DWM Solids Control Handbook

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Sections 1 — 13

Appendices A — F

January 1998

Dowell ITM-1158

Schlumberger Dowell

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MASTER TABLE OF CONTENTS

SECTION 100 INTRODUCTION SECTION 200 ECONOMICS 1 Introduction ...1 2 Economic Justification ...2 2.1 Penetration Rate ...2 2.2 Dilution Rate ...3

2.2.1 Economic Analysis Calculations ...4

3 Solids Control Economics and Performance Program (SECOP) ...8

4 Monitoring System Performance ...9

4.1 API Procedure for Evaluating Total Efficiency of Solids Control Systems (Water-Based Muds) ...10

5 Summary ...12

Figures Fig. 1. Effects of solids content on drilling performance. ...3

Tables Table 1 Solids Control Economic Analysis Parameters...4

SECTION 300 SHALE SHAKERS 1 Introduction ...3

2 Principle of Operation...4

2.1 Vibration Patterns...4

2.1.1 Circular Motion...5

2.1.1.1 Solids Conveyance and Fluid Throughput ...5

2.1.1.2 Recommended Applications...5

2.1.2 Unbalanced Elliptical Motion ...5

2.1.2.1 Solids Conveyance and Fluid Throughput ...6

2.1.3 Linear Motion ...6

2.1.3.1 Solids Conveyance and Liquid Throughput ...7

2.1.4 Balanced Elliptical Motion ...8

2.1.5 Vibration Dynamics ...9

2.1.5.1 Acceleration ...9

2.1.5.2 Frequency (RPM), Stroke Length ...11

2.1.6 Deck Angle ...12

3 Screen Fastening and Support...12

3.1 Hookstrip Screen Panels...13

3.2 Rigid Frame (Pretensioned) Screen Panels ...15

4 Single Deck Shakers...17

5 Cascading Shaker Systems ...21

5.1 Unitized Cascading Systems...22

6 Integral Tandem Deck Shakers ...23

7 Shaker Manifolds ...27

8 Operating Guidelines...30

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8.3 Cuttings Dryness...30

8.4 Sticky Solids (Gumbo)...32

8.5 Polymer Muds ...33

8.6 Blinding, Plugging ...33

8.7 Lost Circulation Material ...33

9 Estimating Number of Shakers Required ...34

10 Summary...35

Figures Fig. 1. Shale shaker components...4

Fig. 2. Circular motion. ...5

Fig. 3. Unbalanced elliptical motion...6

Fig. 4. Linear motion. ...7

Fig. 5. Balanced elliptical motion...8

Fig. 6. Conveyance velocity. ...9

Fig. 7. Adjustable vibrator counterweights...10

Fig. 8. Shaker throughput versus vibrator frequency. ...11

Fig. 9. Solids bed buildup...12

Fig. 10. Typical hookstrip screen...13

Fig. 11. Hookstrip screen tensioners. ...14

Fig. 12. Shaker fluid endpoints...15

Fig. 13. Rigid screen panel with perforated plate...16

Fig. 14. Rigid screen panel...17

Fig. 15. Derrick flo-line cleaner plus. ...18

Fig. 16. Fluid systems model 500...18

Fig. 17. Swaco ALS. ...19

Fig. 18. Sweco LF-3 oil-mizer...19

Fig. 19. Sweco LM-3. ...20

Fig. 20. Triton NNF. ...20

Fig. 21. Cascading shaker system. ...21

Fig. 22. Brandt ATL-CS...23

Fig. 23. Brandt ATL 1000 ...24

Fig. 24. Derrick cascade system. ...25

Fig. 25. Thule VSM 100 ...26

Fig. 26. Poor manifold design...27

Fig. 27. Better manifold design...28

Fig. 28. Best conventional manifold design. ...28

Fig. 29. Circular manifold design...29

Fig. 30. Overhead manifold design...29

Tables Table 1 Shakers Required...34

SECTION 400 SHAKER SCREENS 1 Introduction ...2

2 Separation Performance ...2

2.1 Grade Efficiency...2

2.2 Separation Potential ...3

3 Liquid Throughput Performance ...4

4 Screen Life...4

4.1 Effect of Screen Composition...4

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4.2.1 Linear Motion ...5

4.2.2 Circular, Elliptical Motion...5

5 Shaker Screen Designations ...5

5.1 Mesh Count...5

5.2 API RP13E Screen Designation ...6

5.2.1 Screen Name...6

5.2.2 Equivalent U.S. Sieve Number...7

5.2.3 Separation Potential (d50, d16, d84) ...7

5.2.4 Flow Capacity (Conductance, Non-blanked Area) ...8

5.2.5 Transmittance ...8

5.2.6 Aspect Ratio ...9

5.3 Field Procedure to Estimate Cut Point (D50) ...10

5.3.1 Equipment ...10

5.3.2 Procedure ...10

6 Summary ...11

Figures Fig. 1. Percent separated curve. ...3

Fig. 2. Effect of plate opening size on screen blinding...9

Tables Table 1 U.S. Sieve Series ...7

Table 2 Blinding Resistance of Common Screens ...10

SECTION 500 DEGASSERS 1 Introduction ...1

2 Placement and Operation...2

3 Summary ...3

Figures Fig. 1. Correct degasser operation. ...3

Tables Table 1 Ranking of Degasser Models ...2

SECTION 600 HYDROCYCLONES 1 Introduction ...2 2 Principle of Operation...2 3 Performance Parameters ...4 3.1 Cone Diameter ...5 3.2 Plastic Viscosity ...6 3.3 Feed Head ...6 3.4 Underflow Diameter...8 3.4.1 Spray Discharge ...8 3.4.2 Rope Discharge ...8 4 Desanders...10 4.1 Recommended Desanders...10 5 Desilters...10 5.1.1 Recommended Desilters...12

6 Sizing Hydrocyclone Manifolds...12

7 Operating Guidelines...13

8 Troubleshooting ...15

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Figures

Fig. 1. Hydrocyclone operating principles...3

Fig. 2. Cone efficiency...4

Fig. 3. Sensitivity to plastic viscosity. ...6

Fig. 4. Sensitivity to feed head. ...7

Fig. 5. Rope flow operation characteristics...9

Fig. 6. “Amoco” near optimum core efficiency. ...11

Fig. 7. Estimated discard rates...11

Fig. 8. Typical hydrocyclone manifold. ...13

Tables Table 1 Effect of Variables on Hydrocyclone Performance...5

Table 2 Cone Capacity...5

SECTION 700 MUD CLEANERS 1 Introduction ...1 2 Operating Guidelines...4 2.1 Unweighted Muds...4 2.2 Weighted Muds ...4 3 Summary ...5 Figures Fig. 1. Mudcleaner combines hydrocyclone and shale shaker...2

Fig. 2. Brandt ATL 2800 mud cleaner...3

SECTION 800 DECANTING CENTRIFUGES 1 Introduction ...2 2 Principle of Operation...3 3 Performance Parameters ...4 3.1 G-Force...4 3.2 Viscosity...6 3.3 Cake Dryness...6

3.4 Pond Depth and Processing Capacity ...7

3.5 Bowl - Conveyor Differential RPM And Torque ...9

4 Centrifuging Unweighted Mud ...10

4.1 Centrifuging Hydrocyclone Underflow...10

4.2 Operating Guidelines, Centrifuging Unweighted Mud ...13

5 Centrifuging Weighted Muds ...13

5.1 Operating Guidelines, Barite Recovery Mode ...15

6 Two-Stage Centrifuging...16

6.1 Field Evaluation of Two-Stage Centrifuging Economics ...18

6.1.1 Calculations ...18

7 Centrifuge Selection ...19

7.1 Equipment Descriptions ...23

7.1.1 Hutcheson-Hayes HH5500 (16 X 55) ...23

7.1.2 Alpha-Laval 418/Swaco HS 518 (14 X 56) ...23

7.1.3 Derrick DE1000/Sharples P3400/Brandt HS3400 (14 X 50) ...23

7.1.4 Oiltools S3.0 (21 X 62), S2.1 (18 X 56) ...23

7.1.5 Bird Design Centrifuges - Sweco SC-4, Broadbent, Brandt CF-2, Derrick DB1...24

7.1.6 Alpha-Laval 414, Swaco 414 (14 X 38), Sharples P3000, Hutcheson Hayes HH1430 (14 X 30)...24

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8 Summary ...25

Figures Fig. 1. Centrifuge components. ...3

Fig. 2. Centrifuge operation...4

Fig. 3. Effect of G-force on separation. ...5

Fig. 4. Effect of viscosity on separation performance. ...6

Fig. 5. Effect of G-force on cuttings dryness. ...7

Fig. 6. Effect of pond depth on fine solids removal...8

Fig. 7. Effect of pond depth on coarse solids removal. ...9

Fig. 8. Economics of centrifuging hydrocyclone underflow. ...11

Fig. 9. Fluid routing to centrifuge hydrocyclone underflows. ...12

Fig. 10. Internal centrifuge feed compartment design...12

Fig. 11. Choice of drilled solids removal from weighted mud...14

Fig. 12. Benefits of increased G-force on barite recovery...15

Fig. 13. Two stage centrifuging. ...17

Fig. 14. Centrifuge performance comparison on fine solids distribution...20

Fig. 15. Centrifuge performance comparison on coarse solids distribution...21

Tables Table 1 Recommended Centrifuges for Unweighted Mud ...22

Table 2 Recommended Centrifuges for Weighted Mud...22

SECTION 900 CENTRIFUGAL PUMPS AND PIPING 1 Introduction ...2

2 Principle of Operation...2

3 Sizing Centrifugal Pumps ...3

3.1 Centrifugal Pump Sizing Example ...4

3.2 Estimating Impeller Size...8

4 Pipe Sizing ...8

4.1 Suction Head Requirements (NPSH) ...9

4.1.1 NPSH Example ...12

4.1.2 Suction Line Entrance...13

5 Installation and Operating Guidelines...13

6 Summary ...14

Figures Fig. 1. Typical centrifugal pump. ...3

Fig. 2. Centrifugal pump sizing example. ...4

Fig. 3. Minimum suction line submergence. ...10

Fig. 4. Elevation vs. barometric pressure. ...11

Fig. 5. Vapor pressure as a function of fluid temperature. ...12

Fig. 6. Pump suction pipe entrances. ...13

Tables Table 1 Detailed Worksheet for Pump Sizing...6

Table 2 Friction Loss Coefficients for Pipe Fittings...7

Table 3 Recommended Flow Rates for Pipe ...9

SECTION 1000 ADDITION/MIXING SYSTEMS 1 Introduction ...2

2 Mixing Hoppers ...2

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4 Polymer Mixing...5

5 Active System Addition ...7

6 Premix System...8

7 Water Addition ...9

7.1 Waste Pit Water ...9

8 Agitation ...10

8.1 Agitator Design...11

8.2 Agitator Sizing Example ...13

9 Summary ...15

Figures Fig. 1. Jet/Venturi mixer. ...3

Fig. 2. Sidewinder mixer...4

Fig. 3. Jet shear mixer...6

Fig. 4. SECO (Echols) homogenizer ring...7

Fig. 5. Horsepower requirements for canted-blade impellers...12

Fig. 6. Horsepower requirements for flat-blade impellers. ...12

Fig. 7. Floor baffles. ...13

Tables Table 1 Recommended Turnover Rates...11

Table 2 Impeller Displacement Rates...14

Table 3 Physical Specifications for Mechanical Mixers...14

SECTION 1100 TANK DESIGN AND EQUIPMENT ARRANGEMENT 1 Tank Design...1

1.1 Compartment Equalization ...2

1.2 Sand Trap ...3

1.3 Slug Tank...3

1.4 Equipment Arrangement ...4

1.5 General Guidelines for Surface System Arrangements ...5

2 Equipment Arrangements...6

2.1 Unweighted Mud - Centrifuge Processing Active System ...6

2.2 Unweighted Mud - Centrifuge Processing Hydrocyclone Underflow...8

2.3 Unweighted Mud - Centrifuge Processing Mud Cleaner Underflow...10

2.4 Weighted Water-Based Mud - Single-Stage Centrifuging (Barite Recovery)...12

2.5 Weighted Mud - Two-Stage Centrifuging...14

2.6 Complete System Layout For Both Weighted and Unweighted Mud...16

3 Summary ...18

Figures Fig. 1. Unweighted mud - centrifuge processing active system. ...7

Fig. 2. Unweighted mud - centrifuge processing hydrocyclone underflow...9

Fig. 3. Unweighted mud - centrifuge processing mud cleaner underflow. ...11

Fig. 4. Weighted water-based mud - single-stage centrifuging (Barite recovery) ...13

Fig. 5. Weighted mud - two stage centrifuging. ...15

Fig. 6. Generic - complete system...17

SECTION 1200 DEWATERING SYSTEMS 1 Introduction ...1

2 Economic Overview...2

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4 Equipment Selection ...10

4.1 Dewatering Devices ...10

5 Waste Management ...11

6 Summary ...13

Figures Fig. 1. Effect of solids on flocculent concentration. ...5

Fig. 2. Evaluation of dewatering centrate. ...6

Fig. 3. Material returned in centrate...7

Fig. 4. Form for calculating dewatering efficiency...8

Fig. 5. Dewatering costs, by interval...9

Fig. 6. Dewatering system equipment. ...10

SECTION 1300 REFERENCES APPENDIX A SOLIDS CONTROL PROGRAMS 1 “SHAKCAP” Spreadsheet Program ...1

1.1 Input...2 1.1.1 Screen Data...2 1.1.2 Mud Data ...3 1.1.3 Drilling Data ...3 1.2 Output ...3 1.3 Using Shakcap ...4

2 “DEWATER” Spreadsheet Program ...5

2.1 Dewatering and Disposal Cost Section...5

2.1.1 Dewatering Equipment Used...6

2.1.2 Manpower Costs ...6

2.1.3 Per Barrel Costs ...6

2.2 Interval Data and Analysis Section ...7

2.2.1 Input Data ...7

2.2.2 Output Data ...8

3 Summary Section...10

Figures Fig. 1. SHAKCAP spreadsheet. ...2

Fig. 2. Input section of the DEWATER spreadsheet...5

Fig. 3. Interval data and analysis section of the DEWATER spreadsheet. ...7

Fig. 4. Summary section of the DEWATER spreadsheet. ...10

APPENDIX B CONDUCTANCE CALCULATION 1 Introduction ...1

2 Nomenclature...2

APPENDIX C SOLIDS CONTROL EQUIPMENT DISCHARGE ANALYSIS 1 Introduction ...1

2 Sample Collection ...1

3 Retort Procedure...2

4 Alternate Retort Procedure for Air-Entrained Cuttings Samples ...2

5 Solids Analysis Calculations...3

6 Example Calculations...5

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APPENDIX D SCREEN DESIGNATIONS

1 Brandt - ATL-1000, ATL CS (Main Deck) ...2

2 Brandt - Retrofit Tandem, ATL-CS (Scalping Deck) ...4

3 Broadbent - Tandem Master (Lower Deck)...8

4 Derrick - Flo-Line Cleaner, Cascade System, High G Dryer ...9

5 Fluid Systems - Model 500, Model 50 ...24

6 Harrisburg - Linear Tandem ...30

7 Swaco - ALS ...31

8 Sweco - LM-3 ...35

9 Sweco - LF-3...41

10 Thule Rigtech - VSM 100 ...43

11 Tri-Flo - Model 148 ...44

12 Triton NNF Screening Machine ...45

APPENDIX E PUMP PERFORMANCE CURVES Figures Fig. 1. 4M-21, BJ 5” at 1750 rpm...1

Fig. 2. 4M-18, BJ 6” at 1150 rpm...2

Fig. 3. 4M-19, BJ 6” at 1750 rpm...2

Fig. 4. Mission Magnum 1, 6 x 5 x 11 at 1150 rpm. ...3

Fig. 10. Mission Magnum, 8 x 6 x 14 at 1150 rpm. ...6

Fig. 11. Mission Magnum, 8 x 6 x 14 at 1750 rpm. ...6

Fig. 12. Harrisburg curve no. 2013, 5 x 4 x 14 at 1150 rpm. ...7

APPENDIX F EQUIPMENT SPECIFICATIONS Tables Table 1 Oilfield Shale Shakers ...2

Table 2 Oilfield Shale Shaker Classification ...18

Table 3 Oilfield Centrifugal Pumps ...19

Table 4 Oilfield Degassers ...26

Table 5 Oilfield Hydrocyclones ...33

Table 6 Oilfield Mud Cleaners ...44

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INTRODUCTION

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

1. Do nothing and let the solids build up. When the mud no longer meets

specifications, throw it away and start with fresh mud.

2. Dilute the mud and rebuild the system to keep the properties within

acceptable ranges, while dumping excess mud to the reserve pit.

3. Lower the solids content of the mud through solids removal to

minimize the addition/dilution necessary to maintain acceptable properties.

In recent years, increased public awareness of environmental issues has provided both regulatory and economic incentives to minimize drilling waste. In many instances, the first two choices have become very expensive and unacceptable. This has served to stress the importance of the third option, efficient solids control. Using solids removal to minimize addition/dilution volumes is normally most effective 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 maintenance of a good drilling fluid. Solids control equipment has been standard hardware on most rotary drilling rigs since the early 1960s. In the early years, many of the solid/liquid separation devices were borrowed from

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other industries and applied directly to oilfield rotary drilling. Although the basic operating principles and technology associated with mechanical solids removal have not changed significantly over the years, refinements in design specifically for drilling applications have yielded considerable improvements in performance and reliability.

· This manual provides drilling personnel with the information to help

optimize the selection and operation of solids control equipment. Emphasis is placed on mechanical solids removal equipment and the factors that impact its performance. Practical operating guidelines are provided to help achieve maximum performance in the field.

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Economics

1 Introduction ... 1

2 Economic Justification...2

2.1 Penetration Rate... 2

2.2 Dilution Rate ... 3

2.2.1 Economic Analysis Calculations... 4

3 Solids Control Economics and Performance Program (SECOP) ... 8

4 Monitoring System Performance ... 9

4.1 API Procedure for Evaluating Total Efficiency of Solids Control Systems (Water-Based Muds) ... 10

5 Summary... 12

FIGURES Fig. 1. Effects of solids content on drilling performance. ... 3

TABLES Table 1 Solids Control Economic Analysis Parameters... 4

1 Introduction

The impact of good solids control can be very significant and can lead to substantial cost savings, but often there is reluctance to invest in solids control for the following 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.

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Although the benefits from good solids control are numerous, the cost savings are not apparent in normal drilling cost accounting. For example, the savings due to reduced trouble costs and improved penetration rate, although substantial benefits, cannot be accurately calculated. Usually the drilling fluid gets most of the credit (or blame) since mud material consumption is easily tracked and the mud properties are the only direct indication of solids control system performance. In a realistic sense, the mud and the solids control equipment are integral parts of one system. One cannot plan the mud without considering the solids control system and vice versa. This does not mean that the benefits of good solids control practices cannot be measured.

2 Economic Justification

2.1 Penetration Rate

The impact of solids control on penetration rate is best depicted by Fig. 1. This has become somewhat of a classic illustration of the benefits of a low solids content 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 a 10,000 ft well costing $700,000 excluding mud cost, the estimated savings could reach $100,000. If even half of these savings were realized, it would more than pay for the best solids removal system available.

In soft rock country such as the Gulf Coast, efficient solids removal can reduce the need to control-drill by limiting required dilution rates to manageable levels and reducing operational problems due to overloaded solids removal equipment. The benefits from efficient solids removal, e.g., “low-silt” muds, have been documented for Gulf Coast drilling since the mid-60s when hydrocyclone use was first advocated.

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Fig. 1. Effects of solids content on drilling performance.

Note: The benefits of low solids contents are most apparent at less than 5% solids.

2.2 Dilution Rate

Solids removal efficiency directly impacts dilution costs. When dilution water is added 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, while real, cannot be reliably predicted as justification for improved solids control equipment. In many cases however, the economic advantages due to reduced dilution and disposal costs are more than enough to justify expenditures for additional equipment. The economic benefits in terms of mud consumption and disposal can be determined through a simple mass balance analysis: Removing a given percentage of drilled solids will result in a certain dilution volume to maintain the desired maximum concentration of drilled solids in the mud. The relevant parameters and their symbols used in the calculations are listed below.

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Table 1 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

rd ₌ _{Density of dilution fluid, ppg}

rc ₌ _{Density of drilled cuttings, ppg}

ri ₌ _{Mud weight at the start of the section, ppg}

re ₌ _{Desired mud weight, end of section, ppg}

2.2.1 Economic Analysis Calculations

First, the volume of cuttings generated in a given interval must be calculated:

V

_c

= 0.000971 x D x L x W

2

For a given percent of drilled solids removed, X, the required dilution volume is computed by:

(

)

(

)

V

k

V

d c i i s i

=

1- k

k

1- X

s s

-

+

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The following equations may be used to calculate the solids removal efficiency, Xc, and the associated dilution volume required to discharge only wet solids:

(

)

(

)

X

k V

V

k V

V

k Y

c s f c i i c s

=

V

c

-

+

1 (

)

(

)

V

_d

= V

_f

−

V

_i

+

X V

_c _c

1 +

Y

The required mud weight (density) of the dilution volume, Vd, is based on the specified starting and ending densities and is calculated by:

(

)

ρ

d

ρ

e

ρ

e

ρ

i c

ρ

d c e

V

X

=

V

i d

+

−

(

1 −

)(

−

)

The total volume of solids and liquid generated in an interval is given by:

V

t

= V

i

+

V

c

+

V

d

The wet solids volume, Vsw, and liquid volume, Vlw, discharged while drilling the interval is computed by:

(

)

V

_sw

= XV

_c

1 +

Y

(

)

V

_lw

= V

_t

−

V

_f

+

V

_c

+

V

_sw

The remaining circulating volume includes the volume of solids not removed by the solids removal equipment. Since the solids are assumed to be too fine to be removed by the solids control equipment, their volume is counted as liquid volume for 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:

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Once the waste volumes are calculated, the total dilution and disposal cost for the interval may be determined by estimating the equipment rental cost and the cost/bbl for addition/dilution and liquid/solids disposal:

1. Solids Control Equipment Cost

- Estimate rental, transport, service, and maintenance (e.g., screens) cost for the interval.

2. Addition/Dilution Cost

- Estimate the cost/bbl by including purchase cost for dilution liquid, trucking, and additive cost.

3. Liquid/Solids Disposal Cost

- Estimate the cost/bbl by including hauling, disposal, treatment, reserve pit construction 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)

rd = Density of dilution/addition fluid, ppg

rc = 2.6 x 8.34 = 21.68 ppg

ri = 8.6 ppg initial mud weight

re = 9.4 ppg final mud weight

Dilution Cost: $5.00/bbl

Liquid Waste Cost: $3.00/bbl

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Calculations: 1. Cuttings volume:

V

_c

= 0.000971 x D x L x W

2

(

) (

) ( )

V

_c

= 0.000971 x 12.25 x 1600 x 1.1 = 256 bbls

2 2. Dilution volumes for each solids removal efficiency:

(

)

₍

₎

V

k

V

d c i i s i

=

1- k

k

1- X

s s

-

+

For X = 0.0

(

)

_{( )}

V

_d

=

1- 0.06

= 3650 bbls

0 06

1 0 256

360

0 0 06

360 .

(

−

)

−

+

.

For X = 0.1

(

)

_{( )}

V

_d

=

1- 0.06

= 3250 bbls

0 06

1 0 1 256

360

0 0 06

360 .

(

−

. )

−

+

.

For X = 0.5

(

)

_{( )}

V

_d

=

1- 0.06

= 1645 bbls

0 06

1 0 5 256

360

0 0 06

360 .

(

−

. )

−

+

.

3. Dilution density:

In this example, the required density will not change with each case. The parameters for X=1 are chosen for illustration purposes.

(

)

ρ

d

ρ

e

ρ

e

ρ

i c

ρ

d c e

V

X

=

V

i d

+

−

(

1 −

)(

−

)

(

)

ρ

d

= .4

360

360 = 8.6 ppg

9 9 4

8 6

256 3250

1 0 1 217

9 4

+

.

−

.

−

(

−

. )(

.

−

. )

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4. Solids removal efficiency and dilution volume to achieve zero whole-mud discharge while drilling:

(

)

(

)

X

k V

V

k V

V

k Y

c s f c i i c s

=

V

c

-

+

1 (

) ( )

(

)

X

_c

=

256 x 1.0

= 0.81

−

+

0 06 360

256 0 360

256 1 0 06

.

(

)

(

)

V

_d

= V

_f

−

V

_i

+

X V

_c _c

1 +

Y

(

)

( )( )

V

_d

= 360

−

360 +

0 81 256 1 1

.

+

= 415 bbls

5. Summary of waste disposal volumes:

Total Volume bbls

Wet Solids bbls

Liquid While Drilling bbls Total Liquid bbls 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

6. Cost estimate for each case, discarding total liquid volume (last column in Step 5): Drilled Solids Removed Equipment Costs Addition/Dilution Costs Disposal Costs Solids Liquids Total Costs 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

The example illustrates how an increase in equipment costs to improve solids removal efficiency is justified by the savings in addition/dilution and disposal costs, even without considering savings attributable to higher penetration rates or reduced trouble costs.

3 Solids Control Economics and Performance Program (SECOP)

A natural question arising from the economic analysis exercise is “What equipment will I need to achieve the optimum solids removal efficiency?” It is also apparent that the determination of an economically-optimum solids control system can be a time-consuming, iterative process. The equipment costs to achieve the minimum required dilution volume (commonly called a “closed-loop” mud system) may not be economic in all cases. It may not even be physically possible with available mechanical solids removal

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technology. The Solids Control Economic and Performance Analysis Program (SECOP) was developed at APR to assist drilling personnel in the optimum selection of solids control equipment. It is available as an Integrated Drilling Assistance Program for use on the PC.

1. The economics of solids control in terms of potential savings in mud

dilution and disposal costs versus the percent drill solids removed.

2. The performance of solids control equipment. It predicts the drill solids

removed by each piece of equipment selected.

3. The loss of weighting material and mud from each piece of equipment

for weighted muds and the predicted recovery from barite-recovery centrifuging.

4. The performance for different equipment options to determine the

most effective solids control system for drilling a well.

SECOP predicts only the savings in mud and disposal costs. As discussed previously, no model exists to predict additional savings from higher penetration rates and lower trouble costs that result from effective solids control. The program uses models developed as a result of extensive equipment testing at APR to predict individual equipment and total system performance. The overall economics calculations are based on the same equations described above. A complete description of the program is provided in the IDAP reference manual.

The recommended application of SECOP is to match the performance history of the solids control system for an offset well. This can be done by selecting the proper lithology and resulting particle size distribution which matches the mud volumes and costs for the offset well. Once a lithology match has been made, different equipment options may be tried to find the most economically-effective solids control equipment for the proposed well. A successful economic analysis for future wells will depend on determining a representative particle size distribution from the offset well which, in turn, is dependent upon having accurate records of dilution volumes and equipment operation. This emphasizes the importance of accurately metering water additions and equipment performance while drilling. SECOP may then be used to monitor equipment performance and establish representative particle size distributions for future economic analysis and equipment selection.

4 Monitoring System Performance

The API Recommended Practice 13C contains a field method for evaluating the total efficiency of the drilling fluid processing system in water-based fluids. As with any performance analysis, this procedure depends upon accurate dilution volume information. The API procedure uses the dilution volume over a given interval to compute a dilution factor, DF, which is the volume ratio of actual mud built to mud dilution required to maintain a desired solids concentration with no solids removal equipment. The dilution factor is used to determine the total solids removal efficiency of the system.

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This total efficiency can then be used in SECOP to establish a representative particle-size distribution for further analysis and equipment performance predictions.

4.1 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:

V

k

m w w =

4. Calculate the volume of drilled solids, Vc:

Vc =0.000971 x D

2

x L x W

5. Calculate the dilution volume required if no solids were removed, Vd:

V

k

d c s =

6. Calculate the dilution factor, DF:

DF

V

m d

=

7. Calculate the total solids removal performance, Et:

Et = (1 - DF) Multiply by 100 to calculate as a percentage. The accuracy of the API procedure depends on a relatively constant solids concentration in the mud, constant surface circulating volume, and consistent averaging techniques over the interval of interest. Regardless, the total solids removal performance should be reported at frequent intervals to facilitate solids control analysis and planning for future wells.

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Example Calculation

Interval Data:

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

Calculations:

1. Calculate the volume of mud built, Vm:

V

k

m w w =

=

1481

0.9 = 1645 bbls

2. Calculate the volume of drilled solids, Vc:

Vc = 0.000971 x D

2

x L x W

= 0.000971 (12.25)

2

(1600)(1.1)

= 256 bbls

3. Calculate the dilution volume required if no solids were removed, Vd:

V

_d

=

V

k

=

256

0.06 = 4267 bbls

c s

4. Calculate the dilution factor, DF:

DF

V

m d

=

1645

4267

= 0.386

5. Calculate the total solids removal performance, Et:

(

)

E

_t

= 1- DF = 1- 0.386 = 0.614

Expressed as a percentage:

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5 Summary

· The economic advantages of good solids control practices, while real,

are usually difficult to predict in terms of improved penetration rates and reduced trouble time. However, savings in dilution and disposal costs can be predicted and are often ample justification to invest in improved solids control equipment.

· Solids removal efficiency directly impacts the cost of dilution, material

consumption and waste disposal. A simple mass balance approach may be used to predict total dilution and waste volumes as a function of solids removal efficiency. Example calculations show how an investment in solids control equipment may be easily justified by the savings realized from reduced addition/dilution and disposal costs.

· The solids control economics and performance program “SECOP” may

be used to select the most effective solids control system. This program predicts:

- The savings in mud dilution and disposal costs vs. the percent solids removed.

- The drilled solids removed by each piece of equipment.

- Loss of weighting material and mud from each piece of equipment. - Recovery from barite-recovery centrifuging.

· The program is available as an Integrated Drilling Assistance Program.

· The API Recommended Practice 13C contains a field method for

monitoring system performance in the field. This method depends upon accurate dilution volume monitoring to determine total solids removal efficiency. The API procedure and example calculations are presented in this section.

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Shale Shakers

1 Introduction ... 3

2 Principle of Operation... 4

2.1 Vibration Patterns ... 4 2.1.1 Circular Motion ... 5 2.1.1.1 Solids Conveyance and Fluid Throughput... 5 2.1.1.2 Recommended Applications ... 5 2.1.2 Unbalanced Elliptical Motion ... 5 2.1.2.1 Solids Conveyance and Fluid Throughput... 6 2.1.2.2 Recommended Applications ... 6 2.1.3 Linear Motion ... 6 2.1.3.1 Solids Conveyance and Liquid Throughput... 7 2.1.3.2 Recommended Applications ... 7 2.1.4 Balanced Elliptical Motion ... 8 2.1.5 Vibration Dynamics ... 9 2.1.5.1 Acceleration... 9 2.1.5.2 Frequency (RPM), Stroke Length ... 11 2.1.6 Deck Angle ... 12

3 Screen Fastening and Support ... 12

3.1 Hookstrip Screen Panels ... 13 3.2 Rigid Frame (Pretensioned) Screen Panels ... 15

4 Single Deck Shakers... 17

5 Cascading Shaker Systems... 21

5.1 Unitized Cascading Systems ... 22

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7 Shaker Manifolds ... 27

8 Operating Guidelines... 30

8.1 Optimizing Screen Life... 30 8.2 Screen Selection ... 30 8.3 Cuttings Dryness ... 30 8.4 Sticky Solids (Gumbo) ... 32 8.5 Polymer Muds... 33 8.6 Blinding, Plugging ... 33 8.7 Lost Circulation Material ... 33

9 Estimating Number of Shakers Required ... 34

10 Summary... 35 FIGURES

Fig. 1. Shale shaker components...4 Fig. 2. Circular motion. ...5 Fig. 3. Unbalanced elliptical motion...6 Fig. 4. Linear motion. ...7 Fig. 5. Balanced elliptical motion...8 Fig. 6. Conveyance velocity. ...9 Fig. 7. Adjustable vibrator counterweights... 10 Fig. 8. Shaker throughput versus vibrator frequency. ... 11 Fig. 9. Solids bed buildup... 12 Fig. 10. Typical hookstrip screen... 13 Fig. 11. Hookstrip screen tensioners. ... 14 Fig. 12. Shaker fluid endpoints... 15 Fig. 13. Rigid screen panel with perforated plate... 16 Fig. 14. Rigid screen panel... 17 Fig. 15. Derrick flo-line cleaner plus. ... 18 Fig. 16. Fluid systems model 500... 18 Fig. 17. Swaco ALS. ... 19 Fig. 18. Sweco LF-3 oil-mizer... 19 Fig. 19. Sweco LM-3. ... 20 Fig. 20. Triton NNF. ... 20 Fig. 21. Cascading shaker system. ... 21 Fig. 22. Brandt ATL-CS... 23 Fig. 23. Brandt ATL 1000 ...24 Fig. 24. Derrick cascade system. ... 25 Fig. 25. Thule VSM 100 ...26 Fig. 26. Poor manifold design... 27 Fig. 27. Better manifold design... 28

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Fig. 28. Best conventional manifold design. ... 28 Fig. 29. Circular manifold design... 29 Fig. 30. Overhead manifold design... 29

TABLES

Table 1 Shakers Required... 34

1 Introduction

The shale shaker can be regarded as the “first line of defense” in the solids removal system. It has proven to be a simple and reliable method of removing large amounts of coarse, drilled cuttings from the circulating system. The shale shaker’s performance can be easily observed; all aspects of its operation are visible. Shale shakers provide the advantage of not degrading soft or friable cuttings. When well-operated and maintained, shale shakers can produce a relatively dry cuttings discharge.

In unweighted muds, the shale shaker’s main role is to reduce the solids loading to the downstream hydrocyclones and centrifuges to improve their efficiency. In muds containing solid weighting agents such as barite, the shale shaker is the primary solids removal device. It is usually relied upon to remove all drilled cuttings coarser than the weighting material. Downstream equipment will often remove too much valuable weighting material.

Enough shakers should be installed to process the entire circulating rate with the goal of removing as many drilled cuttings as economically feasible. Given the importance of the shale shaker, the most efficient shakers and screens should be selected 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 and screen selection are also provided.

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2 Principle of Operation

Simply stated, a shale shaker works by channeling mud and solids onto vibrating screens. The mud and fine solids pass through the screens and return to the active system. Solids coarser than the screen openings are conveyed off the screen by the vibratory motion of the shaker. The shaker is

the only solids removal device that makes a separation based on physical particle size. Hydrocyclones and centrifuges separate solids

based on differences in their relative mass.

The screens are vibrated by rotating eccentrically-weighted shafts attached to the basket. The major components of a typical shale shaker are illustrated in Fig. 1.

Fig. 1. Shale shaker components.

Note: These components are common to most shale shakers.

2.1 Vibration Patterns

Shale shakers are classified in part by the vibration pattern made by the shaker basket location over a vibration cycle (e.g., “linear motion” shakers). The pattern will depend on the placement and orientation of the vibrators. Four basic vibration patterns are possible: circular, unbalanced elliptical, linear, and balanced elliptical motion.

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2.1.1 Circular Motion

As the name implies, the shaker basket moves in a uniform circular motion when viewed from the side (Fig. 2.). This is a “balanced” vibration pattern because all regions of the shaker basket move in phase with the identical pattern. In order to achieve “balanced” circular motion, a vibrator must be located on each side of the shaker basket at its center of gravity (CG) with the axis of rotation perpendicular to the side of the basket. The Brandt Tandem is a common example of a circular motion shale shaker.

Fig. 2. Circular motion.

Note: All areas of the basket rotate in a circular motion.

2.1.1.1 Solids Conveyance and Fluid Throughput

Circular motion shakers will not efficiently convey solids uphill. Therefore, most shakers of this type are designed with horizontal configurations. Fluid throughput is limited by the deck angle, but augmented slightly by the higher G’s normally used (see Vibration Dynamics section). The “soft” acceleration pattern does not tend to drive soft, sticky solids, such as gumbo, into the screens.

2.1.1.2 Recommended Applications

· gumbo, or soft, sticky solids conditions

· scalping shakers for coarse solids removal

2.1.2 Unbalanced Elliptical Motion

The difference between circular motion and unbalanced elliptical motion is a matter of vibrator placement. To achieve unbalanced elliptical motion, the vibrators are typically located above the shaker basket. Because the vibrator counterweights no longer rotate about the shaker’s center of gravity, torque is applied on the shaker basket. This causes a rocking motion which generates different vibration patterns to occur along the length of the basket,

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hence the term “unbalanced.” Refer to Appendix F, Equipment Specifications, for a list of shakers having unbalanced elliptical motion. Fig. 3. illustrates how the vibration pattern may change along the length of the basket. At the feed end of the shaker, an elliptical vibration pattern is created; the angle of vibration is pointed toward the discharge end. In this region, forward solids conveyance is good. However, at the discharge end of the shaker, angle of the elliptical pattern is pointed back towards the feed end. This will cause the solids to convey backwards unless the deck is pitched downhill at a sufficient angle to overcome the uphill acceleration imparted on the solids by the shaker motion.

Fig. 3. Unbalanced elliptical motion.

Note: The vibration pattern changes along the length of the basket.

2.1.2.1 Solids Conveyance and Fluid Throughput

The downhill deck orientation restricts the unbalanced elliptical motion shaker’s ability to process fluid; mud losses can be a concern. However, the deck orientation is beneficial for removing sticky solids such as gumbo.

· gumbo, or soft, sticky solids conditions

· scalping shakers for coarse solids removal

2.1.3 Linear Motion

Linear motion is achieved by using two counter-rotating vibrators which, because of their positioning and vibration dynamics, will naturally operate in phase. They are located so that a line drawn from the shaker’s center of

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Fig. 4. Linear motion.

Note: All areas move in a synchronous linear motion.

Because the counterweights rotate in opposite directions, the net force on the shaker basket is zero except along a line passing through the shaker’s center of gravity. The resultant shaker motion is therefore “linear.” The angle

of this line of motion is usually at 45-50° relative to the shaker deck to

achieve maximum solids conveyance. Because acceleration is applied through the shaker CG, the basket is dynamically balanced; the same pattern of motion will exist at all points along the shaker.

2.1.3.1 Solids Conveyance and Liquid Throughput

Linear motion shakers have become the shaker of choice for most applications because of their superior solids conveyance and fluid-handling capacity. Solids can be strongly conveyed uphill by linear motion. The uphill deck configuration allows a pool of liquid to form at the shaker's feed end to provide additional head and high fluid throughput capability. This allows the use of fine screens to improve separation performance. The Derrick Flo-Line Cleaner is one example of a linear motion shale shaker.

One drawback to linear motion shakers is their relatively poor performance in processing gumbo. The short vibration stroke length when combined with long, basket lengths, uphill deck angles and strong acceleration forces tends to make the soft gumbo “patties” adhere to the screen cloth. Some success has been reported by using linear motion shakers with short deck lengths and horizontal or downhill deck angles.

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2.1.4 Balanced Elliptical Motion

Amoco's analytical shaker dynamics model has predicted that this is the optimum vibration pattern for maximum solids conveyance. Unlike “unbalanced” elliptical motion, all points on the shaker basket move in phase with the identical elliptical pattern. The model predicts that a “thin” ellipse will provide solids conveyance superior even to linear motion. Because elliptical motion provides a “softer” acceleration pattern than linear motion, it is likely that screen life may also be improved.

Amoco Production Research has recently tested a simple and commercially-viable method to achieve balanced elliptical motion. The vibrators are located as shown in Fig. 5. The vertical orientation of the vibrators dictates the shape of the ellipse. The more the vibrators are tilted out from the shaker basket, the more circular the vibration pattern.

Fig. 5. Balanced elliptical motion.

Note: This motion is the most efficient in conveying solids.

Full-scale experiments have verified analytical model predictions of improved solids conveyance with a thin ellipse. In Fig. 6, the numbers in parentheses are the ratios of major axis length to minor axis length of the vibration patterns. By adjusting the shape of the ellipse, solids conveyance velocity can be adjusted without changing deck angle or acceleration normal to the screen. This feature has potential for optimizing cuttings conveyance with respect to oil retention on cuttings.

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Fig. 6. Conveyance velocity.

Note: The shape of the ellipse controls conveyance velocity. A thin ellipse

conveys solids faster than linear motion.

2.1.5 Vibration Dynamics

2.1.5.1 Acceleration

During the vibration cycle, the shaker basket undergoes acceleration which changes in both magnitude and direction. As discussed previously, the placement of the vibrators determines the vibration pattern and therefore the net acceleration direction during the vibration cycle. The mass of the counterweights and the frequency of the vibration determine the magnitude of the acceleration.

The vertical component of acceleration has the most effect on shaker liquid throughput. We relate the vertical components of acceleration and stroke length to frequency by the following equation:

( )

G's = stroke in. x RPM2

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where the stroke length is the total vertical distance traveled by the shaker basket and 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 of 2.5-5.0

G’s, depending upon the vibration pattern. Field experience has shown this range offers the best compromise between throughput capacity and screen life.

Many manufacturers report the acceleration of linear motion shakers along the line of motion. This yields a larger number and looks good on the specification sheet. However, unless the angle of vibration is also specified, it reveals little about the performance of the shaker. The “G's” for shale shakers listed in the appendix are calculated for the direction normal to the screen surface.

Some shakers have adjustable counterweights to vary acceleration (Fig. 7). Although flow capacity and cuttings dryness improves with increased acceleration, screen life is negatively affected. By reducing the “G’s” when extra flow capacity is available, screen life may be improved.

Fig. 7. Adjustable vibrator counterweights. Note: Other designs are used, this is the most simple.

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2.1.5.2 Frequency (RPM), Stroke Length

The vibrator frequency of most shale shakers is not normally adjustable. The vibrators typically rotate at a nominal rpm of 1200 or 1800 at 60 Hz. Stroke length varies inversely with rpm. A higher rpm will result in a shorter stroke length at the same acceleration.

The effect of vibrator frequency and stroke length on shaker processing rate has been evaluated in the laboratory. The results of these tests show improved shaker flow capacity in the presence of solids with decreased rpm (or conversely, increased stroke length) at the same G level. (Fig. 8). Therefore, the term “high speed” should not be used to mean “high performance” since the opposite relationship is often more correct.

Fig. 8. Shaker throughput versus vibrator frequency. Note: Shaker throughput improves as frequency decreases.

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 with a fine coating of mud. More frequent housekeeping is required to maintain a safe environment around the shakers. Longer stroke lengths also tend to reduce screen life.

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2.1.6 Deck Angle

Because linear motion shakers will convey uphill, most provide an easily-adjustable deck angle feature to optimize fluid throughput capacity and cuttings conveyance velocity. Uphill deck angles also provide protection against overflow due to surges at the flow line.

At deck angles greater than 3_°, solids grinding in the pool region can be a

problem. Although fluid throughput increases with uphill deck angle, cuttings conveyance decreases. Solids conveyance within the pool region is slower than out of the pool due to viscous drag forces and the differential pressure created across the 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 is observed at the discharge end (Fig. 9). The vibrating action of the screen and extended residence time will tend to grind soft or friable cuttings before they have the opportunity to be conveyed out of the pool. This condition should be avoided since 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 connection immediately after circulation is stopped. There should not be a disproportionate amount of solids accumulated at the feed end. The problem can be rectified by lowering the deck angle until the solids mound is eliminated.

Fig. 9. Solids bed buildup.

Note: This may occur when the shaker deck is tilted up to high.

3 Screen Fastening and Support

The type of screen panel dictates the type and amount of support and fastening system necessary. The screen fastening and support structure provide the following functions:

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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 labeled as “pretensioned” and “nonpretensioned” panels. However, these terms do not exactly describe their construction since many nonpretensioned panels are, indeed, pretensioned. The terms “rigid frame” and “hookstrip” more correctly differentiate the two main panel types.

3.1 Hookstrip Screen Panels

This is the most common type of panel, consisting of one to three layers of screen cloth. The cloth is frequently bonded to a thin perforated-metal grid plate or a plastic grid. Fig. 10 shows the construction of a typical hookstrip screen. The screen panel is tensioned on the shaker deck by an interlocked hookstrip and drawbar arrangement located on both sides of the shaker (Fig. 11). Three or more tensioning bolts are used to pull each drawbar down and towards the side of the basket. This seats the screen on the shaker deck and distributes even tension along the hookstrip.

Fig. 10. Typical hookstrip screen.

Note: The backing grid, though not necessary, provides support and improves

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Fig. 11. Hookstrip screen tensioners.

Note: This is the most common type of fastening system for hookstrip screens.

These panels are not rigid; the shaker deck must be crowned to maintain screen-to-deck contact throughout the vibration cycle. Support ribs in the shaker deck are designed to ensure even support of the screen across the width of the basket. Full contact with all support stringers is critical, especially with metal-backed panels. The panels will suffer premature fatigue failure if flexing is allowed to occur.

Because screen tension is extremely important to ensure good screen life, the tension should be checked frequently on nonpretensioned hookstrip-style screens. Spring-loaded tensioning bolts are recommended to aid in preventing a complete loss of tension and premature failure as the screens stretch and “seat” onto the deck. Tensioning springs are not required for hookstrip panels with metal backing plates since these panels will not normally stretch.

The crowned deck can cause uneven fluid coverage (Fig. 12). The mud may extend further out along the sides of the shaker than at the center where maximum 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 discharge and contribute to unacceptably wet cuttings even though the fluid endpoint along the centerline of the shaker may be well back from the discharge. The problem can be mitigated by increasing the deck angle and selecting high efficiency screens 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 improved screen changing on their Flo-Line Cleaner; the tensioning nut and spring have been replaced by an integral nut and spring assembly which requires a half-turn to fully operate.

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Fig. 12. Shaker fluid endpoints.

Note: Crowned decks will cause uneven fluid coverage especially at low deck

angles.

3.2 Rigid Frame (Pretensioned) Screen Panels

In rigid frame screen panel construction, the screen cloth is tensioned and bonded to an integral steel frame; no additional tensioning is required. Because rigid frame screens are flat, uneven fluid coverage on the shaker is not a problem. All other factors being equal, discharged cuttings dryness is reported to be superior to shakers with hookstrip screen designs.

Since no tensioning is required during installation, the fastening system can be designed for fast panel replacement. For example, each panel on the Fluid Systems Model 500 is held in place by two wedges (one on each side). A tap on the wedge locks the panel in place. The Thule VSM100 has a

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pneumatically-actuated system. Sweco's LF-3 Oil-Mizer and Brandt's ATL-1000 also have quick-release fastening systems.

The two most common types of pretensioned panels are shown in Fig. 13 and Fig. 14.

1. The screen cloth is tensioned and glued directly to the steel frame. Additional glue lines may be included between the frame members to provide additional support. The bonding pattern divides the panel into 3-to 4-in. wide strips oriented parallel 3-to the flow. This design is used in the Fluid Systems Model 500.

This panel design maximizes usable screening area. However, the large unsupported area normally limits cloth selection to the heavier grades with lower flow capacity. The panel is not normally considered repairable.

2. Alternatively, the screen cloth may be bonded to a perforated metal backing plate similar to a hookstrip screen. The metal backing plate is then bonded to the support frame to create a rigid panel. The Brandt ATL-1000 and the Thule VSM-100 use this type of panel.

Usable screen area is reduced by the perforated plated design, but this is offset by the option of using higher conductance screen cloth, repairability, and better screen life under high solids loading conditions.

Fig. 13. Rigid screen panel with perforated plate. Note: The metal grid is bonded to a steel frame.

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Fig. 14. Rigid screen panel.

Note: The screen cloth is glued directly to a steel frame.

4 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 panels may be used to provide a continuous screening surface. Deck profiles of single deck linear motion shakers are usually flat from feed to discharge, but other profiles are used. For example, the panels of the Fluid Systems Model 500 and Swaco ALS are arranged in a stairstep pattern: Each downstream panel is slightly lower than the upstream panel, primarily for ease of panel positioning. Unbalanced elliptical motion shakers, such as the Derrick Standard or Swaco Super Screen, have an increasingly negative (downhill) slope on downstream panels to improve solids conveyance. Single deck shakers provide the advantage of allowing complete access to the screening surface. This simplifies maintenance, panel changes, screen inspection and cleaning. The disadvantage of single deck shakers becomes apparent under high solids loading conditions; flow capacity, cuttings dryness and screen life may be greatly reduced. These problems can be circumvented by using a cascading shaker arrangement. (Refer to the following section: Cascading Shaker Systems.)

Linear motion single deck shakers are preferred for most applications because of their simplicity, high flow capacity and fine-screening capability. Their popularity has spurred numerous companies to manufacture linear motion shakers. A complete list is provided in Appendix F, Equipment Specifications. Many of the major manufacturers’ shakers have been evaluated in the laboratory at APR. Differences in overall performance were found to be relatively minor. Examples of single deck linear motion shakers that will provide acceptable performance are pictured in Figures 15-20. The

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shakers are listed in alphabetical order, no ranking is implied by the order of their appearance.

Fig. 15. Derrick flo-line cleaner plus.

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Fig. 17. Swaco ALS.

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Fig. 19. Sweco LM-3.

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5 Cascading Shaker Systems

“Cascading” refers to the use of shakers in series (the mud passes sequentially through two shakers) to remove drill cuttings in two stages. The first set of shakers remove or “scalp” the coarsest cuttings from the returned drilling fluid. The mud and fine cuttings are then fed to a second set of shakers with finer screens. This arrangement increases the capacity of the fine screen shakers through reduced solids loading. This arrangement is especially effective when drilling fast, large diameter hole sections or gumbo formations.

Fig. 21 illustrates a “2 over 3" cascading shaker arrangement. This arrangement usually provides adequate shale shaker solids removal for drilling most 17-1/2-in. diameter holes. It is important to ensure that valves are provided to isolate each shaker in the system as required for screen maintenance and shaker repair.

Fig. 21. Cascading shaker system.

In most instances, unbalanced elliptical or circular motion shakers are the preferred scalping devices. Soft, sticky cuttings such as gumbo are generally handled better by these vibration patterns with a flat or downhill deck angle. However, linear motion shakers have been successfully used as scalpers when the deck angle is steeply pitched downhill (such as a Derrick Standard) or when the deck length is short (such as the Fluid Systems two-panel shaker).

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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 available to avoid solids settling in the return line. A good “rule of thumb” is 1 ft of drop per 12 ft of flowline. Also, additional space is obviously necessary to accommodate a cascading system.

5.1 Unitized Cascading Systems

A unitized cascading system incorporates two shakers, one stacked over the other, on a single skid. This design reduces many of the plumbing problems and costs normally associated with retrofitting a cascading system on a rig. Also, the unitized system takes up less floor area than a standard cascading system. Because the top and bottom shaker are separate units, each can be designed for its specific function without severely impeding screen panel access or performance. This is an advantage over integral tandem deck shakers.

There are two disadvantages to unitized cascading systems: (1) They have high weirs which will limit their application to rigs with sufficient elevation difference between the flow nipple and the upper shaker weir; and (2) the upper shaker may be too high to be worked on easily. A permanent walkway or ladder should be installed to improve access to the upper shaker’s screens.

Two systems are currently available: The Brandt ATL-CS (Fig. 22) and the Fluid Systems Model 50-500. The Brandt is a tandem deck, circular motion basket over a linear motion basket. The Fluid Systems version uses a short, two-panel linear motion basket as the scalping shaker over their standard Model 500 shaker.

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Fig. 22. Brandt ATL-CS.

Note: This is one example of a “utilized” cascading shaker arrangement.

6 Integral Tandem Deck Shakers

These shakers incorporate two distinct screening decks stacked in a single basket. The top deck screen “scalps” off the coarse solids to reduce the solids loading to 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 shakers are preferred. In either case, flow back pans are recommended to improve throughput.

Tandem deck shakers offer a compromise between a true cascading system and single deck shakers. If the top scalping deck covers the entire basket width, solids handling capacity is good. However, accessibility to the lower deck screens and the ability to monitor screen wear is limited. Conversely, a

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small scalping deck limits solids loading capacity, but improves accessibility and screen monitoring. Tandem deck shakers are recommended for medium-high solids loading applications or where space or height limitations will not permit the use of a cascading shaker system.

The total combined area of both screening surfaces cannot be used to compare the performance of these shakers to single deck shakers. The relative processing capacity of tandem deck shakers will depend upon the size distribution of the solids in the feed, solids generation rate and other factors. Generally, tandem deck shakers will outperform single deck shakers when large diameter hole and high penetration rates are encountered. Examples of linear motion tandem deck shakers are shown in Figures 23-25.

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7 Shaker Manifolds

The flowline and manifold system must be designed to provide an even distribution of mud and cuttings to the shakers. The flow line must have sufficient drop to prevent solids from accumulating in the line: A drop of 1 ft per 12 ft of run is a good rule of thumb. Flowline diameter must also be sufficient to handle the maximum 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 parallel. Because the shaker feed is essentially two-phase, liquid being one phase and solids the other phase, equal division of both phases can become difficult to achieve with typical manifold designs (Fig. 26 and Fig. 27). Branch tees should be avoided. The solids will preferentially travel a straight path, resulting in uneven solids loading to the shakers. Dead end tees will distribute the solids more evenly. Examples of recommended manifold designs for multi-shaker installations are provided in Fig. 28, Fig. 29, and Fig. 30. Overhead or circular manifolds will provide better distribution of mud and solids.

All shakers should be level with equal weir heights to ensure even flow distribution. A common shaker box (possum belly) is acceptable for scalping shakers. It is not recommended for the fine screen shakers since a large shaker box only serves to collect solids, which can enter the mud tanks if the bypass gate is opened.

Fig. 26. Poor manifold design. Note: Distribution to the shakers may be uneven.

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Fig. 27. Better manifold design. Note: There are less branch tee’s in this design.

Fig. 28. Best conventional manifold design. Note: All branch tee’s are eliminated.

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Fig. 29. Circular manifold design.

Note: Useful for odd number of shakers. Flowline lengths are exaggerated.

Fig. 30. Overhead manifold design.