IADC Drilling Manual Part 14 pdf

International Association of Drilling Contractors Gas Delivery, Based on 1000 Ft pipeline lengths Volume Of Gas Delivered -- 1000's CF/Hr* 1000 Foot Lines... International Association of

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International Association of Drilling Contractors

Gas Delivery, Based on 1000 Ft pipeline lengths

Volume Of Gas Delivered 1000's CF/Hr* 1000 Foot Lines

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V-52 International Association of Drilling Contractors

Volume Of Gas Delivered 1000's CF/Hr* 2000 Foot Lines

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Multipliers To Convert 1000 Foot Line Values To Lengths Listed

+ Calculations are based upon listed inside diameters of the Standard Weight Threaded Line Pipe sizes shown

* Calculated from the Weymouth Formula for gas of 0.70 Specific Gravity (Air = 1.0), flowing at 60°F, and

measured at a standard of 60°F and 14.65 psi Absolute (4 oz Gage)

Local Atmospheric pressure is assumed to be 14.4 psi Absolute

For adjustment to other sp gr and temperature see sheet 40-110

Multiply the proper factor by the volume listed for a similar sized 1000 foot line

Example: A 3800 foot 2" line at 200 psi Upstream and 50 psi Downstream gage pressures would deliver (.51)(109.5) or 55845 cu ft per hour

Gas engines consume 10 to 15 cu ft of gas per horsepower hour

Uninsulated boilers consume 50 to 60 cu ft of gas per horsepower hour

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Gas Delivery, Based on 1 Mile pipeline lengths

Volume Of Gas Delivered 1000's CF/Hr* 1 Mile Lines

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Volume Of Gas Delivered 1000's CF/Hr* 2-1/2 Mile Lines

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Multipliers To Convert 1 Mile Line Values To Lengths Listed

* Calculated from the Weymouth Formula for gas of 0.70 Specific Gravity (Air = 1.0), flowing at 60°F, andmeasured at a standard of 6°F and 14.65 psi Absolute (4 oz Gauge)

Multiply the proper factor by the volume listed for a similar sized 1 mile line

Example: A 4 mile 2-1/2" line at 250 psi Upstream and 100 psi Downstream gauge pressures would deliver (.50)(89.21) or 44605 cu ft per hour

Gas engines consume 10 to 15 cu ft of gas per horsepower hour

Uninsulated boilers consume 50 to 60 cu ft of gas per horsepower hour

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Gas Delivery, Based on 10 Mile pipeline lengths

Volume Of Gas Delivered 1000's CF/Hr* 1 Mile Lines

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Volume Of Gas Delivered 1000's CF/Hr* 2-1/2 Mile Lines

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Multipliers To Convert 10 Mile Line Values To Lengths Listed

* Calculated from the Weymouth Formula for gas of 0.70 Specific Gravity (Air = 1.0), flowing at 60°F., andmeasured at a standard of 60°F and 14.65 psi Absolute (4 oz Gauge)

Multiply the proper factor by the volume listed for a similar sized 10 mile line

Example: A 6.6 mile 3" line at 100 psi Upstream and 75 psi Downstream gage pressures would deliver (1.23)(15.08) or 18548 cu ft per hour

Gas engines consume 10 to 15 cu ft of gas per horsepower hour Uninsulated boilers consume 50 to 60 cu ft ofgas per horsepower hour

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4 Waterlines - Line Pipe Capacities

APPROXIMATE LINE PIPE CAPACITIES FOR WATER

Where inlet and outlet are at different elevations pressure should be added or subtracted, using the factor 0.433times the difference in

height in feet After determining pressures corrected for elevation convert to Horse Power

Thus: (0.00048 x Pressure x Bbls/hr) = Hydraulic Horse Power, based on 85 % Efficiency

For engine or motor Horse Power add 20 - 25 percent

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V-61

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Pit Gain or Loss Tables

5 Tank and Pit Capacity

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Pit Gain or Loss Tables - Continued

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Pit Gain or Loss Tables - Continued

How To Calculate Capacities of Tanks (Pits), Dimensions in Feet

1 Rectangular

Area = L x W

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3 Sloping Ends & Sides

Note: Both length and width are measured from bottom at one hand to line from top at other hand

Cubic Feet= L x W x h

Barrels= (L x W x h)/5.61

4 Cylindrical, Flat Ends

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6 Conversion Factors

The international System of Units (SI for short) is a modernized version of the metric system It is built upon sixbase units and two supplementary units Symbols for units with specific names are given in parentheses Theinformation in this Data Sheet, adapted from the revised "Metric Practice Guide," Standard E380-68, 1969 Book ofASTM Standards, Part 30, includes a selected list of factors for converting U.S customary units to SI units

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Metric Conversion Factors

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Metric Conversion Factors - Continued

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Table of Conversion Factors

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Table of Conversion Factors - Continued

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Table of Conversion Factors - Continued

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Decimal and Metric Equivalents of Inch Fractions

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Decimal and Metric Equivalents of Inch Fractions - Continued

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Decimal and Metric Equivalents of Inch Fractions - Continued

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Fractions, Inches to Decimals of a Foot

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Flow Rate Conversions

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Flow Rate Conversions - Continued

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7 Density of Oilfield Materials and Wood

Cement, Portland (Loose) 94

Coal (Loosely Piled) 40-58

Concrete (Stone & Gravel) 150

Rags (Compressed Bales) 19

Salt (Ground in Sacks) 60

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Snow (Loosely Piled) 35

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8 Density of Fluids and Petroleum Products

Fluids and Petroleum Products Density , ppg

Acid - Hydrochloric (Muriatic)

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9 Soil Bearing Capacity

Kinds of Soil Safe bearing capacity, tons per sq ft

Solid ledge of hard rock 25 to 100

Sound shale and other medium rock, 10 to 15

requiring blasting for removal

Hard pan, cemented sand and gravel, 8 to 10

difficult to remove by picking

Soft rock, disintegrated ledge; in natural 5 to 10

ledge, difficult to remove by picking

Compact sand and gravel, requiring 5 to 6

picking for removal

Hard clay, requiring picking for removal 4 to 5

Gravel, coarse sand, in natural thick beds 4 to 5

Loose medium and coarse sand, fine dry sand 3 to 4

Medium clay, stiff but capable of being spaded 2 to 4

Fine wet sand, confined 2 to 3

Soft clay 1

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Chapter Y Drilling Mud Processing

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Y-2 International Association of Drilling Contractors

Table of Contents - Chapter Y

Drilling Mud Processing

1 Introduction - Solids Control Removal Systems Y-4

A Overview Y-4

B Solids Removal Theory Y-5

C Equipment Arrangement Y-9

II Solids Control Equipment Y-11

A Shale Shakers Y-11

B Degassers Y-26

C Hydrocyclones Y-30

D Mud Cleaners Y-39

E Centrifuges Y-50 III Surface Circulating Equipment Y-55

A Introduction Y-55

B Considerations and Methods for Sizing Surface Mud Systems Y-55

C Special Considerations Y-56

D Sizing Steel Pits Y-57

E Earthen Pits Y-58

F Reserve and/or Waste Pits Y-59

4 System Rig-up Information Y-61

A Solids Control System Layout Considerations Y-61

B Centrifugal Pump Selection and Piping Design Y-70

C Mud Troughs After the Shale Shakers Y-88 Index - Section Y - Solids Removal Systems Y-91

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Chapter Y

Solids Control Removal

The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjectsrelated to drilling operations

The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry ested in providing information to field personnel to encourage proper operations, maintenance and repair of equip-ment and training and safety of personnel

inter-It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators orindividual drilling company recommendations, policies and/or procedures In those areas where local, state andfederal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws IADC has endeav-ored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connec-tion with these recommendations

As technology continues to develop this manual will be updated It is important that the user continue to updatetheir knowledge through research and study

The following industry representatives have contributed to the development and updating of this chapter:

MEMBERS OF THE TASK GROUP:

Robert Bennett - Milpark Drilling Fluids

Roger DeSpain - Premier, Inc

Charles Girchar - SWECO Oilfield Services

William Halliday - Milpark Drilling Fluids

Mike Montgomery - SWECO Oilfield Services

Ron Morrison - Derrick Equipment Co

Janice Skalnik - SWECO Oilfield Services

SWECO Oilfield Services has permitted IADC the use of its Solids Control Handbook for text development Inaddition, the artwork contained in Section III was provided by SWECO Oilfield Services

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Y-6 International Association of Drilling Contractors

74 to 440 microns - sand

2 to 74 microns - silt

0.5 to 2 microns - clay

0.5 micron and smaller - colloids

All solids in the colloidal range are not detrimental to a mud system: Some finer particles in the colloid range arenecessary for building a thin, slick wall cake in the borehole and reduce the possibility of differential pressuresticking of the drill string However, it is highly important that drilled solids are removed the first time they arecirculated to the surface or they would eventually degrade to a colloid size by continuous circulation through themud pumps, drill pipe, bit jets, bit teeth, etc

As an example, one particle having a diameter of 100 microns will become 125,000 particles with a diameter of 2microns and require 50 times as much liquid to coat the surface of this same mass of drilled solids without anyreduction in solids concentration This thickening process, occurring without an absolute increase in solids concen-tration, is referred to as viscosity or the resistance to flow

Adding water or oil to the system reduces the concentration of those solids, thus reducing the viscosity Removal

of drilled solids during the early circulation stages with solids removal equipment at the surface is much moresimple and less expensive Water-soluable chemicals, such as lignites, lignosulfonates, phosphates, quebracho, may

be added to the water phase to control the extremely fine clays in the mud Also, some flocculants are effective inagglomerating many fine solids into one large floc that can be removed by settling in the tanks or by removalequipment

2 Benefits Of Low Solids Mud

1 Increased drilling penetration rate

2 Increased bit life

3 Reduced mud costs

4 Reduced main mud pump maintenance cost

5 Reduced differential pressure sticking

6 Bore-hole is closer to gauge

7 Reduced water dilution

8 Increased cementing efficiency

9 Increased accuracy of geological information retrieved from wellbore

10 Reduced drill pipe torque

11 Increased control of mud properties

Obviously, these benefits are the result of planning prior to drilling a well and are accomplished through the use ofproperly designed, sized and operated solids removal equipment It is the obligation of the drilling crew to becomeknowledgeable in the proper use of the equipment; otherwise, its potential benefits may he reduced or nullified

3 Methods Of Controlling Solids

1 Mechanical treatment

2 Chemical treatment

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3 Dilution of whole mud

4 Jetting or discarding whole mud

Each of the above methods is effective at the proper time and place; however the last two categories are quiteoften employed due to lack of planning when mechanical treatment would be more effective and economical;especially during the early phases of the drilling program

3.A MECHANICAL TREATMENT

This is the method of mechanically removing solids using shale shakers, desanders, desilters, mud cleaners andcentrifuges with each piece of equipment generally limited to the following range of particle removal:

1 Standard Shale Shaker - 440 microns and larger

2 Fine Screen Shaker - 74 microns and larger (weighted muds)

44 microns and larger - (unweighted muds)

3 Mud cleaner - 74 microns and larger (weighted muds)

44 microns and larger(unweighted muds)

4 Desanders - 100 microns and larger

5 Desilters - 15 microns and larger

6 Centrifuge - 4 to 8 microns and smaller (weighted muds);

4 to 8 microns and larger (unweighted muds)

Each piece of mechanical equipment is effective within a certain particle size range Utilizing all of the above itemsthroughout a drilling program will produce maximum benefits without overloading any one piece of equipment.None of the above items will take the place of another piece of equipment; however no piece of equipment

operating at optimum efficiency should cause downstream equipment becoming overloaded

Removing solids from spud of a drilling program is a first priority in solids control as it is much easier to removeone particle 100 microns in diameter with a fine screen shaker than to attempt to remove 125,000 particles of 2micron size with a centrifuge

In unweighted water-base muds, the fine screen shaker, desander and desirer are generally used until the point ofadding barites Centrifuges are added to increase drilled solids removal With weighted waterbase muds and all oilbase muds, fine screen shaker, mud cleaner and centrifuge are utilized

B CHEMICAL TREATMENT

Chemical treatment of a water-base mud for solids removal involves adding a "flocculant" to the mud system Thiscauses extremely fine solids to agglomerate together in order to be removed mechanically or allowed to settle bygravity in the mud tanks Normally, flocculant is used in conjunction with mechanical treatment For example,flocculants can be added at the shaker screen to increase apparent particle size Polymer flocculant may also beinjected into the centrifuge feed to improve centrifuge performance

Deflocculants such as lignosulfonates may be added to a water base mud to increase the solids tolerance of thefluid These "thinners" allow more solids to be incorporated into the mud before viscosity becomes too much of aproblem

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