DWM Solids Control Handbook

SOLIDS CONTROL HANDBOOK

Sections 1 — 13 Appendices A — F

January 1998 Dowell ITM-1158

Schlumberger

Dowell

Section 000 SOLIDS CONTROL HANDBOOK Schlumberger Dowell

Master Table of Contents

January 1998 Page 1 of 8

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 2.1.2.2 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 6 Integral Tandem Deck Shakers ........................................................................................23 7 Shaker Manifolds .............................................................................................................27 8 Operating Guidelines........................................................................................................30 8.1 Optimizing Screen Life ............................................................................................30 8.2 Screen Selection .....................................................................................................30

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Schlumberger Dowell

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 4.2 Effect of Vibration Pattern .......................................................................................5

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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 9 Summary .........................................................................................................................16

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Schlumberger Dowell

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 3 Bulk Systems ...................................................................................................................4

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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 3 Monitoring Dewatering Costs and Efficiency.....................................................................7

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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 7 Calculations .....................................................................................................................6

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Schlumberger Dowell

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. 5. Mission Magnum 1, 6 x 5 x 11 at 1750 rpm. ..............................................................3 Fig. 6. Mission Magnum 1, 6 x 5 x 14 at 1150 rpm. ..............................................................4 Fig. 7. Mission Magnum 1, 6 x 5 x 14 at 1750 rpm. ..............................................................4 Fig. 8. Mission Magnum 1, 8 x 6 x 11 at 1150 rpm. ..............................................................5 Fig. 9. Mission Magnum 1, 8 x 6 x 11 at 1750 rpm. ..............................................................5 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 Fig. 13. Harrisburg curve no. 2014, 5 x 4 x 14 at 1750 rpm. .................................................7 Fig. 14. Harrisburg curve no. 2005, 6 x 5 x 11 at 1150 rpm. .................................................8 Fig. 15. Harrisburg curve no. 2002, 6 x 5 x 11 at 1750 rpm. .................................................8 Fig. 16. Harrisburg curve no. 2011, 6 x 5 x 14 at 1150 rpm. .................................................9 Fig. 17. Harrisburg curve no. 2008, 6 x 5 x 14 at 1750 rpm. .................................................9 Fig. 18. Harrisburg curve no. 2007, 8 x 6 x 14 at 1150 rpm. .................................................10 Fig. 19. Harrisburg curve no. 2006, 8 x 6 x 14 at 1750 rpm. .................................................10 APPENDIX F EQUIPMENT SPECIFICATIONS Tables Table 1 Table 2 Table 3 Table 4 Table 5 Table 6 Table 7

Oilfield Shale Shakers .............................................................................................2 Oilfield Shale Shaker Classification .........................................................................18 Oilfield Centrifugal Pumps .......................................................................................19 Oilfield Degassers ...................................................................................................26 Oilfield Hydrocyclones .............................................................................................33 Oilfield Mud Cleaners ..............................................................................................44 Oilfield Centrifuges ..................................................................................................50

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Introduction


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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Section 100 SOLIDS CONTROL HANDBOOK

January 1998

Introduction

Page 2 of 2

Schlumberger Dowell

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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January 1998

Economics

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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 equipment.

results

from

ill-chosen

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or

incorrectly-operated

Section 200 January 1998


Economics

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Schlumberger Dowell

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 mid60s when hydrocyclone use was first advocated.

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Economics


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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Economics

Page 4 of 12

Table 1 Solids Control Economic Analysis Parameters Vc Vi Vf Vd Vlw Vsw Vt

= = = = = = =

Volume of drilled solids generated, bbls Initial volume in tanks, previous hole/casing, bbls Final volume in tanks, previous hole/casing, bbls Volume of addition/dilution fluid required, bbls Volume of liquid waste to be disposed, bbls Volume of wet solids to be disposed, bbls Total volume of solids and liquids to be disposed, bbls

ki ks X Y

= = = =

Initial concentration of drilled solids, vol. fraction Maximum volume fraction of drilled solids, vol. fraction Drilled solids removed by equipment, vol. fraction Liquid associated with the cuttings, bbl/bbl

D L W

= = =

Hole diameter, in. Section length, ft Washout, vol. fraction

rd rc ri re

= = = =

Density of dilution fluid, ppg Density of drilled cuttings, ppg Mud weight at the start of the section, ppg 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:

Vc = 0.000971 x D 2 x L x W For a given percent of drilled solids removed, X, the required dilution volume is computed by:

Vd =

(1- k s) (1- X)V ks

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c

- Vi +

ki Vi ks


Economics


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

Xc =

( ) Vc(1+ k s Y)

Vc - k s Vf + Vc + k iVi

Vd = (Vf − Vi ) + X c Vc (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:

ρd = ρe +

V Vi ρe − ρi ) − c (1 − X )(ρc − ρe ) ( Vd Vd

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

Vt = Vi + Vc + Vd The wet solids volume, Vsw, and liquid volume, Vlw, discharged while drilling the interval is computed by:

Vsw = XVc (1+ Y) Vlw = Vt − (Vf + Vc + Vsw ) 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:

Vlw = Vt − Vsw

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Economics

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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 Vi Vf Vd Vlw Vsw Vt

= = = = = = =

Volume of drilled solids generated, bbls 360 bbls 360 bbls Volume of addition/dilution fluid required, bbls Volume of liquid waste to be disposed, bbls Volume of wet solids to be disposed, bbls Total volume of solids and liquids to be disposed, bbls

ki ks X Y

= = = =

0 (fresh mud, no drilled solids) 0.06 (6% maximum drilled solids) 0, 0.1, 0.5 (3 cases) 1.0 (1:1 solids to liquid ratio in wet solids discharge)

D L W

= = =

12.25 in. 1600 ft 1.10 (10% washout)

rd rc ri re

= = = =

Density of dilution/addition fluid, ppg 2.6 x 8.34 = 21.68 ppg 8.6 ppg initial mud weight 9.4 ppg final mud weight

Dilution Cost: $5.00/bbl Liquid Waste Cost: $3.00/bbl Solid Waste Cost: $5.60/bbl

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Economics

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Calculations: 1. Cuttings volume:

Vc = 0.000971 x D 2 x L x W Vc = 0.000971 x (12.25) x (1600) x (1.1) = 256 bbls 2

2. Dilution volumes for each solids removal efficiency:

Vd =

(1- k s) (1- X)V ks

c

- Vi +

ki Vi ks

For X = 0.0

(1- 0.06) (1 − 0)256 − 360 +

Vd =

0.06

0 (360) = 3650 bbls 0.06

For X = 0.1

Vd =

(1- 0.06) (1 − 0.1)256 − 360 + 0.06

0 (360) = 3250 bbls 0.06

For X = 0.5

Vd =

(1- 0.06) (1 − 0.5)256 − 360 + 0.06

0 (360) = 1645 bbls 0.06

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.

ρd = ρe +

ρd = 9.4 +

Vi V ρe − ρi ) − c (1 − X )(ρc − ρe ) ( Vd Vd

360 256 . − 9.4) = 8.6 ppg (9.4 − 8.6) − 3250 (1 − 0.1)(217 360

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

Xc =

Xc =

( (

) )

Vc - k s Vf + Vc + k iVi Vc 1+ k s Y

256 − 0.06(360 + 256) + 0(360) 256(1 + 0.06 x 1.0)

= 0.81

Vd = (Vf − Vi ) + X c Vc (1 + Y) Vd = (360 − 360) + 0.81(256)(1 + 1) = 415 bbls 5. Summary of waste disposal volumes:

X = 0.00 X = 0.10 X = 0.50 X = 0.81

Total Volume bbls 4266 3866 2261 1030

Wet Solids bbls 0 51 256 414

Liquid While Drilling bbls 3650 3199 1389 0

Total Liquid bbls 4266 3815 2005 616

6. Cost estimate for each case, discarding total liquid volume (last column in Step 5): Drilled Solids Removed 0% 10% 50% 81%

Equipment Costs $0 $100 $500 $5000

Addition/Dilution Costs $18,250 $16,250 $8225 $2075

Disposal Costs Solids Liquids $0 $12,678 $286 $11,445 $1434 $6015 $2318 $1848

Total Costs $30,928 $28,081 $16,174 $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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Page 10 of 12

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:

Vm = 4.

Vw kw

Calculate the volume of drilled solids, Vc: 2

Vc =0.000971 x D x L x W 5.

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

Vd = 6.

Vc ks

Calculate the dilution factor, DF:

DF = 7.

Vm Vd

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 Interval Length, L Bit Diameter, D Washout, W Average Drilled Solids Concentration, ks

1600 ft 12.25 in. 10% 0.06

0.9

Calculations: 1. Calculate the volume of mud built, Vm:

Vm =

Vw 1481 = = 1645 bbls kw 0.9

2. Calculate the volume of drilled solids, Vc: 2

Vc = 0.000971 x D x L x W 2

= 0.000971 (12.25) (1600)(1.1) = 256 bbls 3. Calculate the dilution volume required if no solids were removed, Vd:

Vd =

Vc 256 = = 4267 bbls ks 0.06

4. Calculate the dilution factor, DF:

DF = 5.

Vm 1645 = = 0.386 Vd 4267

Calculate the total solids removal performance, Et:

Et = (1- DF) = 1- 0.386 = 0.614 Expressed as a percentage:

Et = 61.4%

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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

6 Integral Tandem Deck Shakers ........................................................................................ 23

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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. 2.1.2.2 Recommended Applications ·

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 gravity bisects at 90° a line drawn between the two axes of rotation (Fig. 4.).

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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. 2.1.3.2 Recommended Applications ·

All applications where fine screening is required.

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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 commerciallyviable 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 70,400

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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 2 in./sec ). 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 easilyadjustable 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 screen life.

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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 ATL1000 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 3to 4-in. wide strips oriented parallel 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.

Fig. 16. Fluid systems model 500.

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Fig. 17. Swaco ALS.

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




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Fig. 19. Sweco LM-3.

Fig. 20. Triton NNF.

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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.

Fig. 23. Brandt ATL 1000.

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Fig. 24. Derrick cascade system.

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Fig. 25. Thule VSM 100.

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Shale Shakers


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. Note: Excellent for even distribution of liquids and solids, but more complicated to fabricate.

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8 Operating Guidelines 8.1 Optimizing Screen Life Perforated plate screens usually exhibit longer screen life than other hookstrip screens. They provide the most support and are repairable. 1.

Screen life is inversely proportional to plate opening size. If premature wear is apparent in the pool region, install panels with smaller perforated plate sizes at the feed end of the shaker where loading and wear is greatest.

2.

Reduce deck angles to improve solids conveyance, reduce loading and eliminate solids grinding at the feed end.

3.

If premature backing plate failure is experienced, check that all deck rubbers are in place and in good condition. Check for a buildup of solids between the screen and the support areas on the shaker deck.

8.2 Screen Selection 1.

When possible, run the same screen mesh over the entire deck of a single deck shaker. When running different mesh cannot be avoided, the coarser mesh should be run at the discharge end. Do not vary the mesh size by more than 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.

Use the spreadsheet program, SHAKCAP, to assist in predicting shaker requirements to achieve a separation target of at least 100 mesh (149 microns).

4.

Always run the coarser screens on the top deck of a tandem deck shaker or on the upstream shaker. The upper deck screen should be at least two mesh sizes coarser than the bottom deck. It has been observed that running screens which are too fine on the top deck can actually impede cuttings conveyance on the lower deck.

5.

Select screens for which the new API designations are known to ensure predictable performance.

8.3 Cuttings Dryness The volume of drilling fluid lost with the discharged cuttings is becoming more important in the wake of increasingly stringent environmental regulations and more expensive drilling fluid formulations. In most cases, minimizing liquid waste from the shale shakers makes both economic and environmental sense. A field procedure to determine composition of the discharge is given in Appendix C, Solids Control Equipment Discharge Analysis, Oil-Based muds.

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Shaker discharge dryness is heavily dependent upon the size distribution of the cuttings and the viscosity of the mud. There will always be an irreducible “volume fraction” of fluid wetting the cuttings and this will vary inversely with particle size. Extremely fine solids have substantially higher percentages of associated liquid than larger solids due to surface area and surface tension effects. Mud viscosity will also impact the thickness of this fluid layer. The shaker can remove a portion of this residual wetness by the acceleration and impact forces imparted on the cuttings after they exit the pool region. Dryness may 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 liquid pool to achieve a desired separation, the remaining dry screening area may not be sufficient to remove excess moisture carried with the cuttings. High solids loading rates will also have a negative impact on cuttings dryness. Solids loading and dry screening area can be addressed during the planning phase by ensuring that sufficient shaker area is available to maximize cuttings dryness: 1.

When using SHAKCAP (see Appendix A, Solids Control Programs) to estimate shaker requirements, provide an additional shaker over the minimum number recommended by the program when shaker discharge dryness is critical.

2.

Install a cascading system or tandem deck linear motion shakers to reduce solids loading and fluid coverage.

The following remedial actions may help improve cuttings dryness: 1.

Deck Angle Increase - This is the most simple solution. Fluid loss along the hookstrips is reduced. Solids conveyance will decrease with steeper deck inclinations, 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 deck angle selected. Because conveyance is lessened, the solids remain in the pool longer and can interfere with the ability of the fluid to pass through the screen, especially at higher solids loading rates. This may retard the formation of a shorter, deeper pool. Also, solids grinding may become a problem.

2.

High Efficiency Screens - Screens with high transmittance values will reduce fluid coverage and increase dry screening area. Two new screens, the Derrick “Pyramid” and Cagle’s “HCR” series offer distinct advantages in this application. The corrugated “Pyramid” design may reduce mud loss along the hookstrips and offers increased screening area. Cagle’s HCR cloth has very high transmittance values and has exhibited service life up to 4 times standard DX designs.

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3.

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Coarser Screens - This has two effects. First, the fluid endpoint on the shaker will recede, and second, the average discharged cuttings size will increase. However, this action usually carries with it the penalty of poorer separation efficiency and higher costs, unless downstream solids removal equipment “picks up the slack.” Try running a coarser screen at the discharge end before converting the entire deck to coarser screens. There are special considerations worth mentioning depending upon the mud system in use: Unweighted Muds The importance of fine screening in unweighted muds is typically not as critical, provided: 1) sufficient hydrocyclones and centrifuges are used, and 2) the cuttings are not soft and easily degraded by centrifugal pumps. In fact, significant fluid savings in oil-based muds have been realized by running coarser screens on the shakers to produce a dry discharge and transferring a greater share of the solids removal to the downstream centrifuges. Weighted Muds In weighted muds, the importance of the shaker in the solids removal system generally precludes the option of running coarser screens. Economics usually dictate that the finest separation possible be made by the shaker without substantial loss of barite in the discharge. Drill cuttings missed by the shaker will remain in the circulating system and eventually contribute to a low gravity solids buildup and subsequent viscosity increase.

4.

G Force Increase - Increased shaker acceleration will help remove excess liquid by overcoming part of the surface tension forces which bind the fluid to the cuttings. Conversely, cuttings conveyance velocity will increase and screen life will decrease. Conveyance velocity can be reduced by increasing the deck inclination, but screen life will decline considerably at accelerations above 4 Gs.

8.4 Sticky Solids (Gumbo) 1.

Use scalping shakers ahead of fine screen shakers. Circular or unbalanced elliptical motion shakers or shakers with short basket lengths are recommended as the scalping shakers. If space is limited, tandem deck linear motion 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 necessary to keep the screens wet, use low flow rate nozzles which produce a fine mist with an umbrella or fan-shaped discharge. These nozzles operate at less than 0.5 gpm. No more than two are normally required. Do not use high volume or high pressure sprays on a continuous basis. This will degrade the gumbo patties and drive the solids through the screens.

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8.5 Polymer Muds 1.

Prehydrate and preshear the polymer before adding into the active mud system 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%.

8.6 Blinding, Plugging 1.

Gilsonite (Asphaltenes) Triple-layer screens are susceptible to plugging by gilsonite or other asphaltene-based products in the drilling fluid. The problem may be mitigated by selecting single or double-layer screens. For example, on Derrick Flo-Line Cleaners, use the PBP HP or GBG HP series. Refer to Appendix D, Screen Designations, for a complete list of screen panel descriptions.

2.

Sand (Near Size) ·

Unbonded triple layer screens provide the best resistance to blinding, but screen life is generally poor.

·

Single layer, square mesh cloth is most susceptible to blinding. Select screen 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. The sands may have a relatively narrow size distribution which might not blind a smaller opening size.

8.7 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 concentrations are continuously required in the mud, provided:

high

·

Cuttings size distribution is sufficiently fine to pass through the scalping screens.

·

Solids loading rates do not negatively impact the performance of the downstream shakers and cause solids buildup in the active system.

·

The LCM removed by the scalpers is returned to the active system downstream of the centrifuge.

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9 Estimating Number of Shakers Required 1.

Base the number of shakers required on the economics and the physical constraints of the specific application. A complete economic evaluation using SECOP is recommended.

2.

As a quick estimate, the spreadsheet file SHAKCAP can be used to estimate the number of shakers required or the performance of existing shakers.

3.

A “ballpark” estimate of shaker requirements, based on average drilling conditions can be made from Table 1. This is a very rough estimate and should be used only as a guide.

Table 1 Shakers Required Approximate Number of High Performance Linear Motion Shakers Maximum Viscosity (cP)

Circulation Rate (gpm)

5

10

15

20

25

30

40

50

60

300

1

1

1

1

1

1

2

2

2

400

1

1

1

2

2

2

2

2

2

500

1

1

2

2

2

2

3

3

3

600

1

2

2

2

2

3

3

3

3

700

2

2

2

2

3

3

3

3

4

800

2

2

2

3

3

3

4

4

4

900

2

2

3

3

3

4

4

4

1000

2

2

3

3

4

4

4

1100

2

3

3

4

4

4

1200

2

3

3

4

4

1300

2

3

4

4

1400

2

3

4

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10 Summary ·

The shale shaker is the only solids control device that makes a separation based on the physical size of the particle. The separation size is dictated by the opening sizes in the shaker screens. Hydrocyclones and centrifuges separate solids based on differences in their relative mass and the fluid.

·

Shale shakers with linear vibratory motion are preferred for most applications because of their superior processing capacity and finescreening ability. Circular motion or unbalanced elliptical motion shakers are recommended as scalping shakers in cascading systems.

·

Vibration of the shaker basket creates G-forces which help drive shear thinning fluids such as drilling mud through the screens. Vibration also conveys solids off the screens. Most linear motion shakers operate in the range of 3 to 4 G’s to balance throughput with screen life. G-force is a function of vibration frequency (rpm) and stroke length.

·

“High-speed” should not be equated with “high performance.” Laboratory tests indicate that, in the normal operating range for linear motion shale shakers, lower frequency vibration and longer stroke lengths improve throughput capacity. Most linear motion shakers operate at 1200 to 1800 rpm.

·

Avoid deck inclinations above 3°. High deck angles reduce solids conveyance and 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, rigid frame panels promote even fluid coverage, but can cost more.

·

Shakers may have single or tandem screening decks. Single deck shakers offer mechanical simplicity and full access to the screening surface. Single deck shakers may be arranged to process mud sequentially as a “cascading” system to improve performance under high solids loading conditions. Tandem deck shakers offer improved processing capacity under high solids loading 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 dryness, handling sticky solids, polymer muds, blinding and LCM problems.

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The spreadsheet program SHAKCAP can estimate the number of shakers required or to determine the screening capability of existing shakers. A complete economic evaluation using the SECOP program is recommended to determine the optimum shaker configuration when designing a system.

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Shaker Screens


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 4.2 Effect of Vibration Pattern..............................................................................................5 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

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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

1 Introduction Shaker screen selection has the largest impact on the overall performance of the shale shaker. It is therefore important to understand the factors which may impact screen performance and how to properly select screens. Shaker screen performance 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

2 Separation Performance 2.1 Grade Efficiency The separation performance of a shale shaker screen (or any other solids control device) is commonly represented by its percentseparated, or grade efficiency, curve. This curve is generated from fullscale experimental measurements and depicts the percent solids removed as a function of particle size. It reports the screen's probability of separating any specific particle size with a given shaker under conditions specific to the test. Grade efficiency is the preferred measure of separation performance because it is independent of feed particle size distribution. An example of a percent-separated curve is shown in Fig. 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 of the median cut point (d50) can be made in the field by the wet sieve procedure (see Field Procedure to Estimate Cut Point).

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Fig. 1. Percent separated curve. Note: This curve indicates the percentage of solids removed as a function of particle size.

2.2 Separation Potential APR has developed a method to characterize the relative separation efficiency potential of shaker screens without the expense and time required for full-scale testing. The technique links the relative separation performance of screens to a volume-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 corresponding to an ellipsoidal volume calculated from the image analysis data. The cumulative volume of these ellipsoids, when plotted as a function of spherical diameter, yields a curve which correlates well with the standard grade efficiency curve. This curve represents the “separation potential” of the screen. The word “potential” is used because the screen's separation performance is not measured directly, but implied by the size of the screen's apertures. Note: Grade separation efficiencies as measured on the shaker are subject to specific shaker and flowline conditions. They may not always agree with separation potential values. For example, the separation potential value for a screen with rectangular openings may be pessimistic when drilling clean sand sections producing predominantly spherical sand grains. The image analysis method assumes solids of all shapes and sizes are available to the screen. However, on average, the

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separation potential values have been shown to adequately represent the screen's separation performance.

3 Liquid Throughput Performance The liquid throughput capacity of a screen panel is primarily a function of screen conductance and usable area. Conductance describes the ease with which fluid can flow through a unit area of screen cloth. In simplistic terms, it is analogous to permeability with the length in the direction of flow (screen thickness) taken into account. Higher conductances will result in higher flow rates through the screen. Conductance is calculated from the mesh count and wire diameters of the screen cloth by the equations given in Appendix B, Conductance Calculation. Multilayer screens can also be handled by the conductance equation. The inverse of conductance for each screen layer is summed to equal the inverse of the net overall conductance: 1 1 1 1 = + +... Ct C1 C2 Cn This is valid provided that the screen layers used in the composition are designed to remain in contact. Oilfield screens are typically bonded to a perforated metal panel or plastic grid to provide extra strength and improve service life. This practice eliminates some of the usable area through which fluid may pass. Some metal backing plate designs may reduce effective screening area by as much as 40 percent. Because conductance describes screen flow capacity per unit area, the usable unblocked area available for screening must also be considered when comparing the mud processing capacity of shaker screen panels.

4 Screen Life The definition of “acceptable” screen life must be judged within the context of the total solids removal system economics. Besides screen replacement cost, consideration must be given to the costs of drilling mud dilution and waste disposal costs when determining whether longer screen life is warranted at the expense of solids removal efficiency. In weighted mud applications, the economic benefits of improved solids removal efficiency usually outweigh the additional screen costs.

4.1 Effect of Screen Composition Only very general correlations may be made between composition and service life. Unfortunately, features that improved life are usually detrimental to flow capacity. Using wires with greater tensile strength or adding supporting layers

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can both reduce conductance. Increasing support through additional bonding area (smaller plate openings) eliminates usable screening area. Also, support techniques and screen tension can have a major effect on screen life. As a result, screen panels are typically designed to balance flow 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 composition effects.

4.2 Effect of Vibration Pattern 4.2.1 Linear Motion The abrupt changes in acceleration during the vibration cycle tends to cause screens to wear more quickly unless close attention is paid to tensioning and screen support techniques. Perforated metal backing plates and pretensioned screen panels have been specifically developed to address this problem. Linear motion shakers usually operate at less than 4.0 G's (normal to the screen) to balance screen life with processing capacity. Regardless, the finer screens normally run on linear motion shakers cannot be expected to outlast the coarser screens used in the past. For screens finer than 100 mesh, expect an average service life in excess of 100 hours.

4.2.2 Circular, Elliptical Motion The smooth change in acceleration with respect to direction translates into longer screen life compared to other vibration patterns. However, many circular motion shakers were designed before the advent of fine mesh screens and may provide less support for the screens. This will tend to negate much of the screen life benefit associated with circular motion.

5 Shaker Screen Designations 5.1 Mesh Count Shaker screens have traditionally been assigned mesh count designations by the manufacturer. Unfortunately, they do not adequately describe screen performance in 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 is known. The opening size, D, is related to the wire diameter, d, and the mesh count, n, by the following equation:

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D =

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1 -n d

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 designation are rarely consistent: 1.

Manufacturers commonly designate layered screens by a single mesh count number. Experimental separation efficiency tests have revealed that these designations are predominantly optimistic.

2.

Oblong mesh screens may be identified by a single number which may be the sum of mesh counts in both the horizontal and vertical direction. For example, a 60 x 40 mesh screen may be labeled “100 mesh”. This practice is misleading: The opening sizes of a 60 x 40 mesh screen will pass much larger particles than a 100 x 100 square mesh screen.

5.2 API RP13E Screen Designation Recently, a new performance-based screen designation system has been developed. This designation system has been adopted by the API RP13E as a Recommended Practice for Shale Shaker Screen Cloth Designations. The API has recommended that all screens be labeled with the following information: Screen Name Separation Potential (d50, d16, d84) Flow Capacity (Conductance, Total Non-Blanked Area) A comprehensive list of screen designations for most shakers is included in Appendix D, Screen Designations. The screen designations include additional information not specified by the API to further define screen performance. Each of the designation components are described in detail below:

5.2.1 Screen Name This is the “mesh count” designation or part number used by the manufacturer to identify the screen. Typically, it consists of a mesh count number preceded by a letter code which may describe the screen's cloth type or layering technique. For example, MG100 signifies a 100 x 100 mesh “market grade” bolting cloth, a PWP HP100 signifies a perforated plate, triple-layer screen composed of oblong mesh screen cloth.

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5.2.2 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 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 equivalent U.S. Sieve Number is a linearly-interpolated value. This value provides a simple scale by which to quickly rank the separation potential of screens. Caution should be exercised when using this value to compare screens of different type since it represents only the median separation potential of the screen.

Table 1 U.S. Sieve Series U.S. Sieve Number

Opening Size Microns

U.S. Sieve Number

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

5.2.3 Separation Potential (d50, d16, d84) The separation potential of the screen is represented by 3 points on the separation potential curve, labeled d16, d50 and d84 (Fig. 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

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of a screen's potential ability to remove solids. They may not necessarily agree with measured grade efficiency cut points for a given application. d50 The d50 is the median aperture size of the screen on a volume-equivalent basis. In experimental grade efficiency terms, it is analogous to the size of solid that has a 50% probability of separation. The d50 is typically used as a single value indicator of separation efficiency performance. Because of it's importance, the d50 is listed first. d16, d84 The d16 and d84 values indicate the range of hole sizes present in the screen. The d16 and d84 values can be important when the removal of fines from an unweighted mud is desired, or when the removal of barite is a concern. The deviation from the d50 describes the screen's implied separation characteristics. As the difference between the d16 and d50 increases, it is more likely that some solids finer than the d50 will likely be removed. Conversely, a smaller percentage of solids coarser than the d50 may be removed as the difference between the d84 and d50 increases. A multilayered screen will generally have a larger spread between the d16 and d84 values than a single mesh screen with the same d50.

5.2.4 Flow Capacity (Conductance, Non-blanked Area) The calculated conductance is reported in units of kilodarcies/millimeter for the total screen composition. Non-blanked area is the total effective screening area per panel, in units of square feet. Note: Support rails on the shaker deck can reduce the usable area of screens not mounted on metal backing plates. This area reduction is not included in the calculation of usable area because it is not a function of screen panel construction and will vary with the shaker type.

5.2.5 Transmittance Transmittance represents the net flow capacity of individual screens. It is the product of conductance and unblocked screening area. Transmittance permits the comparison of individual screens which differ in usable screening area.

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Shaker Screens


5.2.6 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 information about the screen's potential resistance to blinding. Rectangular, or oblong, mesh screens have been customarily employed to reduce the “blinding” problems exhibited by square mesh screens when drilling sand sections. The “near-size” sand grains lodge in the square mesh screen apertures and reduce mud processing capability. The longer slots in the oblong screens are more likely to be only partially blocked by these spherical particles and thus tend to resist blinding. Aspect ratios in excess of 1.5 are typical of oblong mesh screens (both single and multilayered designs) used in the oil field. Single layer square 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 layers. This feature is lost when the layers are bonded together to improve screen life. Laboratory tests have shown that blinding increases substantially when the apertures in the metal backing plate or plastic grid have dimensions of less than 4 x 4 in. Fig. 2 shows how blinding severely restricts the flow capacity of the shaker when smaller opening dimensions in the screen panel are used.

Fig. 2. Effect of plate opening size on screen blinding. Note: Plate openings with dimensions less than 4 x 4 in. lose their deblinding ability. CONFIDENTIAL


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Schlumberger Dowell

Shaker Screens

Page 10 of 11

Some improvement in blinding resistance over single layer square mesh cloth is still apparent in bonded, multilayer square mesh screens: Stacking one screen cloth 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 to be blinded. Aspect ratios of layered square mesh screen compositions range from 1.3 to 1.5. The relationship between screen composition and blinding resistance is summarized in Table 2.

Table 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*

> 1.5

better

Rectangular mesh, all types

* provides “active” deblinding through layer interaction

5.3 Field Procedure to Estimate Cut Point (D50) Note: This procedure provides only a rough approximation of the cutpoint. It assumes that the mass flowrate of the solids discard is negligible compared to the feed and screen unders. Results may be inaccurate under high solids loading.

5.3.1 Equipment ·

U.S. Test Sieves (Enough sizes to bracket expected cut)

·

Sample Containers

·

Sand Content Tube and Funnel

5.3.2 Procedure 1.

Take equal sized samples of both feed and unders. Avoid taking unders samples at the point where the fluid enters the sand trap. Where possible, take them from directly under the screen.

2.

Wet sieve each sample and measure the volume retained on each sieve using sand content tube.

3.

Calculate the percent separated for each test sieve by the following method:

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January 1998

Shaker Screens

%Separated =

Page 11 of 11

Feed Vol. - Unders Vol. x100 Feed Vol.

4.

Plot through the midpoint of each sieve range as a function of volume percent removed.

5.

Read the median cut point (d50).

6 Summary ·

Shaker screens control the separation performance of the shale shaker.

·

Separation performance may be measured by two methods: A.

and

liquid

throughput

Percent-separated or grade efficiency. Generated from full-scale measurements, a grade efficiency curve represents the screen’s probability of separating any specific particle size under the specific conditions of the test. The median separation of the screen, commonly called the “d50” or “cut point,” represents the particle size that has a 50% probability of being removed. A field procedure is provided to estimate the d50 of the shaker screens.

B.

Separation potential. This method uses the range of opening sizes in the screen to indicate the relative separation performance of the screen. Because the screen is visually analyzed, separation potential is independent of operating conditions. This method has been adopted by the API as a Recommended Practice for Shaker Screen Cloth Designations under API RP13E.

·

Liquid throughput performance is represented by the screen’s conductance and usable screening area. Conductance, calculated from the physical dimensions of the screen composition, is analogous to the screen’s permeability. The conductance equations are included in Appendix B, Conductance Calculation. Usable screening area is the area in the screen panel available for fluid flow.

·

Mesh count designations do not adequately describe performance because wire diameters and opening size.

CONFIDENTIAL

screen


Degassers


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

1 Introduction Degassers are necessary to remove entrained gas bubbles from the mud. Gas-cut mud will impair the performance of centrifugal pumps. Since all solids removal equipment beyond the shakers requires a pump, the gas must be removed before it reaches these devices. If left unchecked and pumped downhole, the entrained gas will reduce mud density, which will, in turn, reduce the hydrostatic head in the wellbore. The fundamental principle for all degassers is that gas bubbles must reach the liquid-gas interface before they will burst. Any action which brings these gas bubbles to the surface will result in degassing. Four basic mechanisms exist for bringing gas to the surface: 1) increase the bubble size by drawing a vacuum, 2) create a thin film, 3) create turbulent action, and 4) impart centrifugal force on the mud to drive the gas bubbles to surface. There are two basic types of degassers: atmospheric degassers and vacuum degassers. Tests conducted by Amoco Production Research have shown that vacuum degassers provide superior performance in the presence of 2 higher mud weights and yield points greater than 10 lb/100 ft . Atmospheric degassers are acceptable for unweighted muds with low yield points. The overall ranking of degasser models resulting from experimental data is given in Table 1.

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Schlumberger Dowell

Degassers

Page 2 of 4

Table 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 A complete list of available degassers and their processing capacities are listed in Appendix F, Equipment Specifications.

2 Placement and Operation 1.

Provide enough degasser capacity to treat at least 100% of the circulation rate. Be aware that actual processing rates for gas-cut mud are much lower than claimed rates for water.

2.

Degassers should be located downstream from the shale shakers and upstream of any equipment requiring a centrifugal pump. The degasser suction should be installed downstream of the sand trap. The suction entry should 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 processing of the circulation rate. If equalization is low, the light gas-cut mud entering the suction compartment may not be able to displace the heavier mud returning from the discharge compartment. As a result, the light mud may overflow the suction compartment. Fig. 1 illustrates correct fluid routing for degassers.

CONFIDENTIAL


Degassers


Fig. 1. Correct degasser operation. Note: The high weir helps ensure complete processing of gas cut mud. 4.

Atmospheric degassers should discharge horizontally across the surface of the tank to allow large gas bubbles to break out. Vacuum type degassers should discharge below the mud surface with the flow turned up towards surface.

5.

Vacuum degassers must take power mud suction from their discharge compartment. Power mud is the mud pumped at high velocity through an eductor to create the vacuum in the degasser tank. Taking suction upstream will likely result in the pump becoming gas-locked. Suction from further downstream will likely 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.

3 Summary ·

Degassers are used to remove entrained gas bubbles from the mud to prevent impairment of centrifugal pump performance, a reduction in mud density and a subsequent reduction in hydrostatic head in the wellbore.

·

There are two basic types of degassers: atmospheric and vacuum. Vacuum degassers are recommended for weighted muds and yield 2 points over 10 lb/100 ft . Atmospheric degassers are acceptable for unweighted, low viscosity muds.

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Degassers

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Schlumberger Dowell

·

An overall ranking of degasser models resulting from experimental data is provided in this chapter. Vacuum degassers are generally superior. A comprehensive list of available degassers is listed in Appendix F, Equipment Specifications.

·

Provide enough degasser capacity to process over 100% of the circulating rate.

·

Locate the degasser downstream of the shakers and upstream of any centrifugal pumps.

CONFIDENTIAL


Hydrocyclones


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

9 Summary............................................................................................................................ 16 FIGURES Fig. 1. Fig. 2. Fig. 3. Fig. 4. Fig. 5.

Hydrocyclone operating principles................................................................................3 Cone efficiency. ...........................................................................................................4 Sensitivity to plastic viscosity. ......................................................................................6 Sensitivity to feed head. ...............................................................................................7 Rope flow operation characteristics..............................................................................9

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Hydrocyclones

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Schlumberger Dowell

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

1 Introduction Although the shale shaker is considered the primary solids removal device on the rig, hydrocyclones are a cost-effective method of removing many of the fine solids missed by the shaker in unweighted muds. In some formations, the solids are too fine for the shakers to remove; hydrocyclones must be relied upon to remove the majority of the solids. In these instances, the shaker protects the hydrocyclones from oversize particles which may cause plugging. Because the hydrocyclone has no moving parts, it can be a very reliable piece of solids removal equipment when correctly operated and maintained.

2 Principle of Operation Think of a tornado inside a bottle and you have a rudimentary idea of how a hydrocyclone operates. Fig. 1 illustrates the basic concepts of hydrocyclone operating principles. Mud enters the feed chamber tangentially at a high velocity provided by pump pressure. As the mud spirals downward through the conical section, 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 largest influence on settling. The largest particles will settle preferentially. As the cone narrows, the innermost layers of fluid turn back toward the overflow creating a low pressure vortex in the center of the cone. This low pressure area causes air to be pulled in from the underflow outlet. Correctlyoperating cones should exhibit a slight vacuum at the cone underflow. The air and cleaned fluid then report to the overflow through the vortex finder. The purpose of the vortex finder is to prevent some of the feed mud from “short-circuiting” directly into the overflow. Solids with sufficient mass cannot make the turn back towards the overflow because of their momentum and continue out the underflow. Maximum cone wear usually occurs at or near the underflow exit, where velocities are the highest. In cones 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 too fine to be removed by the cyclone, no liquid should be discharged. “Unbalanced” hydrocyclones will discharge mud without the presence of solids in the mud.

CONFIDENTIAL


Hydrocyclones


Fig. 1. Hydrocyclone operating principles. Note: The dark ribbon indicates the path taken by the mud and solids entering the cone. The smaller light ribbon shows the exit path of the cleaned fluid and fine solids.

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Hydrocyclones

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Schlumberger Dowell

Because fine solids have more specific area (surface area per unit volume) than large particles, the amount of liquid removed per pound of solids is higher with fine solids than with coarse solids. Therefore, the difference between the feed and underflow density is not a reliable indicator of hydrocyclone performance. Fig. 2 shows the relationship between underflow density and cone efficiency for an unweighted mud. Observe how overall cone efficiency decreases as underflow density increases.

Fig. 2. Cone efficiency. Note: Decreasing underflow diameter to improve dryness impairs cone efficiency.

3 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 than 74 microns). Hence the term “desander.” By convention, hydrocyclones with diameters of 6 in. or larger are labeled as desanders. As the benefits of smaller, more efficient hydrocyclones became apparent, the term “desilter” was coined to reflect the smaller “silt-sized” particles these

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January 1998

Hydrocyclones

Page 5 of 16

smaller cones could remove. Hydrocyclones with diameters of less than 5 in. are usually called desilters. However, these terms are not based on any particular performance standard. Separation efficiency varies widely among hydrocyclones classified as desilters. Amoco Production Research has investigated the operational and geometric design factors affecting hydrocyclone performance. Over 500 tests were conducted using bentonite and ground silica slurries. The effect of these variables on cone performance are summarized in Table 1. Selected variables are discussed below.

Table 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

3.1 Cone Diameter Cone diameter is the main factor in determining processing capacity, provided the basic design is sound. Larger cone diameters have higher throughput capacity and generally display inferior separation performance. Individual cone capacity guidelines are listed in Table 2.

Table 2 Cone Capacity Cone Size, inches

Cone Capacity, gpm @ 75 ft head

2

20

3 (Amoco)

50

4

50

5

75

6

100

8

125

10

500

12

500

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Hydrocyclones

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Schlumberger Dowell

3.2 Plastic Viscosity Hydrocyclone performance is extremely sensitive to the plastic viscosity of the feed mud. Fig. 3 shows the effect of plastic viscosity on median separation size (d50) for a constant underflow solids concentration using a 3-in. hydrocyclone. Note how the median separation size increases rapidly with plastic viscosity from an initial 20 micron cut at PV=6 cp to 50 microns at PV=24 cp.

Fig. 3. Sensitivity to plastic viscosity. Note: Hydrocyclone performance declines with increasing plastic viscosity.

3.3 Feed Head Feed head, or feed pressure, affects hydrocyclone performance as shown in Fig. 4. Insufficient head reduces fluid velocity within the cone and adversely affects separation efficiency. Excessive head will cause premature wear and increased maintenance cost.

CONFIDENTIAL


Hydrocyclones


Head is related to pressure and fluid density by the hydrostatic pressure equation: P = 0.052 x H x rmud where P is the feed pressure in psi, 0.052 is a gravitational constant, H is the head in ft, and rmud is the fluid density in lb/gal. Since most hydrocyclones require 75 ft of head, the required pressure for a given mud density can be approximated by: P = 4 x rmud Specific head requirements for most hydrocyclones are provided in Appendix F, Equipment Specifications. A centrifugal pump is used to feed the hydrocyclones because it provides a relatively constant head at a given flow rate. However, correct sizing of the pump is critical to ensure that sufficient head is available at the desired flow rate. Refer to the section on centrifugal pumps for a more detailed discussion on sizing and selecting centrifugal pumps for this application.

Fig. 4. Sensitivity to feed head. Note: This example, for a 3-in. cone, illustrates the importance of maintaining sufficient feed head. CONFIDENTIAL



Hydrocyclones

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Schlumberger Dowell

3.4 Underflow Diameter As underflow diameter is reduced, fewer solids will have sufficient mass (and momentum) to be discharged. The discharge will be dryer at the expense of separation efficiency. The appearance of the discharge gives a good indication of cone performance.

3.4.1 Spray Discharge A normally-operating cone should have an umbrella-shaped discharge of liquid and solids. The solids spiraling downward and out the cone bottom with their associated liquid are said to be in “spray discharge.” The inside stream moving up toward the overflow at high velocity will pull air with it in the vortex. This causes a slight vacuum to occur in the very center of the cone. The air is replaced by air drawn up through the center of the underflow opening as shown in Fig. 1. Therefore, the presence of spray discharge and a slight vacuum in the center of the underflow opening is a good indication of a properly operating hydrocyclone.

3.4.2 Rope Discharge If the solids concentration is high, there may not be room for all of the downward moving solids to exit the underflow. This causes an undesirable condition known as “rope discharge‚” so-called because of the shape of the underflow stream (Fig. 5). In rope flow, the solids back up near the exit and decelerate. The underflow density is very high, since the liquid volume is severely reduced and only the largest particles will exit the cone. Exit velocities are low; the solids will appear to be falling out of the underflow nozzle. Many of the solids will not be able to exit the cone and will return with the liquid in the overflow. High cone wear will occur in the lower region of the cone. Corrective action consists of opening up the underflow and making sure the opening is clear. If the problem still occurs, this is an indication that the solids loading needs to be reduced by adding more hydrocyclones. If the problem is with the desilter, ensure that the desander is operating and that the shakers are running the finest screens possible.

CONFIDENTIAL


Hydrocyclones


Fig. 5. Rope flow operation characteristics. Note: This condition should be avoided; try increasing the underflow opening size. CONFIDENTIAL



Hydrocyclones

Page 10 of 16

Schlumberger Dowell

4 Desanders With the improved fine screening capability of shale shakers, the need for desanders has diminished. The primary role of the desander should be to reduce solids loading to the desilter cones in unweighted water-based muds. Desanders are recommended 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 or faster. Considering that 75 microns is probably the best performance that can be expected from a desander cone, one might conclude they would have an application in weighted muds as well. This is generally not the case. Hydrocyclones separate solids based on their mass and the density difference between the solid particles and the fluid. Since barite's specific gravity is substantially higher than drilled solids, it will tend to be preferentially removed by hydrocyclones. Also, as shown in Fig. 3, the higher plastic viscosities normally associated with weighted muds will greatly reduce the desander's efficiency. Desander underflows are normally quite dry and abrasive and should be discarded directly. When processing expensive muds, the underflow may be routed to a centrifuge to recover the liquid, provided the solids are not abrasive and the underflow is diluted with whole mud before centrifuging. Another option is to screen the desander underflow down to 200 mesh (74 microns) to remove the larger, abrasive solids before processing with the centrifuge.

4.1 Recommended Desanders Ten-inch diameter desander cones are recommended. They provide the best combination of separation and capacity. The larger 12-in. cones usually cannot make a fine enough cut to be economic. Smaller cones are limited in flowrate and may deteriorate more quickly in abrasive conditions.

5 Desilters Desilters should be used on all unweighted, water-based muds. They are not recommended for use on weighted muds since barite will be lost. When using expensive muds, process the desilter underflow with a centrifuge. APR has developed a 3-in. hydrocyclone which is up to 50% more efficient than some existing oilfield desilters. Fig. 6 shows the improvement in performance over a typical 50 gpm, 4-in. cone. The Amoco-designed, 3-in. cone is not a balanced cone; it will discharge fluid even when no solids are present. In many cases, this cone's underflow should be processed by a centrifuge. The economics of centrifuging the underflow should be checked using the SECOP program. Estimated discard rates per cone are plotted as a function of underflow diameter in Fig. 7. Size

CONFIDENTIAL


Hydrocyclones


the centrifuge for the calculated underflow rate. Run the cones intermittently on unweighted mud when no centrifuge is available.

Fig. 6. “Amoco” near optimum core efficiency. Note: The 50 gpm Amoco-designed 3-in. cone exhibits greatly improved performance over a typical 4-in. cone at the same flowrate.

Fig. 7. Estimated discard rates. Note: Use this chart to estimate underflow rates from the Amoco-designed 3-in. cone. CONFIDENTIAL



Hydrocyclones

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Schlumberger Dowell

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 finescreened or run an efficient, properly installed desander ahead of the 3-in. cones. Desilters can also be used in certain weighted mud applications to reduce the barite loading to the centrifuge thereby improving its efficiency in barite recovery mode (see Chapter 8, Centrifuges). Here, the underflow of the desilter cones are returned to the active system and the overflow is fed to the Barite Recovery centrifuge. The upper limit for this application is generally limited to mud densities of 15 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 available to prevent plugging or rope flow.

5.1.1 Recommended Desilters MPE 3 in. (15° Cone) MPE 3 in. (10° Cone) These Amoco-designed cones are recommended because of their superior performance. They will provide the separation performance of a 2-in. cone at the flowrate of a typical 4-in. cone.

6 Sizing Hydrocyclone Manifolds For properly routed hydrocyclones, the minimum number required can be estimated by: No. of Cones Required =

Maximum Circulation Rate x 1.1 Single Cone Flow Rate

This equation does not consider solids loading. If penetration rates in excess of 100 ft/hr are anticipated, the number of cones should be increased. Specific head requirements and flow capacities for each cone are listed in Appendix F, Equipment Specifications. Table 2 may be used to estimate the flow capacity of each cone operating at 75 ft of head. Hydrocyclones are normally provided in banks of 8, 10, 12 and 16 cones per manifold (Fig. 8). Increase the required number of cones to one of these standard manifold sizes.

CONFIDENTIAL


Hydrocyclones


Fig. 8. Typical hydrocyclone manifold. Note: This is an “inline” manifold. Circular manifolds are also common.

7 Operating Guidelines 1.

Operate enough hydrocyclones to process over 100% of the circulation rate or to handle the maximum solids loading rate.

2.

The hydrocyclone overflow should be discharged to a compartment downstream from the feed compartment. Use bottom equalization between compartments.

CONFIDENTIAL



Hydrocyclones

Schlumberger Dowell

3.

Mechanically stir all hydrocyclone removal and discharge compartments to ensure uniform feed. Mud guns should not be used because they can reduce hydrocyclone 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 premature wear and is less efficient. Rope flow indicates that either more hydrocyclones or finer shaker screens are required or that the underflow apex size is too small.

6.

Because 2-in. cones are extremely susceptible to plugging, consider using the 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 the active system to prevent accidental loss of mud by siphoning when the cones are not operating.

9.

Replace flanged-type hydrocyclones with the quick-connect type to improve servicing 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 of 5-10 ft/sec. Refer to Chapter 9, Centrifugal Pumps & Piping. 14. Use one centrifugal pump per hydrocyclone manifold.

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January 1998

Hydrocyclones

Page 15 of 16

8 Troubleshooting Symptoms

Probable Causes

One or more cones are discharging - others OK.

not

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 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 varying feed head.

Air or gas in feed, too small feed lines, air from upstream equipment discharge.

is

unsteady,

opening,

bypassed

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.

Cones are discharging a heavy, slow-moving stream.

Cones are overloaded - use larger apex size, insufficient 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 hydrocyclone overflow return.

of

Viscous mud, return line ends above fluid level in tank - route hydrocyclone overflow into trough to allow air to break out.

CONFIDENTIAL



Hydrocyclones

Schlumberger Dowell

9 Summary ·

Hydrocyclones separate solids from fluid by using centrifugal force to cause solids to be settled from the fluid. There are no moving parts. Centrifugal force is created by the conversion of centrifugal pump head into a high velocity stream spiraling within the cone. Solids concentrate in proportion to their mass near the wall of the cone and are discharged at the bottom of the cone in the underflow. Clean fluid and fine solids are returned through the top of the cone in the overflow.

·

Cone diameter, cone angle, underflow diameter, feed head, and plastic viscosity have the largest effect on hydrocyclone performance.

·

Hydrocyclones will produce a relatively wet discharge compared to shale shakers and centrifuges. Underflow density is not a good indicator of cone performance. Finer solids will have more associated liquid and the resultant density will be lower than with coarse solids.

·

Provide enough hydrocyclones to process at least 110% of the circulation rate, more if high penetration rates are expected.

·

Use desanders in unweighted mud when the shakers are unable to screen down to 140 mesh (100 microns). The role of the desander is to reduce solids loading to the downstream desilter. Ten inch diameter desander cones are recommended; they provide the best combination of separation and flow capacity.

·

Use desilters on all unweighted, water-based muds. The recommended Amoco-designed 3-in. cone is up to 50% more efficient than typical 4-in. cones. This cone is an unbalanced design and will discharge a very wet underflow. Process the underflow with a centrifuge to recover fluid, if the economics warrant.

·

Installation and operating guidelines, along with a troubleshooting guide are included in this chapter.

CONFIDENTIAL


Mud Cleaners


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

1 Introduction A mud cleaner is a bank of hydrocyclones mounted over a vibrating screen (Fig. 1). Free liquid and particles smaller than the screen openings are returned to the circulating system. Solids removed by the screen are discarded. Screen sizes between 100 mesh and 325 mesh are commonly available. Mud cleaners were originally developed for use in weighted muds to remove drilled solids down to the size of barite (< 74 microns) when shakers could only run 100 mesh (149 microns) screens at best. However, with the fine-screening capability of today’s linear motion shakers, the applications for mud cleaners are limited.

CONFIDENTIAL



Mud Cleaners

Schlumberger Dowell

Fig. 1. Mudcleaner combines hydrocyclone and shale shaker. Note: The hydrocyclone underflow is screened to remove solids. Where possible, the installation of sufficient fine screen shakers is recommended for weighted muds in lieu of a mud cleaner. Shakers equipped with fine-mesh screens guarantee that all of the circulation rate is processed, whereas mud cleaners may treat only a portion of the circulation rate. Shakers are more dependable and their screens typically last longer. Barite losses measured over mud cleaner screens are higher than losses over shaker screens at the same mesh size. This is due to the high viscosity of the cone underflow and the relatively small screening area of most mud cleaners. Drexel-Brandt and Derrick, among others, have addressed this by mounting desilter cones over a full-size shaker deck (Fig. 2). Derrick uses a specially-designed “High-G” shaker which they claim also improves cuttings dryness. Regardless, overall system efficiency would be better served by an additional shaker at the flowline rather than a mud cleaner in most cases.

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Mud Cleaners


Fig. 2. Brandt ATL 2800 mud cleaner. Note: This design mounts 28 4-in. cones over a standard ATL shaker basket. Mud cleaners continue to be a popular solids removal device within the industry and will be encountered on many rigs. If economics or space constraints do not justify the installation of additional shakers on an existing solids removal system, the mud cleaner, when routed and operated correctly, can be used to advantage in both unweighted and weighted muds. Refer to the system arrangements section for proper fluid routing and mud cleaner placement.

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Mud Cleaners

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Schlumberger Dowell

2 Operating Guidelines 1.

Since the mud cleaner is both a hydrocyclone and a shaker, many of the operating guidelines listed for these devices apply to mud cleaners.

2.

A decrease in solids coming off the screen may indicate a torn screen which should be replaced as soon as possible.

3.

Plugged cones or large solids coming off the screen can imply a problem with the upstream shale shakers. The likely causes are bypassed screens, torn screens 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.

2.1 Unweighted Muds 1.

In unweighted muds, the mud cleaner should be used as a desilter by blanking off the screen and discharging the underflow directly.

2.

Because the mud cleaner is operated as a desilter, it must be run in parallel with other desilters (same suction and discharge compartments). As with desilters, the suction should be from the desander discharge compartment and the overflow discharged to a downstream compartment.

3.

If the hydrocyclone underflow is to be processed by a centrifuge, the screens may be used to reduce solids loading to the centrifuge. Run the finest screens possible.

4.

In closed-loop systems, route the desander’s underflow onto the mud cleaner screens to help dry the discharge. Note, however, that the mud passing through the screen should be processed by a centrifuge.

5.

The hydrocyclones on the mud cleaner should be run as wet as possible to improve solids removal efficiency.

2.2 Weighted Muds 1.

Use the mud cleaners when 150 mesh (100 micron) screens cannot be run on the shale shakers.

2.

At higher mud weights, the screen may become overloaded with solids. If the screen overloads, remove enough cones to keep it from discharging excess fluid.

3.

Monitor the composition and rate of losses over the screens, especially in oil-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 may reduce barite losses by reducing the viscosity of the hydrocyclone

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Mud Cleaners


underflow. However, the amount of drilled solids discarded may also be reduced.

3 Summary ·

A mud cleaner is a desilter mounted over a vibrating screen. The desilter underflow is screened. Fluid and solids finer than the screen are returned to the active system. Only solids coarser than the screen openings are removed.

·

Mud cleaners were originally designed for use in weighted muds when shakers were incapable of screening down to the size of the weighting material. With today’s fine screen shakers, the applications for mud cleaners are limited.

·

Fine screen shakers are recommended in lieu of mud cleaners: Screen life is better, all of the circulation rate is processed, and barite losses are reported to be lower.

·

In unweighted mud, the mud cleaner should be used as a desilter. Screening the underflow is unnecessary unless the mud cleaner is used to screen abrasive 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.

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Decanting Centrifuges


Decanting Centrifuges 1 Introduction .........................................................................................................................2


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

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

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

1 Introduction Since their introduction to the oilfield in the early 1950s, decanting centrifuges have become an increasingly common addition to the solids control system. Centrifuges are capable of removing very fine solids that cannot be removed by any other mechanical separation device. In unweighted muds, the centrifuge can greatly improve the separation efficiency of the solids removal system and reduce liquid discharge volumes when used in conjunction with hydrocyclones. Increasingly stringent environmental restrictions on drilling waste discharge and the incentive of reduced dilution and disposal volumes have made the use of centrifuges economically attractive in many instances. In weighted muds, the centrifuge is used to reclaim barite while removing colloidal solids which can cause high mud viscosity, poor filtercake properties, and decreased penetration rates. The centrifuge is the primary separation device used in a chemicallyenhanced dewatering system to reduce liquid discharge volumes. Unlike other solids removal devices, decanting centrifuges are usually leased from service companies. Very few rigs come equipped with centrifuges because they are relatively expensive to purchase and require specialized

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maintenance. A typical oilfield-ready centrifuge may cost $80-$150 thousand, depending upon size, performance and design features. Lease rates range from $150 to $300 per day. It is therefore important to understand the factors affecting centrifuge performance to economically justify the specific application and to achieve maximum performance.

2 Principle of Operation The major components of a decanting centrifuge are shown in Fig. 1. Decanting centrifuges separate solids from liquid by imparting high centrifugal forces on the solid-liquid slurry fed into a bowl rotating at high speed. The feed stream is pumped into the center of the bowl via a feed tube. The slurry exits the feed tube and enters an acceleration chamber housed inside the conveyor. It exits the chamber through feed ports and enters the bowl area. Here, the slurry is exposed to a high G-force created by the bowl’s rotation. The high G-force causes sedimentation of the feed stream solids. The rotating conveyor has flights similar to threads on a screw which auger the settled solids up the conical section of the bowl and out of the liquid pool. The gear box causes the conveyor to rotate at a slightly slower speed than the bowl. The torque needed to turn the conveyor is carried through the gear box and emerges at a shaft. This shaft is held by a shear pin or other safety device so that excess torque will not be applied to the gearbox or conveyor. The relatively dry solids continue out of the bowl. The cleaned liquid is “decanted” off through ports at the opposite end (Fig. 2).

Fig. 1. Centrifuge components. Note: These components are common to most decanting centrifuges used in oilfield applications.

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Fig. 2. Centrifuge operation. Note: The conveyor augers solids up the conical section of the bowl and out of the liquid pool.

3 Performance Parameters The effect of various design and feed parameters on centrifuge performance have been evaluated by APR. The results of this study are summarized to assist in the selection and operation of centrifuges. Since many centrifuge parameters are related, one aspect of performance cannot be discussed singularly without implicating others. However, in general, centrifuge performance is affected by the following parameters in decreasing order of importance:

3.1 G-Force According to Stokes’ Law, particle settling velocity is proportional to G-force: 2 aDp

(ρs

VT =

 -6  - ρL ) 10  116µ

where: VT

=

Particle terminal velocity, in./sec

a

=

Bowl acceleration, in./sec 2 RPM 2 (1 g = 386 in./sec )

Dp

=

Particle diameter, microns

ρS

=

Solids Density, gm/cm

3

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2

= .0054812 x bowl Diameter x


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ρL

=

Feed Slurry Density, gm/cm

m

=

Feed Slurry Viscosity, (centipoise = gm/100 cm sec)

3

Since G-force increases with the square of bowl RPM, it is an important parameter. G-force also increases linearly with bowl diameter. Fig. 3 shows how solids removal efficiency improves with increasing G-force. For a given particle size and 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 bowl rpm and there are similar economic limitations on bowl diameter as well. Thus, the required G-force must be obtained from a practical combination of speed and diameter. Most oilfield centrifuges have bowl dimensions from 14 to 28 in. in diameter and lengths from 30 to 55 in. Rotational speeds range from 1000 rpm to 4000 rpm, depending on the application. The more expensive, “high-G” machines can provide up to 3,000 G’s. The specifications for each centrifuge are listed in Appendix F, Equipment Specifications.

Fig. 3. Effect of G-force on separation. Note: Higher G’s improve separation performance. Note, however, that increasing G-force eventually reduces solids conveyance capacity due to torque limitations. As G-forces increase, more solids are settled in the bowl and they adhere more tightly. More conveyor torque is required to move the solids out. Once the torque limitations of the machine are reached, conveyance ceases.

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3.2 Viscosity From Stokes’ Law, particle settling velocity is inversely proportional to fluid viscosity. Fig. 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 also helps explain the relatively poor performance of centrifuges when processing polymer fluids with characteristically high viscosities at low shear rates.

Fig. 4. Effect of viscosity on separation performance. Note: Higher yield values degrade centrifuge separation performance.

3.3 Cake Dryness Discharge dryness is commonly considered a direct indication of centrifuge performance. However, test results have shown that cake dryness is more correctly a function of particle size and, therefore, is inversely related to separation efficiency. Test points which yielded the driest solids corresponded to the lowest efficiency and coarsest D50 separation. As shown in Fig. 5, solids dryness occurs at a threshold G-force level. Subsequent increases in G-force do not remove additional liquid. Length of the dry beach within the centrifuge bowl (a function of pond depth) also has little effect on dryness. Dry beach length refers to the distance from the solids discharge ports to the surface of the fluid pond within the centrifuge bowl. But, the small difference in dryness made a significant difference in the appearance of the solids. At 71% by weight, the solids were quite runny and at 76% by weight, the solids seemed much more “stackable.”

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Fig. 5. Effect of G-force on cuttings dryness. Note: Above a certain threshold G-force, cuttings dryness does not improve.

3.4 Pond Depth and Processing Capacity Pond depth controls both fluid residence time and dry beach length. Test data confirms that increased pond depth residence time increases separation. However, increased pond depth reduces centrifuge flow capacity. Maximum flow capacity is controlled by the height of the cake discharge port. When the fluid depth in the centrifuge bowl reaches this height, drilling fluid flows out along with the discarded cake. The flowrate at which liquid spills out the cake discharge port is called the “flood-out” point. Since one objective of centrifuging is to limit liquid waste, it is obviously not advantageous to run the centrifuge at a flow rate beyond the flood-out point. Flooding is controlled by a combination of pond depth and flowrate. The pond depth is set mechanically by an adjustable weir. The flowrate increases pond height according to the viscous drag forces which increase the fluid head required to drive the liquid through the centrifuge. The head height is added to the fixed pond depth to give a total depth of fluid in the bowl. For example, consider a centrifuge 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 adjusted to 2 in., then only 1 in. of fluid head is available before the 3-in. flood-out point is reached. Obviously,

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Schlumberger Dowell

the maximum flowrate for this pond depth setting will have to be much less than 300 gpm. Maximum flow capacity is achieved when the shallowest pond depth is used at the expense of separation efficiency. Conversely, deep ponds maximize separation efficiency at the cost of flowrate capacity. The best combination is determined by the coarseness of the solids to be separated. Fig. 6 illustrates how, for a fine solids size distribution, a deep pond depth at lower flow rates can produce almost the same cake rate as a shallow pond depth at higher flow rates. This is due to the improved separation efficiency of the deep pond case. Fig. 7 shows how, for coarse solids, the higher flow capacity of the shallow pond produces more solids removal than the deep pond case. The results suggest that, for coarse particle size distributions as encountered in top hole drilling, shallow pond depths are advantageous, whereas deep ponds should be used for all other applications.

Fig. 6. Effect of pond depth on fine solids removal. Note: Deeper ponds are more efficient than shallow ponds when the solids are very fine.

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Fig. 7. Effect of pond depth on coarse solids removal. Note: Shallow pond depths are preferred for coarse solids distributions.

3.5 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 to the conveyor. Differential RPM is simply calculated by dividing the bowl RPM by the gearbox ratio. Many centrifuge manufacturers provide a “backdrive” which can independently alter the DRPM. Backdrive units are, in effect, hydraulic gear reduction systems used to vary the speed of the conveyor relative to the bowl. On “backdrive” units, DRPM depends upon the rotation of the gearbox pinion and the orientation of the flights on the conveyor. For these units, DRPM may be calculated by:

DRPM = (Bowl RPM - Pinion Speed)/Gearbox ratio. DRPM is important because it determines the velocity at which solids are conveyed through the centrifuge. For example, a DRPM of 50 and a flight pitch of 3-in. yields a conveyance velocity of 150 in./min. Another expression takes the flight pitch and number of leads on the conveyor into account to describe the surface area of the bowl swept by the conveyor flights per unit time. The faster the rate at which the area is swept, the greater the solids capacity. As = 2p rcyl x DRPM x SN

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where: As

=

swept area/unit time

rcyl

=

cylindrical bowl radius

S

=

flight pitch

N

=

number of leads on the conveyor

This equation suggests that solids capacity can be increased by increasing the DRPM (lowering the gearbox ratio). Low swept area values could indicate potential torque problems. For example, centrifuges with 130:1 or higher gearbox ratios and centrifuges with 80:1 gearbox ratios with single-lead conveyors may be limited in flowrate by torque. Test data indicates that increasing DRPM reduces torque. Also, torque increases as feed median particle size increases. Despite the common belief that high DRPM values agitate the pond and inhibit sedimentation, test results indicate that the effect of DRPM on solids removal efficiency is slight, provided sufficient differential exists to remove the solids.

4 Centrifuging Unweighted Mud Centrifuging unweighted muds provides two major benefits: 1) The removal of drilled 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 into these submicron particles. As a rule, at least 25% of the circulating rate should be centrifuged. It is usually uneconomic (and logistically unfeasible) to process the entire circulating rate. Regardless, the benefits of centrifuging to remove fine solids cannot be understated. High-G, high capacity centrifuges are recommended to maximize separation performance. Refer to the discussion on centrifuge selection, appearing later in this chapter. Since separation efficiency varies inversely with feed rate and residence time, the optimum feed rate is not necessarily the highest possible rate. Rather, it is the combination of pond depth and feed rate that produces the highest solids discharge rate. The maximum efficient processing rate for a large oilfield centrifuge will seldom exceed 250 gpm, even for relatively coarse drilled solids and low fluid viscosities. If the particle size distribution is very fine, more solids may be removed with a lower feed rate and deeper pond depths.

4.1 Centrifuging Hydrocyclone Underflow When liquid discharge must be strictly controlled due to high mud cost, high liquid disposal cost or limited reserve pit capacity, the centrifuge should process the underflow of the desilter cones. In this configuration, the hydrocyclones are used to concentrate solids to the centrifuge which then separates the drill cuttings from the free liquid and colloidal solids. System

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performance can be improved by opening the cone apexes to discharge more liquid. This improves the separation efficiency of the cones and produces a less viscous slurry at the underflow. Fig. 8 gives an example of how centrifuging desilter underflow becomes economic with increasing mud cost and desilter underflow rates. Enough centrifuge capacity must be available to process slightly more than the cone underflow rate. Additional makeup volume should be provided from the active system downstream of the hydrocyclone feed. Because the hydrocyclone underflow must be segregated from the active system, a separate centrifuge feed compartment is required. Fig. 9 and Fig. 10 illustrate two designs for the centrifuge feed compartment. The compartment should be small (<50 bbls) to prevent solids settling. Both high and low equalization should be provided. The low equalizer supplies makeup volume from the active system during normal processing. A valve (normally open) should be installed on the low equalizer. This valve may be used to check that the centrifuge feed rate exceeds the cone underflow rate. If the centrifuge is to be used in weighted mud to process the centrate of the barite recovery centrifuge, the valve should be closed to isolate the feed compartment. The high equalizer is provided to prevent accidental overflow.

Fig. 8. Economics of centrifuging hydrocyclone underflow. Note: Substantial savings are possible by recovering the liquid from cone underflows.

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Schlumberger Dowell

Fig. 9. Fluid routing to centrifuge hydrocyclone underflows. Note: The disilter underflow is segregated from the active system for processing by the centrifuge.

Fig. 10. Internal centrifuge feed compartment design. Note: The dense desilter underflow will displace the lighter active system mud from the centrifuge feed compartment. CONFIDENTIAL




4.2 Operating Guidelines, Centrifuging Unweighted Mud 1.

When processing the active system, the centrifuge feed should be taken from the desilter discharge compartment or downstream. The centrate should be returned to next downstream compartment.

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 the drilled solids. Use shallow ponds and high feed rates when coarse solids predominate. Conversely, deeper ponds and lower feed rates are more efficient when fine drilled solids are to be removed. Field experimentation is necessary to 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 to allow either option. Both the centrate and solids streams should be rigged up to allow each to be discarded or returned to the active system.

8.

The solids discharge chute should be angled at greater than 45° to prevent solids buildup. If this is not possible, a wash line may be necessary to assist in moving the solids. On land-based operations, use the reserve pit as a source for wash fluid. Do not create unnecessary reserve pit volume by using rig water.

5 Centrifuging Weighted Muds The centrifuge is used in weighted mud applications to recover valuable weighting material from mud which must be discharged due to unacceptable colloidal solids content. The centrifuge settles out barite and coarse drilled solids which are returned to the active mud system to maintain density. The relatively clean centrate containing liquid and colloidal solids is discarded. These colloidal solids cause many drilling fluid problems, such as high surge/swab pressures and ECDs, differential sticking, and high chemical costs. Usually, the value of the weighting agent in these mud systems makes it economic to recover the weighting agent from the whole mud before it is discarded. Fig. 11 gives an example of the economics of centrifuging weighted muds.

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Schlumberger Dowell

Fig. 11. Choice of drilled solids removal from weighted mud. Note: This example shows the economic advantage of recovering barite. Ideally, the barite recovery process should remove only colloidal solids without losing the larger particle sizes used as weighting material. Discarding potentially reusable barite increases barite use and drilling fluid cost. Barite losses can be reduced when the centrifuge makes the maximum liquid/solids separation. As discussed in the previous section, this means operating the centrifuge at high G-force. Fig. 12 shows the effect of G-force on the amount of barite discarded in the centrate. At 20 gpm, the difference in barite losses is 4.58 lb/min. Based on 10 hours per day centrifuging and barite cost of $6.50 per 100 lb, high G-force centrifuging should save $175 per day. Centrifuges are usually torque-limited in weighted muds due to the high solids content. Typically, torque is reduced by slowing bowl RPM. This reduces G-force and DRPM, resulting in less effective liquid/solids separation and the likelihood of increased torque from reduced solids conveyance.

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Fig. 12. Benefits of increased G-force on barite recovery. Note: Less barite is lost in the centrifuge centrate with increased G-force.

5.1 Operating Guidelines, Barite Recovery Mode 1.

The following procedures are recommended to reduce torque when operating centrifuges in barite recovery mode to maximize liquid/solids separation: A.

For a given flowrate, increase the pond depth until the recovered solids become “runny.” Buoyant force reduces the torque needed to convey solids out of the centrifuge. A shallow pond creates a long beach section. Once the solids exit the pool, the extra energy required to convey these solids results in higher torque.

B.

Process weighted mud continuously at a reduced feed rate rather than intermittently at higher feed rates. This reduces solids loads and results in less torque. It also increases residence time which will result in finer separation.

C.

At higher mud weights, use hydrocyclones to reduce the solids loading in the feed mud to the centrifuge. The cone underflow is returned to the active system. The overflow, containing fewer solids, is fed to the centrifuge. Since solids concentration is reduced, torque from conveying settled solids is reduced and permits higher G-force centrifuging.

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2.

Provide sufficient centrifuge capacity to process 5-15% of the rig circulation rate. Centrifuge capacity is reduced in weighted mud; the 25% target recommended 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 the mud viscosity and improve centrifuge separation performance.

4.

Return the solids to a well-agitated compartment upstream of the suction and mixing tanks.

5.

Use a high weir between the barite return compartment and the next downstream compartment to keep the fluid level high. This will promote better mixing.

6.

Always wash out the centrifuge on shutdown.

7.

Routinely check the centrifuge performance by measuring the flow rate and solids composition of the cake and centrate.

6 Two-Stage Centrifuging Two-stage centrifuging is used in weighted muds when the liquid phase cannot be discarded for economic or environmental reasons. The most frequent application is in weighted, oil-based muds where the expensive liquid phase cannot be discarded. The first centrifuge recovers weighting material from the weighted mud as discussed in the previous section on single-stage centrifuging for barite recovery. The centrate, instead of being discarded, is fed to a second centrifuge operating at higher G-force. This centrifuge is used to discard the solids and return the cleaned liquid phase into the active mud system (Fig. 13).

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Fig. 13. Two stage centrifuging. Note: The first centrifuging recovers barite; the second centrifuge dries its centrate and recovers valuable fluid. For two-stage centrifuging to be efficient, the first centrifuge must make a good separation since most of the solids in its centrate will be discarded. The poorer the separation, the more barite which will be carried over in the centrate and discarded by the second centrifuge. Similarly, the second centrifuge must operate at the highest possible G-force to remove the most solids. Pond depths should also be 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 economics. Field experience has been mixed on the costeffectiveness. 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 this concentration, centrifuging to strip all solids including barite may be more economical, especially at lower mud weights. At intermediate mud weights, “dump and dilute” may be a viable option depending upon the conditions of the buy-back agreement. “Dump and dilute” in this case means transferring mud laden with low gravity solids from the active system to storage tanks for return to the mud company. 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 possible to maintain mud properties. The decision to employ this alternative should be made judiciously. It is usually better to err on the side of caution. Over time, low gravity solids will become a large percentage of the weighting

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material. Filtercake thickness, mud viscosity, and material consumption also may increase. However, this may be the least expensive alternative when drilling time is short and hole sizes are small. Oil-based muds are quite “solids-tolerant” and can withstand some buildup of low-gravity solids. This option is not generally recommended for water-based fluids.

6.1 Field Evaluation of Two-Stage Centrifuging Economics An evaluation of two-stage centrifuging economics can be made in the field. This method computes the total centrifuging cost (including rental cost and the value of the mud and barite discarded). This cost is compared to the value of the whole mud that must be discarded to remove an equivalent amount of low gravity solids. The following data is required: Active System

Centrifuge Discard

Costs

Mud Density, rm (ppg) Barite Concentration, HGS (lb/bbl)* Low Gravity Solids Concentration, LGS (lb/bbl)* Sludge Density, rdis (ppg) Operating Time, t (hrs) Centrifuge Discard Rate, Qcen (lb/hr)* Barite Concentration, HGSdis (lb/bbl)* Low Gravity Solids Concentration, LGSdis (lb/bbl) Barite Unit Cost, Cb ($/sack) Liquid Mud Cost, Clm ($/bbl) Centrifuge Rental Cost, Ccen ($/day)

*Barite and Low Gravity Solids concentrations in lb/bbl of whole mud are determined from retort analysis and must be corrected for salt content.

6.1.1 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

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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))


* Disposal/treatment cost of the centrifuge discard should be added to the Total 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 be subtracted from the daily disposal cost.

7 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.

Since centrifuges are normally leased, quality of service in the local area should be a primary consideration when selecting centrifuges. A centrifuge

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with all the features listed above will not be much use if it cannot be kept running because of poor maintenance. Contract length should also be considered. For example, hard-facing on the conveyor instead of tungsten carbide tiles, or a carbon steel bowl instead of stainless steel is entirely acceptable if the centrifuge is to be leased for a short term and maintenance costs are borne by the contractor. Conversely, when drilling in remote areas or under harsh conditions, the features listed above will help ensure continued trouble-free operation. Regardless, a full inspection should be performed before the centrifuge is accepted for lease. The coarseness of the solids can also influence centrifuge selection. As shown in Fig. 14, when the solids distribution is fine, a small “high G” machine such as the Sharples 14 x 30 may remove more solids at a lower feed rate than a large bowl, “low G” machine such as the Bird 24 x 38. Conversely, the larger bowl machine will provide superior performance when the solids are coarse (Fig. 15).

Fig. 14. Centrifuge performance comparison on fine solids distribution. Note: The smaller 14 x 30 “High G” centrifuge is more efficient when solids are fine.

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Fig. 15. Centrifuge performance comparison on coarse solids distribution. Note: The high flow capacity of larger “Low G” machines is preferred in the presence of coarse solids.

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Table 1 and Table 2 contain recommended common oilfield centrifuges. Table 1 lists centrifuges recommended for unweighted mud applications. Table 2 lists centrifuges recommended for weighted mud applications. These tables are provided as a guideline only. Centrifuges not listed in these tables may provide equivalent performance provided the performance criteria discussed previously are met. For example, Sharples builds larger centrifuges than the P3400. These larger centrifuges will provide superior performance, but very few are available for drilling application and are not listed here.

Table 1 Recommended Centrifuges for Unweighted Mud Centrifuge

Bowl Size

Maximum 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

Table 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.

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7.1 Equipment Descriptions 7.1.1 Hutcheson-Hayes HH5500 (16 X 55) This machine has all of the recommended features including a high capacity gearbox to minimize gearbox failure. In most applications, it has more flow capacity and separating power than the other centrifuges listed. The 5500 can be run at 3250 RPM in unweighted muds and approximately 2600 RPM in weighted fluids. A variable speed controller on the main drive is recommended for dual purpose applications. Because it is a relatively new product, few HH5500s are currently available as rental units.

7.1.2 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 have more separating power than the slower Swaco unit. Plate type pond dams require total replacement for adjusting pond depth. Adjustment for three differential RPMs is provided. The flight spacing and 60:1 gearbox ratio give reasonable performance. The 418 and 518 are not recommended for barite recovery; the long bowl length is prone to developing high torque in weighted muds.

7.1.3 Derrick DE1000/Sharples P3400/Brandt HS3400 (14 X 50) These Sharples-designed centrifuges have most of the desired design features and will provide superior performance in unweighted muds. Recently, Sharples was bought out by Alfa-Laval, who reportedly will discontinue production of the Sharples P3400 and P3000 in favor of their own 418 and 414 models. The long bowl is susceptible to developing high torque in weighted muds and is not normally recommended for barite recovery. Derrick now manufactures this design with some mechanical improvements, fully-tiled conveyor flights, and the option of variable main and back drives. With the variable drive, Derrick has been successful in using this machine as a barite-recovery unit.

7.1.4 Oiltools S3.0 (21 X 62), S2.1 (18 X 56) These centrifuges are manufactured by Humbolt-Wedag in Germany under a Bird Machine Co. license. Both can provide reasonably good separation performance provided they are operated at maximum RPM in unweighted muds. Both units are fully hydraulic which helps prevent solids overloading and bowl plugging in barite recovery mode. The S2.1 is normally supplied as the barite recovery centrifuge. The quality of local service is an important consideration for these centrifuges as with all hydraulic units.

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Schlumberger Dowell

7.1.5 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 the basic design have been made in accordance to the specific company’s design concepts. Both Sweco and Broadbent build their machines in-house. Brandt purchases the centrifuge rotating assembly and “skids it out” inhouse. These machines will have suitable separation performance above 1900 RPM. All except the Brandt have x-rayed welds to certify operation at this higher RPM. The Derrick machine has a longer bowl (24 x 45 in.) and will perform best in unweighted muds. Gearbox ratio and conveyor flight design vary significantly. The Sweco and Broadbent machines have 60:1 gearbox ratios and double-lead conveyors that provide good performance in barite recovery operations. The Brandt CF-2 has a widely-spaced, single-lead conveyor with a 140:1 gearbox more suited to unweighted mud. The optional hydraulics package offered by Sweco is recommended when the SC-4 is used as the high-g centrifuge in two-stage operations. It will provide a slightly higher bowl RPM and adjustable differential RPM to maximize separation performance.

7.1.6 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. The shorter bowl length reduces retention time and makes these centrifuges less susceptible to high torque in barite recovery applications. The larger machines are recommended for unweighted mud applications.

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8 Summary ·

With the emphasis on reduced waste volumes and improved solids removal efficiency, the centrifuge has become an integral part of the drilling solids removal system. Centrifuges are capable of removing very fine solids that cannot be removed by any other mechanical solid removal device. The solids discharge is relatively dry.

·

Laboratory tests indicate that centrifuge performance is chiefly a function of G-force, pond depth, bowl-conveyor differential rpm and mud viscosity. G-force, a function of bowl rpm and diameter has the greatest impact on separation efficiency. Pond depth controls both fluid residence time and flow capacity. Differential rpm is a factor in solids conveyance and torque limitations. Increasing yield values detrimentally affect separation efficiency.

·

Once a minimum threshold G-force is reached, cake dryness is relatively unaffected by G-force. However, a minor difference in dryness may change the appearance of the solids from runny to stackable.

·

Large, high G-force machines are recommended for centrifuging unweighted muds. Use deep pond depths and lower flow rates for fine solids distributions. Coarse solids distributions may be more efficiently processed using shallow pond depths and higher flow rates.

·

Centrifuging hydrocyclone underflows becomes increasingly economic as mud formulation and waste disposal costs increase. The centrifuge should process in excess of the hydrocyclone underflow rate. Two designs for centrifuge catch tanks are shown. A low-G, high capacity centrifuge is recommended for these coarse solids.

·

The centrifuge is used in weighted mud to recover valuable weighting material from mud which must be discharged due to unacceptable colloidal solids content. The economics of barite-recovery centrifuging is usually positive when the liquid phase is inexpensive and disposal costs are not prohibitive. G-force should be maximized to improve barite recovery.

·

Two-stage centrifuging is necessary in weighted muds when liquid discharge must be minimized. The first centrifuge recovers barite. Its effluent is fed to a second centrifuge operating a maximum G’s, which discards solids and returns the liquid phase. Colloidal solids are not removed. The economics of two-stage centrifuging are site-dependent. A method for monitoring the cost effectiveness 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 adjustable pond dams, and 4) stainless steel bowl and conveyor. However, quality of service is paramount. Recommended centrifuges for both unweighted and weighted muds are listed.

CONFIDENTIAL


Centrifugal Pumps and Piping


Centrifugal Pumps and Piping 1 Introduction .........................................................................................................................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. Fig. 2. Fig. 3. Fig. 4. Fig. 5. Fig. 6.

Typical centrifugal pump. .............................................................................................3 Centrifugal pump sizing example. ................................................................................4 Minimum suction line submergence. .......................................................................... 10 Elevation vs. barometric pressure. ............................................................................. 11 Vapor pressure as a function of fluid temperature. ..................................................... 12 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

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1 Introduction Centrifugal pumps are ideal for the low pressure, high flow rate requirements of hydrocyclones and mixing systems. Unlike constant-volume piston pumps, centrifugal pumps provide constant “head.” Consequently, the pump and associated piping system must be correctly sized and designed to deliver the required flow rate and desired head. This section briefly describes how centrifugal pumps work and provides guidelines for the design, installation and operation of centrifugal pumps and piping systems.

2 Principle of Operation The centrifugal pump consists of a rotating impeller mounted inside a casing (Fig. 1). Fluid enters the casing at the center (the eye of the impeller). As the impeller spins, the fluid is accelerated to the circumference by the curved impeller vanes. The accelerated fluid exits the impeller and enters the pump casing where this kinetic energy is converted into pressure energy. Although the pump can operate against a closed discharge valve, it is not recommended. When there is no flow, all the pump power is dissipated into the fluid. This will cause the pump and motor to quickly overheat. A drive shaft connected to the impeller transmits power from the driver. A stuffing box or seal is normally used to prevent leakage. The most common driver for centrifugal pumps is the a.c., fixed-speed, induction motor. Variable-speed motors are available, but rarely required for drilling rig applications. The motor is joined to the pump shaft by a flexible coupling. Drivers are usually three-phase motors. The rotation of the pump should be checked when it is installed to make sure that it is rotating in the proper direction. Centrifugal pumps are usually constructed of a cast-steel housing with castiron internal parts. Long-life packages offer hard-facing on the high-wear areas of the pump. Wear-resistant tungsten carbide seals are also available. Both are highly recommended. The pump performance curves in Appendix E, Pump Performance Curves, illustrate that the head generated by centrifugal pumps decreases very little as the flow rate is increased. Conversely, the flow rate through hydrocyclones is not affected much by head. Note, however, that hydrocyclones are designed to operate at a certain amount of head. Less or more may be detrimental to their performance. Therefore, the pump should be sized to provide the correct head at the flow rate dictated by the hydrocyclones.

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Fig. 1. Typical centrifugal pump. Note: Kinetic energy is converted into pressure energy by the rotating impeller vanes to provide consistent head.

3 Sizing Centrifugal Pumps 1.

Determine the total flow rate needed. For a hydrocyclone manifold, the flow rate is calculated by:

2.

Determine the total head required. For most hydrocyclones, the required inlet head is 75 ft. The total head required from the pump is:

Q (gpm) = # of Cones x Flow Capacity/Cone

Ht = 75 ft + Lift Height (ft) + friction Losses (ft) where: Lift Height is the height between the hydrocyclone manifold and the mud surface (not the pump suction). Friction Losses are the equivalent loss of head through lines, elbows and tees. For most installations, this is generally between 2 and 5 ft. If long line lengths and/or numerous elbows and tees are present, use a

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worksheet as shown in Table 1 to calculate the actual friction losses. An example calculation is provided. 3.

Using the pump performance curve for your pump (Appendix E, Pump Performance Curves), find the intersection of the total flow rate required (Step 1) and the total head required (Step 2). Choose the impeller size which corresponds 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 performance diagram for your pump, find the intersection point for the impeller size determined in Step 3 and the total flow rate (Step 1). Read the corresponding horsepower required at this point. Interpolate between the horsepower curves when necessary. This is the horsepower required to pump water. For any mud weight, the required brake horsepower (BHP) is calculated by: BHPmud =

ρmud (ppg) x BHPcurve 8.34

3.1 Centrifugal Pump Sizing Example Problem: Determine the pump requirements, given the following desilter arrangement: 12-50 gpm cones Required head - 75 ft Maximum Mud Density - 10 ppg Piping System as shown in Fig. 2

Fig. 2. Centrifugal pump sizing example.

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Solution: 1.

Calculate Total Flow Rate Q = 12 cones x 50

2.

3.

gpm = 600 gpm cone

Calculate the pump discharge head: A.

Using a worksheet such as Table 1, list the length and size of each pipe, and the number and size of each fitting.

B.

From Table 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, the feet of lift and the friction losses.

From the Pump Performance Curves (Appendix E, Pump Performance Curves), 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 at 1150 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: ρmud (ppg) x BHPcurve 8.34

BHPmud = =

(10) (25) 8.34

= 30 HP

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Page 6 of 14

Table 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

1

Pipe Length or Fitting Type

Extended Entrance

Size (in.)

2 N × C × QR

6

(1) (0.664) (600)2

=

Friction Loss (ft)

=

.02

=

.24

=

.87

=

.93

1 × 10 6

1 × 10 6

10

Suction Line

6

(10 ) (0.0664) (600)2 1 × 10 6

15

Discharge Line

5

(15 ) (0.1612) (600)2 1 × 10 6

2

Short Elbows

5

(2) (1.29) (600)2 1 × 10 6

Total Friction Loss, HF (ft) Total Required Head, HT (ft) HH + HL + HT = HT 75 + 6 + 2 = 83 ft

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=

2.06

Schlumberger Dowell



Table 2 Friction Loss Coefficients for Pipe Fittings

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2



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3.2 Estimating Impeller Size In many instances, we are dealing with existing equipment and need to determine the pump impeller size to estimate output capacity. The impeller size of a centrifugal pump can be estimated by the following procedure: 1.

The fluid density, pump rpm, a valve on the pump discharge and an accurate pressure 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. Estimate the effective impeller size.

4 Pipe Sizing As was evident in the centrifugal pump sizing example, the pipe diameter and the design of the piping system will affect the size of the pump and the horsepower requirements. Suction and discharge lines should be as short as practical and sized to flow at velocities in the range of 5 to 10 ft/s. Low velocities will allow solids to drop out in the lines. High velocities erode elbows and cause distribution problems in the hydrocyclone manifold. Inadequate suction line size can cause cavitation in the pump. Also, the suction line should have no elbows, tees or reducers within 3 pipe diameters of the pump suction flange. Pipe velocity can be calculated using the following equation: v( ft / s) =

Q

(2.48)

where: Q = flow rate, in gal/min di = inside diameter of the pipe, in inches

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As a quick reference, the maximum and minimum recommended flow rates for common pipe diameters are listed in Table 3.

Table 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

4.1 Suction Head Requirements (NPSH) The suction line of the pump must be submerged to prevent vortexes in the suction tank or air locking of the pump. Centrifugal pumps require a net positive suction head (NPSH) to prevent cavitation and subsequent damage to the pump. The NPSH required is a function of the pump design and the flow rate. NPSH curves are included on the Centrifugal Pump Performance figures to find the minimum NPSH needed. The amount of NPSH available must then be determined.

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Schlumberger Dowell

As a shortcut, the minimum submergence for 6 in. and 8 in. suction lines as a function of flow rate is provided in Fig. 3. These curves may be used for most applications where the suction line is short and straight.

Fig. 3. Minimum suction line submergence. Note: Points below or right of the lines should be avoided.

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If the intersection of your submergence depth and flow rate fall near the line, a detailed determination of suction head should be made using the following equation: NSPH ( ft ) =

Pvapor V2 Patm + dsubmergence - s - Hfs 2g 0.052 × ρm 0.052 × ρm

where: Patm

=

uncorrected barometric pressure, psi (Fig. 4)

dsubmergence

=

height from pump suction to fluid level, ft

Pvapor

=

vapor pressure of liquid, psi (Fig. 5)

pm

=

mud density, lb/gal

vs

=

velocity of suction line fluid, ft/s

g

=

gravitational constant = 32 ft/s

Hfs

=

friction head losses in the suction line, ft

2

Fig. 4. Elevation vs. barometric pressure.

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

4.1.1 NPSH Example From the previous example, the required NPSH from the Pump Performance Curves for our flowrate and impeller size is approximately 4.5 ft. Head loss in the suction 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 100°F., the available NPSH is determined as follows: 1.

Patm = 14.2 psia (from Fig. 4)

2.

dsubmergence = 6 ft

3.

Pvapor = 0.95 psia (from Fig. 5)

4.

v =

5.

The available NPSH is:

Q

(2.48) × di2

NPSH ( ft) =

=

400 2.48 × 6.056 2

= 4.38 ft / s

( 4.38) 2 − 0.64 = 30.54 ft 14.2 0.95 +6− − 0.052 × 10 0.05 × 10 2 × 32.4

Since only 4.5 ft is required, there is sufficient NPSH available.

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4.1.2 Suction Line Entrance A properly-designed entrance will minimize friction loss, reduce air entrainment and will reduce the amount of dead volume before suction is lost. Various designs are compared in Fig. 6.

Fig. 6. Pump suction pipe entrances. Note: The recommended designs reduce friction loss and air entrainment.

5 Installation and Operating Guidelines 1.

Eliminate manifolding wherever possible.

2.

Keep air out of the mud by degassing, having adequate suction line submergence 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.

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Schlumberger Dowell

Check direction of rotation.

10. To reduce start up load on the electric motor, start the pump with the discharge valve partially open, then open fully once the pump is up to speed. This will also reduce shock loading on the downstream equipment.

6 Summary ·

A centrifugal pump provides constant head, which is ideal for the low pressure, high flow rate requirements of hydrocyclones and mixing systems. Centrifugal pumps are constructed of a cast-steel housing with cast-iron internal parts. Hardfacing on the high-wear areas and tungsten carbide seals are recommended.

·

Centrifugal pumps must be sized to provide the required head. Charts of head versus flow rate for the most common centrifugal pumps supplied in Appendix E, Pump Performance Curves. A procedure to correctly size centrifugal pumps is outlined in this section.

·

Suction and discharge piping should be short as possible to reduce friction losses. The piping should be sized to flow at velocities in the range of 5 to 10 ft/s to prevent solids settling or erosion problems. Tables and charts are supplied to estimate the friction losses in pipe and fittings.

·

The suction line of the pump must be submerged to prevent vortexes in the suction and subsequent air locking of the pump. Guidelines are presented for determination of minimum submergence depth. Designs for suction line entrances are also illustrated.

CONFIDENTIAL


Addition/Mixing Systems


Addition/Mixing Systems 1 Introduction .........................................................................................................................2

2 Mixing Hoppers ...................................................................................................................2

3 Bulk Systems.......................................................................................................................4

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. Fig. 2. Fig. 3. Fig. 4. Fig. 5. Fig. 6. Fig. 7.

Jet/Venturi mixer. .........................................................................................................3 Sidewinder mixer..........................................................................................................4 Jet shear mixer. ...........................................................................................................6 SECO (Echols) homogenizer ring. ...............................................................................7 Horsepower requirements for canted-blade impellers................................................. 12 Horsepower requirements for flat-blade impellers. ..................................................... 12 Floor baffles. .............................................................................................................. 13 TABLES

Table 1 Recommended Turnover Rates................................................................................ 11 Table 2 Impeller Displacement Rates ................................................................................... 14 Table 3 Physical Specifications for Mechanical Mixers.......................................................... 14

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1 Introduction All mud systems require a mixing system for the addition of viscosifiers, weighting agents and chemicals to maintain desired mud properties. The method and location chosen for addition can greatly impact material consumption and the resultant properties of the active system. For example, if bentonite is not completely hydrated before being pumped downhole, the viscosity of the mud at the flowline will be much higher than at the suction pit. Since viscosity negatively impacts solids control equipment performance, inadequate control of viscosity can lead to higher dilution volumes. Polymers present special mixing concerns to prevent the formation of “fish-eyes”; balls of dry polymer encapsulated by a thick, partially-hydrated layer. Unless properly wetted and sheared, a significant portion of the polymer will be lost at the shakers and increase polymer consumption. It is therefore important to ensure that additions are made correctly and in the right location.

2 Mixing Hoppers The most common device used to add dry material to the mud is the venturi mud mixing hopper (Fig. 1). Fluid is supplied to the mixer by a centrifugal pump. The hopper device works by converting pressure head into velocity through a jet nozzle. The downstream venturi increases the shearing action and changes velocity head back into pressure head. Dry material is added where the jet stream crosses the gap between the nozzle and the venturi. Here, a low pressure area creates a slight vacuum. This vacuum, along with gravity, helps draw the material into the fluid stream. The high velocity and high shear rate of the fluid wets and disperses the dry material. To operate at maximum efficiency, both the nozzle and venturi must be correctly sized for the flowrate and head. This type of hopper is available from many manufacturers. “Homemade” versions, usually without a properly-designed venturi, are common.

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Fig. 1. Jet/Venturi mixer. Note: This design reduces dust but entrains more air into the fluid. Another common mixing device is the Sidewinder hopper (Fig. 2), manufactured by Swaco. The operation is much like a hydrocyclone. Fluid is pumped to a tangential 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 travels twice around the mixing chamber. As the fluid exits the hopper through a tangential outlet, the velocity is converted back into pressure head.

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Fig. 2. Sidewinder mixer. Note: This design does not entrain as much air as the venturi mixer, but creates more dust. Laboratory tests conducted at APR with bentonite showed little difference between the two devices in both capacity and mixing capability as measured by the resultant mud rheology. Since the Sidewinder does not draw air into the hopper, dust can be a problem when adding some materials. Conversely, the Mission Venturi hopper eliminated dust but entrained more air into the mud. Sizing of the jet nozzle and venturi are critical in obtaining maximum performance from venturi mixers; “homemade” versions should be avoided.

3 Bulk Systems Bulk systems are economical for storing and distributing weighting material in large 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 material into the mud hopper. Bulk systems for other dry materials are becoming increasingly popular in offshore applications to eliminate handling and waste associated with sacked material. When consumption is not high enough to justify bulk tanks, hopper systems using 2200 lb “big bags” may be an alternative.

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4 Polymer Mixing Conventional mixing hoppers are not generally adequate for mixing and wetting dry polymers into viscous muds. Problems frequently arise when attempting to mix dry PHPA powder through conventional mixing hoppers regardless of whether the polymer is added directly to the active system or to a concentrated premix. Polymer fish-eyes, excessive viscosities, extensive mixing times and shaker screen blinding are commonly reported. These problems can be reduced by using a liquid form of the product, but liquid formulations contain less active polymer and use an oil as the carrier fluid. Work conducted at APR on the characterization of polymers such as PHPA has led to the following conclusions regarding the mixing and shearing of polymers: 1.

PHPA polymers marketed for use in drilling fluids may contain varying amounts of high molecular weight fractions. Viscosity is a function of molecular weight. Those products with a higher fraction of high molecular weight polymer will be harder to dissolve and generate higher viscosities.

2.

Shear-degradation reduces the molecular weight of many polymers, especially PHPA. Higher shear rates produce lower molecular weights. Below a certain molecular weight, the inhibitive characteristics of PHPA are effectively lost.

A mixing and shearing system consisting of a perforated-wafer type of jet shear mixer coupled with a SECO Homogenizer was found to provide improved mixing and allow preparation of PHPA concentrations to 6 lb/bbl in a 50,000 mg/L chloride brine. The Flo Trend Jet Shear Mixer, pictured in Fig. 3, directs fluid into a mixing chamber through opposing nozzle disks to impart turbulence and increase contact area. Polymer is added into the chamber through a conventional hopper. The mixture is then pulled into a venturi eductor, where further shearing and mixing occurs.

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Schlumberger Dowell

Fig. 3. Jet shear mixer. Note: Designs such as this can improve polymer mixing. The SECO (Echols) homogenizer consists of a perforated ring that fits around the perimeter of the impeller blades in a centrifugal pump (Fig. 4). Test conducted at APR indicate that the SECO homogenizer produces sufficient shear to degrade the higher molecular weight fractions that make the product hard to dissolve, but will not shear-degrade below the molecular weight required for inhibition. The SECO is recommended for premixing polymer to reduce viscosity and elimination fish-eyes. Do not use this device for shearing weighted muds; the high solids content will quickly erode the perforations in the homogenizer ring. Also, barite may be degraded by the homogenizer.

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Fig. 4. SECO (Echols) homogenizer ring. Note: Recommended for shearing polymers. The following guidelines should be followed for building concentrated premix volumes: 1.

When possible, use brine instead of fresh water. Polymers will impart less viscosity 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 be mixed through the jet shear mixer into the brine in a single pass.

4.

After mixing the PHPA, the premix should be sheared through the homogenizer until stable rheological values are achieved.

5 Active System Addition Dry products such as bentonite and barite should not be added, even through a hopper, at the suction compartment nor in the solids removal section. Addition should be made at least one compartment upstream of the suction compartment to allow time for the material to wet and disperse into the active system. Both these compartments must be well-agitated either by mechanical stirrers or mud guns. Mud materials added at the suction can cause air entrainment at the rig pumps and increase the incidence of drill pipe corrosion.

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6 Premix System A premix system is a separate set of tanks with agitators and a hopper for batch mixing mud to desired specifications before addition to the active system. Premix systems 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 the dry material is fully wetted. This also provides time for entrained air to break out of the mud.

2.

Better control over active system mud properties. The properties of the premixed mud can be tailored to meet desired properties before transferral to the active system. Once properties in the premix have stabilized, the mud can be transferred over a complete circulation to ensure even mud properties in the active circulating system.

3.

Less material consumption. With longer hydration and shearing time, premix tanks offer the benefit of maximizing the yield from bentonite and polymers before addition to the active system. Premix tanks are especially effective for polymer muds and almost essential for oil-based muds. Specialized shearing and mixing equipment (see Polymer Mixing) may be used on the premix tank to properly wet polymers at high concentrations and eliminate fisheyes, thus reducing polymer consumption.

4.

Easier to monitor dilution rates. The volumes added to the active system are usually much easier to monitor when transferring liquids of known quantity from a premix tank. The overall solids removal efficiency can be determined much more readily when accurate 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 much more quickly than when making additions over a complete circulation in the active system. Once the material has been added, the premix may be left to agitate and hydrate the slurry. After the desired properties have been achieved, the premix may be metered slowly into the active system. Both the hydration and transferral operations require minimum attention, thus freeing up manpower for other duties.

CONFIDENTIAL




7 Water Addition Dilution water is necessary in all water-based mud systems to maintain circulating volume and desired mud properties. Since the amount of dilution is directly linked to solids removal efficiency, the use of a water meter to monitor dilution volumes is strongly 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 must be supplied to the addition section and solids removal sections of the mud pits for both volume maintenance and cleaning. Since water must be supplied to almost every area on the rig, manifolding is obviously required. Ensure that the water meter is located to account for all water streams that will end up in the active system. Water should be recycled wherever possible. Remember that regardless of its purpose, any water used on and around the rig will contribute to the total liquid waste volume. This is especially important on locations where water supply or disposal costs are high. It is imperative that every water line be equipped with a valve and that no leaks are tolerated. Use low volume nozzles on the wash water lines. When possible, wash water should be collected and segregated from the cuttings disposal pit for recycling or for makeup water in the active system. Water should be added at the flowline when necessary to reduce the viscosity of the mud and allow finer screens to be used on the shakers. Any potential degradation in the cuttings size due to viscosity reduction is offset by the increased removal rate. Lower viscosity mud will also improve downstream degasser and hydrocyclone performance. Because centrifuge performance is sensitive to the viscosity of the feed mud, water addition at the centrifuge is usually necessary to achieve optimum performance. 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 centrifuge is discharged with the centrate and the does not contribute to dilution of the active system unless two-stage centrifuging is employed.

7.1 Waste Pit Water In many instances, recycling water from the waste pit makes both economic and environmental sense. The following guidelines can significantly reduce overall rig water consumption: 1.

Recycle waste pit water to the shaker or centrifuge slides to help flow discarded solids back to the waste pit.

2.

Use clean waste pit water as makeup water for the mud. Design the waste pit to access this fluid. This water must be checked for chemical compatibility before 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.

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4.

Schlumberger Dowell

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

8 Agitation Agitation is necessary to keep weight material suspended and ensure a homogeneous drilling fluid. Agitation also prevents solids buildup in the mud tanks. All removal compartments except the sand trap should be well-stirred. Mechanical (paddle type) stirrers are efficient mixers and are recommended, especially in the solids removal section. Mud guns impart shear which may degrade the drilled solids. Mechanical agitation ensures that the solids control equipment cannot be bypassed. Mud guns are acceptable in the Addition-Suction compartments downstream of the solids control equipment. In the addition section, mud guns may help shear and blend newly-added mud materials. Mechanical stirrers must be correctly sized. They must be large enough to adequately mix the fluid and not so large to cause aeration of the mud. The following method for sizing agitators was developed by the Brandt Company. This agitator sizing method is based on the desired turnover rate (TOR). The TOR is the time required, in seconds, for all of the fluid in the tank to move past the agitator blades: TOR = Vt / D x 60 where: Vt

=

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

D

=

Impeller displacement in gal/min (from Table 2)

The mud area to agitate should be divided into squares. For example, a 10 ft x 30 ft tank should be divided into 3 equal parts, each 10 ft x 10 ft. The TOR would be based on the volume of each 10 ft x 10 ft area. For proper agitation, the TOR should be between 35 and 90. A TOR less than 35 may result in vortices; a TOR over 90 will lead to solids settling. Table 1 gives the recommended TORs for various mud compartment uses.

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Table 1 Recommended Turnover Rates Tank Type

Recommended TOR

Solids Removal

Suction

Reserve

Pill

50-75

65-85

50-80

40-65

8.1 Agitator Design 1.

Calculate volume, Vt, (gal). 3

Vt = L x W x H, in feet x 7.481 gal/ft . 2.

From Table 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 2 with impeller displacement closest to the value calculated in Step 3. For tank depths > 5 ft, use a cantedblade (angled blade) impeller. Flat-blade (vertical blade) impellers may be used in shallower tanks.

5.

Locate the impeller diameter corresponding to the chosen impeller displacement on Table 2. Using Fig. 5 (Canted-Blade) or Fig. 6 (FlatBlade), enter the chart at the impeller diameter and follow the horizontal line until it intersects the maximum anticipated mud weight curve. Read the recommended horsepower.

6.

Determine the recommended agitator shaft length from Table 3.

7.

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

8.

Baffles, as shown in Fig. 7 are highly recommended for flat-bottomed tanks to help direct the flow towards the corners and eliminate “dead areas” in the tank. A baffle is a steel plate 12 in. long, mounted on the tank floor and extending 6 in. above the top of the agitator blades. The baffles should be installed 6 in. from the agitator blade tips along a line from the agitator shaft to each corner of the compartment.

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Schlumberger Dowell

Fig. 5. Horsepower requirements for canted-blade impellers. (Courtesy of Brandt)

Fig. 6. Horsepower requirements for flat-blade impellers. (Courtesy of Brandt)

CONFIDENTIAL




Fig. 7. Floor baffles. Note: These are recommended to eliminate “dead areas” in flat-bottomed tanks.

8.2 Agitator Sizing Example Given:

Suction Tank, 9 ft L x 7 ft W x 9 ft H 18 ppg mud

1.

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

2.

Recommended TOR, from Table 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 2, nearest D = 3764 gpm, Impeller Diameter = 32 in.

5.

From Fig. 6, for 32 in. diameter and 18 ppg mud, required agitator horsepower = 5 HP (MA5).

6.

From Table 3, for model MA5 agitator and 9 ft tank depth, shaft length reduction = 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.

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Page 14 of 15

Table 2 Impeller Displacement Rates Diameter (in.)

Impeller Displacement Rate* GPM at 57.5 (60 Hz)

Impeller Displacement Rate GPM at 48 rpm (50Hz)

Canted-Blade

Flat-Blade

Canted-Blade

Flat-Blade

246 560 1051 1941 2839 4365 6273 8411 11300 14401 18630

177 404 760 1373 2060 3142 4510 6081 8288 10445 13440

205 467 877 1620 2370 3644 5237 7023 9435 12024 15552

Weights (lbs)

12 16 20 24 28 32 36 40 44 48 52

11 15 19 21 38 50 61 74 101 118 126

213 484 909 1645 2468 3764 5402 7284 9928 12512 16100 3

3

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

Table 3 Physical Specifications for Mechanical Mixers

Model

MA1* MA2* MA3* MA5 MA7.5 MA10 MA15 MA20 MA25

HP

1.0 2.0 3.0 5.0 7.5 10.0 15.0 20.0 25.0

Shaft Dia. (in.)

Minimum Impeller Dia. (in.)

1-1/2 1-1/2 1-3/4 2-3/8 2-3/8 3 3 3-1/4 3-1/2

12 20 24 28 32 32 36 40 40

Weight

Shaft Length Reduction (in.)**

Shaft (lb/ft)

Agitator (lbs)

Free

6.0 6.0 8.2 15.1 15.1 24.0 24.0 28.1 32.7

200 310 406 580 1200 1224 1830 1898 3130

9 9 10 11-1/2 22-1/2 22-1/2 26-5/8 27 33

Stablized 9 9 10 10 12 12 13-1/8 13-1/2 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

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9 Summary ·

Addition/mixing systems must be correctly designed to minimize material consumption and ensure complete and even mixing.

·

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

·

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

·

Mixing polymers such as PHPA present additional problems such as polymer fish-eyes, extensive mixing times, and shaker screen blinding. Polymers with a higher fraction of high molecular weight polymer will be harder to dissolve and generate higher viscosities. Higher shear rates produce lower molecular weights, but below a certain molecular weight, the inhibitive characteristics of PHPA are lost.

·

A mixing and shearing system consisting of a perforated-wafer type of jet shear mixer, coupled with a SECO Homogenizer, was found to provide improved polymer mixing. Guidelines for building concentrated premix volumes are provided.

·

Premix systems are highly recommended for the numerous advantages they provide: 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 efficiency. Water should be added at the flowline to reduce viscosity and improve shaker performance. Any water used on the rig will contribute to the total liquid waste volume. No leaks should be tolerated. Use low volume nozzles on the wash water lines. Recycle water where possible.

·

Mechanical (paddle type) agitators are recommended in the solids removal section of the active system. Mud guns are acceptable in the addition/suction compartments only. A procedure is provided to correctly size mechanical stirrers.

CONFIDENTIAL


Tank Design and Equipment Arrangements


Tank Design and Equipment Arrangements 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. Fig. 2. Fig. 3. Fig. 4. Fig. 5. Fig. 6.

Unweighted mud - centrifuge processing active system. ..............................................7 Unweighted mud - centrifuge processing hydrocyclone underflow................................9 Unweighted mud - centrifuge processing mud cleaner underflow. .............................. 11 Weighted water-based mud - single-stage centrifuging (Barite recovery) ................... 13 Weighted mud - two stage centrifuging. ..................................................................... 15 Generic - complete system. ....................................................................................... 17

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

CONFIDENTIAL




Schlumberger Dowell

The active surface system can be divided into two sections: Solids Removal and Addition-Suction. All solids removal equipment and degassing occurs in the Solids Removal section. The Addition-Suction section is used to add fresh mud to the circulating system and provide sufficient residence time for proper mixing to occur before 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 efficiently carry out its designed function. The number of compartments needed will depend upon the amount and type of solids removal equipment, system size and circulation rate. Each compartment must have enough surface area to allow entrained air to break out of the mud. A rule of thumb for the minimum surface area is calculated by: Area (sq ft) = Maximum Circulating Rate (GPM)/40 To maximize solids suspension and usable volume, the best tank shape is round with 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. The ideal tank depth is equal to the width or diameter of the tank. This design provides sufficient pump suction head and is best for complete stirring.

1.1 Compartment Equalization Equalization height between compartments will depend upon the duty of the compartment. As a rule, an adjustable equalizer is needed only between the Solids Removal section and the Addition-Suction section. An adjustable swing-arm equalizer is recommended. Normally, the equalizer will take mud from the bottom of the last solids removal compartment and discharge mud near the top of the first compartment in the Addition-Suction section (high equalization). This keeps the fluid level high in the Solids Removal section to maintain sufficient suction head for the centrifugal pumps, prevents vortexing by the stirrers and provides sufficient mixing volume in barite-recovery operations. In emergencies, the swing-arm can be lowered to provide access to the full surface volume. High equalization between the Solids Removal and Addition-Suction sections also increases the ability to detect volume changes due to influx or losses to formation. Because the volume of the Solids Removal Section remains constant, any volume change 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 level will be more pronounced per unit volume. The minimum equivalent diameter of the equalizer for adequate flow between compartments can be estimated by the following calculation: 1/2

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

CONFIDENTIAL




Recommended equalization between specific compartments is summarized below: 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

1.2 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 in closed-loop systems. Its main function is to remove large solids that might plug the downstream hydrocyclones. With the fine-screen capabilities of today’s shale shakers, the sand trap mainly serves as a backup should the shakers be bypassed or operated with torn screens. The sand trap should be the first compartment the mud enters after passing through the shaker screens. Since it is a settling tank, it should not be stirred and the mud should exit the sand trap over a high weir. The sand trap floor should have a 45° slope to its outlet. A 20 to 30 bbl volume is sufficient. A quick opening solids dump valve that can be closed against the mud flow is recommended to reduce mud losses. The sand trap should be dumped only when nearly filled with solids, since whole mud is lost when the sand trap is dumped.

1.3 Slug Tank A slug tank is a small compartment (10-50 bbls) isolated from the rest of the active system in the Addition/Suction section. Slug tanks provide the ability to mix small volumes of specialized fluids and materials. The mud pump suction is manifolded to provide access to the slug tank. The slug tank is routinely used to mix small slugs of material to be pumped directly downhole, such as high density pills for placement in the drill pipe prior to tripping. It is also commonly used for preparation of LCM pills, spotting fluid for differential sticking, and viscous sweeps. The mixing hopper must be manifolded to permit isolation of the slug tank for mixing these pills.

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Schlumberger Dowell

1.4 Equipment Arrangement The solids removal equipment should be arranged to sequentially remove finer solids as the mud moves from the flowline to the suction pit. The purpose of this arrangement is to reduce the solids loading on the next piece of equipment. Each device must take mud from an upstream compartment and discharge into the next compartment downstream. This applies to both unweighted and weighted mud equipment arrangements. The amount and type of equipment required will depend upon the drilling conditions and economics specific to each well. Unless a detailed economic analysis is made, it is usually better to overestimate solids removal equipment requirements. Underequipping the rigs will usually result in more dire consequences, such as low penetration rates, differential sticking, high material consumption and excessive dilution and disposal volumes. Proper routing of fluids through the solids removal system is essential to achieve maximum solids removal efficiency. Mistakes in fluid routing can drastically reduce separation performance by causing a large percentage of the circulation rate to be bypassed. These errors are most commonly associated with mud cleaners and hydrocyclones. In addition to suction and discharge routing, overflow discharges to 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 singlepurpose pump with no routing option. Mud cleaners, desilters and desanders should not, under any condition, require multiple suction locations. In practice, complex routing with multiple suction options is the rule rather than the exception. When this is the case, the internal configuration of the mud tanks during rig up must be inspected to trace all lines. Do not rely on “as built” schematics; they are usually incorrect. Color-coding of the correct routing schematic to correspond with color-coded valves on the manifolds can greatly assist rig crew members in making correct routing decisions. “Hard-plumbed” routing errors should be corrected as soon as possible.

CONFIDENTIAL




1.5 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 to ensure even solids loading.

2.

Mechanical stirrers are recommended. Check that they are properlysized and installed correctly.

3.

Mud guns are not recommended for the Solids Removal section.

4.

When installed, the degasser should be located immediately downstream of the 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 downstream of their suction compartments.

7.

All equipment except the centrifuge should process at least 100% of the circulation rate. Backflow should be observed in these compartments.

8.

Low equalization between suction and discharge for all solids removal equipment.

9.

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

discharge

immediately

10. Adjustable equalizer between Solids Removal section and AdditionSuction section. This equalizer should normally be high except when access to the additional volume in the solids removal section is desired. 11. No solids removal equipment should discharge into the suction pit.

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Schlumberger Dowell

2 Equipment Arrangements 2.1 Unweighted Mud - Centrifuge Processing Active System This arrangement may be used with unweighted muds having low formulation costs, where liquid disposal costs are negligible. Some whole mud is discarded with the hydrocyclone underflows. Typically used with environmentally benign water-based muds. A mud cleaner should be used only if there are insufficient desilter cones to process the entire circulation rate; it should be run in parallel with the desilter. Blank off the screen and discharge underflow. Use of a centrifuge will depend on the economics of the specific application. Equipment

Median Separation

Comments

Shale Shakers

< 147 mm

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

Degasser

na

Desander

70 mm

If required. Processing Rate = 110% of maximum circulating rate. Discard Underflow.

Mud Cleaner

25 mm

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

Desilter

25 mm

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

Centrifuge

4 mm

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

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Schlumberger Dowell




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

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Schlumberger Dowell

2.2 Unweighted Mud - Centrifuge Processing Hydrocyclone Underflow Used to reduce liquid discharged with cuttings while maintaining high separation efficiency. This arrangement is preferred when the liquid phase is expensive or when free liquid discharge must be limited. Hydrocyclones concentrate solids to centrifuge. Use caution when processing abrasive desander underflow; it may cause premature centrifuge wear. Centrifuge should process in excess of hydrocyclone underflow rate, with makeup mud from the active system. Refer to the centrifuge chapter for details of feed compartment design and routing. Equipment

Median Separation

Comments

Shale Shakers

< 147 mm


Degasser

na

Desander

70 mm

If required. Processing Rate = 110% of maximum circulating rate. Underflow to Centrifuge.

Desilter

25 mm

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

Centrifuge

4 mm

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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Schlumberger Dowell




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

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Schlumberger Dowell

2.3 Unweighted Mud - Centrifuge Processing Mud Cleaner Underflow Recommended when large sections of sand are expected and free liquid must be recovered from desander underflow. The mudcleaner screen receives desander underflow. Sand is removed by the mud cleaner screen. Screen unders are processed by the centrifuge. Best alternative is to provide enough shale shakers to screen down to desander separation efficiency (74 microns) or use full size shaker to process cone unders. Equipment

Median Separation

Comments

Shale Shakers

147 mm


Degasser

na

If required.

Desander

70 mm

Processing Rate circulating rate.

=

110%

of

maximum

Underflow to mud cleaner screen. Mud Cleaner

25 mm

Total processing rate should exceed maximum circulating rate. Both desander and mud cleaner cone underflows screened before processing by centrifuge.

Centrifuge

4 mm

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

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

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Schlumberger Dowell

2.4 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 and liquid discharge is permitted. The mud cleaner may be used when the shakers cannot screen down to 200 mesh, 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 barite recovery. Equipment

Median Separation

Comments

Shale Shakers

> 74 mm

Capable of screening to 200 mesh at maximum circulation rate. Monitor solids discharge for barite content.

Degasser Mud Cleaner

na 74-100 mm

If required. Run only if insufficient shaker capacity. 150 mesh screens recommended. Monitor screen discharge for barite content.

Centrifuge

4 mm

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

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

CONFIDENTIAL

Schlumberger Dowell




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

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Schlumberger Dowell

2.5 Weighted Mud - Two-Stage Centrifuging This arrangement is used when liquid discharge must be minimized. The first centrifuge operates as a barite 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 active system. Colloidal solids are not removed. Equipment

Median Separation

Comments

Shale Shakers

> 74 mm

Screen with finest mesh possible, down to 200 mesh (d50=74 microns) at maximum circulation rate. Monitor solids discharge for barite content.

Degasser Mud Cleaner

na 74-100 mm

If required. 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 mm

Run at maximum rpm, high-G machine. Discard solids. Return centrate to active system.

CONFIDENTIAL

Schlumberger Dowell



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





Schlumberger Dowell

2.6 Complete System Layout For Both Weighted and Unweighted Mud In many cases, multiple suction and discharge locations cannot be avoided. For example, centrifuges that will process both unweighted and weighted systems must be located to permit routing both the cake and centrate streams to either the active system or to discharge. The following schematics show the fluid routing requirements for a solids removal system which must process either unweighted or weighted mud. Note: The centrifuge to be used for barite recovery must be positioned so the solids may be routed either to discharge (unweighted) or returned to the active system (weighted mud). Use a high capacity machine for treating out coarse desilter underflows or recovering barite. The second unit should be a high-G machine capable of removing fine solids. If only one machine is used, it should be a high-G unit.

CONFIDENTIAL

Schlumberger Dowell



Fig. 6. Generic - complete system. CONFIDENTIAL





Schlumberger Dowell

3 Summary ·

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

·

The active circulating system is divided into two sections: Solids Removal and Addition-Suction. The purpose of each is self-explanatory. Each section is further 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 the premix tank discussed in Chapter 10, Addition/Mixing Systems.

·

The best compartment shape is round with a conical bottom, followed by square with a V-bottom. Each must have enough surface area to allow entrained air to break out.

·

Equalization height between compartments will depend upon the duty of the compartment. Refer to the discussion in this chapter for specific recommendations.

·

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

·

Equipment arrangements for a variety of unweighted and weighted muds are illustrated in this chapter. Also included is a complete system arrangement when both unweighted and weighted muds must be processed during the course of the well.

CONFIDENTIAL


Dewatering Systems


Dewatering Systems 1 Introduction .........................................................................................................................1

2 Economic Overview ............................................................................................................2

3 Monitoring Dewatering Costs and Efficiency....................................................................7

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

1 Introduction The use of on-line closed loop circulating systems to achieve drilling waste minimization is gaining popularity both in the domestic U.S. market and in other areas around the world. The recent introduction of dewatering devices to further close the loop of drilling fluid circulating systems and to dewater reserve pits is derived from technology used in the industrial and sanitary waste treatment industries. The optimization of solids control equipment has been of primary concern to the drilling industry for many years. However, the emphasis in the past has been to utilize the solids control equipment to help optimize mud properties in order to control such variables as solids content, solids distribution, rheology, and fluid loss control. These properties affect important drilling parameters such as rate of penetration, stuck pipe, borehole stability, formation damage, and drilling costs. Because these objectives did not include entirely closing the circulating loop, significant volumes of liquid drilling wastes were generated. The recent advent of more stringent

CONFIDENTIAL



Dewatering Systems

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environmental regulations and the better understanding of the economics of running a 100% efficient closed loop system has resulted in the introduction of dewatering technology to the drilling industry. The term “closed loop” has been use quite freely in the drilling industry to describe various solids control layouts and drilling practices. In the context of this discussion, a closed loop system is one where all excess mud from either dilution or effluent from conventional solids control equipment is further processed using chemically-enhanced separation technology. This results in all solids being removed from the waste drilling mud while the liquid portion is recycled back to the active system. Ideally, all other liquid wastes generated on location are processed and also recycled. Using this technology often negates the need for a reserve pit. There are numerous applications for a closed loop dewatering system. Reasons may include restrictive environmental regulations, small locations where reserve pit space is limited, or locations where water is in short supply. Dewatering units can also be used in applications that do not require a fully closed loop system. The application where the primary desire is to recycle valuable chemicals or centrate has just recently been explored. This application may or may not require the fully closed loop system. The options are limited for an operator faced with a zero discharge or reduced discharge scenario. A simple solution still widely used today is to haul off all cuttings and waste fluids to an offsite disposal facility. This can be expensive and there could be costs involving future liability if the disposal site is later declared a hazardous area. In certain areas the cuttings and waste fluids can be spread on nearby land. This can be a cheaper option but availability, meeting environmental specifications, and long-term liability can be a problem. Pumping waste fluid back down into the formation is sometimes used, but possible contamination of groundwater worries some regulators. Whatever method is used to dispose of drilling wastes, using good waste management techniques will usually result in substantial cost reductions. Savings of up to 50% have been realized on disposal and reclamation costs as well as reduced drilling days by operators using sound waste management practices. The use of chemically enhanced dewatering devices is proving to be a reliable method of reducing wastes generated at the rig site. Several dewatering devices have been investigated as possible candidates for oilfield application, including a belt press, horizontal belt/vacuum filter, a vertical screwpress, and decanting bowl centrifuges. Further detailed studies of using chemically enhanced dewatering to increase the solids control efficiency in drilling applications have been documented.

2 Economic Overview Dewatering flocculation units are practical devices for the control of solids and liquids. They are not, however, cost effective in all situations. Since they are often used as an alternative to disposing of liquid mud, operating the unit in this mode would have to be less expensive than the disposal costs. If an

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Dewatering Systems


inexpensive mud is to be discarded as waste on location (with no associated treatment costs), it is unlikely the dewatering unit would be beneficial. However, if the liquid phase is expensive, 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 prove its feasibility. Some of the costs that should be considered when determining whether or not the dewatering unit will be cost effective are as follows: ·

Disposal Costs: The proper use of the dewatering unit can negate the necessity to dispose of liquid mud until the well is completed. Solids will have to be disposed of in a manner according to local or national government regulations. If the estimated disposal costs without a dewatering unit are higher than the costs associated with the dewatering unit, then the dewatering unit is definitely cost effective.

·

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

·

Solids Control Equipment: The efficiency of the overall solids removal equipment will increase considerably with the use of a dewatering system. The dewatering unit will remove almost all of the insoluble solids and very little of the 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 pits to be built, thereby decreasing overall location costs. Since no liquid will be discarded, reserve pits can be constructed to accommodate only solid material. Often reserve pits can be eliminated completely if solids can be immediately spread on the land or taken off site for disposal.

To determine the cost effectiveness of using a dewatering closed loop system, follow 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 the costs that will be incurred. Estimate the overall efficiency of this equipment as this will be needed to determine how much of the drilled solids will be removed.

2.

Calculate the total solids per interval that will be generated (including washouts) as a result of the hole drilled. Determine the amount of solids that will be removed with the solids control equipment and the cost of disposing of these solids. Disposal rates at commercial facilities usually do not vary significantly between the mud and cuttings. Transportation rates, however, will differ considerably if road transportation is used.

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Keep in mind that the solids generated will 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 generated and can be determined through analysis. For estimation purposes, a reasonable solids-to-liquid ratio is 1:1 or 50% liquid by volume. 3.

Calculate the dilution volumes that will be required to maintain the desired drilled solids content. The efficiency of the solids control equipment selected will play a crucial part in determining this number. Since this volume will have to be disposed of before dilution can be added, use this volume to determine the liquid disposal costs. Disposal rates will usually range from $5.00 to $10.00 per barrel (plus transportation) depending on the type of mud being discarded. Next, look at the costs of the dewatering, closed loop system:

4.

Dewatering system costs include the equipment, personnel, and the chemicals used in the flocculation process. Equipment and personnel costs are relatively fixed, but chemical usage will vary and will be the most difficult to quantify. The chemical costs will depend on the product cost and the concentrations required to achieve the correct flocculated state. Flocculent concentration increases significantly as the solids content of the feed fluid increases, particularly when the measured solids is above 5% by volume. Fig. 1 graphically illustrates this point as the amount of flocculent needed increased from 325 ppm at 4.85% solids to almost 600 ppm at 5.1% solids to 750 ppm at 5.5% solids. This demonstrates the need for good solids removal ability upstream of the dewatering unit.

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Fig. 1. Effect of solids on flocculent concentration. Note: Flocculent consumption can increase dramatically as solids concentrations increase. Different mud systems will also require different flocculating polymer concentrations. Dispersed muds need more flocculent to achieve desired results than do nondispersed. Optimum concentrations of the flocculent are needed to provide the best “floc” for the lowest price. Since any excess flocculent used will be returned to the mud system, keeping this concentration to a minimum is important. Elevated chemical costs can make the overall dewatering system cost prohibitive. 5.

Solids disposal costs will be slightly higher when using a closed loop dewatering system as more solids are removed from the mud. It is assumed that the dewatering unit will be able to remove all the solids necessary to maintain the drilled solids content at desired levels. This assumption is based on the fact that enough solids removal equipment is utilized to help the dewatering unit achieve this goal. If these solids are to be spread on location, add the costs of the spreading. If the solids are to be disposed of at a commercial facility, add the costs of disposal, plus transportation. Assume all liquids not associated with 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 in use is a basic inexpensive fresh water system and if fresh water is readily available, the liquid phase cost will be minimal. However, if the centrate contains salts, glycols, or expensive polymers, recycling this

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Schlumberger Dowell

liquid must be included in the economics and may be a significant factor in deciding whether or not to use a closed loop system with a dewatering unit. Fig. 2 clearly shows that the amount of material returned in some centrates can be significant. As shown, a considerable amount of polymer, fluid loss control agents, and soluble salts return to the active system in the centrate. As expected, barite, bentonite and low gravity solids are almost totally removed and discarded as waste. Fig. 3 shows an example of the cost of the chemicals salvaged by the dewatering unit versus the cost of the mud in use. As can be seen, a substantial portion of the mud makeup cost can be returned.

Fig. 2. Evaluation of dewatering centrate. Note: The amount of valuable material returned in the centrate can be significant.

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Dewatering Systems


Fig. 3. Material returned in centrate. Note: The value of the centrate must be considered when estimating dewatering economics. 7.

Subtract the portion of the location costs that would not otherwise be incurred if the closed loop system were not applied. This will normally include the preparation of the reserve pit system, larger location, location clean-up and backfill of pits.

After all calculations are completed, compare the costs of having a dewatering system versus not having one, and decide if a dewatering closed system is economically warranted. These figures may be crude at first, but with more precise data 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 is obviously economical to proceed in this direction. The spreadsheet program DEWATER has been provided to assist in making these calculations. Refer to Appendix A, Solids Control Programs.

3 Monitoring Dewatering Costs and Efficiency If it is decided that a dewatering system is warranted, monitoring the cost efficiency on a daily basis is imperative. To approach this, equate all costs associated 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 be made. Fig. 4 is a sample form that can be used to keep track of these expenses as well as the mud volumes processed. The

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Dewatering Systems

Schlumberger Dowell

contributing factors in determining overall cost efficiency are: a) dewatering equipment, personnel and chemical costs, and b) volume of liquid processed. The centrate returned may contribute to the cost savings as well and should be determined by multiplying the centrate value times the volume returned.

Fig. 4. Form for calculating dewatering efficiency.

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Dewatering Systems


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 be greater than disposal costs. Fig. 5 shows the interval cost per barrel of a dewatering operation that lasts through five intervals. Note that the cost usually increases with each subsequent interval. Hole sizes are smaller and therefore circulating volumes are less. At the point where the cost per barrel approaches the cost of disposal, a decision will have to be made to either remove the dewatering equipment, or treat the mud on a “batch” basis. In this example, that point is reached at the end of interval #3. Continual processing of mud in interval #4 is 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 sufficient volume 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 the unit on standby will depend on the standby rate and anticipated frequency of use.

Fig. 5. Dewatering costs, by interval. Note: Intervals 4 and 5 are uneconomic to dewater in this example since the liquid disposal cost is less.

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January 1998

Dewatering Systems

Page 10 of 13

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4 Equipment Selection 4.1 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 for separation of liquid and solids (Fig. 6).

Fig. 6. Dewatering system equipment. Note: This schematic shows a typical dewatering configuration for a weighted mud.

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Dewatering Systems


These systems, when operated correctly have the capability of taking a stream of mud from the active system or storage and separating all of the solids from the liquid. 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 piece of solids control equipment. If the volume capability of the unit is adequate, no dilution in excess of circulating maintenance will be required. Since no free liquid is discharged, the loop is closed. On the unweighted sections of the hole, the dewatering unit should be operating on the active system, processing mud after it has passed the other solids control equipment. If a high volume centrifuge is being used for solids removal on the unweighted section, it may be advisable to process the effluent of this unit. This will lower the solids load to the dewatering unit and decrease polymer consumption. If the centrifuge is not capable of generating enough effluent to keep up with the solids removal required, then treating some of the active system should be done. Note also that in some cases, flocculation may become more difficult when processing only centrifuge effluent in unweighted mud. Laboratory tests conducted at APR showed that the presence of some larger solids will aid the flocculation process. Therefore, the addition of some whole mud to the centrifuge effluent is likely beneficial to the dewatering process. On weighted systems where a barite recovery centrifuge is in operation, the dewatering unit should process the effluent of this unit. Because of this type of equipment arrangement, no hesitation is necessary in operating the centrifuge for adjustment of the mud properties. The effluent that is normally a disposal problem can now be treated and returned to the active system.

5 Waste Management The operator is responsible for all wastes generated on the drilling location. Although drilling wastes are not generally regarded as hazardous, the disposal method must be in compliance with applicable regulations. These regulations and economic considerations will ultimately dictate how the drilling waste streams must be handled. Efficient solids control and chemically-enhanced dewatering systems can greatly reduce the volume of liquid drilling waste, but they are only a part of a comprehensive drilling waste management plan. The optimum approach is 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 environmental regulations and individual well drilling conditions will affect the design, implementation and economics of the solids control and waste handling system. There is no single system design that can be recommended for all cases. However, the following approach can help implement a solids control and waste handling system which is economically and environmentally sound:

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Schlumberger Dowell

1.

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

2.

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

3.

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

4.

Design the location layout, grading plan and reserve pits to support the solids control and waste handling plan. Allow for the proper segregation of waste streams to avoid contamination.

5.

Evaluate the drilling contractor’s existing solids control equipment and mud pits. Modify and/or add to the contractor’s solids removal system as necessary to achieve the most efficient and cost effective system.

6.

Select drilling fluids and additives that are compatible with the waste disposal method and the drilling requirements.

7.

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

During the implementation phase, the following steps can help ensure that the operation proceeds according to the plan: 8.

Inspect the solids equipment piping and fluid routing well before spud to provide enough time to make corrections.

9.

Educate the rig personnel. The best solids control equipment is of little value if it is not run correctly. Use a team approach. Make sure the rig personnel completely understand the system and its purpose. Stress any limitations on discharge.

10. Monitor solids removal efficiency. Measure the amount of water added to the system with a water meter. Analyze the solids contents of the solids control equipment discharge streams. Monitor the efficiency of the dewatering unit. Maintain performance data records on individual solids removal equipment and the entire system. 11. Follow up on disposal logistics. Plan ahead for regulatory permitting requirements. 12. Reinspect the solids control system arrangements between drilling intervals to be sure that the required changes are made in fluid routing and equipment operation. Conduct additional rig personnel training.

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6 Summary ·

Chemically-enhanced dewatering units are increasing in popularity due to more stringent environmental regulations and the incentive of reduced potential, long-term liability associated with drilling wastes. Use has also increased because of a better understanding of the economic benefits attributable to improved solids removal efficiency.

·

Alternatives to dewatering include hauling the waste to a central disposal facility, land spreading, or injecting the liquid and/or solid waste downhole into a suitable formation.

·

In this context, the term “closed-loop” is defined as one where all excess mud from either dilution or solids control equipment effluent is further processed using chemically-enhanced dewatering technology to minimize liquid waste volumes. Applications include locations with environmental restrictions, small locations where reserve pit space is limited, or where water is in short supply.

·

The economics of dewatering will depend upon the cost of disposal, liquid centrate value, solids control equipment efficiency, and location costs. A procedure is outlined in this chapter to determine the cost effectiveness of dewatering. A spreadsheet program “DEWATER” has been developed to assist in estimating the economics of dewatering up to four consecutive drilling intervals. The program is described in Appendix A, Solids Control Programs.

·

Monitoring the cost efficiency of dewatering on a daily basis is imperative. All costs associated with the dewatering unit should be converted to “dollar ($) per barrel of mud processed” figure. A sample form for tracking dewatering efficiency is provided.

·

A typical dewatering system consists of a polymer hydration and storage section, mixing and injection manifold, injection and transfer pumps, and a centrifuge for separation of liquid and solids. The liquid content of the centrifuge cake will average 40 to 50%.

·

On unweighted muds, the dewatering unit should be rigged up to process both the centrifuge centrate with additional makeup as required from the active system. Laboratory tests indicate that the presence of some larger solids will aid the flocculation process. On weighted systems, the dewatering unit should process the effluent of bariterecovery centrifuge. In both cases, the recovered liquid can be treated and returned to the active system.

·

Successful drilling waste management requires thorough planning. No single system design is optimum in all instances. An approach is provided to help implement a solids control and waste handling system that is both economically and environmentally sound. These guidelines do not detail specific waste handling or remediation procedures, but provide a checklist of issues that must be considered when planning and operating the system.

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References


References 1.

Young, G. A. 1983. “Handbook for Successful Solids Control,” Amoco Production Company, 1st Edition.

2.

Stone, V. D. “Low-Silt Mud Increases Gulf’s Drilling Efficiency, Cuts Costs,” Oil and Gas Journal, V. 62, No. 41, October 12, 1964.

3.

Lal, M. “Economic and Performance Analysis Models for Solids Control,” SPE Paper 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 Performance,” SPE Paper 14389 (1985).

5.

Cagle, W. S. and Wilder, L. B. 1978. “Layered Shale Shaker Screens Improve Mud Solids Control,” World Oil, April 1978.

6.

Hoberock, L. L. 1990. “Fluid Conductance and Separation Characteristics of Oilfield Screen Cloths,” Paper presented at the American Filtration Society National 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,” SPE Paper 22570 (1991).

9.

API Recommended Practice 13E (RP13E) Third Edition, May 1, 1993. “Recommended Practice for Shale Shaker Screen Cloth Designation.”

10. Hoberock, L. L. 1982. “Shale-Shaker Selection & Operation,” Reprint Series from Oil & Gas Journal, Pennwell Publishing Company. 11. Bray, R. P. 1984. “An Experimental Evaluation of Oilfield Degassers,” Amoco Production Company, Research Report F84-P-12 (83269ART0053). 12. Young, G. A. 1987. “An Experimental Investigation of the Performance of a Three Inch Hydrocyclone,” SPE Paper 143899, presented at the IADC/SPE Drilling Conference, March 1987. 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 on Drilling Economics,” Amoco Production Company, Research Report F88-P-43 (88126ART0171). 15. Young, G. A. 1984. “Economic Analysis of Dual Stage Centrifuging,” Amoco Production Company, Internal Report, 84067ART0102.

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References

Schlumberger Dowell

16. MacDonald, J. G. 1982. “Mud Mixing Hopper Evaluation: Geosource Sidewinder 400 and Mission Venturi,” Amoco Production Company, Research Report F82-P-37 (82202ART0148). 17. Lal, M. and Thurber, N. E. “Drilling Waste Management and Closed Loop Systems,” paper presented at the 1988 International Conference on Drilling Wastes, April 5-8, 1988, Calgary, Canada. 18. Young, G. and Robinson, L. H. “How to Design a Mud System for Optimum Solids Removal,” World Oil, September-November 1982. 19. Young, G. A. 1982. “Mud Equipment Manual, Mud System Arrangement,” Amoco Production Company, Research Report F82-P28 (82144ART0017). 20. Love, W. W. “Engineered Sizing of Mud Agitators Works Well,” Oil and Gas Journal, 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: An Environmentally Acceptable Solution,” SPE Paper 23373 (1991). 24. Moschovidis, Z. A. et al. “Disposal of Oily Cuttings by Downhole Fracture Injection - Part 1: Field Testing and Data Interpretation,” APR Greenback. 25. Williams, M. P. “Solids Control for the Man on the Rig,” Petroleum Engineer International, 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 Company, 1988.

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Appendix A SOLIDS CONTROL HANDBOOK Schlumberger Dowell

Solids Control Programs


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. Fig. 2. Fig. 3. Fig. 4.

SHAKCAP spreadsheet. ..............................................................................................2 Input section of the DEWATER spreadsheet................................................................5 Interval data and analysis section of the DEWATER spreadsheet. ..............................7 Summary section of the DEWATER spreadsheet. ..................................................... 10

1 “SHAKCAP” Spreadsheet Program The spreadsheet file SHAKCAP can be used to calculate the flow capacity of shale shakers for a specified screen. This spreadsheet replaces the flow curves and hand calculations published in the previous solids control handbook. The flow capacity equations contained in SHAKCAP are based on empirical relationships developed from full-scale testing of numerous linear motion shakers. This model is also available in the solids control economics program SECOP. Fig. 1 is an example of the spreadsheet.

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Appendix A SOLIDS CONTROL HANDBOOK

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There are three versions of SHAKCAP. They are: SHAKCAP.WQ1

-

for Quattro Pro 3.0 or higher

SHAKCAP.WK1

-

for Lotus 123 2.1 or higher

SHAKCAP.WB1

-

for Quattro Pro for Windows

Fig. 1. SHAKCAP spreadsheet.

1.1 Input 1.1.1 Screen Data The new shaker screen designations are required for input to describe the screen panel. A complete listing of screen designations for the most common shale shakers is included below the INPUT/OUTPUT window in the spreadsheet. 1.

2.

Screen Name (Optional)

-

typically the manufacturer's designation

-

use this field to identify screen

Conductance (kd/mm)

3.

conductance value listed in the screen designation

Area (sq ft)

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4.

the usable area of the panel, listed in the designation

the number of panels required by the shaker

Deck Angle

-

use 3 degrees as the default angle, lower for sticky cuttings, higher only when necessary (refer to Deck Angle discussion, Chapter 3).

1.1.2 Mud Data 6.

Mud Wt (ppg)

7.

Mud PV (cp)

8.

Mud Type (Polymer or Non-polymer)

-

enter 0.6 for polymer muds (e.g., PHPA).

-

enter 1.0 for all other muds.

1.1.3 Drilling Data 9.

ROP (ft/hr)

-

estimated average ROP for the interval

10. Hole Diam (in)

-

bit diameter is normally sufficient

11. Flow Rate (gpm)

-

total circulating rate

1.2 Output 1.

2

Usable Screen Area, (ft )

2.

2/3 of the total available screening area

Drl. Solids Generated, (gpm)

3.

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Number of Panels

5.

January 1998

rate at which solids will be returned

Solids Loading Factor, (%)

-

the percent drilled solids in the mud

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4.

Flow Capacity-Fluid Only, (gpm)

5.

the estimated flow capacity of one shaker without solids

Flow Capacity-With Solids, (gpm)

6.

Schlumberger Dowell

the estimated flow capacity of one shaker with the effect of solids loading taken into account

No. of Shakers Required

-

the total number of shakers required to process the entire flow rate using the specified screens

1.3 Using Shakcap 1.

The flow capacities are calculated for single deck shakers. Adjustment for tandem deck shakers or cascading systems can be made by reducing ROP by 25-50% to account for the solids removed by the scalping deck.

2.

Acceleration is assumed to be constant for all shaker types. This model assumes 3.0 g's normal to the screen. This may cause some discrepancies between actual and predicted flow capacities for shakers with significantly different accelerations.

3.

To estimate the screen size required for a given number of shakers, the following procedure is recommended:

4.

A.

Enter all input data except screen name. Choose a screen series from the supplied designation tables and use an area value common to that series. For example, all screens in Derrick's PWP 2 HP series have an area of 5.3 ft .

B.

Enter some starting value for conductance as a “first guess”.

C.

Adjust the conductance value in the input column until the number of shakers required matches the actual number available.

D.

Decrease the conductance in 0.2 or smaller increments until the “Flow Capacity-With Solids” output closely matches the anticipated circulation rate per shaker.

E.

Find the screen in the series with a conductance that most closely matches the required conductance. Enter that screen's name and conductance into the input table. Check that the number of shakers is correct.

The flow capacity for polymer muds, such as PHPA, is impossible to predict with any certainty. The spreadsheet uses 0.6 as an “average” flow capacity reduction factor. Actual throughput will depend heavily upon the concentration of the polymer and the amount of shear imparted.

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2 “DEWATER” Spreadsheet Program This spreadsheet was developed to help assess the economics of using a chemically-enhanced dewatering unit to reduce liquid discharge volumes. Dilution volumes, liquid and sludge discharge volumes are predicted for up to 4 drilling intervals with and without the dewatering option. The total costs of each case are compared to determine the most economical option. The output also can be used to estimate reserve pit or cuttings haul-off requirements. Computations are based on the mass balance equations presented in the economics chapter of the Solids Control Handbook and will not be repeated here. The spreadsheet is provided in two formats: Lotus .wk1 and Quattro Pro .wq1. The spreadsheet is divided into 3 sections: Dewatering and disposal cost input (Fig. 2), interval data (Fig. 3), and cost analysis summary (Fig. 4). Required input cells are highlighted or shaded, depending on the spreadsheet software. Scroll down through the spreadsheet to view the sections.

2.1 Dewatering and Disposal Cost Section

Fig. 2. Input section of the DEWATER spreadsheet. Cells A1.G22 contain the input data required for the dewatering economics calculations.

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Appendix A January 1998



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2.1.1 Dewatering Equipment Used Input the number and unit cost for the listed equipment. These costs can be obtained from a service company in your area. The spreadsheet uses only the total equipment cost in the calculations; individual entries do not have to be precise, provided the total equipment cost is correct.

2.1.2 Manpower Costs ENGINEER, TECH Enter the estimated daily cost for each service engineer or technician. The number of personnel required will be made as a separate entry for each interval, since the number of service personnel will often depend on the average daily processing rate.

2.1.3 Per Barrel Costs VALUE OF RECOVERED LIQUID This is applicable when the liquid phase recovered from the dewatering unit can be used to defray the cost of the dilution mud. For example, if the base fluid is a brine costing $2/bbl, the cost of dilution will be reduced by $2 for each barrel of liquid recovered by the dewatering unit. If the liquid is to be treated and discharged, or if the recovered liquid has little value, enter a “0” in this cell. LIQUID, SOLID DISPOSAL COSTS Input the estimated cost per bbl for disposal of liquids and solids. The disposal costs should include any applicable charges for pit construction, liquid or cuttings haul-off, spreading, and remedial treatment to reclaim the site. Offshore site charges include cuttings box rental, transportation and material disposal. DEWATERING COST Chemical dewatering cost will depend primarily on the mud and solids type presented to the dewatering unit. Low solids non-dispersed muds may cost as little as $1/bbl to treat. Heavily dispersed mud systems and fine, reactive solids can push chemical treatment costs to near $10/bbl. Refer to the Dewatering chapter for more information regarding dewatering chemical costs. When possible, have the service company pilot test a sample of the mud to provide an estimate of chemical treatment cost to flocculate. Further chemical treatment, such as pH adjustment, may be necessary to reuse the recovered liquid in the mud system. This cost should also be included in the chemical treatment cost.

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2.2 Interval Data and Analysis Section Four intervals are provided in the spreadsheet. Each interval will require an estimate of drilling time, section length and hole size, existing solids control efficiency, low gravity solids content and initial circulating volume. The spreadsheet will calculate the predicted dilution and disposal volumes for the interval, and provide an analysis of dewatering costs per barrel and interval dewatering cost.

Fig. 3. Interval data and analysis section of the DEWATER spreadsheet. (1 of 4 intervals)

2.2.1 Input Data DRILLING DAYS Input the number of rotating days anticipated for this interval. START/STOP DEPTH, ft Enter the beginning and ending depth of the interval. BIT SIZE, in. Enter the bit size for the interval.

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Appendix A January 1998



Page 8 of 10

Schlumberger Dowell

WASHOUT,% This is the estimated average volume % washout. This less than 10% for hard, consolidated formations. Highly dispersive or unconsolidated formation may wash out as much as 50%. INITIAL CIRCULATING VOLUME, bbls Enter the estimated volume in the surface pits and downhole at the beginning of the interval. INITIAL/ENDING LGS, % For the purposes of this spreadsheet, LGS pertains to the drilled solids content. If the mud is new, enter 0 as the initial drill solids content. The ending LGS should be the maximum percent drilled solids to be tolerated in the mud. EQUIPMENT EFFICIENCY, % Enter the estimated efficiency of the active system solids control system. This value can be determined by running the solids control equipment performance and economics program, SECOP. Usually, this figure will range from 30% for poor solids control systems and fine drilled solids to 75% for excellent solids control and coarse drilled solids.

2.2.2 Output Data SOLIDS GENERATED, bbls This is the total volume of drilled solids generated in the specified interval. SOLIDS REMAINING, bbls The solids left in the mud after processing by the solids removal equipment. DILUTION REQUIRED, bbls This is the dilution volume required to reduce the mud system to the maximum specified LGS content at the efficiency specified for the solids removal equipment. MUD VOLUME TO TREAT, bbls This is the volume of whole mud which must be dumped to accommodate the required dilution volume. EQUIPMENT SLUDGE, bbls The volume of wet solids discharged by the solids removal equipment, assuming a 1:1 ratio of liquid to solids. This program does not account for weight material which may be discharged by the equipment. In weighted mud applications, the actual equipment sludge volume may be higher.

CONFIDENTIAL




DEWATERING SLUDGE, bbls The volume of wet solids discharged by the dewatering equipment, assuming a 1:1 volume ratio of liquid to solids. TOTAL SLUDGE, bbls The total sludge volume is the sum of the equipment sludge and the dewatering sludge volumes. LIQUID SAVED, bbls This the estimated total volume of liquid recovered by the dewatering unit. DEWATERING RATE, bbl/day This is the average volume which must be treated daily to accommodate the required dilution volume. DEWATERING COST, $/bbl This is the average cost per barrel to treat the expected volume of whole mud discharged, based on the dewatering chemical cost and the daily equipment and manpower costs. INTERVAL COST w/ DEWATERING, $ This is the total waste disposal and dewatering cost less the value of the recovered fluid. SAVINGS (LOSSES), $ The interval cost with dewatering is subtracted from the total disposal cost without dewatering. Positive values indicate savings, or the reduction in cost attributable to dewatering, for this interval.

CONFIDENTIAL


January 1998


Page 10 of 10

Schlumberger Dowell

3 Summary Section The summary section begins at line 100. This section of the spreadsheet provides cumulative cost data on interval savings or losses and total liquid and sludge discharge volumes. At the bottom of this section, a recommendation is displayed regarding the deployment of a dewatering unit based on the economics of each interval. Savings of less than $1000 for an interval are considered uneconomic.

Fig. 4. Summary section of the DEWATER spreadsheet.

CONFIDENTIAL

Appendix B SOLIDS CONTROL HANDBOOK Schlumberger Dowell

Conductance Calculation


Conductance Calculation 1 Introduction .........................................................................................................................1

2 Nomenclature ......................................................................................................................2

1 Introduction Conductance is a measure of the ease with which fluid can flow throughout the screen per unit area. The conductance of square mesh or rectangular mesh screen cloth is calculated from the screen’s mesh count and wire diameter in both the warp and shute direction. Warp wires run lengthwise during the process of weaving the screen and are crossed at right angles by the shute wires. The shute wires are carried by the shuttle in the weaving process and may also be known as woof or weft wires. In the context of this discussion it is not important to distinguish which is warp and which is shute. However, it is important to be aware that there may be wires of two dimensions which should be considered separately in the equations. The equations are valid for most standard open-weave oilfield screens with the exception of some nonstandard polyester weaves and coated screen cloth. The conductance, C, in units of kilodarcies/millimeter for a standard weave screen cloth is computed by: C=

4095 × E2 A2 × t

where: The void fraction of the screen, E, is given by: 1 1 × ) t − ( Vw + Vs ) Ns Nw E= 1 1 ( × ) ×t Ns Nw (

The screen thickness, t, in inches, is given by: t = ds + dw

CONFIDENTIAL

Appendix B SOLIDS CONTROL HANDBOOK

January 1998

Conductance Calculation

Page 2 of 2

Schlumberger Dowell

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

1 2 ) + d2 s Ns

ls = (

1 2 ) + d2 w Nw 3

The volume of the warp and shute wires Vw, Vs, in inches, are computed by:  πd2  Vw =  w  l w  4   

 πd2  Vs =  s  l s  4   

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

πdw l w + πdsls t ( ) NsNw

For screens composed of two or more layers, the conductances are calculated for each layer individually. The total conductance of the layered screen composition is then calculated by: 1 1 1 1 = + + +..... C t C1 C 2 C 3

2 Nomenclature -1

A

=

Wire surface area to mesh volume ratio, inch .

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

CONFIDENTIAL


Solids Control Equipment Discharge Analysis, Oil Based Muds

Appendix C January 1998 Page 1 of 7

Solids Control Equipment Discharge Analysis, Oil-Based Muds 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

7 Calculations.........................................................................................................................6

1 Introduction Analysis of the solids control equipment discharge provides valuable information about equipment performance and identifies the composition and rate of the discharge stream. These calculations are designed for oil-based muds, but can be used for water-based fluids as well.

2 Sample Collection For shale shakers, a box will be needed to collect the discharge from the entire width of the shaker screens. A wooden core box can be used, or have a box fabricated. For mud cleaners, hydrocyclones or centrifuges, a 5 gallon bucket may be used. 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.

CONFIDENTIAL

Appendix C


January 1998


Page 2 of 7

Schlumberger Dowell

3.

Record the weight of the container and wet solids.

4.

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

3 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: W ws = W2 - W1

6.

Density of wet solids:

rs = Wws/Vt 7.

Weight of dry solids (including salt), gm: W ds = W3 - W1

4 Alternate Retort Procedure for Air-Entrained Cuttings Samples Occasionally, there will not be sufficient liquid on the wet solids to avoid entrainment of air in the retort. This will cause errors in the retort calculations. The following 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 W 2, gm.

3.

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

4.

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

5.

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

6.

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

CONFIDENTIAL

Appendix C


January 1998


Page 3 of 7

7.

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

8.

Weight of wet solids, gm: W ws = W2 - W1

9.

Weight of dry solids (including salt), gm: W ds = W4 - W1 3

10. Volume of oil added by syringe, cm : Voa = (W3 - W2)/SGoil 3

11. Corrected oil on cuttings Volume, cm : Vo = Vto - Voa 3

12. Corrected retort Volume, cm : Vt = 50 ml - Voa

5 Solids Analysis Calculations Note: Use brine density, rb, and Wt% salt, %S, recorded on mud check. 1.


rws = Wws /Vt 2.

Weight of oil, gm: W o = Vo * SGoil

3.

3

Volume of brine, cm : Vb = 100 (Vw)/(rb(100 - %S))

4.

3

Corrected dry solids Volume, cm : Vs = (Vt - Vo - Vb)

5.

Corrected dry solids weight, gm: W s = (Wws - Wo - (Vb * rb)

6.

3

Dry solids density, gm/cm :

rs = Ws/Vs 7.

Corrected Volume% solids: %Vs = 100 * Vs/Vt

CONFIDENTIAL

Appendix C


January 1998


Page 4 of 7

8.

Schlumberger Dowell

Volume% high-density solids (% of wet slurry): %HDS = %Vs (rs - 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) (rws)) 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.

CONFIDENTIAL

Appendix C


January 1998


Page 5 of 7

6 Example Calculations The following example calculations are designed to show how the equations listed in this section may be used to determine the composition and rate of the solid and liquid discharge streams.

Sample Source: Shaker discharge Mud Check Data Brine phase density, gm/cm

Symbol 3

rb

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

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

Vo

17.0

Vw

6.0

Vt

50.0

Retort Data

Volume of oil recovered, cm

3

Volume of water recovered, cm Total Volume retorted, cm

3

3

CONFIDENTIAL

Appendix C


January 1998


Page 6 of 7

7 Calculations 1.

Weight of wet solids: W ws = W2 - W1 = 391.5 - 297 = 94.5 gm

2.


rws = Wws/Vt = 94.5/50.0 = 1.89 gm/cm 3.

3

Weight of dry solids (including salt), gm: W ds = W3 - W1 = 378 - 297 = 81 gm

4.

Weight of oil, gm: W o = Vo * SGoil = (17) (0.84) = 14.28 gm

5.

3

Volume of brine, cm : Vb = 100 (Vw)/(rb(100 - %S)) 3

= (100) (6)/(1.24 (100 - 26.7)) = 6.6 cm 6.

3

Corrected dry solids volume, cm : Vs = (Vt - Vo - Vb) 3

= 50 - 17 - 6.6 = 26.4 cm 7.

Corrected dry solids weight, gm: W s = (Wws - Wo - (Vb * rb) = 94.5 - 14.3 - (6.6) (1.24) = 72.0 gm

8.

3

Dry solids density, gm/cm :

rs = Ws/Vs = 72.0/26.4 = 2.73 gm/cm 9.

3

Corrected Volume% solids: %Vs = 100 * Vs/Vt = (100) (26.4)/(50) = 52.8%

10. Volume% high-density solids (% of wet slurry): %HDS = %Vs (rs - 2.65)/(rHDS - 2.65) = 52.8 (2.73 - 2.65) / (4.2 - 2.65) = 2.73%

CONFIDENTIAL

Schlumberger Dowell



Appendix C January 1998 Page 7 of 7

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 (rHDS) (%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) (rws)) = (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: 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.

CONFIDENTIAL

Appendix D SOLIDS CONTROL HANDBOOK Schlumberger Dowell

Screen Designations


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

CONFIDENTIAL

Appendix D SOLIDS CONTROL HANDBOOK

January 1998

Screen Designations

Page 2 of 46

Schlumberger Dowell

1 Brandt - ATL-1000, ATL CS (Main Deck) SCREEN SERIES:

BHX

Description:

Hexagonal opening pattern perf plate bonded to rigid frame. Triple layer, square mesh screen cloth similar to Derrick DX 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 Screen

U.S.

Separation Potential

Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 3 of 46

Advanced BHX Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

Aspect

Trans.

Southwestern BHX Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 4 of 46

2 Brandt - Retrofit Tandem, ATL-CS (Scalping Deck) SCREEN SERIES: Description:

BXL 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 Screen Name

U.S. Sieve


Cond.

Area

Aspect Ratio

Trans

BXL 50

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

D50

D16

D84

na

CONFIDENTIAL


January 1998

Screen Designations

SCREEN SERIES: Description:

Page 5 of 46

BLS 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 Screen Name

U.S. Sieve

Separation Potential D50 D16 D84

Cond.

Area

Aspect Ratio

Trans

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

CONFIDENTIAL


January 1998

Screen Designations

Page 6 of 46

SCREEN SERIES:

S

Description:

Hookstrip, unbonded.

Schlumberger Dowell

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 Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 7 of 46

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 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

CONFIDENTIAL


January 1998

Screen Designations

Page 8 of 46

Schlumberger Dowell

3 Broadbent - Tandem Master (Lower Deck) SCREEN SERIES:

BL

Description:

Hookstrip, perforated plate with 2 in. openings.

Sources:

Broadbent

Comments:

Repairable Scalping screens (2 required):

Layered square mesh cloth composition.

- BG10, BG16, BG20, BG24, BG38. Broadbent BL Series Screen

U.S.


Flow Capacity

Name BL 60

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 9 of 46

4 Derrick - Flo-Line Cleaner, Cascade System, High G Dryer SCREEN SERIES:

PMD DX, PMD HP

Description:

Hookstrip panel with unique corrugated screening surface, 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 higher throughput than flat panels; helps reduce mud losses along shaker rails.

Derrick PMD DX Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Schlumberger Dowell

Screen Designations

Page 10 of 46

Derrick PMD HP Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

13.5

PMD HP 200

203

76

60

82

1.59

7.42

1.86

11.8

PMD 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

CONFIDENTIAL


January 1998

Screen Designations

Page 11 of 46

SCREEN SERIES:

PWP DX

Description:

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

Sources:

Derrick (original equipment manufacturer) Advanced Southwestern

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-Line Cleaner (panel area = 7.57 sq ft).

Derrick PWP DX Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 12 of 46

Advanced PWP DX Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

Aspect

Trans.

Southwestern PWP DX Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Screen Designations

Page 13 of 46

SCREEN SERIES:

PWP HP

Description:

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

Sources:

Derrick (original equipment) Advanced Southwestern

Comments:

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

Derrick PWP HP Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Schlumberger Dowell

Screen Designations

Page 14 of 46

Advanced PWP HP Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

Aspect

Trans.

Southwestern PWP HP Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

PWP HP 45

44

362

283

388

9.96

5.50

1.87

54.8

PWP 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

CONFIDENTIAL


January 1998

Screen Designations

Page 15 of 46

SCREEN SERIES:

GBG HP

Description:

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

Sources:

Derrick (original equipment manufacturer)

Comments:

GBG design maximizes screening area, and flow capacity, but screen life is limited.

Southwestern

Derrick GBG HP Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 16 of 46

Southwestern GBG HP Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Screen Designations

Page 17 of 46

SCREEN SERIES:

PBP HP

Description:

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

Sources:

Derrick

Comments:

Highest conductance of Derrick’s standard perforated plate panels. Shorter screen life than standard PWP series, but more resistant to plugging from sticky material such as gilsonite.

Derrick PBP HP Series Screen

U.S.


Flow Capacity

Name

Sieve

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Schlumberger Dowell

Screen Designations

Page 18 of 46

SCREEN SERIES:

SWG DX

Description:

Hookstrip panel, unbonded, layered, extra-fine square mesh cloth.

Sources:

Derrick (original equipment manufacturer) Southwestern

Comments:

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

Derrick SWG DX Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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 Screen

U.S.


Flow Capacity

Aspect

Trans.

Name SWG DX 24

Sieve 25

D50 715

D16 508

D84 824

Cond. 14.82

Area 7.60

Ratio 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

CONFIDENTIAL


January 1998

Screen Designations

Page 19 of 46

SCREEN SERIES:

BXL-D

Description:

Hookstrip perforated plate with hexagonal openings. Triple layer, extra-fine square mesh cloth, similar to PWP DX

Sources:

Brandt

Comments:

Replacement screen offered by Brandt.

Brandt BXL-D Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Schlumberger Dowell

Screen Designations

Page 20 of 46

SCREEN SERIES:

Diamond Back, DX and HP type

Description:

Hookstrip panel, perforated plate with triangularshaped openings. HP Type - Two layers, extra-fine rectangular mesh over square mesh backing cloth. DX Type - Two layers, extra-fine square mesh over square mesh backing cloth.

Sources:

Advanced Diamond-shaped plate pattern offers slightly more usable screening area than standard 1 in. PWP-type square openings.

Advanced Diamond Back DX Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Screen Designations

Page 21 of 46

Advanced Diamond Back HP Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 22 of 46

SCREEN SERIES:

HCR

Description:

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

Sources:


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

CONFIDENTIAL


January 1998

Screen Designations

Page 23 of 46

SCREEN SERIES:

HCS

Description:

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

Sources:


Comments:

High conductance series, less susceptible to plugging by asphaltenes than triple layer screens.

Derrick (designated PBP DX)

Screen life averages 40% less than PWP DX type. Derrick Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 24 of 46

Schlumberger Dowell

5 Fluid Systems - Model 500, Model 50 SCREEN SERIES:

MF

Description:

Pretensioned, glued to rigid frame, 3 in. spacing between glue 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 Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 25 of 46

Southwest Replacement Series Screen

U.S.


Flow Capacity

Name 10

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 26 of 46

Schlumberger Dowell

SCREEN SERIES:

HCS

Description:

Pretensioned, glued to rigid frame, 3 in. spacing between glue 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 MF series.

Fluid Systems HCS Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 27 of 46

SCREEN SERIES:

XS

Description:

Pretensioned, glued to rigid frame, 3 in. spacing between glue lines. Single layer, synthetic mesh over steel wire backing cloth.

Sources:

Fluid Systems

Comments:

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

Fluid Systems XS Series Screen

U.S.


Flow Capacity

Name XS 40

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Schlumberger Dowell

Screen Designations

Page 28 of 46

SCREEN SERIES:

PTP DX, PTP HP

Description:

Perforated plate with 1 in. openings bonded to rigid frame. PTP DX - Two layers, extra-fine rectangular mesh over backing cloth.

Sources:

Advanced

Comments:

Repairable

Advanced PTP DX Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 29 of 46

Advanced PTP HP Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 30 of 46

Schlumberger Dowell

6 Harrisburg - Linear Tandem SCREEN SERIES:

Harrisburg

Description:

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

Sources:

Harrisburg

Comments:

Use coarser mesh on top deck. Monitor tension for maximum screen life.

Harrisburg Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 31 of 46

7 Swaco - ALS SCREEN SERIES:

XL

Description:

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

Sources:

Swaco (Southwestern)

Comments:

Monitor screen tension for maximum screen life.

Advanced

Swaco XL Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Aspect Ratio

Trans.

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

Aspect

Trans.

Advanced DX 2 in. Plastic Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 32 of 46

SCREEN SERIES:

ALS

Description:

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

Sources:

Swaco

Comments:

Higher capacity, good deblinding characteristics but shorter life than XL series. Monitor screen tension for maximum screen life.

Swaco ALS Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

SCREEN SERIES: Description:

Page 33 of 46

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

Sources:


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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 34 of 46

SCREEN SERIES:

Advanced DX Replacement Series

Description:

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

Sources:

Advanced

Comments:

Check support stringers carefully to ensure full contact.

Advanced DX 1 in. Metal Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 35 of 46

8 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 heavier solids loading applications.

Sweco TBC 1 in. Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 36 of 46

Sweco TBC 2 in. Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

Aspect

Trans.

Southwestern 1 in. TBC Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

TBC 30

26

682

671

687

24.33

6.81

1.03

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

122.6

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

CONFIDENTIAL


January 1998

Screen Designations

Page 37 of 46

Southwestern TBC 2 in. Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Schlumberger Dowell

Screen Designations

Page 38 of 46

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 heavier solids loading applications.

Southwestern 1 in. MG Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 39 of 46

Southwestern MG 2 in. Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Screen Designations

Page 40 of 46

Schlumberger Dowell

SCREEN SERIES:

DX-Type

Description:

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

Sources:

Advanced

Comments:

May provide better resistance to blinding in some applications. Usable screening area, flow capacity is better than 1 in. TBC panel.

Advanced DX 1 in. Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 41 of 46

9 Sweco - LF-3 SCREEN SERIES:

CTB

Description:

Perforated plate with 1 in. openings bonded to a rigid frame. 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, at lower throughput.

Advanced CTB Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

Cond.

Area

CTB 20

18

1041

40.93

7.54

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

D16

D84

CONFIDENTIAL

Aspect

Trans.

Ratio 308.6


January 1998

Screen Designations

Page 42 of 46

Schlumberger Dowell

SCREEN SERIES:

CHC

Description:

Perforated plate with 1 in. openings bonded to a rigid frame. Two layers, extra-fine rectangular mesh over coarse mesh backing cloth.

Sources:

Advanced

Comments:

High capacity screening option for LF-3 shaker.

Advanced CHC Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 43 of 46

10 Thule Rigtech - VSM 100 SCREEN SERIES:

Thule TBC

Description:

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

Sources:

Thule Southwestern

Comments:

Standard screen series for this shaker.

Thule TBC Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Aspect Ratio

Trans.

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

Aspect

Trans.

Southwestern TBC Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL


January 1998

Screen Designations

Page 44 of 46

Schlumberger Dowell

11 Tri-Flo - Model 148 SCREEN SERIES:

Tri-Flow

Description:

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

Sources:

Tri-Flow

Comments: Tri-Flo Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 45 of 46

12 Triton NNF Screening Machine SCREEN SERIES:

TSS

Description:

Hookstrip panel, perforated plate with 2 in. openings. Two layers, extra-fine square mesh over square mesh backing cloth. Middle cloth is rectangular mesh in some compositions.

Sources:

Triton Advanced Southwestern

Comments:

Standard screen series for this shaker.

Triton TSS Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Aspect

Trans.


January 1998

Screen Designations

Page 46 of 46

Schlumberger Dowell

Southwestern TSS Replacement Series Screen

U.S.


Flow Capacity

Aspect

Trans.

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

Aspect

Trans.

Advanced TSS Replacement Series Screen

U.S.


Flow Capacity

Name

Sieve

D50

D16

D84

Cond.

Area

Ratio

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

CONFIDENTIAL

Appendix E SOLIDS CONTROL HANDBOOK Schlumberger Dowell

Pump Performance Curves


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. 5. Mission Magnum 1, 6 x 5 x 11 at 1750 rpm. .................................................................3 Fig. 6. Mission Magnum 1, 6 x 5 x 14 at 1150 rpm. .................................................................4 Fig. 7. Mission Magnum 1, 6 x 5 x 14 at 1750 rpm. .................................................................4 Fig. 8. Mission Magnum 1, 8 x 6 x 11 at 1150 rpm. .................................................................5 Fig. 9. Mission Magnum 1, 8 x 6 x 11 at 1750 rpm. .................................................................5 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 Fig. 13. Harrisburg curve no. 2014, 5 x 4 x 14 at 1750 rpm. ....................................................7 Fig. 14. Harrisburg curve no. 2005, 6 x 5 x 11 at 1150 rpm. ....................................................8 Fig. 15. Harrisburg curve no. 2002, 6 x 5 x 11 at 1750 rpm. ....................................................8 Fig. 16. Harrisburg curve no. 2011, 6 x 5 x 14 at 1150 rpm. ....................................................9 Fig. 17. Harrisburg curve no. 2008, 6 x 5 x 14 at 1750 rpm. ....................................................9 Fig. 18. Harrisburg curve no. 2007, 8 x 6 x 14 at 1150 rpm. .................................................. 10 Fig. 19. Harrisburg curve no. 2006, 8 x 6 x 14 at 1750 rpm. .................................................. 10

Fig. 1. 4M-21, BJ 5” at 1750 rpm. CONFIDENTIAL

Appendix E January 1998 Page 2 of 10



Fig. 2. 4M-18, BJ 6” at 1150 rpm.

Fig. 3. 4M-19, BJ 6” at 1750 rpm.

CONFIDENTIAL

Schlumberger Dowell



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


CONFIDENTIAL







CONFIDENTIAL

Schlumberger Dowell





CONFIDENTIAL





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

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

CONFIDENTIAL

Schlumberger Dowell




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

Fig. 13. Harrisburg curve no. 2014, 5 x 4 x 14 at 1750 rpm. CONFIDENTIAL




Schlumberger Dowell











Schlumberger Dowell



Appendix F SOLIDS CONTROL HANDBOOK Schlumberger Dowell

Equipment Specifications


Appendix F. Equipment Specifications Tables Table 1 Table 2 Table 3 Table 4 Table 5 Table 6 Table 7

Oilfield Shale Shakers ................................................................................................2 Oilfield Shale Shaker Classification .......................................................................... 18 Oilfield Centrifugal Pumps........................................................................................ 19 Oilfield Degassers ....................................................................................................26 Oilfield Hydrocyclones.............................................................................................. 33 Oilfield Mud Cleaners ............................................................................................... 44 Oilfield Centrifuges ................................................................................................... 50

CONFIDENTIAL

Appendix F SOLIDS CONTROL HANDBOOK

January 1998

Schlumberger Dowell


Page 2 of 64

Appendix F. Equipment Specifications Table 1 Oilfield Shale Shakers a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)

Overall Dimensions LxWxH (In.)

Weight (lbs)

Comments

5

1

Mfg. & Model

Number of Decks Screens

2

Screen Angles

3

Screen Mfg.

4

Screen Tension

Total 6 Vibrator Screen Vibrator Speed Area (RPM) (Sq Ft)

13

Stroke

7

8 Gas

Acceleration

12

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.


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.


40

B.D.

1380

.18

C

38

79.75x72x52-5/8

2865



50

C

40

114.25x82x55.25

5800

Flowback pan; Variable speed model available.

Total Flow Cleaner

2

4

Adjust Top +3°, +1.5° Btm 0°, -1.5°

O.S.

1425

B.D.

11

1860

CONFIDENTIAL

4.9 4.0

.11

9

11

5.2

9


January 1998


Page 3 of 64 Table 1 (Continued) Oilfield Shale Shakers

a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

9

C

38

60-5/16x66-3/8x25-3/16

1430

Flowback pan.

11

L

43

99.5x71x56.75

4300

Variable angle

9

L

35

110x69x61.5

4180


C

30.5

122x71x53

3700

Duals & Low profiles available.

5

1

Mfg. & Model


2

3

4

Screen Angles

Screen Mfg.

Screen Tension


13

Stroke

7

8 Gas

Acceleration

Retro FS Basket

2

2

Fixed 0°

O.S.


40

B.D.

1620

.14

5.2

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

D.G.B.D.

1765

.068

3.0

2&3: +10° to 0°

N.A.

Btm-P.T.

Top-2

Top Adjust -10° to -4°, -5° to +1°

O.S.

N.P.T. Bonded Spring Loaded

B.D

1760

.12

7

5.3

Btm-3

Btm Adjust 0° to +6°

3

Adjust +3° to -4°

B.D.

1350

.185

4.8

15

ATL-CS

12

16

25.0

Broadbent DT 2000

2

Top-19.0

Bot-26.4

Cagle Ultra-Screen

1

O.S.

N.P.T. Not Spring Loaded

23.3

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 4 of 64

Table 1 (Continued) Oilfield Shale Shakers a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

3.6

L

30.5

122x71x64

4000

5

1

Mfg. & Model

Linear Screen


2

3

4

Screen Angles

Screen Mfg.

Screen Tension


1

3

Adjust +6° to -4°

O.S.


23.3

B.D.

1

3

Adjust 0° to +5°

O.S.

N.P.T. Spring Loaded both sides

27

Direct or Hydraulic

13

Stroke

7

8 Gas

Acceleration

11

12

1325

.160

1740

?

?

L

34

112x60x60

5000

Duals & Low profiles available.

Dahlory 139

1400-2000

145

1

1

Fixed-13°

O.S.


20

B.D.

1750

1/4-3/8?

?

UE

18

84x66x54

2000

245

2

2

Fixed 0°

U.S.


40

B.D.

1500

?

?

C

?

156x84x46

5600


37.5

B.D.

1400

C

33.5

97x73x48

2300

Duals available.

Demco (Discontinued Solids Control Product Line) Tandem Screen

2

2

Fixed-3°

O.S.

3/8. .18

CONFIDENTIAL

11

5.09 5.0

11



January 1998



a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

UE

51.5

118x63x74

4500

Ramp-Lok screen tensioning avail. for all units. Singles available.

UE

31.5

124x57x58

4500


5

1

Mfg. & Model


2

3

4

Total Vibrator Screen Vibrator6 Speed Area (RPM) (Sq Ft)

Screen Angles

Screen Mfg.

Screen Tension

Fixed-20°, -25°, -30°

O.S.


23.3

Fixed-5°, 10°, -15°

O.S.


23.3

13

Stroke

7

8 Gas

Acceleration

12

Derrick Standard

LP

1

1

3

3

I.

3600

.031 .022

I.

1750

11

.100

5.7 4.0

11

4.4

.080

11

3.5

11

Flo-Line Cleaner

1

3

Adjust +6° to 0°

O.S.


23.3

I., I.

1750

.078

11

3.4

11

L

31.5

123x63x57

5000

Duals & triples available. AWD available.

Flo-Line Cleaner (+)

1

3

Adjust +5° to -15°

O.S.


23.3

I., I.

1750

.078

11

3.4

11

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°

O.S.


32.9

I., I.

1750

L

27-44

125.375x91.25x68

6600

Duals & triples available. Deck angles adjustable while drilling.

CONFIDENTIAL

.078

3.4


January 1998

Schlumberger Dowell


Page 6 of 64


b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

5

1

Mfg. & Model


2

Screen Angles

3

4

Screen Mfg.

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

DFE/Solids Control (see N L Baroid) Double Life Corporation Single Tandem Linear

2

2

Adjust +5° to -3°

O.S.


40

B.D.

1750

3/16?

L

38

84x72x62

3300

Low Profile Linear

1

3

Adjust +5° to -1°

O.S.


23.3

B.D.

1750

3/16?

L

26"

117.5x66x58

5000

O.S.

N.P.T.

35.0

I., I.

1728

.123

9

4.2

9

L

49

128x78x56

5100

25.4

I.

1200

.176

3.7

11

L

34

115x66x42

2500

Drexel Oilfield Services, Inc. (see Brandt) Flo-Trend Transition Screen Separator

1

3

Adjust 1:-46° to-39° 2&3: -10 to +6°

(FTS 3600L) Linear Horizontal (LH) Screen Separator (see MTM RLM 28) Fluid Systems, Inc. High Volume Linear Shaker

1

3

Adjust +5° to -5°

N.A.

P.T.

CONFIDENTIAL

Polyester screens available.


January 1998



a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

8

UE

28

68x42x50

1360

8

UE

28

68x54x50

1735

8

UE

30

80x66x50

2100

Dual 45H-400 available.

C

38

68x60x46

2500

Discontinued, parts only available.

C

38

80x72x46

3200

Dual DT & Triple TT available.

5

1

Mfg. & Model


2

Screen Angles

3

Screen Mfg.

4

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

Geolograph-Pioneer (has merged with Swaco) 24H-100

1

1

Fixed-9°

U.S.


8

B.D.

1725

3/16?

7.9 ?

34H-150

1

1

Fixed-9°

U.S.


12

B.D.

1725

3/16?

7.9 ?

45H-200

1

1

Fixed-10°

U.S.


20

B.D.

1725

3/16?

7.9 ?

JT

2

2

Fixed 0°

U.S.


24

B.D.

1350

3/16?

4.9


40

ST

2

2

Fixed 0°

U.S.

8

4.8

B.D.

1350

CONFIDENTIAL

3/16?

11

8

4.9


January 1998

Schlumberger Dowell


Page 8 of 64


b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

5

1

Mfg. & Model


2

3

4

Screen Angles

Screen Mfg.

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

Harrisburg Junior Standard

1

1

Fixed-8°

U.S.


8.3

B.D.

1750

.125?

5.4?

UE

24.5

54-3/4x55.5x43.5

920

Standard

1

1

Fixed-8°

U.S.


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.


40

B.D.

1500

.125

4.0

C

36.75

85-15/16x68.25x52.5

2800

Has flowback pan; dual & triple tandems available.


40

B.D.

1750

.115

40

B.D.

1350

.155

Linear Tandem Retrofit

2

2

Adjust +5° to -3°

O.S

3.5

11

9

4.5

11

L

36.75

85-15/16x65x43.75

3200

11

4.0

11

C

38

80x72x46

3200

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

2

2

Fixed 0°

U.S.


CONFIDENTIAL

Same as Geolograph Pioneer ST.


January 1998



a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

9

UE

30

106x72x49

4500

Same as Totco EVS 24.

Same as Totco EVS 32.

5

1

Mfg. & Model


2

3

4

Screen Angles

Screen Mfg.

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

LP

1

3

Fixed-8.5°, -11.5°, -12.5°,

O.S.


24

B.D.

1750

.113

4.9

Series

1

4

Fixed-15°, -18°, -19°

O.S.


32

B.D.

1750

.113

4.9

9

UE

59

124.5x72x66

4900

HutchisonHayes 2760JR

1

1

Fixed-13°

U.S.


11.3

B.D.

1750

.139

6.1?

UE

34.75

91x47x56

1800

4860-B4

1

1

Fixed-13°

U.S.


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.


20

B.D.

1445

.140

4.4

UE

20-13/16

84x67x38

2100

Dual 4860-EM-DU available.

4860-SuSing

2

2

Fixed-13°

U.S.


40

B.D.

1750

.070

3.1

UE

36-11/16

91x71x56

2800

Dual 4860-SU-DU available.

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 10 of 64


b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

5

1

Mfg. & Model


2

3

4

Screen Angles

Screen Mfg.

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

101

2

2

Adjust -5° to +3°

U.S.


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.


40

B.D.

1492

.167

5.3

C

37-3/16

92x70x45

2500

Dual 202-DT available; flowback pan.

Quadraflow

1

4

Fixed +6°

O.S.


37.7

Direct

1200

.16

3.0

L

31

128x68x56.5

4800

Not available for sale.

1

3

Adjust +2.5° to 5.5°

O.S.


28

I.

1740

.125

L

30

122x70x55

4500

10" flowline connection.

MTM RLM 28

7

4.75

9

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

Double Deck

2

2

2

2

Adjust +3° to -3°

O.S.

Adjust +3° to -3°

O.S.


40


48

B.D.

1303

3/16

4.5 5.0

B.D.

1424

CONFIDENTIAL

Adjust .063--.5 Norm .25

C

37

100x75x47

2600

Tandem SM II available; 10" flowline connection.

C

38

124x84x46

4600

Tandem Double Deck available; 10" flowline connection.

11

11

.063 /1.8 11 .25 /7.2 11 .5 /14.4


January 1998



a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

9

L

30

115x69x54

4500

9

L

37

124x72x48

4200

UE

27

112x44x38

1600

6-position vibrator.

C

37-3/16

92x72x43

2500

Same as HutchisonHayes 201-ST; duals available.

UE

28.5

132x74x54

4800

5

1

Mfg. & Model


2

Screen Angles

3

Screen Mfg.

4

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

Petroleum Solids Control (same as Dahlory 139) Quality Solids Separation Co. Linear Motion Model QLM-1

1

3

Adjust +5° to -5°

O.S.


26.6

I.

1750

.125-.156

3.0-5.5

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

1.3-6.4

Swaco Geolograph Mini-Shaker

1

2

Adjust -3.5° to -7.25°

O.S.


12

B.D.

1750

.101-.026

1.13-4.3

Over/Under

2

2

Fixed 0°

U.S.


40

B.D.

1492

.167

5.3

Super Screen

1

2

Fixed 0°, -5°

O.S.


32

B.D.

1140

.275-.313

5.1-5.8

1150

11

CONFIDENTIAL

9

9

3.3

11

9


January 1998

Schlumberger Dowell


Page 12 of 64


b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

UE

37.75

100x74x45

3700

11,14

L

33.56

128.75x63x58.32

5200

Vibrator angle adjustable from 25° to 65° in 10° increments.

9

C

39.25

91.5x81.5x46.25

2950

Duals & triples available; deck hung on cables; flowback pan.

5

1

Mfg. & Model


2

3

4

Screen Angles

Screen Mfg.

Screen Tension

13


Stroke

7

8 Gas

Acceleration

4.4

12

Super Shaker

1

2

Fixed 0°, -5°

O.S.


24

B.D.

1150

.24

Adjustable Linear Shaker

1

2

Adjust -3° to +3°

O.S.


32

I., I.

1800

?

Single Tandem

2

2

Adjust +2° to -2°

U.S.

N.P.T. Pneumatic

40

B.D.

1460

.21

Full-Flo LM-3

1

3

Adjust 0° to +5°

O.S.

N.P.T.

33.7

B.D.

1735

0-.140 Norm-.094

0-6.0 9 Norm-4.0 11 2.8

L

38

132-1/8x69x71-1/8

5000

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

L

38

132-1/8x69x71-1/8

5500

3.7

Sweco

Oilmizer

TM

6.4 4.0

9

2.8

CONFIDENTIAL

11

11

P.T. Screens secured by pneumatic seal; unit designed to achieve 10% or less oil content on cuttings.


January 1998



a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

Automatic sample catcher. Discontinued.

5

1

Mfg. & Model


2

3

4

Screen Angles

Screen Mfg.

Screen Tension


13

Stroke

7

8 Gas

Acceleration

12

Thompson Tool Co. 10

?

10

UE

23

83x48x39

1475

10

?

10

UE

23

83x38x39

1300

?

10

?

10

UE

26

96x63x48

2300

2000

?

10

?

10

UE

26

96x49x40

1600

B.D.

2000

?

10

?

10

UE

31

96x73x48

2500

B.D.

2000

?

10

?

10

UE

31

96x63x48

2300

A2R

1

1

Fixed-15°

O.S.


8

B.D.

2000

?

B2

1

1

Fixed-15°

O.S.


8

B.D.

2000

?

A3R

1

1

Fixed-15°

O.S.


12

B.D.

2000

B3

1

1

Fixed-15°

O.S.


12

B.D.

A54

1

1

Fixed-15°

O.S.


20

B54

1

1

Fixed-15°

O.S.


20

CONFIDENTIAL




January 1998

Schlumberger Dowell


Page 14 of 64


b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

C

43.75

113-5/8x98.25x53-7/16

6845

Duals & triples available. Bottom P.T. screens secured by hydraulic clamps. Flowback pan.

L

41.8

109x74x54

4905

Duals & triples available. Bottom P.T. screens secured by pneumatic seal. Discharge mud recovery module as standard.

9

UE

30

106x72x49

4500

Dual EVS 48 units were available. Motor vibrate.

9

UE

59

124.5x72x66

4900

Dual EVS 64 & Triple EVS 96 units were available. Motor vibrates.

5

Number of

1

Mfg. & Model

Decks Screens

2

3

4


Screen Angles

Screen Mfg.

Screen Tension

Top-N.P.T. Not Spring Loaded BtmP.T.

46

Top-N.P.T. Not Spring Loaded Btm-P.T.

15

13

Stroke

7

8 Gas

Acceleration

12

Thule Rigtech VSM 120

VSM 100

2

2

2

Adjust

U.S.

Top +11 to -6.5° Btm 0° to +8°

N.A.

5

Fixed

1

Top-0°

O.S. N.A.

4

Btm-0°, 15°

Hydraulic

Variable 1000-2000

.079

Variable 11 1700/3.9 11

1800/4.4

11

1900/4.9 B.D.

1720

.083

3.5

26

Totco (Milchem) (Totco no longer in solids control business.) EVS 24

1

3

Fixed-8.5°, -11.5°, -12.5°

O.S.


24

B.D.

1750

.113

4.9

EVS 32

1

4

Fixed-15°, -18°, -19°

O.S.


32

B.D.

1750

.113

4.9

CONFIDENTIAL


January 1998



a

b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

L

42-1/8

81x76x39

3900

Resonance brakes.

5

1

Mfg. & Model

MudMaster

Number of Decks Screens 2

2

2

3

4


Screen Angles

Screen Mfg.

Screen Tension

Fixed 0°

O.S.


40

I., I.

900

13

Stroke

7

.5

8 Gas

Acceleration

5.8 3.5

9

12

11

Tri-Flo International, Inc. TFI-126

1

2

Adjust -5° to -2°

O.S.


12

B.D.

1750

Adjust .026-.101

1.1-4.4

9

UE

24

93x44x41

1420

Single only.

TFI-134

1

11

Fixed -5°

O.S.


12

B.D.

1750

Adjust .040-.134

1.7-5.8

9

UE

23

93x44x41

1420

Single only.

TFI-146

1

2

Fixed 0°, -5°

O.S.


24

B.D.

1750

Adjust .057-.147

2.5-6.4

9

UE

30.5

98x65.5x38

2575


TFI-148

1

3

Adjust 0° to +5°

O.S.


32

B.D.

1750

?

?

L

18

117x80x50

4300

Singles only.

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 16 of 64


b

c

d

e

f

g

h

i

j

k

l

m

n

o

p

Type Motion

Weir Height (In.)


Weight (lbs)

Comments

L

33

122x68x60

4960

5

1

Mfg. & Model

Triton NNF Screening Machine

Number of Decks Screens 1

3

2

3

4

Screen Angles

Screen Mfg.

Screen Tension

Adjust -1° to +5°

O.S.


Total 6 Vibrator Screen Vibrator Speed Area (RPM) (Sq Ft) 27.4

I., I.

1728

13

Stroke

7

8 Gas

Acceleration

9

5.1

.121

3.7

.125

9

12

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) divided by 70,400. One G = 386 in./sec . Indicated Gs are zero to peak normal to the screen surface.

2

2

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.

CONFIDENTIAL


January 1998


Page 17 of 64

14.

Measured at 80% of maximum eccentricity setting.

15.

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.

CONFIDENTIAL

Appendix F January 1998 Page 18 of 64



Schlumberger Dowell

Table 2 Oilfield Shale Shaker Classification Coarse 10-30 Mesh Brandt Junior Brandt Standard Dahlory 145 Geolograph-Pioneer 24 H-100, 34 H-150, 45 H-200, & JT Harrisburg Junior & Standard Hutchinson Hayes 2760-JR, 4860-B4, 4860-EM, 4860-SU-SING Swaco Mini-Shaker Thompson A2R, B2, A3R, B3, A54, B54 Tri-Flo TFI-126, TFI-134

Medium 40-80 Mesh Brandt Tandem Dahlory 147 Demco Tandem Geolograph-Pioneer ST Harrisburg Tandem Hutchison Hayes 101 & 201-ST NL Bariod SM II Swaco Super Shaker Sweco Tandem Totco EVS 24

Extra Fine 130-325 Mesh Brandt ATL1000 Broadbent DT-2000 Cagle Linear Screen Cagle Ultra-Screen Dahlory 139 Derrick LP Derrick Flo-Line Cleaner Derrick Flo-Line Cleaner (+) Derrick Flo-Line Cleaner Model 58 Double like Single Tandem Linear Double like Low Profile Linear Flo-Trend Transition Screen Separator (FTS 3600L) Flo-Trend Linear Horizontal Screen Separator Fluid Systems High Volume Linear Shaker Harrisburg Linear Tandem Retrofit Hutchison Hayes Quadraflow Quality QLM-1 MTM RLM 28 Schiffner Super Sifter Swaco Adjustable Linear Shaker Sweco Full-Flo LM-3 Sweco Oilmizer Thule VSM 100 Thule VSM 120 Tri-Flo TFI-148 MT Triton 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.

CONFIDENTIAL

Fine 80-120 Mesh Brandt Retrofit FS Brandt Total Flow Cleaner Derrick Standard Flo-Trend Floline Separator NL Bariod Double Deck Oiltools Tandem 800A Swaco Super Screen Totco EVS 32 Totco MudMaster Tri-Flo TFI-146


January 1998


Page 19 of 64 Table 3 Oilfield Centrifugal Pumps1

a Mfg. & Model

b

c

Impeller Size Range (in.)

Casing Design

d Materials of Constr.

e

Lubrication

f

g

Shaft6 Sealing

Shaft Size Coupling End/Thru Packing (in.)

h

i

j

k

l

m

n

Required Impeller Size (in.) & Horsepower for 500 gpm & 75 ft of Head for Various RPM’s Mud Weights Impeller Horsepower (RPM) Size Water 10 ppg 14 ppg 18 ppg

Comments

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

6x8 (6x8x14)

11-14

C.P.

4

Cast Iron, Elastomer 11 Lined

Oil Bath

Circular

Cast Iron, Elastomer 11 Lined

Oil Bath

C.P.

Volute

Cast Iron

Grease

C.P.

4

1-7/8/3.0

>11” 9"

N.A.

N.A.

N.A.

N.A.

1750

1150

18.0

21.5

30.2

38.8

Impeller locked on or threaded. 13 Clockwise rotation only.

1-7/8/3.0

1150

12.25

21

25.2

35.3

45.4

Impeller locked on or threadbare on. 13 Clockwise rotation only.

1-13/16/1-13/16

1150

13.5

14.0

16.8

23.5

30.3

1750

9

15.5

18.6

26.1

33.5

Suction line should never be smaller than suction inlet. Discontinued manufacturing.

1150

13.25

15.5

18.6

26.1

33.5

1750

<10"

N.A.

N.A.

N.A.

N.A.

BJ Hughes3 9

5" (5x6x13.5)

9-13.5

6" (6x8x14.5)

10-14.5

9

Volute

Cast Iron

Grease

C.P.

1-13/16/1-13/16

CONFIDENTIAL

Suction line should never be smaller than suction inlet. Discontinued manufacturing.


January 1998

Schlumberger Dowell


Page 20 of 64

Table 3 (Continued) Oilfield Centrifugal Pumps1 a

b

Mfg. & Model

c


Casing Design


e

Lubrication

f

g

Shaft6 Sealing


C.P., M.S.

1-7/8/1-7/8

h

i

j

k

l

m

n


Comments

Demco3,12 (Demco centrifugal pumps now available from Mattco.) CP 5x6 (5x6x12) 6x8 (6x8x12) 4

8-12

8-12

8

8

XD 5x6x11

8-11.5

5x6x14

10-14

6x8x11 6x8x14

8-11 10-14

Circular

Circular Circular Circular Circular Circular

Cast Iron 11 Std.

Oil Bath

Cast Iron 11 Std.

Oil Bath

Hard Iron Std.

Oil Bath

Hard Iron Std.

Oil Bath

Hard Iron Std.

Oil Bath

Hard Iron Std.

Oil Bath

C.P., M.S. C.P., M.S. C.P., M.S. C.P., M.S. C.P., M.S.

1-7/8/1-7/8 1-7/8/2.5 1-7/8/2.5 1-7/8/2.5 1-7/8/2.5

CONFIDENTIAL

1150

>12”

N.A.

N.A.

N.A.

N.A.

1750

8.5

16.0

19.2

26.9

34.6

1150

12-3/8

17.0

20.4

28.6

36.7

1750

9

24.0

28.8

40.3

51.9

1150

>11.5

N.A.

N.A.

N.A.

N.A.

1750

9

15

18.0

25.2

32.4

1150

12.5

16

19.2

26.9

34.6

1750

<10"

N.A.

N.A.

N.A.

N.A.

1150

<11"

N.A.

N.A.

N.A.

N.A.

1750

9.25

16.5

19.38

27.7

35.7

1150

12.75

18.0

21.6

30.3

38.9

1750

<10"

N.A.

N.A.

N.A.

N.A.

Clockwise rotation only.

13


January 1998


Page 21 of 64 Table 3 (Continued) Oilfield Centrifugal Pumps1

a Mfg. & Model

b Impeller Size Range (in.)

c

d

Casing Design

Materials of Constr.

e

Lubrication

f

g

Shaft6 Sealing


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

h

i

j

k

l

m

Impeller Horsepower (RPM) Size Water 10 ppg 14 ppg 18 ppg

n

Comments

Gorman-Rupp2,3 ID Series 1.5"-6” pumps

4-7/8-11.25

Volute

Cast Iron

Grease, oil

Grease-lubr. seal w/springloaded 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 Series 1.5"-12”,40 Models

5-18

Volute

Cast Iron

Grease, oil

Grease-lubr. seal w/springloaded grease cup

Variable

Flow rates up to 7000 gpm: Heads up to 200 ft.

Designed for dirty water & limited solids-handling appl. Self-priming. Avail. with air cooled or water cooled gasoline or diesel engines. Pumps mounted on pneumatic tires or skid base.

Mud 4 Pumps 6x5x11

8-11

Circular

Cast Iron Casing w/Ductile Iron Impeller

Grease, oil

C.P., M.S.

1-7/8/2.157

CONFIDENTIAL

1150

>11

N.A.

N.A.

N.A.

N.A.

1750

9"

17.0

20.4

28.6

36.7


January 1998

Schlumberger Dowell


Page 22 of 64

Table 3 (Continued) Oilfield Centrifugal Pumps1 a Mfg. & Model

b

c


d

e

Casing Design


Circular

Cast Iron, Ductile Iron, or Alum. Bronze

Oil Bath

Cast Iron, Ductile Iron, or Alum. Bronze

Oil Bath

Ductile Iron

Oil, grease

Lubrication

f

g

Shaft6 Sealing


C.P., M.S.

1-7/8/1-7/8

h

i

j

k

l

m

n


Comments

Harrisburg3,9 178

9-12

5x6 (5x6x12) 6x8

Honcho

9-13.25

10-14

Circular

Circular

C.P., M.S.

C.P., M.S.

1-7/8/1-7/8

1-7/8/2.5

250

1150

>12

N.A.

N.A.

N.A.

N.A.

1750

8.5

16.3

19.6

27.4

35.2

1150

12.5

17.5

21.0

29.4

37.8

1750

<9

N.A.

N.A.

N.A.

N.A.

1150

12.5

17.8

21.4

29.9

38.5

1750

<10

N.A.

N.A.

N.A.

N.A.

1150

13.5

22.9

27.5

38.5

49.5

1750

10.5

29.0

34.8

48.7

62.7

Impeller locking system. Extra Life Package available for abrasive service.

1150

>12

N.A.

N.A.

N.A.

N.A.

All impellers made of ductile iron.

1750

8.5

16.0

19.2

26.9

34.6

Impeller locking system.

5x6 6x8

10-14

Circular

Ductile Iron

Oil, grease

C.P., M.S.

1-7/8/2.5

MCM4,7,12 178 3 Series 5x6 (5x6x12)

8-12

7

Circular

Cast Iron, 11 Hard Iron

Oil Bath

C.P., M.S.

1-7/8/1-7/8

CONFIDENTIAL


January 1998



a

b

Mfg. & Model

c


6x8 (6x8x13)

9-13.25

250 4 Series 5x6x11

8-11.5

5x6x14

10-14

6x8x11 6x8x14

7

d

e

Casing Design


Circular

Cast Iron, 11 Hard Iron

Oil Bath

Ductile Iron

Oil Bath

Circular

Lubrication

f

g

Shaft6 Sealing


C.P., M.S.

1-7/8/1-7/8

C.P., M.S.

1-7/8/2.5

8-11.0 Circular

8-11

Circular

10-14.125

Circular

Ductile Iron Ductile Iron Ductile Iron

Oil Bath Oil Bath Oil Bath

C.P., M.S. C.P., M.S. C.P., M.S.

1-7/8/2.5 1-7/8/2.5 1-7/8/2.5

10-14

h

i

j

k

l

m

Impeller Horsepower (RPM) Size Water 10 ppg 14 ppg 18 ppg 1150

12.5

17.0

20.4

28.6

36.7

1750

9

24.0

28.38

40.3

51.9

1150

>11.5

N.A.

N.A.

N.A.

N.A.

1750

9

15.0

18.0

25.2

32.4

1150

12.5

15.1

18.1

25.4

32.6

1750

<10

N.A.

N.A.

N.A.

N.A.

1150

>11

N.A.

N.A.

N.A.

N.A.

1750

9.25

17.0

20.4

28.6

36.7

1150

12.75

18.0

21.6

30.3

38.9

1750

<10

N.A.

N.A.

N.A.

N.A.

1150

>12

N.A.

N.A.

N.A.

N.A.

1750

9.5

16.9

20.3

28.4

36.5

1150

12-3/8

17.1

20.5

28.7

37.0

1750

9

24.0

Mission - Fluid King Oilfield Products Type 3,4,7,12 W 13 5x6 R&C 13

6x8 R

8-12

7

9-13.25

Circular

7

Circular

11

Cast Iron

11

Cast Iron

Grease

Grease

C.P.

C.P.

1-7/8/1-7/8

1-7/8/1-7/8

CONFIDENTIAL

n

Required Impeller Size (in.) & Horsepower for 500 gpm & 75 ft of Head for Various RPM’s Mud Weights Comments All impellers made of ductile iron. All 250 Series impellers are open design and right hand rotation only.


January 1998

Schlumberger Dowell


Page 24 of 64

Table 3 (Continued) Oilfield Centrifugal Pumps1 a

b

Mfg. & Model


c Casing Design

d

e


Lubrication

f

g

Shaft6 Sealing


h

C.P., M.S.

1-7/8/2.5

i

j

k

l

m

n


Comments

Magnum 13,4,7 6x5x11 6x5x14

11-14 10-14

Circular Circular

11

Cast Iron

11

Cast Iron

1-7/8/2.5

C.P., M.S.

1-7/8/2.5

11

Grease, oil

C.P., M.S.

1-7/8/2.5

Circular

Cast Iron

8x6x14

10--14-1/8

Circular

Cast Iron

Circular

C.P., M.S.

Grease, oil

8-11

12-14

Grease, oil

11

8x6x11

10x8x14

Grease, oil

11

Cast Iron

Grease, oil

C.P., M.S.

1-7/8/2.5

1150

>11.5

N.A.

N.A.

N.A.

N.A.

1750

9.0

15.0

18.0

25.2

32.4

1150

12.5

15.6

1750

<10

N.A.

N.A.

N.A.

N.A.

1150

<11

N.A.

N.A.

N.A.

N.A.

1750

9.25

16.7

20.0

28.1

36.1

1150

13-1/8

20.7

24.8

34.8

44.7

1750

10

26.0

31.2

43.7

56.2

1150

14

26.4

31.7

44.4

57.0

1750

<12

N.A.

N.A.

N.A.

N.A.

Clockwise rotation only.

Thompson Tool Co.3,4,7,12 Type F Packless 13 5x6 R&C

8.5-10.5

Circular

Hard Iron Std.

Grease

Packless

1.75/N.A.

10

1750

8.5

16.4

19.7

27.6

35.4

13

8.5-10.5

Circular

Hard Iron Std.

Grease

Packless

1.75/N.A.

10

?

?

?

?

?

?

6x6 R&C

CONFIDENTIAL

Type FS Packless self-priming pumps also available in 5" and 6" sizes.


January 1998



a

b

Mfg. & Model


c Casing Design


e

Lubrication

f

g

Shaft6 Sealing


h

i

j

k

l

m

n


Comments

A. R. Wilfley & Sons, Inc.4,11 ES 6x4 8x6

13 2" diam range

Volute

17 2" diam range

Volute

Hard Iron Std.

Oil Bath

Hard Iron Std.

Oil Bath

N.A.

10

N.A.10

2.12/N.A.

10

2.38/N.A.10

1150

13" gives 82' TDH and requires 17 HP

1750

13" gives 196' TDH and requires 52 HP

1150

Packingless design; available in a variety of metals and elastomers. Closed impeller design. Packingless design; available in a variety of metals and elastomers. Closed impeller design.

1750

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

7.

Cutdown impellers available in 1/8” increments.

1.

All horizontal-type mounted on pedestal or frame except as indicated.

8.


2.

Vertical centrifugal pumps available.

9.


3.

All impellers of semi-open design.

10.

N.A. means “not applicable.”

4.

Impeller has expeller vanes on back side.

11.

Also available in more wear-resistant metals.

5.

Pumps are elastomer lined.

12.

Available in both clockwise and counterclockwise rotation.

6.

C.P. means “conventional packing”; M.S. means “mechanical seal.”

13.

R means “clockwise rotation from drive end” and C means “counterclockwise rotation from drive end.”

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 26 of 64

Table 4 Oilfield Degassers a

b

Mfg. & Model

Type1

c Nominal 2,3 Flow Rate (gpm)

d Vacuum5 Range (in. Hg)

Overall Dimensions LxWxH (in.)

Weight (lbs)

Comments

Brandt DG-5

4

2

Vacuum emptied by jet pump.

500

7-20 max 29

88x54x62

2390

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


1000

7-20

100x60x77

3900

Mud flows over seven stacked conical baffles (32060 in area). Jet pump requires 75 ft feed head.

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.

Magna-Vac 1000 Vacuum emptied by self-contained centrifugal pump.

1000

10"

44" diam x 73" ht

1475

20 HP motor. Portable unit breaks down into two pieces weighing 875 and 600 lbs respectively.

DG-10

4

2

Burgess & Associates Mfg., Inc. Magna-Vac 500

CONFIDENTIAL


January 1998


Page 27 of 64 Table 4 (Continued) Oilfield Degassers

a

b


Vacuum5 Range (in. Hg)


Weight (lbs)

Vacuum emptied by self-contained centrifugal pump.

1000

10"

44" diam x 58" ht

875

20 HP hydraulic motor. Portable.

Magna-Vac 1500 Vacuum emptied by self-contained centrifugal pump.

1000

15"

44" diam x 73" ht

1675

20 HP drive motor and 5 HP vacuum booster. Portable.

Type1

Mfg. & Model

Magna-Vac 1000 H

d Comments

Demco (Discontinued Solids Control Product Line - Model 600 degasser taken off market in early 1980's.) Derrick Equipment Co. Vacu-Flo 500

4

Vacu-Flo 1000

4

Vacuum emptied by jet.

500

Vacuum emptied by jet.

1000

7-20 max 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 locking. Except for top outlet, bolt-on access door, and corrugated baffles, the Vacu-Flo 500 is a copy of the Brandt DG-5.

7-20

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.

max 29

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.)

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 28 of 64

Table 4 (Continued) Oilfield Degassers a Mfg. & Model

b


Type1



Weight (lbs)

Comments

Hutchison-Hayes Intl, Inc. (Discontinued marketing Rhumba Vac-Degasser about 1986.) Smith International (Drilco) See-Flo Standard Pit

Atmospheric filled by patented centrifugal pump.

700

None

69x?x90.5

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 patented centrifugal pump.

700

None

69x?x114.5

1200

10 HP motor.

2000

30 HP motor.

See-Flo Big Volume

(Discontinued this model during early 1980's)

Swaco D-Gasser 4 Horizontal


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 4 Vertical


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.

CONFIDENTIAL


January 1998



a Mfg. & Model

b




Weight (lbs)

Comments

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.

Atmospheric filled by centrifugal pump action.

1400 w/water

none

57.5x46.5x104

2400

25 HP motor.

Vacuum emptied by centrifugal 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.

Type1

Hurricane CD-800 Atmospheric filled by centrifugal pump action.

Hurricane CD1400

d

Sweco DG-2

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


1000

8-15

144x42x60

CONFIDENTIAL

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 Horizontal D-Gasser except vessel is slightly larger in diameter and vacuum pump and motor both located on the skid.


January 1998

Schlumberger Dowell


Page 30 of 64

Table 4 (Continued) Oilfield Degassers a

b

Mfg. & Model

Type1




<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.

10-26

76x72x72

2200

Unit has microprocessor which monitors oil pressure inside the vacuum pump, liquid 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 limits, 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.

Weight (lbs)

Comments

Thule Rigtech (Thule markets the Burgess Degasser.) Tillett Tool Co. Gas Hog

Atmospheric filled by impeller pump.

800-1000 800 optimum

Totco (Discontinued Solids Control product Line.) 4

TSC-500 A

Vacuum emptied by jet pump fed by selfpriming centrifugal pump.

500 w/water

27 max

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 4 Degasser


600

Max 13

48x48x95

CONFIDENTIAL

2600

Gas separated by vacuum over baffle plates. Gas being separated used to equalize 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.


January 1998



a

b



d Overall Dimensions LxWxH (in.)

Weight (lbs)

Mfg. & Model

Type1

Horizontal 4 Degasser


1200

Max 13

171x43x72

3900

Gas separated by vacuum over angled baffle plates.

Comments

Well Control 8200

4


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 separated over cone and inverted cone reversing flow baffles. Unit must be started before gas cut mud appears to prevent gas locking.

6200

4


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 separated over cone and inverted cone reversing flow baffles. Unit must be started before gas cut mud appears to prevent gas locking.

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.

3200

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 32 of 64

Table 4 (Continued) Oilfield Degassers a

b

Mfg. & Model

5200

4

Type1




d Overall Dimensions LxWxH (in.)

Weight (lbs)

Comments

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 2 under vacuum over four stacked conical baffles (9328 in ). 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 nozzle. 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.

CONFIDENTIAL


January 1998


Page 33 of 64 Table 5 Oilfield Hydrocyclones1

a

b

Mfg. &1 Model

Cone Diam. (in.)

c Inlet Type

d Cone Construction

e

f

g

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

Polyurethane

4

Fixed .125 & cutoff to .75"

6,45

1.25" Victaulics on inlet and overflow, 3-piece cone

4"

4.0


Polyurethane

4

Adjust .125 to .50"

50,75

2" Victaulics on inlet and overflow, 2-piece cone

5"

5.0

Circular Tangent

Polyurethane

4

Adjust .25 to .75"

80,75


5"

5.0

Circular Tangent

Polyurethane

4

Adjust .25 to .75"

80,75

2" Flange on inlet; 2" Victaulic on overflow, 2-piece cone

10"

10.125

Rectangular Involute

Polyurethane

4

Adjust .75 to 1.25"

500,75


Baker 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, 3238 psi

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

CONFIDENTIAL


January 1998


Page 34 of 64

Schlumberger Dowell

Table 5 (Continued) Oilfield Hydrocyclones1 a

b

c

Cone Diam. (in.)

Mfg. &1 Model

Inlet Type

d Cone Construction

e

f

g




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.) 2

2

3"(600-3)

3

Circular Tangent

Nylon

Fixed .125 and cut off to .75"

20,92

17 gpm at 75 ft head Threaded

6"(606-110)

6

Circular Tangent

Nylon

Fixed .25 and cut off to 1.125"

110,80

12"(623-4)

12

Circular Tangent

Stainless Steel

Fixed 1.0 and cut off to 2.75"

650,115

2

2

108 gpm at 75 ft head Victaulics 2

2

400 gpm at 75 ft head Victaulics or Flanges

Brandt (Division of Drexel Oilfield Services, Inc.) 2"

?

?

Polyurethane?

Fixed?

20,75

4"

3.9


Polyurethane?

Adjust .125 to .69"

66,75

12"

12.2

Circular Involute

Polyurethane?

Fixed 1.5, 1.75, 2.125"

492,75

CONFIDENTIAL

?2-piece cone, victaulics on feed and overflow, ceramic insert molded into apex, manifolds available with 4-24 cones

2

2-piece cone, victaulics on feed and overflow, manifolds available with 1, 2, or 3 cones in either vertical or slant mounting 2

3-piece cone, victaulics on feed and overflow, manifolds available with 1, 2, or 3 cones in either vertical or slant mounting


January 1998


Page 35 of 64 Table 5 (Continued) Oilfield Hydrocyclones1

a

b

c

Cone Diam. (in.)

Mfg. &1 Model

d

Inlet Type

Cone Construction

e

f

g




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, 2piece 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

Polyurethane

4

Adjust .25 to .50"

15,75

All 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.

4

Adjust .25 to .56"

50,75

Polykineticurethane bottom liner, screws together, 2-piece cone, in-line or circular manifolds available, 2" valves on inlets, victaulics on inlet and overflow, manifolds available with 6-20 4" cones

3" (same as MPE 3" 50 gpm cone with rectangular tangent entry) 4"

3.813

Circular Tangent Ramp

Polyurethane

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


Polyurethane

4

Adjust 0 to .625"

CONFIDENTIAL

2

62,75

Victaulics on feed and overflow, 2-piece cone, manifolds available with 4-20 4" cones


January 1998


Page 36 of 64

Schlumberger Dowell


b Cone Diam. (in.)

Mfg. &1 Model

5"

c

4.9

Inlet Type


d Cone Construction

Polyurethane

e

f

g




4

Adjust 0 to .625" 0 to .750"

102,75

2

4

Adjust 0 to .75"

50,75

Manifolds available with 8-24 cones, victaulics on feed and overflow, 2-piece cone

4

Adjust 0 to .75"

80,75

Manifolds available with 8-20 cones, flange on inlet and victaulic on overflow, 2-piece cone

4

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

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

Polyurethane

5"

4.875

Circular Tangent

Polyurethane

10"

10.0


Polyurethane

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


Polyurethane

Fixed 1, 1.25, 1.50"

500,75

Manifolds available with 1-4 cones, victaulics on inlet and overflow, 3-piece cone

Fixed .080"

5,75

All cones designed and developed by Amoco's Grant Young, brass snaplocks on inlets and overflows, 2-piece cone

Hydro-Separation Systems, Inc. (Now MPE) 1"

1.0

Rectangular Tangent

Polyurethane

4

CONFIDENTIAL


January 1998



a

b Cone Diam. (in.)

Mfg. &1 Model

c Inlet Type

d Cone Construction

e

f

g




3"

3.0

Rectangular Tangent

Polyurethane

4

Fixed .24, .30, .40, .50, .60"

32,75

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

3"

3.0

Rectangular Tangent

Polyurethane

4

Fixed .24, .30, .40, .50, .60"

50,75

2-piece cone

3"

3.0


Polyurethane

4

Fixed .24, .30, .40, .50, .60"

50,75

Fits Brandt 4" cone manifolds, 2-piece cone

U4”

3.9


Polyurethane

4

Adjust 3.75 to 1.063" Fixed .375 and cut off to 1.5"

86,75

U4B”

3.9


Polyurethane

4

Same as U4”

91,75

Same as U4”

180,75

Krebs Engineers 2

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

2

Same as above

PU6”

6.0


Polyurethane

4

TU10” 3.25" 2 vortex 6.3 in inlet

10.0


Polyurethane

4

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

390,75

TU10” 4" vortex 2 9.52 in inlet

10.0


Polyurethane

4

Same as TU10” above

600,75

CONFIDENTIAL

2

Same as above

2

Victaulic connections on inlet, and overflow. Replaceable, fixed and adjustable apexes in various sizes. Ceramic apexes also available.

2

Same as above


January 1998


Page 38 of 64

Schlumberger Dowell


b Cone Diam. (in.)

Mfg. &1 Model

c Inlet Type

d Cone Construction

e

f

g




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 manifolds available with 6, 8, m 12, or 16 5" cones

10"

10.1


Polyurethane?

? to 1.3

500,75

Victaulics on inlet and overflow, 3-piece cone manifolds 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

Polyurethane top section & aluminum alloy body with polyurethane liner

Adjust .25 to .625"

50,75

Retrofit the Pioneer Siltmaster 4" and Economaster 4" cones and Sweco 4" cone, manifolds available with 4-24 4" cones, victaulics on inlet and overflow

Permathane Ind. (see Wren Sales (92) Ltd.) Quality Solids Separation Co. 4" Model 240

3.813

Rectangular Tangent

CONFIDENTIAL


January 1998



a

b Cone Diam. (in.)

Mfg. &1 Model

c Inlet Type

d Cone Construction

e

f

g




6" Model 260

6.0

Rectangular Tangent

Polyurethane top section with aluminum alloy body with polyurethane liner

Adjust .5 to 1.0"

100,75

Retrofit the Pioneer Sandmaster 6" or Economaster 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 nipple, cone liner and vortex finder made of hycar rubber, apex lined with polyurethane

Fixed 1.75, 2.0, 2.25"

500,75

Retrofits 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

4H

4.87

Circular Tangent

Polyurethane

.69, .44, .3, .2"

76,75

8"

6.95

Circular Tangent

Cast Iron

.73, .44, .3, .2"

156,75

4

CONFIDENTIAL

2

Flanged inlet and victaulic on overflow, manifolds available with 2-24 cones Flanged inlet, victaulic on overflow, orifice control plate. Also available in ductile iron. Manifolds available with 2-24 cones Flanged inlets, overflow manifolds available with 1-8 cones, available in either vertical or inclined mounting


January 1998


Page 40 of 64

Schlumberger Dowell


b Cone Diam. (in.)

Mfg. &1 Model

c Inlet Type

d Cone Construction

10"

10.2


Polyurethane

12"

12.81

Circular Tangent

Cast Iron

4

e

f

g




1.5" Fixed

640,75

3-piece cone with victaulics on inlet and overflow manifolds available with 1-4 cones

Adjustable Valve

400,75

Orifice control valve, manifolds available with 1-4 cones in either vertical or inclined mounting

Fixed .25"

25,125

20-cone manifolds Ceramic liner in apex, 20-cone manifolds

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

1.97 50 mm

Rectangular Tangent

Ceramic

2" Microclone

2.3

Rectangular Tangent

Polyurethane

4

Fixed .5"

25,125

4" Twin Cone

4.04

Rectangular Tangent

Polyurethane

4

Fixed .375 (most common) .5, .625"

69,91

Circular Tangent

Polyurethane

4

Fixed .5, .75 (most common) 1.25, 1.5"

500,75

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

22,75

All cones have victaulics on inlet and overflow, all Economaster cones have an aluminum bottom with a replaceable polyurethane liner

Bit Nozzle

Double 12"

12.1

2

2

63 gpm at 75 ft feed head , manifolds available with 8-20 4" cones

Cones formerly available from Geolograph Pioneer 3" Solidsmaster

Cast Iron

CONFIDENTIAL


January 1998



a

b Cone Diam. (in.)

Mfg. &1 Model

c Inlet Type

d Cone Construction

e

f

g




4

3" Economaster

3.0

Square Tangent

Polyurethane

4" Siltmaster

3.75

Circular Tangent

Cast Iron

22,75 2

Manifolds available with 4-24 4" cones, 2-piece cone

2


Adjust .25 to .625"

48,75

Adjust .25 to .625"

48,75

Adjust .25 to .75"

80,75

Adjust .5 to 1.0"

100,75

Adjust up 1.0"

100,75


Fixed 1.75, 2.0, 2.25"

500,75

Manifolds available with 1-4 cones, 3-piece cone

4

Adjustable .75 to 2.25"

500,75

Manifolds available with 1-4 cones, 3-piece cone

4

Adjust 0 to .620"

52,75

Manifolds available with 8-20 cones, 2-piece cone, victaulics on inlet and overflow

4

Adjust 0 to .685"

80,75

78 gpm at 60 ft feed head , manifolds available with 23 or 16 cones, flange on inlet and victaulic on overflow, 2-piece cone

4

Variable to 1.5"

500,75

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

4" Economaster

3.75

Circular Tangent

Polyurethane

4

4" HV Economaster

3.75


Polyurethane

4

6" Sandmaster

6

Circular Tangent

Cast Iron

6" Economaster

6

Rectangular Tangent

Polyurethane

12" Volumemaster

12.0

Circular Tangent

Cast Iron

12" Economaster

11.75

Rectangular Tangent

Polyurethane top

4"

3.785

Circular Tangent

Polyurethane

5"

4.875

Circular Tangent

Polyurethane

10"

10.0

Rectangular Volute

Polyurethane

4


Sweco

CONFIDENTIAL

2

2

2


January 1998


Page 42 of 64

Schlumberger Dowell


b

c

Cone Diam. (in.)

Mfg. &1 Model

Inlet Type

d Cone Construction

e

f

g




Thompson Tool Co. 2

4"

4.25

Circular Tangent

Cast Iron w/liner

Automatic Adjust 0 to .625"

50 psi

40 gpm at 60 ft feed head . Circular manifold, flanges on 45 gpm at 75 ft 2 2 feed head inlet and overflow, manifolds 50 gpm at 90 ft feed head 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 head Circular manifold, flanges on 187 gpm at 75 ft head 2 inlet and overflow, manifolds 196 gpm at 90 ft head with 1-4 8" cones

4" PH4/LV

?

?

Polyurethane?

Adjust?

50,75

Victaulics on inlet and overflow, 2-piece cone

4" PH4/HV

?

?

Polyurethane?

Adjust?

80,75


2

Thule Rigtech

Totco (No longer in solids control business) Tri-Flo International, Inc. 2"

2.0

Rectangular Tangent

Polyurethane

4

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

Polyurethane

4

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

CONFIDENTIAL

2


January 1998



a Mfg. &1 Model

b Cone Diam. (in.)

c Inlet Type

d Cone Construction

e

f

g




Wren Sales (92) Ltd. (Cones originally available from Permathane and then subsequently Morganite Canada, Inc.) 2"

2.35

Circular Tangential Ramp

Polyurethane

4

Fixed .2 to .375"

16,65-70

Victaulics on inlet and overflow, 3-piece cone, 17 gpm at 75 ft feed head

4"

4.06


Polyurethane

4

Adjust 0 to .625"

39,75

Victaulics on inlet and overflows, 2 and 3-piece cones available

5"

5.00


Polyurethane

4

Adjust 0 to .625"

86,90

Victaulics on inlet and overflows, 3-piece cone, 78 gpm at 75 ft feed head

10"

10.25

Rectangular Volute Ramp

Polyurethane

4

Adjust .5 to 1.5"

585,75


2

2

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.

CONFIDENTIAL

2


January 1998

Schlumberger Dowell


Page 44 of 64

Table 6 Oilfield Mud Cleaners a

b

Mfg. &1 Model Manifold1

c

d

e

f

No.

Size2 (in.)

Rec. Head (ft)

Capacity (gpm)

g

h Number of

Decks

i

j

k

l

m

n

o

Screen3 Angles

Screen4 Mtg.

Screen5 Tension

Total Area (sq. ft)

Screen Vibrator6

Speed (rpm)

Comments

1356

Reflux line, feed gauge, siphon breaker standard. Self-cleaning sliders standard.

Screens

Brandt (Division of Drexel Oilfield Services, Inc.) Mud Cleaner

1

8

4” PU

75

400

1

1

Fixed 0°

N.A.

P.T.

45x52”=16.25

B.D.

4" PU

80

8(87)=696

1

1

Fixed-5°

N.A.

P.T.

16

I.

2

2

Fixed-5°

N.A.

P.T.

32

I.

1

1

0-10°

O.S.

N.P.T. Spring Loaded

11

B.D.

1400

O.S.


11

B.D.

1400

Chronaloy (No longer available) Mud Cleaner

R

8

1800/3600 Individual cone overflows each with siphon breaker, 1800/3600 Krebs cones. Rotex shaker. Victaulic connections on all cones.

Demco Siltrite (now available from RETSCO) 4MC6

I

6

4"H

90-100

C.I.

4MC8

I

8

4"H C.I.

480_14 ppg 240 14-18 ppg

90-100

600014 ppg

Adjust 0 to -10°

1

1

Adjust 0 to -10°

300 14018 ppg

CONFIDENTIAL

Cone inlets flanged, Victaulics on overflow, see units available with either metal or urethane cones. Cone inlets flanged.


January 1998


Page 45 of 64 Table 6 (Continued) Oilfield Mud Cleaners

a

b

1

Mfg. & Model Manifold

c 1

No.

d

e 2

Size (in.)

Rec. Head (ft)

f

g

Capacity (gpm)

h Number of

Decks 4MC10

I

10

4"H

90-100

C.I. 4MC12

I

12

4"H

I

14

4"H

90-100

I

16

4"H

90-100

Screen Angles

Screen Mtg.

1120014 ppg

90-100

1280014 ppg

l

m

n

o

Screen Tension

Total Area (sq. ft)

Screen Vibrator6

Speed (rpm)

Comments

5

Screens

1

1

Adjust 0 to -10°

O.S.


16.5

B.D.

1400

Cone inlets flanged.

1

1

Adjust 0 to -10°

O.S.


16.5

B.D.

1400


1

1

Adjust 0 to -10°

O.S.


22

B.D.

1400


1

1

Adjust 0 to -10°

O.S.


22

B.D.

1400


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

15.53

I.

1750

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

23.3

I.

1750

32.9

I.

1750

560 14018 ppg

C.I. Derrick

960014 ppg

k 4

480 14018 ppg

C.I. 4MC16

j

400 14-18 ppg

C.I. 4MC14

800014 ppg

i 3

640 14018 ppg

R

8

4" PU

75

8(50)=400

1

2

Adjust -1° to +5°

O.S.

R

16

4" PU

75

16(50)=800

1

3

Adjust -1° to +5°

O.S.

R

20

4" PU

75

20(50)=1000

1

3

Adjust -1° to +5°

O.S.

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 46 of 64

Table 6 (Continued) Oilfield Mud Cleaners a

b

1


c 1

No.

d

e 2

Size (in.)

Rec. Head (ft)

f

g

Capacity (gpm)

h Number of

Decks Geolograph Pioneer Mud Cleaner (now Swaco Geolograph)

i

j

k

3

4

Screen Angles

Screen Mtg.

l

m

n

o

Screen Tension

Total Area (sq. ft)

Screen Vibrator6

Speed (rpm)

Comments

5

Screens

R

16

4"

75

16(50)=800

1

1

Fixed 0°

N.A.

P.T.

12.57

B.D.

0-1450

R

16

4"HV

75

16(80)=1280

1

1

Fixed 0°

N.A.

P.T.

12.57

B.D.

0-1450

All Economaster cones with plastic upper and urethane lined aluminum lower section. Head gauge. All cones have victaulic connections. Screens interchangeable with Sweco. All units variable speed, variable eccentricity.

R

8

6"

75

8(100)=800

1

1

Fixed 0°

N.A.

P.T.

12.57

B.D.

0-1450

R

16

3" PU

75

16(22)=352

1

1

Fixed 0°

N.A.

P.T.

12.57

B.D.

0-1450

Harrisburg Mud Cleaner MC-800

I

10

5" PU

75

10(80)=800

1

1

Fixed -4°

O.S.

B.D.

1500

5" cone inlets flanged.

Hutchinson Hayes Rhumba Mud Cleaner

I

10

5" PU

75

10(80)=800

1

2

Fixed -6°

O.S.


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.


12

B.D.

1610

All cones have victaulic connections on feed & overflow.

CONFIDENTIAL

42x60 = N.P.T. 2520 in2 17.5 Spring Loaded both


January 1998



a

b

1


c 1

No.

d

e 2

Size (in.)

Rec. Head (ft)

f

g

Capacity (gpm)

h Number of

Decks Oiltools Mud Cleaner

I

8

4" PU

75

400

1

i

j

k

3

4

Screen Angles

Screen Mtg.

Fixed 0°

N.A.

l

m

n

o

Screen Tension

Total Area (sq. ft)

Screen Vibrator6

Speed (rpm)

Comments

P.T.

12.57

I

1800

5

Screens 1

Self-cleaning sliders.

1500

Quality Solids Separation Co. Mud Cleaner Model Q48R

1

8

6" PU

75

800

16

4" PU

75

800

1

1

Fixed 0°

N.A.

P.T.

12.5

B.D.

1200 1750

All cones have victaulics on feed and overflow. All cones have flanged inlets.

Swaco Mud Cleaner 4T4

I

8

4" PU

96

600

1

1 or 2

O.S.


12

B.D.

1750

Mini-Shaker

6T4

I

12

4" PU

96

850

1

1 or 2

O.S.


12

B.D.

1750

Mini-Shaker

6T4SS

I

12

4" PU

96

950

1

2

Fixed 0°, -5°

O.S.


32

B.D.

1140

Super Screen

16

4" PU

96

1200

1

2

Fixed 0°, -5°

O.S.


32

B.D.

1140

8T4SS

CONFIDENTIAL

Super Screen


January 1998

Schlumberger Dowell


Page 48 of 64

Table 6 (Continued) Oilfield Mud Cleaners a

b

1


c 1

No.

d

e 2

Size (in.)

f

Rec. Head (ft)

g

Capacity (gpm)

h Number of

Decks Sweco Mud Cleaner

I

8

4" PU

9.0/35

7

8(50)=400

11.0/40

i

j

k

3

4

Screen Angles

Screen Mtg.

l

m

n

o

Screen Tension

Total Area (sq. ft)

Screen Vibrator6

Speed (rpm)

Comments

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

5

Screens

1

1

Fixed 0°

N.A.

P.T.

12.57

I

1800

2

2

Fixed 0°

N.A.

P.T.

25.14

I

1800

1

2

Adjust 4.5" up on discard end.

N.A.

P.T.

16.0

H.M.D.

18.0/55 Thule VSM 200

I

8

4" PU

75

400

16

4" PU

800

16

4" PU

1280

6

900-2000

Upper deck can be added for saving LCM. 4“ Pioneer Economaster fitted at customer's request. EVS 24 shaker. Victaulic connection on cone inlet and overflow.

Totco (Milchem) Mud Cleaner

I

10

4" PU

75

500

1

3

Fixed -8.5°, -11.5°, -12.5°

O.S.


24

B.D.

1750

Totco (Milchem) MudMaster Mud Cleaner

I

10

4" PU

75

500

2

2

Fixed 0°

O.S.


40

I., I.

900

I

8

4" PU

1

2

Adjust -5°

O.S.


6

B.D.

1750

Tri-Flo Fluid Separators TFI-8

20 psi

520

for any mud weight

to +2°

CONFIDENTIAL

Feed inlet valves and individual overflows with control valves.


January 1998



Mfg. &1 Model Manifold1

No.

Size2 (in.)

Rec. Head (ft)

Capacity (gpm)

Number of Decks

TFI-16

I

16

4" PU

20 psi

1040

Screen3 Angles

Screen4 Mtg.

Screen5 Tension

Total Area (sq. ft)

Screen Vibrator6

Speed (rpm)

Comments

Screens

1

2

Fixed 0°, -5°

O.S.


12

B.D.

1750

Victaulic connections on cone inlets and overflows.

1

3

Adjust -1° to +5°

O.S.

N.P.T. NonSpring Loaded

27.4

I., I.

1728

Triton NNF Screening Machine with bolt-on 16-cone desilter.

for any mud weight

Triton Linear Mud Cleaner

I

16

3"-5”

75

3"-800 4"-800 5"-1280

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.

CONFIDENTIAL


January 1998


Page 50 of 64

Schlumberger Dowell

Table 7 Oilfield Centrifuges a Mfg. & Model1

b

c

Bowl Size Rotating2 Assembly Materials (in.) of Construction

d

e

f

g

h

i

j

k

Bowl/Conveyor Differential

Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Mud4 Pump

Capacity6 Mud Wt/GPM.

Comments

Adjust w/single lead conveyor

57/1

1500-3400

1500/447 2500/1243 3400/2299

E

P.D.


57/1

1500/447

E


57/1

Alfa-Laval 414

418

14"x36” Contour

SS

14"x56” Contour

SS

14"x56” Contour

SS

1500-3400

14.0/60 P.D.

2500/1243 0-4000

2000/795

9.0/150 11.0/100

3400/2299 418

9.0/100 11.0/80

14.0/70 E

P.D.

9.0/150

3000/1790

11.0/100

4000/3182

14.0/70

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

18"x28” Conical

CS Standard

Fixed with double lead conveyor

80/1

1300-1800

1300/432 1800/828

DH, EH

P.D.

9.0/45 12-14/20 14-16/15 >16/10

CONFIDENTIAL


January 1998


Page 51 of 64 Table 7 (Continued) Oilfield Centrifuges

a Mfg. & Model1 High Volume Centrifuge

b

c

Bowl Size Rotating2 (in.) Assembly Materials of Construction 24"x38”

CS Standard

Contour

d

e

f

g

h

i

j

k


Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Mud4 Pump


Comments

1500/767

E

P.D. or Centrifugal

Fixed with single lead 140/1 or 80/1 conveyor

Variable 1000-2500

1800/1104

17.0/10 9.0/25-150

2300/1803 2500/2/31 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 Derrick. Bird offers a variety of centrifuges applicable to the oilfield. Broadbent, Inc. Compact Unit

18"x28”

CS Standard

Contour


80/1

1000-2400

1000/256

E

P.D.

10.0/65

E

P.D.

10.0/130

1500/575 2000/1022 2400/1472

High Volume Standard

24"x38”

CS Standard

Fixed with double lead 130/1 or 80/1 conveyor

1000-2400

1000/341 1500/767 2000/1363 2400/1963

CONFIDENTIAL

Options available for all Broadbent centrifuges include variable bowl speeds, variable bowl/conveyor differentials, and a choice of abrasion protection materials for conveyors.


January 1998

Schlumberger Dowell


Page 52 of 64

Table 7 (Continued) Oilfield Centrifuges a Mfg. & Model1

b

c

Bowl Size Rotating2 (in.) Assembly Materials of Construction

d

e

f

g

h

i

j

k


Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Mud4 Pump


Comments

Fixed 2300

2300/451

D or E

P.D.

15-28 gpm

Same as Totco RMS Centrifuge, except Rotosep has tungsten carbide seals.

1600-2000

1600/654

E

1650/696

P.D. or Centrifugal Pump

unwtd/100

Rec 1650 usually

Manufactured by Bird Machine Co.

Brandt (Division of Drexel Oilfield Services) Rotosep

1

CF-1

2

2

6" rotor

CS Standard

N.A.

N.A.

18"x28”

CS

Fixed with single lead conveyor

40/1

Contour

2000/1022

9.0/90 12.0/60 16.0/30 18.0/25

CF-2

24"x38”

CS

Contour


80/1

1400-2000 Rec 1450 usually 1900

1400/668

E

2000/1363

P.D. or Centrifugal Pump

unwtd/175 9.0/150

Manufactured by Bird Machine Co.

12.0/60 16.0/30 18.0/25

HS-3400

14"x49.5” Contour

SS Standard


52/1

1750-4000

1750/609

2900 normally

2400/1145

12.0/85

2900/1672

15.0/25

3500/2435

18.0/15

4000/3181

CONFIDENTIAL

E

P.D.

9.0/140

Manufactured by Sharples. Patented tungsten carbide tiling on conveyor for abrasion resistance.


January 1998



Mfg. & Model1



Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Mud4 Pump



130/1 or 80/1

1000-3200

1000/312

E

P.D.

10.0/230

Comments

Broadbent, Inc. High Volume High Speed

22"x54”

CS Standard

1500/703

14.0/90

2000/1250 2500/1953 3200/3199 Derrick Equipment Co. DS1 (Sharples 3400)

14"x49”

SS

Contour


52/1

1800-3250

1800/644


52/1 or 125/1

1800-3250


80/1

1500-2400

1500/767

1600 usually

2000/1363


80/1 or 130/1

1500-2400


80/1

1600-2000

E

P.D. or Centrifugal

9.0/150

P.D. or Centrifugal

9.0/150

E

P.D. or Centrifugal

9.0/230

E

P.D. or Centrifugal

9.0/150

E

P.D. or Centrifugal

2500/1243

17.0/20

Carbide tiles on conveyor.

3250/2100 DE 1000

14"49”

SS

Contour

1800/644

E

2500/1243

17.0/20

3250/2100 DB1 (Bird)

24"x45”

SS

Contour

2400/1963 DB2 (Bird, BirdBroadbent, Broadbent)

24"x38” Contour

DB3 (Bird)

18"x28”

CS & SS

1500/767 2000/1363 2400/1963

Contour

CS

1600/654 2000/1022

CONFIDENTIAL

9.0/80 17.0/10

Carbide tiles on entire length of conveyor.


January 1998

Schlumberger Dowell


Page 54 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1 DS2 (Sharples 3000)


SS

Contour


Gearbox Ratio

Speed Range (RPM)


52/1

2000-3250

Adjust 10-150 RPM

35/1

RPM/G’s8

Drive3

Mud4 Pump


2000/795

E

P.D. or Centrifugal

9.0/120

P.D. or Centrifugal

9.0/100

2500/1243

17.0/30

Comments

Carbide tiles on conveyor.

3250/2100 DDO (Dorr Oliver)

16"x49”

SS

1800-4000

Contour

1800/736

E

3000/2045 4000/3635

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.) Decantmaster Standard

18"x28”

CS Standard

Conical


80/1

1500-2000

1500/575 2000/1022

DH, EH, or E

P.D.

9.0/10-50 10.0/35.0 17.0/10.1

Decantmaster Mark I

18"x28” Contour

CS Standard


80/1

1500-2000

1500/575 2000/1022

DH, EH, or E

P.D.

9.0/20-150 10.0/70.0 17.0/20.2

CONFIDENTIAL

Pioneer Centrifuges were manufactured by Pioneer. Patented conveyor gauging system for all units. Backdrive with variable scroll speed available for all units.


January 1998



Mfg. & Model1 Decantmaster Mark II


CS Standard

Contour


Gearbox Ratio

Speed Range (RPM)


80/1

1500-2000

RPM/G’s8

Drive3

Mud4 Pump


1500/575

DH, EH, or E

P.D. or Centrifugal

9.0/20-200

2000/1022

Comments

10.0/70.0 17.0/20.2

Hutchison-Hayes Intl., Inc. Model 1430

14"x30”

SS Standard

Contour


52/1

2000-4000

2000/795

E

3250/2100 4000/3181

Model 1448

14"x48”

SS Standard

Contour


52/1

2000-4000

2000/795

E

3250/2100 4000/3181

Model 5500

16"x55” Contour

SS Standard

Fixed or Variable single lead conveyor

53/1

2000-3250

2000/909 3050/2114 3250/2400

CONFIDENTIAL

E

P.D. Diaphragm pump

9.0/20-100

P.D. Diaphragm pump

9.0/20-100

P.D. or Centrifugal

10.0/60 17.0/9

10.0/60 17.0/9

9.0/250 10.0/205 17.0/32

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


January 1998

Schlumberger Dowell


Page 56 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1

Bowl Size Rotating2 Assembly Materials (in.) of Construction


Gearbox Ratio

Speed Range (RPM)

Adjust 1-70 RPM

40/1

Max 2800 1500 or 2000 on some units

RPM/G’s8

Drive3

Mud4 Pump

1500/575

E, H

P.D.


Comments

9.0/100

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

Hytech Centrifuges, Inc. Hysep MD 43 (previously 142)

16"x50” Contour

CS & SS

2000/1022

12.0/50

2780/1975

15.0/35 18.0/20

Hysep MD 53(previously 152)

20"x69” Contour

CS & SS

Adjust 1-40 RPM

40/1

Max 2400

2400/1636

E, H

P.D.

9.0/160 10.0/125 12.0/65 15.0/45 18.0/30

Hysep MD 44

16"x64”

SS & Duplex

Adjust 1-40 RPM

40/1

Max 3600

3600/2945

E, H

P.D.

9.0/135 10.0/95 12.0/75 18.0/35

Hysep MD 54

20"x80”

CS & SS

Adjust 1-40 RPM

40/1

Max 2400

2400/1636

E, H

P.D.

9.0/200 10.0/165 12.0/105 18.0/45

CONFIDENTIAL

Manufactured by M & J in Denmark. Conveyor can run approx. 30 RPM faster than bowl, if desired. Patented dual conveyor design. Manufactured by M & J in Denmark. New 4:1 single scroll with unique acceleration feed chamber. Manufactured by M & J in Denmark. New 4:1 single scroll with unique acceleration feed chamber.


January 1998



Mfg. & Model1



Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Mud4 Pump


Comments

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.) S2-1G

18"x54” Contour, CounterCurrent or Co-Current

CS Standard/SS

Hydraulically variable Hydraulically with single lead Variable conveyor 0-60

0-3400

E

P.D.

up to 70 gpm

S2-1G manufactured by Humboldt. WATER DILUTION MUST NOT BE USED WITH CO-CURRENT MODEL. Co-Current model not recommended for weighted muds.

S3-0G

20"x60” Contour, CounterCurrent or Co-Current

CS Standard/SS

Hydraulically variable Hydraulically with single lead Variable conveyor 0-60

0-2600

E

P.D.

up to 97 gpm

S3-0G manufactured by Humboldt. WATER DILUTION MUST NOT BE USED WITH CO-CURRENT MODEL. Co-Current model not recommended for weighted muds.

E

P.D.

9.0/0-75

Automatic selfcleaning on shutdown

Quality Solids Separation Co. Q30

18"x28” Conical

CS Standard


80/1

1500-2000

1500/575 2000/1022

10.0/35 17.0/10.1

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 58 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1 Q100

Bowl Size Rotating2 (in.) Assembly Materials of Construction 18"x28” Contour

CS Standard

18"x50” Contour

CS Standard


Gearbox Ratio

Speed Range (RPM)


80/1

1500-2000


80/1

RPM/G’s8

Drive3

Mud4 Pump


Comments

1500/575

E

P.D. or Centrifugal

9.0/100


2000/1022

10.0/70 17.0/15

Q200

1500-2000

1500/575

E

2000/1022

P.D. or Centrifugal

9.0/200 10.0/150


17.0/15 Sharples, Inc.7 P-1000 PM20000 (P-3000)

14"x22”

SS

14"x30.9” Contour

SS

Not manufactured any longer. Fixed with single lead conveyor

52/1 or 125/1

2600-4000

2600/1344

E

P.D. preferred

9.0/100

3250/2100

10.0/90

4000/3181

11.0/60 17.0/20

PM30000 (P-3400)

14"x49.4” Contour

SS


52/1 or 125/1

2600-4000

2600/1344 3250/2100 4000/3181

E

P.D. preferred

9.0/180 10.0/170 11.0/100 17.0/15-20

PM35000

16.75"x49.4” Contour

SS


52/1 or 125/1

CONFIDENTIAL

Comments for Sharples Centrifuges (excluding P-1000): Sharples centrifuges have axial flow conveyors and tungsten carbide tiles on conveyors for abrasion resistance. P” series is older & does not have axial flow and tungsten carbide tiles as standard.


January 1998


Page 59 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1


PM40000 (P-4600)

20"x50.3” Contour

SS

PM50000 (P-4800)

20"x76.4” Contour

SS

PM55000

24"x76” Contour

SS

PM60000 (P-5000)

25"x65” Contour

SS

PM70000 (P-5400)

25"x90” Contour

SS


Gearbox Ratio


Speed Range (RPM)

2000-3200

RPM/G’s8

Drive3

Mud4 Pump

2000/1136

E

Centrifugal


9.0/425

2550/1847

10.0/425

2800/2227

11.0/300

3200/2908

17.0/100

Same as PM70000 except for length. Fixed with single lead 47/1 or 95/1 conveyor

1800-300

1800/1150

E

Centrifugal

9.0/700

2250/1797

10.0/630

2500/2219

11.0/400

3000/3195

17.0/130

Spike Enterprises, Inc. Bird

18"x28” Conical

CS Standard


80/1

1500-2000

1500/575 2000/1022

EH, E

Centrifugal

90/10-40 10.0/30 17.0/5-10

CONFIDENTIAL

Comments


January 1998

Schlumberger Dowell


Page 60 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1 Broadbent


CS Standard

Contour


Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Mud4 Pump

Fixed single and fixed double lead conveyor

80/1

1000-2400

1000/341

E, D

Centrifugal

130/1

1500/767


Comments

9.0/150 10.0/100

2000/1363 2400/1963 Bird

24"x38”

SS

Cylinder Bird

24"x38”

CS, SS

Contour

Fixed single and fixed double lead conveyors 9 degrees

80/1

Fixed single lead conveyor

80/1

1000-2400

1800/1104

E

Centrifugal

2000/1363

9.0/120 10.0/85

2400/1963 1000-2400

1800/1104

E

Centrifugal

2000/1363

9.0/120 10.0/85

2400/1963 Bird

24"x60”

CS Standard

Contour

Fixed with 6" SW, 6 lead conveyor

80/1

1800-2500

1800/1104

E

Centrifugal

2000/1363

9.0/250 10.0

2500/2130 Bird

32"x50”

SS Standard

Contour


80/1

800-1700 variable

800/291

Diesel

1200/654

Direct

Centrifugal

9.0/450

1700/1313 Sharples P-5400

25"x90” Contour

SS


1800-3000

CONFIDENTIAL

1800/1150

E

Centrifugal

9.0/700

2250/1797

10.0/630

2500/2219

11.0/300

3000/3195

17.0/100

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


January 1998



Mfg. & Model1


Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Drive3

Adjust (3 settings) w/single lead conveyor

60/1

1600-3250

1600/509

E


60/1


60/1


Mud4 Pump


Comments

P.D.

9.0/0-60

Centrifugal

11.0/40

Swaco 414 & 518 centrifuges manufactured by Swaco Geolograph.

Swaco Geolograph (Swaco & Geolograph-Pioneer merged.) Model 414 Centrifuge

14"x36” Contour

SS Standard

Model 518 High Speed Centrifuge

14"x56” Contour

SS

Model 518 High Speed Centrifuge

14"x56” Contour

SS

1800/644 2500/1243 1600-3250

2500/1243

17.0/17 E

Centrifugal

3250/2100

8.5/90 9.0/75 10.0/60

1900

1900/718

E

Centrifugal

Model 518 not designed for weighted muds.

9.0/250 9.5/200 10.0/150

Mark I

(Same as Geolograph-Pioneer Mark I.)

Mark II

(Same as Geolograph-Pioneer Mark II.)

Sweco SC-2

SC-4

18"x30” Contour

CS Standard SS Available

Double lead Fixed or variable conveyor

59/1

24"x40” Contour


Double lead Fixed or variable conveyor

59/1

1350-2250

1350/466

E

P.D. or Centrifugal

9.0/200

Manufactured by Sweco. Backdrive for variable conveyor speed avail.

E

P.D. or Centrifugal

9.0/280

Manufactured by Sweco. Backdrive for variable conveyor speed avail.

2250/1294

1150-1950

1150/451

1550 typ.

1350/621 1950/1296

CONFIDENTIAL


January 1998

Schlumberger Dowell


Page 62 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1 Z-34

Omega Mark I Omega Mark II NX 329 643

P3400



Gearbox Ratio

Speed Range (RPM) 2000-3500

14"x56” Contour


Single lead variable conveyor

140/1

18"x28” Contour

CS Standard


80/1

18"x48” Contour

CS Standard


80/1

20"x62” Contour

SS Standard

Single lead variable axial flow conveyor

143/1

16"x54”

CS Standard

Variable Double Conveyor

140/1


141/1

14"x50”

CS or SS

RPM/G’s8

Drive3

Mud4 Pump


Comments

2000/795

E

P.D. or Centrifugal

9.0/100

Manufactured by Flottweg. Backdrive for variable conveyor speed.

E or DH

P.D. or Centrifugal

9.0/150

E

P.D. or Centrifugal

9.0/200

E

P.D. or Centrifugal

9.0/150

Manufactured by Alfa Laval.

E

P.D. or Centrifugal

9.0/125

Manufactured in Denmark by GVS.

E

P.D. or Centrifugal

9.0/100

Manufactured by Sharples.

D or E

P.D.

15-28 gpm

3500/2435

1350-2000

1350/466 2000/1022

1350-2000

1350/466 2000/1022

1350-2400

1350/518 2400/1636

1350-2500

1350/414 2500/1420

up to 3000

2000/795 2500/1243 3000/1789

RMS

(same as Totco Milchem RMS Centrifuge)

Totco (Milchem) (Totco no longer in solids control business.) RMS 1 Centrifuge

6" rotor

CS Standard

2

N.A.

2

N.A.

Fixed 2300

CONFIDENTIAL

2300/451

Developed by Mobil in 60's, portable, does not decant.


January 1998



Mfg. & Model1 HV 18

Bowl Size Rotating2 Assembly Materials (in.) of Construction 18"x28” Contour

CS Standard

24"x38” Contour

CS Standard


Gearbox Ratio

Speed Range (RPM)


80/1

1800-2000


130/1

RPM/G’s8

Drive3

Mud4 Pump

1800/828

E

Centrifugal

2000/1022


Comments

9.0/70

HV 18 manufactured by Broadbent.

10.0/50 19.0/20

HV 24

1600-1800

1600/872

E

Centrifugal

1800/1104

9.0/150 10.0/120

HV 24 manufactured by Broadbent.

19.0/50 Tri-Flo International, Inc. Alfa-Laval 418

14"x56” Contour

SS Standard

Adjust (5 settings) with single lead conveyor

160/1

1500-3400

1500/447

E

2800 typical

2800/1559

50HP

PD

9.0/140 for 1800-1900

3400/2298

Not designed for weighted muds.

9.0/75 for 2800 RPM

Humboldt SCS/142 SCS/152

24"x54” Contour

CS Standard

15"x38” Contour

CS

19.5"x62” Contour

CS


25/1

Variable with double lead conveyor

N.A.

Variable with double lead conveyor

N.A.


80/1

1638-1850

1638/914

E

Centrifugal

9.0/185

EH

PD

8.5/60

PD

8.5/100

Centrifugal

8.5/125 9.5/80 10.5/60

1850/1166 2800 variable

2800/1670

50 HP 2400 variable

2400/1595

EH 50 HP

Wagner International, Ltd. (merged with Wadeco) Sigma 100

18"x28” Contour

CS Standard

2000 typical

2000/1022

E 50HP

CONFIDENTIAL

Manufactured by Humboldt.


January 1998

Schlumberger Dowell


Page 64 of 64

Table 7 (Continued) Oilfield Centrifuges Mfg. & Model1 Sigma 150

Bowl Size Rotating2 (in.) Assembly Materials of Construction 18"x48” Contour

CS Standard


Gearbox Ratio

Speed Range (RPM)

RPM/G’s8

Fixed with double lead conveyor; axial flow

80/1

2000 typical

2000/1022

Drive3

Mud4 Pump


E

Centrifugal

8.5/175

50HP

Comments

9.1/140 9.5/120 10.0/65

Sharples PM40000

20"x50” Contour

CS &/or SS

Sharples PM60000

25"x65” Contour

SS

Fixed with single lead conveyor; axial flow; STC tiles

49/1

Fixed with single lead conveyor; axial flow; STC tiles

47.5/1

2800 typical

2800/2226

E

Centrifugal

8.5/300

Sintered Tungsten Carbide tiles (STC) on conveyor for abrasion resistance.

Centrifugal

8.5/400

Sintered Tungsten Carbide tiles (STC) on conveyor for abrasion resistance.

100HP

2500 typical

2500/2218

E 200HP

NOTES: 1. 2. 3. 4. 5. 6. 7. 8.

All centrifuges are decanters except Totco (Milchem) RMS Centrifuge which is a perforated rotor centrifuge. CS means “carbon steel,” SS means “stainless steel,” N.A. means “not applicable.” DH means “diesel-hydraulic,” EH means “electric-hydraulic,” D means “diesel,” and E means “electric.” P.D. means “positive displacement.” Not available from manufacturer. Values given are per manufacturer. 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 resistance and 360 degree solids discharge. 2 “G” = .0000142 x Bowl Diameter (in.) x RPM .

CONFIDENTIAL

DWM Solids Control Handbook

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