oil_solid controls.pdf

“Proprietary: - for the exclusive use of Chevron Corporatioin and other wholly owned subsidiaries of Chevron Corporation.”

A.1

Appendix A. Conductance Calculation

Conductance is a measure of the ease with which fluid can flow throughout thescreen per unit area. The conductance of square mesh or rectangular meshscreen cloth is calculated from the screen’s mesh count and wire diameter in boththe warp and shute direction. Warp wires run lengthwise during the process ofweaving the screen and are crossed at right angles by the shute wires. The shutewires are carried by the shuttle in the weaving process and may also be known aswoof or weft wires. In the context of this discussion it is not important to distinguishwhich is warp and which is shute. However, it is important to be aware that theremay be wires of two dimensions which should be considered separately in theequations.

The equations are valid for most standard open-weave oilfield screens with theexception of some nonstandard polyester weaves and coated screen cloth.

The conductance, C, in units of kilodarcies/millimeter for a standard weave screencloth is computed by:

where:

The void fraction of the screen, E, is given by:

The screen thickness, t, in inches, is given by:

The length of the warp and shute wires lw, ls, in inches are calculated by:

C 4095 E2×

A2

t×------------------------=

E

1Ns------

1Nw--------×

t Vw Vs+( )–

1Ns------

1Nw--------×

t×------------------------------------------------------------=

t ds dw+=

lw1

Ns------

2ds

2+= ls

1Nw--------

2dw

2+=

Solids Control Manual


A.2

The volume of the warp and shute wires Vw, Vs, in inches,3 are computed by:

The wire surface area to volume ratio, A, is computed by:

For screens composed of two or more layers, the conductances are calculated foreach layer individually. The total conductance of the layered screen composition isthen calculated by:

Nomenclature

A = Wire surface area to mesh volume ratio, inch-1.

C = Conductance, kD/mm.

CT = Conductance of layered screen composition, kD/mm

ds = Shute wire diameter, in.

dw = Warp wire diameter, in.

E = Void fraction.

ls = Length of shute wire, in.

lw = Length of warp wire, in.

Ns = Mesh count in shute direction, wires per in.

Nw = Mesh count in warp direction, wires per in.

t = Screen thickness, in.

Vs = Volume of shute wire, in.3.

Vw

πdw2

4----------

lw= Vs

πds2

4---------

ls=

Aπdw lw πdsls+

tNsNw---------------

------------------------------------=

1Ct-----

1C1------

1C2------

1C3------ ……+ + +=


B.1

Appendix B. Solids Control Equipment DischargeAnalysis, Oil-Based Muds

Analysis of the solids control equipment discharge provides valuable informationabout equipment performance and identifies the composition and rate of the dis-charge stream. These calculations are designed for oil-based muds, but can beused for water-based fluids as well.

Sample Collection

For shale shakers, a box will be needed to collect the discharge from the entirewidth of the shaker screens. A wooden core box can be used, or have a box fabri-cated. For mud cleaners, hydrocyclones or centrifuges, a 5 gallon bucket may beused. The larger the sample collected, the more accurate the results.

1. Weigh the sample container before collecting the sample.

2. Measure the sample collection time.

3. Record the weight of the container and wet solids.

4. Calculate the mass flow rate of the wet solids, mws, in lbm/min.

Retort Procedure

1. Weigh the empty retort W1, gm.:

2. Fill with a representative sample of wet solids and weight, W2, gm.

3. Run retort. Weigh retort and dry cuttings, W3, gm.

4. Record Volume of oil, Vo, and Volume of water, Vw, recovered.

5. Weight of wet solids, gm:

Wws = W2 - W1

6. Density of wet solids:



B.2

ρs = Wws/Vt

7. Weight of dry solids (including salt), gm:

Wds = W3 - W1

Alternate Retort Procedure for Air-Entrained Cuttings Samples

Occasionally, there will not be sufficient liquid on the wet solids to avoid entrain-ment of air in the retort. This will cause errors in the retort calculations. The follow-ing procedure may be used if a problem with air entrainment is anticipated:

1. Place the retort cup lid on the retort cup. Place entire assembly on a balance.Record the weight of retort cup, lid, expansion chamber and steel wool as W1,gm.

2. Fill the cup approximately 3/4 full with wet cuttings. Weigh the wet cuttings,retort cup, lid, expansion chamber and steel wool. Record as W2, gm.

3. With a syringe, fill the retort cup with oil until the cuttings are covered. Care-fully stir cuttings to remove entrapped air.

4. Place the lid on retort cup. Using the syringe and needle, fill retort cup with oilthrough the hole in the cup lid.

5. Weigh the wet cuttings/oil mixture, retort cup, lid, expansion chamber andsteel wool. Record as W3.

6. Run retort. Record Volume of oil, Vto, and Volume of water, Vw, recovered.

7. Allow retort to cool. Weigh dry solids, retort cup, lid, expansion chamber andsteel wool. Record as W4.

8. Weight of wet solids, gm:

Wws = W2 - W1


Wds = W4 - W1

10. Volume of oil added by syringe, cm3:

Solids Control Equipment Discharge


B.3

Voa = (W3 - W2)/SGoil

11. Corrected oil on cuttings Volume, cm3:

Vo = Vto - Voa

12. Corrected retort Volume, cm3:

Vt = 50 ml - Voa

Solids Analysis Calculations

Note: Use brine density, ρb, and Wt% salt, %S, recorded on mud check.


ρws = Wws /Vt

2. Weight of oil, gm:

Wo = Vo * SGoil

3. Volume of brine, cm3:

Vb = 100 (Vw)/(ρb(100 - %S))

4. Corrected dry solids Volume, cm3:

Vs = (Vt - Vo - Vb)

5. Corrected dry solids weight, gm:

Ws = (Wws - Wo - (Vb * ρb)

6. Dry solids density, gm/cm3:

ρs = Ws/Vs

7. Corrected Volume% solids:

%Vs = 100 * Vs/Vt

8. Volume% high-density solids (% of wet slurry):



B.4

%HDS = %Vs (ρs - 2.65) / (SGHDS - 2.65)

9. Volume% low-density solids (% of wet slurry):

%LDS = %Vs - %HDS

10. High-density solids concentration, lb/bbl:

HDS = 3.5 (SGHDS) (%HDS)

11. Low-density solids concentration, lb/bbl:

LGS = 3.5 (SGLGS) (%LGS)

12. Weight% oil to dry solids:

%Oil = (Wo/Ws) * 100

13. Total discharge rate, bbl/hr:

Qt = (60) (ms)/((350) (ρws))

14. Solid discharge rate, bbl/hr:

Qs = (%Vs) (Qt)/100

15. Liquid discharge rate, bbl/hr:

Ql = Qt - Qs

16. High-density solids mass flow rate, lb/hr:

mHDS = (Qt) (HDS)

17. Low-density solids mass flow rate, lb/hr:

mLDS = (Qt) (LDS)

18. Check HDS/LDS ratio of discharge to HDS/LDS ratio of mud

If HDS/LDS > HDS/LDS of mud, then barite is being preferentially removed.



B.5

Example Calculations

The following example calculations are designed to show how the equations listedin this section may be used to determine the composition and rate of the solid andliquid discharge streams.

Sample Source:

Shaker discharge

Mud Check Data Symbol

Brine phase density, gm/cm3 ρb 1.24

Wt% Salt in Brine %S 26.7

Barite, lb/bbl HDS 100.0

Low Gravity Solids, lb/bbl LDS 75.0

Drilled Solids Specific Gravity SGLGS 2.65

Barite Specific Gravity SGHDS 4.2

Sample Data

Net Sample Weight, lb 60.0

Sampling time, min 1.0

Mass flow rate, lb/min mws 60.0

Retort Data

Weight of empty retort, gm W1 297.0

Weight of retort and wet solids, gm W2 391.5

Weight of retort and dry solids, gm W3 378.0

Volume of oil recovered, cm3 Vo 17.0

Volume of water recovered, cm3 Vw 6.0

Total Volume retorted, cm3 Vt 50.0



B.6

Calculations

1. Weight of wet solids:

Wws = W2 - W1

= 391.5 - 297 = 94.5 gm


ρws = Wws / Vt

= 94.5 / 50.0 = 1.89 gm/cm3


Wds = W3 - W1

= 378 - 297 = 81 gm

4. Weight of oil, gm:

Wo = Vo * SGoil

= (17) (0.84) = 14.28 gm

5. Volume of brine, cm3:

Vb = 100 (Vw)/(ρb(100 - %S))

= (100) (6)/(1.24 (100 - 26.7)) = 6.6 cm3

6. Corrected dry solids volume, cm3:

Vs = (Vt - Vo - Vb)

= 50 - 17 - 6.6 = 26.4 cm3

7. Corrected dry solids weight, gm:

Ws = (Wws - Wo - (Vb * ρb)

= 94.5 - 14.3 - (6.6) (1.24) = 72.0 gm

8. Dry solids density, gm/cm3:

ρs = Ws/Vs

= 72.0/26.4 = 2.73 gm/cm3

9. Corrected Volume% solids:



B.7

%Vs = 100 * Vs / Vt

= (100) (26.4) / (50) = 52.8%

10. Volume% high-density solids (% of wet slurry):

%HDS = %Vs (ρs - 2.65) / (ρHDS - 2.65)

= 52.8 (2.73 - 2.65) / (4.2 - 2.65) = 2.73%

11. Volume% low-density solids (% of wet slurry):

%LDS = %Vs - %HDS

= 52.8 - 2.73 = 50.07%

12. High-density solids concentration, lb/bbl:

HDSdis = 3.5 (ρHDS) (%HDS)

= 3.5 (4.2) (2.73) = 40 lb/bbl

13. Low-density solids concentration, lb/bbl:

LGSdis = 3.5 (SGLGS) (%LGS)

= 3.5 (2.65) (50.07) = 464 lb/bbl

14. Weight% oil to dry solids:

%Oil = (Wo/Ws) * 100

= (14.28 / 72.04) (100) = 19.8%

15. Total discharge rate, bbl/hr:

Qt = (60) (ms) / ((350) (ρws))

= (60) (60) / ((350) (1.89) = 5.44 bbl/hr

16. Solid discharge rate, bbl/hr:

Qs = (%Vs) (Qt) / 100

= (52.8) (5.44) / 100 = 2.87 bbl/hr

17. Liquid discharge rate, bbl/hr:

Ql = Qt - Qs

= 5.44 - 2.87 = 2.57 bbl/hr

18. High-density solids mass flow rate, lb/hr:



B.8

mHDS = (Qt) (HDS)

= (5.44) (40) = 216 lb/hr

19. Low-density solids mass flow rate, lb/hr:

mLDS = (Qt) (LDS)

= (5.44) (464) = 2523 lb/hr

20. Check HDS/LDS ratio of discharge to HDS/LDS ratio of mud

Discharge HDS/LDS / Mud HDS/LDS (40/464) / (100/75) = 0.06 Since ratio is << 1.0, shaker is not preferentially removing barite.

“Proprietary: - for the exclusive use of Chevron Corporation and other wholly owned subsidiaries of Chevron Corporation.”

C. 1

Appendix D. Screen Designations

Brandt - ATL-1000, ATL CS (Main Deck)

SCREEN SERIES: BHX

Description: Hexagonal opening pattern perf plate bonded to rigidframe.Triple layer, square mesh screen cloth similar to DerrickDX series.

Sources Brandt (original equipment manufacturer)Advanced Southwestern

Comments: Repairable Scalping Screens for ATL-1000 shaker: -S8L, S12L, S20L,B20L(8X20),B40L(20X30).

Brandt BHX Series

ScreenName

U.S.Sieve

Separation Potential Flow Capacity AspectRatio

Trans.D50 D16 D84 Cond. Area

BHX 24 28 625 435 760 34.11 7.28 1.49 248.3

BHX 38 36 494 360 572 22.45 7.28 1.40 163.4

BHX 50 47 327 231 349 8.85 7.28 1.43 64.4

BHX 70 68 219 158 252 4.89 7.28 1.39 35.6

BHX 84 79 181 127 218 3.79 7.28 1.46 27.5

BHX 110 100 149 105 184 3.11 7.28 1.44 22.6

BHX 140 118 127 95 147 1.94 7.28 1.39 14.1

BHX 175 152 98 70 118 1.95 6.76 1.45 13.2

BHX 210 158 82 58 100 1.71 6.76 1.41 11.5

BHX 250 213 69 49 81 1.37 6.76 1.43 9.3



- C-2 -

Advanced BHX Replacement Series

ScreenName

U.S.Sieve



BHX 50 47 324 234 390 6.77 6.01 1.45 40.7

BHX 70 64 234 171 274 4.73 6.01 1.39 28.4

BHX 84 79 181 131 223 3.62 6.01 1.48 21.7

BHX 110 99 151 107 185 3.00 6.01 1.46 18.0

BHX 140 127 118 86 143 2.33 6.01 1.45 14.0

BHX 175 158 95 66 113 1.87 6.01 1.46 11.2

BHX 210 185 81 57 100 1.67 6.01 1.47 10.0

BHX 250 205 72 51 85 1.49 6.01 1.42 8.9

Southwestern BHX Replacement Series

ScreenName

U.S.Sieve



BHX 38 38 440 313 537 11.86 6.01 1.45 71.3

BHX 50 48 320 234 380 6.77 6.01 1.45 40.7

BHX 84 86 169 119 200 3.09 6.01 1.44 18.6

BHX 110 97 153 107 182 2.89 6.01 1.46 17.4

BHX 140 118 127 91 153 2.32 6.01 1.41 13.9

BHX 210 174 86 60 106 1.67 6.01 1.41 10.0

BHX 250 215 68 48 82 1.23 6.01 1.45 7.4

Screen Designations


- C-3 -

Brandt - Retrofit Tandem, ATL-CS (Scalping Deck)

SCREEN SERIES: BXL

Description: Hookstrip, 2 in. plastic grid.Triple layer, square mesh cloth.

Sources: Brandt (original equipment manufacturer)Advanced Southwestern

Comments: Use coarser mesh on top deck. Check tension.

Brandt BXL Series

ScreenName

U.S.Sieve

Separation Potential Cond. Area Aspect

RatioTrans

.D50 D16 D84

BXL 50 na na 8.50 16.4 na 139.4

BXL 84 70 210 155 240 4.58 16.4 1.35 75.1

BLX 110 82 171 124 195 3.57 16.4 1.39 58.5

BXL 140 116 130 97 150 2.73 16.4 1.39 44.7

BXL 175 144 102 76 121 2.24 16.4 1.42 36.7

BXL 210 158 95 67 111 2.23 16.4 1.40 36.6

BXL 250 203 73 54 83 1.56 16.4 1.36 25.6



- C-4 -


SCREEN SERIES: BLS

Description: Hookstrip unbonded panel.Plastic strips at contact with support ribs.Triple layer, extra-fine square mesh.

Sources: Brandt

Comments: Nonrepairable.Use coarser mesh on top deck. Good deblinding characteristics, short screen life.

Brandt BLS Series

ScreenName

U.S.Sieve

Separation PotentialCond. Area Aspect

Ratio Trans.D50 D16 D84

BLS 50 43 377 263 427 7.31 17.74 1.39 129.6

BLS 80 67 222 160 251 3.53 17.74 1.35 62.7

BLS 120 78 185 137 214 2.70 17.74 1.35 47.9

BLS 150 113 134 95 150 1.77 17.74 1.37 31.4

BLS 180 136 109 80 122 1.37 17.74 1.35 24.4

Screen Designations


- C-5 -


SCREEN SERIES: S

Description: Hookstrip, unbonded.Single layer, market grade square mesh.

Sources: Brandt Advanced Southwestern

Comments: Heavy gauge wire, long screen life. Poor resistance to blinding.Use as scalping screen.

Brandt S Series

ScreenName

U.S.Sieve

Separation Potential Flow Capacity AspectRatio Trans.

D50 D16 D84 Cond. Area

S-8 8 2464 n/a n/a 74.06 17.74 n/a 1313.8

S-10 10 1905 n/a n/a 49.68 17.74 n/a 881.34

S-12 12 1533 n/a n/a 34.97 17.74 n/a 620.30

S-14 14 1306 n/a n/a 29.22 17.74 n/a 518.31

S-16 16 1130 n/a n/a 24.30 17.74 n/a 431.12

S-18 18 979 n/a n/a 19.30 17.74 n/a 342.41

S-20 20 864 n/a n/a 15.93 17.74 n/a 282.62

S-30 33 561 548 578 8.32 17.74 1.05 147.59

S-40 41 402 389 411 4.89 17.74 1.05 86.79

S-50 49 305 298 313 2.88 17.74 1.07 51.01

S-60 61 245 239 252 2.40 17.74 1.04 42.51

S-80 77 188 181 194 1.91 17.74 1.06 33.93

S-100 103 146 141 152 1.44 17.74 1.11 25.51

S-120 121 124 121 126 1.24 17.74 1.04 22.07



- C-6 -


SCREEN SERIES: HCR

Description: Hookstrip, 2 in. plastic grid Proprietary weave, openingsare long narrow slots.

Sources: Cagle (built by Advanced)Comments: High conductance, extremely long life.

Cut point will depend on shape of solids.- near minimum listed D50 for sands.- near maximum listed D50 for slivers.

Brandt

Screen Name Mesh Count D50 Range Conductance Area Aspect

Ratio

HCR 80 12 X 93 173-250 7.06 16.4 10

HCR 100 15 X 115 141-203 5.58 16.4 10

HCR 150 19 X 158 105-151 4.45 16.4 10

HCR 200 19 X 200 74-107 3.32 16.4 14

HCR 250 20 X 229 61-88 2.50 16.4 17

HCR 325 43 X 259 43-62 1.51 16.4 20

Screen Designations


- C-7 -

Broadbent - Tandem Master (Lower Deck)

SCREEN SERIES: BL

Description: Hookstrip, perforated plate with 2 in. openings.Layered square mesh cloth composition.

Sources: Broadbent Comments: Repairable Scalping screens (2 required):

- BG10, BG16, BG20, BG24, BG38.

Broadbent BL Series

ScreenName

U.S.Sieve



BL 60 48 316 238 325 7.03 6.89 1.26 48.44

BL 84 80 177 120 215 3.69 6.89 1.57 25.42

BL 120 100 149 104 187 3.21 6.89 1.50 22.12

BL 140 122 123 87 148 2.46 6.89 1.45 16.95

BL 175 152 98 69 120 2.04 6.89 1.48 14.06

BL 210 168 89 62 106 1.77 6.89 1.47 12.20

BL 250 208 71 50 84 1.25 6.89 1.41 8.61



- C-8 -

Derrick - Flo-Line Cleaner, Cascade System, High G Dryer

SCREEN SERIES: PMD DX, PMD HP

Description: Hookstrip panel with unique corrugated screening sur-face, valleys run parallel to flow.PMD DX - Layered extra-fine square mesh.PMD HP - Layered extra-fine rectangular mesh.

Sources: Derrick

Comments: This design offers larger screening area and higherthroughput than flat panels; helps reduce mud lossesalong shaker rails.

Derrick PMD DX Series

ScreenName

U.S.Sieve



PMD DX 50 48 318 231 389 6.10 7.42 1.45 45.3

PMD DX 70 68 220 158 269 4.18 7.42 1.47 31.0

PMD DX 84 78 181 127 218 3.53 7.42 1.46 26.2

PMD DX 110 100 149 105 184 2.93 7.42 1.44 21.8

PMD DX 140 125 120 86 143 2.29 7.42 1.45 17.0

PMD DX 175 156 96 70 118 1.77 7.42 1.45 13.1

PMD DX 210 174 86 60 104 1.59 7.42 1.41 11.8

PMD DX 250 213 69 49 84 1.39 7.42 1.45 10.3

Derrick PMD HP Series

ScreenName

U.S.Sieve



PMD HP 45 44 362 283 388 9.51 7.42 2.02 70.6

PMD HP 50 50 299 234 313 8.20 7.42 1.92 60.8

PMD HP 60 57 263 207 278 6.78 7.42 2.06 50.3

PMD HP 70 71 208 158 221 4.81 7.42 1.92 35.7

PMD HP 80 77 186 145 192 3.93 7.42 1.88 29.1

PMD HP 100 105 143 113 154 3.20 7.42 1.96 23.8

PMD HP 125 121 124 100 133 2.59 7.42 1.88 19.2

PMD HP 140 147 101 79 113 2.24 7.42 1.98 16.6

PMD HP 180 168 89 67 94 1.82 7.42 1.88 13.5PMD HP 200 203 76 60 82 1.59 7.42 1.86 11.8PMD HP 230 230 62 52 72 1.31 7.42 2.13 9.7

PMD HP 265 261 55 44 59 0.97 7.42 2.25 7.2

PMD HP 310 300 48 38 53 0.85 7.42 2.52 6.3

PMD HP 460 357 41 31 47 0.60 7.42 2.50 4.5

Screen Designations


- C-9 -


SCREEN SERIES: PWP DX

Description: Hookstrip panel, perforated plate with 1 in. openings.Two layers, extra-fine square mesh over square meshbacking cloth.

Sources: Derrick (original equipment manufacturer)AdvancedSouthwestern

Comments: Has been standard screen series for all Derrick shakers,slightly less capacity than newer HP series.This series is also available for Derrick Model 58 Flo-LineCleaner (panel area = 7.57 sq ft).

Derrick PWP DX Series

ScreenName

U.S.Sieve



PWP DX 50 48 318 231 389 6.10 5.30 1.45 32.4

PWP DX 70 68 220 158 269 4.18 5.30 1.47 22.1

PWP DX 84 78 181 127 218 3.53 5.30 1.46 18.7

PWP DX 110 100 149 105 184 2.93 5.30 1.44 15.6

PWP DX 140 125 120 86 143 2.29 5.30 1.45 12.2

PWP DX 175 156 96 70 118 1.77 5.30 1.45 9.4

PWP DX 210 174 86 60 104 1.59 5.30 1.41 8.4

PWP DX 250 213 69 49 84 1.39 5.30 1.45 7.4

Advanced PWP DX Replacement Series

ScreenName

U.S.Sieve



PWP DX 24 25 715 508 824 20.69 5.50 1.42 113.8

PWP DX 38 39 429 317 528 11.86 5.50 1.47 65.2

PWP DX 50 47 324 234 390 6.77 5.50 1.45 37.2

PWP DX 70 64 234 171 274 4.73 5.50 1.39 26.0

PWP DX 84 79 181 131 223 3.62 5.50 1.48 19.9

PWP DX 110 99 151 107 185 3.00 5.50 1.46 16.5

PWP DX 140 127 118 86 143 2.33 5.50 1.45 12.8

PWP DX 175 158 95 66 113 1.87 5.50 1.46 10.3

PWP DX 210 185 81 57 100 1.67 5.50 1.47 9.2

PWP DX 250 205 72 51 85 1.49 5.50 1.42 8.2



- C-10 -

Southwestern PWP DX Replacement Series

ScreenName

U.S.Sieve



PWP DX 24 25 715 508 824 20.69 5.50 1.42 113.8

PWP DX 38 39 429 317 528 11.86 5.50 1.47 65.2

PWP DX 50 48 320 234 380 6.77 5.50 1.45 37.2

PWP DX 70 73 200 150 241 4.17 5.50 1.48 22.9

PWP DX 84 86 169 119 200 3.62 5.50 1.44 19.9

PWP DX 110 97 153 107 182 3.89 5.50 1.46 15.9

PWP DX 140 118 127 91 153 2.32 5.50 1.41 12.7

PWP DX 175 152 98 70 117 1.90 5.50 1.48 10.5

PWP DX 210 174 86 60 106 1.67 5.50 1.41 9.2

PWP DX 250 215 68 48 82 1.23 5.50 1.45 6.8

Screen Designations


- C-11 -


SCREEN SERIES: PWP HP

Description: Hookstrip panel, perforated plate with 1 in. openings.Two layers, extra-fine rectangular mesh over squaremesh backing cloth.

Sources: Derrick (original equipment)AdvancedSouthwestern

Comments: Standard screen series for all Derrick shakers, slightlyhigher capacity than older DX series.Also available for Derrick Model 58 Flo-Line Cleaner(panel area = 7.57 sq ft).

Derrick PWP HP Series

ScreenName

U.S.Sieve



PWP HP 45 44 362 283 388 9.51 5.30 2.02 50.4

PWP HP 50 50 299 234 313 8.20 5.30 1.92 43.5

PWP HP 60 57 263 207 278 6.78 5.30 2.06 35.9

PWP HP 70 71 208 158 221 4.81 5.30 1.92 25.5

PWP HP 80 77 186 145 192 3.93 5.30 1.88 20.8

PWP HP 100 105 143 113 154 3.20 5.30 1.96 17.0

PWP HP 125 121 124 100 133 2.59 5.30 1.88 13.7

PWP HP 150 147 101 79 113 2.24 5.30 1.98 11.9

PWP HP 180 168 89 67 94 1.82 5.30 1.88 9.6

PWP HP 200 203 76 60 82 1.59 5.30 1.86 8.4

PWP HP 230 230 62 52 72 1.31 5.30 2.13 6.9

PWP HP 265 261 55 44 59 0.97 5.30 2.25 5.2

PWP HP 310 300 48 38 53 0.85 5.30 2.52 4.5

PWP HP 460 357 41 31 47 0.60 5.30 2.50 3.2



- C-12 -

Advanced PWP HP Replacement Series

ScreenName

U.S.Sieve



PWP HP 45 47 353 270 379 9.81 5.50 1.87 53.9

PWP HP 50 61 274 216 301 7.56 5.50 1.79 41.6

PWP HP 60 62 240 184 267 5.75 5.50 2.10 31.6

PWP HP 70 71 208 158 221 5.02 5.50 1.96 27.6

PWP HP 80 77 186 145 192 4.08 5.50 1.95 22.4

PWP HP 100 105 143 113 154 3.44 5.50 1.96 18.9

PWP HP 125 121 124 100 133 2.63 5.50 1.88 14.5

PWP HP 150 147 101 79 113 2.28 5.50 1.98 12.5

PWP HP 180 168 89 67 94 1.91 5.50 1.88 10.5

PWP HP 200 203 76 60 82 1.67 5.50 1.86 9.2

PWP HP 230 230 62 52 72 1.35 5.50 2.13 7.4

PWP HP 265 261 55 44 59 1.00 5.50 2.25 5.5

PWP HP 310 300 48 38 53 0.87 5.50 2.52 4.8

Southwestern PWP HP Replacement Series

ScreenName

U.S.Sieve



PWP HP 45 44 362 283 388 9.96 5.50 1.87 54.8PWP HP 50 50 299 234 313 8.33 5.50 1.79 45.8

PWP HP 60 57 263 207 278 6.78 5.50 2.10 37.9

PWP HP 70 71 208 158 221 4.81 5.50 1.96 26.5

PWP HP 80 77 186 145 192 3.93 5.50 1.95 21.6

PWP HP 100 105 143 113 154 3.20 5.50 1.90 17.6

PWP HP 125 121 124 100 133 2.65 5.50 1.98 14.6

PWP HP 150 147 101 79 113 2.28 5.50 2.17 12.5

PWP HP 180 168 89 67 94 1.91 5.50 1.93 10.53

PWP HP 200 203 76 60 82 1.67 5.50 1.78 9.2

PWP HP 230 230 62 52 72 1.31 5.50 2.20 7.2

PWP HP 265 261 55 44 59 .088 5.50 2.29 4.8

Screen Designations


- C-13 -


SCREEN SERIES: GBG HP

Description: Hookstrip panel, no perforated plate.Fine, HP-type rectangular mesh expoxy-bonded at con-tact points to 8 mesh backing cloth.

Sources: Derrick (original equipment manufacturer)Southwestern

Comments: GBG design maximizes screening area, and flow capac-ity, but screen life is limited.

Derrick GBG HP Series

ScreenName

U.S.Sieve



GBG HP 25 24 734 622 766 23.38 6.84 1.80 159.9

GBG HP 30 29 610 527 640 18.86 6.84 1.92 129.0

GBG HP 35 36 485 430 492 16.53 6.84 1.54 113.1

GBG HP 40 38 445 400 462 14.26 6.84 1.90 97.5

GBH HP 45 44 368 340 375 11.56 6.84 1.87 79.1

GBG HP 50 49 310 304 316 9.86 6.84 1.87 67.4

GBG HP 60 55 273 250 298 8.43 6.84 2.07 57.7

GBG HP 70 67 221 214 226 7.04 6.84 1.85 48.2

GBG HP 80 76 190 184 197 5.97 6.84 1.74 40.8

GBG HP 100 93 159 141 176 4.97 6.84 1.82 32.8

GBG HP 125 113 134 127 140 3.86 6.84 1.89 26.4

GBG HP 150 136 109 106 112 3.30 6.84 1.87 22.6

GBG HP 180 163 92 90 95 2.75 6.84 1.85 18.8

GBG HP 200 194 77 74 80 2.41 6.84 1.71 16.5

GBG HP 230 215 68 63 73 1.86 6.84 2.04 12.7

GBG HP 265 257 56 54 60 1.38 6.84 2.32 9.4

GBG HP 310 270 52 51 55 1.20 6.84 2.52 8.2

GBG HP 460 301 48 45 50 0.94 6.84 3.23 6.4



- C-14 -

Southwestern GBG HP Replacement Series

ScreenName

U.S.Sieve



GBG HP 45 44 368 340 375 11.66 6.84 1.87 79.7

GBG HP 50 49 310 304 316 9.93 6.84 1.87 67.9

GBG HP 60 55 273 250 298 8.48 6.84 2.07 58.0

GBG HP 70 67 221 214 226 7.08 6.84 1.85 48.4

GBG HP 80 76 190 184 197 5.99 6.84 1.74 41.0

GBG HP 100 93 159 141 176 4.81 6.84 1.82 32.9

GBG HP 125 113 134 127 140 3.87 6.84 1.89 26.5

GBG HP 150 136 109 106 112 3.30 6.84 1.87 22.6

GBG HP 180 163 92 90 95 2.76 6.84 1.85 18.9

GBG HP 200 194 77 74 80 2.41 6.84 1.71 16.5

GBG HP 230 215 68 63 73 1.87 6.84 2.04 12.8

GBG HP 265 257 56 54 60 1.38 6.84 2.32 9.5

Screen Designations


- C-15 -


SCREEN SERIES: PBP HP

Description: Hookstrip panel, perforated plate with 1 in. openings.Single extra-fine rectangular mesh screening layer oversquare mesh backing cloth.

Sources: Derrick

Comments: Highest conductance of Derrick’s standard perforatedplate panels.Shorter screen life than standard PWP series, but moreresistant to plugging from sticky material such as gilso-nite.

Derrick PBP HP Series

ScreenName

U.S.Sieve

Separation Potential Flow Capacity Aspect Trans.D50 D16 D84 Cond. Area Ratio

PBP HP 60 60 252 241 263 6.78 5.30 1.92 35.9

PBP HP 70 69 215 207 223 6.20 5.30 1.76 32.9

PBP HP 80 78 182 149 189 4.91 5.30 1.73 26.0

PBP HP 100 101 148 129 157 4.01 5.30 1.76 21.3

PBP HP 125 115 131 117 137 3.38 5.30 1.79 17.9

PBP HP 150 131 114 98 118 2.95 5.30 2.11 15.6

PBP HP 180 165 91 79 94 2.38 5.30 1.80 12.6

PBP HP 200 189 79 71 83 2.12 5.30 1.66 11.2

PBP HP 230 208 71 65 75 1.76 5.30 2.08 9.3

PBP HP 265 261 55 44 59 1.28 5.30 2.25 6.8

PBP HP 310 300 48 38 53 1.12 5.30 2.52 6.0



- C-16 -


SCREEN SERIES: SWG DX

Description: Hookstrip panel, unbonded, layered, extra-fine squaremesh cloth.

Sources: Derrick (original equipment manufacturer)Southwestern

Comments: Original layered screen series.Good deblinding characteristics.Screen life is poor.

Derrick SWG DX Series

ScreenName

U.S.Sieve



SWG DX 50 48 318 231 389 7.42 7.60 1.45 56.4

SWG DX 70 68 220 158 269 4.75 7.60 1.47 36.1

SWG DX 84 78 182 129 223 3.93 7.60 1.46 29.9

SWG DX 110 100 149 105 184 3.21 7.60 1.44 24.4

SWG DX 140 125 120 86 143 2.46 7.60 1.45 18.7

SWG DX 175 156 96 70 118 1.94 7.60 1.45 14.8

SWG DX 210 174 86 60 104 1.73 7.60 1.41 13.1

SWG DX 250 213 69 49 84 1.50 7.60 1.45 11.4

Southwestern SWG DX Series

ScreenName

U.S.Sieve



SWG DX 24 25 715 508 824 14.82 7.60 1.44 112.6

SWG DX 38 39 429 317 528 8.46 7.60 1.55 64.29

SWG DX 50 48 320 234 380 7.11 7.60 1.45 54.1

SWG DX 70 73 200 150 241 4.59 7.60 1.47 34.9

SWG DX 84 86 169 119 200 3.93 7.60 1.46 29.85

SWG DX 110 97 153 107 182 3.09 7.60 1.44 23.5

SWG DX 140 118 127 91 153 2.44 7.60 1.45 18.5

SWG DX 175 152 98 70 117 1.98 7.60 1.45 15.1

SWG DX 210 174 86 60 106 1.73 7.60 1.41 13.2

SWG DX 250 215 68 48 82 1.26 7.60 1.45 9.6

Screen Designations


- C-17 -


SCREEN SERIES: BXL-D

Description: Hookstrip perforated plate with hexagonal openings.Triple layer, extra-fine square mesh cloth, similar toPWP DX

Sources: Brandt

Comments: Replacement screen offered by Brandt.

Brandt BXL-D Replacement Series

ScreenName

U.S.Sieve



BHX-D24 28 625 435 760 34.11 5.53 1.49 188.62

BHX-D38 36 494 360 572 22.45 5.53 1.40 124.12

BHX-D50 47 327 231 349 8.85 5.53 1.43 48.92

BHX-D70 68 219 158 252 4.89 5.53 1.39 27.05

BHX-D84 79 181 127 218 3.78 5.53 1.46 20.92

BHX-D110 100 149 105 184 3.11 5.53 1.44 17.20

BHX-D140 118 127 95 147 2.97 5.53 1.39 16.41

BHX-D175 152 98 70 118 1.95 5.53 1.45 10.76

BHX-D210 158 95 69 109 1.81 5.53 1.41 10.03

BHX-D250 213 69 49 81 1.44 5.53 1.43 7.96



- C-18 -


SCREEN SERIES: Diamond Back, DX and HP type

Description: Hookstrip panel, perforated plate with triangular-shapedopenings.HP Type - Two layers, extra-fine rectangular mesh oversquare mesh backing cloth.DX Type - Two layers, extra-fine square mesh oversquare mesh backing cloth.

Sources: AdvancedDiamond-shaped plate pattern offers slightly more usablescreening area than standard 1 in. PWP-type squareopenings.

Advanced Diamond Back DX Replacement Series

ScreenName

U.S.Sieve



PWP DX 24 25 715 508 824 20.69 5.70 1.42 117.9

PWP DX 38 39 429 317 528 11.86 5.70 1.47 67.6

PWP DX 50 47 324 234 390 6.77 5.70 1.45 38.6

PWP DX 70 64 234 171 274 4.73 5.70 1.39 26.9

PWP DX 84 79 181 131 223 3.62 5.70 1.48 20.6

PWP DX 110 99 151 107 185 3.00 5.70 1.46 17.1

PWP DX 140 127 118 86 143 2.33 5.70 1.45 13.3

PWP DX 175 158 95 66 113 1.87 5.70 1.46 10.7

PWP DX 210 185 81 57 100 1.67 5.70 1.47 9.5

PWP DX 250 205 72 51 85 1.49 5.70 1.42 8.5

Screen Designations


- C-19 -

Advanced Diamond Back HP Replacement Series

ScreenName

U.S.Sieve



PWP HP 45 47 353 270 379 9.81 5.70 1.87 1.87

PWP HP 50 61 274 216 301 7.56 5.70 1.79 1.79

PWP HP 60 62 240 184 267 5.75 5.70 2.10 2.10

PWP HP 70 71 208 158 221 5.02 5.70 1.96 1.96

PWP HP 80 77 186 145 192 4.08 5.70 1.95 1.95

PWP HP 100 105 143 113 154 3.44 5.70 1.96 1.96

PWP HP 125 121 124 100 133 2.63 5.70 1.88 1.88

PWP HP 150 147 101 79 113 2.28 5.70 1.98 1.98

PWP HP 180 168 89 67 94 1.91 5.70 1.88 1.88

PWP HP 200 203 76 60 82 1.67 5.70 1.86 1.86

PWP HP 230 230 62 52 72 1.35 5.70 2.13 2.13

PWP HP 265 261 55 44 59 1.00 5.70 2.25 2.25

PWP HP 310 300 48 38 53 0.87 5.70 2.52 2.52



- C-20 -


SCREEN SERIES: HCR

Description: Hookstrip, perforated plate with 1 in. openings.Proprietary weave, openings are long narrow slots.

Sources: Cagle (built by Advanced)

Comments: High conductance, extremely long life.Cut point will depend on shape of solids.- near minimum listed D50 for sands.- near maximum listed D50 for slivers.

Derrick

Screen Name Mesh Count D50 Range Conductance Area Aspect Ratio

HCR 80 12 X 93 173-250 7.06 5.5 10

HCR 100 15 X 115 141-203 5.58 5.5 10

HCR 150 19 X 158 105-151 4.45 5.5 10

HCR 200 19 X 200 74-107 3.32 5.5 14

HCR 250 20 X 229 61-88 2.50 5.5 17

HCR 325 43 X 259 43-62 1.51 5.5 20

Screen Designations


- C-21 -


SCREEN SERIES: HCS

Description: Hookstrip perforated plate with 1 in. openings.Single layer, extra-fine square mesh cloth over backingcloth.

Sources: Cagle (built by Advanced)Derrick (designated PBP DX)

Comments: High conductance series, less susceptible to plugging byasphaltenes than triple layer screens.Screen life averages 40% less than PWP DX type.

Derrick

ScreenName

U.S.Sieve



HCS 24 25 715 508 824 20.69 5.30 1.42 109.66

HCS 38 34 522 403 558 14.46 5.30 1.29 76.65

HCS 50 44 367 264 426 9.56 5.30 1.41 50.67

HCS 70 57 266 191 275 6.75 5.30 1.29 35.78

HCS 84 64 234 178 243 5.90 5.30 1.29 31.26

HCS 100 76 189 157 197 4.61 5.30 1.22 24.42

HCS 130 100 149 137 151 3.62 5.30 1.14 19.19

HCS 160 124 121 113 123 3.21 5.30 1.12 17.03

HCS 180 135 110 100 115 3.05 5.30 1.16 16.14

HCS 220 176 85 81 88 1.90 5.30 1.10 10.07

HCS 280 228 63 60 65 1.17 5.30 1.09 6.18

HCS 325 282 51 48 53 0.76 5.30 1.09 4.00



- C-22 -

Fluid Systems - Model 500, Model 50

SCREEN SERIES: MF

Description: Pretensioned, glued to rigid frame, 3 in. spacing betweenglue lines.Square mesh tensile bolting cloth over backing cloth.

Sources: Fluid Systems (original equipment manufacturer)Southwestern

Comments: Screens are not repairable.Standard screen series for Fluid Systems shaker.

Fluid Systems MF Series

ScreenName

U.S.Sieve



MF 10 11 1905 na na 49.68 6.61 na 328.4

MF 20 20 863 na na 15.93 6.61 na 105.3

MF 28 24 716 na na 16.14 6.61 na 106.7

MF 30 26 682 671 687 16.60 6.61 1.03 109.7

MF 40 37 476 465 487 9.51 6.61 1.04 62.9

MF 74 61 248 241 252 5.18 6.61 1.08 34.2

MF 100 75 193 186 197 5.13 6.61 1.09 33.9

MF 120 100 149 129 152 2.65 6.61 1.18 17.5

MF 145 126 119 109 122 1.95 6.61 1.14 12.90

MF 165 137 108 99 111 1.79 6.61 1.13 11.85

MF 180 156 96 93 97 1.56 6.61 1.10 10.34

MF 200 172 87 82 90 1.45 6.61 1.10 9.61

Screen Designations


- C-23 -

Southwest Replacement Series

ScreenName

U.S.Sieve



10 11 1905 na na 49.68 7.10 na 352.7

20 20 864 na na 15.93 7.10 na 113.1

40 41 402 389 411 6.09 7.10 1.05 43.2

60 61 245 239 252 2.32 7.10 1.04 16.5

74 61 248 241 252 5.18 7.10 1.08 36.8

100 75 193 186 197 5.13 7.10 1.09 36.4

120 100 149 129 152 2.65 7.10 1.18 18.8

145 126 119 109 122 1.95 7.10 1.14 13.8

165 137 108 99 111 1.79 7.10 1.13 12.7

180 156 96 93 97 1.56 7.10 1.10 11.1

200 172 87 82 90 1.45 7.10 1.10 10.3



- C-24 -


SCREEN SERIES: HCS

Description: Pretensioned, glued to rigid frame, 3 in. spacing betweenglue lines.Single layer, extra-fine square mesh over backing cloth.

Sources: Fluid Systems

Comments: Screens are not repairable.High conductance series, shorter screen life than MFseries.

Fluid Systems HCS Series

ScreenName

U.S.Sieve



HCS 38 34 522 403 558 19.08 6.61 1.29 126.1

HCS 50 44 367 264 426 9.60 6.61 1.41 63.5

HCS 70 57 266 191 275 7.93 6.61 1.29 52.4

HCS 84 64 234 178 243 6.78 6.61 1.29 44.8

HCS 130 100 149 137 151 3.92 6.61 1.14 25.9

HCS 160 124 121 113 123 3.45 6.61 1.12 22.8

HCS 180 135 110 100 115 3.25 6.61 1.16 21.5

HCS 220 176 85 81 88 1.98 6.61 1.10 13.1

HCS 280 228 63 60 65 1.20 6.61 1.09 7.9

HCS 325 282 51 48 53 0.77 6.61 1.09 5.1

Screen Designations


- C-25 -


SCREEN SERIES: XS

Description: Pretensioned, glued to rigid frame, 3 in. spacing betweenglue lines.Single layer, synthetic mesh over steel wire backingcloth.

Sources: Fluid Systems

Comments: Screens are not repairable.Conductance is generally low in this series.

Fluid Systems XS Series

ScreenName

U.S.Sieve



XS 40 44 429 356 439 7.21 6.61 1.17 47.7

XS 60 60 250 242 255 4.14 6.61 1.09 27.4

XS 80 84 171 167 175 3.02 6.61 1.07 19.9

XS 100 100 149 125 152 2.82 6.61 1.17 18.6

XS 120 114 132 128 135 2.16 6.61 1.04 14.3

XS 150 158 95 91 98 1.93 6.61 1.12 12.7

XS 180 174 86 82 89 1.38 6.61 1.06 9.1

XS 250 294 49 48 51 0.58 6.61 1.11 3.8

XS 325 346 42 41 43 0.50 6.61 1.09 3.3



- C-26 -


SCREEN SERIES: PTP, DX, PTP, HP

Description: Perforated plate with 1 in. openings bonded to rigidframe.PTP DX - Two layers, extra-fine rectangular mesh overbacking cloth.

Sources: Advanced

Comments: Repairable

Advanced PTP DX Replacement Series

ScreenName

U.S.Sieve



PTP DX 50 47 324 234 390 6.77 5.34 1.45 36.1

PTP DX 70 64 234 171 274 4.73 5.34 1.39 25.2

PTP DX 84 79 181 131 223 3.62 5.34 1.48 19.3

PTP DX 110 99 151 107 185 3.00 5.34 1.46 16.0

PTP DX 140 127 118 86 143 2.33 5.34 1.45 12.5

PTP DX 175 158 95 66 113 1.87 5.34 1.46 10.0

PTP DX 210 185 81 57 100 1.67 5.34 1.47 8.9

PTP DX 250 205 72 51 85 1.49 5.34 1.42 7.9

Advanced PTP DX Replacement Series

ScreenName

U.S.Sieve



PTP HP 45 47 353 270 379 9.81 5.34 1.87 52.4

PTP HP 50 61 274 216 301 7.56 5.34 1.79 40.3

PTP HP 60 62 240 184 267 5.75 5.34 2.10 30.7

PTP HP 70 71 208 158 221 5.02 5.34 1.96 26.8

PTP HP 80 77 186 145 192 4.08 5.34 1.95 21.8

PTP HP 100 105 143 113 154 3.44 5.34 1.96 18.4

PTP HP 125 121 124 100 133 2.63 5.34 1.88 14.1

PTP HP 140 147 101 79 113 2.28 5.34 1.98 12.2

PTP HP 180 168 89 67 94 1.91 5.34 1.88 10.2

PTP HP 200 203 76 60 82 1.67 5.34 1.86 8.9

PTP HP 230 230 62 52 72 1.35 5.34 2.13 7.2

PTP HP 265 261 55 44 59 1.00 5.34 2.25 5.3

PTP HP 310 300 48 38 53 0.87 5.34 2.52 4.6

Screen Designations


- C-27 -

Harrisburg - Linear Tandem

SCREEN SERIES: Harrisburg


Sources: HarrisburgComments: Use coarser mesh on top deck.

Monitor tension for maximum screen life.

Harrisburg Series

ScreenName

U.S.Sieve



24 23 625 435 760 34.11 8.20 1.49 279.7

38 30 494 360 572 10.00 8.20 1.40 82.0

50 42 386 286 406 8.07 8.20 1.29 66.2

70 58 258 252 263 6.15 8.20 1.04 50.5

84 56 260 251 267 5.44 8.20 1.05 44.6

110 113 134 97 166 3.00 8.20 1.50 18.0

140 132 113 77 138 2.38 8.20 1.54 14.3

175 152 98 70 118 1.90 8.20 1.45 11.4

210 158 95 69 109 1.67 8.20 1.41 10.0



- C-28 -

Swaco - ALS

SCREEN SERIES: XL


Sources: Swaco (Southwestern)Advanced

Comments: Monitor screen tension for maximum screen life.

Swaco XL Series

ScreenName

U.S.Sieve



XL 50 48 320 234 380 6.17 9.40 1.45 58.0

XL 70 73 200 150 241 3.76 9.40 1.48 35.4

XL 84 86 169 119 200 3.44 9.40 1.44 32.3

XL 110 97 153 107 182 2.75 9.40 1.46 25.9

XL 140 118 127 91 153 2.14 9.40 1.41 20.1

XL 175 152 98 70 117 1.78 9.40 1.48 16.8

XL 210 174 86 60 106 1.63 9.40 1.41 15.3

XL 250 215 68 48 82 1.21 9.40 1.45 11.4

Advanced DX 2 in. Plastic Replacement Series

ScreenName

U.S.Sieve



DX 50 47 324 234 390 6.77 9.74 1.45 65.9

DX 70 64 234 171 274 4.73 9.74 1.39 46.0

DX 84 79 181 131 223 3.65 9.74 1.48 35.2

DX 110 99 151 107 185 3.00 9.74 1.46 29.2

DX 140 127 118 86 143 2.33 9.74 1.45 22.7

DX 175 158 95 66 113 1.87 9.74 1.46 18.2

DX 210 185 81 57 100 1.67 9.74 1.47 16.3

DX 250 205 72 51 85 1.49 9.74 1.42 14.5

Screen Designations


- C-29 -

Swaco - ALS

SCREEN SERIES: ALS

Description: Hookstrip, unbonded, plastic strips at support rails.Triple layer, square mesh cloth.

Sources: SwacoComments: Higher capacity, good deblinding characteristics but

shorter life than XL series.Monitor screen tension for maximum screen life.

Swaco ALS Series

ScreenName

U.S.Sieve



ALS 50 48 320 234 380 6.17 11.75 1.45 72.5

ALS 70 73 200 150 241 3.76 11.75 1.48 44.2

ALS 84 86 169 119 200 3.44 11.75 1.44 40.4

ALS 110 97 153 107 182 2.75 11.75 1.46 32.3

ALS 140 118 127 91 153 2.14 11.75 1.41 25.2

ALS 175 152 98 70 117 1.78 11.75 1.48 21.0

ALS 210 174 86 60 106 1.63 11.75 1.41 19.2

ALS 250 215 68 48 82 1.21 11.75 1.45 14.2



- C-30 -

Swaco - ALS

SCREEN SERIES: HCR

Description: Hookstrip, 2 in. plastic grid.Proprietary weave, openings are long narrow slots.

Sources: Cagle (built by Advanced)Comments: High conductance, extremely long life.

Cut point will depend on shape of solids.- near minimum listed D50 for sands.- near maximum listed for D50 for slivers.

Swaco

Screen Name Mesh Count D50 Range Conductance Area Aspect Ratio

HCR 80 12 X 93 173-250 7.06 9.4 10

HCR 100 15 X 115 141-203 5.58 9.4 10

HCR 150 19 X 158 105-151 4.45 9.4 10

HCR 200 19 X 200 74-107 3.32 9.4 14

HCR 250 20 X 229 61-88 2.50 9.4 17

HCR 325 43 X 259 43-62 1.51 9.4 20

Screen Designations


- C-31 -

Swaco - ALS

SCREEN SERIES: Advanced DX Replacement Series

Description: Hookstrip, perforated plate with 1 in. openings.Two layers, extra-fine square mesh over square meshbacking cloth.

Sources: Advanced

Comments: Check support stringers carefully to ensure full contact.

Advanced DX 1 in. Metal Replacement Series

ScreenName

U.S.Sieve



DX 50 47 324 234 390 6.77 9.88 1.45 66.8

DX 70 64 234 171 274 4.73 9.88 1.39 46.7

DX 84 79 181 131 223 3.65 9.88 1.48 35.7

DX 110 99 151 107 185 3.00 9.88 1.46 29.6

DX 140 127 118 86 143 2.33 9.88 1.45 23.1

DX 175 158 95 66 113 1.87 9.88 1.46 18.2

DX 210 185 81 57 100 1.67 9.88 1.47 16.3

DX 250 205 72 51 85 1.49 9.88 1.42 14.7



- C-32 -

Sweco - LM-3

SCREEN SERIES: TBC

Description: Hookstrip, perforated plate, available with 1 in. or 2 in.openings.Tensile bolting cloth over coarse backing cloth.

Sources: Sweco (original equipment manufacturer)Southwestern

Comments: Use 1 in. perf plate as feed end panel and under heaviersolids loading applications.

Sweco TBC 1 in. Series

ScreenName

U.S.Sieve



TBC 30 26 682 671 687 24.33 6.60 1.03 160.6

TBC 40 37 476 465 487 11.63 6.60 1.04 76.7

TBC 50 41 400 381 417 8.45 6.60 1.08 55.8

TBC 60 49 318 306 330 6.58 6.60 1.05 43.4

TBC 70 57 266 261 272 6.10 6.60 1.05 40.3

TBC 80 66 228 222 231 4.34 6.60 1.05 28.6

TBC 94 78 185 181 188 3.07 6.60 1.03 20.3

TBC 105 94 158 154 162 3.00 6.60 1.08 19.8

TBC 120 102 147 144 150 2.68 6.60 1.03 17.7

TBC 145 122 123 118 126 2.14 6.60 1.07 14.1

TBC 165 133 112 108 115 1.95 6.60 1.04 12.9

TBC 200 168 89 86 92 1.56 6.60 1.05 10.3

TBC 230 193 75 73 77 1.34 6.60 1.04 8.8

Screen Designations


- C-33 -

Sweco TBC 2 in. Series

ScreenName

U.S.Sieve



TBC 30 26 682 671 687 24.33 7.16 1.03 174.2

TBC 40 37 476 465 487 11.63 7.16 1.04 83.3

TBC 50 41 400 381 417 8.45 7.16 1.08 60.5

TBC 60 49 318 306 330 6.58 7.16 1.05 47.1

TBC 70 57 266 261 272 6.10 7.16 1.05 43.7

TBC 80 66 228 222 231 4.34 7.16 1.05 31.1

TBC 94 78 185 181 188 3.07 7.16 1.03 22.0

TBC 105 94 158 154 162 3.00 7.16 1.08 21.5

TBC 120 102 147 144 150 2.68 7.16 1.03 19.2

TBC 145 122 123 118 126 2.14 7.16 1.07 15.3

TBC 165 133 112 108 115 1.95 7.16 1.04 13.9

TBC 200 168 89 86 92 1.56 7.16 1.05 11.2

TBC 230 193 75 73 77 1.34 7.16 1.04 9.6

Southwestern 1 in. TBC Replacement Series

ScreenName

U.S.Sieve



TBC 30 26 682 671 687 24.33 6.81 1.03 122.6

TBC 40 37 476 465 487 11.63 6.81 1.04 67.8

TBC 50 41 400 381 417 8.45 6.81 1.08 68.5

TBC 60 49 318 306 330 6.58 6.81 1.05 44.8

TBC 70 57 266 261 272 6.10 6.81 1.05 41.5

TBC 80 66 228 222 231 4.34 6.81 1.05 29.5

TBC 94 78 185 181 188 3.07 6.81 1.03 20.9

TBC 105 94 158 154 162 3.00 6.81 1.08 20.4

TBC 120 102 147 144 150 2.68 6.81 1.03 18.3

TBC 145 122 123 118 126 2.14 6.81 1.07 14.6

TBC 165 133 112 108 115 1.95 6.81 1.04 13.3

TBC 200 168 89 86 92 1.56 6.81 1.05 10.6

TBC 230 193 75 73 77 1.34 6.81 1.04 9.1



- C-34 -

Southwestern TBC 2 in. Replacement Series

ScreenName

U.S.Sieve



TBC 30 26 682 671 687 24.33 7.68 1.03 186.9

TBC 40 37 476 465 487 11.63 7.68 1.04 89.4

TBC 50 41 400 381 417 8.45 7.68 1.08 64.9

TBC 60 49 318 306 330 6.58 7.68 1.05 50.5

TBC 70 57 266 261 272 6.10 7.68 1.05 46.9

TBC 80 66 228 222 231 4.34 7.68 1.05 33.3

TBC 94 78 185 181 188 3.07 7.68 1.03 23.6

TBC 105 94 158 154 162 3.00 7.68 1.08 23.0

TBC 120 102 147 144 150 2.68 7.68 1.03 20.6

TBC 145 122 123 118 126 2.14 7.68 1.07 16.5

TBC 165 133 112 108 115 1.95 7.68 1.04 15.0

TBC 200 168 89 86 92 1.56 7.68 1.05 12.0

TBC 230 193 75 73 77 1.34 7.68 1.04 10.3

Screen Designations


- C-35 -

Sweco - LM-3

SCREEN SERIES: MG

Description: Hookstrip, perforated plate, available with 1 in. or 2 in.openings.Market grade cloth over coarse backing cloth.

Sources: Southwestern

Comments: TBC panels preferred except for extreme conditions.Use 1 in. perf plate as feed end panel and under heaviersolids loading applications.

Southwestern 1 in. MG Replacement Series

ScreenName

U.S.Sieve



MG 30 33 561 548 578 9.10 6.81 1.05 42.9

MG 40 41 402 389 411 6.09 6.81 1.05 31.1

MG 50 49 305 298 313 3.23 6.81 1.07 18.8

MG 60 61 245 239 252 2.32 6.81 1.04 15.8

MG 80 77 188 181 194 1.86 6.81 1.06 12.7

MG 100 103 146 141 152 1.69 6.81 1.11 9.6

MG 120 121 124 121 126 1.22 6.81 1.04 8.3

MG 150 138 107 102 110 1.36 6.81 1.07 9.3

MG 200 198 75 73 78 0.86 6.81 1.04 5.8

MG 250 230 62 61 63 0.77 6.81 1.07 5.3

MG 325 325 44 38 47 0.43 6.81 1.14 2.9

Southwestern MG 2 in. Replacement Series

ScreenName

U.S.Sieve



MG 30 33 561 548 578 9.10 7.68 1.05 69.9

MG 40 41 402 389 411 6.09 7.68 1.05 46.8

MG 50 49 305 298 313 3.23 7.68 1.07 24.8

MG 60 61 245 239 252 2.32 7.68 1.04 17.7

MG 80 77 188 181 194 1.86 7.68 1.06 14.3

MG 100 103 146 141 152 1.69 7.68 1.11 13.0

MG 120 121 124 121 126 1.22 7.68 1.04 9.4

MG 150 138 107 102 110 1.36 7.68 1.07 10.4

MG 200 198 75 73 78 0.86 7.68 1.04 6.6

MG 250 230 62 61 63 0.77 7.68 1.07 5.9

MG 325 325 44 38 47 0.43 7.68 1.14 3.3



- C-36 -

Sweco - LM-3

SCREEN SERIES: DX-Type

Description: Hookstrip, perforated plate with 1 in. openings.Two layers, extra-fine mesh over coarse backing cloth.

Sources: AdvancedComments: May provide better resistance to blinding in some appli-

cations.Usable screening area, flow capacity is better than 1 in.TBC panel.

Advanced DX 1 in. Replacement Series

ScreenName

U.S.Sieve



DX 38 39 429 317 528 11.86 7.7 1.47 91.32

DX 50 47 324 234 390 6.77 7.7 1.45 52.09

DX 70 64 234 171 274 4.73 7.7 1.39 36.39

DX 84 79 181 131 223 3.62 7.7 1.48 27.84

DX 110 99 151 107 185 3.00 7.7 1.46 23.08

DX 140 127 118 86 143 2.38 7.7 1.45 18.33

DX 175 158 95 66 113 1.86 7.7 1.46 14.35

DX 210 185 81 57 100 1.67 7.7 1.47 12.82

DX 250 205 72 51 85 1.45 7.7 1.42 11.17

Screen Designations


- C-37 -

Sweco - LF-3

SCREEN SERIES: CTB

Description: Perforated plate with 1 in. openings bonded to a rigidframe.Tensile bolting cloth over coarse backing cloth.

Sources: Sweco (built by Advanced)

Comments: One of two screen types available for this shaker.The CTB series should provide longer life than CHC, atlower throughput.

Advanced CTB Series

ScreenName

U.S.Sieve



CTB 20 18 1041 40.93 7.54 308.6

CTB 30 26 682 671 687 18.00 7.54 1.03 135.7

CTB 40 37 476 465 487 9.96 7.54 1.04 75.1

CTB 70 57 266 261 272 6.10 7.54 1.05 46.0

CTB 120 102 147 144 150 2.68 7.54 1.03 20.2

CTB 145 122 123 118 126 2.14 7.54 1.07 16.2

CTB 165 133 112 108 115 1.95 7.54 1.04 14.7

CTB 200 168 89 86 92 1.56 7.54 1.05 11.7



- C-38 -

Sweco - LF-3

SCREEN SERIES: CHC

Description: Perforated plate with 1 in. openings bonded to a rigidframe.Two layers, extra-fine rectangular mesh over coarsemesh backing cloth.

Sources: Advanced

Comments: High capacity screening option for LF-3 shaker.

Advanced CHC Series

ScreenName

U.S.Sieve



CHC 24 25 715 508 824 20.69 7.54 1.42 156.0

CHC 38 39 429 317 528 11.86 7.54 1.47 89.4

CHC 45 47 353 270 379 9.81 7.54 1.87 73.9

CHC 60 62 240 184 267 5.75 7.54 2.10 43.3

CHC 80 77 186 145 192 4.08 7.54 1.95 30.8

CHC 110 99 151 107 185 3.00 7.54 1.46 22.6

CHC 125 127 120 92 131 2.53 7.54 1.98 19.1

CHC 150 161 107 78 117 2.15 7.54 2.17 16.2

CHC 180 189 85 62 93 1.83 7.54 1.93 13.8

CHC 210 185 81 57 100 1.55 7.54 1.47 11.7

CHC 230 239 60 47 69 1.27 7.54 1.47 9.6

Screen Designations


- C-39 -

Thule Rigtech - VSM 100

SCREEN SERIES: Thule TBC

Description: Perforated plate type bonded to a rigid frame.Tensile bolting cloth square mesh over coarse meshbacking cloth.

Sources: ThuleSouthwestern

Comments: Standard screen series for this shaker.

Thule TBC Series

ScreenName

U.S.Sieve



TBC 52 49 311 222 344 3.99 4.30 1.38 17.2

TBC 84 70 212 n/a n/a 3.08 4.30 n/a 13.3

TBC 105 95 156 130 161 2.38 4.30 1.21 10.3

TBC 120 106 142 118 146 2.18 4.30 1.17 9.4

TBC 140 122 123 118 126 1.81 4.30 1.07 7.8

TBC 165 133 112 108 115 1.67 4.30 1.04 7.2

TBC 200 168 89 86 92 1.37 4.30 1.05 5.9

TBC 230 193 75 73 77 1.20 4.30 1.04 5.2

Southwestern TBC Replacement Series

ScreenName

U.S.Sieve



52 49 311 222 344 4.65 4.30 1.38 20.0

84 70 212 n/a n/a 3.25 4.30 n/a 14.0

105 95 156 130 161 2.48 4.30 1.21 10.7

120 106 142 118 146 2.26 4.30 1.17 9.7

145 122 123 118 126 1.87 4.30 1.07 8.0

165 133 112 108 115 1.72 4.30 1.04 7.4

200 168 89 86 92 1.41 4.30 1.05 6.1

230 193 75 73 77 1.23 4.30 1.04 5.3



- C-40 -

Tri-Flo - Model 148

SCREEN SERIES: Tri-Flow

Description: Hookstrip, 2 in. plastic grid.Standard DX-style composition.

Sources: Tri-FlowComments:

Tri-Flo Series

ScreenName

U.S.Sieve



50 48 320 234 380 6.77 5.09 1.45 34.46

70 73 200 150 241 3.97 5.09 1.48 20.21

84 86 169 119 200 3.61 5.09 1.44 18.37

110 97 153 107 182 2.89 5.09 1.46 14.71

140 118 127 91 153 2.21 5.09 1.41 11.25

175 152 98 70 117 1.83 5.09 1.48 9.31

210 174 86 60 106 1.67 5.09 1.41 8.50

250 215 68 48 82 1.23 5.09 1.45 6.26

Screen Designations


- C-41 -

Triton NNF Screening Machine

SCREEN SERIES: TSS

Description: Hookstrip panel, perforated plate with 2 in. openings.Two layers, extra-fine square mesh over square meshbacking cloth. Middle cloth is rectangular mesh in somecompositions.

Sources: TritonAdvancedSouthwestern

Comments: Standard screen series for this shaker.

Triton TSS Series

ScreenName

U.S.Sieve



TSS 24 21 811 587 889 34.11 6.19 1.36 211.1

TSS 50 48 403 302 429 10.77 6.19 1.32 66.7

TSS 84 66 228 190 237 6.34 6.19 1.21 39.2

TSS 100 98 152 108 188 2.89 6.19 1.47 17.9

TSS 140 117 129 93 143 2.76 6.19 1.37 17.0

TSS 175 133 112 84 123 2.40 6.19 1.36 14.9

TSS 180 138 107 102 110 1.33 6.19 1.04 8.3

TSS 210 144 103 79 110 2.30 6.19 1.32 14.3

TSS 230 200 74 57 82 1.29 6.19 1.36 8.0

Southwestern TSS Replacement Series

ScreenName

U.S.Sieve



TSS 24 21 811 587 889 20.69 5.91 1.36 122.3

TSS 38 38 440 313 537 11.86 5.91 1.45 70.1

TSS 50 48 320 234 380 6.77 5.91 1.45 40.0

TSS 70 73 200 150 241 4.17 5.91 1.48 24.7

TSS 84 86 169 119 200 3.62 5.91 1.44 21.4

TSS 110 97 153 107 182 2.89 5.91 1.46 17.1

TSS 140 118 127 91 153 2.32 5.91 1.41 13.7

TSS 175 152 98 70 117 1.90 5.91 1.48 11.2

TSS 210 174 86 60 106 1.67 5.91 1.41 9.9

TSS 230 215 68 48 82 1.23 5.91 1.45 7.3



- C-42 -

Advanced TSS Replacement Series

ScreenName

U.S.Sieve



TSS 50 47 324 234 390 6.77 6.23 1.45 42.1

TSS 70 64 234 171 274 4.73 6.23 1.39 29.4

TSS 84 79 181 131 223 3.62 6.23 1.48 22.5

TSS 110 99 151 107 185 3.00 6.23 1.46 18.7

TSS 140 127 118 86 143 2.33 6.23 1.45 14.5

TSS 175 158 95 66 113 1.87 6.23 1.46 11.7

TSS 210 185 81 57 100 1.67 6.23 1.47 10.4

TSS 250 205 72 51 85 1.49 6.23 1.42 9.3

“Proprietary: - for the exclusive use of Chevron Corporation Company and other wholly owned subsidiaries of Chevron Corporation.”

D.1

Appendix D. Pump Performance Curves



D.2

“Proprietary: - for the exclusive use of A

moco P

roduction and other wholly ow

ned subsidiaries of Am

oco Corporation.”

D.3

Pum

p Performance C

urves



D.4

Solids Control M

anual


moco P

roduction Com

pany and other wholly ow


oco Corporation.”

D.5


moco P



oco Corporation.”

D.6

Pum

p Performance C

urves

Solids Control M

anual


moco P

roduction Com



oco Corporation.”

D.7


moco P



oco Corporation.”

D.8

Pum

p Performance C

urves

MISSION MAGNUM 16 X 5 X 14

Solids Control M

anual


moco P

roduction Com



oco Corporation.”

D.9


moco P



oco Corporation.”

D.10

Pum

p Performance C

urves

MISSION MAGNUM 18 X 6 X 11

Solids Control M

anual


moco P

roduction Com



oco Corporation.”

D.11



D.12

MISSION MAGNUM8 X 6 X 14

Pump Performance Curves


D.13

HARRISBURG



D.14



D.15

HARRISBURG



D.16

HARRISBURG



D.17



D.18

HARRISBURG

“Proprietary: - for the exclusive use of C

hevron Corporatin and other w

holly owned subsidiaries of C

hevron Corporation.”

.1

Table E.1Oilfield Shale Shakers

a b c d e f g h i j k l m n o p

Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight

(lbs) CommentsDecks Screens

Brandt (Division of Drexel Oilfield Services, Inc.)

Junior 1 1 Fixed-13° U.S. N.P.T. Spring

Loaded one side

9 B.D. 1390 .188 5.1 UE 25.5 54.75x80.75x41.5 980 Duals available.

Standard 1 1 Fixed-13° U.S. N.P.T. Spring

Loaded one side

20 B.D. 1750 .047 2.0 UE 36.25 83.25x63-5/8x44 1880 Duals & triples available.

Tandem 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

40 B.D. 1380142511

.18 4.99

4.011

C 38 79.75x72x52-5/8 2865 Duals & triples available.

Total FlowCleaner

2 4 Adjust Top +3°, +1.5°

Btm 0°, -1.5°

O.S. N.P.T. Spring

Loaded one side

50 B.D. 1860 .11 5.29 C 40 114.25x82x55.25 5800 Flowback pan; Variable speed model available.

Retro FSBasket

2 2 Fixed 0° O.S. N.P.T. Spring

Loaded one side

40 B.D. 1620 .14 5.29 C 38 60-5/16x66-3/8x25-3/16

1430 Flowback pan.16

ATL-1000 2 4 Adjust Top -0° to

-10° Btm -1:0° to

-10°

U.S. Top-N.P.T. Not Spring

Loaded

10.8

25.0

D.G.B.D. 1765 .068 3.011 L 43 99.5x71x56.75 4300 Variable angle

ATL-CS15 2&3: +10° to 0°

N.A. Btm-P.T.

Broadbent

DT 2000 2 Top-2 Top Adjust -10° to

-4°,-5° to +1°

O.S. N.P.T. Bonded Spring Loaded

Top-19.0 B.D 1760 .127 5.39 L 35 110x69x61.5 4180 Duals & triples available.

Btm-3 Btm Adjust 0° to +6°

Bot-26.4

Solids Control M

anual





.2

Cagle

Ultra-Screen 1 3 Adjust +3° to -4°

O.S. N.P.T. Not Spring Loaded

23.3 B.D. 1350 .185 4.8 C 30.5 122x71x53 3700 Duals & Low pro-files available.

Linear Screen

1 3 Adjust +6° to -4°

O.S. N.P.T. Spring

Loaded one side

23.3 B.D. 1325 .160 3.611 L 30.5 122x71x64 4000 Duals & Low pro-files available.

Dahlory

139 1 3 Adjust 0° to +5°

O.S. N.P.T. Spring

Loaded both sides

27 Direct or Hydraulic

17401400-2000

? ? L 34 112x60x60 5000

145 1 1 Fixed-13° O.S. N.P.T. Spring

Loaded one side

20 B.D. 1750 1/4-3/8? ? UE 18 84x66x54 2000 Duals available.

245 2 2 Fixed 0° U.S. N.P.T. Not Spring Loaded

40 B.D. 1500 ? ? C ? 156x84x46 5600

Demco (Discontinued Solids Control Product Line)

Tandem Screen

2 2 Fixed-3° O.S. N.P.T. Not Spring Loaded

37.5 B.D. 1400 3/8.1811

5.095.011

C 33.5 97x73x48 2300 Duals & triples available.

Derrick

Standard 1 3 Fixed-20°, -25°,-30°

O.S. N.P.T. Spring

Loaded both sides

23.3 I. 3600 .031.02211

5.74.011

UE 51.5 118x63x74 4500 Ramp-Lok screen tensioning avail. for all units. Singles available.

LP 1 3 Fixed-5°, 10°, -15°

O.S. N.P.T. Spring

Loaded both sides

23.3 I. 1750 .100.08011

4.43.511

UE 31.5 124x57x58 4500 Duals & triples available.

Flo-Line Cleaner

1 3 Adjust +6° to 0°


23.3 I., I. 1750 .07811 3.411 L 31.5 123x63x57 5000 Duals & triples available. AWD available.

Table E.1 (Continued)Oilfield Shale Shakers


Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight






.3

Flo-Line Cleaner (+)

1 3 Adjust +5° to -15°


23.3 I., I. 1750 .07811 3.411 L 27-44 125.75x73.75x68 6000 Duals & triples available. Deck angles adjustable while drilling.

Flo-Line Cleaner

Model 58

1 3 Adjust +5° to -15°


32.9 I., I. 1750 .078 3.4 L 27-44 125.375x91.25x68 6600 Duals & triples available. Deck angles adjustable while drilling.

DFE/Solids Control (see N L Baroid)

Double Life Corporation

Single Tandem Linear

2 2 Adjust +5° to -3°

O.S. N.P.T. Spring

Loaded one side

40 B.D. 1750 3/16? L 38 84x72x62 3300

Low Profile Linear

1 3 Adjust +5° to -1°


23.3 B.D. 1750 3/16? L 26" 117.5x66x58 5000

Drexel Oilfield Services, Inc. (see Brandt)

Flo-Trend

Transition Screen

Separator(FTS 3600L)

1 3 Adjust 1:-46° to-39° 2&3: -10 to +6°

O.S. N.P.T. 35.0 I., I. 1728 .1239 4.29 L 49 128x78x56 5100

Linear Horizontal (LH) Screen Separator (see MTM RLM 28)

Fluid Systems, Inc.

High VolumeLinear Shaker

1 3 Adjust +5° to -5°

N.A. P.T. 25.4 I. 1200 .176 3.711 L 34 115x66x42 2500 Polyester screens available.

Geolograph-Pioneer (has merged with Swaco)

24H-100 1 1 Fixed-9° U.S. N.P.T. Spring

Loaded one side

8 B.D. 1725 3/16? 7.98? UE 28 68x42x50 1360


Loaded one side

12 B.D. 1725 3/16? 7.98? UE 28 68x54x50 1735



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight


Solids Control M

anual





.4


Loaded one side

20 B.D. 1725 3/16? 7.98? UE 30 80x66x50 2100 Dual 45H-400 available.

JT 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

24 B.D. 1350 3/16? 4.98

4.811

C 38 68x60x46 2500 Discontinued, parts only avail-able.

ST 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

40 B.D. 1350 3/16? 4.98 C 38 80x72x46 3200 Dual DT & Triple TT available.

Harrisburg

Junior Standard

1 1 Fixed-8° U.S. N.P.T. Spring

Loaded one side

8.3 B.D. 1750 .125? 5.4? UE 24.5 54-3/4x55.5x43.5 920

Standard 1 1 Fixed-8° U.S. N.P.T. Spring

Loaded one side

20 B.D. 1500 .125? 4.0 UE 30 85-15/16x65x43-3/4 1850 Dual Standard available.

Tandem 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

40 B.D. 1500 .125 4.03.511

C 36.75 85-15/16x68.25x52.5

2800 Has flowback pan; dual & triple tan-dems available.

Linear Tandem Retrofit

2 2 Adjust +5° to -3°

O.S N.P.T. Spring

Loaded both sides

40 B.D. 1750 .1159 4.511 L 36.75 85-15/16x65x43.75 3200

Homco Omega (has merged with Sweco Oilfield Services, Inc.)

Double Deck 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

40 B.D. 1350 .15511 4.011 C 38 80x72x46 3200 Same as Geolo-graph Pioneer ST.

LP 1 3 Fixed-8.5°, -11.5°,-12.

5°,

O.S. N.P.T. Spring

Loaded both sides

24 B.D. 1750 .113 4.99 UE 30 106x72x49 4500 Same as Totco EVS 24.



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight






.5

Series 1 4 Fixed-15°, -18°,-19°

O.S. N.P.T. Spring

Loaded both sides

32 B.D. 1750 .113 4.99 UE 59 124.5x72x66 4900 Same as Totco EVS 32.

Hutchison-Hayes

2760-JR

1 1 Fixed-13° U.S. N.P.T. Not Spring Loaded

11.3 B.D. 1750 .139 6.1? UE 34.75 91x47x56 1800

4860-B4 1 1 Fixed-13° U.S. N.P.T. Not Spring Loaded

20 B.D. 1750 .054 2.4 UE 36-11/16 91x71x56 2600 Dual 4860-DU available.

4860-EM 1 1 Fixed-8° U.S. N.P.T. Not Spring Loaded

20 B.D. 1445 .140 4.4 UE 20-13/16 84x67x38 2100 Dual 4860-EM-DU available.

4860-Su-Sing

2 2 Fixed-13° U.S. N.P.T. Not Spring Loaded

40 B.D. 1750 .070 3.1 UE 36-11/16 91x71x56 2800 Dual 4860-SU-DU available.

101 2 2 Adjust -5° to +3°

U.S. N.P.T. Not Spring Loaded

40 B.D. 1750 .076 3.3 UE 39-5/8 95x75x54 2800 Dual 102 available; air mounts.

201-ST 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

40 B.D. 1492 .167 5.3 C 37-3/16 92x70x45 2500 Dual 202-DT avail-able; flowback pan.

Quadraflow 1 4 Fixed +6° O.S. N.P.T. Not Spring Loaded

37.7 Direct 1200 .16 3.0 L 31 128x68x56.5 4800 Not available for sale.

MTM

RLM 28 1 3 Adjust +2.5° to

5.5°


28 I. 1740 .1257 4.759 L 30 122x70x55 4500 10" flowline con-nection.

N L Bariod (Bariod sold its line of solids control equipment which is now available from Baker Hughes Treatment Services/Bird Machine Co.)

SM II 2 2 Adjust +3° to -3°


40 B.D. 1303 3/16 4.55.011

C 37 100x75x47 2600 Tandem SM II available; 10" flow-line connection.

Double Deck 2 2 Adjust +3° to -3°


48 B.D. 1424 Adjust .063--.5

Norm .25

.06311/1.8.2511/7.2.511/14.4

C 38 124x84x46 4600 Tandem Double Deck available; 10" flowline con-nection.



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight


Solids Control M

anual





.6

Petroleum Solids Control (same as Dahlory 139)

Quality Solids Separation Co.

Linear Motion Model QLM-1

1 3 Adjust +5° to -5°


26.6 I. 1750 .125-.156 3.0-5.59 L 30 115x69x54 4500 Singles & Duals available. 1500 RPM available.

Schiffner (available in Oklahoma from Spike Enterprises)

Super Sifter 1 2 Adjust 0° to +3°

N.A. P.T. 29.4 I., I. 1200 1/16-5/16 1.3-6.49 L 37 124x72x48 4200

Swaco Geolograph

Mini-Shaker 1 2 Adjust -3.5° to -7.25°

O.S. N.P.T. Spring

Loaded both sides

12 B.D. 1750 .101-.026 1.13-4.39 UE 27 112x44x38 1600 6-position vibrator.

Over/Under 2 2 Fixed 0° U.S. N.P.T. Spring

Loaded one side

40 B.D. 1492 .167 5.39 C 37-3/16 92x72x43 2500 Same as Hutchi-son-Hayes 201-ST; duals available.

Super Screen

1 2 Fixed 0°, -5°

O.S. N.P.T. Spring

Loaded both sides

32 B.D. 1140115011

.275-.313 5.1-5.89

3.311

UE 28.5 132x74x54 4800

Super Shaker

1 2 Fixed 0°, -5°

O.S. N.P.T. Spring

Loaded both sides

24 B.D. 1150 .24 4.4 UE 37.75 100x74x45 3700

Adjustable Linear Shaker

1 2 Adjust -3° to +3°


32 I., I. 1800 ? 3.711,14 L 33.56 128.75x63x58.32 5200 Vibrator angle adjustable from 25° to 65° in 10° increments.

Sweco

Single Tandem

2 2 Adjust +2° to -2°

U.S. N.P.T. Pneu-matic

40 B.D. 1460 .21 6.49

4.011

C 39.25 91.5x81.5x46.25 2950 Duals & triples available; deck hung on cables; flowback pan.

Full-Flo LM-3 1 3 Adjust 0° to +5°

O.S. N.P.T. 33.7 B.D. 1735 0-.140 Norm-.094

0-6.09

Norm-4.09

2.811

L 38 132-1/8x69x71-1/8 5000



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight






.7

OilmizerTM 1 3 Adjust 0° to +5°

N.A. P.T. 33.7 B.D. 1735 0-.140 Norm-.094

0-6.09

Norm-4.09

2.811

L 38 132-1/8x69x71-1/8 5500 P.T. Screens secured by pneu-matic seal; unit designed to achieve 10% or less oil content on cuttings.

Thompson Tool Co.

A2R 1 1 Fixed-15° O.S. N.P.T. Not Spring Loaded

8 B.D. 2000 ?10 ?10 UE 23 83x48x39 1475 Automatic sample catcher. Discontin-ued

B2 1 1 Fixed-15° O.S. N.P.T. Not Spring Loaded

8 B.D. 2000 ?10 ?10 UE 23 83x38x39 1300

A3R 1 1 Fixed-15° O.S. N.P.T. Not Spring Loaded



12 B.D. 2000 ?10 ?10 UE 26 96x49x40 1600

A54 1 1 Fixed-15° O.S. N.P.T. Not Spring Loaded



20 B.D. 2000 ?10 ?10 UE 31 96x63x48 2300

Thule Rigtech

VSM 120 2 2 AdjustTop +11 to -6.5° Btm 0° to +8°

U.S.N.A.

Top-N.P.T. Not Spring

Loaded Btm-P.T.

46 Hydraulic Variable 1000-2000

.079 Variable 1700/3.911

1800/4.411

1900/4.911

C 43.75 113-5/8x98.25x53-7/16 6845 Duals & triples available. Bottom P.T. screens secured by hydrau-lic clamps. Flow-back pan.



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight


Solids Control M

anual





.8

VSM 100 2 51

4

FixedTop-0°

Btm-0°, 15°

O.S.

N.A.

Top-N.P.T. Not Spring

LoadedBtm-P.T.

15

26

B.D. 1720 .083 3.5 L 41.8 109x74x54 4905 Duals & triples available. Bottom P.T. screens secured by pneu-matic seal. Dis-charge mud recovery module as standard.

Totco (Milchem) (Totco no longer in solids control business.)

EVS 24 1 3 Fixed-8.5°, -11.5°, -12.5°

O.S. N.P.T. Spring

Loaded both sides

24 B.D. 1750 .113 4.99 UE 30 106x72x49 4500 Dual EVS 48 units were available. Motor vibrate.

EVS 32 1 4 Fixed-15°, -18°,-19°

O.S. N.P.T. Spring

Loaded both sides

32 B.D. 1750 .113 4.99 UE 59 124.5x72x66 4900 Dual EVS 64 & Tri-ple EVS 96 units were available. Motor vibrates.

MudMaster 2 2 Fixed 0° O.S. N.P.T. Spring

Loaded both sides

40 I., I. 900 .5 5.89

3.511

L 42-1/8 81x76x39 3900 Resonance brakes.

Tri-Flo International, Inc.

TFI-126 1 2 Adjust -5° to -2°

O.S. N.P.T. Spring

Loaded both sides

12 B.D. 1750 Adjust .026-.101

1.1-4.49 UE 24 93x44x41 1420 Single only.

TFI-134 1 11 Fixed -5° O.S. N.P.T. Spring

Loaded both sides

12 B.D. 1750 Adjust .040-.134

1.7-5.89 UE 23 93x44x41 1420 Single only.

TFI-146 1 2 Fixed 0°, -5°

O.S. N.P.T. Spring

Loaded both sides

24 B.D. 1750 Adjust .057-.147

2.5-6.49 UE 30.5 98x65.5x38 2575 Duals & triples available.

TFI-148 1 3 Adjust 0° to +5°

O.S. N.P.T. Spring

Loaded both sides

32 B.D. 1750 ? ? L 18 117x80x50 4300 Singles only.



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight






.9

Triton NNF Screening Machine

1 3 Adjust -1° to +5°


27.4 I., I. 1728 .1259

.1215.19

3.7L 33 122x68x60 4960 Singles only.

NOTES:

1. All shakers end feed.

2. Negative angles mean the screen slopes downward from the feed end, and positive angles mean upward slopes. For decks with screens with different screen angles, the angles of the individual screens are given in order from the feed to the discharge end.

3. O.S. means “overslung” and U.S. means “underslung.” N.A. means “not applicable.”

4. N.P.T. means “nonpretensioned” and P.T. means “pretensioned.”

5. Larger total screen area does not necessarily mean larger fluid or solids handling capability.

6. B.D. means “belt drive,” I. means “integral,” and D.G.B.D. means “Direct Gear Box Drive.”

7. Sometimes referred to as throw. Stroke is twice amplitude and is total motion normal to the screen surface.

8. “G” = Stroke (in.) x (vibration speed per minute)2 divided by 70,400. One G = 386 in./sec2. Indicated Gs are zero to peak normal to the screen surface.

9. Indicated “G” value is per manufacturer.

10. Not available from manufacturer.

11. Measured by Amoco's Grant Young or Al Cutt, OSU’s Larry Hoberock, and/or Cagle Oilfield Services, Inc.'s Bill Cagle.

12. Type motion is either circular (C), balanced elliptical (BE), unbalanced elliptical (UE), or linear (L). “N.A.” means not applicable.

13. “L” is length, “W” is width, and “H” is height. Per manufacturer.

14. Measured at 80% of maximum eccentricity setting.

15. Advanced Technology Linear Cascading System (ATL-CS) also available. The ATL-CS incorporates a circular motion double-deck scalping shaker above a linear motion single deck shaker (ATL-1100). Deck angles for ATL-1000 & ATL-1100 are the same. Weir height = 80" Weight = 8000 lbs.

16. Note: The Retro FS Basket replaces the Tandem Basket on existing rig shakers.



Mfg.&1

Model

Numberof

Screen2

AnglesScreen3

Mfg.Screen4

Tension

Total5

Screen Area

(Sq Ft) Vibrator6

VibratorSpeed(RPM)

Stroke7

(in.)Acceleration8

GasType12

Motion

WeirHeight

(in.)

Overall13

DimensionsLxWxH

(in.)Weight


Solids Control M

anual





.10

Table E.2Oilfield Shale Shaker Classification

Coarse10-30 Mesh

Medium40-80 Mesh

Fine80-120 Mesh

Extra Fine130-325 Mesh

Brandt JuniorBrandt StandardDahlory 145Geolograph-Pioneer 24 H-100, 34 H-150, 45 H-200, & JTHarrisburg Junior & StandardHutchinson Hayes 2760-JR, 4860-B4, 4860-EM, 4860-SU-SINGSwaco Mini-ShakerThompson A2R, B2, A3R, B3, A54, B54Tri-Flo TFI-126, TFI-134

Brandt TandemDahlory 147Demco TandemGeolograph-Pioneer STHarrisburg TandemHutchison Hayes 101 & 201-STNL Bariod SM IISwaco Super ShakerSweco TandemTotco EVS 24

Brandt Retrofit FSBrandt Total Flow CleanerDerrick StandardFlo-Trend Floline Separa-torNL Bariod Double DeckOiltools Tandem 800ASwaco Super ScreenTotco EVS 32Totco MudMasterTri-Flo TFI-146

Brandt ATL1000Broadbent DT-2000Cagle Linear ScreenCagle Ultra-ScreenDahlory 139Derrick LPDerrick Flo-Line CleanerDerrick Flo-Line Cleaner (+)Derrick Flo-Line Cleaner Model 58Double like Single Tandem LinearDouble like Low Profile LinearFlo-Trend Transition Screen Separator (FTS 3600L)Flo-Trend Linear Horizontal Screen SeparatorFluid Systems High Volume Linear ShakerHarrisburg Linear Tandem RetrofitHutchison Hayes QuadraflowQuality QLM-1MTM RLM 28Schiffner Super SifterSwaco Adjustable Linear ShakerSweco Full-Flo LM-3Sweco OilmizerThule VSM 100Thule VSM 120Tri-Flo TFI-148 MTTriton NNF Screening Machine

Note: The above classifications are general and are based on design and performance. In special flow rate, plugging, and/or viscosity situations, any of the above shakers could probably run finer or coarser screens than indicated.





.11

Table E.3Oilfield Centrifugal Pumps1

a b c d e f g h i j k l m n

Mfg. & Model

Impeller Size

Range (in.)

Casing Design

Materi-als of

Constr. LubricationShaft6

Sealing

Shaft Size

Coupling End/Thru Packing

(in.)

Required Impeller Size (in.) & Horsepower for 500 gpm & 75 ft of Head for Various RPM’s

Mud Weights

CommentsImpeller Horsepower

(RPM) Size Water 10 ppg 14 ppg 18 ppg

Baker Huges Pumps 2,3,4,5

1780 Series (equivalent to Mission Type W pumps)

2500 Series (equivalent to Mission Magnum 1 pump)

3000 Series (Formerly Galigher Pumps)

5x6(5x6x11)

9-11 Circular Cast Iron,Elastomer

Lined11

Oil Bath C.P.4 1-7/8/3.0 11501750

>11”9"

N.A.18.0

N.A.21.5

N.A.30.2

N.A.38.8

Impeller locked on or threaded.Clockwise rotation only.13

6x8 (6x8x14)

11-14 Circular Cast Iron,Elastomer

Lined11

Oil Bath C.P.4 1-7/8/3.0 1150 12.25 21 25.2 35.3 45.4 Impeller locked on or threadbare on.Clockwise rotation only.13

BJ Hughes3

5"(5x6x13.5)

9-13.59 Volute Cast Iron Grease C.P. 1-13/16/1-13/16

11501750

13.59

14.015.5

16.818.6

23.526.1

30.333.5

Suction line should never be smaller than suction inlet. Discontinued manu-facturing.

6"(6x8x14.5)

10-14.59 Volute Cast Iron Grease C.P. 1-13/16/1-13/16

11501750

13.25<10"

15.5N.A.

18.6N.A.

26.1N.A.

33.5N.A.

Suction line should never be smaller than suction inlet. Discontinued manu-facturing.

Demco3,12 (Demco centrifugal pumps now available from Mattco.)

CP

5x6

(5x6x12)

8-128 Circular Cast Iron Std.11

Oil Bath C.P., M.S. 1-7/8/1-7/8 11501750

>12”8.5

N.A.16.0

N.A.19.2

N.A.26.9

N.A.34.6

6x8(6x8x12)

8-128 Circular Cast Iron Std.11

Oil Bath C.P., M.S. 1-7/8/1-7/8 11501750

12-3/89

17.024.0

20.428.8

28.640.3

36.751.9

XD4

5x6x11

8-11.5 Circular Hard Iron Std.

Oil Bath C.P., M.S. 1-7/8/2.5 11501750

>11.59

N.A.15

N.A.18.0

N.A.25.2

N.A.32.4

Clockwise rotation only.13

5x6x14 10-14 Circular Hard Iron Std.

Oil Bath C.P., M.S. 1-7/8/2.5 11501750

12.5<10"

16N.A.

19.2N.A.

26.9N.A.

34.6N.A.

Solids Control M

anual





.12


Oil Bath C.P., M.S. 1-7/8/2.5 11501750

<11"9.25

N.A.16.5

N.A.19.38

N.A.27.7

N.A.35.7


Oil Bath C.P., M.S. 1-7/8/2.5 11501750

12.75<10"

18.0N.A.

21.6N.A.

30.3N.A.

38.9N.A.

Gorman-Rupp2,3

ID Series

1.5"-6” pumps

4-7/8-11.25

Volute Cast Iron Grease, oil Grease-lubr. seal

w/spring-loaded

grease cup

Variable Flow rates up to 3500 gpm: Heads up to 180 ft. Trash pumps. Inspect impeller thru removable coverplate without removing piping. Self-priming. Handle 1"-3” size solids depending on model. Available with air cooled gasoline or diesel engines. Pumps mounted on pneumatic tires or skid base.

80 Series1.5"-12”,

40 Models

5-18 Volute Cast Iron Grease, oil Grease-lubr. seal

w/spring-loaded

grease cup

Variable Flow rates up to 7000 gpm: Heads up to 200 ft. Designed for dirty water & limited sol-ids-handling appl. Self-priming. Avail. with air cooled or water cooled gasoline or diesel engines. Pumps mounted on pneumatic tires or skid base.

Mud Pumps4

6x5x118-11 Circular Cast Iron

Casing w/Ductile

Iron Impel-ler

Grease, oil C.P., M.S. 1-7/8/2.157 11501750

>119"

N.A.17.0

N.A.20.4

N.A.28.6

N.A.36.7

Harrisburg3,9

178

5x6

(5x6x12)

9-12 Circular Cast Iron, Ductile Iron, or Alum.

Bronze

Oil Bath C.P., M.S. 1-7/8/1-7/8 11501750

>128.5

N.A.16.3

N.A.19.6

N.A.27.4

N.A.35.2

6x8 9-13.25 Circular Cast Iron, Ductile Iron, or Alum.

Bronze

Oil Bath C.P., M.S. 1-7/8/1-7/8 11501750

12.5<9

17.5N.A.

21.0N.A.

29.4N.A.

37.8N.A.

Table E.3 (Continued)Oilfield Centrifugal Pumps1


Mfg. & Model

Impeller Size

Range (in.)

Casing Design

Materi-als of


Sealing

Shaft Size


(in.)


Mud Weights







.13

Honcho 2505x6

10-14 Circular Ductile Iron Oil, grease C.P., M.S. 1-7/8/2.5 11501750

12.5<10

17.8N.A.

21.4N.A.

29.9N.A.

38.5N.A.

Impeller locking system.

6x8 10-14 Circular Ductile Iron Oil, grease C.P., M.S. 1-7/8/2.5 11501750

13.510.5

22.929.0

27.534.8

38.548.7

49.562.7

Impeller locking system. Extra Life Pack-age available for abrasive service.

MCM4,7,12

178 Series3

5x6(5x6x12)

8-127 Circular Cast Iron, Hard Iron11

Oil Bath C.P., M.S. 1-7/8/1-7/8 11501750

>128.5

N.A.16.0

N.A.19.2

N.A.26.9

N.A.34.6

All impellers made of ductile iron.

6x8(6x8x13)

9-13.257 Circular Cast Iron, Hard Iron11

Oil Bath C.P., M.S. 1-7/8/1-7/8 11501750

12.59

17.024.0

20.428.38

28.640.3

36.751.9

All impellers made of ductile iron.

250 Series4

5x6x118-11.58-11.0

Circular Ductile Iron Oil Bath C.P., M.S. 1-7/8/2.5 11501750

>11.59

N.A.15.0

N.A.18.0

N.A.25.2

N.A.32.4

All 250 Series impellers are open design and right hand rotation only.

5x6x14 10-14 Circular Ductile Iron Oil Bath C.P., M.S. 1-7/8/2.5 11501750

12.5<10

15.1N.A.

18.1N.A.

25.4N.A.

32.6N.A.

6x8x11 8-11 Circular Ductile Iron Oil Bath C.P., M.S. 1-7/8/2.5 11501750

>119.25

N.A.17.0

N.A.20.4

N.A.28.6

N.A.36.7

6x8x14 10-14.12510-14

Circular Ductile Iron Oil Bath C.P., M.S. 1-7/8/2.5 11501750

12.75<10

18.0N.A.

21.6N.A.

30.3N.A.

38.9N.A.

Mission - Fluid King Oilfield Products

Type W3,4,7,12

5x6 R&C138-127 Circular Cast Iron11 Grease C.P. 1-7/8/1-7/8 1150

1750>129.5

N.A.16.9

N.A.20.3

N.A.28.4

N.A.36.5

6x8 R13 9-13.257 Circular Cast Iron11 Grease C.P. 1-7/8/1-7/8 11501750

12-3/89

17.124.0

20.5 28.7 37.0

Magnum 13,4,7

6x5x11

11-14 Circular Cast Iron11 Grease, oil C.P., M.S. 1-7/8/2.5 11501750

>11.59.0

N.A.15.0

N.A.18.0

N.A.25.2

N.A.32.4

Clockwise rotation only.

6x5x14 10-14 Circular Cast Iron11 Grease, oil C.P., M.S. 1-7/8/2.5 11501750

12.5<10

15.6N.A. N.A. N.A. N.A.



Mfg. & Model

Impeller Size

Range (in.)

Casing Design

Materi-als of


Sealing

Shaft Size


(in.)


Mud Weights



Solids Control M

anual





.14


<119.25

N.A.16.7

N.A.20.0

N.A.28.1

N.A.36.1

8x6x14 10--14-1/8 Circular Cast Iron11 Grease, oil C.P., M.S. 1-7/8/2.5 11501750

13-1/810

20.726.0

24.831.2

34.843.7

44.756.2


14<12

26.4N.A.

31.7N.A.

44.4N.A.

57.0N.A.

Thompson Tool Co.3,4,7,12

Type F Packless

5x6 R&C138.5-10.5 Circular Hard Iron

Std.Grease Packless 1.75/N.A.10 1750 8.5 16.4 19.7 27.6 35.4 Type FS Packless self-priming pumps

also available in 5" and 6" sizes.

6x6 R&C13 8.5-10.5 Circular Hard Iron Std.

Grease Packless 1.75/N.A.10 ? ? ? ? ? ?

A. R. Wilfley & Sons, Inc.4,11

ES6x4 13

2" diam range

Volute Hard Iron Std.

Oil Bath N.A.10 2.12/N.A.10 11501750

13" gives 82' TDH and requires 17 HP13" gives 196' TDH and requires 52 HP

Packingless design; available in a variety of metals and elastomers. Closed impel-ler design.

8x6 172" diam range

Volute Hard Iron Std.

Oil Bath N.A.10 2.38/N.A.10 11501750

Packingless design; available in a variety of metals and elastomers. Closed impel-ler design.

Note: Wilfley impellers are too hard to be turned down as many other manufacturer's impellers can be.



Mfg. & Model

Impeller Size

Range (in.)

Casing Design

Materi-als of


Sealing

Shaft Size


(in.)


Mud Weights







.15

NOTES:1. All horizontal-type mounted on pedestal or frame except as indicated.2. Vertical centrifugal pumps available.3. All impellers of semi-open design.4. Impeller has expeller vanes on back side.5. Pumps are elastomer lined.6. C.P. means “conventional packing”; M.S. means “mechanical seal.”7. Cutdown impellers available in 1/8” increments.8. Cutdown impellers available in 1/4” increments.9. Cutdown impellers available in 1/2” increments.

10. N.A. means “not applicable.”11. Also available in more wear-resistant metals.12. Available in both clockwise and counterclockwise rotation.13. R means “clockwise rotation from drive end” and C means “counterclockwise rotation from drive end.”



Mfg. & Model

Impeller Size

Range (in.)

Casing Design

Materi-als of


Sealing

Shaft Size


(in.)


Mud Weights



Solids Control M

anual





.16

Table E.4Oilfield Degassers

a b c d

Mfg. & Model Type1

Nominal2,3

FlowRate

(gpm)

Vacuum5

Range(in. Hg)

Overall Dimensions

LxWxH(in.)

Weight (lbs) Comments

Brandt

DG-54 Vacuum emptied by jet pump.

500 7-20max 29

88x54x62 2390 Mud flows over four stacked conical baffles (9956 in2 area). Jet pump requires 75 ft feed head. All units must be started up before gas cut mud appears to prevent gas locking.

DG-104 Vacuum emptied by jet pump.

1000 7-20 100x60x77 3900 Mud flows over seven stacked conical baffles (32060 in2 area). Jet pump requires 75 ft feed head.

Burgess & Associates Mfg., Inc.

Magna-Vac 500 Vacuum emptied by self-contained centrifugal pump.

500 10" 39" diam x 64" ht 1000 All units self-contained. All models designed to set down in mud tank. All models designed to allow easy passage of lost circulation materials. All units designed to break down into two pieces for portability. All models have vacuum created by regenerative vacuum blower. All units have positive gas discharge. Gas separated by vacuum and turbulence. All units must have suction and discharge submerged to start up. All units run noisy at approximately 85 db, and ear protection should be worn if working near for extended periods. 20 HP motor.


1000 10" 44" diam x 73" ht 1475 20 HP motor. Portable unit breaks down into two pieces weighing 875 and 600 lbs respectively.

Magna-Vac 1000 H

Vacuum emptied by self-contained centrifugal pump.

1000 10" 44" diam x 58" ht 875 20 HP hydraulic motor. Portable.


1000 15" 44" diam x 73" ht 1675 20 HP drive motor and 5 HP vacuum booster. Portable.

Demco (Discontinued Solids Control Product Line - Model 600 degasser taken off market in early 1980's.)

Derrick Equipment Co.

Vacu-Flo 5004 Vacuum emptied by jet. 500 7-20max 29

93.75x59.5x60 2900 Mud flows over four stacked conical corrugated baffles. Jet pump requires 75 ft feed head. Unit must be started before gas cut mud appears to prevent gas lock-ing. Except for top outlet, bolt-on access door, and corrugated baffles, the Vacu-Flo 500 is a copy of the Brandt DG-5.





.17

Vacu-Flo 10004 Vacuum emptied by jet. 1000 7-20max 29

100x60x77 3900 Mud flows over seven stacked conical baffles. Jet pump requires 75 ft feed head. Unit must be started before gas cut mud appears to prevent gas locking. Except for top outlet, bolt-on access door, and corrugated baffles, the Vacu-Flo 1000 is a copy of the Brandt DG-10.

Table E.4 (Continued)Oilfield Degassers

a b c d

Mfg. & Model Type1

Nominal2,3

FlowRate

(gpm)

Vacuum5

Range(in. Hg)

Overall Dimensions

LxWxH(in.)


Solids Control M

anual





.18

Flo-Trend Systems, Inc. (Discontinued marketing Centri-Vac Ft-600 and FT-1000 degassers.)

Geolograph Pioneer (Geolograph Pioneer now merged with Swaco Geolograph who advised 4/24/91 that Pioneer Solids Control equipment still available. See Swaco-Geolograph for information about the Geolograph Pioneer Hurricane CD-800 and CD-1400 degassers.)

Hutchison-Hayes Intl, Inc. (Discontinued marketing Rhumba Vac-Degasser about 1986.

Smith International (Drilco)

See-Flo Stan-dard Pit

Atmospheric filled by pat-ented centrifugal pump.

700 None 69x44x90.5 1000 All units set down in the mud tank. All units separate gas by turbulence and impact. Gas disposal vent system (optional) available. Standard and Deep Pit models are portable. 7.5 HP motor.

See-Flo Deep Pit Atmospheric filled by pat-ented centrifugal pump.

700 None 69x44x114.5 1200 10 HP motor.

See-Flo Big Vol-ume

(Discontinued this model during early 1980's) 2000 30 HP motor.

Swaco

D-Gasser Horizontal4

Vacuum emptied by jet pump.

1200 8-15 157x42x89 3350 Gas separated as mud flows over flat plates under vacuum. Jet pump requires 75-160 feet feed head. TOGA (Total Gas) H2S Containment System available which consists of a Swaco H2S Mud-Gas Separator working in series with a Swaco D-Gasser. Unit must be started up before gas cut mud appears to prevent gas locking.

D-Gasser Vertical4


1200 8-15 60x42x146 2950 Vertical unit consists of several cascading baffle plates and only recommended for applications with limited space. Not as efficient as horizontal unit. Unit must be started up before gas cut mud appears to prevent gas locking.

Hurricane CD-800

Atmospheric filled by centrif-ugal pump action.

800 w/water

none 42.5x37.5x103 1650 All Hurricane units designed to set down in the mud tank. Uses centrifugal force to pump the fluid and to separate the gas. Used to deaerate muds that inherently tend to foam. All Hurricane units originally developed by Geolograph Pioneer. All units compact and can be broken down for easy transport.15 HP motor.

Hurricane CD-1400

Atmospheric filled by centrif-ugal pump action.

1400 w/water

none 57.5x46.5x104 2400 25 HP motor.

Sweco


a b c d

Mfg. & Model Type1

Nominal2,3

FlowRate

(gpm)

Vacuum5

Range(in. Hg)

Overall Dimensions

LxWxH(in.)






.19

DG-2 Vacuum emptied by centrif-ugal pump.

800 9-14 77x49x86 2400 Self-contained unit must set beside mud tank. Vacuum pump creates vacuum in the chamber. Gas separated by combination of centrifugal force, turbulence, and vacuum. No auxiliary pump required. Vacuum adjusted with a regulator valve. 15 HP motor.

Note: Sweco at one time marketed DG-3 and DG-4 degassers but has discontinued these two units and now only markets the DG-2.

VG-1 Vacuum emptied by jet pump.

1000 8-15 144x42x60 2200 Gas separated as mud flows over flat plates under vacuum. Unit must be started up before gas cut mud appears to prevent gas locking. Unit much like Swaco Hori-zontal D-Gasser except vessel is slightly larger in diameter and vacuum pump and motor both located on the skid.

Thule Rigtech (Thule markets the Burgess Degasser.)

Tillett Tool Co.

Gas Hog Atmospheric filled by impel-ler pump.

800-1000800 opti-

mum

<2 42x42x125 or 150 1200&

1250

Unit sets down in tank. Mud pumped into chamber where a spinning disk deflects the mud radially toward the wall over three sets of baffles. Gas separated by impact and turbulence and removed by vacuum blower. Optional blower available if gas is to be vented more than 200 ft away.

Totco (Discontinued Solids Control product Line.)

TSC-500 A4 Vacuum emptied by jet pump fed by self-priming centrifugal pump.

500 w/water

10-2627 max

76x72x72 2200 Unit has microprocessor which monitors oil pressure inside the vacuum pump, liq-uid level inside the suction air scrubber and the load condition on both the vacuum pump and the centrifugal pump motor. If any of these conditions exceed preset lim-its, the unit shuts down and indicates where the problem is on the control panel. Gas separated by turbulence, flow as thin sheet over baffles, and vacuum. Unit must be started up before gas out mud appears to prevent gas locking.

Note: Totco at one time marketed Milchem's AV vacuum degasser but discontinued the AV in favor of the TSC-500 A.

Tri-Flo

Compact 800 Degasser4


600 Max 13 48x48x95 2600 Gas separated by vacuum over baffle plates. Gas being separated used to equal-ize the vacuum rather than air as with other manufacturer's units. All units must be started up before gas cut mud appears to prevent gas locking.

Horizontal Degasser4


1200 Max 13 171x43x72 3900 Gas separated by vacuum over angled baffle plates.

Well Control


a b c d

Mfg. & Model Type1

Nominal2,3

FlowRate

(gpm)

Vacuum5

Range(in. Hg)

Overall Dimensions

LxWxH(in.)


Solids Control M

anual





.20

82004 Vacuum emptied by jet pump.

450 8-12 96x36x62 1500 No vacuum pump. Like Model 5200 uses a dual ejector venturi and jet pump with a 1.939" nozzle and a cyclone separator. Jet pump requires 10 to 35 psi. Gas sepa-rated over cone and inverted cone reversing flow baffles. Unit must be started before gas cut mud appears to prevent gas locking.


850 8-12 168x48x76 2600 No vacuum pump. Like Model 5200 uses a dual ejector venturi and jet pump with a 1.939" nozzle and a cyclone separator. Jet pump requires 10 to 35 psi. Gas sepa-rated over cone and inverted cone reversing flow baffles. Unit must be started before gas cut mud appears to prevent gas locking.

3200 Vacuum emptied by self-priming centrifugal pump.

1100 8-12 91x60x92 6000 Self-contained unit with vacuum pump for drawing mud into the vessel and a self-priming centrifugal pump to remove mud from the vessel. Gas separated under vacuum over a series of conical shaped baffles. A 60-75 HP motor used on self-priming centrifugal pump.


1100 8-12 156x60x72 3500 No vacuum pump. Uses a dual ejector venturi jet pump to draw mud into the unit by vacuum and to discharge the mud from the vessel. Gas separated under vac-uum over four stacked conical baffles (9328 in2). Mud and gas mixture discharged by ejector through a cyclone separator which separates the gas out top and mud out bottom to active mud pit. Mud return line should extend down to one ft. above bottom of mud tank. Jet pump requires 35 to 55 psi. Uses a 1.939" jet pump noz-zle. Unit must be started up before gas cut mud appears to prevent gas locking.

NOTES:

1. Degassers are classified as either atmospheric or vacuum. To be classified as a vacuum degasser, a unit must maintain a continuous 5 in. of mercury vacuum.

2. Nominal flow rates given are for water. Flow rates for viscous muds are less. Flow rates for heavy, viscous gas cut muds are much less.

3. Values given are per manufacturer.

4. All vacuum units using jet pumps to discharge the mud must be started up before the gas cut mud appears to prevent gas locking.

5. The level of vacuum attained is a function of mud weight, mud viscosity, the height of the degasser above the mud surface, and the capability of the vacuum pump.


a b c d

Mfg. & Model Type1

Nominal2,3

FlowRate

(gpm)

Vacuum5

Range(in. Hg)

Overall Dimensions

LxWxH(in.)






.21

Table E.5Oilfield Hydrocyclones1

a b c d e f g

Mfg. &1

Model

ConeDiam.(in.) Inlet Type Cone Construction Underflow Adjustment

Flow Rate5 at

Rec. Head

(gpm,ft) Special Features/Comments

Bailey-Parks Urethane, Inc. (Bailey-Parks builds cones for various oilfield solids control companies.)

2.5" 2.375 Rectangular Tangent Ramp Polyurethane4 Fixed .125 & cutoff to .75" 6,45 1.25" Victaulics on inlet and overflow, 3-piece cone

4" 4.0 Rectangular Tangent Ramp Polyurethane4 Adjust .125 to .50" 50,75 2" Victaulics on inlet and overflow, 2-piece cone

5" 5.0 Circular Tangent Polyurethane4 Adjust .25 to .75" 80,75 2" Victaulics on inlet and overflow, 2-piece cone

5" 5.0 Circular Tangent Polyurethane4 Adjust .25 to .75" 80,75 2" Flange on inlet; 2" Victaulic on overflow, 2-piece cone

10" 10.125 Rectangular Involute Polyurethane4 Adjust .75 to 1.25" 500,75 5" Victaulics on inlet and overflow, 3-piece coneBaker Hughes Pumps 3" (same as MPE 3" 50 gpm cone with rectangular tangent entry)

4" 4.07 Circular Tangent Polyurethane Adjust .125 to .625" 50,32-38 psi

Ceramic insert in apex area for wear resistance, victaulics on inlet and overflow, 2-piece cone

5" 5.07 Circular Tangent Polyurethane Adjust .125 to .625" 80,32-38 psi

Ceramic insert in apex area on inlet and victaulic on overflow, either flanged or victaulic, 2-piece cone

10" 9.95 Rectangular Tangent Polyurethane Fixed 1, 1.25, 1.75" 500, 32-38 psi

5" Victaulics on inlet and overflow, fixed apex acts as wear inserts, available with ceramic insert

Baker-Hughes Treatment Systems, Inc. (see NL Baroid)Baroid (see NL Baroid)Bird Machine Co. (see NL Baroid)C. E. Bauer (Bauer manufactures a wide variety of cones of common and exotic materials for a wide variety of industrial users and has supplied cones to the oilfield.)

3"(600-3) 3 Circular Tangent Nylon Fixed .125 and cut off to .75" 20,922 17 gpm at 75 ft head2 Threaded

6"(606-110) 6 Circular Tangent Nylon Fixed .25 and cut off to 1.125" 110,802 108 gpm at 75 ft head2 Victaulics

12"(623-4) 12 Circular Tangent Stainless Steel Fixed 1.0 and cut off to 2.75" 650,1152 400 gpm at 75 ft head2 Victaulics or Flanges


2" ? ? Polyurethane? Fixed? 20,75?2-piece cone, victaulics on feed and overflow, ceramic insert molded into apex, manifolds avail-able with 4-24 cones

4" 3.9 Rectangular Involute Polyurethane? Adjust .125 to .69" 66,7522-piece cone, victaulics on feed and overflow, manifolds available with 1, 2, or 3 cones in either vertical or slant mounting

Solids Control M

anual





.22

12" 12.2 Circular Involute Polyurethane? Fixed 1.5, 1.75, 2.125" 492,7523-piece cone, victaulics on feed and overflow, manifolds available with 1, 2, or 3 cones in either vertical or slant mounting

Dahlory, Inc.

4" 3.9 Rectangular Tangent Polyurethane Adjustable .25 to .625" 55,75 Manifolds available with 2-20 4" cones,Victaulics on feed and overflow, 2-piece cone

10" 10.25 Rectangular Tangent Polyurethane Adjustable .5 to 1.75" 500,75 Manifolds available with 1, 2, or 3 10" cones,Victaulics on feed and overflows, 3-piece cone

Demco (Discontinued Solids Control Product Line; see RETSCO for available Demco cones.)Derrick Equipment Co.

2" 2 Circular Tangent Polyurethane4 Adjust .25 to .50" 15,75All Derrick 2", 3", and 4" cones are designed to fit the same manifold. 2“ valves are standard on all circular manifolds optional for all in-line manifolds.

3" (same as MPE 3" 50 gpm cone with rectangular tangent entry)

4" 3.813 Circular Tangent Ramp Polyurethane4 Adjust .25 to .56" 50,75

Polykineticurethane bottom liner, screws together, 2-piece cone, in-line or circular manifolds avail-able, 2" valves on inlets, victaulics on inlet and overflow, manifolds available with 6-204" cones

DFE/Solids Control (see NL Baroid)Drilco (see Smith International)Flo Trend Systems, Inc. 2" (same as Bailey Parks 2.5"; see Bailey Parks) 3" (same as Hydro-Separation Systems, Inc. 3" 50 gpm cone with rectangular tangent entry)

4" 4 Rectangular Tangent Ramp Polyurethane4 Adjust 0 to .625" 62,752 Victaulics on feed and overflow, 2-piece cone,

manifolds available with 4-20 4" cones

5" 4.9 Rectangular Tangent Ramp Polyurethane4 Adjust 0 to .625"

0 to .750" 102,752 Flange on inlet and victaulic on overflow, 2-piece cone; manifolds available with 4-20 5" cones

Geolograph-Pioneer (has merged with Swaco; see Swaco)Harrisburg

4" 3.875 Circular Tangent Polyurethane4 Adjust 0 to .75" 50,75 Manifolds available with 8-24 cones, victaulics on feed and overflow, 2-piece cone

5" 4.875 Circular Tangent Polyurethane4 Adjust 0 to .75" 80,75 Manifolds available with 8-20 cones, flange on inlet and victaulic on overflow, 2-piece cone

Table E.5 (Continued)Oilfield Hydrocyclones1

a b c d e f g

Mfg. &1

Model


Flow Rate5 at

Rec. Head






.23

10" 10.0 Rectangular Involute Polyurethane4 Adjust 0 to 1.5" 500,75

Manifolds available with 1-3 cones slant mounted and 1-2 cones vertically mounted, victaulics on inlet and overflow,3-piece cone

Hutchinson Hayes International, Inc.

5" 4.77 Circular Tangent Polyurethane Adjust .25 to .5" 80,75 Manifolds available with 4-16 cones, flange on inlet and victaulic on overflow, 2-piece cone

10" 10.2 Rectangular Involute Polyurethane Fixed 1, 1.25, 1.50" 500,75 Manifolds available with 1-4 cones, victaulics on inlet and overflow, 3-piece cone

Hydro-Separation Systems, Inc. (Now MPE)

1" 1.0 Rectangular Tangent Polyurethane4 Fixed .080" 5,75All cones designed and developed by Amoco's Grant Young, brass snap-locks on inlets and over-flows, 2-piece cone

3" 3.0 Rectangular Tangent Polyurethane4 Fixed .24, .30, .40, .50, .60" 32,75

All 3" cones made to fit several other manufactur-ers' 4" cone manifolds, all 3" have victaulics on inlets and overflows, 2-piece cone

3" 3.0 Rectangular Tangent Polyurethane4 Fixed .24, .30, .40, .50, .60" 50,75 2-piece cone

3" 3.0 Rectangular Involute Polyurethane4 Fixed .24, .30, .40, .50, .60" 50,75 Fits Brandt 4" cone manifolds, 2-piece cone

Krebs Engineers

U4” 3.9 Rectangular Involute Polyurethane4Adjust 3.75 to 1.063"Fixed .375 and cut off to 1.5"

86,752

Victaulic connections on inlet, and overflow. Replaceable, fixed and adjustable apexes in vari-ous sizes. Replaceable vortex finders in various sizes.

U4B” 3.9 Rectangular Involute Polyurethane4 Same as U4” 91,752 Same as abovePU6” 6.0 Rectangular Involute Polyurethane4 Same as U4” 180,752 Same as above

TU10” 3.25" vortex6.3 in2 inlet 10.0 Rectangular Involute Polyurethane4

Adjust .375 to 3.0"Fixed .5 to 2.0"Fixed ceramic .5 to 3.0"

390,752Victaulic connections on inlet, and overflow. Replaceable, fixed and adjustable apexes in vari-ous sizes. Ceramic apexes also available.

TU10” 4" vortex9.52 in2 inlet 10.0 Rectangular Involute Polyurethane4 Same as TU10” above 600,752 Same as above

Morganite Canada, Inc. (formerly Permathane; now see Wren Sales (92) Ltd.)NL Bariod (Baroid sold its line of solids control equipment to DFE/Solids control who sold to Reserve Pits Inc., who sold to Baker Hughes Treatment Services; Baroid solids control equipment now available from Baker Hughes Treatment Services/Bird Machine Co.)

5" 4.7 Circular Tangent Polyurethane? Adjust 0 to .7" 83,75 Victaulics on inlet and overflow, 2-piece cone man-ifolds available with 6, 8, m 12, or 16 5" cones


a b c d e f g

Mfg. &1

Model


Flow Rate5 at

Rec. Head


Solids Control M

anual





.24

10" 10.1 Rectangular Involute Polyurethane? ? to 1.3 500,75Victaulics on inlet and overflow, 3-piece cone man-ifolds available with 1, 2, 3, or 4 10" slant-mounted cones

Ohio Rubber (Discontinued oilfield hydrocyclone line and sold cone molds to various other companies; see MPE.)Oiltools

4" 4.0 Circular Tangent Polyurethane Fixed .37, .51, .59, .67, .75" 50,75

Victaulics on inlet and overflow, polyurethane will withstand 185°F, 3-piece cone, manifolds available with 3-16 or more cones

10" 10.0 Rectangular Tangent Polyurethane Fixed .75, 1.0, 1.25, 1.5, 1.75" 500,75

Victaulics on inlet and overflow, polyurethane will withstand 185°F, 3-piece cone, manifolds available with 1-3 cones

Permathane Ind. (see Wren Sales (92) Ltd.)Quality Solids Separation Co.

4" Model 240 3.813 Rectangular Tangent

Polyurethane top sec-tion & aluminum alloy body with polyure-thane liner

Adjust .25 to .625" 50,75

Retrofit the Pioneer Siltmaster 4" and Economas-ter 4" cones and Sweco 4" cone, manifolds avail-able with 4-24 4" cones, victaulics on inlet and overflow

6" Model 260 6.0 Rectangular Tangent

Polyurethane top sec-tion with aluminum alloy body with polyure-thane liner

Adjust .5 to 1.0" 100,75Retrofit the Pioneer Sandmaster 6" or Economas-ter 6" cones, manifolds available with 3-12 6" cones, victaulics on inlet and overflow

12" Model 212 12.0 Circular Tangent

Aluminum housing with aluminum bronze cone top and feed nip-ple, cone liner and vor-tex finder made of hycar rubber, apex lined with polyurethane

Fixed 1.75, 2.0, 2.25" 500,75Retrofits the Pioneer 12" Volumemaster cone, manifolds available with 1-4 12" cones, victaulics on inlet and overflow

RETSCO (formerly Demco hydrocyclone line)

2" 2.25 Circular Tangent Cast Iron .3, .18" 20,75 Flanged inlet and overflow, buna or urethane cone liners available

3" 3.1 Circular Tangent Cast Iron .44, .3, .2" 27,75 Flanged inlet and overflow, urethane liner

4" 4.0 Circular Tangent Cast Iron .55, .44, .3, .2" 42,75 Flanged inlet and victaulic on overflow, manifolds available with 2-24 cones

4H 4.87 Circular Tangent Polyurethane4 .69, .44, .3, .2" 76,752Flanged inlet, victaulic on overflow, orifice control plate. Also available in ductile iron. Manifolds avail-able with 2-24 cones


a b c d e f g

Mfg. &1

Model


Flow Rate5 at

Rec. Head






.25

8" 6.95 Circular Tangent Cast Iron .73, .44, .3, .2" 156,75Flanged inlets, overflow manifolds available with 1-8 cones, available in either vertical or inclined mounting

10" 10.2 Rectangular Involute Polyurethane4 1.5" Fixed 640,75 3-piece cone with victaulics on inlet and overflow manifolds available with 1-4 cones

12" 12.81 Circular Tangent Cast Iron Adjustable Valve 400,75 Orifice control valve, manifolds available with 1-4 cones in either vertical or inclined mounting

Schiffner (some Schiffner 2" and 4" cones available in US from Spike Enterprises)Smith InternationalDrilco Division (Discontinued cyclone product line.)Swaco Geolograph

2" Microclone 1.9750 mm Rectangular Tangent Ceramic Fixed .25"

Bit Nozzle 25,125 20-cone manifolds

2" Microclone 2.3 Rectangular Tangent Polyurethane4 Fixed .5" 25,125 Ceramic liner in apex, 20-cone manifolds

4" Twin Cone 4.04Double Rectangular Tangent Polyurethane4 Fixed .375 (most common)

.5, .625" 69,91263 gpm at 75 ft feed head2, manifolds available with 8-204" cones

12" 12.1 Circular Tangent Polyurethane4Fixed .5, .75 (most com-mon)1.25, 1.5"

500,75 Manifolds available with 1, 2, or 3 cones in either vertical or slant mounting, 4-piece cone

Cones formerly available from Geolograph Pioneer

3" Solidsmaster Cast Iron 22,75All cones have victaulics on inlet and overflow, all Economaster cones have an aluminum bottom with a replaceable polyurethane liner

3" Economaster 3.0 Square Tangent Polyurethane4 22,75

4" Siltmaster 3.75 Circular Tangent Cast Iron Adjust .25 to .625" 48,752 Manifolds available with 4-24 4" cones, 2-piece cone

4" Economaster 3.75 Circular Tangent Polyurethane4 Adjust .25 to .625" 48,752 Manifolds available with 4-24 4" cones, 2-piece cone

4" HV Economaster 3.75 Rectangular Tangent Ramp Polyurethane4 Adjust .25 to .75" 80,75

6" Sandmaster 6 Circular Tangent Cast Iron Adjust .5 to 1.0" 100,75 Manifolds available with 3-12 6" cones, 2-piece cone

6" Economaster 6 Rectangular Tangent Polyurethane4 Adjust up 1.0" 100,75 Manifolds available with 3-12 6" cones, 2-piece cone

12" Volumemaster 12.0 Circular Tangent Cast Iron Fixed 1.75, 2.0, 2.25" 500,75 Manifolds available with 1-4 cones, 3-piece cone12" Economaster 11.75 Rectangular Tangent Polyurethane4 top Adjustable .75 to 2.25" 500,75 Manifolds available with 1-4 cones, 3-piece cone


a b c d e f g

Mfg. &1

Model


Flow Rate5 at

Rec. Head


Solids Control M

anual





.26

Sweco

4" 3.785 Circular Tangent Polyurethane4 Adjust 0 to .620" 52,752 Manifolds available with 8-20 cones, 2-piece cone, victaulics on inlet and overflow

5" 4.875 Circular Tangent Polyurethane4 Adjust 0 to .685" 80,7578 gpm at 60 ft feed head2, manifolds available with 23 or 16 cones, flange on inlet and victaulic on overflow, 2-piece cone

10" 10.0 Rectangular Volute Polyurethane4 Variable to 1.5" 500,75

506 gpm at 60 ft feed head2, manifolds available with 1-3 vertically-mounted cones and with 2-3 slant-mounted cones, victaulics on inlet and over-flow, 3-piece cone

Thompson Tool Co.

4" 4.25 Circular Tangent Cast Iron w/liner Automatic Adjust 0 to .625" 50 psi

40 gpm at 60 ft feed head2. Circular manifold, flanges on 45 gpm at 75 ft feed head2 inlet and overflow, manifolds 50 gpm at 90 ft feed head2 available with 4-12 4" cones

8" 7.75 Circular Tangent Cast Iron w/liner Automatic Adjust 0 to 1.25" 35-40 psi

176 gpm at 60 ft head2 Circular manifold, flanges on 187 gpm at 75 ft head2 inlet and overflow, man-ifolds 196 gpm at 90 ft head2 with 1-4 8" cones

Thule Rigtech4" PH4/LV ? ? Polyurethane? Adjust? 50,75 Victaulics on inlet and overflow, 2-piece cone4" PH4/HV ? ? Polyurethane? Adjust? 80,75 Victaulics on inlet and overflow, 2-piece coneTotco (No longer in solids control business)Tri-Flo International, Inc.

2" 2.0 Rectangular Tangent Polyurethane4 Fixed .188" 15,81

Victaulics on inlet and overflow, cutoff valves on inlets, individual overflows with patented control rod which acts as adjustable vacuum breaker for varying the wetness of the solids discharge, unit available with 20-2” cones

4" 4.0 Rectangular Tangent Polyurethane4 Adjust 0 to .5" 60,58

Victaulics on inlet and overflow, cutoff valves on inlets, individual overflows with patented control rod which acts as adjustable vacuum breaker for varying the wetness of the solids discharge, units available with 8, 12, and 16-4” cones

Wren Sales (92) Ltd. (Cones originally available from Permathane and then subsequently Morganite Canada, Inc.)

2" 2.35 Circular Tangential Ramp Polyurethane4 Fixed .2 to .375" 16,65-70 Victaulics on inlet and overflow, 3-piece cone, 17 gpm at 75 ft feed head2

4" 4.06 Circular Tangential Ramp Polyurethane4 Adjust 0 to .625" 39,75 Victaulics on inlet and overflows, 2 and 3-piece cones available


a b c d e f g

Mfg. &1

Model


Flow Rate5 at

Rec. Head






.27

5" 5.00 Circular Tangential Ramp Polyurethane4 Adjust 0 to .625" 86,902 Victaulics on inlet and overflows, 3-piece cone, 78 gpm at 75 ft feed head2

10" 10.25 Rectangular Volute Ramp Polyurethane4 Adjust .5 to 1.5" 585,75 Victaulics on inlet and overflow, 3-piece cone

NOTES:1. Original Table compiled by Amoco’s Grant Young.2. Value given is per Amoco’s Grant Young.3. Value given is manufacturer’s recommended feed head.4. Polyurethane is moca-cured type which has a higher temperature stability which is needed for mud temperatures in the 175-200 F range.5. Value given is per Manufacturer except as otherwise noted.


a b c d e f g

Mfg. &1

Model


Flow Rate5 at

Rec. Head


Solids Control M

anual





.28

Table E.6Oilfield Mud Cleaners

a b c d e f g h i j k l m n o

Mfg. & Model Manifold1 No.Size2 (in.)

Rec. Head

(ft)Capacity

(gpm)Number of

Decks Screens Screen3 AnglesScreen4

Mtg. Screen5 TensionTotal Area

(sq. ft)Screen

Vibrator6Speed (rpm) Comments


Mud Cleaner 1 8 4” PU 75 400 1 1 Fixed 0° N.A. P.T. 45x52”=16.25

B.D. 1356 Reflux line, feed gauge, siphon breaker stan-dard. Self-cleaning slid-ers standard.

Chronaloy (No longer available)

Mud Cleaner R 8 4" PU 80 8(87)=696 12

12

Fixed-5°Fixed-5°

N.A.N.A.

P.T.P.T.

1632

I.I.

1800/36001800/3600

Individual cone overflows each with siphon breaker, Krebs cones. Rotex shaker. Victaulic connections on all cones.

Demco Siltrite (now available from RETSCO)

4MC6 I 6 4"H C.I.

90-100 480_14 ppg240 14-18 ppg

1 1 0-10°Adjust 0 to -10°

O.S. N.P.T. Spring Loaded

11 B.D. 1400 Cone inlets flanged, Vic-taulics on overflow, see units available with either metal or urethane cones.

4MC8 I 8 4"H C.I.

90-100 600 14 ppg300 14018 ppg

1 1 Adjust 0 to -10° O.S. N.P.T. Spring Loaded

11 B.D. 1400 Cone inlets flanged.

4MC10 I 10 4"H C.I.

90-100 800 14 ppg400 14-18 ppg


16.5 B.D. 1400 Cone inlets flanged.

4MC12 I 12 4"H C.I.

90-100 960 14 ppg480 14018 ppg


16.5 B.D. 1400 Cone inlets flanged.

4MC14 I 14 4"H C.I.

90-100 1120 14 ppg560 14018 ppg



4MC16 I 16 4"H C.I.

90-100

1280

14

ppg

640

1401

8 pp

g 1 1 Adjust 0 to -10° O.S. N.P.T. Spring Loaded


Derrick R

R

R

8

16

20

4" PU

4" PU

4" PU

75

75

75

8(50)=400

16(50)=800

20(50)=1000

1

1

1

2

3

3

Adjust -1° to +5°

Adjust -1° to +5°

Adjust -1° to +5°

O.S.

O.S.

O.S.

Ramp-Lok Spring LoadedRamp-Lok Spring LoadedRamp-Lok Spring Loaded

15.53

23.3

32.9

I.

I.

I.

1750

1750

1750

All cones have victaulic connections and 2" valves on inlets.





.29

Geolograph-Pio-neerMud Cleaner (now Swaco Geolograph)

RRRR

16168

16

4"4"HV

6"3" PU

75757575

16(50)=80016(80)=12808(100)=80016(22)=352

1111

1111

Fixed 0°Fixed 0°Fixed 0°Fixed 0°

N.A.N.A.N.A.N.A.

P.T.P.T.P.T.P.T.

12.5712.5712.5712.57

B.D.B.D.B.D.B.D.

0-14500-14500-14500-1450

All Economaster cones with plastic upper and urethane lined alumi-num lower section. Head gauge. All cones have victaulic connec-tions. Screens inter-changeable with Sweco. All units variable speed, variable eccentricity.

HarrisburgMud CleanerMC-800

I 10 5" PU 75 10(80)=800 1 1 Fixed -4° O.S. N.P.T. Spring Loaded both

42x60 = 2520 in2

17.5

B.D. 1500 5" cone inlets flanged.

Hutchin-son-HayesRhumbaMud Cleaner

I 10 5" PU 75 10(80)=800 1 2 Fixed -6° O.S. N.P.T. Spring Loaded

28 B.D. 2100 5" cone inlets flanged.

NL Bariod Mud Cleaner(now available from Bird Machine Co.)

I 8 5" PU 75 700 1 1 Adjust +2 to -2° O.S. N.P.T. Not Spring Loaded

12 B.D. 1610 All cones have victaulic connections on feed & overflow.

Oiltools Mud Cleaner

I 8 4" PU 75 400 1 1 Fixed 0° N.A. P.T. 12.57 I 18001500

Self-cleaning sliders.


Mud CleanerModel Q48R

1 816

6" PU4" PU

7575

800800

1 1 Fixed 0° N.A. P.T. 12.5 B.D. 12001750

All cones have victaulics on feed and overflow.

Swaco Mud Cleaner

All cones have flanged inlets.

4T4 I 8 4" PU 96 600 1 1 or 2 O.S. N.P.T. Spring Loaded

12 B.D. 1750 Mini-Shaker

6T4 I 12 4" PU 96 850 1 1 or 2 O.S. N.P.T. Spring Loaded

12 B.D. 1750 Mini-Shaker

6T4SS I 12 4" PU 96 950 1 2 Fixed 0°, -5° O.S. N.P.T. Spring Loaded

32 B.D. 1140 Super Screen

8T4SS 16 4" PU 96 1200 1 2 Fixed 0°, -5° O.S. N.P.T. Spring Loaded

32 B.D. 1140 Super Screen

Sweco Mud Cleaner

I 8 4" PU 9.0/357

11.0/4018.0/55

8(50)=400 12

12

Fixed 0°Fixed 0°

N.A.N.A.

P.T.P.T.

12.5725.14

II

18001800

Self-cleaning sliders. Double tub unit. Mani-folds with 10 & 12 cones available. Also available with 5" cones.

Table E.6 (Continued)Oilfield Mud Cleaners



Rec. Head

(ft)Capacity

(gpm)Number of



(sq. ft)Screen


Solids Control M

anual





.30

Thule VSM 200 I 81616

4" PU4" PU4" PU

75 4008001280

1 2 Adjust 4.5" up on discard end.

N.A. P.T. 16.0 H.M.D.6 900-2000 Upper deck can be added for saving LCM. 4“ Pioneer Economaster fitted at customer's request.

Totco (Milchem)Mud Cleaner I 10 4" PU 75 500 1 3 Fixed -8.5°,

-11.5°, -12.5°O.S. N.P.T. Spring

Loaded24 B.D. 1750 EVS 24 shaker. Victaulic

connection on cone inlet and overflow.

Totco (Milchem)MudMasterMud Cleaner

I 10 4" PU 75 500 2 2 Fixed 0° O.S. N.P.T. Spring Loaded both sides

40 I., I. 900

Tri-Flo Fluid Sepa-rators

TFI-8 I 8 4" PU 20 psi 520 for any mud weight

1 2 Adjust -5°to +2°

O.S. N.P.T. Spring Loaded both sides

6 B.D. 1750 Feed inlet valves and individual overflows with control valves.

TFI-16 I 16 4" PU 20 psi 1040for any mud weight

1 2 Fixed 0°, -5° O.S. N.P.T. Spring Loaded both sides

12 B.D. 1750 Victaulic connections on cone inlets and over-flows.

Triton LinearMud Cleaner

I 16 3"-5” 75 3"-8004"-8005"-1280

1 3 Adjust -1°to +5°

O.S. N.P.T. Non-Spring Loaded

27.4 I., I. 1728 Triton NNF Screening Machine with bolt-on16-cone desilter.

NOTES:

1. R means “radial” and I means “in-line.”

2. PU means “polyurethane,” C.I. means “cast iron,” and HV means “high volume.”

3. Negative angles means the screen slopes downward from the feed end, and positive angles means upward slopes.

4. O.S. means “overslung” and U.S. means “underslung.” N.A. means not applicable.

5. N.P.T. means “nonpretensioned” and P.T. means “pretensioned.”

6. B.D. means “belt-driven” and I. means “integral,” H.M.D. means “hydraulic motor driven.”

7. Manufacturer recommends given pressures for given mud weights.

Table E.6 (Continued)Oilfield Mud Cleaners



Rec. Head

(ft)Capacity

(gpm)Number of



(sq. ft)Screen






.31

Table E.7Oilfield Centrifuges

a b c d e f g h i j k

Mft. & Model1Bowl Size

(in.)

Rotating2 Assembly

Materials of Construction

Bowl/ConveyorDifferential

Gear-box

Ratio

Speed Range (RPM) RPM/G’s8 Drive3 Mud4 Pump

Capacity6 Mud Wt/GPM Comments

Alfa-Laval

414 14"x36”Contour

SS Adjust w/single lead conveyor

57/1 1500-3400 1500/4472500/12433400/2299

E P.D. 9.0/10011.0/8014.0/60


SS “ 57/1 1500-3400 1500/4472500/12433400/2299

E P.D. 9.0/15011.0/10014.0/70


SS “ 57/1 0-4000 2000/7953000/17904000/3182

E P.D. 9.0/15011.0/10014.0/70

Baker Hughes Treatment Services (marketing Baroid line of solids equipment.)

Standard MudCentrifuge

18"x28”Conical

CS Standard Fixed with dou-ble lead con-veyor

80/1 1300-1800 1300/4321800/828

DH, EH P.D. 9.0/4512-14/2014-16/15>16/10

High VolumeCentrifuge

24"x38”Contour

CS Standard Fixed with single lead conveyor

140/1 or 80/1

Variable1000-2500

1500/7671800/11042300/18032500/2/31

E P.D. orCentrifugal

17.0/109.0/25-150

Bird Machine Co. Note: Bird has supplied 18"x28”'s (conical & contour) & 24"x38”'s (contour) to Pioneer, Baroid, Milchem (Totco), & Brandt (Drexel). Also 24"x45” (contour) to Der-rick. Bird offers a variety of centrifuges applicable to the oilfield.

Broadbent, Inc.

Compact Unit 18"x28”Contour


80/1 1000-2400 1000/2561500/575

2000/10222400/1472

E P.D. 10.0/65 Options available for all Broadbent centrifuges include variable bowl speeds, variable bowl/con-veyor differentials, and a choice of abrasion protec-tion materials for conveyors.

High VolumeStandard

24"x38” CS Standard Fixed with dou-ble lead con-veyor

130/1 or 80/1

1000-2400 1000/3411500/767

2000/13632400/1963

E P.D. 10.0/130

Brandt (Division of Drexel Oilfield Services)

Solids Control M

anual





.32

Rotosep1 6" rotor CS Standard N.A.2 N.A.2 Fixed 2300 2300/451 D or E P.D. 15-28 gpm Same as Totco RMS Centri-fuge, except Rotosep has tungsten carbide seals.

CF-1 18"x28”Contour

CS Fixed with single lead conveyor

40/1 1600-2000Rec 1650 usu-

ally

1600/6541650/696

2000/1022

E P.D. or Cen-trifugal Pump

unwtd/1009.0/90

12.0/6016.0/3018.0/25

Manufactured by Bird Machine Co.

CF-2 24"x38”Contour

CS Fixed with single lead conveyor

80/1 1400-2000Rec 1450 usu-

ally 1900

1400/6682000/1363

E P.D. or Cen-trifugal Pump

unwtd/1759.0/15012.0/6016.0/3018.0/25

Manufactured by Bird Machine Co.

HS-3400 14"x49.5” Contour

SS Standard Fixed with single lead conveyor

52/1 1750-40002900 normally

1750/6092400/11452900/16723500/24354000/3181

E P.D. 9.0/14012.0/8515.0/2518.0/15

Manufactured by Sharples. Patented tungsten carbide tiling on conveyor for abra-sion resistance.

Broadbent, Inc.

High VolumeHigh Speed

22"x54” CS Standard Fixed with dou-ble lead con-veyor

130/1 or 80/1

1000-3200 1000/3121500/703

2000/12502500/19533200/3199

E P.D. 10.0/23014.0/90

Derrick Equipment Co.

DS1(Sharples 3400)

14"x49”Contour

SS Fixed with single lead conveyor

52/1 1800-3250 1800/6442500/12433250/2100

E P.D. or Cen-trifugal

9.0/15017.0/20

Carbide tiles on conveyor.

DE 1000 14"49”Contour


52/1 or 125/1

1800-3250 1800/6442500/12433250/2100


9.0/15017.0/20

Carbide tiles on entire length of conveyor.

DB1 (Bird) 24"x45”Contour


80/1 1500-24001600 usually

1500/7672000/13632400/1963


9.0/230

DB2 (Bird,Bird-Broadbent, Broadbent)

24"x38”Contour

CS & SS Fixed with dou-ble lead con-veyor

80/1 or 130/1

1500-2400 1500/7672000/13632400/1963


9.0/150

Table E.7 (Continued)Oilfield Centrifuges



(in.)

Rotating2 Assembly



Gear-box

Ratio







.33

DB3 (Bird) 18"x28”Contour

CS Fixed with dou-ble lead con-veyor

80/1 1600-2000 1600/6542000/1022


9.0/8017.0/10

DS2(Sharples 3000)

14"x30”Contour


52/1 2000-3250 2000/7952500/12433250/2100


9.0/12017.0/30

Carbide tiles on conveyor.

DDO(Dorr Oliver)

16"x49”Contour

SS Adjust 10-150 RPM

35/1 1800-4000 1800/7363000/20454000/3635


9.0/100

DFE/Solids Control (DFE purchased Bariod's line of solids control equipment; DFE sold to Reserve Pits, Inc. who sold to Baker Hughes Treatment Services; see Baker Hughes Treatment Services/Bird Machine Co.)

Flo-Trend

Model ? (same as Hutchison-Hayes Model 1430)

Model ? (same as Hutchison-Hayes Model 1448)

Geolograph-Pioneer (Merged with Swaco; now Swaco Geolograph.)

DecantmasterStandard

18"x28”Conical


80/1 1500-2000 1500/5752000/1022

DH, EH, or E P.D. 9.0/10-5010.0/35.017.0/10.1

Pioneer Centrifuges were manufactured by Pioneer. Patented conveyor gauging system for all units.

DecantmasterMark I

18"x28”Contour


80/1 1500-2000 1500/5752000/1022

DH, EH, or E P.D. 9.0/20-15010.0/70.017.0/20.2

Backdrive with variable scroll speed available for all units.

DecantmasterMark II

18"x48”Contour


80/1 1500-2000 1500/5752000/1022

DH, EH, or E P.D. or Cen-trifugal

9.0/20-20010.0/70.017.0/20.2

Hutchison-Hayes Intl., Inc.

Model 1430 14"x30”Contour


52/1 2000-4000 2000/7953250/21004000/3181

E P.D. Dia-phragm pump

9.0/20-10010.0/6017.0/9

Manufactured by Hutchi-son-Hayes. Weighted mud capacities at 2100 g's. Slightly higher capacities at lower “g” levels.




(in.)

Rotating2 Assembly



Gear-box

Ratio



Solids Control M

anual





.34



52/1 2000-4000 2000/7953250/21004000/3181

E P.D. Dia-phragm pump

9.0/20-10010.0/6017.0/9

Manufactured by Hutchi-son-Hayes. Weighted mud capacities at 2100 g's. Slightly higher capacities at lower “g” levels.


SS Standard Fixed or Vari-able single lead conveyor

53/1 2000-3250 2000/9093050/21143250/2400


9.0/25010.0/20517.0/32

Manufactured by Hutchi-son-Hayes. Weighted mud capacities at 2100 g's. Slightly higher flows at lower “g” levels.

Hytech Centrifuges, Inc.

Hysep MD 43(previously 142)

16"x50”Contour

CS & SS Adjust 1-70 RPM 40/1 Max 28001500 or 2000on some units

1500/5752000/10222780/1975

E, H P.D. 9.0/10012.0/5015.0/3518.0/20

Manufactured by M & J in Denmark. Conveyor can run approx. 30 RPM faster than bowl, if desired. Pat-ented dual conveyor design.

Hysep MD 53(previously 152)

20"x69”Contour

CS & SS Adjust 1-40 RPM 40/1 Max 2400 2400/1636 E, H P.D. 9.0/16010.0/12512.0/6515.0/4518.0/30

Manufactured by M & J in Denmark. Conveyor can run approx. 30 RPM faster than bowl, if desired. Pat-ented dual conveyor design.

Hysep MD 44 16"x64” SS & Duplex Adjust 1-40 RPM 40/1 Max 3600 3600/2945 E, H P.D. 9.0/13510.0/9512.0/7518.0/35

Manufactured by M & J in Denmark. New 4:1 single scroll with unique accelera-tion feed chamber.

Hysep MD 54 20"x80” CS & SS Adjust 1-40 RPM 40/1 Max 2400 2400/1636 E, H P.D. 9.0/20010.0/16512.0/10518.0/45

Manufactured by M & J in Denmark. New 4:1 single scroll with unique accelera-tion feed chamber.

NL Bariod (Bariod sold its line of solids control equipment to DFE/Solids Control who sold to Baker Hughes Treatment Services; see Baker Hughes Treatment Services.)

Oiltools (No longer in solids control business in USA.)




(in.)

Rotating2 Assembly



Gear-box

Ratio







.35

S2-1G 18"x54” Con-tour,

Counter-Cur-rent or

Co-Current

CS Stan-dard/SS

Hydraulically variable with sin-gle lead con-veyor

Hydraul-ically Variable 0-60

0-3400 E P.D. up to 70 gpm S2-1G manufactured by Humboldt. WATER DILU-TION MUST NOT BE USED WITH CO-CURRENT MODEL. Co-Current model not recommended for weighted muds.

S3-0G 20"x60” Con-tour,

Counter-Cur-rent or

Co-Current

CS Stan-dard/SS

Hydraulically variable with sin-gle lead con-veyor

Hydrau-lically Variable 0-60

0-2600 E P.D. up to 97 gpm S3-0G manufactured by Humboldt. WATER DILU-TION MUST NOT BE USED WITH CO-CURRENT MODEL. Co-Current model not recommended for weighted muds.


Q30 18"x28”Conical


80/1 1500-2000 1500/5752000/1022

E P.D. 9.0/0-7510.0/35

17.0/10.1

Automatic self-cleaning on shutdown.

Q100 18"x28”Contour


80/1 1500-2000 1500/5752000/1022


9.0/10010.0/7017.0/15


Q200 18"x50”Contour


80/1 1500-2000 1500/5752000/1022


9.0/20010.0/15017.0/15


Sharples, Inc.7

P-1000 14"x22” SS Not manufactured any longer.




(in.)

Rotating2 Assembly



Gear-box

Ratio



Solids Control M

anual





.36

PM20000(P-3000)

14"x30.9” Contour


52/1 or 125/1

2600-4000 2600/13443250/21004000/3181

E P.D. pre-ferred

9.0/10010.0/9011.0/6017.0/20

Comments for Sharples Centrifuges (excluding P-1000): Sharples centri-fuges have axial flow con-veyors and tungsten carbide tiles on conveyors for abra-sion resistance. P” series is older & does not have axial flow and tungsten carbide tiles as standard.

PM30000(P-3400)

14"x49.4” Contour


52/1 or 125/1

2600-4000 2600/13443250/21004000/3181

E P.D. pre-ferred

9.0/18010.0/17011.0/100

17.0/15-20

PM35000 16.75"x49.4” Contour


52/1 or 125/1

PM40000(P-4600)

20"x50.3” Contour

SS

PM50000(P-4800)

20"x76.4” Contour


47/1 or 95/1

2000-3200 2000/11362550/18472800/22273200/2908

E Centrifugal 9.0/42510.0/42511.0/30017.0/100

PM55000 24"x76”Contour

SS

PM60000(P-5000)

25"x65”Contour

SS Same as PM70000 except for length.

PM70000(P-5400)

25"x90”Contour


47/1 or 95/1

1800-300 1800/11502250/17972500/22193000/3195

E Centrifugal 9.0/70010.0/63011.0/40017.0/130

Spike Enterprises, Inc.

Bird 18"x28”Conical


80/1 1500-2000 1500/5752000/1022

EH, E Centrifugal 90/10-4010.0/30

17.0/5-10

Broadbent 24"x38”Contour

CS Standard Fixed single and fixed double lead conveyor

80/1130/1

1000-2400 1000/3411500/767

2000/13632400/1963

E, D Centrifugal 9.0/15010.0/100

Bird 24"x38”Cylinder

SS Fixed single and fixed double lead conveyors 9 degrees

80/1 1000-2400 1800/11042000/13632400/1963

E Centrifugal 9.0/12010.0/85




(in.)

Rotating2 Assembly



Gear-box

Ratio







.37

Bird 24"x38”Contour

CS, SS Fixed single lead conveyor

80/1 1000-2400 1800/11042000/13632400/1963



CS Standard Fixed with 6" SW, 6 lead con-veyor

80/1 1800-2500 1800/11042000/13632500/2130

E Centrifugal 9.0/25010.0



80/1 800-1700variable

800/2911200/654

1700/1313

DieselDirect

Centrifugal 9.0/450

SharplesP-5400

25"x90”Contour


47/1 or 95/1

1800-3000 1800/11502250/17972500/22193000/3195

E Centrifugal 9.0/70010.0/63011.0/30017.0/100

Tungsten carbide tiles on conveyor just before feed inlet to solids discharge end; no axial flow conveyor.

Swaco Geolograph (Swaco & Geolograph-Pioneer merged.)

Model 414Centrifuge

14"x36”Contour

SS Standard Adjust (3 set-tings) w/single lead conveyor

60/1 1600-3250 1600/5091800/644

2500/1243

E P.D.Centrifugal

9.0/0-6011.0/4017.0/17

Swaco 414 & 518 centri-fuges manufactured by Swaco Geolograph.

Model 518High SpeedCentrifuge

14"x56”Contour

SS Adjust (3 set-tings) w/single lead conveyor

60/1 1600-3250 2500/12433250/2100


10.0/60

Model 518 not designed for weighted muds.

Model 518High SpeedCentrifuge

14"x56”Contour

SS Adjust (3 set-tings) w/single lead conveyor

60/1 1900 1900/718 E Centrifugal 9.0/2509.5/200

10.0/150

Model 518 not designed for weighted muds.

Mark I (Same as Geolograph-Pioneer Mark I.)

Mark II (Same as Geolograph-Pioneer Mark II.)

Sweco

SC-2 18"x30”Contour

CS StandardSS Available

Double lead Fixed or variable conveyor

59/1 1350-2250 1350/4662250/1294


9.0/200 Manufactured by Sweco. Backdrive for variable con-veyor speed avail.

SC-4 24"x40”Contour


Double lead Fixed or variable conveyor

59/1 1150-19501550 typ.

1150/4511350/621

1950/1296


9.0/280 Manufactured by Sweco. Backdrive for variable con-veyor speed avail.




(in.)

Rotating2 Assembly



Gear-box

Ratio



Solids Control M

anual





.38

Z-34 14"x56”Contour


Single lead vari-able conveyor

140/1 2000-3500 2000/7953500/2435


9.0/100 Manufactured by Flottweg. Backdrive for variable con-veyor speed.

Omega Mark I 18"x28”Contour


80/1 1350-2000 1350/4662000/1022

E or DH P.D. or Cen-trifugal

9.0/150

Omega Mark II 18"x48”Contour


80/1 1350-2000 1350/4662000/1022


9.0/200

NX 329 20"x62”Contour

SS Standard Single lead vari-able axial flow conveyor

143/1 1350-2400 1350/5182400/1636


9.0/150 Manufactured by Alfa Laval.

643 16"x54” CS Standard Variable Double Conveyor

140/1 1350-2500 1350/4142500/1420


9.0/125 Manufactured in Denmark by GVS.

P3400 14"x50” CS or SS Fixed with single lead conveyor

141/1 up to 3000 2000/7952500/12433000/1789


9.0/100 Manufactured by Sharples.

RMS (same as Totco Milchem RMS Centrifuge)

Totco (Milchem) (Totco no longer in solids control business.)

RMSCentrifuge1 6" rotor CS Standard N.A.2 N.A.2 Fixed 2300 2300/451 D or E P.D. 15-28 gpm Developed by Mobil in 60's,

portable, does not decant.

HV 18 18"x28”Contour


80/1 1800-2000 1800/8282000/1022

E Centrifugal 9.0/7010.0/5019.0/20

HV 18 manufactured by Broadbent.

HV 24 24"x38”Contour


130/1 1600-1800 1600/8721800/1104

E Centrifugal 9.0/15010.0/12019.0/50

HV 24 manufactured by Broadbent.

Tri-Flo International, Inc.

Alfa-Laval418

14"x56”Contour

SS Standard Adjust (5 set-tings) with single lead conveyor

160/1 1500-34002800 typical

1500/4472800/15593400/2298

E50HP

PD 9.0/140 for1800-19009.0/75 for2800 RPM

Not designed for weighted muds.




(in.)

Rotating2 Assembly



Gear-box

Ratio







.39

Humboldt 24"x54”Contour

CS Standard Fixed with single lead conveyor

25/1 1638-1850 1638/9141850/1166

E Centrifugal 9.0/185 Manufactured by Humboldt.

SCS/142 15"x38”Contour

CS Variable with double lead con-veyor

N.A. 2800 variable 2800/1670 EH50 HP

PD 8.5/60

SCS/152 19.5"x62”Contour

CS Variable with double lead con-veyor

N.A. 2400 variable 2400/1595 EH50 HP

PD 8.5/100

Wagner International, Ltd. (merged with Wadeco)

Sigma 100 18"x28”Contour


80/1 2000 typical 2000/1022 E50HP

Centrifugal 8.5/1259.5/80

10.5/60

Sigma 150 18"x48”Contour

CS Standard Fixed with dou-ble lead con-veyor; axial flow

80/1 2000 typical 2000/1022 E50HP

Centrifugal 8.5/1759.1/1409.5/12010.0/65

SharplesPM40000

20"x50”Contour

CS &/or SS Fixed with single lead conveyor; axial flow; STC tiles

49/1 2800 typical 2800/2226 E100HP

Centrifugal 8.5/300 Sintered Tungsten Carbide tiles (STC) on conveyor for abrasion resistance.

SharplesPM60000

25"x65”Contour

SS Fixed with single lead conveyor; axial flow; STC tiles

47.5/1 2500 typical 2500/2218 E200HP

Centrifugal 8.5/400 Sintered Tungsten Carbide tiles (STC) on conveyor for abrasion resistance.

NOTES:

1. All centrifuges are decanters except Totco (Milchem) RMS Centrifuge which is a perforated rotor centrifuge.

2. CS means “carbon steel,” SS means “stainless steel,” N.A. means “not applicable.”

3. DH means “diesel-hydraulic,” EH means “electric-hydraulic,” D means “diesel,” and E means “electric.”




(in.)

Rotating2 Assembly



Gear-box

Ratio



Solids Control M

anual





.40

4.P.D

. means “positive displacem

ent.”

5. Not available from manufacturer.

6. Values given are per manufacturer.

7. The “PM” Series Sharples centrifuges are newer versions of the older “P” series. Among the differences are axial flow conveyors with tungsten carbide tiles for abrasion resis-tance and 360 degree solids discharge.

8. “G” = .0000142 x Bowl Diameter (in.) x RPM2




(in.)

Rotating2 Assembly



Gear-box

Ratio




1.1

Chapter 1. Introduction

All drilling personnel recognize the importance of mud in the successful drilling ofa well. One of the primary uses for drilling fluid is to carry unwanted drilled solidsfrom the borehole. These solids are essentially a contaminant and, if left in themud, can lead to numerous operational problems. Three options are available tomaintain acceptable drilling fluid properties:

1. Do nothing and let the solids build up. When the mud no longer meets specifi-cations, throw it away and start with fresh mud.

2. Dilute the mud and rebuild the system to keep the properties within accept-able ranges, while dumping excess mud to the reserve pit.

3. Lower the solids content of the mud through solids removal to minimize theaddition/dilution necessary to maintain acceptable properties.

In recent years, increased public awareness of environmental issues has providedboth regulatory and economic incentives to minimize drilling waste. In manyinstances, the first two choices have become very expensive and unacceptable.This has served to stress the importance of the third option, efficient solids con-trol. Using solids removal to minimize addition/dilution volumes is normally mosteffective and provides the following benefits:

• Increased penetration rates

• Reduced mud costs

• Lower water requirements

• Reduced torque and drag

• Less mixing problems

• Reduced system pressure losses

• Lower circulating density (ECD)

• Better cement jobs

• Reduced instances of lost circulation

• Reduced formation damage

• Less differential sticking

• Reduced environmental impact

• Less waste, lower disposal costs

It is apparent from this list that the role of solids control is instrumental in the main-tenance of a good drilling fluid. Solids control equipment has been standard hard-

Introduction


1.2

ware on most rotary drilling rigs since the early 1960s. In the early years, many ofthe solid/liquid separation devices were borrowed from other industries andapplied directly to oilfield rotary drilling. Although the basic operating principlesand technology associated with mechanical solids removal have not changed sig-nificantly over the years, refinements in design specifically for drilling applicationshave yielded considerable improvements in performance and reliability.

This manual provides drilling personnel with the information to help optimize theselection and operation of solids control equipment. Emphasis is placed onmechanical solids removal equipment and the factors that impact its performance.Practical operating guidelines are provided to help achieve maximum perfor-mance in the field.


10.1

Chapter 10. Addition/Mixing Systems

All mud systems require a mixing system for the addition of viscosifiers, weightingagents and chemicals to maintain desired mud properties. The method and loca-tion chosen for addition can greatly impact material consumption and the resultantproperties of the active system. For example, if bentonite is not completelyhydrated before being pumped downhole, the viscosity of the mud at the flowlinewill be much higher than at the suction pit. Since viscosity negatively impacts sol-ids control equipment performance, inadequate control of viscosity can lead tohigher dilution volumes. Polymers present special mixing concerns to prevent theformation of “fish-eyes”; balls of dry polymer encapsulated by a thick,partially-hydrated layer. Unless properly wetted and sheared, a significant portionof the polymer will be lost at the shakers and increase polymer consumption. It istherefore important to ensure that additions are made correctly and in the rightlocation.

Mixing Hoppers

The most common device used to add dry material to the mud is the venturi mudmixing hopper (Figure 10.1). Fluid is supplied to the mixer by a centrifugal pump.The hopper device works by converting pressure head into velocity through a jetnozzle. The downstream venturi increases the shearing action and changesvelocity head back into pressure head. Dry material is added where the jet streamcrosses the gap between the nozzle and the venturi. Here, a low pressure areacreates a slight vacuum. This vacuum, along with gravity, helps draw the materialinto the fluid stream. The high velocity and high shear rate of the fluid wets anddisperses the dry material. To operate at maximum efficiency, both the nozzle andventuri must be correctly sized for the flowrate and head. This type of hopper isavailable from many manufacturers. “Homemade” versions, usually without aproperly-designed venturi, are common.

Another common mixing device is the Sidewinder hopper (Figure 10.2), manufac-tured by Swaco. The operation is much like a hydrocyclone. Fluid is pumped to atangential inlet which allows pressure energy to be converted to centrifugal force.The spiraling fluid picks up the dry mud where it undergoes shear as it travelstwice around the mixing chamber. As the fluid exits the hopper through a tangen-tial outlet, the velocity is converted back into pressure head.

Laboratory tests conducted with bentonite showed little difference between thetwo devices in both capacity and mixing capability as measured by the resultantmud rheology. Since the Sidewinder does not draw air into the hopper, dust can



10.2

Figure 10.1 Jet/Venturi Mixer. This design reduces dust but entrains more air into the fluid.

Figure 10.2 Sidewinder Mixer. This design does not entrain as much air as the venturi mixer, but creates more dust.

Addition/Mixing Systems


10.3

be a problem when adding some materials. Conversely, the Mission Venturi hop-per eliminated dust but entrained more air into the mud. Sizing of the jet nozzleand venturi are critical in obtaining maximum performance from venturi mixers;“homemade” versions should be avoided.

Bulk Systems

Bulk systems are economical for storing and distributing weighting material inlarge quantities. There is less waste and trash than when using sacked material.Bulk barite is stored in large vertical tanks, equipped with an air delivery system.Barite is drawn from the tank by a venturi to a bulk hopper which meters the mate-rial into the mud hopper. Bulk systems for other dry materials are becomingincreasingly popular in offshore applications to eliminate handling and wasteassociated with sacked material. When consumption is not high enough to justifybulk tanks, hopper systems using 2200 lb “big bags” may be an alternative.

Polymer Mixing

Conventional mixing hoppers are not generally adequate for mixing and wettingdry polymers into viscous muds. Problems frequently arise when attempting tomix dry PHPA powder through conventional mixing hoppers regardless of whetherthe polymer is added directly to the active system or to a concentrated premix.Polymer fish-eyes, excessive viscosities, extensive mixing times and shakerscreen blinding are commonly reported. These problems can be reduced by usinga liquid form of the product, but liquid formulations contain less active polymer anduse an oil as the carrier fluid.

Work conducted on the characterization of polymers such as PHPA has led to thefollowing conclusions regarding the mixing and shearing of polymers:

1. PHPA polymers marketed for use in drilling fluids may contain varyingamounts of high molecular weight fractions. Viscosity is a function of molecu-lar weight. Those products with a higher fraction of high molecular weightpolymer will be harder to dissolve and generate higher viscosities.

2. Shear-degradation reduces the molecular weight of many polymers, espe-cially PHPA. Higher shear rates produce lower molecular weights. Below acertain molecular weight, the inhibitive characteristics of PHPA are effectivelylost.

A mixing and shearing system consisting of a perforated-wafer type of jet shearmixer coupled with a SECO Homogenizer was found to provide improved mixing



10.4

and allow preparation of PHPA concentrations to 6 lb/bbl in a 50,000 mg/L chlo-ride brine. The Flo Trend Jet Shear Mixer, pictured in Figure 10.3, directs fluid intoa mixing chamber through opposing nozzle disks to impart turbulence andincrease contact area. Polymer is added into the chamber through a conventionalhopper. The mixture is then pulled into a venturi eductor, where further shearingand mixing occurs.

The SECO (Echols) homogenizer consists of a perforated ring that fits around theperimeter of the impeller blades in a centrifugal pump (Figure 10.4). Test con-ducted indicate that the SECO homogenizer produces sufficient shear to degradethe higher molecular weight fractions that make the product hard to dissolve, butwill not shear-degrade below the molecular weight required for inhibition. TheSECO is recommended for premixing polymer to reduce viscosity and eliminationfish-eyes. Do not use this device for shearing weighted muds; the high solids con-tent will quickly erode the perforations in the homogenizer ring. Also, barite maybe degraded by the homogenizer.

The following guidelines should be followed for building concentrated premix vol-umes:

Figure 10.3 Jet Shear Mixer. Designs such as this can improve polymer mixing.



10.5

1. When possible, use brine instead of fresh water. Polymers will impart less vis-cosity in brine than in fresh water.

2. Mix supplemental material into the brine prior to adding the polymer.

3. After mixing the supplemental material, the total amount of polymer should bemixed through the jet shear mixer into the brine in a single pass.

4. After mixing the PHPA, the premix should be sheared through the homoge-nizer until stable rheological values are achieved.

Active System Addition

Dry products such as bentonite and barite should not be added, even through ahopper, at the suction compartment nor in the solids removal section. Additionshould be made at least one compartment upstream of the suction compartmentto allow time for the material to wet and disperse into the active system. Boththese compartments must be well-agitated either by mechanical stirrers or mud

Figure 10.4 SECO (Echols) Homogenizer Ring. Recommended for shearing polymers.



10.6

guns. Mud materials added at the suction can cause air entrainment at the rigpumps and increase the incidence of drill pipe corrosion.

Premix System

A premix system is a separate set of tanks with agitators and a hopper for batchmixing mud to desired specifications before addition to the active system. Premixsystems are highly recommended for the advantages they provide:

1. Improved hydration and less air entrainment with dry solids addition.

After mixing dry material in the premix tank, the mud can be agitated until thedry material is fully wetted. This also provides time for entrained air to breakout of the mud.

2. Better control over active system mud properties.

The properties of the premixed mud can be tailored to meet desired proper-ties before transferal to the active system. Once properties in the premix havestabilized, the mud can be transferred over a complete circulation to ensureeven mud properties in the active circulating system.

3. Less material consumption.

With longer hydration and shearing time, premix tanks offer the benefit ofmaximizing the yield from bentonite and polymers before addition to the activesystem. Premix tanks are especially effective for polymer muds and almostessential for oil-based muds. Specialized shearing and mixing equipment(see Polymer Mixing) may be used on the premix tank to properly wet poly-mers at high concentrations and eliminate fish-eyes, thus reducing polymerconsumption.

4. Easier to monitor dilution rates.

The volumes added to the active system are usually much easier to monitorwhen transferring liquids of known quantity from a premix tank. The overallsolids removal efficiency can be determined much more readily when accu-rate measurements can be made of dilution volumes and water additions.

5. Less manpower requirements.

Since the premix is prepared in a batch process, material may be added muchmore quickly than when making additions over a complete circulation in theactive system. Once the material has been added, the premix may be left toagitate and hydrate the slurry. After the desired properties have beenachieved, the premix may be metered slowly into the active system. Both the



10.7

hydration and transferral operations require minimum attention, thus freeingup manpower for other duties.

Water Addition

Dilution water is necessary in all water-based mud systems to maintain circulatingvolume and desired mud properties. Since the amount of dilution is directly linkedto solids removal efficiency, the use of a water meter to monitor dilution volumes isstrongly recommended. Water will be necessary on the rig floor, in the motor area,and may be required to help move discarded solids to the waste pit. Water mustbe supplied to the addition section and solids removal sections of the mud pits forboth volume maintenance and cleaning. Since water must be supplied to almostevery area on the rig, manifolding is obviously required. Ensure that the watermeter is located to account for all water streams that will end up in the active sys-tem. Water should be recycled wherever possible.

Remember that regardless of its purpose, any water used on and around the rigwill contribute to the total liquid waste volume. This is especially important onlocations where water supply or disposal costs are high. It is imperative that everywater line be equipped with a valve and that no leaks are tolerated. Use low vol-ume nozzles on the wash water lines. When possible, wash water should be col-lected and segregated from the cuttings disposal pit for recycling or for makeupwater in the active system.

Water should be added at the flowline when necessary to reduce the viscosity ofthe mud and allow finer screens to be used on the shakers. Any potential degra-dation in the cuttings size due to viscosity reduction is offset by the increasedremoval rate. Lower viscosity mud will also improve downstream degasser andhydrocyclone performance.

Because centrifuge performance is sensitive to the viscosity of the feed mud,water addition at the centrifuge is usually necessary to achieve optimum perfor-mance. Since the centrifuge feed rate is usually much lower than other devices,the beneficial effect of water addition is proportionately greater at the centrifuge.Note, however, that dilution water added to the feed of the barite-recovery centri-fuge is discharged with the centrate and does not contribute to dilution of theactive system unless two-stage centrifuging is employed.

Waste Pit Water

In many instances, recycling water from the waste pit makes both economic andenvironmental sense. The following guidelines can significantly reduce overall rigwater consumption:



10.8

1. Recycle waste pit water to the shaker or centrifuge slides to help flow dis-carded solids back to the waste pit.

2. Use clean waste pit water as makeup water for the mud. Design the waste pitto access this fluid. This water must be checked for chemical compatibilitybefore addition to the active system.

3. Use the waste pit water as dilution water for the barite-recovery centrifuge,provided the volume of colloidal solids in the water is low.

4. Segregate wash water and runoff water from the solid waste pit. This is espe-cially important when using salt muds or oil-based muds to control waste pitremediation costs.

Agitation

Agitation is necessary to keep weight material suspended and ensure a homoge-neous drilling fluid. Agitation also prevents solids buildup in the mud tanks. Allremoval compartments except the sand trap should be well-stirred. Mechanical(paddle type) stirrers are efficient mixers and are recommended, especially in thesolids removal section. Mud guns impart shear which may degrade the drilled sol-ids. Mechanical agitation ensures that the solids control equipment cannot bebypassed. Mud guns are acceptable in the Addition-Suction compartments down-stream of the solids control equipment. In the addition section, mud guns mayhelp shear and blend newly-added mud materials.

Mechanical stirrers must be correctly sized. They must be large enough to ade-quately mix the fluid and not so large to cause aeration of the mud. The followingmethod for sizing agitators was developed by the Brandt Company. This agitatorsizing method is based on the desired turnover rate (TOR). The TOR is the timerequired, in seconds, for all of the fluid in the tank to move past the agitatorblades:

where:

Vt = Tank volume in gallons (L x W x H, in feet x 7.481)

D = Impeller displacement in gal/min (from Table 10.2)

The mud area to agitate should be divided into squares. For example, a 10 ft x30 ft tank should be divided into 3 equal parts, each 10 ft x 10 ft. The TOR wouldbe based on the volume of each 10 ft x 10 ft area.

TOR Vt D⁄ 60×=



10.9

For proper agitation, the TOR should be between 35 and 90. A TOR less than 35may result in vortices; a TOR over 90 will lead to solids settling. Table 10.1 givesthe recommended TORs for various mud compartment uses.

Agitator Design

1. Calculate volume, Vt, (gal).

Vt = L x W x H, in feet x 7.481 gal/ft3.

2. From Table 10.1, determine the required TOR, (sec).

3. Calculate the required impeller displacement, D, (gpm).

D = Vt x 60 / TOR

4. Choose an impeller from Table 10.2 with impeller displacement closest to thevalue calculated in Step 3. For tank depths > 5 ft, use a canted-blade (angledblade) impeller. Flat-blade (vertical blade) impellers may be used in shallowertanks.

5. Locate the impeller diameter corresponding to the chosen impeller displace-ment on Table 10.2. Using Figure 10.5 (Canted-Blade) or Figure 10.6(Flat-Blade), enter the chart at the impeller diameter and follow the horizontalline until it intersects the maximum anticipated mud weight curve. Read therecommended horsepower.

6. Determine the recommended agitator shaft length from Table 10.3.

7. Canted-blade impellers should be located so that the distance between thetank bottom and the lower edge of the impeller blades is equal to 0.75 timesthe impeller blade diameter. Flat-blade impellers should be placed 6 in. abovethe bottom of the tank, or 2 in. above the bottom shaft stabilizer.

8. Baffles, as shown in Figure 10.7 are highly recommended for flat-bottomedtanks to help direct the flow towards the corners and eliminate “dead areas” in

Table 10.1 Recommended Turnover Rates

Tank Type

Solids Removal

Suction Reserve Pill

Recommended TOR 50-75 65-85 50-80 40-65



10.10

the tank. A baffle is a steel plate 12 in. long, mounted on the tank floor andextending 6 in. above the top of the agitator blades. The baffles should beinstalled 6 in. from the agitator blade tips along a line from the agitator shaft toeach corner of the compartment.

Agitator Sizing Example

Given: Suction Tank, 9 ft L x 7 ft W x 9 ft H18 ppg mud

1. Vt = (9 x 7 x 9) x 7.481 = 4242 gal

2. Recommended TOR, from Table 10.1: 75 sec

3. Impeller Displacement Rate: D = (60) (4242)/75 = 3394 gpm

4. Since tank depth > 5 ft, a canted-blade impeller is selected. From Table 10.2, nearest D = 3764 gpm, Impeller Diameter = 32 in.

5. From Figure 10.6, for 32 in. diameter and 18 ppg mud, required agitatorhorsepower = 5 HP (MA5).

6. From Table 10.3, for model MA5 agitator and 9 ft tank depth, shaft lengthreduction = 10 in. Total Shaft Length = 9 ft x 12 in./ft - 10 in. = 98 in.

7. Impeller location above tank bottom = 0.75 x 32 = 24 in.

8. Total Agitator Weight = 98/12 x 15.1 lbs/ft + 580 lbs + 50 lbs = 753 lbs.



10.11

Table 10.2 Impeller Displacement Rates

Diameter(in.)

Weights(lbs)

Impeller Displacement Rate*GPM at 57.5 rpm (60 Hz)

Impeller Displacement RateGPM at 48 rpm (50 Hz)

Canted-Blade Flat-Blade Canted-Blade Flat-Blade

12 11 213 246 177 205

16 15 484 560 404 467

20 19 909 1051 760 877

24 21 1645 1941 1373 1620

28 38 2468 2839 2060 2370

32 50 3764 4365 3142 3644

36 61 5402 6273 4510 5237

40 74 7284 8411 6081 7023

44 101 9928 11300 8288 9435

48 118 12512 14401 10445 12024

52 126 16100 18630 13440 15552

* D = AB x V x 7.481 gal/ft3, where AB = projected blade area, ft3, V = impeller velocity, ft/min Canted-blade area based on 60° angleBrandt data

Table 10.3 Physical Specifications for Mechanical Mixers

Model HPShaftDia.(in.)

Minimum Impeller Dia. (in.)

WeightShaft Length Reduction

(in.)**

Shaft (lb/ft)

Agitator (lbs) Free Stabilized

MA1* 1.0 1-1/2 12 6.0 200 9 9

MA2* 2.0 1-1/2 20 6.0 310 9 9

MA3* 3.0 1-3/4 24 8.2 406 10 10

MA5 5.0 2-3/8 28 15.1 580 11-1/2 10

MA7.5 7.5 2-3/8 32 15.1 1200 22-1/2 12

MA10 10.0 3 32 24.0 1224 22-1/2 12

MA15 15.0 3 36 24.0 1830 26-5/8 13-1/8

MA20 20.0 3-1/4 40 28.1 1898 27 13-1/2

MA25 25.0 3-1/2 40 32.7 3130 33 13-1/2

* Bottom shaft stabilizer required at 6 ft, all others require bottom stabilizer at 8 ft.** Shaft Length = Distance from tank bottom to top of agitator support beams - shaft length reduction.Brandt data



10.12

Figure 10.5 Horsepower Requirements for Canted-Blade Impellers (Courtesy of Brandt).

Figure 10.6 Horsepower Requirements for Flat-Blade Impellers (Courtesy of Brandt).



10.13

Figure 10.7 Floor Baffles. These are recommended to eliminate “dead areas” in flat-bottomed tanks.



10.14

Summary

• Addition/mixing systems must be correctly designed to minimize material con-sumption and ensure complete and even mixing.

• The two most common mixing hoppers are the venturi type and theSidewinder hopper. Laboratory tests conducted with bentonite showed littledifference between the two devices in both capacity and mixing capability.The Sidewinder does not entrain air like the venturi hopper, but dust can be aproblem when adding some materials.

• Bulk systems are economical for storing and distributing material required inlarge quantities. There is less waste and trash compared to sacked material.Bulk systems are also becoming popular for the accurate metering of drymaterial and chemicals in low dosages.

• Mixing polymers such as PHPA presents additional problems such as polymerfish-eyes, extensive mixing times, and shaker screen blinding. Polymers witha higher fraction of high molecular weight polymer will be harder to dissolveand generate higher viscosities. Higher shear rates produce lower molecularweights, but below a certain molecular weight, the inhibitive characteristics ofPHPA are lost.

• A mixing and shearing system consisting of a perforated-wafer type of jetshear mixer, coupled with a SECO Homogenizer, was found to provideimproved polymer mixing. Guidelines for building concentrated premix vol-umes are provided.

• Premix systems are highly recommended for the numerous advantages theyprovide:

A. Improved hydration

B. Better control over active system mud properties

C. Less material consumption

D. Easier to monitor dilution rates

E. Less manpower requirements

• All dilution water streams should be metered to monitor solids removal effi-ciency. Water should be added at the flowline to reduce viscosity and improveshaker performance. Any water used on the rig will contribute to the total liq-uid waste volume. No leaks should be tolerated. Use low volume nozzles onthe wash water lines. Recycle water where possible.

• Mechanical (paddle type) agitators are recommended in the solids removalsection of the active system. Mud guns are acceptable in the addition/suctioncompartments only. A procedure is provided to correctly size mechanical stir-rers.


11.1

Chapter 11. Tank Design and EquipmentArrangements

Tank Design

The surface pits that comprise the active circulating system should be designed tocontain enough usable mud to maintain mud properties and to fill the hole during awet trip at the rig’s maximum rated depth. Usable mud is defined as the mud vol-ume which can be pumped before suction is lost. For example, a typical 10,000 ftwell will normally require a minimum active system tank volume of 500 bbls.

The active surface system can be divided into two sections: Solids Removal andAddition-Suction. All solids removal equipment and degassing occurs in the SolidsRemoval section. The Addition-Suction section is used to add fresh mud to the cir-culating system and provide sufficient residence time for proper mixing to occurbefore being pumped downhole. A slug tank is usually available to pump small“pills” such as LCM or barite slugs for tripping.

Each section must be further divided into enough compartments to efficientlycarry out its designed function. The number of compartments needed will dependupon the amount and type of solids removal equipment, system size and circula-tion rate. Each compartment must have enough surface area to allow entrainedair to break out of the mud. A rule of thumb for the minimum surface area is calcu-lated by:

Area (sq ft) = Maximum Circulating Rate (GPM)/40

To maximize solids suspension and usable volume, the best tank shape is roundwith a conical bottom. Next best is a square or rectangular shape with a V-bottom.The least-preferred shape is the square or rectangular box with a flat bottom. Theideal tank depth is equal to the width or diameter of the tank. This design providessufficient pump suction head and is best for complete stirring.

Compartment Equalization

Equalization height between compartments will depend upon the duty of the com-partment. As a rule, an adjustable equalizer is needed only between the SolidsRemoval section and the Addition-Suction section. An adjustable swing-armequalizer is recommended. Normally, the equalizer will take mud from the bottomof the last solids removal compartment and discharge mud near the top of the first



11.2

compartment in the Addition-Suction section (high equalization). This keeps thefluid level high in the Solids Removal section to maintain sufficient suction headfor the centrifugal pumps, prevents vortexing by the stirrers and provides sufficientmixing volume in barite-recovery operations. In emergencies, the swing-arm canbe lowered to provide access to the full surface volume.

High equalization between the Solids Removal and Addition-Suction sections alsoincreases the ability to detect volume changes due to influx or losses to formation.Because the volume of the Solids Removal Section remains constant, any volumechange is apparent as a liquid level change in the Addition-Suction section only.This increases the sensitivity to volume fluctuations since the change in fluid levelwill be more pronounced per unit volume.

The minimum equivalent diameter of the equalizer for adequate flow betweencompartments can be estimated by the following calculation:

Diameter, in. = (Qmax, gpm/15)1/2

Recommended equalization between specific compartments is summarizedbelow:

Sand Trap

A sand trap is the settling compartment located downstream of the shale shakers.It should be the ONLY settling compartment and should not be used inclosed-loop systems. Its main function is to remove large solids that might plugthe downstream hydrocyclones. With the fine-screen capabilities of today’s shaleshakers, the sand trap mainly serves as a backup should the shakers bebypassed or operated with torn screens. The sand trap should be the first com-partment the mud enters after passing through the shaker screens. Since it is asettling tank, it should not be stirred and the mud should exit the sand trap over ahigh weir.

Location Equalization

Sand Trap Exit High

Degasser High

Desander Low

Desilter Low

Centrifuge Low

Solids Removal - Addition High (Adjustable)

Addition-Blend Low

Blend-Suction Low

Tank Design and Equipment Arrangements


11.3

The sand trap floor should have a 45° slope to its outlet. A 20 to 30 bbl volume issufficient. A quick opening solids dump valve that can be closed against the mudflow is recommended to reduce mud losses. The sand trap should be dumpedonly when nearly filled with solids, since whole mud is lost when the sand trap isdumped.

Slug Tank

A slug tank is a small compartment (10-50 bbls) isolated from the rest of the activesystem in the Addition/Suction section. Slug tanks provide the ability to mix smallvolumes of specialized fluids and materials. The mud pump suction is manifoldedto provide access to the slug tank. The slug tank is routinely used to mix smallslugs of material to be pumped directly downhole, such as high density pills forplacement in the drill pipe prior to tripping. It is also commonly used for prepara-tion of LCM pills, spotting fluid for differential sticking, and viscous sweeps. Themixing hopper must be manifolded to permit isolation of the slug tank for mixingthese pills.

Equipment Arrangement

The solids removal equipment should be arranged to sequentially remove finersolids as the mud moves from the flowline to the suction pit. The purpose of thisarrangement is to reduce the solids loading on the next piece of equipment. Eachdevice must take mud from an upstream compartment and discharge into the nextcompartment downstream. This applies to both unweighted and weighted mudequipment arrangements. The amount and type of equipment required willdepend upon the drilling conditions and economics specific to each well. Unless adetailed economic analysis is made, it is usually better to overestimate solidsremoval equipment requirements. Underequipping the rigs can frequenly result inlow penetration rates, differential sticking, high material consumption and exces-sive dilution and disposal volumes.

Proper routing of fluids through the solids removal system is essential to achievemaximum solids removal efficiency. Mistakes in fluid routing can drastically reduceseparation performance by causing a large percentage of the circulation flow to bebypassed. These errors are most commonly associated with mud cleaners andhydrocyclones. In addition to suction and discharge routing, overflow dischargesto mud ditches and mud gun use are other common sources of routing errors.

Ideally, each piece of solids control equipment should be fed by a single-purposepump with no routing option. Mud cleaners, desilters and desanders should not,under any condition, require multiple suction locations. In practice, complex rout-ing with multiple suction options is the rule rather than the exception. When this isthe case, the internal configuration of the mud tanks during rig up must beinspected to trace all lines. Do not rely on “as built” schematics; they are usually



11.4

incorrect. Color-coding of the correct routing schematic to correspond withcolor-coded valves on the manifolds can greatly assist rig crew members in mak-ing correct routing decisions. “Hard-plumbed” routing errors should be correctedas soon as possible.



11.5

General Guidelines for Surface System Arrangements

The following guidelines are common to all equipment arrangements.

1. All removal compartments except the sand trap should be well-agitated toensure even solids loading.

2. Mechanical stirrers are recommended. Check that they are properly-sizedand installed correctly.

3. Mud guns are not recommended for the Solids Removal section.

4. When installed, the degasser should be located immediately downstream ofthe shale shaker and upstream of any equipment fed from a centrifugal pump.

5. Use a high equalizer between degasser suction and discharge.

6. All solids removal equipment should discharge immediately downstream oftheir suction compartments.

7. All equipment except the centrifuge should process at least 100% of the circu-lation flow. Backflow should be observed in these compartments.

8. Low equalization between suction and discharge for all solids removal equip-ment.

9. Different solids control devices must not share suction compartments or sharedischarge compartments unless they are making the same cut. For example,two desilters may share the same fluid routing, but a desander and desiltershould not.

10. Adjustable equalizer between Solids Removal section and Addition-Suctionsection. This equalizer should normally be high except when access to theadditional volume in the solids removal section is desired.

11. No solids removal equipment should discharge into the suction pit.

Solids C

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11.6

Equipment Arrangements

Unweighted Mud - Centrifuge Processing Active System

This arrangement may be used with unweighted muds having low formulation costs, where liquid disposalcosts are negligible. Some whole mud is discarded with the hydrocyclone underflows. Typically used withenvironmentally benign water-based muds. A mud cleaner should be used only if there are insufficientdesilter cones to process the entire circulation rate; it should be run in parallel with the desilter. Blank offthe screen and discharge underflow. Use of a centrifuge will depend on the economics of the specific appli-cation.

EquipmentMedian

SeparationComments

Shale Shakers < 147 µm Capable of running 100 mesh (d50=147 microns) at maximum circulation rate.

Degasser na If required.

Desander 70 µm Processing Rate = 110% of maximum circulating rate. Discard Underflow.

Mud Cleaner 25 µm Use as a desilter if required to achieve 110% of circulation rate. Run in parallel with other desilter manifolds.

Desilter 25 µm Total Processing Rate (including mud cleaner cones) = 110% of maximum circulating rate. Discard Underflow.

Centrifuge 4 µm Process at least 25% of maximum circulating rate. High G, high capacity machine. Discard Cake (Solids).

Tank D

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11.7

Figure 10.8 Unweighted Mud - Centrifuge Processing Active System

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11.8

Unweighted Mud - Centrifuge Processing Hydrocyclone Underflow

Used to reduce liquid discharged with cuttings while maintaining high separation efficiency. This arrange-ment is preferred when the liquid phase is expensive or when free liquid discharge must be limited. Hydro-cyclones concentrate solids to centrifuge. Use caution when processing abrasive desander underflow; itmay cause premature centrifuge wear. Centrifuge should process in excess of hydrocyclone underflowrate, with makeup mud from the active system. Refer to the centrifuge chapter for details of feed compart-ment design and routing.

EquipmentMedian

SeparationComments

Shale Shakers < 147 µm Capable of running 100 mesh (d50=147 microns) at maximum circulation rate.


Desander 70 µm Processing Rate = 110% of maximum circulating rate. Underflow to Centrifuge.

Desilter 25 µm Processing Rate = 110% of maximum circulating rate. Underflow to Centrifuge.

Centrifuge 4 µm Processing Rate > Hydrocyclone underflow rate.High G, high capacity machine. Feed from hydrocyclone underflows, plus active system. Cake (wet solids) are discarded.

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11.9

Solids C

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11.10

Figure 10.9 Unweighted Mud - Centrifuge Processing Hydrocyclone Underflow

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11.11

Unweighted Mud - Centrifuge Processing Mud Cleaner Underflow

Recommended when large sections of sand are expected and free liquid must be recovered fromdesander underflow. The mudcleaner screen receives desander underflow. Sand is removed by the mudcleaner screen. Screen unders are processed by the centrifuge. Best alternative is to provide enoughshale shakers to screen down to desander separation efficiency (74 microns) or use full size shaker to pro-cess cone unders.

EquipmentMedian

SeparationComments

Shale Shakers 147 µm Capable of running 100 mesh (d50=147 microns) at maximum circulation rate.


Desander 70 µm Processing Rate = 110% of maximum circulating rate. Underflow to mud cleaner screen.

Mud Cleaner 25 µm Total processing rate should exceed maximum circulating rate. Both desander and mud cleaner cone underflows screened before processing by centri-fuge.

Centrifuge 4 µm Processing Rate > Hydrocyclone underflow rate.High G, high capacity machine. Feed from hydrocyclone underflows, plus active system. Discard Cake (wet solids) are discarded.

Solids C

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11.12

Tank D

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11.13

Figure 10.10 Unweighted Mud - Centrifuge Processing Mud Cleaner Underflow

Solids C

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11.14

Weighted Water-Based Mud - Single-Stage Centrifuging (Barite Recovery)

This is the standard equipment arrangement for weighted water-based muds when fluid costs are low andliquid discharge is permitted. The mud cleaner may be used when the shakers cannot screen down to 200mesh, but monitor barite losses. The centrifuge removes liquid and colloidal solids while recovering barite.Low centrifuge feed rates at high g-force and continuous processing are recommended to maximize bariterecovery.

Note: Refer to the Dewatering chapter for addition of chemically-enhanced dewatering unit to this system.

EquipmentMedian

SeparationComments

Shale Shakers > 74 µm Capable of screening to 200 mesh at maximum circulation rate. Monitor solids discharge for barite content.


Mud Cleaner 74-100 µm Run only if insufficient shaker capacity. 150 mesh screens recommended. Monitor screen discharge for barite content.

Centrifuge 4 µm Process 10-15% of circulation rate. Return solids to well-agitated compartment, upstream of addition section. Dilute feed. Discard centrate.

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11.15

Solids C

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11.16

Figure 10.11 Weighted Water-Based Mud - Single-Stage Centrifuging (Barite Recovery)

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11.17

Weighted Mud - Two-Stage Centrifuging

This arrangement is used when liquid discharge must be minimized. The first centrifuge operates as a bar-ite recovery unit. The second centrifuge, operating at maximum g-force, processes the centrate (overflow)from the barite recovery centrifuge. The solids are discharged and the centrate is returned to the activesystem. Colloidal solids are not removed.

EquipmentMedian

SeparationComments

Shale Shakers > 74 µm Screen with finest mesh possible, down to 200 mesh (d50=74 microns) at maximum circu-lation rate. Monitor solids discharge for barite content.


Mud Cleaner 74-100 µm Run only if insufficient shaker capacity. 150 mesh screens recommended. Monitor solids discharge for barite content.

Centrifuge #1 Barite recovery mode, high capacity machine.Return barite to well-agitated compartment upstream of addition section.Dilute feed.Run at highest G-force conditions will allow.Centrate to centrifuge #2.

Centrifuge #2 4 µm Run at maximum rpm, high-G machine.Discard solids. Return centrate to active system.

Solids C

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11.18

Tank D

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11.19

Figure 10.12 Weighted Mud - Two Stage Centrifuging



11.20

Complete System Layout For Both Weighted and Unweighted Mud

In many cases, multiple suction and discharge locations cannot be avoided. Forexample, centrifuges that will process both unweighted and weighted systemsmust be located to permit routing both the cake and centrate streams to either theactive system or to discharge. The following schematics show the fluid routingrequirements for a solids removal system which must process either unweightedor weighted mud.

Note: The centrifuge to be used for barite recovery must be positioned so the sol-ids may be routed either to discharge (unweighted) or returned to the activesystem (weighted mud). Use a high capacity machine for treating outcoarse desilter underflows or recovering barite. The second unit should bea high-G machine capable of removing fine solids. If only one machine isused, it should be a high-G unit.

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11.21

Solids C

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11.22

Figure 10.13 Generic - Complete System



11.23

Summary

• The mud pits must contain enough usable mud to maintain mud propertiesand to fill the hole during a wet trip at maximum depth.

• The active circulating system is divided into two sections: Solids Removal andAddition-Suction. The purpose of each is self-explanatory. Each section is fur-ther divided into enough compartments to carry out its designed function.Additional tankage includes the slug tank for mixing and pumping small pills,the trip tank for accurately metering pipe displacement during trips, and thepremix tank discussed in Chapter 10, Addition/Mixing Systems.

• The best compartment shape is round with a conical bottom, followed bysquare with a V-bottom. Each must have enough surface area to allowentrained air to break out.

• Equalization height between compartments will depend upon the duty of thecompartment. Refer to the discussion in this chapter for specific recommen-dations.

• The sand trap, located under the shale shakers, is the only settling compart-ment and should not be used in closed loop systems.

• Equipment arrangements for a variety of unweighted and weighted muds areillustrated in this chapter. Also included is a complete system arrangementwhen both unweighted and weighted muds must be processed during thecourse of the well.



11.24

“Proprietary: - for the exclusive use of Chevron Corporatiom and other wholly owned subsidiaries of Chevron Corporation.”

12.1

Chapter 12. Dewatering Systems

The use of on-line closed loop circulating systems to achieve drilling waste mini-mization is gaining popularity both in the domestic U.S. market and in other areasaround the world. The recent introduction of dewatering devices to further closethe loop of drilling fluid circulating systems and to dewater reserve pits is derivedfrom technology used in the industrial and sanitary waste treatment industries.

The optimization of solids control equipment has been of primary concern to thedrilling industry for many years. However, the emphasis in the past has been toutilize the solids control equipment to help optimize mud properties in order tocontrol such variables as solids content, solids distribution, rheology, and fluidloss control. These properties affect important drilling parameters such as rate ofpenetration, stuck pipe, borehole stability, formation damage, and drilling costs.Because these objectives did not include entirely closing the circulating loop, sig-nificant volumes of liquid drilling wastes were generated. The recent advent ofmore stringent environmental regulations and the better understanding of the eco-nomics of running a 100% efficient closed loop system has resulted in the intro-duction of dewatering technology to the drilling industry.

The term “closed loop” has been used quite freely in the drilling industry todescribe various solids control layouts and drilling practices. In the context of thisdiscussion, a closed loop system is one where all excess mud from either dilutionor effluent from conventional solids control equipment is further processed usingchemically-enhanced separation technology. This results in all solids beingremoved from the waste drilling mud while the liquid portion is recycled back tothe active system. Ideally, all other liquid wastes generated on location are pro-cessed and also recycled. Using this technology often eliminates the need for areserve pit.

There are numerous applications for a closed loop dewatering system. Reasonsmay include restrictive environmental regulations, small locations where reservepit space is limited, or locations where water is in short supply.

The options are limited for an operator faced with a zero discharge or reduced dis-charge scenario. A simple solution still widely used today is to haul off all cuttingsand waste fluids to an offsite disposal facility. This can be expensive and therecould be costs involving future liability if the disposal site is later declared a haz-ardous area. In certain areas the cuttings and waste fluids can be spread onnearby land. This can be a cheaper option but availability, meeting environmentalspecifications, and long-term liability can be a problem. Pumping waste fluid backdown into the formation is sometimes used, but possible contamination of ground-water worries some regulators. Whatever method is used to dispose of drilling



12.2

wastes, using good waste management techniques will usually result in substan-tial cost reductions. Savings of up to 50% have been realized on disposal and rec-lamation costs as well as reduced drilling days by operators using sound wastemanagement practices.

The use of chemically enhanced dewatering devices is proving to be a reliablemethod of reducing wastes generated at the rig site. Several dewatering deviceshave been investigated as possible candidates for oilfield application, including abelt press, horizontal belt/vacuum filter, a vertical screwpress, and decanting bowlcentrifuges.

Economic Overview

Dewatering flocculation units are practical devices for the control of solids and liq-uids. They are not, however, cost effective in all situations. Since they are oftenused as an alternative to disposing of liquid mud, operating the unit in this modewould have to be less expensive than the disposal costs. If an inexpensive mud isto be discarded as waste on location (with no associated treatment costs), it isunlikely the dewatering unit would be beneficial. However, if the liquid phase isexpensive, or the mud has to be disposed of at a commercial waste disposal site,then the use of the dewatering equipment should be investigated further to proveits feasibility.

Some of the costs that should be considered when determining whether or not thedewatering unit will be cost effective are as follows:

• Disposal Costs: The proper use of the dewatering unit can negate the neces-sity to dispose of liquid mud until the well is completed. Solids will have to bedisposed of in a manner according to local or national government regula-tions. If the estimated disposal costs without a dewatering unit are higher thanthe costs associated with the dewatering unit, then the dewatering unit is defi-nitely cost effective.

• Centrate Cost: If the centrate (filtrate) of the liquid water base mud is expen-sive to formulate (i.e., saturated brine, glycol, etc.), then recovering the liquidcould be extremely beneficial and cost effective.

• Solids Control Equipment: The efficiency of the overall solids removal equip-ment will increase considerably with the use of a dewatering system. Thedewatering unit will remove almost all of the insoluble solids and very little ofthe dissolved solids. Other than makeup volume, usually no additional dilution(that would otherwise be needed without the use of the dewatering system),will be required unless lost circulation occurs.

• Location Costs: The use of the dewatering unit will allow smaller reserve pitsto be built, thereby decreasing overall location costs. Since no liquid will be

Dewatering Systems


12.3

discarded, reserve pits can be constructed to accommodate only solid mate-rial. Often reserve pits can be eliminated completely if solids can be immedi-ately spread on the land or taken off site for disposal.

To determine the cost effectiveness of using a dewatering closed loop system, fol-low this logical order when calculating the economics:

First, look at the costs that would be incurred if a dewatering unit was not used:

1. Choose the solids control equipment that will be needed and determine thecosts that will be incurred. Estimate the overall efficiency of this equipment asthis will be needed to determine how much of the drilled solids will beremoved.

2. Calculate the total solids per interval that will be generated (including wash-outs) as a result of the hole drilled. Determine the amount of solids that will beremoved with the solids control equipment and the cost of disposing of thesesolids. Disposal rates at commercial facilities usually do not vary significantlybetween the mud and cuttings. Transportation rates, however, will differ con-siderably if road transportation is used. Keep in mind that the solids generatedwill not be dry, but rather will contain a significant amount of liquid.

The amount of liquid will usually depend on the size and type of solids gener-ated and can be determined through analysis. For estimation purposes, a rea-sonable solids-to-liquid ratio is 1:1 or 50% liquid by volume.

3. Calculate the dilution volumes that will be required to maintain the desireddrilled solids content. The efficiency of the solids control equipment selectedwill play a crucial part in determining this number. Since this volume will haveto be disposed of before dilution can be added, use this volume to determinethe liquid disposal costs. Disposal rates will usually range from $5.00 to$10.00 per barrel (plus transportation) depending on the type of mud beingdiscarded.

Next, look at the costs of the dewatering, closed loop system:

4. Dewatering system costs include the equipment, personnel, and the chemi-cals used in the flocculation process. Equipment and personnel costs are rel-atively fixed, but chemical usage will vary and will be the most difficult toquantify. The chemical costs will depend on the product cost and the concen-trations required to achieve the correct flocculated state. Flocculent concen-tration increases significantly as the solids content of the feed fluid increases,particularly when the measured solids is above 5% by volume. Figure 12.1graphically illustrates this point as the amount of flocculent needed increasedfrom 325 ppm at 4.85% solids to almost 600 ppm at 5.1% solids to 750 ppm at5.5% solids. This demonstrates the need for good solids removal abilityupstream of the dewatering unit.



12.4

Different mud systems will also require different flocculating polymer concen-trations. Dispersed muds need more flocculent to achieve desired results thando nondispersed. Optimum concentrations of the flocculent are needed toprovide the best “floc” for the lowest price. Since any excess flocculent usedwill be returned to the mud system, keeping this concentration to a minimumis important. Elevated chemical costs can make the overall dewatering sys-tem cost prohibitive.

5. Solids disposal costs will be slightly higher when using a closed loop dewater-ing system as more solids are removed from the mud. It is assumed that thedewatering unit will be able to remove all the solids necessary to maintain thedrilled solids content at desired levels. This assumption is based on the factthat enough solids removal equipment is utilized to help the dewatering unitachieve this goal. If these solids are to be spread on location, add the costs ofthe spreading. If the solids are to be disposed of at a commercial facility, addthe costs of disposal, plus transportation. Assume all liquids not associatedwith the solids can be recycled back to the mud system or dewatering unit.

6. Recovering a costly centrate can be a definite economic saving. If the mud inuse is a basic inexpensive fresh water system and if fresh water is readilyavailable, the liquid phase cost will be minimal. However, if the centrate con-tains salts, glycols, or expensive polymers, recycling this liquid must beincluded in the economics and may be a significant factor in deciding whetheror not to use a closed loop system with a dewatering unit. Figure 12.2 clearly

Figure 12.1 Effect of Solids on Flocculent Concentration. Flocculent consumption can increase dramatically as solids concentrations increase.

Floc

cule

nt C

once

ntra

tion

, PP

M

Dewatering Systems


12.5

shows that the amount of material returned in some centrates can be signifi-cant. As shown, a considerable amount of polymer, fluid loss control agents,and soluble salts return to the active system in the centrate. As expected, bar-ite, bentonite and low gravity solids are almost totally removed and discardedas waste. Figure 12.3 shows an example of the cost of the chemicals sal-vaged by the dewatering unit versus the cost of the mud in use. As can beseen, a substantial portion of the mud makeup cost can be returned.

7. Subtract the portion of the location costs that would not otherwise be incurredif the closed loop system were not applied. This will normally include the prep-aration of the reserve pit system, larger location, location clean-up and backfillof pits.

After all calculations are completed, compare the costs of having a dewateringsystem versus not having one, and decide if a dewatering closed system is eco-nomically warranted. These figures may be crude at first, but with more precisedata and increased experience, the values will become more accurate.

If the cost per barrel of dewatering is less than the cost per barrel of disposal, it isobviously economical to proceed in this direction.

Figure 12.2 Evaluation of Dewatering Centrate. The amount of valuable material returned in the centrate can be significant.



12.6

Monitoring Dewatering Costs and Efficiency

If it is decided that a dewatering system is warranted, monitoring the cost effi-ciency on a daily basis is imperative. To approach this, equate all costs associ-ated with the dewatering unit to a “dollar ($) per barrel of mud processed” figure.By equating all costs to $/barrel, comparisons against disposal costs can easily bemade. Figure 12.4 is a sample form that can be used to keep track of theseexpenses as well as the mud volumes processed. The contributing factors indetermining overall cost efficiency are: a) dewatering equipment, personnel andchemical costs, and b) volume of liquid processed. The centrate returned maycontribute to the cost savings as well and should be determined by multiplying thecentrate value times the volume returned.

As hole size and process volumes decrease, the cost of dewatering ($/bbl)increases. At some stage it may become evident that the dewatering cost will begreater than disposal costs. Figure 12.5 shows the interval cost per barrel of adewatering operation that lasts through five intervals. Note that the cost usuallyincreases with each subsequent interval. Hole sizes are smaller and therefore cir-culating volumes are less. At the point where the cost per barrel approaches thecost of disposal, a decision will have to be made to either remove the dewateringequipment, or treat the mud on a “batch” basis. In this example, that point isreached at the end of interval #3. Continual processing of mud in interval #4 is

Figure 12.3 Material Returned in Centrate. The value of the centrate must be considered when estimating dewatering economics.

Dewatering Systems


12.7

more costly than disposing of the liquid volume. Two options are available:(1) Cease dewatering operations, or (2) place the unit on standby until a sufficientvolume is accumulated to warrant the operating cost to dewater. As stated before,the $/bbl efficiency of dewatering can be decreased either by lowering the costs($), or increasing the processed volume (bbl). The economics of maintaining theunit on standby will depend on the standby rate and anticipated frequency of use.

Figure 12.4 Form for Calculating Dewatering Efficiency



12.8

Equipment Selection

Dewatering Devices

A typical dewatering system consists of a polymer hydration and storage section,mixing and injection manifold, injection and transfer pumps and a centrifuge forseparation of liquid and solids (Figure 12.6).

These systems, when operated correctly have the capability of taking a stream ofmud from the active system or storage and separating all of the solids from the liq-uid. Depending on the mud type and the solids distribution in the feed (influent),the liquid content will average 30 to 50% by volume after separation.

With this ability for separation, the dewatering device makes a very efficient pieceof solids control equipment. If the volume capability of the unit is adequate, nodilution in excess of circulating maintenance will be required. Since no free liquidis discharged, the loop is considered to be closed.

Figure 12.5 Dewatering Costs, by Interval. Intervals 4 and 5 are uneconomic to dewater in this example since the liquid disposal cost is less.

Dewatering Systems


12.9

On the unweighted sections of the hole, the dewatering unit should be operatingon the active system, processing mud after it has passed the other solids controlequipment. If a high volume centrifuge is being used for solids removal on theunweighted section, it may be advisable to process the effluent of this unit. Thiswill lower the solids load to the dewatering unit and decrease polymer consump-tion. If the centrifuge is not capable of generating enough effluent to keep up withthe solids removal required, then treating some of the active system should bedone. Note also that in some cases, flocculation may become more difficult whenprocessing only centrifuge effluent in unweighted mud. Laboratory tests con-ducted at APR showed that the presence of some larger solids will aid the floccu-lation process. Therefore, the addition of some whole mud to the centrifugeeffluent is likely beneficial to the dewatering process.

Figure 12.6 Dewatering System Equipment. This schematic shows a typical dewatering config-uration for a weighted mud.



12.10

On weighted systems where a barite recovery centrifuge is in operation, the dew-atering unit should process the effluent of this unit. Because of this type of equip-ment arrangement, no hesitation is necessary in operating the centrifuge foradjustment of the mud properties. The effluent that is normally a disposal problemcan now be treated and returned to the active system.

Waste Management

The operator is responsible for all wastes generated on the drilling location.Although drilling wastes are not generally regarded as hazardous, the disposalmethod must be in compliance with applicable regulations. These regulations andeconomic considerations will ultimately dictate how the drilling waste streamsmust be handled. Efficient solids control and chemically-enhanced dewateringsystems can greatly reduce the volume of liquid drilling waste, but they are only apart of a comprehensive drilling waste management plan. The optimum approachis one that first reduces the quantity of waste, assures the waste is nonhazardous,and then selects the least expensive, acceptable disposal method.

An effective drilling waste management plan recognizes that local environmentalregulations and individual well drilling conditions will affect the design, implemen-tation and economics of the solids control and waste handling system. There is nosingle system design that can be recommended for all cases. However, the fol-lowing approach can help implement a solids control and waste handling systemwhich is economically and environmentally sound:

1. Know the regulations applicable to the area. Select a safe and economicwaste disposal process and drilling fluid that is compatible with these regula-tions. The potential long-term liability of the waste disposal options must alsobe considered, especially when waste will be hauled off to a central commer-cial disposal facility.

2. Identify and isolate all potential waste sources both on the location and in thesurrounding environment. This can include location or deck drainage, effluentfrom sewage processing, drilling fluids, drilled cuttings, cement returns andfluids produced from well tests.

3. Check the drilling plan to be sure that all elements of the solids control planare compatible throughout the entire drilling stage.

4. Design the location layout, grading plan and reserve pits to support the solidscontrol and waste handling plan. Allow for the proper segregation of wastestreams to avoid contamination.

Dewatering Systems


12.11

5. Evaluate the drilling contractor’s existing solids control equipment and mudpits. Modify and/or add to the contractor’s solids removal system as neces-sary to achieve the most efficient and cost effective system.

6. Select drilling fluids and additives that are compatible with the waste disposalmethod and the drilling requirements.

7. Coordinate your solids and fluid disposal plans with regulatory authorities. Besure advance approval is obtained to handle all disposal as it occurs duringthe drilling of the well.

During the implementation phase, the following steps can help ensure that theoperation proceeds according to the plan:

8. Inspect the solids equipment piping and fluid routing well before spud to pro-vide enough time to make corrections.

9. Educate the rig personnel. The best solids control equipment is of little value ifit is not run correctly. Use a team approach. Make sure the rig personnel com-pletely understand the system and its purpose. Stress any limitations on dis-charge.

10. Monitor solids removal efficiency. Measure the amount of water added to thesystem with a water meter. Analyze the solids contents of the solids controlequipment discharge streams. Monitor the efficiency of the dewatering unit.Maintain performance data records on individual solids removal equipmentand the entire system.

11. Follow up on disposal logistics. Plan ahead for regulatory permitting require-ments.

12. Reinspect the solids control system arrangements between drilling intervals tobe sure that the required changes are made in fluid routing and equipmentoperation. Conduct additional rig personnel training.



12.12

Summary

• Chemically-enhanced dewatering units are increasing in popularity due tomore stringent environmental regulations and the incentive of reduced poten-tial, long-term liability associated with drilling wastes. Use has also increasedbecause of a better understanding of the economic benefits attributable toimproved solids removal efficiency.

• Alternatives to dewatering include hauling the waste to a central disposalfacility, land spreading, or injecting the liquid and/or solid waste downhole intoa suitable formation.

• In this context, the term “closed-loop” is defined as one where all excess mudfrom either dilution or solids control equipment effluent is further processedusing chemically-enhanced dewatering technology to minimize liquid wastevolumes. Applications include locations with environmental restrictions, smalllocations where reserve pit space is limited, or where water is in short supply.

• The economics of dewatering will depend upon the cost of disposal, liquidcentrate value, solids control equipment efficiency, and location costs. A pro-cedure is outlined in this chapter to determine the cost effectiveness of dewa-tering.

• Monitoring the cost efficiency of dewatering on a daily basis is imperative. Allcosts associated with the dewatering unit should be converted to “dollar ($)per barrel of mud processed” figure. A sample form for tracking dewateringefficiency is provided.

• A typical dewatering system consists of a polymer hydration and storage sec-tion, mixing and injection manifold, injection and transfer pumps, and a centri-fuge for separation of liquid and solids. The liquid content of the centrifugecake will average 40 to 50%.

• On unweighted muds, the dewatering unit should be rigged up to processboth the centrifuge centrate with additional makeup as required from theactive system. Laboratory tests indicate that the presence of some larger sol-ids will aid the flocculation process. On weighted systems, the dewatering unitshould process the effluent of barite-recovery centrifuge. In both cases, therecovered liquid can be treated and returned to the active system.

• Successful drilling waste management requires thorough planning. No singlesystem design is optimum in all instances. An approach is provided to helpimplement a solids control and waste handling system that is both economi-cally and environmentally sound. These guidelines do not detail specificwaste handling or remediation procedures, but provide a checklist of issuesthat must be considered when planning and operating the system.


2.1

Chapter 2. Economics

The impact of good solids control can be very significant and can lead to substan-tial cost savings, but often there is reluctance to invest in solids control for the fol-lowing reasons:

1. Many of the benefits are indirect and the savings are hard to quantify.

2. Methods to economically justify solids control equipment were not available.

3. Techniques to measure performance are limited.

4. Disappointing results from ill-chosen or incorrectly-operated equipment.

Although the benefits from good solids control are numerous, the cost savings arenot apparent in normal drilling cost accounting. For example, the savings due toreduced trouble costs and improved penetration rate, although substantial bene-fits, cannot be accurately calculated. Usually the drilling fluid gets most of thecredit (or blame) since mud material consumption is easily tracked and the mudproperties are the only direct indication of solids control system performance. In arealistic sense, the mud and the solids control equipment are integral parts of onesystem. One cannot plan the mud without considering the solids control systemand vice versa. This does not mean that the benefits of good solids control prac-tices cannot be measured.

Economic Justification

Penetration Rate

The impact of solids control on penetration rate is best depicted by Figure 2.1.This has become somewhat of a classic illustration of the benefits of a low solidscontent mud. For example, a reduction in average solids content from 4.8%(9.0 ppg) to 2.6% (8.7 ppg) results in a 15% reduction in total rig days. Given a10,000 ft well costing $700,000 excluding mud cost, the estimated savings couldreach $100,000. If even half of these savings were realized, it would more thanpay for the best solids removal system available.

In soft rock country such as the Gulf Coast, efficient solids removal can reduce theneed to control-drill by limiting required dilution rates to manageable levels andreducing operational problems due to overloaded solids removal equipment. Thebenefits from efficient solids removal, e.g., “low-silt” muds, have been docu-


“Proprietary: - for the exclusive use of Chevron Corporation and other wholly owned subsidiaries of Chevron Corporation .”

2.2

mented for Gulf Coast drilling since the mid-60s when hydrocyclone use was firstadvocated.

Dilution Rate

Solids removal efficiency directly impacts dilution costs. When dilution water isadded to the system, three costs are incurred simultaneously:

1. Dilution water cost.

2. Cost of additives to maintain stable mud properties.

3. Disposal cost.

The savings due to improved penetration rates and reduced trouble time, whilereal, cannot be reliably predicted as justification for improved solids control equip-ment. In many cases however, the economic advantages due to reduced dilutionand disposal costs are more than enough to justify expenditures for additionalequipment. The economic benefits in terms of mud consumption and disposal canbe determined through a simple mass balance analysis: Removing a given per-centage of drilled solids will result in a certain dilution volume to maintain the

Figure 2.1 Effect of Solids Content on Drilling Performance. The benefits of low solids con-tents are most apparent at less than 5% solids.

Economics


2.3

desired maximum concentration of drilled solids in the mud. The relevant parame-ters and their symbols used in the calculations are listed below.

Economic Analysis Calculations

First, the volume of cuttings generated in a given interval must be calculated:

For a given percent of drilled solids removed, X, the required dilution volume iscomputed by:

Solids Control Economic Analysis Parameters

Vc = Volume of drilled solids generated, bbls

Vi = Initial volume in tanks, previous hole/casing, bbls

Vf = Final volume in tanks, previous hole/casing, bbls

Vd = Volume of addition/dilution fluid required, bbls

Vlw = Volume of liquid waste to be disposed, bbls

Vsw = Volume of wet solids to be disposed, bbls

Vt = Total volume of solids and liquids to be disposed, bbls

ki = Initial concentration of drilled solids, vol. fraction

ks = Maximum volume fraction of drilled solids, vol. fraction

X = Drilled solids removed by equipment, vol. fraction

Y = Liquid associated with the cuttings, bbl/bbl

D = Hole diameter, in.

L = Section length, ft

W = Washout, vol. fraction

ρd = Density of dilution fluid, ppg

ρc = Density of drilled cuttings, ppg

ρi = Mud weight at the start of the section, ppg

ρe = Desired mud weight, end of section, ppg

Vc 0.000971 D2 L W×××=

Vd

1 ks–( )ks

------------------- 1 X–( )Vc Vi–k iks-----V i+=



2.4

The following equations may be used to calculate the solids removal efficiency,Xc, and the associated dilution volume required to discharge only wet solids:

The required mud weight (density) of the dilution volume, Vd, is based on thespecified starting and ending densities and is calculated by:

The total volume of solids and liquid generated in an interval is given by:

The wet solids volume, Vsw, and liquid volume, Vlw, discharged while drilling theinterval is computed by:

The remaining circulating volume includes the volume of solids not removed bythe solids removal equipment. Since the solids are assumed to be too fine to beremoved by the solids control equipment, their volume is counted as liquid volumefor disposal purposes.

When the entire circulating system is to be discharged at the end of the interval,the total liquid for disposal is calculated by:

Once the waste volumes are calculated, the total dilution and disposal cost for theinterval may be determined by estimating the equipment rental cost and thecost/bbl for addition/dilution and liquid/solids disposal:

1. Solids Control Equipment Cost

- Estimate rental, transport, service, and maintenance (e.g., screens) costfor the interval.

XcVc ks Vf Vc+( ) k iV i+–

Vc 1 ksY+( )----------------------------------------------------------=

Vd Vf Vi–( ) XcVC 1 Y+( )+=

ρd ρe

V iVd------ ρe ρi–( )

VcVd------ 1 X–( ) ρc ρe–( )–+=

Vt V i Vc Vd+ +=

Vsw XVc 1 Y+( )=

Vlw Vt Vf Vc Vsw+ +( )–=

V lw Vt Vsw–=

Economics


2.5

2. Addition/Dilution Cost

- Estimate the cost/bbl by including purchase cost for dilution liquid, truck-ing, and additive cost.

3. Liquid/Solids Disposal Cost

- Estimate the cost/bbl by including hauling, disposal, treatment, reserve pitconstruction and reclamation.

Example Calculations

Interval Data:

Vc = Volume of drilled solids generated, bbls

Vi = 360 bbls

Vf = 360 bbls

Vd = Volume of addition/dilution fluid required, bbls

Vlw = Volume of liquid waste to be disposed, bbls

Vsw = Volume of wet solids to be disposed, bbls

Vt = Total volume of solids and liquids to be disposed, bbls

ki = 0 (fresh mud, no drilled solids)

ks = 0.06 (6% maximum drilled solids)

X = 0, 0.1, 0.5 (3 cases)

Y = 1.0 (1:1 solids to liquid ratio in wet solids discharge)

D = 12.25 in.

L = 1600 ft

W = 1.10 (10% washout)

ρd = Density of dilution/addition fluid, ppg

ρc = 2.6 x 8.34 = 21.68 ppg

ρi = 8.6 ppg initial mud weight

ρe = 9.4 ppg final mud weight

Dilution Cost: $5.00/bblLiquid Waste Cost: $3.00/bblSolid Waste Cost: $5.60/bbl



2.6

Calculations:

1. Cuttings volume:

2. Dilution volumes for each solids removal efficiency:

For X = 0.0

For X = 0.1

For X = 0.5

3. Dilution density:

In this example, the required density will not change with each case. The param-eters for X=1 are chosen for illustration purposes.

VC 0.000971 D2 L W×××=

Vc 0.000971 12.25( )21600( ) 1.1( ) 256 bbls= =

Vd

1 ks–( )ks

------------------- 1 X–( )Vc Vi–=k iks-----Vi+

Vd1 0.06–( )

0.06------------------------ 1 0–( )256 360–

00.06---------- 360( )+ 3650 bbls= =

Vd1 0.06–( )

0.06------------------------ 1 0.1–( )256 360

00.06---------- 360( )+– 3250 bbls= =

Vd1 0.06–( )

0.06------------------------ 1 0.5–( )256 360–

00.06---------- 360( )+ 1645= = bbls

ρd ρe

ViVd------ ρe ρi–( )

VcVd------ 1 X–( ) ρc ρe–( )–+=

ρd 9.4=360360--------- 9.4 8.6–( )

2563250------------ 1 0.1–( ) 21.7 9.4–( )–+ 8.6 ppg=

Economics


2.7

4. Solids removal efficiency and dilution volume to achieve zero whole-mud dis-charge while drilling:

5. Summary of waste disposal volumes:

6. Cost estimate for each case, discarding total liquid volume (last column inStep 5):

The example illustrates how an increase in equipment costs to improve solidsremoval efficiency is justified by the savings in addition/dilution and disposalcosts, even without considering savings attributable to higher penetration rates orreduced trouble costs.

Total Vol-umebbls

Wet Solidsbbls

Liquid While Drillingbbls

Total Liquidbbls

X = 0.00 4266 0 3650 4266

X = 0.10 3866 51 3199 3815

X = 0.50 2261 256 1389 2005

X = 0.81 1030 414 0 616

Drilled Solids Removed

Equip-ment Costs

Addition/Dilution Costs

Disposal Costs Total CostsSolids Liquids

0% $0 $18,250 $0 $12,678 $30,928

10% $100 $16,250 $286 $11,445 $28,081

50% $500 $8225 $1434 $6015 $16,174

81% $5000 $2075 $2318 $1848 $11,241

XcVc ks Vf Vc+( )– k iVi+

Vc 1 ksY+( )----------------------------------------------------------=

Xc256 0.06 360 256+( )– 0 360( )+

256 1 0.06+ 1.0×( )------------------------------------------------------------------------------ 0.81= =

Vd Vf V i–( ) XcVc 1 Y+( )+=

Vd 360 360–( ) 0.81 256( ) 1 1+( )+ 415 bbls= =



2.8

Solids Control Economics and Performance Program (SECOP)

A natural question arising from the economic analysis exercise is "What equip-ment will I need to achieve the optimum solids removal efficiency?" It is alsoapparent that the determination of an economically-optimum solids control systemcan be a time consuming, iterative process. The equipment costs to achieve theminimum required dilution volume (commonly called a "closed-loop" mud system)may not be economic in all cases. It may not even be physically possible withavailable mechanical solids removal technology. The Solids Control Economicand Performance Analysis Program (SECOP) was developed at APR to assistdrilling personnel in the optimum selection of solids control equipment. It is avail-able as an Integrated Drilling Assistance Program for use on the PC. The disketteprovided with this manual contains an earlier, interactive version of the program.This program analyzes:

1. The economics of solids control in terms of potential savings in mud dilutionand disposal costs versus the percent drill solids removed.

2. The performance of solids control equipment. It predicts the drill solidsremoved by each piece of equipment selected.

3. The loss of weighting material and mud from each piece of equipment forweighted muds and the predicted recovery from barite-recovery centrifuging.

4. The performance for different equipment options to determine the most effec-tive solids control system for drilling a well.

SECOP predicts only the savings in mud and disposal costs. As discussed previ-ously, no model exists to predict additional savings from higher penetration ratesand lower trouble costs that result from effective solids control. The program usesmodels developed as a result of extensive equipment testing at APR to predictindividual equipment and total system performance. The overall economics cal-culations are based on the same equations described above. A complete descrip-tion of the program is provided in the IDAP reference manual.

The recommended application of SECOP is to match the performance history ofthe solids control system for an offset well. This can be done by selecting theproper lithology and resulting particle size distribution which matches the mud vol-

Economics


2.9

umes and costs for the offset well. Once a lithology match has been made, differ-ent equipment options may be tried to find the most economically-effective solidscontrol equipment for the proposed well.

A successful economic analysis for future wells will depend on determining a rep-resentative particle size distribution from the offset well which, in turn, is depen-dent upon having accurate records of dilution volumes and equipment operation.This emphasizes the importance of accurately metering water additions andequipment performance while drilling. SECOP may then be used to monitorequipment performance and establish representative particle size distributions forfuture economic analysis and equipment selection.

Monitoring System Performance

The API Recommended Practice 13C contains a field method for evaluating thetotal efficiency of the drilling fluid processing system in water-based fluids. As withany performance analysis, this procedure depends upon accurate dilution volumeinformation. The API procedure uses the dilution volume over a given interval tocompute a dilution factor, DF, which is the volume ratio of actual mud built to muddilution required to maintain a desired solids concentration with no solids removalequipment. The dilution factor is used to determine the total solids removal effi-ciency of the system. This total efficiency can then be used in SECOP to establisha representative particle-size distribution for further analysis and equipment per-formance predictions.

API Procedure for Evaluating Total Efficiency of Solids Control Systems (Water-Based Muds)

1. Over a desired interval length, obtain accurate water additions and retort data.

2. From the retort data, calculate:

- The average drilled solids concentration in the mud, ks.

- The average water fraction in the mud, kw.

3. Calculate the volume of mud built, Vm:

4. Calculate the volume of drilled solids, Vc:

VmVwkw-------=

Vc 0.000971 D2 L W×××=



2.10

5. Calculate the dilution volume required if no solids were removed, Vd:

6. Calculate the dilution factor, DF:

7. Calculate the total solids removal performance, Et:

Multiply by 100 to calculate as a percentage.

The accuracy of the API procedure depends on a relatively constant solids con-centration in the mud, constant surface circulating volume, and consistent averag-ing techniques over the interval of interest. Regardless, the total solids removalperformance should be reported at frequent intervals to facilitate solids controlanalysis and planning for future wells.

Example Calculation

Interval Data:

Calculations:

1. Calculate the volume of mud built, Vm:

2. Calculate the volume of drilled solids, Vc:

Water Added, Vw 1481 bbl

Average Water Fraction, kw 0.9

Interval Length, L 1600 ft

Bit Diameter, D 12.25 in.

Washout, W 10%

Average Drilled Solids Concentration, ks 0.06

VdVcks------=

DFVmVd--------=

Et 1 DF–( )=

VmVwkw------- 1481

0.9------------ 1645 bbls= = =

Vc 0.000971 D2 L W×××=

0.000971 12.25( )21600( ) 1.1( )=

256 bbls=

Economics


2.11

3. Calculate the dilution volume required if no solids were removed, Vd:

4. Calculate the dilution factor, DF:

5. Calculate the total solids removal performance, Et:

Expressed as a percentage:

Et = 61.4%

VdVcks------ 256

0.06---------- 4267 bbls= = =

DFVmVd-------- 1645

4267------------ 0.386= = =

Et 1 DF–( ) 1 0.386– 0.614= = =



2.12

Summary

• The economic advantages of good solids control practices, while real, areusually difficult to predict in terms of improved penetration rates and reducedtrouble time. However, savings in dilution and disposal costs can be predictedand are often ample justification to invest in improved solids control equip-ment.

• Solids removal efficiency directly impacts the cost of dilution, material con-sumption and waste disposal. A simple mass balance approach may be usedto predict total dilution and waste volumes as a function of solids removal effi-ciency. Example calculations show how an investment in solids control equip-ment may be easily justified by the savings realized from reducedaddition/dilution and disposal costs.

• The API Recommended Practice 13C contains a field method for monitoringsystem performance in the field. This method depends upon accurate dilutionvolume monitoring to determine total solids removal efficiency. The API pro-cedure and example calculations are presented in this section.


3.1

Chapter 3. Shale Shakers

The shale shaker can be regarded as the “first line of defense” in the solidsremoval system. It has proven to be a simple and reliable method of removinglarge amounts of coarse, drilled cuttings from the circulating system. The shaleshaker’s performance can be easily observed; all aspects of its operation are visi-ble. Shale shakers provide the advantage of not degrading soft or friable cuttings.When well-operated and maintained, shale shakers can produce a relatively drycuttings discharge.

In unweighted muds, the shale shaker’s main role is to reduce the solids loadingto the downstream hydrocyclones and centrifuges to improve their efficiency. Inmuds containing solid weighting agents such as barite, the shale shaker is the pri-mary solids removal device. It is usually relied upon to remove all drilled cuttingscoarser than the weighting material. Downstream equipment will often remove toomuch valuable weighting material.

Enough shakers should be installed to process the entire circulating rate with thegoal of removing as many drilled cuttings as economically feasible. Given theimportance of the shale shaker, the most efficient shakers and screens should beselected to achieve optimum economic performance of the solids control system.

Shaker performance is a function of:

• Vibration pattern

• Vibration dynamics

• Deck size and configuration

• Shaker screen characteristics

• Mud rheology (plastic viscosity)

• Solids loading rate (penetration rate, hole diameter)

The impact of each is discussed in detail in this chapter. Guidelines for shaker andscreen selection are also provided.

Principle of Operation

Simply stated, a shale shaker works by channeling mud and solids onto vibratingscreens. The mud and fine solids pass through the screens and return to theactive system. Solids coarser than the screen openings are conveyed off thescreen by the vibratory motion of the shaker. The shaker is the only solids



3.2

removal device that makes a separation based on physical particle size.Hydrocyclones and centrifuges separate solids based on differences in their rela-tive mass.

The screens are vibrated by rotating eccentrically-weighted shafts attached to thebasket. The major components of a typical shale shaker are illustrated inFigure 3.1.

Vibration Patterns

Shale shakers are classified in part by the vibration pattern made by the shakerbasket location over a vibration cycle (e.g., “linear motion” shakers). The patternwill depend on the placement and orientation of the vibrators. Four basic vibrationpatterns are possible: circular, unbalanced elliptical, linear, and balanced ellipticalmotion.

Circular Motion

As the name implies, the shaker basket moves in a uniform circular motion whenviewed from the side (Figure 3.2). This is a “balanced” vibration pattern becauseall regions of the shaker basket move in phase with the identical pattern. In orderto achieve “balanced” circular motion, a vibrator must be located on each side ofthe shaker basket at its center of gravity (CG) with the axis of rotation perpendicu-

Figure 3.1 Shale Shaker Components. These components are common to most shale shakers.

Shale Shakers


3.3

lar to the side of the basket. The Brandt Tandem is a common example of a circu-lar motion shale shaker.

Solids Conveyance and Fluid Throughput

Circular motion shakers will not efficiently convey solids uphill. Therefore, mostshakers of this type are designed with horizontal configurations. Fluid throughputis limited by the deck angle, but augmented slightly by the higher G’s normallyused (see Vibration Dynamics section). The “soft” acceleration pattern does nottend to drive soft, sticky solids, such as gumbo, into the screens.

Recommended Applications

• gumbo, or soft, sticky solids conditions

• scalping shakers for coarse solids removal

Unbalanced Elliptical Motion

The difference between circular motion and unbalanced elliptical motion is a mat-ter of vibrator placement. To achieve unbalanced elliptical motion, the vibratorsare typically located above the shaker basket. Because the vibrator counter-weights no longer rotate about the shaker’s center of gravity, torque is applied onthe shaker basket. This causes a rocking motion which generates different vibra-tion patterns to occur along the length of the basket, hence the term “unbalanced.”Refer to Appendix E, Equipment Specifications, for a list of shakers having unbal-anced elliptical motion.

Figure 3.3 illustrates how the vibration pattern may change along the length of thebasket. At the feed end of the shaker, an elliptical vibration pattern is created; theangle of vibration is pointed toward the discharge end. In this region, forward sol-ids conveyance is good. However, at the discharge end of the shaker, angle of theelliptical pattern is pointed back towards the feed end. This will cause the solids toconvey backwards unless the deck is pitched downhill at a sufficient angle toovercome the uphill acceleration imparted on the solids by the shaker motion.

Figure 3.2 Circular Motion. All areas of the basket rotate in a circular motion.



3.4

Solids Conveyance and Fluid Throughput

The downhill deck orientation restricts the unbalanced elliptical motion shaker’sability to process fluid; mud losses can be a concern. However, the deck orienta-tion is beneficial for removing sticky solids such as gumbo.


• gumbo, or soft, sticky solids conditions

• scalping shakers for coarse solids removal

Linear Motion

Linear motion is achieved by using two counter-rotating vibrators which, becauseof their positioning and vibration dynamics, will naturally operate in phase. Theyare located so that a line drawn from the shaker’s center of gravity bisects at 90° aline drawn between the two axes of rotation (Figure 3.4).

Because the counterweights rotate in opposite directions, the net force on theshaker basket is zero except along a line passing through the shaker’s center ofgravity. The resultant shaker motion is therefore “linear.” The angle of this line ofmotion is usually at 45-50° relative to the shaker deck to achieve maximum solidsconveyance. Because acceleration is applied through the shaker CG, the basketis dynamically balanced; the same pattern of motion will exist at all points alongthe shaker.

Figure 3.3 Unbalanced Elliptical Motion. The vibration pattern changes along the length of the basket.

Shale Shakers


3.5

Solids Conveyance and Liquid Throughput

Linear motion shakers have become the shaker of choice for most applicationsbecause of their superior solids conveyance and fluid-handling capacity. Solidscan be strongly conveyed uphill by linear motion. The uphill deck configurationallows a pool of liquid to form at the shaker's feed end to provide additional headand high fluid throughput capability. This allows the use of fine screens to improveseparation performance. The Derrick Flo-Line Cleaner is one example of a linearmotion shale shaker.

One drawback to linear motion shakers is their relatively poor performance in pro-cessing gumbo. The short vibration stroke length when combined with long, bas-ket lengths, uphill deck angles and strong acceleration forces tends to make thesoft gumbo “patties” adhere to the screen cloth. Some success has been reportedby using linear motion shakers with short deck lengths and horizontal or downhilldeck angles.


• All applications where fine screening is required.

Balanced Elliptical Motion

Amoco's analytical shaker dynamics model has predicted that this is the optimumvibration pattern for maximum solids conveyance. Unlike “unbalanced” ellipticalmotion, all points on the shaker basket move in phase with the identical ellipticalpattern. The model predicts that a “thin” ellipse will provide solids conveyance

Figure 3.4 Linear Motion. All areas move in a synchronous linear motion.



3.6

superior even to linear motion. Because elliptical motion provides a “softer” accel-eration pattern than linear motion, it is likely that screen life may also be improved.

A simple and commercially-viable method to achieve balanced elliptical motionhas recently been tested. The vibrators are located as shown in Figure 3.5. Thevertical orientation of the vibrators dictates the shape of the ellipse. The more thevibrators are tilted out from the shaker basket, the more circular the vibration pat-tern.

Full-scale experiments have verified analytical model predictions of improved sol-ids conveyance with a thin ellipse. In Figure 3.6, the numbers in parentheses arethe ratios of major axis length to minor axis length of the vibration patterns. Byadjusting the shape of the ellipse, solids conveyance velocity can be adjustedwithout changing deck angle or acceleration normal to the screen. This featurehas potential for optimizing cuttings conveyance with respect to oil retention oncuttings.

Vibration Dynamics

Acceleration

During the vibration cycle, the shaker basket undergoes acceleration whichchanges in both magnitude and direction. As discussed previously, the placementof the vibrators determines the vibration pattern and therefore the net accelerationdirection during the vibration cycle. The mass of the counterweights and the fre-quency of the vibration determine the magnitude of the acceleration.

The vertical component of acceleration has the most effect on shaker liquidthroughput. We relate the vertical components of acceleration and stroke length tofrequency by the following equation:

Figure 3.5 Balanced Elliptical Motion. This motion is the most efficient in conveying solids.

G‘sstroke in.( ) RPM

2×70 400,

--------------------------------------------------=

Shale Shakers


3.7

where the stroke length is the total vertical distance travelled by the shaker basketand the G-force is measured from midpoint to peak.

An acceleration of one “G” is the standard acceleration due to gravity(386 in./sec2). Most shakers operate at accelerations within the range of2.5-5.0 G’s, depending upon the vibration pattern. Field experience has shownthis range offers the best compromise between throughput capacity and screenlife.

Many manufacturers report the acceleration of linear motion shakers along theline of motion. This yields a larger number and looks good on the specificationsheet. However, unless the angle of vibration is also specified, it reveals littleabout the performance of the shaker. The “G's” for shale shakers listed in theappendix are calculated for the direction normal to the screen surface.

Some shakers have adjustable counterweights to vary acceleration (Figure 3.7).Although flow capacity and cuttings dryness improves with increased accelera-tion, screen life is negatively affected. By reducing the “G’s” when extra flowcapacity is available, screen life may be improved.

Frequency (RPM), Stroke Length

The vibrator frequency of most shale shakers is not normally adjustable. Thevibrators typically rotate at a nominal rpm of 1200 or 1800 at 60 Hz. Stroke length

Figure 3.6 Conveyance Velocity. The shape of the ellipse controls conveyance velocity. A thin ellipse conveys solids faster than linear motion.

Acceleration (normal to screen), G’s



3.8

varies inversely with rpm. A higher rpm will result in a shorter stroke length at thesame acceleration.

The effect of vibrator frequency and stroke length on shaker processing rate hasbeen evaluated in the laboratory. The results of these tests show improved shakerflow capacity in the presence of solids with decreased rpm (or conversely,increased stroke length) at the same G level. (Figure 3.8). Therefore, the term“high speed” should not be used to mean “high performance” since the oppositerelationship is often more correct.

The main disadvantage to lower frequency shale shakers is that the mud tends to“bounce” much higher off the screens and cover the area around the shakers witha fine coating of mud. More frequent housekeeping is required to maintain a safeenvironment around the shakers. Longer stroke lengths also tend to reducescreen life.

Deck Angle

Because linear motion shakers will convey uphill, most provide an easily-adjust-able deck angle feature to optimize fluid throughput capacity and cuttings convey-ance velocity. Uphill deck angles also provide protection against overflow due tosurges at the flow line.

Figure 3.7 Adjustable Vibrator Counterweights. Other designs are used, this is the most simple.

Shale Shakers


3.9

At deck angles greater than 3°, solids grinding in the pool region can be a prob-lem. Although fluid throughput increases with uphill deck angle, cuttings convey-ance decreases. Solids conveyance within the pool region is slower than out ofthe pool due to viscous drag forces and the differential pressure created acrossthe cuttings load by the hydrostatic head of the fluid. If the deck angle is too high,a stationary mound of solids can build up in the pool even though conveyance isobserved at the discharge end (Figure 3.9). The vibrating action of the screen andextended residence time will tend to grind soft or friable cuttings before they havethe opportunity to be conveyed out of the pool. This condition should be avoidedsince the generation of fines in the mud is definitely not desired.

To check for this problem, observe the feed end of the shaker at a connectionimmediately after circulation is stopped. There should not be a disproportionateamount of solids accumulated at the feed end. The problem can be rectified bylowering the deck angle until the solids mound is eliminated.

Figure 3.8 Shaker Throughput vs. Vibrator Frequency. Shaker throughput improves as fre-quency decreases.



3.10

Screen Fastening and Support

The type of screen panel dictates the type and amount of support and fasteningsystem necessary. The screen fastening and support structure provide the follow-ing functions:

1. Prevent leakage past the screens

2. Expedite screen replacement

3. Provide even tension on screens to extend screen life

The two types of screen panels are commonly labelled as “pretensioned” and“nonpretensioned” panels. However, these terms do not exactly describe theirconstruction since many nonpretensioned panels are, indeed, pretensioned. Theterms “rigid frame” and “hookstrip” more correctly differentiate the two main paneltypes.

Hookstrip Screen Panels

This is the most common type of panel, consisting of one to three layers of screencloth. The cloth is frequently bonded to a thin perforated-metal grid plate or a plas-tic grid. Figure 3.10 shows the construction of a typical hookstrip screen. The

Figure 3.9 Solids Bed Buildup. This may occur when the shaker deck is tilted up too high.

Shale Shakers


3.11

screen panel is tensioned on the shaker deck by an interlocked hookstrip anddrawbar arrangement located on both sides of the shaker (Figure 3.11). Three ormore tensioning bolts are used to pull each drawbar down and towards the side ofthe basket. This seats the screen on the shaker deck and distributes even tensionalong the hookstrip.

These panels are not rigid; the shaker deck must be crowned to maintainscreen-to-deck contact throughout the vibration cycle. Support ribs in the shaker

Figure 3.10 Typical Hookstrip Screen. The backing grid, though not necessary, provides support and improves screen life.

Figure 3.11 Hookstrip Screen Tensioners. This is the most common type of fastening system for hookstrip screens.



3.12

deck are designed to ensure even support of the screen across the width of thebasket. Full contact with all support stringers is critical, especially withmetal-backed panels. The panels will suffer premature fatigue failure if flexing isallowed to occur.

Because screen tension is extremely important to ensure good screen life, thetension should be checked frequently on nonpretensioned hookstrip-stylescreens. Spring-loaded tensioning bolts are recommended to aid in preventing acomplete loss of tension and premature failure as the screens stretch and “seat”onto the deck. Tensioning springs are not required for hookstrip panels with metalbacking plates since these panels will not normally stretch.

The crowned deck can cause uneven fluid coverage (Figure 3.12). The mud mayextend further out along the sides of the shaker than at the center where maxi-mum deck height occurs. This reduces the effective screening area of the shaker,especially at low deck angles. It can lead to whole mud losses at the dischargeand contribute to unacceptably wet cuttings even though the fluid endpoint alongthe centerline of the shaker may be well back from the discharge. The problemcan be mitigated by increasing the deck angle and selecting high efficiencyscreens to reduce fluid coverage area.

Screen replacement time is usually much longer than with rigid frame panels.However, Derrick has developed a new tension bolt design which has improvedscreen changing on their Flo-Line Cleaner; the tensioning nut and spring havebeen replaced by an integral nut and spring assembly which requires a half-turn tofully operate.

Rigid Frame (Pretensioned) Screen Panels

In rigid frame screen panel construction, the screen cloth is tensioned and bondedto an integral steel frame; no additional tensioning is required. Because rigidframe screens are flat, uneven fluid coverage on the shaker is not a problem. Allother factors being equal, discharged cuttings dryness is reported to be superiorto shakers with hookstrip screen designs.

Since no tensioning is required during installation, the fastening system can bedesigned for fast panel replacement. For example, each panel on the Fluid Sys-tems Model 500 is held in place by two wedges (one on each side). A tap on thewedge locks the panel in place. The Thule VSM100 has a pneumatically-actuatedsystem. Sweco's LF-3 Oil-Mizer and Brandt's ATL-1000 also have quick-releasefastening systems.

The two most common types of pretensioned panels are shown in Figure 3.14and Figure 3.13.

Shale Shakers


3.13

1. The screen cloth is tensioned and glued directly to the steel frame. Addi-tional glue lines may be included between the frame members to provideadditional support. The bonding pattern divides the panel into 3- to 4-in. widestrips oriented parallel to the flow. This design is used in the Fluid SystemsModel 500.

This panel design maximizes usable screening area. However, the largeunsupported area normally limits cloth selection to the heavier grades withlower flow capacity. The panel is not normally considered repairable.

2. Alternatively, the screen cloth may be bonded to a perforated metal backingplate similar to a hookstrip screen. The metal backing plate is then bonded tothe support frame to create a rigid panel. The Brandt ATL-1000 and the ThuleVSM-100 use this type of panel.

Figure 3.12 Shaker Fluid Endpoints. Crowned decks will cause uneven fluid coverage espe-cially at low deck angles.



3.14

Usable screen area is reduced by the perforated plated design, but this is off-set by the option of using higher conductance screen cloth, repairability, andbetter screen life under high solids loading conditions.

Figure 3.13 Rigid Screen Panel with Perforated Plate. The metal grid is bonded to a steel frame.

Shale Shakers


3.15

Three Dimensional Screens

In recent years three dimensional screens have been introduced to the oilindustry. This wave design increases the area of the screen by 40% over theflat screens. This increase in conductance is only relevant if the screen iscompletely submerged in drilling fluid. This reportedly increases the shakercapacity and allows for finer screening. A picture of a three dimensionalscreen is shown in Figure 3.14a.

Figure 3.14 Rigid Screen Panel. The screen cloth is glued directly to a steel frame.



3.16

Single Deck Shakers

As the name implies, a single deck shale shaker has one discrete screening layer;the mud and solids fed to the shaker are screened once. One or more screen pan-els may be used to provide a continuous screening surface. Deck profiles of sin-gle deck linear motion shakers are usually flat from feed to discharge, but otherprofiles are used. For example, the panels of the Fluid Systems Model 500 andSwaco ALS are arranged in a stairstep pattern: Each downstream panel is slightlylower than the upstream panel, primarily for ease of panel positioning. Unbal-anced elliptical motion shakers, such as the Derrick Standard or Swaco SuperScreen, have an increasingly negative (downhill) slope on downstream panels toimprove solids conveyance.

Single deck shakers provide the advantage of allowing complete access to thescreening surface. This simplifies maintenance, panel changes, screen inspectionand cleaning. The disadvantage of single deck shakers becomes apparent underhigh solids loading conditions; flow capacity, cuttings dryness and screen life maybe greatly reduced. These problems can be circumvented by using a cascadingshaker arrangement. (Refer to the following section: Cascading Shaker Systems.)

Linear motion single deck shakers are preferred for most applications because oftheir simplicity, high flow capacity and fine-screening capability. Their popularityhas spurred numerous companies to manufacture linear motion shakers. A com-plete list is provided in Appendix E, Equipment Specifications. Many of the majormanufacturers’ shakers have been evaluated in laboratories. Differences in over-all performance were found to be relatively minor. Examples of single deck linearmotion shakers that will provide acceptable performance are pictured in Figures3.15-3.20. The shakers are listed in alphabetical order, no ranking is implied bythe order of their appearance.

Shale Shakers


3.17

Figure 3.15 Derrick Flo-Line Cleaner Plus.

Figure 3.16 Fluid Systems Model 500



3.18

Figure 3.17 Swaco ALS

Figure 3.18 Sweco LF-3 Oil-Mizer

Shale Shakers


3.19

Figure 3.19 Sweco LM-3

Figure 3.20 Triton NNF



3.20

Cascading Shaker Systems

“Cascading” refers to the use of shakers in series (the mud passes sequentiallythrough two shakers) to remove drill cuttings in two stages. The first set of shakersremove or “scalp” the coarsest cuttings from the returned drilling fluid. The mudand fine cuttings are then fed to a second set of shakers with finer screens. Thisarrangement increases the capacity of the fine screen shakers through reducedsolids loading. This arrangement is especially effective when drilling fast, largediameter hole sections or gumbo formations.

Figure 3.21 illustrates a “2 over 3" cascading shaker arrangement. This arrange-ment usually provides adequate shale shaker solids removal for drilling most17-1/2-in. diameter holes. It is important to ensure that valves are provided to iso-late each shaker in the system as required for screen maintenance and shakerrepair.

In most instances, unbalanced elliptical or circular motion shakers are the pre-ferred scalping devices. Soft, sticky cuttings such as gumbo are generally handledbetter by these vibration patterns with a flat or downhill deck angle. However, lin-ear motion shakers have been successfully used as scalpers when the deck angleis steeply pitched downhill (such as a Derrick Standard) or when the deck lengthis short (such as the Fluid Systems two-panel shaker).

Because the scalping shakers must be positioned above the fine screen shakers,sufficient height between the flow nipple and the scalping shaker weirs must be

Figure 3.21 Cascading Shaker System

Shale Shakers


3.21

available to avoid solids settling in the return line. A good “rule of thumb” is 1 ft ofdrop per 12 ft of flowline. Also, additional space is obviously necessary to accom-modate a cascading system.

Unitized Cascading Systems

A unitized cascading system incorporates two shakers, one stacked over theother, on a single skid. This design reduces many of the plumbing problems andcosts normally associated with retrofitting a cascading system on a rig. Also, theunitized system takes up less floor area than a standard cascading system.Because the top and bottom shaker are separate units, each can be designed forits specific function without severely impeding screen panel access or perfor-mance. This is an advantage over integral tandem deck shakers.

There are two disadvantages to unitized cascading systems: (1) They have highweirs which will limit their application to rigs with sufficient elevation differencebetween the flow nipple and the upper shaker weir; and (2) the upper shaker maybe too high to be worked on easily. A permanent walkway or ladder should beinstalled to improve access to the upper shaker’s screens.

Two systems are currently available: The Brandt ATL-CS (Figure 3.22) and theFluid Systems Model 50-500. The Brandt is a tandem deck, circular motion basketover a linear motion basket. The Fluid Systems version uses a short, two-panellinear motion basket as the scalping shaker over their standard Model 500 shaker.

Integral Tandem Deck Shakers

These shakers incorporate two distinct screening decks stacked in a single bas-ket. The top deck screen “scalps” off the coarse solids to reduce the solids loadingto the lower screens.

Tandem deck shakers are available in both circular and linear motion designs.The superior fluid processing and finer screening features of linear motion shak-ers are preferred. In either case, flow back pans are recommended to improvethroughput.

Tandem deck shakers offer a compromise between a true cascading system andsingle deck shakers. If the top scalping deck covers the entire basket width, solidshandling capacity is good. However, accessibility to the lower deck screens andthe ability to monitor screen wear is limited. Conversely, a small scalping deck lim-its solids loading capacity, but improves accessibility and screen monitoring. Tan-dem deck shakers are recommended for medium-high solids loading applicationsor where space or height limitations will not permit the use of a cascading shakersystem.



3.22

The total combined area of both screening surfaces cannot be used to comparethe performance of these shakers to single deck shakers. The relative processingcapacity of tandem deck shakers will depend upon the size distribution of the sol-ids in the feed, solids generation rate and other factors. Generally, tandem deckshakers will outperform single deck shakers when large diameter hole and highpenetration rates are encountered. Examples of linear motion tandem deck shak-ers are shown in Figures 3.23-3.25.

Figure 3.22 Brandt ATL-CS. This is one example of a “unitized” cascading shaker arrangement.

Shale Shakers


3.23

Figure 3.23 Brandt ATL 1000

Figure 3.24 Derrick Cascade System



3.24

Shaker Manifolds

The flowline and manifold system must be designed to provide an even distribu-tion of mud and cuttings to the shakers. The flow line must have sufficient drop toprevent solids from accumulating in the line: A drop of 1 ft per 12 ft of run is agood rule of thumb. Flowline diameter must also be sufficient to handle the maxi-mum anticipated circulation rates. Diameters of 10 or 12 in. are usually sufficient.

Manifolding can be a problem when three or more shakers are arranged in paral-lel. Because the shaker feed is essentially two-phase, liquid being one phase andsolids the other phase, equal division of both phases can become difficult toachieve with typical manifold designs (Figure 3.26 and Figure 3.27). Branch teesshould be avoided. The solids will preferentially travel a straight path, resulting inuneven solids loading to the shakers. Dead end tees will distribute the solids moreevenly. Examples of recommended manifold designs for multi-shaker installations

Figure 3.25 Thule VSM 100

Shale Shakers


3.25

are provided in Figure 3.28, Figure 3.29, and Figure 3.30. Overhead or circularmanifolds will provide better distribution of mud and solids.

All shakers should be level with equal weir heights to ensure even flow distribu-tion. A common shaker box (possum belly) is acceptable for scalping shakers. It isnot recommended for the fine screen shakers since a large shaker box onlyserves to collect solids, which can enter the mud tanks if the bypass gate isopened.

Operating Guidelines

Optimizing Screen Life

Perforated plate screens usually exhibit longer screen life than other hookstripscreens. They provide the most support and are repairable.

1. Screen life is inversely proportional to plate opening size. If premature wear isapparent in the pool region, install panels with smaller perforated plate sizesat the feed end of the shaker where loading and wear is greatest.

2. Reduce deck angles to improve solids conveyance, reduce loading and elimi-nate solids grinding at the feed end.

Figure 3.26 Poor Manifold Design. Distribution to the shakers may be uneven.



3.26

Figure 3.27 Better Manifold Design. There are less branch tee’s in this design.

Figure 3.28 Best Conventional Manifold Design. All branch tee’s are eliminated.

Shale Shakers


3.27

3. If premature backing plate failure is experienced, check that all deck rubbersare in place and in good condition. Check for a buildup of solids between thescreen and the support areas on the shaker deck.

Screen Selection

1. When possible, run the same screen mesh over the entire deck of a singledeck shaker. When running different mesh cannot be avoided, the coarsermesh should be run at the discharge end. Do not vary the mesh size by morethan one increment from feed to discharge.

2. Select the finest screens which will give 70-80% fluid coverage on the shaker(Exception: See cuttings dryness discussion).

3. Always run the coarser screens on the top deck of a tandem deck shaker oron the upstream shaker. The upper deck screen should be at least two meshsizes coarser than the bottom deck. It has been observed that runningscreens which are too fine on the top deck can actually impede cuttings con-veyance on the lower deck.

Figure 3.29 Circular Manifold Design. Useful for odd number of shakers. Flowline lengths are exaggerated.



3.28

4. Select screens for which the new API designations are known to ensure pre-dictable performance.

Cuttings Dryness

The volume of drilling fluid lost with the discharged cuttings is becoming moreimportant in the wake of increasingly stringent environmental regulations andmore expensive drilling fluid formulations. In most cases, minimizing liquid wastefrom the shale shakers makes both economic and environmental sense. A fieldprocedure to determine composition of the discharge is given in Appendix C, Sol-ids Control Equipment Discharge Analysis, Oil-Based muds.

Shaker discharge dryness is heavily dependent upon the size distribution of thecuttings and the viscosity of the mud. There will always be an irreducible “volumefraction” of fluid wetting the cuttings and this will vary inversely with particle size.Extremely fine solids have substantially higher percentages of associated liquidthan larger solids due to surface area and surface tension effects. Mud viscositywill also impact the thickness of this fluid layer.

Figure 3.30 Overhead Manifold Design. Excellent for even distribution of liquid and solids, but more complicated to fabricate.

Shale Shakers


3.29

The shaker can remove a portion of this residual wetness by the acceleration andimpact forces imparted on the cuttings after they exit the pool region. Drynessmay depend on the magnitude of these forces and the exposure time.

Since a substantial portion of the shaker screening area can be covered by the liq-uid pool to achieve a desired separation, the remaining dry screening area maynot be sufficient to remove excess moisture carried with the cuttings. High solidsloading rates will also have a negative impact on cuttings dryness.

Solids loading and dry screening area can be addressed during the planningphase by ensuring that sufficient shaker area is available to maximize cuttingsdryness. The following remedial actions may help improve cuttings dryness:

1. Deck Angle Increase - This is the most simple solution. Fluid loss along thehookstrips is reduced. Solids conveyance will decrease with steeper deckinclinations, which increases the contact time to remove excess moisture.Protection against whole mud losses due to flowline surges is also improved.

The reduction in fluid coverage is not necessarily proportional to the deckangle selected. Because conveyance is lessened, the solids remain in thepool longer and can interfere with the ability of the fluid to pass through thescreen, especially at higher solids loading rates. This may retard the forma-tion of a shorter, deeper pool. Also, solids grinding may become a problem.

2. High Efficiency Screens - Screens with high transmittance values will reducefluid coverage and increase dry screening area. Two new screens, the Derrick“Pyramid” and Cagle’s “HCR” series offer distinct advantages in this applica-tion. The corrugated “Pyramid” design may reduce mud loss along the hook-strips and offers increased screening area. Cagle’s HCR cloth has very hightransmittance values and has exhibited service life up to 4 times standard DXdesigns.

3. Coarser Screens - This has two effects. First, the fluid endpoint on the shakerwill recede, and second, the average discharged cuttings size will increase.However, this action usually carries with it the penalty of poorer separationefficiency and higher costs, unless downstream solids removal equipment“picks up the slack.” Try running a coarser screen at the discharge end beforeconverting the entire deck to coarser screens. There are special consider-ations worth mentioning depending upon the mud system in use:

Unweighted Muds

The importance of fine screening in unweighted muds is typically not as criti-cal, provided: 1) sufficient hydrocyclones and centrifuges are used, and 2) thecuttings are not soft and easily degraded by centrifugal pumps. In fact, signifi-cant fluid savings in oil-based muds have been realized by running coarser



3.30

screens on the shakers to produce a dry discharge and transferring a greatershare of the solids removal to the downstream centrifuges.

Weighted Muds

In weighted muds, the importance of the shaker in the solids removal systemgenerally precludes the option of running coarser screens. Economics usuallydictate that the finest separation possible be made by the shaker without sub-stantial loss of barite in the discharge. Drill cuttings missed by the shaker willremain in the circulating system and eventually contribute to a low gravity sol-ids buildup and subsequent viscosity increase.

4. G Force Increase - Increased shaker acceleration will help remove excess liq-uid by overcoming part of the surface tension forces which bind the fluid to thecuttings. Conversely, cuttings conveyance velocity will increase and screenlife will decrease. Conveyance velocity can be reduced by increasing the deckinclination, but screen life will decline considerably at accelerations above4 Gs.

Sticky Solids (Gumbo)

1. Use scalping shakers ahead of fine screen shakers. Circular or unbalancedelliptical motion shakers or shakers with short basket lengths are recom-mended as the scalping shakers. If space is limited, tandem deck linearmotion shakers may be used.

2. Use downhill or flat deck angles. Gumbo will not convey well uphill.

3. Gumbo will not stick as persistently to wet screens. When spray bars are nec-essary to keep the screens wet, use low flow rate nozzles which produce afine mist with an umbrella or fan-shaped discharge. These nozzles operate atless than 0.5 gpm. No more than two are normally required. Do not use highvolume or high pressure sprays on a continuous basis. This will degrade thegumbo patties and drive the solids through the screens.

Polymer Muds

1. Prehydrate and preshear the polymer before adding into the active mud sys-tem to eliminate “fish-eyes” and blinding at the shaker.

2. Select high efficiency screens to maximize the flow capacity of the shakers.

3. Expect an overall reduction in shaker flow capacity of as much as 40%.

Shale Shakers


3.31

Blinding, Plugging

1. Gilsonite (Asphaltenes)

Triple-layer screens are susceptible to plugging by gilsonite or other asphalt-ene-based products in the drilling fluid. The problem may be mitigated byselecting single or double-layer screens. For example, on Derrick Flo-LineCleaners, use the PBP HP or GBG HP series. Refer to Appendix D, ScreenDesignations, for a complete list of screen panel descriptions.

2. Sand (Near Size)

- Unbonded triple layer screens provide the best resistance to blinding, butscreen life is generally poor.

- Single layer, square mesh cloth is most susceptible to blinding. Selectscreen series with aspect ratios greater than 1.4. (Refer to Chapter 4,Shaker Screens.)

- If excess shaker capacity is available, try running a finer screen. Thesands may have a relatively narrow size distribution which might not blinda smaller opening size.

Lost Circulation Material

1. Do not bypass the shakers to avoid screening out the LCM material.

2. Scalping shakers can be used to recover LCM when high concentrations arecontinuously required in the mud, provided:

- Cuttings size distribution is sufficiently fine to pass through the scalpingscreens.

- Solids loading rates do not negatively impact the performance of thedownstream shakers and cause solids buildup in the active system.

- The LCM removed by the scalpers is returned to the active system down-stream of the centrifuge.



3.32

Estimating Number of Shakers Required

1. Base the number of shakers required on the economics and the physical con-straints of the specific application.

2. A “ballpark” estimate of shaker requirements, based on average drilling condi-tions can be made from Table 3.1. This is a very rough estimate and shouldbe used only as a guide.

Table 3.1 Shakers RequiredApproximate Number of High Performance

Linear Motion Shakers

Maximum Viscosity (cP)

5 10 15 20 25 30 40 50 60

Circ

ulat

ion

Rat

e (g

pm)

300 1 1 1 1 1 1 2 2 2400 1 1 1 2 2 2 2 2 2500 1 1 2 2 2 2 3 3 3600 1 2 2 2 2 3 3 3 3700 2 2 2 2 3 3 3 3 4800 2 2 2 3 3 3 4 4 4900 2 2 3 3 3 4 4 4

1000 2 2 3 3 4 4 41100 2 3 3 4 4 41200 2 3 3 4 41300 2 3 4 41400 2 3 4

Shale Shakers


3.33

Summary

• The shale shaker is the only solids control device that makes a separationbased on the physical size of the particle. The separation size is dictated bythe opening sizes in the shaker screens. Hydrocyclones and centrifuges sep-arate solids based on differences in their relative mass and the fluid.

• Shale shakers with linear vibratory motion are preferred for most applicationsbecause of their superior processing capacity and fine-screening ability. Cir-cular motion or unbalanced elliptical motion shakers are recommended asscalping shakers in cascading systems.

• Vibration of the shaker basket creates G-forces which help drive shear thin-ning fluids such as drilling mud through the screens. Vibration also conveyssolids off the screens. Most linear motion shakers operate in the range of 3 to4 G’s to balance throughput with screen life. G-force is a function of vibrationfrequency (rpm) and stroke length.

• “High-speed” should not be equated with “high performance.” Laboratory testsindicate that, in the normal operating range for linear motion shale shakers,lower frequency vibration and longer stroke lengths improve throughputcapacity. Most linear motion shakers operate at 1200 to 1800 rpm.

• Avoid deck inclinations above 3°. High deck angles reduce solids conveyanceand increase the risk of grinding soft or friable solids through the screens.

• Shakers are designed to accept either hookstrip or rigid frame screen panels.Hookstrip screen panels are the most common and are usually cheaper,although cuttings wetness can be a concern due to deck curvature. Flat, rigidframe panels promote even fluid coverage, but can cost more.

• Shakers may have single or tandem screening decks. Single deck shakersoffer mechanical simplicity and full access to the screening surface. Singledeck shakers may be arranged to process mud sequentially as a “cascading”system to improve performance under high solids loading conditions. Tan-dem deck shakers offer improved processing capacity under high solids load-ing conditions when space is limited.

• Manifolds should provide even distribution of mud and solids to each shaker.Avoid branch tee’s. Recommended manifold designs are illustrated.

• Operating guidelines are provided for optimizing screen life and cuttings dry-ness, handling sticky solids, polymer muds, blinding and LCM problems.



3.34


4.1

Chapter 4. Shaker Screens

Shaker screen selection has the largest impact on the overall performance of theshale shaker. It is therefore important to understand the factors which may impactscreen performance and how to properly select screens. Shaker screen perfor-mance is measured by:

1. Separation Performance - the size of the solids removed

2. Liquid Throughput Performance - the capability of the screen to transmit fluid

3. Service life

Separation Performance

Grade Efficiency

The separation performance of a shale shaker screen (or any other solids controldevice) is commonly represented by its percent-s99eparated, or grade efficiency,curve. This curve is generated from full-scale experimental measurements anddepicts the percent solids removed as a function of particle size. It reports thescreen's probability of separating any specific particle size with a given shakerunder conditions specific to the test. Grade efficiency is the preferred measure ofseparation performance because it is independent of feed particle size distribu-tion.

An example of a percent-separated curve is shown in Figure 4.1. In this example,the median size separated by the screen was 145 microns. This means that 50%of the solids with a diameter of 145 microns were removed. A rough estimate ofthe median cut point (d50) can be made in the field by the wet sieve procedure(see Field Procedure to Estimate Cut Point, p 4.9).

Separation Potential

A method was developed that characterize the relative separation efficiencypotential of shaker screens without the expense and time required for full-scaletesting. The technique links the relative separation performance of screens to avolume-equivalent distribution of their opening sizes.

The screen's openings are measured using PC-based image analysis technology.Each opening in the screen is then represented by a spherical diameter corre-



4.2

sponding to an ellipsoidal volume calculated from the image analysis data. Thecumulative volume of these ellipsoids, when plotted as a function of sphericaldiameter, yields a curve which correlates well with the standard grade efficiencycurve. This curve represents the “separation potential” of the screen. The word“potential” is used because the screen's separation performance is not measureddirectly, but implied by the size of the screen's apertures.

Note: Grade separation efficiencies as measured on the shaker are subject tospecific shaker and flowline conditions. They may not always agree with separa-tion potential values. For example, the separation potential value for a screen withrectangular openings may be pessimistic when drilling clean sand sections pro-ducing predominantly spherical sand grains. The image analysis methodassumes solids of all shapes and sizes are available to the screen. However, onaverage, the separation potential values have been shown to adequately repre-sent the screen's separation performance.

Figure 4.1 Percent Separated Curve. This curve indicates the percentage of solids removed as a function of particle size.

Shaker Screens


4.3

Liquid Throughput Performance

The liquid throughput capacity of a screen panel is primarily a function of screenconductance and usable area. Conductance describes the ease with which fluidcan flow through a unit area of screen cloth. In simplistic terms, it is analogous topermeability with the length in the direction of flow (screen thickness) taken intoaccount. Higher conductances will result in higher flow rates through the screen.

Conductance is calculated from the mesh count and wire diameters of the screencloth by the equations given in Appendix A, Conductance Calculation. Multilayerscreens can also be handled by the conductance equation. The inverse of con-ductance for each screen layer is summed to equal the inverse of the net overallconductance:

This is valid provided that the screen layers used in the composition are designedto remain in contact.

Oilfield screens are typically bonded to a perforated metal panel or plastic grid toprovide extra strength and improve service life. This practice eliminates some ofthe usable area through which fluid may pass. Some metal backing plate designsmay reduce effective screening area by as much as 40 percent. Because conduc-tance describes screen flow capacity per unit area, the usable unblocked areaavailable for screening must also be considered when comparing the mud pro-cessing capacity of shaker screen panels.

Screen Life

The definition of “acceptable” screen life must be judged within the context of thetotal solids removal system economics. Besides screen replacement cost, consid-eration must be given to the costs of drilling mud dilution and waste disposal costswhen determining whether longer screen life is warranted at the expense of solidsremoval efficiency. In weighted mud applications, the economic benefits ofimproved solids removal efficiency usually outweigh the additional screen costs.

Effect of Screen Composition

Only very general correlations may be made between screen composition andservice life. Unfortunately, features that lead to improved life are usually detrimen-tal to flow capacity. Using heavier wires with greater tensile strength or adding

1Ct-----

1C1------

1C2------ …

1Cn-------+ +=



4.4

supporting layers of cloth can both reduce conductance. Increasing supportthrough additional bonding area (smaller plate openings) eliminates usablescreening area. Also, support techniques and screen tension can have a majoreffect on screen life. As a result, screen panels are typically designed to balanceflow capacity performance with screen life.

Screen life is heavily dependent upon flow line conditions. Solids loading rate,drilled cuttings abrasiveness, and shaker dynamics can easily outweigh composi-tion effects.

Effect of Vibration Pattern

Linear Motion

The abrupt changes in acceleration during the vibration cycle tends to causescreens to wear more quickly unless close attention is paid to tensioning andscreen support techniques. Perforated metal backing plates and pretensionedscreen panels have been specifically developed to address this problem. Linearmotion shakers usually operate at less than 4.0 G's (normal to the screen) to bal-ance screen life with processing capacity. Regardless, the finer screens normallyrun on linear motion shakers cannot be expected to outlast the coarser screensused in the past. For screens finer than 100 mesh, expect an average service lifein excess of 100 hours.

Circular, Elliptical Motion

The smooth change in acceleration with respect to direction translates into longerscreen life compared to other vibration patterns. However, many circular motionshakers were designed before the advent of fine mesh screens and may provideless support for the screens. This will tend to negate much of the screen life bene-fit associated with circular motion.

Shaker Screen Designations

Mesh Count

Shaker screens have traditionally been assigned mesh count designations by themanufacturer. Unfortunately, they do not adequately describe screen performancein terms of separation efficiency or flow capacity.

Mesh count is defined as the number of openings per linear inch of screen cloth.Mesh count does not establish the size of screen openings unless wire diameter

Shaker Screens


4.5

is known. The opening size, D, is related to the wire diameter, d, and the meshcount, n, by the following equation:

With the wide variety of wire diameters used to construct the same mesh count,the actual separation efficiencies of screens with the same mesh count designa-tion are rarely consistent:

1. Manufacturers commonly designate layered screens by a single mesh countnumber. Experimental separation efficiency tests have revealed that thesedesignations are predominantly optimistic.

2. Oblong mesh screens may be identified by a single number which may be thesum of mesh counts in both the horizontal and vertical direction. For example,a 60 x 40 mesh screen may be labelled “100 mesh”. This practice is mislead-ing: The opening sizes of a 60 x 40 mesh screen will pass much larger parti-cles than a 100 x 100 square mesh screen.

API RP13E Screen Designation

Recently, a new performance-based screen designation system has been devel-oped. This designation system has been adopted by the API RP13E as a Recom-mended Practice for Shale Shaker Screen Cloth Designations. The API hasrecommended that all screens be labelled with the following information:

Screen NameSeparation Potential (d50, d16, d84)Flow Capacity (Conductance, Total Non-Blanked Area)

A comprehensive list of screen designations for most shakers is included inAppendix C, Screen Designations. The screen designations include additionalinformation not specified by the API to further define screen performance. Each ofthe designation components are described in detail below:

Screen Name

This is the “mesh count” designation or part number used by the manufacturer toidentify the screen. Typically, it consists of a mesh count number preceded by aletter code which may describe the screen's cloth type or layering technique. Forexample, MG100 signifies a 100 x 100 mesh “market grade” bolting cloth, a PWPHP100 signifies a perforated plate, triple-layer screen composed of oblong meshscreen cloth.

D 1d--- n–=



4.6

Equivalent U.S. Sieve Number

This is the U.S. Sieve Number which has the same median opening size, or d50,as the screen. Table 4.1 lists the opening sizes of the standard U.S. Sieve series.In cases where no actual U.S. Sieve exists for a given opening size, the equiva-lent U.S. Sieve Number is a linearly-interpolated value. This value provides a sim-ple scale by which to quickly rank the separation potential of screens. Cautionshould be exercised when using this value to compare screens of different typesince it represents only the median separation potential of the screen.

Separation Potential (d50, d16, d84)

The separation potential of the screen is represented by 3 points on the separa-

tion potential curve, labelled d16, d50 and d84 (Figure 4.1). These points are the

spherical diameters, in microns, corresponding to 16, 50 and 84 percent of the

cumulative ellipsoidal volume distribution of hole sizes present in the screen. It

must be stressed that these values provide a relative measure of a screen'spotential ability to remove solids. They may not necessarily agree with mea-

sured grade efficiency cut points for a given application.

Table 4.1 U.S. Sieve Series

U.S. SieveNumber

Opening Size Microns

U.S. SieveNumber

Opening Size Microns

3.5 5660 40 420

4 4760 45 350

5 4000 50 297

6 3360 60 250

7 2830 70 210

8 2380 80 177

10 2000 100 149

12 1680 120 125

14 1410 140 105

16 1190 170 88

18 1000 200 74

20 840 230 62

25 710 270 53

30 590 325 44

35 500 400 37

Shaker Screens


4.7

d50

The d50 is the median aperture size of the screen on a volume-equivalent basis. Inexperimental grade efficiency terms, it is analogous to the size of solid that has a50% probability of separation. The d50 is typically used as a single value indicatorof separation efficiency performance. Because of it's importance, the d50 is listedfirst.

d16, d84

The d16 and d84 values indicate the range of hole sizes present in the screen. Thed16 and d84 values can be important when the removal of fines from anunweighted mud is desired, or when the removal of barite is a concern. The devi-ation from the d50 describes the screen's implied separation characteristics. Asthe difference between the d16 and d50 increases, it is more likely that some solidsfiner than the d50 will likely be removed. Conversely, a smaller percentage of sol-ids coarser than the d50 may be removed as the difference between the d84 andd50 increases. A multilayered screen will generally have a larger spread betweenthe d16 and d84 values than a single mesh screen with the same d50.

Flow Capacity (Conductance, Nonblanked Area)

The calculated conductance is reported in units of kilodarcies/millimeter for thetotal screen composition.

Non-blanked area is the total effective screening area per panel, in units of squarefeet.

Note: Support rails on the shaker deck can reduce the usable area of screens notmounted on metal backing plates. This area reduction is not included in the calcu-lation of usable area because it is not a function of screen panel construction andwill vary with the shaker type.

Transmittance

Transmittance represents the net flow capacity of individual screens. It is theproduct of conductance and unblocked screening area. Transmittance permits thecomparison of individual screens which differ in usable screening area.

Aspect Ratio

Aspect ratio describes the average shape of the screen openings.

It is the volume-weighted average length-to-width ratio of the screen openings.Aspect ratio serves as an indicator of screen composition and provides informa-tion about the screen's potential resistance to blinding.



4.8

Rectangular, or oblong, mesh screens have been customarily employed to reducethe “blinding” problems exhibited by square mesh screens when drilling sand sec-tions. The “near-size” sand grains lodge in the square mesh screen apertures andreduce mud processing capability. The longer slots in the oblong screens aremore likely to be only partially blocked by these spherical particles and thus tendto resist blinding. Aspect ratios in excess of 1.5 are typical of oblong meshscreens (both single and multilayered designs) used in the oil field. Single layersquare mesh screens have aspect ratios near unity.

Layered, unbonded, square mesh “sandwich” screens have the capacity to“actively deblind” (remove particles) by the interactive movement between the lay-ers. This feature is lost when the layers are bonded together to improve screenlife. Laboratory tests have shown that blinding increases substantially when theapertures in the metal backing plate or plastic grid have dimensions of less than4 x 4 in. Figure 4.2 shows how blinding severely restricts the flow capacity of theshaker when smaller opening dimensions in the screen panel are used.

Some improvement in blinding resistance over single layer square mesh cloth isstill apparent in bonded, multilayer square mesh screens: Stacking one screencloth over a slightly coarser cloth results in a wide range of hole sizes and shapes.Only the portion of the screen with openings near in size to the sand will tend tobe blinded. Aspect ratios of layered square mesh screen compositions range from

Figure 4.2 Effect of Plate Opening Size on Screen Blinding. Plate openings with dimen-sions less than 4 x 4 in. lose their deblinding ability.

Shaker Screens


4.9

1.3 to 1.5. The relationship between screen composition and blinding resistance issummarized in Table 4.2.

Field Procedure to Estimate Cut Point (D50)

Note: This procedure provides only a rough approximation of the cutpoint. Itassumes that the mass flowrate of the solids discard is negligible compared to thefeed and screen unders. Results may be inaccurate under high solids loading.

Equipment

• U.S. Test Sieves (Enough sizes to bracket expected cut)

• Sample Containers

• Sand Content Tube and Funnel

Procedure

1. Take equal sized samples of both feed and unders. Avoid taking unders sam-ples at the point where the fluid enters the sand trap. Where possible, takethem from directly under the screen.

2. Wet sieve each sample and measure the volume retained on each sieveusing sand content tube.

3. Calculate the percent separated for each test sieve by the following method:

4. Plot through the midpoint of each sieve range as a function of volume percentremoved.

5. Read the median cut point (d50).

Table 4.2 Blinding Resistance of Common Screens

Screen Panel Composition Aspect Ratio Blinding Resistance

Single or double layer, square mesh < 1.2 poor

Triple layer, square mesh, bonded 1.3-1.5 fair

Triple layer, square mesh, unbonded 1.3-1.5 best*

Rectangular mesh, all types > 1.5 better

* provides “active” deblinding through layer interaction

%SeparatedFeed Vol. Unders Vol.–

Feed Vol.----------------------------------------------------------- 100×=



4.10

Summary

• Shaker screens control the separation and liquid throughput performance ofthe shale shaker.

• Separation performance may be measured by two methods:

A. Percent-separated or grade efficiency.

Generated from full-scale measurements, a grade efficiency curve repre-sents the screen’s probability of separating any specific particle sizeunder the specific conditions of the test. The median separation of thescreen, commonly called the “d50” or “cut point,” represents the particlesize that has a 50% probability of being removed. A field procedure isprovided to estimate the d50 of the shaker screens.

B. Separation potential.

This method uses the range of opening sizes in the screen to indicate therelative separation performance of the screen. Because the screen isvisually analyzed, separation potential is independent of operating condi-tions. This method has been adopted by the API as a RecommendedPractice for Shaker Screen Cloth Designations under API RP13E.

• Liquid throughput performance is represented by the screen’s conductanceand usable screening area. Conductance, calculated from the physicaldimensions of the screen composition, is analogous to the screen’s perme-ability. The conductance equations are included in Appendix A, ConductanceCalculation. Usable screening area is the area in the screen panel availablefor fluid flow.

• Mesh count designations do not adequately describe screen performancebecause wire diameters and opening sizes are not consistent, and layeredscreen compositions are not correctly represented. The API RP13E recom-mends that all screens be labeled with: screen name, separation potential(d50, d16, d84), and flow capacity (conductance and total nonblanked area).Appendix C, Screen Designations, contains screen designations and dis-cusses the relative merits of specific screen types for most shaker and screencombinations.


5.1

Chapter 5. Degassers

Degassers are necessary to remove entrained gas bubbles from the mud.Gas-cut mud will impair the performance of centrifugal pumps. Since all solidsremoval equipment beyond the shakers requires a pump, the gas must beremoved before it reaches these devices. If left unchecked and pumped down-hole, the entrained gas will reduce mud density, which will, in turn, reduce thehydrostatic head in the wellbore.

The fundamental principle for all degassers is that gas bubbles must reach the liq-uid-gas interface before they will burst. Any action which brings these gas bubblesto the surface will result in degassing. Four basic mechanisms exist for bringinggas to the surface: 1) increase the bubble size by drawing a vacuum, 2) create athin film, 3) create turbulent action, and 4) impart centrifugal force on the mud todrive the gas bubbles to surface.

There are two basic types of degassers: atmospheric degassers and vacuumdegassers. Tests were conducted that show that vacuum degassers providesuperior performance in the presence of higher mud weights and yield pointsgreater than 10 lb/100 ft2. Atmospheric degassers are acceptable for unweightedmuds with low yield points. The overall ranking of degasser models resulting fromexperimental data is given in Table 5.1.

Table 5.1 Ranking of Degasser Models

Manufacturer Type

Drexel-Brandt Vacuum

Derrick* Vacuum

Wellco Vacuum

Sweco Vacuum

Burgess Vacuum

Swaco Vacuum

Totco Vacuum

Tillet Gas Hog Atmospheric

Drilco Atmospheric

Sweco Atmospheric

Judco Atmospheric

* Not tested but similar in design to Drexel-Brandt



5.2

A complete list of available degassers and their processing capacities are listed inAppendix E, Equipment Specifications.

Placement and Operation

1. Provide enough degasser capacity to treat at least 100% of the circulationrate. Be aware that actual processing rates for gas-cut mud are much lowerthan claimed rates for water.

2. Degassers should be located downstream from the shale shakers andupstream of any equipment requiring a centrifugal pump. The degasser suc-tion should be installed downstream of the sand trap. The suction entryshould be approximately 1 ft from the floor in a well-agitated compartment.

3. The equalizer flow between the degasser suction and discharge must be high.There should be a visible backflow across the high weir, indicating full pro-cessing of the circulation rate. If equalization is low, the light gas-cut mudentering the suction compartment may not be able to displace the heaviermud returning from the discharge compartment. As a result, the light mudmay overflow the suction compartment. Figure 5.1 illustrates correct fluid rout-ing for degassers.

4. Atmospheric degassers should discharge horizontally across the surface ofthe tank to allow large gas bubbles to break out. Vacuum type degassersshould discharge below the mud surface with the flow turned up towards sur-face.

Figure 5.1 Correct Degasser Operation. The high weir helps ensure complete process-ing of gas cut mud.

Degassers


5.3

5. Vacuum degassers must take power mud suction from their discharge com-partment. Power mud is the mud pumped at high velocity through an eductorto create the vacuum in the degasser tank. Taking suction upstream will likelyresult in the pump becoming gas-locked. Suction from further downstream willlikely cause mud to bypass the hydrocyclones.

6. The power mud centrifugal pump must supply the necessary feed head.Install a pressure or head gauge to monitor the feed head at the eductor.



5.4

Summary

• Degassers are used to remove entrained gas bubbles from the mud to pre-vent impairment of centrifugal pump performance, a reduction in mud densityand a subsequent reduction in hydrostatic head in the wellbore.

• There are two basic types of degassers: atmospheric and vacuum. Vacuumdegassers are recommended for weighted muds and yield points over10 lb/100 ft2. Atmospheric degassers are acceptable for unweighted, low vis-cosity muds.

• An overall ranking of degasser models resulting from experimental data isprovided in this chapter. Vacuum desgassers are generally superior. A com-prehensive list of available degassers is listed in Appendix E, EquipmentSpecifications.

• Provide enough degasser capacity to process over 100% of the circulatingrate.

• Locate the degasser downstream of the shakers and upstream of any centrif-ugal pumps.


6.1

Chapter 6. Hydrocyclones

Although the shale shaker is considered the primary solids removal device on therig, hydrocyclones are a cost-effective method of removing many of the fine solidsmissed by the shaker in unweighted muds. In some formations, the solids are toofine for the shakers to remove; hydrocyclones must be relied upon to remove themajority of the solids. In these instances, the shaker protects the hydrocyclonesfrom oversize particles which may cause plugging. Because the hydrocyclone hasno moving parts, it can be a very reliable piece of solids removal equipment whencorrectly operated and maintained.


Think of a tornado inside a bottle and you have a rudimentary idea of how ahydrocyclone operates. Figure 6.1 illustrates the basic concepts of hydrocycloneoperating principles. Mud enters the feed chamber tangentially at a high velocityprovided by pump pressure. As the mud spirals downward through the conicalsection, centrifugal force and inertia cause the solids to gravitate towards the wall.The solids settle according to their mass, a function of both density and volume.Since the density range of drilled solids is normally quite narrow, size has the larg-est influence on settling. The largest particles will settle preferentially.

As the cone narrows, the innermost layers of fluid turn back toward the overflowcreating a low pressure vortex in the center of the cone. This low pressure areacauses air to be pulled in from the underflow outlet. Correctly-operating conesshould exhibit a slight vacuum at the cone underflow. The air and cleaned fluidthen report to the overflow through the vortex finder. The purpose of the vortexfinder is to prevent some of the feed mud from “short-circuiting” directly into theoverflow.

Solids with sufficient mass cannot make the turn back towards the overflowbecause of their momentum and continue out the underflow. Maximum cone wearusually occurs at or near the underflow exit, where velocities are the highest. Incones having a “balanced design‚” whole mud losses out the underflow are slight.Only the solids and bound liquid will report to the underflow. If the solids are toofine to be removed by the cyclone, no liquid should be discharged. “Unbalanced”hydrocyclones will discharge mud without the presence of solids in the mud.

Because fine solids have more specific area (surface area per unit volume) thanlarge particles, the amount of liquid removed per pound of solids is higher with finesolids than with coarse solids. Therefore, the difference between the feed and



6.2

Figure 6.1 Hydrocyclone Operating Principles. The dark ribbon indicates the path taken by the mud and soilds entering the cone. The smaller light ribbon shows the exit path of the cleaned fluid and fine solids.

Hydrocyclones


6.3

underflow density is not a reliable indicator of hydrocyclone performance.Figure 6.2 shows the relationship between underflow density and cone efficiencyfor an unweighted mud. Observe how overall cone efficiency decreases as under-flow density increases.

Performance Parameters

Oilfield hydrocyclones are available in cone diameters ranging from 1 in. to 12 in.Hydrocyclones were first used to reduce the API sand content (solids larger than74 microns). Hence the term “desander.” By convention, hydrocyclones withdiameters of 6 in. or larger are labelled as desanders.

As the benefits of smaller, more efficient hydrocyclones became apparent, theterm “desilter” was coined to reflect the smaller “silt-sized” particles these smallercones could remove. Hydrocyclones with diameters of less than 5 in. are usually

Figure 6.2 Cone Efficiency. Decreasing underflow diameter to improve dryness impairs cone efficiency.



6.4

called desilters. However, these terms are not based on any particularperformance standard. Separation efficiency varies widely among hydrocyclonesclassified as desilters.

The Industry has investigated the operational and geometric design factors affect-ing hydrocyclone performance. Over 500 tests were conducted using bentoniteand ground silica slurries. The effect of these variables on cone performance aresummarized in Table 6.1. Selected variables are discussed below.

1) Cone Diameter

Cone diameter is the main factor in determining processing capacity, provided thebasic design is sound. Larger cone diameters have higher throughput capacityand generally display inferior separation performance. Individual cone capacityguidelines are listed in Table 6.2.

Table 6.1 Effect of Variables on Hydrocyclone Performance

Major Effect Minor Effect

Cone Diameter Feed Solids Concentration (at constant PV)

Feed Solids Distribution Yield Point

Plastic Viscosity Inlet Type

Feed Head Cylinder Length

Cone Angle Vortex Finder Length

Underflow Diameter

Table 6.2 Cone Capacity

Cone Size, inches

Cone Capacity, gpm @ 75 ft head

2 20

3 50

4 50

5 75

6 100

8 125

10 500

12 500

Hydrocyclones


6.5

2) Plastic Viscosity

Hydrocyclone performance is extremely sensitive to the plastic viscosity of thefeed mud. Figure 6.3 shows the effect of plastic viscosity on median separationsize (d50) for a constant underflow solids concentration using a 3-in. hydrocy-clone. Note how the median separation size increases rapidly with plastic viscos-ity from an initial 20 micron cut at PV=6 cp to 50 microns at PV=24 cp.

3) Feed Head

Feed head, or feed pressure, affects hydrocyclone performance as shown inFigure 6.4. Insufficient head reduces fluid velocity within the cone and adverselyaffects separation efficiency. Excessive head will cause premature wear andincreased maintenance cost.

Head is related to pressure and fluid density by the hydrostatic pressure equation:

where P is the feed pressure in psi, 0.052 is a gravitational constant, H is the headin ft, and is the fluid density in lb/gal.

Figure 6.3 Sensitivity to Plastic Viscosity. Hydrocyclone performance declines with increas-ing plastic viscosity.

P 0.052 H ρmud××=

ρmud



6.6

Since most hydrocyclones require 75 ft of head, the required pressure for a givenmud density can be approximated by:

Specific head requirements for most hydrocyclones are provided in Appendix E,Equipment Specifications. A centrifugal pump is used to feed the hydrocyclonesbecause it provides a relatively constant head at a given flow rate. However, cor-rect sizing of the pump is critical to ensure that sufficient head is available at thedesired flow rate. Refer to the section on centrifugal pumps for a more detaileddiscussion on sizing and selecting centrifugal pumps for this application.

4) Underflow Diameter

As underflow diameter is reduced, fewer solids will have sufficient mass (andmomentum) to be discharged. The discharge will be dryer at the expense of sepa-ration efficiency. The appearance of the discharge gives a good indication of coneperformance.

P 4 ρmud×≈

Figure 6.4 Sensitivity to Feed Head. This example, for a 3-in. cone, illustrates the importance of maintaining sufficient feed head.

Hydrocyclones


6.7

Spray Discharge

A normally-operating cone should have an umbrella-shaped discharge of liquidand solids. The solids spiralling downward and out the cone bottom with theirassociated liquid are said to be in “spray discharge.” The inside stream moving uptoward the overflow at high velocity will pull air with it in the vortex. This causes aslight vacuum to occur in the very center of the cone. The air is replaced by airdrawn up through the center of the underflow opening as shown in Figure 6.1.

Therefore, the presence of spray discharge and a slight vacuum in the center ofthe underflow opening is a good indication of a properly operating hydrocyclone.

Rope Discharge

If the solids concentration is high, there may not be room for all of the downwardmoving solids to exit the underflow. This causes an undesirable condition knownas “rope discharge‚” so-called because of the shape of the underflow stream(Figure 6.5).

In rope flow, the solids back up near the exit and decelerate. The underflow den-sity is very high, since the liquid volume is severely reduced and only the largestparticles will exit the cone. Exit velocities are low; the solids will appear to be fall-ing out of the underflow nozzle. Many of the solids will not be able to exit the coneand will return with the liquid in the overflow. High cone wear will occur in thelower region of the cone.

Corrective action consists of opening up the underflow and making sure the open-ing is clear. If the problem still occurs, this is an indication that the solids loadingneeds to be reduced by adding more hydrocyclones. If the problem is with thedesilter, ensure that the desander is operating and that the shakers are runningthe finest screens possible.

Desanders

With the improved fine screening capability of shale shakers, the need for desand-ers has diminished. The primary role of the desander should be to reduce solidsloading to the desilter cones in unweighted water-based muds. Desanders arerecommended when the shakers are unable to screen down to 100 microns(140 mesh U.S. Sieve), or when large hole diameters are drilled at 100 ft/hr orfaster.

Considering that 75 microns is probably the best performance that can beexpected from a desander cone, one might conclude they would have an applica-tion in weighted muds as well. This is generally not the case. Hydrocyclones sep-



6.8

Figure 6.5 Rope Flow Operation Characteristics. This condition should be avoided; try increasing the underflow opening size.

Hydrocyclones


6.9

arate solids based on their mass and the density difference between the solidparticles and the fluid. Since barite's specific gravity is substantially higher thandrilled solids, it will tend to be preferentially removed by hydrocyclones. Also, asshown in Figure 6.3, the higher plastic viscosities normally associated withweighted muds will greatly reduce the desander's efficiency.

Desander underflows are normally quite dry and abrasive and should be dis-carded directly. When processing expensive muds, the underflow may be routedto a centrifuge to recover the liquid, provided the solids are not abrasive and theunderflow is diluted with whole mud before centrifuging. Another option is toscreen the desander underflow down to 200 mesh (74 microns) to remove thelarger, abrasive solids before processing with the centrifuge.

Recommended Desanders

Ten inch diameter desander cones are recommended. They provide the bestcombination of separation and capacity. The larger 12-in. cones usually cannotmake a fine enough cut to be economic. Smaller cones are limited in flowrate andmay deteriorate more quickly in abrasive conditions.

Desilters

Desilters should be used on all unweighted, water-based muds. They are not rec-ommended for use on weighted muds since barite will be lost. When using expen-sive muds, process the desilter underflow with a centrifuge.

A 3-in. hydrocyclone has been developoed which is up to 50% more efficient thansome existing oilfield desilters. Figure 6.6 shows the improvement in performanceover a typical 50 gpm, 4-in. cone.

The 3-in. cone is not a balanced cone; it will discharge fluid even when no solidsare present. In many cases, this cone's underflow should be processed by a cen-trifuge. The economics of centrifuging the underflow should be checked using theSECOP program. Estimated discard rates per cone are plotted as a function ofunderflow diameter in Figure 6.7. Size the centrifuge for the calculated underflowrate. Run the cones intermittently on unweighted mud when no centrifuge is avail-able.

Since the underflow opening of the 3-in. cone is smaller than a typical 4-in. cone,it is more susceptible to plugging. Ensure that all of the mud is fine-screened orrun an efficient, properly installed desander ahead of the 3-in. cones.

Desilters can also be used in certain weighted mud applications to reduce the bar-ite loading to the centrifuge thereby improving its efficiency in barite recoverymode (see Chapter 8, Centrifuges). Here, the underflow of the desilter cones are



6.10

Figure 6.6 Near Optimum Core Efficiency. The 50 gpm 3-in. cone exhibits greatly improved performance over a typical 4-in. cone at the same flowrate.

Figure 6.7 Estimated Discard Rates. Use this chart to estimate underflow rates from the 3-in. cone.

Hydrocyclones


6.11

returned to the active system and the overflow is fed to the Barite Recovery centri-fuge. The upper limit for this application is generally limited to mud densities of15 ppg or less due to viscosity and solids content limitations or cone performance.Use only enough 3-in. hydrocyclones to match the feed rate to the centrifuge.Blank off the remaining cones. Use the largest underflow nozzle diameter avail-able to prevent plugging or rope flow.

Recommended Desilters

MPE 3 in. (15° Cone)MPE 3 in. (10° Cone)

These cones are recommended because of their superior performance. They willprovide the separation performance of a 2-in. cone at the flowrate of a typical 4-in.cone.

Sizing Hydrocyclone Manifolds

For properly routed hydrocyclones, the minimum number required can be esti-mated by:

This equation does not consider solids loading. If penetration rates in excess of100 ft/hr are anticipated, the number of cones should be increased.

Specific head requirements and flow capacities for each cone are listed inAppendix E, Equipment Specifications. Table 6.2 may be used to estimate theflow capacity of each cone operating at 75 ft of head.

Hydrocyclones are normally provided in banks of 8, 10, 12 and 16 cones per man-ifold (Figure 6.8). Increase the required number of cones to one of these standardmanifold sizes.


1. Operate enough hydrocyclones to process over 100% of the circulation rateor to handle the maximum solids loading rate.

2. The hydrocyclone overflow should be discharged to a compartment down-stream from the feed compartment. Use bottom equalization between com-partments.

No. of Cones RequiredMaximum Circulation Rate 1.1×

Single Cone Flow Rate-----------------------------------------------------------------------------------=



6.12

3. Mechanically stir all hydrocyclone removal and discharge compartments toensure uniform feed. Mud guns should not be used because they can reducehydrocyclone efficiency by bypassing a portion of the mud.

4. Do not allow cones to operate with plugged apexes or inlets.

5. Spray discharge at the cone underflow is desired. Rope flow will cause pre-mature wear and is less efficient. Rope flow indicates that either more hydro-cyclones or finer shaker screens are required or that the underflow apex sizeis too small.

6. Because 2-in. cones are extremely susceptible to plugging, consider usingthe 3-in. cone instead. It has twice the capacity and equivalent performance.

7. Do not bypass the shale shaker or operate with torn screens.

8. The hydrocyclone manifold should be located above the mud level in theactive system to prevent accidental loss of mud by siphoning when the conesare not operating.

Figure 6.8 Typical Hydrocyclone Manifold. This is an “inline” manifold. Circular manifolds are also common.

Hydrocyclones


6.13

9. Replace flanged-type hydrocyclones with the quick-connect type to improveservicing time.

10. Replace worn, malfunctioning cones immediately. If no spares are available,remove the cone and blank off the feed and outlet lines.

11. Have a working pressure or head gauge on the manifold feed inlet.

12. Install a siphon breaker on the overflow manifold exit.

13. Size suction and discharge piping to provide flow velocities in the range of5-10 ft/sec. Refer to Chapter 9, Centrifugal Pumps & Piping.

14. Use one centrifugal pump per hydrocyclone manifold.

Troubleshooting

Symptoms Probable Causes

One or more cones are not discharging - others OK.

Plugged at feed inlet or outlet - remove cone and clean out lines.

Some cones losing whole mud in a stream. Backflow from overflow manifold, plugged cone inlet.

High mud loss, conical shape in some cones - others normal.

Low inlet velocity due to partially plugged inlet or cone body.

Repeated plugging of apexes. Too small underflow opening, bypassed shaker or torn screens.

High mud loss, all cones, weak stream, conical shape.

Low feed head-check obstruction, pump size and rpm, partially-closed valve, solids settling in feed line, frozen lines.

Cones at discharge end discharge poorly with a dryer stream.

Strong vacuum in manifold discharge line, usually occurs with long drop into pits - install antisiphon tube.

Cone discharge is unsteady, varying feed head. Air or gas in feed, too small feed lines, air from upstream equipment discharge.

Motor protection fuses “blow.” Required input horsepower is higher than rated horsepower of motor - check for tees bypassing mud, additional equipment, manifolding.

Low impeller life. Cavitation in the pump - flow rate is too high - need larger lines.Suction line blockage - check for obstructions.

Mud percent solids continues to increase. Solids removal is insufficient, solids may be too fine to remove, insufficient cones to match drilling rate - add cones.



6.14

Cones are discharging a heavy, slow-moving stream.

Cones are overloaded - use larger apex size, insuffi-cient cones to match drilling rate - add more cones.

High mud losses. Cone opening is too large - reduce size or consider centrifuging underflows.

Aerated mud downstream of hydrocyclone over-flow return.

Viscous mud, return line ends above fluid level in tank - route hydrocyclone overflow into trough to allow air to break out.

Symptoms Probable Causes

Hydrocyclones


6.15

Summary

• Hydrocyclones separate solids from fluid by using centrifugal force to causesolids to be settled from the fluid. There are no moving parts. Centrifugal forceis created by the conversion of centrifugal pump head into a high velocitystream spiraling within the cone. Solids concentrate in proportion to theirmass near the wall of the cone and are discharged at the bottom of the conein the underflow. Clean fluid and fine solids are returned through the top of thecone in the overflow.

• Cone diameter, cone angle, underflow diameter, feed head, and plastic vis-cosity have the largest effect on hydrocyclone performance.

• Hydrocyclones will produce a relatively wet discharge compared to shaleshakers and centrifuges. Underflow density is not a good indicator of coneperformance. Finer solids will have more associated liquid and the resultantdensity will be lower than with coarse solids.

• Provide enough hydrocyclones to process at least 110% of the circulationrate, more if high penetration rates are expected.

• Use desanders in unweighted mud when the shakers are unable to screendown to 140 mesh (100 microns). The role of the desander is to reduce solidsloading to the downstream desilter. Ten inch diameter desander cones arerecommended; they provide the best combination of separation and flowcapacity.

• Use desilters on all unweighted, water-based muds. The recommended 3-in.cone is up to 50% more efficient than typical 4-in. cones. This cone is anunbalanced design and will discharge a very wet underflow. Process theunderflow with a centrifuge to recover fluid, if the economics warrant.

• Installation and operating guidelines, along with a troubleshooting guide areincluded in this chapter.



6.16


7.1

Chapter 7. Mud Cleaners

A mud cleaner is a bank of hydrocyclones mounted over a vibrating screen(Figure 7.1). Free liquid and particles smaller than the screen openings arereturned to the circulating system. Solids removed by the screen are discarded.Screen sizes between 100 mesh and 325 mesh are commonly available. Mudcleaners were originally developed for use in weighted muds to remove drilled sol-ids down to the size of barite (< 74 microns) when shakers could only run100 mesh (149 microns) screens at best. However, with the fine-screening capa-bility of today’s linear motion shakers, the applications for mud cleaners are lim-ited.

Figure 7.1 Mudcleaner Combines Hydrocyclone and Shale Shaker. The hydrocyclone under-flow is screened to remove solids.



7.2

Where possible, the installation of sufficient fine screen shakers is recommendedfor weighted muds in lieu of a mud cleaner. Shakers equipped with fine-meshscreens guarantee that all of the circulation rate is processed, whereas mudcleaners may treat only a portion of the circulation rate. Shakers are moredependable and their screens typically last longer.

Barite losses measured over mud cleaner screens are higher than losses overshaker screens at the same mesh size. This is due to the high viscosity of thecone underflow and the relatively small screening area of most mud cleaners.Drexel-Brandt and Derrick, among others, have addressed this by mounting desil-ter cones over a full-size shaker deck (Figure 7.2). Derrick uses aspecially-designed “High-G” shaker which they claim also improves cuttings dry-ness. Regardless, overall system efficiency would be better served by an addi-tional shaker at the flowline rather than a mud cleaner in most cases.

Figure 7.2 Brandt ATL 2800 Mud Cleaner. This design mounts 28 4-inch cones over a standard ATL shaker basket.

Mud Cleaners


7.3

Mud cleaners continue to be a popular solids removal device within the industryand will be encountered on many rigs. If economics or space constraints do notjustify the installation of additional shakers on an existing solids removal system,the mud cleaner, when routed and operated correctly, can be used to advantagein both unweighted and weighted muds. Refer to the system arrangements sec-tion for proper fluid routing and mud cleaner placement.


1. Since the mud cleaner is both a hydrocyclone and a shaker, many of theoperating guidelines listed for these devices apply to mud cleaners.

2. A decrease in solids coming off the screen may indicate a torn screen whichshould be replaced as soon as possible.

3. Plugged cones or large solids coming off the screen can imply a problem withthe upstream shale shakers. The likely causes are bypassed screens, tornscreens or dumping the shaker box into the active system.

4. The desilter cones on the mud cleaner should be 6 in. diameter or smaller.The median cuts of larger cones are too coarse to be useful.

Unweighted Muds

1. In unweighted muds, the mud cleaner should be used as a desilter by blank-ing off the screen and discharging the underflow directly.

2. Because the mud cleaner is operated as a desilter, it must be run in parallelwith other desilters (same suction and discharge compartments). As withdesilters, the suction should be from the desander discharge compartmentand the overflow discharged to a downstream compartment.

3. If the hydrocyclone underflow is to be processed by a centrifuge, the screensmay be used to reduce solids loading to the centrifuge. Run the finest screenspossible.

4. In closed-loop systems, route the desander’s underflow onto the mud cleanerscreens to help dry the discharge. Note, however, that the mud passingthrough the screen should be processed by a centrifuge.

5. The hydrocyclones on the mud cleaner should be run as wet as possible toimprove solids removal efficiency.



7.4

Weighted Muds

1. Use the mud cleaners when 150 mesh (100 micron) screens cannot be run onthe shale shakers.

2. At higher mud weights, the screen may become overloaded with solids. If thescreen overloads, remove enough cones to keep it from discharging excessfluid.

3. Monitor the composition and rate of losses over the screens, especially inoil-based muds. Use the same procedure as outlined in the shaker section.

4. For water-based muds, dilution water added at the mud cleaner screen mayreduce barite losses by reducing the viscosity of the hydrocyclone underflow.However, the amount of drilled solids discarded may also be reduced.

Summary

• A mud cleaner is a desilter mounted over a vibrating screen. The desilterunderflow is screened. Fluid and solids finer than the screen are returned tothe active system. Only solids coarser than the screen openings are removed.

• Mud cleaners were originally designed for use in weighted muds when shak-ers were incapable of screening down to the size of the weighting material.With today’s fine screen shakers, the applications for mud cleaners are lim-ited.

• Fine screen shakers are recommended in lieu of mud cleaners: Screen life isbetter, all of the circulation rate is processed, and barite losses are reported tobe lower.

• In unweighted mud, the mud cleaner should be used as a desilter. Screeningthe underflow is unnecessary unless the mud cleaner is used to screen abra-sive solids that will be processed by a centrifuge.

• Use the mud cleaner on existing solids control systems, when 150 mesh(100 microns) screens cannot be run on the shakers in weighted mud.


8.1

Chapter 8. Decanting Centrifuges

Since their introduction to the oilfield in the early 1950s, decanting centrifugeshave become an increasingly common addition to the solids control system. Cen-trifuges are capable of removing very fine solids that cannot be removed by anyother mechanical separation device. In unweighted muds, the centrifuge cangreatly improve the separation efficiency of the solids removal system and reduceliquid discharge volumes when used in conjunction with hydrocyclones. Increas-ingly stringent environmental restrictions on drilling waste discharge and theincentive of reduced dilution and disposal volumes have made the use of centri-fuges economically attractive in many instances. In weighted muds, the centrifugeis used to reclaim barite while removing colloidal solids which can cause high mudviscosity, poor filtercake properties, and decreased penetration rates. The centri-fuge is the primary separation device used in a chemically-enhanced dewateringsystem to reduce liquid discharge volumes.

Unlike other solids removal devices, decanting centrifuges are usually leasedfrom service companies. Very few rigs come equipped with centrifuges becausethey are relatively expensive to purchase and require specialized maintenance. Atypical oilfield-ready centrifuge may cost $80-$150 thousand, depending uponsize, performance and design features. Lease rates range from $150 to $300 perday. It is therefore important to understand the factors affecting centrifuge perfor-mance to economically justify the specific application and to achieve maximumperformance.


The major components of a decanting centrifuge are shown in Figure 8.1. Decant-ing centrifuges separate solids from liquid by imparting high centrifugal forces onthe solid-liquid slurry fed into a bowl rotating at high speed. The feed stream ispumped into the center of the bowl via a feed tube. The slurry exits the feed tubeand enters an acceleration chamber housed inside the conveyor. It exits thechamber through feed ports and enters the bowl area. Here, the slurry is exposedto a high G-force created by the bowl’s rotation. The high G-force causes sedi-mentation of the feed stream solids. The rotating conveyor has flights similar tothreads on a screw which auger the settled solids up the conical section of thebowl and out of the liquid pool. The gear box causes the conveyor to rotate at aslightly slower speed than the bowl. The torque needed to turn the conveyor iscarried through the gear box and emerges at a shaft. This shaft is held by a shearpin or other safety device so that excess torque will not be applied to the gearboxor conveyor. The relatively dry solids continue out of the bowl. The cleaned liquidis “decanted” off through ports at the opposite end (Figure 8.2).



8.2

Figure 8.1 Centrifuge Components. These components are common to most decanting centrifuges used in oilfield applications.

Figure 8.2 Centrifuge Operation. The conveyor augers solids up the conical section of the bowl and out of the liquid pool.

Decanting Centrifuges


8.3

Performance Parameters

The effect of various design and feed parameters on centrifuge performance hasbeen evaluated. The results of this study are summarized to assist in the selectionand operation of centrifuges. Since many centrifuge parameters are related, oneaspect of performance cannot be discussed singularly without implicating others.However, in general, centrifuge performance is affected by the following parame-ters in decreasing order of importance:

1) G-Force

According to Stokes’ Law, particle settling velocity is proportional to G-force:

where:

VT = Particle terminal velocity, in./sec a = Bowl acceleration, in./sec2 = .0054812 x Bowl Diameter x

RPM2

(1 g = 386 in./sec2) Dp = Particle diameter, microns ρS = Solids Density, gm/cm3 ρL = Feed Slurry Density, gm/cm3 µ = Feed Slurry Viscosity, (centipoise = gm/100 cm sec)

Since G-force increases with the square of bowl RPM, it is an important parame-ter. G-force also increases linearly with bowl diameter. Figure 8.3 shows how sol-ids removal efficiency improves with increasing G-force. For a given particle sizeand fluid properties, there is a minimum G-force necessary to invoke settling.Although high G-force is desirable, the cost is proportional to the cube of the bowlrpm and there are similar economic limitations on bowl diameter as well. Thus, therequired G-force must be obtained from a practical combination of speed anddiameter. Most oilfield centrifuges have bowl dimensions from 14 to 28 in. indiameter and lengths from 30 to 55 in. Rotational speeds range from 1000 rpm to4000 rpm, depending on the application. The more expensive, “high-G” machinescan provide up to 3,000 G’s. The specifications for each centrifuge are listed inAppendix E, Equipment Specifications.

Note, however, that increasing G-force eventually reduces solids conveyancecapacity due to torque limitations. As G-forces increase, more solids are settled inthe bowl and they adhere more tightly. More conveyor torque is required to move

VT

aDp2 ρs ρL–( ) 10

6–( )116µ

--------------------------------------------------=



8.4

the solids out. Once the torque limitations of the machine are reached, convey-ance ceases.

2) Viscosity

From Stokes’ Law, particle settling velocity is inversely proportional to fluid viscos-ity. Figure 8.4 illustrates the beneficial effects of a feed mud with a low yield value.This shows the merit of diluting the centrifuge feed to improve performance. It alsohelps explain the relatively poor performance of centrifuges when processingpolymer fluids with characteristically high viscosities at low shear rates.

3) Cake Dryness

Discharge dryness is commonly considered a direct indication of centrifuge per-formance. However, test results have shown that cake dryness is more correctly afunction of particle size and, therefore, is inversely related to separation efficiency.Test points which yielded the driest solids corresponded to the lowest efficiencyand coarsest D50 separation. As shown in Figure 8.5, solids dryness occurs at athreshold G-force level. Subsequent increases in G-force do not remove addi-tional liquid. Length of the dry beach within the centrifuge bowl (a function of ponddepth) also has little effect on dryness. Dry beach length refers to the distance

Figure 8.3 Effect of G-Force on Separation. Higher G’s improve separation performance.



8.5

Figure 8.4 Effect of Viscosity on Separation Performance. Higher yield values degrade centri-fuge separation performance.

Figure 8.5 Effect of G-Force on Cuttings Dryness. Above a certain threshold G-force, cuttings dryness does not improve.



8.6

from the solids discharge ports to the surface of the fluid pond within the centri-fuge bowl. But, the small difference in dryness made a significant difference in theappearance of the solids. At 71% by weight, the solids were quite runny and at76% by weight, the solids seemed much more “stackable.”

4) Pond Depth and Processing Capacity

Pond depth controls both fluid residence time and dry beach length. Test dataconfirms that increased pond depth residence time increases separation. How-ever, increased pond depth reduces centrifuge flow capacity. Maximum flowcapacity is controlled by the height of the cake discharge port. When the fluiddepth in the centrifuge bowl reaches this height, drilling fluid flows out along withthe discarded cake. The flowrate at which liquid spills out the cake discharge portis called the “flood-out” point. Since one objective of centrifuging is to limit liquidwaste, it is obviously not advantageous to run the centrifuge at a flow rate beyondthe flood-out point.

Flooding is controlled by a combination of pond depth and flowrate. The ponddepth is set mechanically by an adjustable weir. The flowrate increases pondheight according to the viscous drag forces which increase the fluid head requiredto drive the liquid through the centrifuge. The head height is added to the fixedpond depth to give a total depth of fluid in the bowl. For example, consider a cen-trifuge with a maximum fluid depth of 3 in. before flood-out (closed fluid exit ports).If 300 gpm is the maximum flow rate at floodout with a 1-in. pond depth setting,this means 2 in. of fluid head was developed. If the pond depth setting is adjustedto 2 in., then only 1 in. of fluid head is available before the 3-in. flood-out point isreached. Obviously, the maximum flowrate for this pond depth setting will have tobe much less than 300 gpm.

Maximum flow capacity is achieved when the shallowest pond depth is used atthe expense of separation efficiency. Conversely, deep ponds maximize separa-tion efficiency at the cost of flowrate capacity. The best combination is determinedby the coarseness of the solids to be separated. Figure 8.6 illustrates how, for afine solids size distribution, a deep pond depth at lower flow rates can producealmost the same cake rate as a shallow pond depth at higher flow rates. This isdue to the improved separation efficiency of the deep pond case. Figure 8.7shows how, for coarse solids, the higher flow capacity of the shallow pond pro-duces more solids removal than the deep pond case. The results suggest that, forcoarse particle size distributions as encountered in top hole drilling, shallow ponddepths are advantageous, whereas deep ponds should be used for all other appli-cations.



8.7

Figure 8.6 Effect of Pond Depth on Fine Solids Removal. Deeper ponds are more efficient than shallow ponds when the solids are very fine.

Figure 8.7 Effect of Pond Depth on Coarse Solids Removal. Shallow pond depths are preferred for coarse solids distributions.



8.8

5) Bowl - Conveyor Differential RPM And Torque

Differential RPM is the difference between the bowl RPM and the conveyor RPM.The differential is provided by the gearbox which transmits power from the bowl tothe conveyor. Differential RPM is simply calculated by dividing the bowl RPM bythe gearbox ratio. Many centrifuge manufacturers provide a “backdrive” which canindependently alter the ∆RPM. Backdrive units are, in effect, hydraulic gear reduc-tion systems used to vary the speed of the conveyor relative to the bowl. On“backdrive” units, ∆RPM depends upon the rotation of the gearbox pinion and theorientation of the flights on the conveyor. For these units, ∆RPM may be calcu-lated by:

∆RPM = (Bowl RPM - Pinion Speed)/Gearbox ratio.

∆RPM is important because it determines the velocity at which solids are con-veyed through the centrifuge. For example, a ∆RPM of 50 and a flight pitch of 3-in.yields a conveyance velocity of 150 in./min. Another expression takes the flightpitch and number of leads on the conveyor into account to describe the surfacearea of the bowl swept by the conveyor flights per unit time. The faster the rate atwhich the area is swept, the greater the solids capacity.

As = 2π rcyl x ∆RPM x SN

where:

As = swept area/unit timercyl = cylindrical bowl radiusS = flight pitchN = number of leads on the conveyor

This equation suggests that solids capacity can be increased by increasing the∆RPM (lowering the gearbox ratio). Low swept area values could indicate poten-tial torque problems. For example, centrifuges with 130:1 or higher gearbox ratiosand centrifuges with 80:1 gearbox ratios with single-lead conveyors may be lim-ited in flowrate by torque.

Test data indicates that increasing ∆RPM reduces torque. Also, torque increasesas feed median particle size increases. Despite the common belief that high∆RPM values agitate the pond and inhibit sedimentation, test results indicate thatthe effect of ∆RPM on solids removal efficiency is slight, provided sufficient differ-ential exists to remove the solids.



8.9

Centrifuging Unweighted Mud

Centrifuging unweighted muds provides two major benefits: 1) The removal ofdrilled solids that are too fine to be removed by any other solids removal device,and 2) a relatively dry discharge. Although the centrifuge cannot remove ultrafine,colloidal solids, it is important to remove the fine solids before they degrade intothese submicron particles. As a rule, at least 25% of the circulating rate should becentrifuged. It is usually uneconomic (and logistically unfeasible) to process theentire circulating rate. Regardless, the benefits of centrifuging to remove fine sol-ids cannot be understated.

High-G, high capacity centrifuges are recommended to maximize separation per-formance. Refer to the discussion on centrifuge selection, appearing later in thischapter. Since separation efficiency varies inversely with feed rate and residencetime, the optimum feed rate is not necessarily the highest possible rate. Rather, itis the combination of pond depth and feed rate that produces the highest solidsdischarge rate. The maximum efficient processing rate for a large oilfield centri-fuge will seldom exceed 250 gpm, even for relatively coarse drilled solids and lowfluid viscosities. If the particle size distribution is very fine, more solids may beremoved with a lower feed rate and deeper pond depths.

Centrifuging Hydrocyclone Underflow

When liquid discharge must be strictly controlled due to high mud cost, high liquiddisposal cost or limited reserve pit capacity, the centrifuge should process theunderflow of the desilter cones. In this configuration, the hydrocyclones are usedto concentrate solids to the centrifuge which then separates the drill cuttings fromthe free liquid and colloidal solids. System performance can be improved by open-ing the cone apexes to discharge more liquid. This improves the separation effi-ciency of the cones and produces a less viscous slurry at the underflow.Figure 8.8 gives an example of how centrifuging desilter underflow becomes eco-nomic with increasing mud cost and desilter underflow rates. Enough centrifugecapacity must be available to process slightly more than the cone underflow rate.Additional makeup volume should be provided from the active system down-stream of the hydrocyclone feed.

Because the hydrocyclone underflow must be segregated from the active system,a separate centrifuge feed compartment is required. Figure 8.9 and Figure 8.10illustrate two designs for the centrifuge feed compartment. The compartmentshould be small (<50 bbls) to prevent solids settling. Both high and low equaliza-tion should be provided. The low equalizer supplies makeup volume from theactive system during normal processing. A valve (normally open) should beinstalled on the low equalizer. This valve may be used to check that the centrifuge



8.10

feed rate exceeds the cone underflow rate. If the centrifuge is to be used inweighted mud to process the centrate of the barite recovery centrifuge, the valveshould be closed to isolate the feed compartment. The high equalizer is providedto prevent accidental overflow.

Operating Guidelines, Centrifuging Unweighted Mud

1. When processing the active system, the centrifuge feed should be taken fromthe desilter discharge compartment or downstream. The centrate should bereturned to next downstream compartment.

Figure 8.8 Economics of Centrifuging Hydrocyclone Underflow. Substantial savings are possi-ble by recovering the liquid from cone underflows.



8.11

2. Provide enough centrifuges to process at least 25% of the circulation rate.Large, high-G units are usually required.

3. Run at maximum bowl RPM to achieve highest G-force and best separation.

4. Operate the centrifuge just below the flood-out point.

5. The best feed rate and pond depth will depend on the size distribution of thedrilled solids. Use shallow ponds and high feed rates when coarse solids pre-dominate. Conversely, deeper ponds and lower feed rates are more efficientwhen fine drilled solids are to be removed. Field experimentation is necessaryto optimize centrifuge setup.

6. Always wash out the centrifuge on shutdown.

7. If the centrifuge is to used on both unweighted and weighted muds, rig up toallow either option. Both the centrate and solids streams should be rigged upto allow each to be discarded or returned to the active system.

8. The solids discharge chute should be angled at greater than 45° to preventsolids buildup. If this is not possible, a wash line may be necessary to assist inmoving the solids. On land-based operations, use the reserve pit as a sourcefor wash fluid. Do not create unnecessary reserve pit volume by using rigwater.

Figure 8.9 Fluid Routing to Centrifuge Hydrocyclone Underflows. The desilter underflow is segregated from the active system for processing by the centrifuge.



8.12

Centrifuging Weighted Muds

The centrifuge is used in weighted mud applications to recover valuable weightingmaterial from mud which must be discharged due to unacceptable colloidal solidscontent. The centrifuge settles out barite and coarse drilled solids which arereturned to the active mud system to maintain density. The relatively clean cen-trate containing liquid and colloidal solids is discarded. These colloidal solidscause many drilling fluid problems, such as high surge/swab pressures andECDs, differential sticking, and high chemical costs. Usually, the value of theweighting agent in these mud systems makes it economic to recover the weight-ing agent from the whole mud before it is discarded. Figure 8.11 gives an exampleof the economics of centrifuging weighted muds.

Ideally, the barite recovery process should remove only colloidal solids withoutlosing the larger particle sizes used as weighting material. Discarding potentiallyreusable barite increases barite use and drilling fluid cost. Barite losses can be

Figure 8.10 Internal Centrifuge Feed Compartment Design. The dense desilter underflow will displace the lighter active system mud from the centrifuge feed compartment.



8.13

reduced when the centrifuge makes the maximum liquid/solids separation. As dis-cussed in the previous section, this means operating the centrifuge at highG-force. Figure 8.12 shows the effect of G-force on the amount of barite discardedin the centrate. At 20 gpm, the difference in barite losses is 4.58 lb/min. Based on10 hours per day centrifuging and barite cost of $6.50 per 100 lb, high G-forcecentrifuging should save $175 per day.

Centrifuges are usually torque-limited in weighted muds due to the high solidscontent. Typically, torque is reduced by slowing bowl RPM. This reduces G-forceand ∆RPM, resulting in less effective liquid/solids separation and the likelihood ofincreased torque from reduced solids conveyance.

Figure 8.11 Choice of Drilled Solids Removal from Weighted Mud. This example shows the economic advantage of recovering barite.



8.14

Operating Guidelines, Barite Recovery Mode

1. The following procedures are recommended to reduce torque when operatingcentrifuges in barite recovery mode to maximize liquid/solids separation:

A. For a given flowrate, increase the pond depth until the recovered solidsbecome “runny.” Buoyant force reduces the torque needed to convey sol-ids out of the centrifuge. A shallow pond creates a long beach section.Once the solids exit the pool, the extra energy required to convey thesesolids results in higher torque.

B. Process weighted mud continuously at a reduced feed rate rather thanintermittently at higher feed rates. This reduces solids loads and results inless torque. It also increases residence time which will result in finer sep-aration.

C. At higher mud weights, use hydrocyclones to reduce the solids loading inthe feed mud to the centrifuge. The cone underflow is returned to theactive system. The overflow, containing fewer solids, is fed to the centri-

Figure 8.12 Benefits of Increased G-Force on Barite Recovery. Less barite is lost in the centri-fuge centrate with increased G-force.



8.15

fuge. Since solids concentration is reduced, torque from conveying set-tled solids is reduced and permits higher G-force centrifuging.

2. Provide sufficient centrifuge capacity to process 5-15% of the rig circulationrate. Centrifuge capacity is reduced in weighted mud; the 25% target recom-mended for unweighted mud is usually difficult to attain in weighted mud.

3. Add as much dilution water as possible to the centrifuge feed to reduce themud viscosity and improve centrifuge separation performance.

4. Return the solids to a well-agitated compartment upstream of the suction andmixing tanks.

5. Use a high weir between the barite return compartment and the next down-stream compartment to keep the fluid level high. This will promote better mix-ing.

6. Always wash out the centrifuge on shutdown.

7. Routinely check the centrifuge performance by measuring the flow rate andsolids composition of the cake and centrate.

Two-Stage Centrifuging

Two-stage centrifuging is used in weighted muds when the liquid phase cannot bediscarded for economic or environmental reasons. The most frequent applicationis in weighted, oil-based muds where the expensive liquid phase cannot be dis-carded. The first centrifuge recovers weighting material from the weighted mud asdiscussed in the previous section on single-stage centrifuging for barite recovery.The centrate, instead of being discarded, is fed to a second centrifuge operatingat higher G-force. This centrifuge is used to discard the solids and return thecleaned liquid phase into the active mud system (Figure 8.13).

For two-stage centrifuging to be efficient, the first centrifuge must make a goodseparation since most of the solids in its centrate will be discarded. The poorer theseparation, the more barite which will be carried over in the centrate and dis-carded by the second centrifuge. Similarly, the second centrifuge must operate atthe highest possible G-force to remove the most solids. Pond depths should alsobe deepened to just under the flood-out point for the best separation efficiency.

Economics of two-stage centrifuging are site-dependent. Variables such as time,drilling fluid, buy-back agreements, and well plans contribute to the overall eco-nomics. Field experience has been mixed on the cost-effectiveness. As a rough“rule of thumb,” oil-based muds with barite concentrations greater than 4 lb/gal(i.e., 12 ppg mud) are usually candidates for two-stage centrifuging. Below thisconcentration, centrifuging to strip all solids including barite may be more eco-



8.16

nomical, especially at lower mud weights. At intermediate mud weights, “dumpand dilute” may be a viable option depending upon the conditions of the buy-backagreement. “Dump and dilute” in this case means transferring mud laden with lowgravity solids from the active system to storage tanks for return to the mud com-pany. Clean whole mud is used to replace the “dumped” mud in the active system.

Another option is to “do nothing” except screen the mud and dilute when possibleto maintain mud properties. The decision to employ this alternative should bemade judiciously. It is usually better to err on the side of caution. Over time, lowgravity solids will become a large percentage of the weighting material. Filtercakethickness, mud viscosity, and material consumption also may increase. However,this may be the least expensive alternative when drilling time is short and holesizes are small. Oil-based muds are quite “solids-tolerant” and can withstandsome buildup of low-gravity solids. This option is not generally recommended forwater-based fluids.

Field Evaluation of Two-Stage Centrifuging Economics

An evaluation of two-stage centrifuging economics can be made in the field. Thismethod computes the total centrifuging cost (including rental cost and the value ofthe mud and barite discarded). This cost is compared to the value of the whole

Figure 8.13 Two Stage Centrifuging. The first centrifuge recovers barite; the second centrifuge dries its centrate and recovers valuable fluid.



8.17

mud that must be discarded to remove an equivalent amount of low gravity solids.The following data is required:

*Barite and Low Gravity Solids concentrations in lb/bbl of whole mud are deter-mined from retort analysis and must be corrected for salt content.

Calculations

Two-Stage Centrifuging Cost

1. Mass Flow Rate of Drilled Solids, (lb/hr):

Mds = Qdis x LGSdis

2. Mass Flow Rate of Barite, (lb/hr):

Mbar = Qdis x HGSdis

3. Mud Discard Rate, (bbl/hr):

Qliq = Qdis - Mds/928 - Mbar/1471

4. Value of Discarded Barite, ($/hr):

$/hr(bar) = Mbar x Cb/100

5. Value of Discarded Liquid Mud, ($/hr):

$/hr(mud) = Qliq x Clm

6. Total Two-Stage Centrifuging Cost, ($/hr), ($/day):

$/hr = Ccen/24 + (4) + (5)

*$/day = Ccen + t ((4) + (5))

Active System Mud Density, ρm (ppg) Barite Concentration, HGS (lb/bbl)* Low Gravity Solids Concentration, LGS (lb/bbl)*

Centrifuge Discard Sludge Density, ρdis (ppg) Operating Time, t (hrs)Centrifuge Discard Rate, Qcen (lb/hr)*Barite Concentration, HGSdis (lb/bbl)*Low Gravity Solids Concentration, LGSdis (lb/bbl)

Costs Barite Unit Cost, Cb ($/sack)Liquid Mud Cost, Clm ($/bbl)Centrifuge Rental Cost, Ccen ($/day)



8.18

* Disposal/treatment cost of the centrifuge discard should be added to theTotal Cost, if applicable. Use Qcen for total hourly sludge rate.

Equivalent Whole Mud Disposal Cost

7. Whole Mud Discard Rate, (bbl/hr):

Qmud = Mds/LGS

8. Mass Flow Rate of Barite Losses, (lb/hr):

Mbar(m) = Qmud * HGS

9. Liquid Mud Losses, (lb/hr):

Qliq(m) = Qmud - Mds/928 - Mbar(m)/1471

10. Barite Cost, ($/hr):

$/hr(bar) = Mbar(m) x $/sack x 1/100

11. Liquid Mud Cost, ($/hr):

$/hr(liq) = Qliq(m) * $/bbl

12. Hourly Cost of Discarded Mud, ($/hr):

$/hr = (10) + (11)

13. *Daily Cost of Discarded Mud, ($/day):

$/day = t x (13)

*If using oil-based mud, the “buy-back” value of the discarded mud should besubtracted from the daily disposal cost.

Centrifuge Selection

Generally, the following features on a centrifuge are highly recommended:

1. Accelerator for the feed to decrease turbulence.

2. Tungsten carbide feed port entries to prevent erosion.

3. Tungsten carbide tiles on the conveyor to improve wear resistance.

4. Universally adjustable pond dams to “fine-tune” centrifuge performance.

5. Stainless steel bowl and conveyor to reduce corrosion problems.

6. High G-force to ensure maximum separation performance.



8.19

Since centrifuges are normally leased, quality of service in the local area shouldbe a primary consideration when selecting centrifuges. A centrifuge with all thefeatures listed above will not be much use if it cannot be kept running because ofpoor maintenance. Contract length should also be considered. For example,hard-facing on the conveyor instead of tungsten carbide tiles, or a carbon steelbowl instead of stainless steel is entirely acceptable if the centrifuge is to beleased for a short term and maintenance costs are borne by the contractor. Con-versely, when drilling in remote areas or under harsh conditions, the featureslisted above will help ensure continued trouble-free operation. Regardless, a fullinspection should be performed before the centrifuge is accepted for lease.

The coarseness of the solids can also influence centrifuge selection. As shown inFigure 8.14, when the solids distribution is fine, a small “high G” machine such asthe Sharples 14 x 30 may remove more solids at a lower feed rate than a largebowl, “low G” machine such as the Bird 24 x 38. Conversely, the larger bowlmachine will provide superior performance when the solids are coarse(Figure 8.15).

Table 8.1 and Table 8.2 contain recommended common oilfield centrifuges.Table 8.1 lists centrifuges recommended for unweighted mud applications.Table 8.2 lists centrifuges recommended for weighted mud applications. Thesetables are provided as a guideline only. Centrifuges not listed in these tables mayprovide equivalent performance provided the performance criteria discussedpreviously are met. For example, Sharples builds larger centrifuges than theP3400. These larger centrifuges will provide superior performance, but very feware available for drilling application and are not listed here.

Table 8.1 Recommended Centrifuges for Unweighted Mud

Centrifuge Bowl SizeMaximum Bowl

RPM

Hutcheson Hayes HH5500 16 in. x 55 in. 3250

Alpha-Laval 418 14 in. x 56 in. 4000

Swaco HS 518 14 in x 56 in. 3313

Derrick DE1000 14 in. x 50 in. 4000

Drexel-Brandt HS3400 14 in. x 50 in. 3250

Sharples P3400 14 in. x 50 in. 3250

Oiltools S3.0 21 in. x 62 in. 1800

Sweco SC-4 24 in. x 40 in. 1950

Broadbent 24 in. x 38 in. 1900

Derrick DB-1 24 in. x 40 in. 2000

Drexel-Brandt CF2 24 in. x 38 in. 1900



8.20

Figure 8.14 Centrifuge Performance Comparison on Fine Solids Distribution. The smaller 14 x 30 “High G” centrifuge is more efficient when solids are fine.

Figure 8.15 Centrifuge Performance Comparison on Coarse Solids Distribution. The high flow capacity of larger “Low G” machines is preferred in the presence of coarse solids.



8.21

Equipment Descriptions

Hutcheson-Hayes HH5500 (16 X 55)

This machine has all of the recommended features including a high capacity gear-box to minimize gearbox failure. In most applications, it has more flow capacityand separating power than the other centrifuges listed. The 5500 can be run at3250 RPM in unweighted muds and approximately 2600 RPM in weighted fluids.A variable speed controller on the main drive is recommended for dual purposeapplications. Because it is a relatively new product, few HH5500s are currentlyavailable as rental units.

Alpha-Laval 418/Swaco HS 518 (14 X 56)

The Alpha-Laval 418 and the Swaco HS 518 have the same basic design,although the Alpha-Laval has a higher maximum bowl speed and should havemore separating power than the slower Swaco unit. Plate type pond dams requiretotal replacement for adjusting pond depth. Adjustment for three differential RPMsis provided. The flight spacing and 60:1 gearbox ratio give reasonable perfor-mance. The 418 and 518 are not recommended for barite recovery; the long bowllength is prone to developing high torque in weighted muds.

Derrick DE1000/Sharples P3400/Brandt HS3400 (14 X 50)

These Sharples-designed centrifuges have most of the desired design featuresand will provide superior performance in unweighted muds. Recently, Sharpleswas bought out by Alfa-Laval, who reportedly will discontinue production of theSharples P3400 and P3000 in favor of their own 418 and 414 models. The longbowl is susceptible to developing high torque in weighted muds and is not nor-mally recommended for barite recovery. Derrick now manufactures this design

Table 8.2 Recommended Centrifuges for Weighted Mud

Centrifuge Bowl Size

Alpha-Laval 414 14 in. x 38 in.

Swaco 414 14 in. x 38 in.

Sweco SC-4 24 in. x 40 in.

Broadbent 24 in. x 38 in.

Hutcheson Hayes HH1430 14 in. x 30 in.

Oiltools S3.0s 18 in. x 56 in.

Sharples P3000 14 in. x 30 in.

Sweco SC-2 18 in. x 30 in.



8.22

with some mechanical improvements, fully-tiled conveyor flights, and the option ofvariable main and back drives. With the variable drive, Derrick has been success-ful in using this machine as a barite-recovery unit.

Oiltools S3.0 (21 X 62), S2.1 (18 X 56)

These centrifuges are manufactured by Humbolt-Wedag in Germany under a BirdMachine Co. license. Both can provide reasonably good separation performanceprovided they are operated at maximum RPM in unweighted muds. Both units arefully hydraulic which helps prevent solids overloading and bowl plugging in bariterecovery mode. The S2.1 is normally supplied as the barite recovery centrifuge.The quality of local service is an important consideration for these centrifuges aswith all hydraulic units.

Bird Design Centrifuges - Sweco SC-4, Broadbent, Brandt CF-2,Derrick DB1

This 24 x 38 in. oilfield centrifuge was originally a Bird design. Modifications to thebasic design have been made in accordance to the specific company’s designconcepts. Both Sweco and Broadbent build their machines in-house. Brandt pur-chases the centrifuge rotating assembly and “skids it out” in-house.

These machines will have suitable separation performance above 1900 RPM. Allexcept the Brandt have x-rayed welds to certify operation at this higher RPM. TheDerrick machine has a longer bowl (24 x 45 in.) and will perform best inunweighted muds. Gearbox ratio and conveyor flight design vary significantly. TheSweco and Broadbent machines have 60:1 gearbox ratios and double-lead con-veyors that provide good performance in barite recovery operations. The BrandtCF-2 has a widely-spaced, single-lead conveyor with a 140:1 gearbox moresuited to unweighted mud. The optional hydraulics package offered by Sweco isrecommended when the SC-4 is used as the high-g centrifuge in two-stage opera-tions. It will provide a slightly higher bowl RPM and adjustable differential RPM tomaximize separation performance.

Alpha-Laval 414, Swaco 414 (14 X 38), Sharples P3000,Hutcheson Hayes HH1430 (14 X 30)

These machines have the same features as their longer-bowled counterparts. Theshorter bowl length reduces retention time and makes these centrifuges less sus-ceptible to high torque in barite recovery applications. The larger machines arerecommended for unweighted mud applications.



8.23

Summary

• With the emphasis on reduced waste volumes and improved solids removalefficiency, the centrifuge has become an integral part of the drilling solidsremoval system. Centrifuges are capable of removing very fine solids thatcannot be removed by any other mechanical solid removal device. The solidsdischarge is relatively dry.

• Laboratory tests indicate that centrifuge performance is chiefly a function ofG-force, pond depth, bowl-conveyor differential rpm and mud viscosity.G-force, a function of bowl rpm and diameter has the greatest impact on sep-aration efficiency. Pond depth controls both fluid residence time and flowcapacity. Differential rpm is a factor in solids conveyance and torque limita-tions. Increasing yield values detrimentally affect separation efficiency.

• Once a minimum threshold G-force is reached, cake dryness is relativelyunaffected by G-force. However, a minor difference in dryness may changethe appearance of the solids from runny to stackable.

• Large, high G-force machines are recommended for centrifuging unweightedmuds. Use deep pond depths and lower flow rates for fine solids distributions.Coarse solids distributions may be more efficiently processed using shallowpond depths and higher flow rates.

• Centrifuging hydrocyclone underflows becomes increasingly economic asmud formulation and waste disposal costs increase. The centrifuge shouldprocess in excess of the hydrocyclone underflow rate. Two designs for centri-fuge catch tanks are shown. A low-G, high capacity centrifuge is recom-mended for these coarse solids.

• The centrifuge is used in weighted mud to recover valuable weighting materialfrom mud which must be discharged due to unacceptable colloidal solids con-tent. The economics of barite-recovery centrifuging is usually positive whenthe liquid phase is inexpensive and disposal costs are not prohibitive. G-forceshould be maximized to improve barite recovery.

• Two-stage centrifuging is necessary in weighted muds when liquid dischargemust be minimized. The first centrifuge recovers barite. Its effluent is fed to asecond centrifuge operating a maximum G’s, which discards solids andreturns the liquid phase. Colloidal solids are not removed. The economics oftwo-stage centrifuging are site-dependent. A method for monitoring the costeffectiveness of two-stage centrifuging is presented in this section.

• Recommended features on a centrifuge include: 1) Accelerator for the feed,2) tungsten carbide feed port entries and conveyor tiles, 3) universally adjust-able pond dams, and 4) stainless steel bowl and conveyor. However, qualityof service is paramount. Recommended centrifuges for both unweighted andweighted muds are listed.



8.24


9.1

Chapter 9. Centrifugal Pumps & Piping

Centrifugal pumps are ideal for the low pressure, high flow rate requirements ofhydrocyclones and mixing systems. Unlike constant-volume piston pumps, centrif-ugal pumps provide constant “head.” Consequently, the pump and associated pip-ing system must be correctly sized and designed to deliver the required flow rateand desired head. This section briefly describes how centrifugal pumps work andprovides guidelines for the design, installation and operation of centrifugal pumpsand piping systems.


The centrifugal pump consists of a rotating impeller mounted inside a casing(Figure 9.1). Fluid enters the casing at the center (the eye of the impeller). As theimpeller spins, the fluid is accelerated to the circumference by the curved impellervanes. The accelerated fluid exits the impeller and enters the pump casing wherethis kinetic energy is converted into pressure energy. Although the pump canoperate against a closed discharge valve, it is not recommended. When there isno flow, all the pump power is dissipated into the fluid. This will cause the pumpand motor to quickly overheat.

A drive shaft connected to the impeller transmits power from the driver. A stuffingbox or seal is normally used to prevent leakage. The most common driver for cen-trifugal pumps is the a.c., fixed-speed, induction motor. Variable-speed motors areavailable, but rarely required for drilling rig applications. The motor is joined to thepump shaft by a flexible coupling. Drivers are usually three-phase motors. Therotation of the pump should be checked when it is installed to make sure that it isrotating in the proper direction.

Centrifugal pumps are usually constructed of a cast-steel housing with cast-ironinternal parts. Long-life packages offer hard-facing on the high-wear areas of thepump. Wear-resistant tungsten carbide seals are also available. Both are highlyrecommended.

The pump performance curves in Appendix D, Pump Performance Curves, illus-trate that the head generated by centrifugal pumps decreases very little as theflow rate is increased. Conversely, the flow rate through hydrocyclones is notaffected much by head. Note, however, that hydrocyclones are designed to oper-ate at a certain amount of head. Less or more may be detrimental to their perfor-mance. Therefore, the pump should be sized to provide the correct head at theflow rate dictated by the hydrocyclones.



9.2

Sizing Centrifugal Pumps

1. Determine the total flow rate needed. For a hydrocyclone manifold, the flowrate is calculated by:

2. Determine the total head required. For most hydrocyclones, the required inlethead is 75 ft. The total head required from the pump is:

where:

Figure 9.1 Typical Centrifugal Pump. Kinetic energy is converted into pressure energy by the rotating impeller vanes to provide consistent head.

Q (gpm) # of Cones Flow Capacity Cone⁄×=

Ht 75 ft Lift Height (ft) Friction Losses (ft)+ +=

Centrifugal Pumps & Piping


9.3

Lift Height is the height between the hydrocyclone manifold and the mud sur-face (not the pump suction).

Friction Losses are the equivalent loss of head through lines, elbows andtees. For most installations, this is generally between 2 and 5 ft. If long linelengths and/or numerous elbows and tees are present, use a worksheet asshown in Table 9.1 to calculate the actual friction losses. An example calcula-tion is provided.

3. Using the pump performance curve for your pump (Appendix D, Pump Perfor-mance Curves), find the intersection of the total flow rate required (Step 1)and the total head required (Step 2). Choose the impeller size which corre-sponds to this point. If the intersection point falls between impeller sizes,choose the next larger impeller size.

4. Determine the required horsepower to drive the pump. Using the pump perfor-mance diagram for your pump, find the intersection point for the impeller sizedetermined in Step 3 and the total flow rate (Step 1). Read the correspond-ing horsepower required at this point. Interpolate between the horsepowercurves when necessary. This is the horsepower required to pump water. Forany mud weight, the required brake horsepower (BHP) is calculated by:

Centrifugal Pump Sizing Example

Problem:

Determine the pump requirements, given the following desilter arrangement:

12-50 gpm conesRequired head - 75 ftMaximum Mud Density - 10 ppgPiping System as shown in Figure 9.2

Solution:

1. Calculate Total Flow Rate

BHPmudρmud ppg( ) BHPcurve×

8.34--------------------------------------------------------------=

Q 12 cones 50gpmcone--------------× 600 gpm= =



9.4

2. Calculate the pump discharge head:

A. Using a worksheet such as Table 9.1, list the length and size of each pipe,and the number and size of each fitting.

B. From Table 9.2, find the friction loss coefficients (C) for each item listed.

C. Calculate the friction loss for each item.

D. Sum the friction losses to arrive at the total friction losses.

E. The total required head is the sum of the required hydrocyclone head, thefeet of lift and the friction losses.

3. From the Pump Performance Curves (Appendix D, Pump PerformanceCurves), select a pump which will provide the required head and flow rate.

For this example, a Harrisburg Series 250 6 x 5 x 14 pump operating at1150 rpm with a 14 in. impeller will provide 95 ft of head at 600 gpm.

4. Determine the Horsepower required.

At 95 ft of head and 600 gpm, this pump will require 25 HP to pump water.Correcting for 10 ppg mud:

Figure 9.2 Centrifugal Pump Sizing Example.



9.5

Table 9.1 Detailed Worksheet for Pump Sizing

Equipment Information

Required Flow Rate Q (gpm) = 600

Required Hydrocyclone Head HH (ft) = 75

Feet of Lift HL (ft) = 6

Tabulation of Friction Losses

N is the length of pipe (ft) or number of Fittings

N Pipe Length or Fitting Type Size (in.)

= Friction Loss (ft)

1 Extended Entrance 6 = .02

10 Suction Line 6 = .24

15 Discharge Line 5 = .87

2 Short Elbows 5 = .93

Total Friction Loss, HF (ft) = 2.06

Total Required Head, HT (ft)

HH + HL + HT = HT

75 + 6 + 2 = 83 ft

BHPmudρmud ppg( ) BHPcurve×

8.34--------------------------------------------------------------=

10( ) (25)8.34

------------------------=

30 HP=

N C QR2××

1 106×

-----------------------------

1( ) 0.664( ) 600( )2

1 106×

-------------------------------------------

10( ) 0.0664( ) 600( )2

1 106×

-------------------------------------------------

15( ) 0.1612( ) 600( )2

1 106×

-------------------------------------------------

2( ) 1.29( ) 600( )2

1 106×

----------------------------------------

Solids Control M

anual


hevron Corporation C

ompany and other w



9.6

Table 9.2 Friction Loss Coefficients for Pipe Fittings2

Nominal Pipe Size

Actual Inside

Diameter (Inches) Std Wt

Straight Pipe1

Gate Valve FULLY OPEN

Long Ell Threaded

45°Ell Threaded

Cone Entrance

Standard Tee

Threaded

Square Entrance

90° Ell Threaded

Reduced Tee

Threaded

Extended Entrance

Square Ell

Standard Tee

Threaded

Butterfly Valve

FULLY OPEN

Swing Check Valve

FULLY OPEN

Globe Valve FULLY OPEN

Welding Ell 90°Standard Weight

Short Long

For 45° EllsUse 65% of Values

Given Below

1/23/4

.622

.82410,0482,300

4,019920

8,0342,300

11,0533,220

17,0824,830

33,15896,600

--

50,24016,100

190,91252,900

--

--

11-1/41-1/2

1.0491.3801.610

62814767

37710361

879264148

1,130338182

1,632514276

3,3261,028546

---

5,0201,616877

18,1985,7293,035

---

---

22-1/2

3

2.0672.4673.068

18.77.32.3

18.77.34.6

56229.1

74.729.411.4

9344

18.3

1878834

20581

18.3

28014053

1,083507196

562911

37227

456

4.0265.0476.065

.5485

.1612

.0664

1.10.48.20

2.741.13.53

3.841.29.66

5.492.101.00

10.974.031.99

4.941.13.73

17.66.453.19

62.022.911.3

3.841.29.66

2.19.81.40

81012

7.98110.02012.000

.0156

.0047

.0019

.062

.024

.011

.172

.061

.030

.203

.080

.038

.312

.118

.057

.624

.235

.114

.203

.075

.042

.515

.197

.095

3.491.32.64

.203

.061

.038

.125

.039

.023

1. Based on pipe friction factor, f = .047. For other function factors, C = [31,088 f/d5] * L where L has units of feet and d has units of inches.2. Adapted from IADC Mud Equipment Manual, Handbook 4, Centrifugal Pumps and Piping Systems.

RD

= 1 RD

= 1.5



9.7

Estimating Impeller Size

In many instances, we are dealing with existing equipment and need to determinethe pump impeller size to estimate output capacity. The impeller size of a centrifu-gal pump can be estimated by the following procedure:

1. The fluid density, pump rpm, a valve on the pump discharge and an accuratepressure gauge between the pump and valve are required.

2. With the pump running, close the discharge valve and read the pressure.Note: Limit time to less than 3 minutes.

3. Convert pressure read in Step 2 to head (feet).

4. Plot the head from Step 3 on the pump performance curve for 0 gpm. Esti-mate the effective impeller size.

Pipe Sizing

As was evident in the centrifugal pump sizing example, the pipe diameter and thedesign of the piping system will affect the size of the pump and the horsepowerrequirements. Suction and discharge lines should be as short as practical andsized to flow at velocities in the range of 5 to 10 ft/s. Low velocities will allow solidsto drop out in the lines. High velocities erode elbows and cause distribution prob-lems in the hydrocyclone manifold. Inadequate suction line size can cause cavita-tion in the pump. Also, the suction line should have no elbows, tees or reducerswithin 3 pipe diameters of the pump suction flange.

Pipe velocity can be calculated using the following equation:

where:

Q = flow rate, in gal/mindi = inside diameter of the pipe, in inches

As a quick reference, the maximum and minimum recommended flow rates forcommon pipe diameters are listed in Table 9.3.

Suction Head Requirements (NPSH)

The suction line of the pump must be submerged to prevent vortexes in the suc-tion tank or air locking of the pump. Centrifugal pumps require a net positive suc-

v ft s⁄( ) Q

2.48( ) d i2×

---------------------------=



9.8

tion head (NPSH) to prevent cavitation and subsequent damage to the pump. TheNPSH required is a function of the pump design and the flow rate. NPSH curvesare included on the Centrifugal Pump Performance figures to find the minimumNPSH needed. The amount of NPSH available must then be determined.

As a shortcut, the minimum submergence for 6 in. and 8 in. suction lines as afunction of flow rate is provided in Figure 9.3. These curves may be used for mostapplications where the suction line is short and straight.

If the intersection of your submergence depth and flow rate fall near the line, adetailed determination of suction head should be made using the following equa-tion:

where:

Patm = uncorrected barometric pressure, psi (Figure 9.4)dsubmergence = height from pump suction to fluid level, ft

Pvapor = vapor pressure of liquid, psi (Figure 9.5)

Table 9.3 Recommended Flow Rates for Pipe

Nominal Pipe Diameter

Schedule 40

Recommended Flow Rates, gpm

Minimum@ 4 ft/s

Maximum@ 10 ft/s

3/4 7 16

1 12 26

1-1/4 20 47

1-1/2 26 63

2 45 105

2-1/2 60 150

3 95 230

3-1/2 130 310

4 160 400

5 260 625

6 360 900

8 650 1550

10 1000 2550

12 1400 3500

NSPH ft( )Patm

0.052 ρm×---------------------------= dsubmergence

Pvapor0.052 ρm×---------------------------–

Vs2

2g------– Hfs–+



9.9

pm = mud density, lb/galvs = velocity of suction line fluid, ft/s

g = gravitational constant = 32 ft/s2

Hfs = friction head losses in the suction line, ft

NPSH Example

From the previous example, the required NPSH from the Pump PerformanceCurves for our flowrate and impeller size is approximately 4.5 ft. Head loss in thesuction line were calculated in the worksheet example to be 0.26 ft.

If the rig elevation is 1000 ft and the mud circulating temperature is 100oF., theavailable NPSH is determined as follows:

1. Patm = 14.2 psia (from Figure 9.4)

2. dsubmergence = 6 ft

3. Pvapor = 0.95 psia (from Figure 9.5)

Figure 9.3 Minimum Suction Line Submergence. Points below or right of the lines should be avoided.



9.10

4.

5. The available NPSH is:

Since only 4.5 ft is required, there is sufficient NPSH available.

Suction Line Entrance

A properly-designed entrance will minimize friction loss, reduce air entrainmentand will reduce the amount of dead volume before suction is lost. Various designsare compared in Figure 9.6.

Installation and Operating Guidelines

1. Eliminate manifolding wherever possible.

2. Keep air out of the mud by degassing, having adequate suction line submer-gence and installing baffles to break vortices.

3. Do not restrict flow on the suction side of centrifugal pumps.

4. Install a pressure or head gauge between the pump and the first valve.

5. Do not completely close off discharge for more than 3 minutes.

6. Suction and discharge lines should be as short and straight as practical.

7. Size lines to achieve velocities of 5 - 10 feet per second.

8. Install pumps to run with flooded suctions. Check NPSH.

9. Check direction of rotation.

10. To reduce start up load on the electric motor, start the pump with the dis-charge valve partially open, then open fully once the pump is up to speed.This will also reduce shock loading on the downstream equipment.

v Q

2.48( ) d i2×

--------------------------- 400

2.48 6.0562×

-------------------------------- 4.38 ft/s= = =

NPSH ft( ) 14.20.052 10×-------------------------= 6

0.950.05 10×----------------------–

4.38( )2

2 32.4×-------------------– 0.64–+ 30.54 ft=



9.11

Figure 9.4 Elevation vs. Barometric Pressure.

Figure 9.5 Vapor Pressure as a Function of Fluid Temperature.

Fluid Temperature, °F



9.12

Figure 9.6 Pump Suction Pipe Entrances. The recommended designs reduce friction loss and air entrainment.



9.13

Summary

• A centrifugal pump provides constant head, which is ideal for the low pres-sure, high flow rate requirements of hydrocyclones and mixing systems. Cen-trifugal pumps are constructed of a cast-steel housing with cast-iron internalparts. Hardfacing on the high-wear areas and tungsten carbide seals are rec-ommended.

• Centrifugal pumps must be sized to provide the required head. Charts of headversus flow rate for the most common centrifugal pumps supplied inAppendix D, Pump Performance Curves. A procedure to correctly size centrif-ugal pumps is outlined in this section.

• Suction and discharge piping should be short as possible to reduce frictionlosses. The piping should be sized to flow at velocities in the range of 5 to10 ft/s to prevent solids settling or erosion problems. Tables and charts aresupplied to estimate the friction losses in pipe and fittings.

• The suction line of the pump must be submerged to prevent vortexes in thesuction and subsequent air locking of the pump. Guidelines are presented fordetermination of minimum submergence depth. Designs for suction lineentrances are also illustrated.



9.14

“Proprietary: - for the exclusive use of Amoco Production and other wholly owned subsidiaries of Amoco Corporation.”

Ref.1

References

1. Young, G. A. 1983. “Handbook for Successful Solids Control,” Amoco Produc-tion Company, 1st Edition.

2. Stone, V. D. “Low-Silt Mud Increases Gulf’s Drilling Efficiency, Cuts Costs,” Oiland Gas Journal, V. 62, No. 41, October 12, 1964.

3. Lal, M. “Economic and Performance Analysis Models for Solids Control,” SPEPaper 18037 presented at the Annual Technical Conference in Houston, TX,October 2-5, 1988.

4. Lal, M. and Hoberock, L. L. “Solids Conveyance Dynamics and Shaker Per-formance,” SPE Paper 14389 (1985).

5. Cagle, W. S. and Wilder, L. B. 1978. “Layered Shale Shaker Screens ImproveMud Solids Control,” World Oil, April 1978.

6. Hoberock, L. L. 1990. “Fluid Conductance and Separation Characteristics ofOilfield Screen Cloths,” Paper presented at the American Filtration SocietyNational Fall Meeting, Lafayette, 1990.

7. Cutt, A. R. 1992. “Shaker Screen Selection,” Amoco Production Company,Research Report F92-P-57 (92352ART0114).

8. Cutt, A. R. “Shaker Screen Characterization Through Image Analysis,” SPEPaper 22570 (1991).

9. API Recommended Practice 13E (RP13E) Third Edition, May 1, 1993. “Rec-ommended Practice for Shale Shaker Screen Cloth Designation.”

10. Hoberock, L. L. 1982. “Shale-Shaker Selection & Operation,” Reprint Seriesfrom Oil & Gas Journal, Pennwell Publishing Company.

11. Bray, R. P. 1984. “An Experimental Evaluation of Oilfield Degassers,” AmocoProduction Company, Research Report F84-P-12 (83269ART0053).

12. Young, G. A. 1987. “An Experimental Investigation of the Performance of aThree Inch Hydrocyclone,” SPE Paper 143899, presented at the IADC/SPEDrilling Conference, March 1987.



Ref.2

13. IADC Mud Equipment Manual, Handbook 6: Hydrocyclones, Handbook 4:Centrifugal Pumps and Piping, Gulf Publishing Company, 1982.

14. Thurber, N. E. 1988. “The Impact of Centrifuge Selection and Operation onDrilling Economics,” Amoco Production Company, Research Report F88-P-43(88126ART0171).

15. Young, G. A. 1984. “Economic Analysis of Dual Stage Centrifuging,” AmocoProduction Company, Internal Report, 84067ART0102.

16. MacDonald, J. G. 1982. “Mud Mixing Hopper Evaluation: GeosourceSidewinder 400 and Mission Venturi,” Amoco Production Company, ResearchReport F82-P-37 (82202ART0148).

17. Lal, M. and Thurber, N. E. “Drilling Waste Management and Closed Loop Sys-tems,” paper presented at the 1988 International Conference on DrillingWastes, April 5-8, 1988, Calgary, Canada.

18. Young, G. and Robinson, L. H. “How to Design a Mud System for OptimumSolids Removal,” World Oil, September-November 1982.

19. Young, G. A. 1982. “Mud Equipment Manual, Mud System Arrangement,”Amoco Production Company, Research Report F82-P-28 (82144ART0017).

20. Love, W. W. “Engineered Sizing of Mud Agitators Works Well,” Oil and GasJournal, November 28, 1977.

21. API Bulletin 13C (RP13C) “Bulletin on Drilling Fluids Processing Equipment.”

22. EPA, 1983. Hazardous Waste Land Treatment. EPA/530-SW-874, 671 p.

23. Malachosky, E. et al. “Offshore Disposal of Oil-Base Drilling Fluid Waste: AnEnvironmentally Acceptable Solution,” SPE Paper 23373 (1991).

24. Moschovidis, Z. A. et al. “Disposal of Oily Cuttings by Downhole FractureInjection - Part 1: Field Testing and Data Interpretation,” APR Greenback.

25. Williams, M. P. “Solids Control for the Man on the Rig,” Petroleum EngineerInternational, October-December 1982.

26. Svarovsky, L. 1981. Solid-Liquid Separation, (Chemical Engineering Series),Butterworth & Co. (Publishers) Ltd., London.

27. Advanced Drilling Fluids Training Manual, Volume II, Amoco Production Com-pany, 1988.

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