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Basic Rig Design Data

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Basic Rig Design Data Powered By Docstoc
					Msc Drilling Engineering

Platform rig design, design,

Daisy 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 with a safety margin. The derrick must be able to hole the entire drillstring required to drill to TD and still be able to run the heaviest casing string.

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Summary
Lifting capacity of draw works : Calculations enclosed illustrate that a 3000Hp draw works working at 85% mechanical efficiency will provide sufficient lifting capacity to take an over pull of 150,000lbs on the heaviest stuck casing or drillstring. In this case the heaviest string is the 9 5/8” casing. (see figures enclosed.) 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 of pipe 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) 49K Cum buoyed wt (lbs) 49K Overpull (pa-Cum Bw) -

Drill collars

8” x 2 13/16” 6 5/8” reg

120m

120m

59K

HWDP

5” x 3” NC-50

200m

320m

35K

29K

78K

-

Drill pipe 1

19.50 “G” NC-50

6000ft (1828m) 2795ft (852m)

2148m

131K

109K

187K

166K

Drill pipe 2

19.50 “S” NC-50

3000m

61K

51K

238K

217K

Drillstring summary for 8 ½” section.
Component Connection Length Cum length Air wt (lbs) Buoyed wt (lbs) 25K Cum buoyed wt (lbs) 25K Overpull (pa-Cum Bw) -

Drill collars

6” x 2 13/16” 4 ½ ” IF

120m

120m

30K

HWDP

5” x 3” NC-50

200m

320m

35K

29K

54K

-

Drill pipe 1

19.50 “G” NC-50

6000ft (1828m) 7060ft (2152m)

2148m

131K

109K

163K

190K

Drill pipe 2

19.50 “S” NC-50

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 and 95% volumetric efficiency.) See summaries in appendix 3. Mud pit capacity : Minimum of 3000bls required. This however is unlikely to be accommodated on a platform 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 be taken 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 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 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.

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Platform rig design
Design assumptions
Well data.
The well data provided represents the TWFH-13 well that is currently under planning. This well is the most demanding well to be drilled from the Daisy field platform. TWFH-13 Well data will hence be used for the platform design criteria.
Platform data Top reservoir Air Gap Water depth @ Daisy Field 16 slot platform No shallow gas present Pressure regime is normal 1950m TVD BDF Normal pore pressure assumed = 8.33ppg Depths (m) 1900m TVD BDF 50m 150m BDF to Seabed = 200m Comments Reservoir pressure

Casing Scheme 30” conductor 20” surface casing 13 3/8” intermediate csg. 9 5/8” intermediate casing

Depths (m) 300m TVD BDF 800m TVD BDF 900m TVD BDF 1400m TVD BDF 1650M AHD BDF 1900m TVD BDF 3000m AHD BDF

Comments

Maximum anticipated angle 27degrees Maximum anticipated angle 32degrees Note: Required to isolate long Salt section. Tangent and build section to almost horizontal. Shale stability required, >mud weight of 0.5ppg per 30deg required for wellbore stability. Set 150m inside 9 5/8” casing Mud weight to represent minimum safe overbalance to limit formation damage. Normal pore pressure assumed = 8.33ppg Reservoir pressure assumed to be 1.5ppg above normal i.e. 9.83ppg.

7” production liner

1950m TVD BDF 4300m AHD BDF

Pressure regime is normal Reservoir pressure

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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 hole angle. (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 be accounted 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 have to 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.

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Preliminary design calculations.
1.) Pressures and mud weights.
Pore pressure Max mud weight 17 ½” section Normal 32degrees angle 300psi safe overbalance shale stability required. Max mud weight 12 ¼” section 32-90degrees max. 300psi safe overbalance shale stability required 0.5ppg/30degrees Reservoir pressure Max mud weight 8 ½” section 1.5ppg above normal Max 90degrees 300psi safe overbalance 9.83ppg 10.2 + (300/1950*3.281)/0.052 = 10.73ppg 8.66 + (300/1900*3.281)/0.052 + (0.5*(90/30)) = 10.8ppg 8.33ppg 8.33 + (300/1400*3.281)/0.052 + (0.5*(32/30)) = 10.12ppg

Ref: see wellbore stratigraphy in appendix 1. 2.) Burst : No pressure tests to be conducted before cementing, burst loads not considered. 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 casing strings. In reality based on platform experience, lost circulation aspects etc, total evacuation not likely to be used in design.
Collapse 17 ½” section For 13 3/8” casing Collapse 12 ¼” section For 9 5/8” casing Collapse 8 ½ ” section For 7” liner 0.052 x 10.73ppg x (1950m x 3.281) x1.15 = 4105psi 0.052 x 10.12ppg x (1400m x 3.281) x1.25 = 3021psi 1.25 design used due to isolating salt section. 0.052 x 10.8ppg x (1900m x 3.281) x1.15 = 4026psi

4.) Design pressures.
Max anticipated surface pressure Maximum bottom hole pressure Water Injection pressure = TVD * ( Formation pressure – gas gradient) = (1950m * 3.281) * ( 9.83ppg– 2ppg) * 0.052)) = 2272psi. = TVD * ( Formation pressure) = (1950m * 3.281) * ( 9.83ppg * 0.052)) = 3270psi. = 300bar (4335psi).

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

© KINGDOM DRILLING SERVICES LTD.

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 other requirements. I.e Drilling (Pumping /pressure) requirements. Choke manifold. SWP of 5000psi valves before chokes. SWP of 3000psi valves downstream of 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 valve fitted as first outlet v/v on choke line. Rams : Solid ram block consisting of Pipe ram, Shear ram, and two pipe rams . Kill and choke lines 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.

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Casing selection
Casing selection
Casing was selected for burst and collapse criteria based on maximum anticipated pressures given on the previous pages. Note: A premium gas tight connection would have to be chosen for the 9 5/8” casing and 7” liner e.g. Vam Size Grade Lbs/ft Yield strength (psi) 80,000 80,000 Burst (psi) Collapse (psi) Body strength (Klbs)

13 3/8” 13 3/8”

P110 N80

72 77*

7400 6390

2880 3170

2596 1773

*Heavier casing may be required over salt section. 9 5/8” 7” N80 N80 47 29 80,000 80,000 6870 8160 4750 7020 1086 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 in air. For high angle wells, this would be accounted as too conservative in design. A design factor of 1.2 has been for hole angle and wellbore profile to be taken into account. In this design, a value of 150,000lbs over-pull has also been used to account for casing being stuck prior to landing at TD. Size 30” * 13 3/8” 9 5/8” 7” 7” ** Grade X-56 X-52 P110 N80 N80 N80 G&S N80 Lbs/ft 310 133 72 77 47 29 21.8 29 Length (m) 300 900 1300 350 3000 1450 2850 4300 Dry Weight (klbs) 305K 393K 307K 88K 463K 138K 203K 409K

* Assuming all ran at once. ** Contingency string if required to run to surface, e.g. if leak in 9 5/8” string.

© KINGDOM DRILLING SERVICES LTD.

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 to drill anticipated formations during tangent and build sections. Build section would incur highest combine loads and worst case stress conditions. It is envisaged that worst case conditions, i.e max WOB, likely buckling conditions would exists 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.

Wob × Df Wdc × Kb × Cosθ 45,000 ×1.1 151× 0.83 × Cos32 = 465 ft (142m)
Based on the above 12 drill collars would be required in addition to other BHA components, e.g. mud motor, MWD collar, stabilisers etc. that would make up the additional length required. The operator prefers however in the directional sections of the well, to run a DS1, BHA type 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 BHA design.

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HWDP required. Based on a drill collar and BHA component length of 120m, the following calculation determines the amount 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.

1  Wob × Df   Kb × cosθ ⋅ (Ldc ÷ Wdc ) W ( hwdp )    35000 × 1.1  1  0.83 × cos 60 ⋅ (120m × 3.281 × 148) 53.7   1 = [92,771 − 58,270] 53.7 = 642 ft (21 jts.)
If buckling was the limiting factor appendix 4 illustrates that at 60degrees, drill-pipe could also be used to apply WOB up to 53,000lbs before buckling would occur. (available weight from BHA components is only 31,000lbs at 60degrees inclination.) Initial tubular selection Size Grade Lbs/ft * Yield strength (psi) 135,000 105.000 -Burst (psi) Collapse (psi) Body strength (Klbs) 560,764 436,150 691,185

5” 5” 5”HWDP

S G --

22.5 21.8 53.7

15,640 12,090 --

10,050 8,765 --

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 " grade for the drill string and depth of well required and that drill string are inspected to a minimum DS1 class 4 standard. Note : For a specification of the various API inspection classifications see API standard 7 : ‘Rotary Drilling 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 and combined tension, torsion, bending, and pressure loads. During any drillstring design it is important to note in the design and operating stag. In reality worst case individual and combined conditions and make compensation for any assumptions used or as the case may be for conditions that may change or 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. back reaming with a top drive, • Stuck pipe e.g. jarring, overpull, combined tension, compression and/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 through misalignment of the crown block, Pressures created by surface and subsurface pressure, or different drilling fluids inside and outside the drillstring. Slip crushing and stability forces. Shock loading on applying tension, compression or combined loads to the drillstring 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 this brief. 3.) Corrosion and erosion are not loads, but they both reduce the strength of tubulars. Accounting for a measure of wall thickness (e.g. 80%) to account for anticipated erosion and corrosion is considered acceptable 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 the strength of the drill string is exceeded by each individual load. Then combine all loads in the Von Mises general stress and fatigue endurance equations to ascertain if general or fatigue failure will occur. (see appendix2)

Tension Design Factors.
The first considerations to be made regarding designing a drillstring for tension applied is to select a maximum 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 , as recommended 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 hanging free in the wellbore and are equal to the string weight in air multiplied by the buoyancy factor for the weight 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 ) = 553,833 x 0.85 1.33 Similarly "G" = 353,953 lbs.

= Min Ys x 0.85 S.F

"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" = Similarly "S" = 233,953 lbs 335,082lbs.

c ) Slip crushing. ( Assume normally lubricated slips, coefficient of friction = 0.08 ) from table provided : 16 slips, friction factor K = 0.08

= 4.00 ( for 5" drillpipe. ) = 1.42.

Safety factor Sh/St

Maximum allowable static load = Min Ys x 0.85 1.42 "G" = 553,833 x 0.85 1.42 Similarly = 331,520 lbs.

"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 Wdp * Kb ( Wdc x Ldc) + (Whwdp x Lhwdp) Wdp Wdp = 86,992lbs

BHA = (2.67 ( 8² - 2.813² ) x 120m + ( 2.67( 5² - 3² ) x 200m) x 3.281 x 0.83 Buoyancy factor ( Kb ) = 0.83 = 233,953 21.80 x 0.83 86,992 21.80 = 8939ft

Maximum length "G" and "S" = max all static load "S" - ( Wbha x Lbha ) + ( Wdp1 x Ldp1) Wdp2 x Kb Wdp2 335,082 22.50 x 0.83 ( 86,992 ) + ( 21.80 x 9839ft) 22.50 = Maximum depth “G” and “S” = 8939ft + 4544ft = 13,483ft 4544ft.

=

12 ¼” section 3000m (9843ft) & 8 ½” section TD 4300m (14,108ft) a combination of G and S would be 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 and spreadsheet calculations have been based on these figures. A design spreadsheet was run (courtesy of Mitchell engineering) to ensure all design criteria are met. ( 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” SR = Z below / Z above = 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” SR = Z below / Z above = 10.682 / 5.708 = 1.87 Stiffness ratios are within acceptable ranges

Torsional check (* values from DS-1) Connection “G” NC-50 “S” NC-50 O.D. (in) 6 5/8” 6 5/8” I.D. (in) 3 ½“ 3 ¼“ *Make up torque (ftlbs) 27,080 31,020 *Torsional strength (ftlbs) 45,130 51,700 Max operating torque (ftlbs) 25,000 25,000

Torsional checks are within max operating torque allowable.

8

Drillstring summary for 12 ¼” section.

Cum length

Air wt (lbs)

Buoyed wt (lbs) 49K

Cum buoyed wt (lbs) 49K

Overpull (pa-Cum Bw) -

Drill collars

8” x 2 13/16” 6 5/8” reg

120m

120m

59K

HWDP

5” x 3” NC-50

200m

320m

35K

29K

78K

-

Drill pipe 1

19.50 “G” NC-50

6000ft (1828m) 2795ft (852m)

2148m

131K

109K

187K

166K

Drill pipe 2

19.50 “S” NC-50

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) 25K Cum buoyed wt (lbs) 25K Overpull (pa-Cum Bw) -

Drill collars

6” x 2 13/16” 4 ½ ” IF

120m

120m

30K

HWDP

5” x 3” NC-50

200m

320m

35K

29K

54K

-

Drill pipe 1

19.50 “G” NC-50

6000ft (1828m) 7060ft (2152m)

2148m

131K

109K

163K

190K

Drill pipe 2

19.50 “S” NC-50

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 be used 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 buckling would have to be determined using a torque and drag simulator.

9

Derrick loading
Derrick loading worst case
1.) Worst case would be running heaviest casing string (95/8” casing 463K), getting stuck at 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 handling system. Pipe in derrick 5” drillpipe required for well 1828m x 21.8 lbs/ft x 3.281 2152m x 22.50 x 3.281 120m BHA (Dc’s + BHA) 21 joints of HWDP 1.) 120m x 99lbs/ft x 3.281 200m x 53.7lbs/ft x 3.281 Pipe weight in derrick 130,749lbs 158,866lbs 58,270lbs 35,238lbs 383,123lbs set back load.

Casing stuck Over pull applied Block and travelling eqpt. weight 2.) 1.) + 2.)

3000m x 47lbs/ft x 3.281 Design for 150,000lbs 80,000lbs Stuck casing load on derrick Worst case derrick loading

463,000lbs 150,000lbs 80,000lvs 693,000lbs. 1,0761,123lbs

Dynamic derrick loading for worst case
Dynamic derrick load (12 lines run blocks) Hook line load (Hl) = Fast line load (Fl) = Casing wt +overpull + blocks etc Hl / (No of lines (n) x eff factor) 693,000 / ( 12 x 0.77) Deadline load (Dl) = Hl / No of lines (n) 693,000 / 12 3.) Dynamic derrick load = 4.) Derrick load static = Hl + Dl + Fl = ((n) + 2 / (n) ) * Hl 825,750lbs 808,500lbs 57,750lbs 693,000lbs 75,000lbs

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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.

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

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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 the 12 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 requires repair.

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Mud pit capacity
Mud pit capacity
Largest volumes required are in the 17 ½” section and would be displacing hole to mud at section TD. 17 ½” hole volume = (900 x 0.3415bbls/ft) + (0.2975bbls/ft x 750m) x 3.281 = 1740 bbls 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 screens as possible to maintain high solids removal efficiency. E.g. High capacity , fine screen shale 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 effect maximum operating performance. Shallow header tanks entry to shakers and proper flowline division to ensure flow can be 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 minimum bends to reduce pressure losses ( 6” or 8” pipe.) with minimum fluid velocity of 10ft/sec. Centrifugal mix pumps 6” x 8”. Desirable to mix and treat mud in large quantities in the shortest possible time. Hoppers : 6” x 8” Centrifugal, 1400-1600GPM, @ 50 – 70psi. Shearing device for mixing polymers, (ABC Oil policy to use WBM exclusively for wells.)

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Appendix 3

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