrust spindle resist

the longitudinal thrust loads and provide additional support for radial load.

Fig. 14.3. Roller cone bit design

11.b. The button bit is commonly used in drilling hard rocks and in

coring. The button bit crushes and chipping the rock by compression and

produces relatively fine cuttings.

Much of the rock removal results from the tooth sliding (gouging)

action which is affected by the degree of cone profile and cone offset (fig.

14.4). Harder bits require more tooth contact with the bottom hole and the

teeth must be designed to operate at higher WOB levels in order to

overcome the greater compressive strength of the rock. As a result, the bit

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230

teeth become shorter, blunter, more closely spaced, and more numerous as

the intended formation hardness increases.

Hard formations are drilled more effectively by a chipping and

crushing action. Hard formations are stronger than softer formation and

more likely to break. Compared to soft formation designs, harder bits utilize

shorter, blunter, more closely-spaced teeth affixed to less curved and low

offset cones. "Harder" bits are typically applied with higher WOB and lower

RPM.

Bit offset is created by offsetting the bearing journals from a

concentric alignment with the bit centerline. The scraping and gouging

action of softer bits is increased by slightly offsetting the bearing journals

from alignment with the bit centerline. This journal arrangement and

resultant cone orientation is called cone offset. Scraping action increases

with cone offset. A non-offset design produces nearly true rolling action.

Fig. 14.4. Cone profile and cone offset

11.c. Due to relatively large thread clearances in connectors, the most

likely leak path is through the thread stab flank clearance spiral. The

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231

lengthening of the pin and shortening of the box cause load flanks near the

end of pin to open, so rated working pressures is not high.

11.d. It is part of subsurface equipment attached to the casing. Float

shoes can be divided into two classifications:

● Seal type shoe that allows the casing to be floated down -- filling

the casing at the top from a hose connected to the standpipe.

● The differential type shoe that allows the drilling fluid to enter the

casing at the bottom as it is being lowered but only allows the fluid level in

the easing to reach 91% of the fluid level in the annulus. Designed to

eliminate or reduce high pressure surges against the formation as casing is

lowered.

12.a. 1 ft = 0,3048 m; 1 psi = 0,068948 bar; ppg = pounds per gallon;

1 ppg = 119,8 kg/m3 For our case: 14 000 ft = 4267 m; 10 000 ft = 3048 m;

4000 ft = 1219,2 m; 11,4 ppg = 1366 kg/m3; 12 ppg = 1438 kg/m3; 0,2 ppg =

= 23,96 kg/m3; 1600 psi = 110,3 bar.

The leak-off pressure at the shoe:

pshoe = psurface + ρf g Hs = 110,3 ⋅ 105 + 1366 ⋅ 9,81 ⋅ 3048 = 518,7 105 Pa =

518,7 bar = 7523 psi.

12.b. The formation pressure at 14 000 ft (4267 m):

pformation = (ρf + 23,96) g H = (1438 + 23,96) ⋅ 9,81 ⋅ 4267 = 611,96 bar =

8875,7 psi.

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232

It is necessary to impose: pformation – l ⋅ Γg – (1219,2 – l) Γf – ≤ pshoe.

After : Γg = 0,1 psi/ft = 0,1 0,068948/ 0,305 = 0,0226 bar/m; Γf = ρf g =

1438 ⋅ 9,81 = 0,141 bar/m.

So:

611,96 ⋅ 105 – l ⋅ 0,0226 ⋅ 105– (1219,2 – l) 0,141 ⋅ 105 ≤ 518,7 ⋅ 105;

611,96 – 0,0226 l – 1219,2 ⋅ 0,141 + 0,141 ⋅ l = 518,7;

0,1184 l = 518,7 – 611,96 + 171,9; 0,1184 l = 78,64;

l = 664,2 m = 2 179,1 ft.

13.

1. Sour oil is crude oil containing the impurity sulfur. It is common to

find crude oil containing some impurities. When the total sulfur level in the

oil is > 0.5 % the oil is called "sour". Thus sour crude is usually processed

into heavy oil such as diesel and fuel oil rather than gasoline to reduce

processing cost. The majority of the sulfur in crude oil occurs bonded to

carbon atoms, with a small amount occurring as elemental sulfur in solution

and as hydrogen sulfide gas. Sour oil can be toxic and corrosive, especially

when the oil contains high levels of hydrogen sulfide. At low concentrations

the oil has the smell of rotten eggs, but at high concentrations the inhalation

of hydrogen sulfide is instantly fatal. At higher concentrations, the hydrogen

sulfide can damage the olfactory nerve, rendering the gas effectively

odorless and undetectable, while paralyzing the respiratory system.

A hazard of hydrogen sulfide is its drastic effect on high strength

steel. H2S is soluble in water and produces a weak diabasic acid. This acid is

troublesome to high strength steels and often results in embitterment and

catastrophic metal failure. Some understanding of the physical and chemical

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action of H2S is vital to the safe and successful handling of this gas in

drilling operations.

2. a) BS&W: bottom settlings (or base sediments) and water.

Downstream of production, the first stage in the refining of crude oil is

usually the separation of BS&W at the tank farm. From here, the oil is

pumped via the crude train to the first column in the refinery system.

b) Abbreviation for basic sediment and water. BS&W is measured

from a liquid sample of the production stream. It includes free water,

sediment and emulsion and is measured as a volume percentage of the

production stream.

3. Cavitation: a) The formation of a cavity between the downstream

surface of a moving body and a liquid normally in contact with it. This can

occur in the case of a pump working at excessive speed, or in water turbines

near the draft tube. It causes corrosion of metal swing to liberation of

oxygen from the water. The accepted terminology for pitting and erosion

caused by the action of cavitation.

b) A localized gazeous conditions that is found within a liquid stream.

The formation of local cavities in a liquid as a result of the reduction of total

pressure.

4. Gravity structures: f.e. gravitational platforms, whose basic

structure is fixed on the bottom of the sea: steel gravitational platforms;

concrete gravitational platforms; hybrid gravitational platforms.

Gravitational platforms are designed in such a way that standing on the

bottom of the sea while drilling and stability in any type of weather

conditions are given by their own weight, not needing connection elements

with the bottom of the sea, as fixed platforms. When this is the case, the

inner area of the basic structure needs to have a big surface so that the

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pressure resulted from the weight of the platform, working on the bottom of

the sea, is lower than the accepted pressure of the rock on site. Concrete

gravitational platforms initially designed for the difficult areas in the North

Sea (the water is deeper than 80 m, the height of the waves is over 23 m, and

the speed of the wind is over 56m/s) and then adapted to other types of seas

and oceans, fall into two categories:

tower gravitational platforms with immersion caisson;

cylindrical gravitational towers.

5. a) “FPSO” stands for Floating Production, Storage and Offloading.

An FPSO system is an offshore production facility that is typically ship-

shaped and stores crude oil in tanks located in the hull of the vessel. The

crude oil is periodically offloaded to shuttle tankers or ocean-going barges

for transport to shore. FPSO’s may be used as production facilities to

develop marginal oil fields or fields in deepwater areas. Some FPSOs are

also capable of drilling; in this case they are termed floating production,

drilling and system off loaders (FPSOs).

b) FPSO: Floating Production, Storage and Offloading. Typically a

tanker type hull or barge with wellheads on a turret that the ship can rotate

freely around (to point into wind, waves or current). The turret has wire rope

and chain connections to several anchors or it can be dynamically positioned

using thrusters. Water depths 200 to 2000 meters. Common with subsea

wells. The main process is placed on the deck, while the hull is used for

storage and offloading to a shuttle tanker. May also be used with pipeline

transport.

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Selective bibliography

1. Macovei, N.: Tehnologia forării sondelor (4 volume), I. P. G. Ploieşti,

1987 – 1990.

2. Georgescu, Ghe.: Tehnologia forării sondelor, Editura Didactică şi

Pedagogică, Bucureşti, 1983

3. Iordache, G., Macovei, N.: Forarea sondelor – probleme, Editura

Tehnică, Bucureşti, 1974.

4. Tatu, Gr.: Carnet tehnic. Forarea sondelor, Editura Tehnică, Bucureşti,

1983.

5. Raşeev, D., Ulmanu, V., Georgescu, Ghe.: Construcţia şi exploatarea

garniturii de foraj, Editura Tehnică, Bucureşti, 1986.

6. Banciu, I.: Optimizarea regimului de foraj, Editura Tehnică, Bucureşti,

1984.

7. Gabolde, G., Nguyen, J.P.: Formulaire du foreur, Editions Technip, Paris,

1989.

8. ∗∗∗ API, Spec. 6A, Ediţia a 5-a, 1 aprilie, 1986.

9. Nguyen, J.P.: Les têtes de puits terrestres, E.N.S.P.M., Paris, 1993.

10. Rădulescu, Al. S.a.: Carnet tehnic. Utilaj petrolier – foraj, Editura

Tehnică, Bucureşti, 1975.

11. Cristea, V. ş.a.: Instalaţii şi utilaje pentru forarea sondelor, Editura

Tehnică, Bucureşti, 1985.

12. Macovei, N.: Fluide de foraj şi cimenturi de sondă, Editura Universităţii

din Ploieşti, 1993.

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13. Avram, L.: Îmbunătăţirea consolidării găurilor de sondă cu diametre

mari, în condiţiile respectării echilibrului strat-sondă-coloană, Teză de

doctorat, Universitatea « Petrol şi Gaze » din Ploieşti, 1993.

14. Iordache, G. ş.a.: Forarea sondelor cu diametre mari, Editura Tehnică,

Bucureşti, 1984.

15. Adams, N.: Drilling engineering, PennWell Publishing Company, Tusla,

Oklahoma, 1985.

16. Iordache, G., Avram, L.: Foraje speciale şi foraj marin (volumul 2),

Editura « Help Ministries România », Ploieşti, 1995.

17. Nguyen, J.P.: Le forage, Editions Technip, Paris, 1993.

18. Coroian – Stoiecescu, C.: Economia petrolului, Universitatea « Petrol şi

Gaze » din Ploieşti, 1996.

19. ∗∗∗ MMS - Mineral Management Service, Agenţie guvernamentală

SUA, 2005.

20. Aid, P., Deepwater well design overview, Kingdom drilling, March,

2001.

21. Helgensen, J.T., Stene, F., Tennessen, R., Cementing in low temperature

enviroment, shallow water flows, and hydrates, Offshore magazine,

September, 2000.

22. Furlow,W., Riser development guidelines example of need for

standardization in deepwater, Offshore magazine, September, 2000.

Periodice: Mine, Petrol şi Gaze; World Oil; Journal Petroleum

Technology (J.P.T.); Oil and Gas Journal; Drilling; Pipeline and Gas

Journal; Offshore; Revue de l`Institut Français du Pétrole; Forages; Revista

Română de Petrol (1990 – 2009).