Drilling.modsol

8/9/2019 Drilling.modsol

1/42

Model Solutions to Examination

1

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, , ,

, , ,

y y y

y y y

y y y

y y y

z z z z

z z z z

z z z z

z z z z

| | | |

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Date:

1. Complete the sections above but do not seal until the examination is finished.

2. Insert in box on right the numbers of the questions attempted.

3. Start each question on a new page.

4. Rough working should be confined to left hand pages.

5. This book must be handed in entire with the top corner sealed.

6. Additional books must bear the name of the candidate, be sealed and be affixed tothe first book by means of a tag provided

Subject:

INSTRUCTIONS TO CANDIDATES

8 Pages

PLEASE READ EXAMINATION REGULATIONS ON BACK COVER

No. Mk.

N A M E : R E G I S T R A T I O N N O . :

C O U R S E : Y E A R : S I G N A T U R E : C o m p l e t e t h i s s e c t i o n b u t

d o n o t

s e a l u n t i l t h e e x a m i n a t i o n

i s f i n i s h e d


2/422


3/42


3

SECTION A

1.a. Cutting Structure (teeth):

- Height and spacing of teeth:

drillability/hardness of form

- Soft formations require long widely spaced teeth.

- Hard formation require shortclosely spaced teeth- Teeth hardfacing:

abrasiveness of formation

Bearings

- size:

large or small depends on WOB and rotating hours- sealed/non-sealed:

sealed results in longer number of rotating hours

- ball/roller/journal bearings:

journal bearings are most resistant to wear and damage but this

will depend on the planned WOB and rotating hours

Cone Design

- diameter of cone:

will be controlled by the size of teeth, size of bearings,and

requirement for mechanical cleaning in soft formations

- meshing/interfit:

requirement for cleaning


4/424

- offset:

high offset to give scraping action in soft formations

no offset (no scraping) in hard formations.

Fluid Circ.

- number/position of nozzles:

determines the distribution of flow over the bit face- centre jet:

used mostly in very soft formations

- extended nozzles:

used mostly in soft formations

1b. Performanc Criteria:ROP

Length run

Cost/ft

i. ROP

useful if run length of run not an issue (10 ft @ 100 ft/hr - good orbad?)

ii. Length run

useful if ROP not an issue (1000ft @ 1ft/hr - good or bad?)


5/42


5

iii. Cost/ft

Cost/ft = Bit cost + Rig Rate(Trip time + Drilling time)

Interval Drilled

Cost/ft includes both ROP and length of run therefore the best option

Cost/ft can be used in both real time (when to pull the bit) and retro

spectively (bit selection). When using retrospectively normalise bitcosts, rig rate and trip time since these are not a function of bit per

formance


6/426

2a. The minimum mudweight is based on the pore pressure and borehole

stability considerations and the maximum is based on the fracture

pressure of the formation to be drilled.

Formation pore pressure: - Minimum mudweight to avoid Influx

- Include 200 psi overbalance over pore

pressure- However, minimise overbalance to avoid-

chip hold down

differential sticking

formation damage in reservoir

Borehole Stability: - Minimum mudweight may depend oninstability

- Difficult to quantify analytically and

may be based on experience

Formation Frac. Pressure: - Max. mudwt. to avoid Lost Circulation

- Less than Geostatic Pressure (1.0 psi/ft)


7/42


7

2b. Minimum mudweight based on Formation Pore pressure which can be

predicted from:

- Pre Drilling information :

seismic (formation velocity)

“d” exponent (previous wells)

DST/RFT data (previous wells)

Production data (reservoir sections)density logs (previous wells)

- Whilst Drilling:

“d” exponent

shale density

losses

influxesborehole collapse

Maximum mudweight is based on Formation Frac Pressure which can be

predicted from :

- Pre Drilling and whilst drilling

- leak off tests- losses

- Calc.from poissons ratio (cores) and pore

pressure


8/428

3a. (List any four of the following)

Flow Rate Increase - While the mud pumps are circulating at a

constant rate there should be a steady flow rate of mud returns. If

this flowrate increases (without changing the pump speed) this is a

sign that formation fluids are feeding into the wellbore and helping to

move the contents of the annulus to the surface.

Pit Volume Increase - A rise in the level of mud in the active pits is a

sign that some mud has been displaced from the annulus by an influx of

formation fluids. The volume of this influx is equal to the pit gain and

should be noted for use in later calculations.

Flowing Well with Pumps Shut Off - When the rig pumps are not oper

ating there should be no returns. If the pumps are shut down and the

well continues to flow it must be due to a kick. (There are 2

exceptions to this rule (a) thermal expansion of mud in the annulus and

(b) U tubing effect when mud in drillstring is heavier than mud in

annulus). A flow check is often carried out to confirm whether thewell is kicking or not.

Improper Hole Fill-Up During Trips - As mentioned earlier the hole

should require to be filled when pipe is tripped out. If it does not take

the calculated volume the drillpipe volume has already been replaced by

formation fluids


9/42


10/4210

(ii) reduced overbalance (increase in pore pressure). Experience

has shown that drilling breaks are often associated with overpressured

zones. It is recommended that a flow check is carried out after a

drilling break.

Event Possible Other Cause

Flow Rate Increase unbalanced mud column

(control on MW pumped)

Pit Volume Increase surface transfer of mud

Flow when not circulating temperature effect/time

Pump pressure decrease Washout in stringGas cut mud Percolatiointo bore hole

Drilling Break poss. new formation

(circ bottoms up)


11/42


11

4a. OBM

Advantages

- Shale Drilling (Inhibition)

- Lubrication (in extended reach) wells

- Produces Gauge hole (for cementing)

- Reduces Corrosion

- Creates a Thin Mud Cake (preventing diff. stick)- Increased ROP

- Minimises Reservoir damage

Disadvantages

- High Cost

- Environmentally sensitive- Complex formulation

- Poor Temp. Stability

- Kick detection difficult

- Special logging tools required

- Rheological control difficult

- Rig Modifications to prevent Leaks- Removal when cementing is diffi cult

4b. (Two of the Following)(Two of the Following)(Two of the Following)(Two of the Following)(Two of the Following)

Mud densityMud densityMud densityMud densityMud density

A sample of mud is weighed in a mud balance. The cup of the balance is

completely filled with mud and the lid placed firmly on top. (Some mud

should escape through the hole in the lid). The balance arm is placed

on the base and the rider adjusted until the arm is level. The density


12/4212

can be read directly off the graduated scale at the left-hand side of

the rider.

Mud densities are usually reported to the nearest 0.1 ppg (lbs per

gallon). Other units in common use are lbs/ft3, psi/ft, psi/1000ft, kg/l

and specific gravity (S.G.).

Viscosity

Two common methods are used on the rig to measure viscosity:

Marsh funnel:Marsh funnel:Marsh funnel:Marsh funnel:Marsh funnel: This is a very quick test which only gives an indication

of viscosity and not an absolute result. The funnel is of standard

dimensions (12" long, 6" diameter at the top, 2" long tube at the bottom, 3 /16" diameter). A mud sample is poured into the funnel and the

time taken for one quart (946 ml) to flow out into a measuring cup is

recorded. (Fresh water at 75oF has a funnel viscosity of 26 sec/

quart.) Since the flow rate varies throughout this test it cannot give a

true viscosity. Non-newtonian fluids (i.e. most drilling fluids) ex

hibit different viscosities at different flow rates. However the funnel viscosity can only be used for checking radical changes in mud vis

cosity. Further tests must be carried out before any treatment can be

recommended.

Rotational viscometer (Figure 6):Rotational viscometer (Figure 6):Rotational viscometer (Figure 6):Rotational viscometer (Figure 6):Rotational viscometer (Figure 6): This device gives a more meaningful

measure of viscosity. A sample of mud is sheared at a constant rate

between a rotating outer sleeve and an inner bob. The test is con

ducted at a range of different speeds, 600 rpm, 300 rpm, 100 rpm etc.


13/42


13

(laboratory models can operate at 6 different speeds). The standard

procedure is to lower the instrument head into the mud sample until

the sleeve is immersed up to the scribe line. The rotor speed is set at

600 rpm and after waiting for a steady dial reading this value is re

corded (degrees). The speed is changed to 300 rpm and again the

reading is recorded. This is repeated until all of the required dial

readings have been recorded. The results can be plotted and assumingthat there is a linear relationship between shear stress and shear rate

(i.e. Bingham plastic) the following parameters can be calculated from

the graph:

Plastic Viscosity (PV) = D600 - D300 (centipose)

Yield Point (YP) = D300 - PV (lb/100 ft2)

Gel StrengthGel StrengthGel StrengthGel StrengthGel Strength

A third property is used to describe the attractive forces while the

mud is static. This is called “gel strength”. Gel strength can be

thought of as the stress required to get the mud moving. The gelstrength can be measured using the viscometer. After the mud has

remained static for some time (10 secs) the rotor is set at a low speed

(3 rpm) and the deflection noted. This is reported as the “initial or

10 second gel”. The same procedure is repeated after the mud remains

static for 10 minutes, to determine the “10 minute gel”. Both gels are

measured in the same units as Yield Point (lbs/100ft2). Gel strength

usually appears on the mud report as two figures (e.g. 17/25). The

first being the initial gel and the second the 10 minute gel.


14/4214

5a.

- Position the rig - Towed (Semis) or self propelled (ships), set

anchors or establish d.p. and perform seabed

inspection,

- Run TGB - run on d.p., 4 guidewires (3/4" dia), has 46"

hole through the centre- Drill 36" hole - bit plus h.o. run with UGF

- Run PGB and 30" csg - run together

- Cement 30" Csg.

- Rig up Diverter* - consists of latch, uniflex joint, riser, tel

escopic joint, diverter

- Drill 26" hole- Rig down diverter**

- Run HPWHH with 20" Csg, - High pressure housing on top of 20"

casing

- Cement 20" csg

- Run BOP stack-up*** - BOP (hydraulic connector, BOP Rams, Hydril),

LMRP (Hydraulic connector, Ann.preventer plus uniflex joint)

Riser and telescopic joint

- Drill 171/2" hole, run cement 133/8" Csg ] All casings land and

- Drill 121/4" hole, run and cement 95/8" Csg ] seal inside 20" hp


15/42


15

wellhead housing

* No diverter - flow at seabed, possible listing of rig with diverter -

gas flow at surface, possible washout and ignition

** Well exposed - may run logs over open hole before removing

diverter.

*** BOP on well untill all casings set and cemented.

b. The major differences between the subsea wellhead and suface

systems are:

Component/Function Subsea Surface

BOP on seabed at surface

casing supported on seabed at surface

annulus access only between tubing all annuli

and prod. casing, none

between casingsannulus seal all at seabed all at surface

configuration 13 3/8", 9 5/8" and 7 “ stack up of spools

land inside HPWHH

BOP removal BOP in place from remove and replace

landing HPWHH BOP on every

spool.


16/4216

6a. Subsurface:

Sensors GR, Resistivity, WOB, RPM, Direction

(azimuth and inclination)

Transmitter :

Rotaryvalve

Motor

Rotating disc

Time

S t a n d p i p e p r e s s u

r e

Bitvalue

(1)

Bitvalue

(1)

Bitvalue

(1)

Phase shift or remain

Valve

Actuator

Time


r e

Pulse presence or absenceMud

oletool

BypassValve

Actuator

Mud

Mud

Time


r e

Bitvalue

(1)

Bitvalue

(1)

Bitvalue

(1)

Bitvalue

(1)

Bitvalue

(1)

Bitvalue

(1)

Power Source:


17/42


17

Surface:

0

4 45 2 56

P u

l s e

I n d i c a

t o r

P r o c e s s e

d

F i l t e r e

d

R a w

Standpipe

Recorder

Computer

Terminal

Rig Floor Display

PressureTransducer

DataAcquisition

System

AuxiliaryServicesPresentationReciever

6b. (Four of the following)

MWD tools are very useful for real time identification ofthe forma

tions which have just been drilled. If not available can only determine

position geologically by circ. bottoms up to retrieve cuttings. This is

very time consuming. The tool is therefore widely used for:

- Core point selection

- Casing point selection (when precise placement required)

- Formation correlation when geosteering to stay in the reservoir

They are used to replace wireline logging operations saving time

and money.

They are most widely used to provide real time information on bit

trajectory (Directional Control) providing more frequent surveys and

saving time and money over the conventional survey techniques.


18/4218

SECTION B

B1 a. Production Casing (9 5/8" @ 10000 ft)

Packer Fluid: 9 ppg

Packer Depth: 7200ft

Perf. Depth: 7350-7750ftMax. Form. Press. grad.: 14 ppg

Burst Design - Production :

Internal Load: Assuming that a leak occurs in the tubing at surface

and that the closed in tubing head pressure (CITHP) is acting on theinside of the top of the casing. This pressure will then act on the

colom of packer fluid. The 9 5/8" casing is only exposed to these

pressure down to the Top of Liner (TOL). The liner protects the re

mainder of the casing.

Max. Pore Pressure at the top of the production zone

= 14 x 0.052 x 7350


19/42


19

= 5351 psi

CITHP (at surface) = Pressure at Top of Perfs - pressure due to

colom of gas (0.115 psi/ft)

= 5351 - 0.115 x 7350

= 4506 psi

Pressure at Top of Packer = CITHP+ hydrostatic colom of packer fluid= 4506 + (9 x 0.052 x 7200)

= 7876 psi

External Load: Assuming that the minimum pore pressure is acting at

the packer depth and zero pressure at surface.

Pore pressure at the Packer

= 9.5 x 0.052 x 7200

= 3557 psi

External pressure at surface = 0 psi

SUMMARY OF BURST LOADSSUMMARY OF BURST LOADSSUMMARY OF BURST LOADSSUMMARY OF BURST LOADSSUMMARY OF BURST LOADS

DEPTH EXT. LOAD INT. LOAD NET LOAD DESIGN LOAD

(LOAD X 1.1)

Surface 0 4506 4506 4957

Packer 3557 7876 4319 4751

(7200 ft)


20/4220

Collapse Design - Drilling

Internal Load: Assuming that the casing is totally evacuated due to

gaslifting operations

Internal Pressure at surface = 0 psi

Internal Pressure at Top of Packer = 0 psi

External Load: Assuming that the maximum pore pressure is acting on

the outside of the casing at the Packer

Pore pressure at the Packer = 9.5 x 0.052 x 7200= 3557 psi

External pressure at surface = 0 psi

SUMMARY OF COLLAPSE LOADSSUMMARY OF COLLAPSE LOADSSUMMARY OF COLLAPSE LOADSSUMMARY OF COLLAPSE LOADSSUMMARY OF COLLAPSE LOADS

DEPTH EXT. LOAD INT. LOAD NET LOAD DESIGN LOAD

(LOAD X 1.1)

Surface 0 0 0 0

Packer 3557 0 3557 3913

(7200 ft)

CASING SELECTED 9 5/8” 47 LB/FT L-80 VAM


21/42


21

B1 b. It has been established that an axial load can affect the burst and

collapse ratings of casing. This is represented in the Figure below. It

can be seen that as the tensile load imposed on a tubular increases

the collapse rating decreases and the burst rating increases. It can

also be seen from this diagram that as the compressive loading in

creases the burst rating decreases and the collapse rating increases.

The burst and collapse ratings for casing quoted by the API assumethat the casing is experiencing zero axial load. However, since

casing strings are very often subjected to a combination of tension and

collapse loading simultaneously, the API has established a relationship

between these loadings.

The Ellipse shown in the Figure below is in fact a 2D representation ofa 3D phenomenon. The casing will in reality experience a combination

of three loads (Triaxial loading). These are Radial, Axial and Tangen

tial loads. The latter being a resultant of the other two.

120 100 80 60 40 20 0 20 40 60 80 100 120

100

100

120

120

80

80

60

60

40

40

20

20

LONGTIUDINA L COMPRESSION LONGTIUDINA L TENSION

C O L L A P S E

B U R S T

0

PER CENT OF YIELD STRESS

P E R

C E N T O F Y I E L D S T R E S S

COMPRESSIONAND

BURST

TENSIONAND

BURST

TENSIONAND

COLLAPSE

COMPRESSIONAND

COLLAPSE


22/4222

B1 c. The conventional wellhead system provides the following functions:

Suspend the weight of the casing -

the casing is generally landed in the wellhead spools in tension.

the total weight of the casing strings will be transmitted down

through the wellhead spools and housing into the

surface casing.

Seal off the casing annulus at surface -

the annulus between casing strings is sealed off at the

bottom of the casing by cement

the annuli at surface are sealed by elastomer seals on the

casing hanger.

Provide access to the Annulus between the casing strings -

access to the annulus will allow any pressure in the annulus to

be monitored and if necessary bled off. These pressures may

originate in open formations above the top of cement in the

annulus. This is particularly important if the build up is due togas.


23/42


23

B2 a.

Pann

P dp Pdp

h dp hann

ρ i h i

ρ m ρ m

Pann

(i) KILL MUDWEIGHT

Bottom hole press= (8000 x 12x 0.052) + 600

= 5592 psi

kill mud = 5592/8000

= 0.699 psi/ft= 13.44 ppg

(if 200 psi overbalance is added kill mudweight = 0.724 psi/ft)

With 200 psi overbalance the kill mudweight is close to the LOT pres

sure at the previous shoe.


24/4224

(ii) NATURE OF INFLUX

20 bbls pit gain

Capacity hole/collars = 0.0323 bbls/ft

300 ft collars = 300 x 0.032 = 9.69 bbls

Therefore (20 - 9.69) = 10.31 bbls of influx opposite d.p.

Capacity d.p/hole = 0.045 bbls/ft

10.4 / 0.045 = 229 ft.

Total height of influx = 529 ft.

(Influx occupies annulus to 231 ft above top of collars)

(12 x 0.052 x h dp) + 600 = 750 + (12 x 0.052 x (d- h i)) + ρ i x 0.052 x h i180 = 27.5 ρ iρ

i = 6.55 ppg

ρ i = 0.34 psi/ft ( probably oh…


25/42


25

B2 b. The one circulation method can be divided into 4 phases (See Figure

B2.1).

Phase I (displacing drillstring to heavier mud)Phase I (displacing drillstring to heavier mud)Phase I (displacing drillstring to heavier mud)Phase I (displacing drillstring to heavier mud)Phase I (displacing drillstring to heavier mud)

As the driller starts pumping the kill mud down the drillstring the

choke is opened. The initial circulating pressure will be Pc1. The choke

should be adjusted to keep the standpipe pressure decreasing until allof the drillpipe is full of killweight. In fact the pressure is reduced in

steps by maintaining standpipe pressure constant for a period of time,

then opening it more to allow the pressure to drop inregularincrements.

Once the heavy mud completely fills the drillstring the stand pipe

pressure should become equal to Pc2. The pressure on the annulus

usually increases during phase I due to the reduction in hydrostaticpressure caused by gas expansion in the annulus.

Phase II (pumping heavy mud into the annulus until influx reachesPhase II (pumping heavy mud into the annulus until influx reachesPhase II (pumping heavy mud into the annulus until influx reachesPhase II (pumping heavy mud into the annulus until influx reachesPhase II (pumping heavy mud into the annulus until influx reaches

the choke)the choke)the choke)the choke)the choke)

During this stage the choke is adjusted to keep the standpipe pressure

constant (i.e. standpipe pressure = Pc2). The annulus pressure will varymore significantly than in phase I due to 2 effects:

(i) the increased hydrostatic head due to the heavy mud will tend to

reduce Pann.

(ii) if the influx is gas, the expansion will tend to increase Pann due to

the decreased hydrostatic head in the annulus.


26/4226

The profile of annulus pressure during phase II therefore depends on

the nature of the influx (see Figure B2.2).

Phase III (time taken for all the influx to be removed from thePhase III (time taken for all the influx to be removed from thePhase III (time taken for all the influx to be removed from thePhase III (time taken for all the influx to be removed from thePhase III (time taken for all the influx to be removed from the

annulus)annulus)annulus)annulus)annulus)

As the influx is allowed to escape the hydrostatic pressure in the

annulus will increase due to more heavy mud being pumped through thebit to replace the influx. Therefore, Pann will reduce significantly. If

the influx is gas this reduction may be very severe and cause

vibrations which may damage the surface equipment (choke lines and

choke manifold should be well secured). As before the standpipe

pressure should remain constant.

Phase IV (stage between all the influx being expelled and heavyPhase IV (stage between all the influx being expelled and heavyPhase IV (stage between all the influx being expelled and heavyPhase IV (stage between all the influx being expelled and heavyPhase IV (stage between all the influx being expelled and heavy

mud reaching surface)mud reaching surface)mud reaching surface)mud reaching surface)mud reaching surface)

During this phase all the original mud is circulated out of the annulus

and is replaced by a full column of heavy mud. The annulus pressure

will reduce to 0, and the choke should be fully open. The standpipe

pressure should be equal to Pc2. To check that the well is finally deadthe pumps can be stopped and the choke closed. The pressures on

drillpipe and annulus should be 0 (if not continue circulating). When

the well is dead open the annular preventer, circulate and condition the

mud prior to resuming normal operations. (A trip margin of 0.2 - 0.3

ppg may be added to the mud weight to allow for swabbing effects

when pulling out of hole).


27/42


27

Phase 1

P c 1

P dp

Phase 2 Phase 4

HOKE P RESSURES

P RESSURES

ND P IP E

P r ess ur es v e r s u s T im e

P c 2

P a nn

Phase 3

(H ea v y m u d fills p ip e ) (In flu x p u m p e d to s ur fa c e )

(In flu x d is c ha r g e d )

(F ill a nn u lu s w i t hhea v y m u d )

Phase 1 Phases 2

Influence of gas

Pann

Influence of heavy mud

Result of P choke

Annulus or Choke Pressures versus Time

Figure B2.2

Figure B2.1


28/4228

B2 c.

i. An internal BOP must be available on the drillfloor.

ii. Adequate Barite must be on site to kill the well. If OBM it

must be possible to condition the mud sufficiently to accept

the Barites.

iii. If drilling a particularly ‘high pressure’ well a pit of heavy weight

mud could be made upand ready for use.

iv. The drilling crew should be trained in detecting a kick and well

killing operations

v. The drilling crew should be trained in ‘stripping into’ a well.

vi. Regular ‘kick drills’ should be conducted to determine the

crews state of alertness.

vii.The BOP stack should be tested regularly (once a week)


29/42


29

B3a

Calculate displacement of target:

, , , ,

, , , ,

y y y y

y y y y

x

y

α

α

β

E

X

BOPK R

R

d

D

Displacement = 3000 2 + 3500 2 √= 4610 ft

a. DRIFT ANGLE:

2.5 R = 360

100 2π


30/4230

R = 360 x 100 (Radius of BU Section)

5.0 x π

= 2292 ft

(i) Tan y = 4610 - 2292 = 2318

5500 5500

y = 22.85o

(ii) Siny = OB = 2318

0X 0X

0X = 5969.3 ft

(iii) Sinx = R

OX

= 2292

5969

x = 22.60

α = x + y

= 45.4o (Drift/Tangent Angle)


31/42


31

b. TVD and Displacement

β = 180 - 90 - α

= 44.6o

Cos β = PE = 0.712EO

PE = 1632

TVD (E) = 4132 ft

Sin β = PO

R

PO = 1609 ft

KP = KO - PO

= 2292 - 1609

= 683 ft

Displacement (E) = 683 ft


32/4232

c. Total Along Hole Depth

α = KE

360 2 π x 2292

0.1261 = KE

14401

KE = 1816 ft

Total AH = 2500 + 1816 + EX

EX = OX cosx= 5969 x 0. 7022

= 551 ft

Total AH depth = 9826.64 ft

B3 b. Formations (BUR, hole angle):

Borehole Stability, mud requirements Casing scheme , KOP, Doglegs,

Shape, Max. Angle, BUR

Specification of Target, Size and Shape

The location, size and shape of the target is usually chosen by

geologists and/or reservoir engineers. They will give the geographical


33/42


33

co-ordinates, true vertical depth and specify the size of the

target(e.g. radius of 100'). In general the smaller the target area, the

more directional control required, and so the more expensive the well

will be.

Rig Location

The position of rig must be considered in relation to the expectedgeological strata to be drilled (e.g. salt domes, faults etc.). When

developing a field from a fixed platform the location is critical in order

to cover the full extent of the reservoir.

Location of Adjacent Wells

Drilling close to an existing well is highly dangerous. This is especiallytrue on offshore platforms where the wells are very closely spaced.

The proposed well must be deflected or nudged away from all adjacent

wells.

Casing and Mud Programmes

In highly deviated wells rubber drillpipe protectors may be installed toprevent casing wear. To avoid drilling problems the mud properties

have to be monitored closely. Some operators prefer to use oil based

mud in directional holes to provide better hole conditions.

Hole Size

Larger hole diameters are preferred since there is less natural

tendency to deviate, resulting in better control of the well path.


34/4234

Geological Section

The equipment and techniques involved in controlling the deviated

wellpath are not suited to certain types of formation. It is for example

difficult to initiate the deviated portion of the well (kickoff the well) in

unconsolidated mudstone. The engineer may therefore decide to

drill vertically through the problematic formation and commence the

deviation once the well has penetrated the next most suitableformation type. The vertical depth of the formation tops will be

provided by the companies geologists.


35/42


35

5b. Gyroscope

Advantages

Use in pipe/casing

no monels required

accurate

provides true north

Disadvantages

complicated tool

requires surface alignment

Magnetic Compass:Advantages

simple

requires monel collars

cheap

Disadvantages

can’t use in csg./pipe

magnetic not true north


36/4236

B4.a.

1250'

1750'

1800'

3300'

5100'5110'

77 lb/ft

72 lb/ft20" Casing

DV Collar

13 3/8" Casing18" Hole

a.a.a.a.a. No. sxs cementNo. sxs cementNo. sxs cementNo. sxs cementNo. sxs cement

Stage 1:Stage 1:Stage 1:Stage 1:Stage 1:

Slurry volume between the casing and hole:Slurry volume between the casing and hole:Slurry volume between the casing and hole:Slurry volume between the casing and hole:Slurry volume between the casing and hole:13 3/8" csg/ 17 1/2" hole capacity = 0.7914 ft 3/ft

annular volume = 1800 x 0.7914

= 1425 ft 3

plus20% excess = 285 ft 3

Total = 1710 ft 3

Slurry volume below the float collar:Slurry volume below the float collar:Slurry volume below the float collar:Slurry volume below the float collar:Slurry volume below the float collar:

Cap. of 13 3/8, 72 lb/ft csg = 0.8314 ft 3/ft


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37

shoetrack vol. = 60 x 0.8314

Total = 50 ft 3

Slurry volume in the rathole:Slurry volume in the rathole:Slurry volume in the rathole:Slurry volume in the rathole:Slurry volume in the rathole:

Cap. of 17 1/2" hole = 1.7617 ft 3/ft

rathole vol. = 10 x 1.7617

= 17.6 ft 3

plus 20% = 3.5 ft 3

Total = 21.1 ft 3

TOTAL SLURRY VOL. STAGE 1 :TOTAL SLURRY VOL. STAGE 1 :TOTAL SLURRY VOL. STAGE 1 :TOTAL SLURRY VOL. STAGE 1 :TOTAL SLURRY VOL. STAGE 1 : 17811781178117811781 ftftftftft 33333

Yield of class G cement for density of 15.8 ppg = 1.15 ft3

/sk

TOTAL No. SXS CEMENT STAGE 1:TOTAL No. SXS CEMENT STAGE 1:TOTAL No. SXS CEMENT STAGE 1:TOTAL No. SXS CEMENT STAGE 1:TOTAL No. SXS CEMENT STAGE 1: 1781/1.15 = 1549 sxs1781/1.15 = 1549 sxs1781/1.15 = 1549 sxs1781/1.15 = 1549 sxs1781/1.15 = 1549 sxs


20" csg/ 13 3/8" csg = 1.019 ft 3/ft

annular volume = 500 x 1.019= 510 ft 3

TOTAL SLURRY VOL. STAGE 2 :TOTAL SLURRY VOL. STAGE 2 :TOTAL SLURRY VOL. STAGE 2 :TOTAL SLURRY VOL. STAGE 2 :TOTAL SLURRY VOL. STAGE 2 : 510 ft510 ft510 ft510 ft510 ft 33333

Yield of class G cement for density of 13.2 ppg = 1.89 ft 3/sk

TOTAL No. SXS CEMENT STAGE 2:TOTAL No. SXS CEMENT STAGE 2:TOTAL No. SXS CEMENT STAGE 2:TOTAL No. SXS CEMENT STAGE 2:TOTAL No. SXS CEMENT STAGE 2: 510/1.89 = 270 sxs510/1.89 = 270 sxs510/1.89 = 270 sxs510/1.89 = 270 sxs510/1.89 = 270 sxs


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b.b.b.b.b. Amount of mixwaterAmount of mixwaterAmount of mixwaterAmount of mixwaterAmount of mixwater


mixwater requirements for class G cement for density of 15.8 ppg

= 0.67 ft 3/sk

Mixwater requiredMixwater requiredMixwater requiredMixwater requiredMixwater required ===== 1549 x 0.671549 x 0.671549 x 0.671549 x 0.671549 x 0.67===== 10381038103810381038 ftftftftft 33333


mixwater requirements for class G cement for density of 13.2 ppg

= 1.37 ft 3/sk

Mixwater requiredMixwater requiredMixwater requiredMixwater requiredMixwater required ===== 270 x 1.37270 x 1.37270 x 1.37270 x 1.37270 x 1.37

===== 370370370370370 ftftftftft 33333

c. Displacement VolumesDisplacement VolumesDisplacement VolumesDisplacement VolumesDisplacement Volumes

Stage 1:Stage 1:Stage 1:Stage 1:Stage 1:Displacement vol. = vol between cement head and float collar

= 0.148 (bbl/ft) x 5040 = 746 bbl

(add 2 bbl for surface line) = 748 bbl= 748 bbl= 748 bbl= 748 bbl= 748 bbl


Displacement vol. = vol between cement head and stage

collar


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39

= 0.148 (bbl/ft) x 1750 = 259 bbl

(add 2 bbl for surface line) = 261 bbl= 261 bbl= 261 bbl= 261 bbl= 261 bbl

B4. b.

Run casing with centralisers and possibly scratchers

Circulate casing contents (x 2)

First stage - The procedure is similar to that for a single stage

operation, except that no wiper plug is used ahead of the cement :

* pump spacer ahead of cement

* pump cement

* release shut-off plug* displace with spacer and low yield mud

A smaller volume of slurry is used, so that only thelower part of the

annulus is cemented and only a second wiper plug is used. The height

of this cemented part of the annulus will depend on the fracture

gradient of the formation (a height of 3000' - 4000' above the shoe iscommon).

Second stage - This involves the use of a special tool known as a

stage collar, which is made up into the casing string at a pre-

determined position. (The position may be fixed by the depth of

the previous casing shoe.) There are ports in the stage collar which

are initially closed by an inner sleeve, held by retaining pins. After


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the first stage is complete a special dart is released form surface

which opens the ports in the stage collar allowing direct

communication between casing and annulus. (A pressure of 1000 -

1500 psi is applied to allow the dart to shear the retaining pins and

move the sleeve down to uncover the ports.) Circulation is

established through the stage collar before the second stage

slurry is pumped. The normal procedure is as follows:

* drop opening dart

* pressure up to shear pins

* circulate though stage collar

* pump spacer

* pump second stage slurry* release closing plug

* displace cement with mud

* pressure up on plug to close ports in stage collar.

To prevent cement falling down the annulus a cement basket or packer

may be run on the casing below the stage collar.


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41

The quality of a cement job can generally be improved by :

* centralising the casing - most important

*reciprocating or rotating the casing - not possible to rotate in

most cases (except for liners) but reciprocation is

quite common.

* circulating spacers- formulated so that they induce turbulence

* circulating at a high velocity - to ensure total mud removal

One disadvantage of stage cementing is that the casing cannot

be moved after the first stage cement has set in the lower part

of the annulus. This increases the risk of channelling and a poor

cement bond.

4 c. The two stage operation are used t reduce the height of heavy

weight cement colom in the annulus. This may be done for several

reasons:

i) to reduce the total hydrostatic head on the bottom of the hole

and therefore prevent lost circulation when cementing. Lostcirculation mat result in the TOC being too low and problem

formations being exposed in the annulus.

ii) to ensure that vcement is placed across the previous casing

shoe. This may be required when abandoning the well. Without

a two stage operation the entire openhole section of the annulus

would have to be cemented.

iii) To reduce the amount (and therefore cost) of cement used.


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