Rig Desgin

© KINGDOM DRILLING SERVICES LTD.

Platform rig designPlatform rig design, , Daisy field development, ABC OilDaisy field development, ABC Oil

Design Requirements

Lifting capacity of draw works.

Derrick load capacity

Substructure and setback load

BOP sizes and ratings

Drillstring capacities

Mud pump output and pressure / power ratings

Mud pit capacity

Solids treatment and mixing equipment.

Limitations:

The rig must be able to handle the heaviest casing string required during the field life witha safety margin.

The derrick must be able to hole the entire drillstring required to drill to TD and still be ableto run the heaviest casing string.

Msc Drilling Engineering

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Summary

Lifting capacity of draw works : Calculations enclosed illustrate that a 3000Hp draw works working at85% mechanical efficiency will provide sufficient lifting capacity to take an over pull of 150,000lbs on theheaviest stuck casing or drillstring. In this case the heaviest string is the 9 5/8” casing. (see figuresenclosed.)

Derrick load capacity to accommodate a dynamic derrick load in excess of 825,750lbs

Substructure and setback load in excess of 1,000,000lbs

BOP sizes and ratings : 18 ¾” 5000 BOP’s, 3000psi annulars. Annular, Blind/shear ram, two sets ofpipe rams. (choke and kill lines located below shear rams.)

Drillstring capacities (critical design sections are 12 ¼ “ and 8 ½ @ sections)

Drillstring summary for 12 ¼” section

Component Connection Length Cum length Air wt (lbs) Buoyed wt(lbs)

Cum buoyedwt (lbs)

Overpull

(pa-Cum Bw)

Drill collars 8” x 2 13/16”

6 5/8” reg

120m 120m 59K 49K 49K -

HWDP 5” x 3”

NC-50

200m 320m 35K 29K 78K -

Drill pipe 1 19.50 “G”

NC-50

6000ft

(1828m)

2148m 131K 109K 187K 166K

Drill pipe 2 19.50 “S”

NC-50

2795ft

(852m)

3000m 61K 51K 238K 217K

Drillstring summary for 8 ½” section.

Component Connection Length Cum length Air wt (lbs) Buoyed wt(lbs)

Cum buoyedwt (lbs)

Overpull

(pa-Cum Bw)


4 ½ ” IF

120m 120m 30K 25K 25K -

HWDP 5” x 3”

NC-50

200m 320m 35K 29K 54K -


NC-50

6000ft

(1828m)

2148m 131K 109K 163K 190K


NC-50

7060ft

(2152m)

4300m 159K 132K 295K 160K

Note: BHA components can be reduced in horizontal section, see appendix 4

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Summary (continued.)

Mud pump output and pressure / power ratings. Mud pumps rates to 4500psi, providing 3000hp(i.e. sufficient to drill at 4350psi @ 950GPM at 12 ¼” section TD, at 85% mechanical efficiency and95% volumetric efficiency.) See summaries in appendix 3.

Mud pit capacity : Minimum of 3000bls required. This however is unlikely to be accommodated on aplatform rig design due to loading conditions. (Note: In reality, Platform design may only allow approx.2000bbls that add constraints to many operational aspects.)

Solids treatment and mixing equipment.

Shale shakers to handle circulation volumes 1100-1200GPM, with redundancy for one shakers to betaken out of service using as fine as screens as possible maintaining high solids removal efficiency.E.g. High capacity , fine screen shale shakers such as thule VSM 100’s)

Built in scalping screen, quick change screen facility, easy to operate and maintin, repairable screens.

Efficient centrifuges to remove fine solids generated during drilling.

Shallow header tanks entry to shakers and proper flowline division to ensure flow can be equallycontrolled and divided to each shakers as required.

Poor boy de-gasser to be fitted with minimum 8” vent line.

Vacuum de-gasser to be able to handle max. operating rate of charge pumps i.e. 1200GPM.

Gumbo box fitted to flowline.

Flowline access platform for fitting and maintaining flow shows, gas detectors etc.

2” weco flushing connections fitted at strategic points for flowline cleaning.

References:

Homco technical handbook.

Ds-1 ( Terrance Hill & associates.)

Drillstring desgin notes, Msc notes and Shell training notes.

Halliburton red-book.


Platform rig design

Design assumptions

Well data.

The well data provided represents the TWFH-13 well that is currently under planning. This well is themost demanding well to be drilled from the Daisy field platform. TWFH-13 Well data will hence be usedfor the platform design criteria.

Platform data Depths (m) Comments

Top reservoir 1900m TVD BDF Reservoir pressure

Air Gap 50m

Water depth @ Daisy Field 150m BDF to Seabed = 200m

16 slot platform

No shallow gas present

Pressure regime is normal 1950m TVD BDF Normal pore pressure assumed = 8.33ppg

Casing Scheme Depths (m) Comments

30” conductor 300m TVD BDF

20” surface casing 800m TVD BDF

900m TVD BDF

Maximum anticipated angle 27degrees

13 3/8” intermediate csg. 1400m TVD BDF

1650M AHD BDF

Maximum anticipated angle 32degrees

Note: Required to isolate long Salt section.

9 5/8” intermediate casing 1900m TVD BDF

3000m AHD BDF

Tangent and build section to almost horizontal.Shale stability required, >mud weight of 0.5ppgper 30deg required for wellbore stability.

7” production liner 1950m TVD BDF

4300m AHD BDF

Set 150m inside 9 5/8” casing

Mud weight to represent minimum safeoverbalance to limit formation damage.

Pressure regime is normal Normal pore pressure assumed = 8.33ppg

Reservoir pressure Reservoir pressure assumed to be 1.5ppgabove normal i.e. 9.83ppg.

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Design Notes

26” section drilled with seawater and displaced to 1.2sg mud prior to running casing

17 ½” section, mud weight to reflect 300psi working overbalance and 0.53ppg for 32 degrees holeangle. (10.12pg)

9 5/8” section, mud weight to reflect 300psi working overbalance and 1.5ppg for hole angle (10.8ppg)

7” section mud weight to reflect 300psi working overbalance over reservoir pressure (10.73ppg)

Design Factors

Tension design 1.33

Tension calculations assume that the drillstring is hanging vertically. For high angle wells this would beaccounted for in design as too conservative, hence a higher design factor has been used.

In reality in high angle wells, each section should be considered at an average hole angle.

Drag is also not accounted for in design calculations. In reality torque and drag simulations would haveto be conducted modeling field data friction factors known etc.

Collapse design factor: 1.15

Burst design factor: 1.15, 1.25 for 13 3/8” section due to requirement for salt section isolation.

BHA design factor: 1.1

Margin of overpull, 120,000lbs drillstring

Margin of overpull, 150,000lbs casing.

The operator would like to trip with a minimum speed of 90ft/min at highest loading conditions.

Draw works Wire rope safety factors, minimum of 2.0 for drilling / casing.

Maximum operating torque = 25,000ftlbs (safe working value for top drive system e.g. TDS-2.)

Solids Control : Enough shakers to have one redundant at required section flowrate.

System to be designed such that shakers and centrifuges provide required solids control efficiency.


Preliminary design calculations.

1.) Pressures and mud weights.

Pore pressure Normal 8.33ppg

Max mud weight 17 ½”section

32degrees angle

300psi safe overbalance

shale stability required.

8.33 + (300/1400*3.281)/0.052 + (0.5*(32/30)) = 10.12ppg

Max mud weight 12 ¼”section

32-90degrees max.


shale stability required0.5ppg/30degrees

8.66 + (300/1900*3.281)/0.052 + (0.5*(90/30)) = 10.8ppg

Reservoir pressure 1.5ppg above normal 9.83ppg

Max mud weight 8 ½”section

Max 90degrees


10.2 + (300/1950*3.281)/0.052 = 10.73ppg

Ref: see wellbore stratigraphy in appendix 1.

2.) Burst : No pressure tests to be conducted before cementing, burst loads notconsidered.

3.) Max collapse pressures. (Design factor 1.15, & 1.25)

Note: Worst case (total evacuation) has been used in collapse for platform design i.e. heaviest casingstrings. In reality based on platform experience, lost circulation aspects etc, total evacuation not likely tobe used in design.

Collapse 17 ½” section

For 13 3/8” casing

0.052 x 10.12ppg x (1400m x 3.281) x1.25 = 3021psi

1.25 design used due to isolating salt section.

Collapse 12 ¼” section

For 9 5/8” casing

0.052 x 10.8ppg x (1900m x 3.281) x1.15 = 4026psi

Collapse 8 ½ ” section

For 7” liner

0.052 x 10.73ppg x (1950m x 3.281) x1.15 = 4105psi

4.) Design pressures.

Max anticipated surfacepressure

= TVD * ( Formation pressure – gas gradient)

= (1950m * 3.281) * ( 9.83ppg– 2ppg) * 0.052)) = 2272psi.

Maximum bottom holepressure

= TVD * ( Formation pressure)

= (1950m * 3.281) * ( 9.83ppg * 0.052)) = 3270psi.

Water Injection pressure = 300bar (4335psi).

Note: Surface equipment, BOP equipment, casing and drillstring component requirements would bebased upon likely maximum injection pressure into the reservoir of 4335psi. This may have to executed

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during some operational stages in the life of a well via drilling equipment Bop’s etc. ( e.g. Injectivity test,well stimulation etc.)

5000psi equipment would therefore be chosen and selected if it can fulfill otherrequirements. I.e Drilling (Pumping /pressure) requirements.

Choke manifold. SWP of 5000psi valves before chokes. SWP of 3000psi valves downstreamof chokes. (one remote and one manual choke.)

Standpipe manifold. : SWP of 5000psi for all valves, lines and fitments.

BOP’s : SWP : 3000psi annular, SWP : 5000psi rams, kill and choke line valves, HCR valvefitted as first outlet v/v on choke line.

Rams : Solid ram block consisting of Pipe ram, Shear ram, and two pipe rams . Kill and chokelines fitted below shear rams. Rams fitted with variables from 3 ½” to 5” and 4 ½ “ to 7”.

IBOP eqpt. : All kellycocks, IBOP’s , Grey valves etc rated to SWP of 5000psi.


Casing selection

Casing selection

Casing was selected for burst and collapse criteria based on maximum anticipatedpressures given on the previous pages. Note: A premium gas tight connection would haveto be chosen for the 9 5/8” casing and 7” liner e.g. Vam

Size Grade Lbs/ft Yieldstrength

(psi)

Burst(psi)

Collapse(psi)

Body strength(Klbs)

13 3/8” P110 72 80,000 7400 2880 2596

13 3/8” N80 77* 80,000 6390 3170 1773

*Heavier casing may be required over salt section.

9 5/8” N80 47 80,000 6870 4750 1086

7” N80 29 80,000 8160 7020 676

Casing weights

Based on casing weight above, the highest casing load would be running the 9 5/8”casing. Note: All tension calculations assume that the casing is hanging vertically and inair. For high angle wells, this would be accounted as too conservative in design. A designfactor of 1.2 has been for hole angle and wellbore profile to be taken into account. In thisdesign, a value of 150,000lbs over-pull has also been used to account for casing beingstuck prior to landing at TD.

Size Grade Lbs/ft Length(m)

Dry Weight(klbs)

30” * X-56 310 300 305K

X-52 133 900 393K

13 3/8” P110 72 1300 307K

N80 77 350 88K

9 5/8” N80 47 3000 463K

7” N80

G&S

29

21.8

1450

2850

138K

203K

7” ** N80 29 4300 409K

* Assuming all ran at once.

** Contingency string if required to run to surface, e.g. if leak in 9 5/8” string.


Drilling Tubulars selection

Drill collar and HWDP selection

The critical BHA for design is in the 12 ¼” section. Here higher WOB will be required todrill anticipated formations during tangent and build sections. Build section would incurhighest combine loads and worst case stress conditions.

It is envisaged that worst case conditions, i.e max WOB, likely buckling conditions wouldexists at start of section (i.e 32degrees).

Drill collar and BHA requirements.

Drill collar, BHA, and drillstring component lengths have been determined as follows:

Length of Drill collars + BHA components required to drill with max 45000lbs WOB in 12 ¼@ section.

Based on the above 12 drill collars would be required in addition to other BHAcomponents, e.g. mud motor, MWD collar, stabilisers etc. that would make up theadditional length required.

The operator prefers however in the directional sections of the well, to run a DS1, BHAtype 3. I.e. utilising HWDP for available WOB. This is to minimise BHA handling time,reduce stuck pipe likeliness, and run drill collars required for directional control and BHAdesign.

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HWDP required.

Based on a drill collar and BHA component length of 120m, the following calculation determines theamount of HWDP required for 35,000WOB (Upper limit of 12 ¼ “ PDC), at an angle of 60degrees (i.e.where cos.θ = 0.5). Note: A t higher angles BHA has a diminishing effect for WOB requirements.

If buckling was the limiting factor appendix 4 illustrates that at 60degrees, drill-pipe could also be usedto apply WOB up to 53,000lbs before buckling would occur. (available weight from BHA components isonly 31,000lbs at 60degrees inclination.)

Initial tubular selection

Size Grade Lbs/ft*

Yieldstrength

(psi)

Burst(psi)

Collapse(psi)

Body strength

(Klbs)

5” S 22.5 135,000 15,640 10,050 560,764

5” G 21.8 105.000 12,090 8,765 436,150

5”HWDP -- 53.7 -- -- -- 691,185

HWDP dimensions: 5” OD x 3” ID

*Adjusted weights.

Burst, collapse and body strengths given for premium pipe.

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Drillstring design

ABC oil companies require that drill strings have at least a quality of API inspection " Premium " gradefor the drill string and depth of well required and that drill string are inspected to a minimum DS1 class 4standard.

Note : For a specification of the various API inspection classifications see API standard 7 : ‘RotaryDrilling Equipment’ or the recently released DS-1 ‘Drill stem Design and Inspection specification’.

Normal operating conditions

During normal drilling operations, the drillstring is subjected to constantly changing individual andcombined tension, torsion, bending, and pressure loads. During any drillstring design it is important tonote in the design and operating stag. In reality worst case individual and combined conditions andmake compensation for any assumptions used or as the case may be for conditions that may changeor not be accounted and/or applied for.

It is generally accepted that the most damaging combined loads occur under the following conditions:

• During extreme drilling operations; Directional , horizontal ,extended reach.

•• Rotating the drillstring under tension and/or torsion e.g. backreaming with a top drive,

•• Stuck pipe e.g. jarring, overpull, combined tension, compressionand/or torsion.

• Fishing operations e.g. jarring, overpull, combined tension,compression and/or torsion.

Main design considerations.

• The main design considerations on the drillstring to be accounted for are :

• Tensional pulling and pushing ( compression ) on the drillstring,

• Combined tension / torsion while twisting the drillstring during rotation.

• The torsion while making up or braking out the drillstring components,

• The bending derived from wellbore geometry, doglegs in the wellbore, or throughmisalignment of the crown block,

• Pressures created by surface and subsurface pressure, or different drilling fluidsinside and outside the drillstring.

• Slip crushing and stability forces.

• Shock loading on applying tension, compression or combined loads to thedrillstring components.

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Notes :

1.) Von Mises triaxial equation, fatigue and jar placement considerations are not considered in design

2.) Due to the complexities involved vibrational analysis is not considered and accounted for in thisbrief.

3.) Corrosion and erosion are not loads, but they both reduce the strength of tubulars. Accounting for ameasure of wall thickness (e.g. 80%) to account for anticipated erosion and corrosion is consideredacceptable in this case. e.g. A long extended reach well where drillpipe wear may be severe.

The fundamental approach to drill string design is to calculate the loads individually to determine if thestrength of the drill string is exceeded by each individual load. Then combine all loads in the Von Misesgeneral stress and fatigue endurance equations to ascertain if general or fatigue failure will occur. (seeappendix2)

Tension Design Factors.

The first considerations to be made regarding designing a drillstring for tension applied is to select amaximum working load that would never be exceeded during normal drilling operations.

In the case of drillpipe this working load is based on a stress of 85% of the yield strength of the pipe , asrecommended in strength and dimensions tables provided.

The second consideration in tension string design is to determine the maximum allowable static load.This is the hook load when the drillstring ( including the drill collars, BHA components, etc. ) are hangingfree in the wellbore and are equal to the string weight in air multiplied by the buoyancy factor for theweight of the drilling fluid in use.

Three general methods are used to determine the Maximum allowable static load, they are

• Design factor.

• Margin of overpull.

• Safety factor for slip crushing.

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TWFH-13 drillstring design requirements :

1.) calculate the lengths of various 5" 19.50 lbs/ft G105 and S135 drillstrings for drilling the hole.

2.) Using maximum lengths of all drillstrings , what is the maximum depth obtainable.

3.) Design the strings to account for slip crushing, safety factor for accelerating loads.

Margin of over pull allowed = 120,000 lbs.

Depth of along hole depths required = 12 ¼” section 9843ft (3000m.), 8 ½ “section 14,108ft(4300m)

Use maximum lengths for G and S.

Drill collars = 8" x 2.813" x 120m, 200m HWDP, 5” x 3”

6” x 2.813” x 120m in 8 ½ @ hole.

Mud in use = 10.8ppg.

From API section B3 page 3

= 5" 19.50 lbs/ft G = 553,833 lbs, minimum yield strength., S = 712,070 lbs

a.) "G" pipe Maximum allowable static load ( for acceleration forces )

= Min Ys x 0.85 = 553,833 x 0.85 "G"= 353,953 lbs. S.F 1.33

Similarly "S" = 455,082 lbs

b.) Margin of overpull, maximum allowable static load.

"G" = (min Ys x 0.85)/1.33 - M.O.P = (553,833 x 0.85)/1.33 - 120,000

"G"= 233,953 lbs

Similarly "S" = 335,082lbs.

c ) Slip crushing. ( Assume normally lubricated slips, coefficient of friction = 0.08 )from table provided :

16 slips, friction factor = 0.08

K = 4.00 ( for 5" drillpipe. )

Safety factor Sh/St = 1.42.

Maximum allowable static load = Min Ys x 0.85 1.42

"G"= 553,833 x 0.85 = 331,520 lbs. 1.42

Similarly "S" = 331,518 lbs.

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For "G" pipe the max. allowable static load = 203,953 lbs.

( From the M.O.P. calculations, i.e.lowest loadings)

Maximum allowable depth of "G" pipe. =

Max allowable static load - ( Wdc x Ldc) + (Whwdp x Lhwdp) Wdp * Kb Wdp Wdp

BHA = (2.67 ( 8² - 2.813² ) x 120m + ( 2.67( 5² - 3² ) x 200m) x 3.281 x 0.83 = 86,992lbs

Buoyancy factor ( Kb ) = 0.83

= 233,953 - 86,992 = 8939ft21.80 x 0.83 21.80

Maximum length "G" and "S"

= max all static load "S" - ( Wbha x Lbha ) + ( Wdp1 x Ldp1)Wdp2 x Kb Wdp2

= 335,082 - ( 86,992 ) + ( 21.80 x 9839ft)22.50 x 0.83 22.50

= 4544ft.

Maximum depth “G” and “S”

= 8939ft + 4544ft = 13,483ft

12 ¼” section 3000m (9843ft) & 8 ½” section TD 4300m (14,108ft) a combination of G and S wouldbe required. Maximum depth we can drill to with G & S pipe.

=13,483t + 120m (drill collars) + 200m HWDP = 14,532ft (TD of well is 4300m (14,108ft.)For additional safety 6000ft of “G” will be run with the remainder “S”. Summary sheets andspreadsheet calculations have been based on these figures.

A design spreadsheet was run (courtesy of Mitchell engineering) to ensure all design criteria aremet. ( See Appendix 2.)

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Stiffness ratio’s

Drill collars to HWDP ( section modulus figures taken from DS-1.)

Drill collars 8” x 2 13/16”, HWDP 5” x 3”

SR = Z below / Z above

= 54.382 / 10.682 = 5.09

Drill collars 6” x 2 13/16”, HWDP 5” x 3”


= 20.181 / 10.682 = 1.89

HWDP to “G” drillpipe ( section modulus figures taken from DS-1.)

HWDP 5” x 3”, “G” pipe 5” x 4.276”


= 10.682 / 5.708 = 1.87

Stiffness ratios are within acceptable ranges

Torsional check (* values from DS-1)

Connection O.D. (in) I.D. (in) *Make uptorque (ftlbs)

*Torsionalstrength (ftlbs)

Max operatingtorque (ftlbs)

“G” NC-50 6 5/8” 3 ½“ 27,080 45,130 25,000“S” NC-50 6 5/8” 3 ¼“ 31,020 51,700 25,000

Torsional checks are within max operating torque allowable.

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Drillstring summary for 12 ¼” section.

Cum length Air wt (lbs) Buoyed wt(lbs)

Cum buoyedwt (lbs)

Overpull

(pa-Cum Bw)


6 5/8” reg

120m 120m 59K 49K 49K -

HWDP 5” x 3”

NC-50

200m 320m 35K 29K 78K -


NC-50

6000ft

(1828m)

2148m 131K 109K 187K 166K


NC-50

2795ft

(852m)

3000m 61K 51K 238K 217K

Pa = maximum allowable load for drillpipe from design calculation

Drillstring summary for 8 ½” section.

Cum length Air wt (lbs) Buoyed wt(lbs)

Cum buoyedwt (lbs)

Overpull

(pa-Cum Bw)


4 ½ ” IF

120m 120m 30K 25K 25K -

HWDP 5” x 3”

NC-50

200m 320m 35K 29K 54K -


NC-50

6000ft

(1828m)

2148m 131K 109K 163K 190K


NC-50

7060ft

(2152m)

4300m 159K 132K 295K 160K

Pa = maximum allowable static load

Note: In reality as inclinations increase, less BHA components are required and more drillpipe can beused for WOB before buckling will occur. (see appendix 4)

To permit drillstring to slide, HWDP may have to be placed in the build section, drags and bucklingwould have to be determined using a torque and drag simulator.


Derrick loading

Derrick loading worst case

1.) Worst case would be running heaviest casing string (95/8” casing 463K), getting stuckat section TD and applying maximum overpull i.e. 150,000lbs.

2.) Assuming all 5” drillpipe has been picked up to drill to TD

Block weight + top drive and hoisting equipment = 80,000lbs.

No account taken for other equipment and fixtures in derrick. E.g. Pipe handlingsystem.

Pipe in derrick

5” drillpipe required for well 1828m x 21.8 lbs/ft x 3.281 130,749lbs

2152m x 22.50 x 3.281 158,866lbs

120m BHA (Dc’s + BHA) 120m x 99lbs/ft x 3.281 58,270lbs

21 joints of HWDP 200m x 53.7lbs/ft x 3.281 35,238lbs

1.) Pipe weight in derrick 383,123lbs set back load.

Casing stuck 3000m x 47lbs/ft x 3.281 463,000lbs

Over pull applied Design for 150,000lbs 150,000lbs

Block and travelling eqpt. weight 80,000lbs 80,000lvs

2.) Stuck casing load on derrick 693,000lbs.

1.) + 2.) Worst case derrick loading 1,0761,123lbs

Dynamic derrick loading for worst case

Dynamic derrick load (12 lines run blocks)

Hook line load (Hl) = Casing wt +overpull + blocks etc 693,000lbs

Fast line load (Fl) = Hl / (No of lines (n) x eff factor)

693,000 / ( 12 x 0.77)

75,000lbs

Deadline load (Dl) = Hl / No of lines (n)

693,000 / 12

57,750lbs

3.) Dynamic derrick load = Hl + Dl + Fl = 825,750lbs

4.) Derrick load static = ((n) + 2 / (n) ) * Hl 808,500lbs


Blockline selection

1 3/8” Extra improved plough steel block line has a breaking strength of 192,000lbs.

Safety factor on maximum fast line load (75,000lbs) from previous page.

Sf = (192,000lbs / 75,000lbs)

Safety factor = 2.56

This is an acceptable factor for drilling and/or casing operations.


Draworks requirements

The operator would like to trip with a minimum speed of 90ft/min at the highest loadingconditions.

Fast line speed = (n) x speed required ft/min

= 12 lines x 90ft/min = 1080 ft/min.

For a 60” drum ( 1.25ft radius = (r) )

Velocity of the fast line (Vf) = 2 x π x r x N

1080 = 2 x 3.14 x 1.25 x N

N = 138 revs /min.

Horse power of the drum (HP) = ( Fl x 2 x π x r x N ) / (33,0000)

Where 33,000 = ftlbs / rev/min / per HP.

HP = (75,000lbs x 2 x 3.14 x 1.25ft x 138revs/min) / (33,000)

Horse power of drum = 2462 HP.

HP of draw works (assuming mechanical efficiency of 85%) = 2462 / 0.85

Horse power of draworks = 2896 Hp.

A 3000hp draw works would therefore be most suited for the Daisy platform.


Mud pump output and pressure ratings

Hydraulics calculations for the two critical hole cleaning sections i.e. the 17 ½” and 12 ¼”sections is provided in appendix 3.

Based on a maximum section depth operating pressure of 4350psi and 950GPM in the12 ¼” section.

The horsepower required for the mud pumps, assuming a 95% volumetric and 0.85%efficiency factors =

HHP = (P x V) / (1714 x 0.85 x0.95)

= (4350psi x 950GPM) / (1714 x 0.85 x0.95)

= 2986HHP.

2 x 1600Hp pumps would be required e.g. National 12-P-160

Three pumps would be preferred to provide operational redundancy if one pump requiresrepair.


Mud pit capacity

Mud pit capacity

Largest volumes required are in the 17 ½” section and would be displacing hole tomud at section TD.

17 ½” hole volume = (900 x 0.3415bbls/ft) + (0.2975bbls/ft x 750m) x 3.281 = 1740bbls

based on a rule of thumb that reserve = active requirements.

A pit volume capacity in excess of 3000bbls would be required.

Solids removal equipment.

Requirements.

Shale shakers to handle circulation volumes 1100-1200GPM in 17 ½” hole section.With redundancy for one shakers to be taken out of service using as fine as screensas possible to maintain high solids removal efficiency. E.g. High capacity , fine screenshale shakers. ( Thule VSM 100’s)

Built in scalping screen, quick change screen facility, easy to operate and maintain,repairable screens.

Efficient centrifuges to remove fine solids generated during drilling.

As WBM being used shakers designed not to be underloaded so as to effectmaximum operating performance.

Shallow header tanks entry to shakers and proper flowline division to ensure flow canbe equally controlled and divided to each shakers as required.

Poor boy de-gasser to be fitted with minimum 8” vent line.

Vacuum de-gasser to be able to handle max. operating rate of charge pumps i.e.1200GPM.

Gumbo box fitted to flowline.

Flowline access platform for fitting and maintaining flowshows, gas detectors etc.

2” weco flushing connections fitted at strategic points for flowline cleaning

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Mud mixing & treatment equipment.

Large diameter piping, with as direct feed and discharge as possible with minimumbends to reduce pressure losses ( 6” or 8” pipe.) with minimum fluid velocity of10ft/sec.

Centrifugal mix pumps 6” x 8”. Desirable to mix and treat mud in large quantities inthe shortest possible time.

Hoppers : 6” x 8” Centrifugal, 1400-1600GPM, @ 50 – 70psi.

Shearing device for mixing polymers, (ABC Oil policy to use WBM exclusively forwells.)


Appendix 3

Rig Desgin

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