THE HANDBOOK ON
SOLIDS CONTROL &
WASTE MANAGEMENT
4th EDITION
1st Edition © 1982 2nd Edition © 1985
3rd Edition © 1995 4th Edition © 1996
All rights reserved. No part of this book may be reproduced in any form without permission in writing from the publisher.
PREFACE
This Handbook was written by the Technical Services staff of Brandt/EPI to provide a basic understanding of effective mechanical removal of drilled solids and management of drilling wastes. Based on sound theoretical con-cepts, this Handbook is a practical working tool. It is designed for use by anyone needing to optimize drilling efficiency: drilling engineers, supervi-sors, tool pushers, mud engineers, derrick hands, service personnel and others.
This 4th edition of the Handbook provides updated sections on equip-ment and techniques, and includes new information on waste processing systems, including downhole injection, solidification/ stabilization, water clarification, and other site remediation techniques. We would appreciate any suggestions for improving future editions of the Handbook. Please address your comments to:
Brandt/EPI Technical Group P.O. Box 2327 Conroe, TX 77305 TEL: (713) 756-4800 FAX: (713) 756-8102 Thanks, Mike Montgomery
Manager, Technical Group Brandt/EPI
TABLE OF CONTENTS
PAGE 1.0 DRILLING MUD AND MUD SOLIDS ...1.1
1.1 Functions of Drilling Mud ...1.1 1.2 The Nature of Drilled Solids ...1.2 1.3 Properties of Drilling Mud ...1.4 1.4 Types of Drilling Muds...1.8 2.0 BENEFITS OF SOLIDS REMOVAL BY MECHANICAL SEPARATION ...2.1 2.1 Reduced Total Solids ...2.1 2.2 Reduced Dilution Requirements ...2.2 3.0 MECHANICAL SOLIDS CONTROL AND RELATED EQUIPMENT ...3.1 3.1 Particle Classification and Cut Point...3.3 3.2 Separation by Vibratory Screening ...3.6 3.3 Shale Shakers ...3.14 3.4 Mud Cleaners/Conditioners...3.21 3.5 Separation by Settling and Centrifugal Force...3.28 3.6 Sand Trap ...3.29 3.7 Hydrocyclones ...3.30 3.8 Desanders...3.33 3.9 Desilters...3.35 3.10 Decanting Centrifuge...3.38 3.11 Auxiliary Equipment...3.43 3.12 Unitized Systems...3.48 3.13 Rig Enhanced Systems...3.49 3.14 High Efficiency Solids Removal Systems...3.50 3.15 Basic Arrangement Guidelines...3.51 4.0 BRANDT/EPI™ PRODUCTS AND SERVICES ...4.1 Company Profile...4.1 4.1 Scope of Services...4.1 4.2 Business Relationship...4.1 4.3 Certification...4.1 4.4 Personnel Resources...4.2 Products and Services ...4.2 4.5 Linear Motion Shakers...4.3 ATL-1000 ...4.3 ATL-1200 ...4.3 LCM-2D ...4.4 ATL-CS ...4.4 LCM-2D/CM2 ...4.5 ATL Drying Shaker...4.5 SDW-25 Drying Shaker...4.6 ATL-16/2 Mud Conditioner...4.6 ATL-2800 Mud Conditioner ...4.7 LCM-2D Mud Conditioner ...4.7 4.6 Orbital Motion Screen Separators ...4.7 Tandem Screen Separator ...4.7 Standard Screen Separator ...4.8 Mud Cleaners ...4.8
4.7 Screen Panels ...4.9 BlueHexSM3HX Screen Panels ...4.9
Pinnacle™ Screen Panels ...4.9 PT Screen Panels ...4.10 Hook-Strip Screen Panels...4.10 4.8 Hydrocyclone Units ...4.10 Desanders...4.10 Desilters...4.11 4.9 Centrifuges ...4.11 SC-1 Decanting Centrifuge ...4.11 SC-4 Decanting Centrifuge ...4.12 HS 3400 High Speed Decanting Centrifuge ...4.12 SC 35HS High Speed Decanting Centrifuge...4.12 HS 5200 High Speed Decanting Centrifuge ...4.13 Roto-Sep Perforated Rotor Centrifuge ...4.13 4.10 Dewatering Units ...4.14 4.11 Filtration Units ...4.14 4.12 Vacuum Degassers...4.15 4.13 Mud Agitators...4.15 4.14 Portable Rig Blowers ...4.15 4.15 Integrated Systems...4.16 Closed Loop Processing Systems ...4.16 Coiled Tubing (CT) Processing Systems...4.17 Trenchless Technology Processing Systems...4.17 Live Oil Systems...4.17 4.16 Remediation Management Services ...4.17 4.17 Technical & Engineering Services...4.18 APPENDICES
Glossary ...A.2 Mud Solids Calculations
Standard Calculations...B.1 Field Calculations to Determine Total Solids Discharge ...B.4 Field Calculations to Determine High and Low Gravity Solids Discharge ...B.5 Solids Control Performance Evaluation ...B.6 Method for Comparison of Cyclone Efficiency ...B.10 Mud Engineering Data
Conversion Constants and Formulas...C.1 Density of Common Materials ...C.2 Hole Capacities ...C.3 Pounds per Hour Drilled Solids — Fast Rates ...C.4 Pounds per Hour Drilled Solids — Slow Rates ...C.5 Solids Content Chart ...C.6 Equipment Selection
Pre-well Project Checklist...D.1 Screen Cloth Comparisons ...D.2 Brandt/EPI Equipment Specifications...D.3 Selecting Size and Number of Agitators ...D.7 Brandt/EPI™ Sales & Service Locations ...D.8
1.0
DRILLING MUD AND MUD SOLIDS
Mud is the common name for
drilling fluid. While it is outside the scope of this handbook to offer a detailed discussion of drilling fluids, a brief outline of the general char-acteristics of drilling mud is included to establish the basic rela-tionships between drilling mud and solids control.
Similarly, any discussion of solids control would be incomplete with-out establishing an understanding of the nature of mud solids — their size, shape and composition.
1.1
FUNCTIONS OF
DRILLING FLUID
The mud system in a drilling operation performs many important functions. Among these are: 1. Carry the drilled solids from
the bottom of the hole to the surface.
2. Support the wall of the hole. 3. Control pressure within the
for-mation being drilled.
4. Cool the bit and lubricate the drill string.
5. Clean beneath the bit.
6. Suspend cuttings while circula-tion is interrupted (e.g., during trips).
7. Secure accurate information from the well (cuttings sam-ples, electric logs, etc.).
8. Help support the weight of the drill string.
9. Transmit hydraulic horse-power to the bit.
10. Allow removal of cuttings by the surface system.
Of the ten functions listed, the fol-lowing are generally considered most important:
1. Drilling mud moves the forma-tions’ solids cut by the drill bit from the bottom of the hole to the surface. Removal of cut-tings from the wellbore is essential in order to continue drilling.
2. Drilling mud must withstand the pressure exerted by the formations exposed in the hole. The pressure exerted by the mud against the formations helps the driller control the pressure created by the gas, oil and water that are exposed while drilling, thus reducing the potential for costly blowouts.
3. Drilling mud protects and sup-ports the walls of the wellbore. The mud has a plastering effect on the walls of the hole and helps prevent the walls from caving in, causing an enlarged hole or leading to stuck pipe.
These problems significantly increase drilling expense and time.
4. Drilling mud cools the bit and lubricates the drill string. This function is important in drilling because it increases the useful life of bits and the drill string.
Drilling mud is obviously a major factor in the success of any drilling program, and the key to any effec-tive mud system is good solids control.
1.2
THE NATURE OF
DRILLED SOLIDS
Mud solids include particles that are drilled from the formation, material from the inside surface of the hole and materials that are added to control the chemical and physical properties of the mud, such as weight material. Drilled solids’ particles are created by the crushing and chipping action of rotary drill bits. Additional solids enter the well bore by sloughing from the sides of the open hole.
The unit of measurement general-ly used to describe particle size is the micron (µ). A micron is one thousandth (0.001) of a millimeter, or approximately 0.00003973 of an inch. To relate this unit of measure-ment in more familiar terms, Figure 1-1 provides a list of common items and their size in microns.
Although individual mud solids can range in size from less than one micron to larger than a human fist, the average particle size is less than 35–40 microns, too small to be seen with the human eye.
Note: The various sizes of solids particles in a particular drilling mud are referred to as the mud’s cuttings, sand, silt or clay content. This content is important to remem-ber because solids control practices will affect the average particle size and the concentration of solids in specific size ranges which may greatly affect mud properties and drilling operations.
Mud solids may be conveniently grouped according to micron size range, but unfortunately not with-out introducing some element of confusion. The API Committee on Standardization of Drilling Fluid Materials, in API Bulletin 13C pub-lished in 1974, recommended certain terminology for mud solids particle size in an attempt to mini-mize this confusion. This new terminology has not yet, however, gained universal acceptance.
Figure 1-1
Micron Size Range of Common Materials
ITEM DIAMETER IN MICRONS
Cement Dust (Portland) 3-100 µ
Talcum Powder 5-50 µ
Red Blood Corpuscles 7.5 µ Finger Tip Sensitivity 20 µ
Human Sight 35-40 µ
Human Hair 30-200 µ
Cigarette (diameter) 7520 µ
The more commonly used classifi-cations shown in Figure 1-2, cuttings, sand, silt and clay (or col-loidal size) will be used throughout this handbook, as they are the most readily recognized in the field. These terms will refer to size classi-fication only, not to material composition.
Note: Drilled solids can originate from sand, limestone, shale or other formations, but their classification in regard to solids control usually depends on particle size since their specific gravity is assumed to be approximately 2.6.
It is important to note that com-mercial solids (such as barite or bentonite added for weight and vis-cosity) are also affected by solids control equipment, according to size. Most barite particles are in the same size group as silt (2–74 microns); bentonite particles are grouped with clay (smaller than 2 microns).
From the time they enter the well until they reach the surface, drilled solids particles are continuously reduced in size by abrasion with other particles and by the grinding action of the drill pipe.
Abrasiveness of mud solids is determined by particle shape and hardness. Drilled solids come in various shapes such as round, nee-dle shaped, platelets, cubic, etc. To be destructive, particles must be sharper and harder than the materi-al they are to abrade. Figure 1-3 illustrates the degradation of drilled solids in a mud system. The main body of the particle becomes less abrasive with wear as the most abrasive corners continue to degrade down through the silt size to approximately 15–20 microns.
Particles smaller than 15–20 microns have much less abrasive effect on drilling equipment. Barite particles, which are not as hard as most drilled solids, are generally less abrasive than similarly-sized drilled solids. Other weighting materials, such as hematite, are generally harder and more abrasive than barite.
Specific surface area, as it relates
Figure 1-2
Common Field Terminology of Particle Size
CLASSIFICATION PARTICLE SIZE
(Diameter in Microns)
Cuttings Larger than 500 µ
Sand 74-500 µ
Silt 2-74 µ
Clay Smaller than 2 µ
Figure 1-3
to various shapes and sizes of solids, is another important con-cept. Specific surface area refers to the surface area per unit of weight or volume. Figure 1-4 lists examples that show surface area greatly increases per unit of mass: 1) as particle size decreases, and 2) as particles become less spherical in shape.
Surface area adsorbs or “ties-up” water. The more surface area, the more water adsorbed. As the parti-cle size decreases toward the colloidal size, the relative effect of the water coating increases. The specific surface area has a pro-nounced effect on viscosity, as Figure 1-5 illustrates. The higher the relative specific surface area, the greater is the viscosity. Formations
composed of clays that easily dis-perses into the mud produce relatively more viscosity increase and will have “wetter” separations in removal by equipment than forma-tions that produce larger sized solids. Bentonite disperses easily into col-loidal solids and also absorbs much more water than most solids types. Hence bentonite builds viscosity at relatively low concentrations. Viscosity and other mud properties are discussed in Section 1.3 of this Handbook.
1.3
PROPERTIES OF
DRILLING MUD
The ability of a drilling fluid to perform its functions depends on various properties of the mud, most of which are measurable and are affected by solids control.
DENSITY (MUD WEIGHT)
Density is a measure of the weight
of the mud in a given volume, and is frequently referred to as mud weight. The instrument used to measure density is the mud balance (see Figure 1-6). The instrument consists of a constant volume cup with a lever arm and rider calibrat-ed to read directly the density of the fluid in lbs/gal (water = 8.33 lbs/gal) and pressure gradient in psi/1000 ft (water = 433 psi/1000 ft) or pounds per cubic foot (water = 62.4 lbs/ft).
Figure 1-4
Effect of Particle Size and Shape on Surface Area
Figure 1-5
Effect of Specific Surface Area on Viscosity EQUIVALENT SPHERICAL
PARTICLE DIAMETER TYPE SQUARE FEET (Microns) PARTICLES PER POUND
5.0 µ Glass Spheres 2,345 5.0 µ Crushed Quartz 3,435 1.0 µ Glass Spheres 11,725 1.0 µ Crushed Quartz 17, 160 0.1 µ Glass Spheres 117,250 0.1 µ Crushed Quartz 171,500
The density of the mud is related to the specific gravity of the fluid. Specific gravity is the ratio of a materials density to the density of water. Pure water has a specific gravity of 1.0. A material twice as dense as water would have a spe-cific gravity of 2.0. A material half as dense as water would have a specific gravity of 0.5. Low gravity solids have an average specific gravity of 2.6. The solids are 2.6 times the weight of the same vol-ume of water.
VISCOSITY
Viscosity measures the mud’s
resistance to flow as a liquid and is one of the key physical properties of mud. Increasing the amount of solids or exposed surface area in a mud increases its resistance to flow as a liquid and therefore increases
its viscosity. Viscosity is routinely measured with a Marsh Funnel and Mud Cup at the drilling site (see Figure 1-7). The person measuring the viscosity fills the funnel with a sample of mud and allows it to
Figure 1-6 Mud Balance
flow through the tip of the funnel container while measuring the time in seconds that it takes to fill the mud cup to the one quart level. The funnel viscosity recorded is in seconds per quart. Internationally, funnel viscosity is recorded in sec-onds per thousand ccs or secsec-onds per liter.
PLASTIC VISCOSITY
A mud’s Plastic Viscosity is the por-tion of a mud’s flow resistance caused by the mechanical friction between the suspended particles and by the viscosity of the continu-ous liquid phase. In practical terms, plastic viscosity depends on the size, shape, and number of parti-cles. For example, as the amount of drilled solids in a mud increases, the plastic viscosity also increases. Plastic viscosity is measured with a
rotational viscometer (Figure 1-8) and is expressed in centipoise (grams per centimeter-second).
YIELD POINT
Yield point is the part of flow
resis-tance that measures the positive and negative inter-particle, or attractive, forces within a mud. Yield point is measured with a viscometer and expressed in lbs/100 ft2. Internationally, yield
point is sometimes measured in dynes/cm2.
GEL STRENGTH
Gel Str ength is a function of a
mud’s inter particle forces and gives an indication of the amount of gela-tion that will occur after circulagela-tion ceases and the mud remains static for a period of time. Typically, gel strengths are reported for initial and 10-second gel strength. A large deviation of these two figures may indicate progressive gels, that is, gelation structures that gain strength over time. Gel strength is also measured with a viscometer and expressed in lbs/100 ft2.
Internationally, gel strength is sometimes measured in dynes/cm2.
SOLIDS CONTENT
The solids content is the volume percentage of the total solids in the
mud. To determine the solids con-tent of a mud containing weight material, a mud container in the retort is filled with a measured vol-ume of mud (see Figure 1-9). The mud is then heated to boil off the liquid. The percentage of the liquid distilled off is measured in a glass cylinder and subtracted from 100%. The difference is the percentage of solids by volume contained in the drilling mud and is recorded as per-centage solids. The total solids from the retort and mud weight are used to calculate the low and high gravi-ty solids content.
If the mud does not contain oil or weight material, such as barite or hematite, the low gravity solids can be determined without a retort by weighing the mud and referring to a solids content chart.
SAND
Sand is any particle larger than 74
microns when referring to solids control separation. Therefore, the sand content of a mud is simply the amount of solids too large to pass through a US Test Sieve 200-mesh screen. This is determined with a sand content set (see Figure 1-10) by washing a
mea-sured amount of mud through the 200-mesh screen in the kit. The amount of solids that does not pass through the screen is measured as percentage by vol-ume and is recorded as per-cent sand.
FILTRATION
Filtration and wall-cake building
are actions that the drilling mud carries out through and on the walls of the hole. Some formations allow the liquid in the mud to seep into them, leaving a layer of mud solids on the wall of the hole. This layer of mud solids is called filter cake or wall-cake. The filter cake builds up a barrier and reduces the amount of the liquid that enters the formation and is lost from the mud. This process is referred to as filtra-tion, or fluid loss. The instrument used to measure the fluid loss due to filtration is a filter press (see Figure 1-11).
Figure 1-9 Retort (Mud Still)
Figure 1-10 Sand Content Set
The person using the filter press places a mud sample in the instru-ment on top of a piece of filter paper and brings the pressure up to 100 pounds per square inch. The amount of fluid flowing from the sample in 30 minutes is measured in milliliters. The mud filtration property is recorded in units of cubic centimeters (ccs) or milliliters (ml) per 30 minutes. Examination of the filter paper will indicate how the solids will plaster the wall of the hole and affect fluid loss. The cake thickness is recorded in units of 1/32s of an inch.
CHEMICAL PROPERTIES
Chemical Properties is a broad
category, including measurements of pH, alkalinity, chlorides, calcium
content, salt content, and other properties that affect drilling mud performance. Some of these chemi-cal properties can be controlled through various mud additives that thicken, thin, precipitate, disperse, emulsify, lubricate or otherwise adjust the mud depending on spe-cific drilling needs. For example, caustic soda can be added to some saltwater mud in order to maintain a high pH level; it makes disper-sants more effective and reduces corrosion. Chemical changes such as these are used to fine tune drilling muds.
1.4
TYPES OF
DRILLING MUDS
Drilling fluids are generally cate-gorized as “water-base” or “oil-base”, and as “weighted” or “unweighted” muds.
Water-base Muds contain water as
the liquid phase and are used to drill most of the wells in the world because they are relatively simple, expense is usually reasonable, and water is commonly available in most places.
Oil-base Mud contains either
nat-ural oil or synthetic oil as the continuous liquid phase and is used for maximum hole protection. Oil-base mud and synthetic oil mud are usually much more expensive than water-base mud and therefore are only used when there is a specific
need, such as to keep the hole from swelling or caving in, or to reduce friction and prevent stuck pipe in very crooked or high angle holes. Either water-base or oil-base mud can be used as “weighted” mud.
Weighted Mud refers to any mud
which has barite or barite substi-tutes added to increase density. These muds normally have a densi-ty greater than 10.0 lbs/gal. The solids in weighted mud consist of drilled solids from the hole, plus barite, plus commercial clays added to control fluid loss and viscosity.
Unweighted Mud refers to any
mud which has not had barite added. This mud type normally has a density of less than 10.0 lbs/gal. The solids in unweighted mud con-sist of drilled solids from the hole, plus commercial clays.
Solids control techniques will vary considerably depending on the type of mud being used. For example, with many unweighted water-base muds, the loss of fluids along with the drilled solids may be economi-cally insignificant, allowing simple solids control techniques. In the case of mud that contains expen-sive chemical additives and/or barite, especially oil-base mud, sophisticated solids control tech-niques must be utilized to minimize overall costs. In addition, environ-mental costs of haul-off and
disposal may require sophisticated solids control techniques. System recommendations for specific appli-cations are covered in detail in Chapter 4.
Here is a list of the most common mud types, followed by a brief description of each type:
I. Water-Base Mud (WBM) A. Spud Mud
B. Natural mud
C. Chemically-Treated Mud
1. Lightly Treated Chemical Mud
2. Highly Treated Chemical Mud
3. Low Solids Mud 4. Polymer Mud 5. Calcium Treated Mud
D. Saltwater Mud
1. Sea Water Mud 2. Saturated Salt Mud
II. Oil-Base Mud (OBM) A. “True” Oil Base B. Invert Emulsion C. Synthetic (SBM)
SPUD MUD
Spud Mud is used to start the
drilling of a well and continues to be used while drilling the first few hundred feet of hole. Spud mud is usually an unweighted water-base mud, made up of water and natural solids from the formation being drilled. It may contain some com-mercial clay, added to increase viscosity and improve wall-cake building properties.
NATURAL MUD
Natural Mud (sometimes called
“native” mud) is usually unweight-ed water-base mud which contains mostly drilled solids. Some ben-tonite and small amounts of chemicals may be used to improve filter cake quality and help prevent hole problems. This mud is often the next mud type used after spud mud. Often, natural mud is used to drill the first few thousand feet of hole, where only minor hole prob-lems are expected.
CHEMICALLY TREATED MUD
Chemically Treated Mud is
water-base mud which contains chemicals to control physical and chemical properties. Bentonite is usually added to help control viscosity and fluid loss. Barite (weight material) may be added to increase density.
This mud is used where more severe hole problems are expected, in order to prevent these problems.
Lightly Treated Chemical Mud is
usually unweighted water-base mud. It is used where minor hole problems are expected, such as sloughing or caving of the walls of the hole.
Highly Treated Chemical Mud is
usually weighted, water-base mud that contains larger amounts of chemicals, bentonite, additives, and barite to maintain strict control of viscosity, fluid loss, chemical
prop-erties, and density. Chemical muds are often treated with lignosul-fonates or lignite and are therefore commonly called “lignosulfonate mud” or “lignite” mud.
These muds are used where mod-erate to severe hole problems are expected or high down-hole pres-sures occur. Of all the water-base mud types, these are the most expensive to maintain. As mud den-sity is increased and potential hole problems (such as stuck drill pipe) become more of a risk, the removal of drilled solids by mechanical solids control equipment becomes increasingly important.
Low Solids Muds are water-base
mud containing less than ten per-cent (10%) drilled solids; 1–5% is a normal range. Generally speaking, the lower the solids content in the mud, the faster the bit will drill.
Low solids muds are usually expensive to maintain because the solids, chemical, and fluid loss properties have to be kept very close to prescribed levels. It is absolutely essential that all solids removal equipment operate at max-imum effectiveness in order to maintain the desired low level of solids at a reasonable cost.
Polymer Muds are special types of
low solids mud which contain syn-thetic materials, polymers, designed to control viscosity and fluid loss. Polymers are very expensive and
often difficult to screen when a high viscosity fluid is used.
Calcium Treated Muds are special
water-base muds, usually weighted, which have lime or gypsum added. Calcium Treated Muds are normally used to prevent shale type forma-tions from swelling or sloughing – problems which could lead to stuck pipe or a ruined hole.
SALTWATER MUD
Saltwater Muds contain a high
concentration of salt. They may be weighted or unweighted.
Sea Water Muds contain sea water
as the continuous phase and, usual-ly, only sea water is used for dilution. They may be weighted or unweighted. These muds are used offshore and in bay areas where fresh water is not readily available.
When sea water mud is being used, only sea water should be used to rinse or wash the screens in solids control equipment.
Saturated Salt Muds (sometimes called brine fluids) contain as much salt as can be dissolved in the water phase. This mud type is often used to drill through salt formations so the fluid will not dissolve the salt formation. If fresh water mud is used, greatly enlarged holes would result, usually leading to hole trou-ble.
It is important to be aware of the use of salt mud because screen
blinding can occur when salt dries and cakes on the solids control equipment. Fresh water may be used to clean the screens, but it must be used very carefully because too much fresh water can upset the chemical balance of this mud.
“TRUE” OIL-BASE MUD
“True” Oil-base Mud contains a
liquid phase with ninety to ninety-five percent (90–95%) diesel oil and five to ten percent (5–10%) water emulsified within the oil. These muds often use asphaltic type mate-rials suspended in the liquid for controlling viscosity and fluid loss. “True” oil-base muds provide good hole protection, especially in shale type formations, and also increase drill string lubrication.
INVERT EMULSION MUD
Invert Emulsion Mud is oil-base
mud in which the liquid phase is sixty to ninety percent (60–90%) diesel oil with ten to forty percent (10–40%) water emulsified within the oil. An invert mud can be for-mulated with mineral oil or other low environmental risk oil substi-tutes when needed. In this mud, water and chemicals are used to-gether to control viscosity and fluid loss. Invert emulsion muds provide good hole protection and are the most commonly used oil mud.
SYNTHETIC OIL MUDS
The term “Synthetic-Based Mud”, or SBM, describes any oil-base mud that has a synthesized liquid base. Some common synthetic base fluids include linear alphaolefins (LAO), straight internal olefins (IO), polyal-phaolefins (PAO), vegetable oils, esters, and ethers. This base fluid is then combined with viscosifiers, weighting material, and other addi-tives to produce a stable, useful drilling fluid.
SBMs share several advantages with traditional oil-base muds, including excellent wellbore stabili-ty, improved drilling rates, good hole cleaning, excellent cuttings integrity, and reduced torque. SBMs also provide additional health and safety benefits — higher flash points, lower vapor production, and
reduced eye and respiratory irrita-tion. The major benefit of SBMs over traditional OBMs is the reduced environmental impact of cuttings and liquid mud. Currently, SBMs and cuttings meet U.S. off-shore environmental requirements and may be discharged under WBM protocols.
SBMs are expensive, $200–400 /bbl., depending on the oil/water ratio. Proper solids removal and liq-uid recovery techniques must be used to maintain desired fluid prop-erties and drilling rate, and to control mud maintenance costs. The alternatives to mechanical solids control — dilution and whole SBM additions — are prohibitively expensive when compared to the cost of proper solids control equip-ment.
INTRODUCTION
Of all the problems that could conceivably occur during the drilling of a well, mud contamina-tion from drilled solids is a certainty. The volume and type of solids present in drilling mud exert a considerable influence over mud treating costs, drilling rates, hydraulics, and the possibility of differential sticking, kicks, and lost returns. Solids control is one of the most important phases of mud con-trol — it is a constant issue, every day, on every well. If drilled solids can be removed mechanically, it is almost always less expensive than trying to combat them with chemi-cals and dilution.
The primary reason for using mechanical solids control equip-ment is to remove unwanted drilled solids particles from the mud in order to prevent drilling problems and reduce mud and waste costs, thereby reducing overall drilling costs. The benefits of solids removal by mechanical separation can best be seen in terms of two outcomes: 1) reduced total mud solids and 2) reduced dilution requirements.
2.1
REDUCED TOTAL
SOLIDS
The presence of large amounts of drilled solids in a drilling mud usu-ally spells trouble for the drilling operation. These solids adversely affect the performance characteris-tics of the mud and can lead to a multitude of costly hole problems.
Drilled solids decrease the life of a mud pump’s parts and thus, can decrease drilling efficiency due to lost time for pump repairs. Continued recirculation of drilled solids produces serious mud prob-lems because recirculated solids will gradually be reduced in size. The smaller the solids become, the more they negatively influence mud properties and hydraulic perfor-mance. The greatest impact of the solids is seen in reduced ROP. The higher the drilled solids content, the lower the penetration rate.
If mud solids are not properly controlled, the mud’s density can increase above its desired weight and the mud can get so thick that it becomes extremely difficult or even impossible to pump.
Since the earliest days of the oil-field, drillers have been trying to combat high solids content through the use of settling pits. However,
2.0
BENEFITS OF SOLIDS REMOVAL BY
some drilled solids are so finely ground that they tend to remain in suspension. This results in increased mud viscosity and gel strength which, in turn results in larger particles also remaining in suspension. Thus, the approach of removing cuttings through settling alone is of limited practical value.
Solids control equipment was developed in order to more effec-tively remove unwanted solids from drilling mud. A variety of devices (which will be discussed in detail in Chapter 3 of this handbook) are available which mechanically sepa-rate the solids particles from the liquid phase of the mud. Thus the driller, depending on the particular situation and equipment used, can regulate to a fine degree the amount and size of solids particles that are removed or maintained in any given drilling mud.
Such control of mud solids through mechanical separation allows the mud to perform its drilling-related functions and avoids the downhole problems caused by excessive solids contamination. Effective solids con-trol permits viscosity and density to be kept within desired levels, dramati-cally increases the life of pump parts and drill bits, and promotes faster penetration — all of which decrease the time and expense of drilling.
2.2
REDUCED DILUTION
REQUIREMENTS
A common method of trying to offset the build-up of drilled solids is the addition of more liquid. This is known as dilution and does not remove cuttings but reduces (or dilutes) their concentration in a drilling mud, thereby reducing the percent of total solids in the mud.
However, it is important to note that dilution is expensive. Every barrel of dilution water (or oil) added requires an additional amount of chemicals, barite or other materials in order to maintain desired mud properties. The lower the drilled solids content to be maintained, the greater the dilution required. In the case of an oil-base mud, oil must be used for dilution — which can become extremely expensive.
It should be noted that chemical treatment alone will ultimately result in high solids content and uncontrollable mud properties. The most effective approach is to use mechanical solids control equip-ment to remove as much of the drilled solids as possible before they are incorporated into the mud system and then treat what is left with appropriate amounts of chemi-cals and dilution.
Effective solids removal by mechanical separation can maintain a minimum solids level in drilling
mud and greatly reduce the need for dilution. Reducing the need to dilute the mud can drastically decrease the cost of having to pur-chase mud products such as weight material (barite) and chemicals. These materials are expensive — mud costs can be 10% of the total cost of drilling a well.
The Dilution Ratio Chart (Figure 2-1) can be used indirectly to approximate the amount of dilution that can be eliminated by use of solids removal equipment. For example, suppose a drilling engi-neer required that no more than 5% solids were to be maintained in an unweighted mud. The chart shows that at 5%, each barrel of mud would contain about 45 pounds of drilled solids. If solids control equipment were removing 1 ton (2000 lbs) of solids per hour, then the equipment would save 2000 ÷
45 = 44 barrels of dilution per hour. If the chemicals and additives were worth only $10 per barrel, the mud treating costs would be reduced by approximately $440 per hour! Over the life of a drilling operation, $440 per hour adds up to a very signifi-cant cost savings.
The same procedure can be used to show reduced dilution require-ment in weighted mud. When heavily — weighted muds (16–18 lbs/gal) are being used, drilling usually proceeds more slowly and less drilled solids are removed per hour. However, if approximately 5% drilled solids are allowed in the mud, then each barrel of mud still contains roughly 44 pounds of drilled solids.
Therefore, if the solids control equipment were removing even a pencil-sized stream of solids which would amount to 44 pounds per
MUD WEIGHT (LBS/GAL) TO BE MAINTAINED 8.5 8.6 8.7 8.8 8.9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 10.0 DRILLED SOLIDS PERCENT BY VOLUME 1.2 2.0 2.7 3.5 4.2 5.0 5.7 6.4 7.2 8.0 8.7 9.4 10.2 11.0 11.7 12.4 POUNDS OF 2.6 SPECIFIC GRAVITY SOLIDS PER BARREL OF MUD 11 18 25 32 38 45 52 59 66 73 79 86 93 100 107 114 BBLS OF WATER REQUIRED TO DILUTE
1 TON SOLIDS AND MAINTAIN MUD WEIGHT
182 111 80 63 53 44 38 34 30 27 25 23 22 20 19 18 Figure 2-1 Dilution Ratio Chart
hour, then 44 ÷ 44 = 1 barrel of dilution saved per hour. With the high cost weighted mud (usually a minimum of $30 per barrel), the solids removal equipment would be saving at least $30 per hour. Over an average operation of 20 hours per day, this represents a savings of approximately $600 per day. If the maximum amount of drilled solids were reduced to 3%, the cost savings would double to approximately $1200 per day.
The expense of the dilution liquid is a major factor in considering the advantages of reduced dilution requirements. Oil is obviously much more costly than water, but water also can be expensive if it has to be trucked into a remote drilling location.
The disposal of “waste” mud can also be a significant factor in overall dilution costs. Heavy reliance on dilution to control solids content can result in the addition of so much extra liquid that the volume of mud exceeds the
capaci-ty of the active mud pits. When this happens, whole mud (including all of the expensive additives) must be discarded into waste or reserve pits.
Appropriate use of solids control equipment in place of dilution lessens the vol-ume of the mud system and can usually eliminate the
discarding of excess mud. The size of the active and waste pits them-selves can be reduced due to smaller capacity requirements. Instead of throwing away valuable mud additives, these can be sal-vaged and returned to the active mud system.
If properly used, solids control equipment can virtually eliminate waste liquid mud through a “closed mud system”. In such a system the liquid phase can be recycled — which can be critical in special applications such as when using oil-base or polymer muds, especial-ly offshore, or where environmental concerns prohibit disposal of liquid waste materials. In these cases the cost of hauling the liquid waste away for disposal is also avoided.
Solids removal by mechanical sep-aration can achieve the benefits of low solids content and at the same time significantly reduce the many costs associated with dilution.
INTRODUCTION
The goal of modern solids control systems is to reduce overall well costs by prompt, efficient removal of drilled solids while minimizing the loss of liquids. Since the size of drilled solids varies greatly — from cuttings larger than one inch in diameter to sub-micron size — sev-eral types of equipment may be used depending upon the specific situation. The fundamental purpose for solids removal equipment is just that — remove drilled solids. The end result is reduced mud and waste disposal costs.
To reach this goal, each piece of equipment will remove a portion of the solids, either by screening or centrifugal force. Each type of equipment is designed to economi-cally separate particles of a particular size range from the liq-uid. Also to operate effectively, each type of equipment must be sized, installed, operated, and main-tained properly.
The efficiency of the solids con-trol system can be evaluated by comparing the final volume of mud accumulated while using the equip-ment to the volume of mud that would result if drilled solids were controlled only by dilution. The
overall results of solids removal can be monitored by the use of flow meters to determine the actual mud volume built.
The efficiency of solids removal equipment and/or systems used can be evaluated in two ways:
1) Efficiency of drilled solids removal,
2) Efficiency of liquid conservation. The greater percentage of drilled solids removed, the higher the removal efficiency. The higher the solids fraction of the waste stream, the better. Both aspects should be considered.
For example, a desilter usually does well at removing solids but at the cost of significant losses of liq-uid; sometimes 80% of the volume of the waste stream will be liquid. By contrast, a properly operating shale shaker or centrifuge typically removes 1 barrel or less of mud with each barrel of solids. Most remaining equipment delivers a lesser degree of dryness than do the shakers or centrifuges.
Most solids control systems include several pieces of equipment connected in series. Each stage of processing is partly dependent upon the previous equipment func-tioning correctly so as to allow the next stage to perform its role.
3.0
MECHANICAL SOLIDS CONTROL AND
Should one piece of equipment fail, the equipment downstream will soon lose efficiency or fail com-pletely.
The first piece of equipment used to separate the solids from the mud is usually a vibrating screen or series of screens. The cuttings that are larger than the mesh openings are removed by the screen but carry an adhered film of mud. The screen mesh should be sized to prevent excessive losses of whole mud over the end screen.
The second step is to remove the sand-sized, silt sized and larger clay particles that were not removed in the shakers by using hydrocy-clones. Hydrocyclones with a cone diameter of 6 to 12 inches are called desanders, and hydrocy-clones with a cone diameter of less than 6 inches are called desilters. These units should normally be sized to process 125% of the maxi-mum flow rate used to drill.
Sometimes a screen is used below a hydrocyclone to “dry-out” the
cone’s discharge to minimize the loss of fluid. The hydrocyclone and vibrating screen device is called a mud cleaner or mud conditioner. If a location must be “pitless”, then the screens are essential to mini-mize the liquid waste volume.
The final step may be to remove the ultrafine silt and clay-sized solids with the use of a decanting centrifuge. On a weighted mud, two centrifuges may be used in series: the first to salvage barite, the second to remove fine solids and reclaim the valuable liquid phase.
3.1 PARTICLE
SIZE
AND CUT POINT
Modern drilling rigs may be equipped with many different types of mechanical solids removal devices depending on the applica-tion and requirements of a particular project. Each device has a specific function in the solids control process. Equipment commonly uti-lized and the effective removal range for each are listed in Figure 3-1.
CUT POINT
Notice the removal range, or Cut
Point, is given as a range of the particle size removed. Mechanical solids control equipment classifies particles based on size, shape, and density. It is typical to refer to parti-cles as being either larger than the cut point of a device (oversize) or
smaller than the cut point (under-size).
Figure 3-2 shows a typical cut point curve. The cut point curve represents the amount of solids of a given size that will be classified as either oversize or undersize. Particles to the right of the cut point curve, in the area labeled “A”,
resent the removed, oversize solids. Particles to the left of the curve, in the area labeled “B”, represent the undersize solids returned with the whole mud.
Particular interest is given to three points along the cut point curve, the D50, the D16, and the D84. Given
these three points, the removal characteristics of screens, hydrocy-clones, or other devices can be compared.
The D50, or median cut point, is
the point where 50% of a certain size of solids in the feed stream will be classified as oversize and 50% as undersize. The D16 and D84 are the
points where 16% and 84%, respec-tively, of the solids in the feed stream will be classified as oversize. These two points are statistically significant because they are one standard deviation from the D50 in a
normal distribution. An “ideal” clas-sifier (the dashed line) would show very little difference between the D50, D16and D84.
Separation Efficiency is a measure
of the D50 size relative to the
num-ber of undersize particles that are removed or oversize particles that are not removed. The higher the separation efficiency, the lower the
false classification. An example will assist in understanding this concept. Figure 3-3 shows the cut point curves for two screens, each with the same D50. Curve No.1 is almost
vertical with a small tail at each end. This results in a very sharp, distinct cut point. Almost all parti-cles larger than the cut point are rejected, with very few undersize solids. Almost all particles smaller than the cut point are recovered, with very few oversize particles included.
Curve No. 2 is an S-shaped curve with a large tail at each end. Even though the D50 is the same as for
Curve No.1, the D16and D84are very
different. Many solids larger than the D50are returned with the
under-size solids and many solids smaller than the D50 are discarded with the
oversize solids.
If curves number 1 and 2 in Figure 3-3 illustrate typical removal gradients for two different types of oilfield shale shakers screens, we can draw conclusions about separa-tion performance. The area between the curves marked “A” represents solids Screen No.1 removes and Screen No. 2 returns. Likewise, the area marked “B” represents solids recovered by Screen No.1, but dis-carded by Screen No. 2.
This is not to say that Screen No.1
is “better” than Screen No. 2, or vice versa; it simply illustrates that two devices with similar “cut point” (as measured by the D50 alone) may
perform very differently. As an example, consider solids removal from a weighted drilling fluid using vibrating screens.
An effective solids control pro-gram for weighted mud should remove as many undesirable, sand-sized solids as practical, while retaining most of the desirable, silt-sized barite particles. Referring back to Figure 3-3, Screen No. 2 would return all the sand in area “A” that Screen No.1 would catch, and Screen No. 2 would remove the silt-size material in area “B” (including all weighting material) that Screen No.1 would recover.
Therefore, in a weighted mud, Screen No. 2 would not perform as well as Screen No.1. Further, if the area to the right of both curves (representing total mass solids removal) were calculated, Screen No.1 could prove superior in terms of mass solids removal.
As shown by this example, it is important to view “cut point” as a continuous curve, rather than a sin-gle point. This concept is equally true with screens, hydrocyclones, centrifuges, or any other separation equipment — the relative slope and shape of the cut point curve are more important than a single point on the curve.
3.2
SEPARATION BY
SCREENING
One method of removing solids from drilling mud is to pass the mud onto the surface of a vibrating screen. Particles smaller than the openings in the screen pass through the holes of the screen along with the liquid phase of the mud. Particles too large to pass through the screen are thereby sep-arated from the mud for disposal. Basically, a screen acts as a “go–no go” gauge: Either a particle is small enough to pass through the screen opening or it is not.
The purpose of vibrating the screen in solids control equipment is to transport the cuttings off the screen and increase the liquid han-dling capacity of the screen. This vibrating action causes rapid sepa-ration of whole mud from the oversized solids, reducing the amount of mud lost with the solids.
For maximum efficiency, the solids on the screen surface must travel in a predetermined pattern — spiral, elliptical, orbital or linear motion — in order to increase par-ticle separation efficiency and reduce blockage of the screen openings. The combined effect of the vibration and the screen sur-faces result in the separation and removal of oversized particles from drilling mud.
SCREENING SURFACES
Screening surfaces used in solids control equipment are generally made of woven wire screen cloth, in many different sizes and shapes. The following characteristics of screen cloth are important in solids control applications.
Screens may be constructed with one or more Layers. Non-layered screens have a single layer, fine-mesh, screen cloth (reinforced by coarser backing cloth) mounted on a screen panel. These screens will have openings that are regular in size and shape. Layered screens have two or more fine mesh screen cloths, usually of different mesh (reinforced by coarser backing cloth), mounted on a screen panel. These screens will have openings that vary greatly in size and shape.
To increase screen life, especially in the 120–200 mesh range, manu-facturers have incorporated two design changes:
1) A coarse backing screen to support fine meshes, and 2) Pre-tensioned screen panels.
The most important advance has been the development of preten-sioned screen panels. Similar panels have been used on mud cleaners since their introduction, but earlier shakers did not possess the engi-neering design to allow their use successfully. With the advent of modern, linear-motion shakers,
pre-tensioned screen panels have extended screen life and justified the use of 200-mesh screens at the flowline. The panels consist of a fine screen layer and a coarse back-ing cloth layer bonded to a support grid (Figure 3-4). The screen cloths are pulled tight, or tensioned, in both directions during the fabrica-tion process for proper tension on every screen. The pre-tensioned panel is then held in place in the bed of the shaker.
Today, fine screens may be rein-forced with one or more coarse backing screens. The cloth may also be bonded to a thin, perforat-ed metal sheet. This extra backing protects the fine screen from being damaged and provides additional support for heavy solids loads. The screens equipped with a perforated plate may be available with several sizes options for the perforation to allow improved performance for a given situation.
Most manufacturers limit them-selves to one support grid opening
size to reduce inventory and pro-duction costs. The opening size is typically 1” for maximum mechani-cal support. Brandt / EPI™ provides screen panels with a variety of openings to allow rig personnel to choose the desired mechanical sup-port and total open area (translating to more liquid flow), depending on the application.
Mesh is defined as the number of
openings per linear inch. Mesh can be measured by starting at the cen-ter of one wire and counting the number of openings to a point one inch away. Figure 3-5 shows a sam-ple 8 mesh screen. A screen counter is useful in determining screen mesh (see Figure 3-6).
SCREEN CLOTH
There are several types of wire cloth used in the manufacture of oilfield screens. The most common of these are Market Grade and
Tensile Bolting Cloth. Both of these
are square mesh weaves, differing in the diameter of wire used in their construction.
Market grade cloths use larger diameter wires and are more resis-tant to abrasion and premature wear. Tensile bolting cloths use smaller diameter wire and have a higher Conductance. Since screen
Figure 3-5 Eight Mesh Screen
selection is a compromise between screen life, liquid capacity, and par-ticle separation, both types are in wide use.
OPENING SIZE
Size of Opening is the distance
between wires in the screen cloth and is usually measured in fractions of an inch or microns. Figure 3-7 shows a screen with a 1/2 inch opening.
Screens of the same mesh may have different sized openings depending on the diameter of the wire used to weave the screen cloth. Smaller diameter wire results
in larger screen openings, with larg-er particles passing through the screen. The larger the diameter of the wire, the smaller the particles that will pass through the screen. Remember, it’s the size of the open-ings in a screen, not the mesh count, that determines the size of the particles separated by the screen. Also, normally the larger the diameter of the wire used in the weaving process, the longer the screen cloth will last.
PERCENT OPEN AREA
Percent Open Area is the amount
of the screen surface which is not blocked by wire. The greater the wire diameter of a given mesh screen, the less open space between the wires. For example, a 4 mesh screen made of thin wire has a greater percent of open area than a 4 mesh screen made of thick wire (see Figure 3-8).
The higher the percent of open area of a screen the greater its theo-retical throughput. Open area can
Figure 3-7 One-half Inch Opening
Figure 3-8 Percent of Open Area 4 Mesh: .080 Wire 46.2% Open Area 4 Mesh: .072 Wire 50.7% Open Area 4 Mesh: .063 Wire 56.0% Open Area
be increased for a given mesh by using smaller diameter wire, but at the sacrifice of screen life. The choice of any particular screen cloth therefore involves a compromise between throughput and screen life. Calculating the percent open area for layered screens is difficult and inaccurate. This is due to the ran-dom and wide variety of openings present. Conductance of a screen is an experimental measure of the flow capacity of a screen. The high-er the conductance of a screen, the greater its flow capacity.
SHAPE OF OPENING
Shape of Opening is determined
by the screen’s construction. Screens with the same number of horizontal and vertical wires per inch produce square-shaped open-ings and are referred to as Square
Meshscreens. Screens with a differ-ent number of horizontal and vertical wires per inch produce
oblong — or rectangular — shaped openings and are referred to as
Rectangular (or Oblong) Mesh
screens. This is illustrated in Figure 3-9.
Use of a single number in refer-ence to a screen usually implies square mesh. For example, “20 mesh” usually identifies a screen with 20 openings per inch in either direction. Oblong mesh screens are generally labeled with two num-bers. For example, a 60 x 20 screen has 60 openings per inch in one direction and 20 openings per inch in the other direction.
It has become common industrial practice to add the two dimensions of an oblong mesh screen and refer to the sum of the two numbers as the mesh of the screen.
For example, a 60 x 20 mesh screen is often called an “oblong 80” mesh. This screen has oblong openings measuring 1040 x 193 microns, much larger than the
Figure 3-9 Shape of Opening
square openings of a “square 80” mesh screen (177 x 177 microns). The “oblong 80” will allow much larger, irregularly-shaped particles to pass through its openings than the 80 x 80 square mesh screen.
EQUIVALENT SCREEN MESH
Screen manufacturers now com-pare different types of screen through charts, such as the one shown in Figure 3-10. The oblong-mesh screens listed in the left-hand column remove similar sized solids as the square-mesh screens listed in the right-hand column. These screens are referred to as “equiva-lent”. In actual field use, the conductance and screen life of the oblong mesh screens is noticeably higher than the equivalent square mesh screen, but the shape of the cut point curve discussed earlier is not as sharp or distinct.
In a similar fashion, a layered screen will often be designated by a single number, e.g. “layered 210” mesh. This implies a screen with
openings smaller than a “square 200” mesh screen (74 x 74 microns). However, the actual opening size and shape of a lay-ered screen is a combination of the multiple screen layers and will pro-duce a wide variety of opening sizes and shapes. Therefore, the “layered 210” mesh screen will remove some solids smaller than 74 microns, but will also allow some particles larger than 74 microns to pass through the screen openings.
SCREEN PLUGGING
AND BLINDING
Screen Plugging and Blinding,
while present to some degree on rig shakers fitted with coarser screens, is most frequently encoun-tered on fine screen shakers. If the mesh openings plug with near-size particles or if the openings become coated over, the throughput capaci-ty of the screen can be drastically reduced and flooding of the screen may occur.
Plugging can often be controlled by adjusting the vibratory motion or deck angle, but sometimes requires changing screens to a coarser or finer mesh. A coarser screen should be used only as a temporary solu-tion until the particular formasolu-tion responsible for near-size particle generation is passed. Changing to a finer mesh screen often presents a better, more permanent solution.
Screen blinding is caused by
OBLONG MESH SQUARE MESH
B-20 S-16 B-40 S-30 B-60 S-40 B-80 S-50 B-100 S-60 B-120 S-80
sticky particles in viscous mud coat-ing over the screen opencoat-ings or by the evaporation of water from dis-solved solids or from grease and requires a screen wash-down to cure. This wash-down may simply be a high pressure water wash, a solvent (in the case of grease, pipe dope or asphalt blinding), or a mild acid soak (in the case of blinding caused by hard water). Stiff brush-es should not be used to clean fine screens because of the fragile nature of fine mesh screen cloth.
Screen life of fine mesh screens varies widely from design to design, even under the best of con-ditions, because of differences in operating characteristics. Screen life can be maximized by following these general precautions:
• Keep screens clean.
• Handle screen carefully when installing.
• Keep screens properly ten-sioned.
• Do not overload screens. • Do not operate shakers dry.
SCREEN CAPACITY
Screen Capacity, or the volume of
mud which will pass through a screen without flooding, varies widely depending on shaker model and drilling conditions. Drilling rate, mud type, weight and viscosity, bit type, formation type, screen mesh — all affect throughput to some degree.
Drilling rate affects screen capacity because increases in drilled solids loading reduce the effective screen area available for mud throughput. The mesh of the screen in use is also directly related to shaker capacity because, in general (but not always), the finer a screen’s mesh, the lower its throughput. Increased viscosity, usually associated with an increase in percent solids by volume and/or increase in mud weight, has a markedly adverse effect on screen capacity. As a general rule, for every 10% increase in viscosity, there is a 2–5% decrease in throughput capaci-ty. Figure 3-11 shows the relationship of mud weight, viscosity, and screen mesh on shaker capacity.
Mud type also has an effect on screen capacity. Higher viscosities generally associated with oil-base and invert emulsion mud usually result in lower screen throughput
Figure 3-11 Shaker Capacity v. Mud Weight, Viscosity, and Screen Mesh
than would be possible with a water-base mud of the same mud weight. Some mud components such as syn-thetic polymers also have an adverse effect on screen capacity. As a result, no fine mesh screen can offer a stan-dard throughput for all operating conditions.
Due to the many factors involved in drilling conditions, mud charac-teristics and features of certain models, capacities on fine screen shakers can range from 50 to 800 GPM. Multiple units, most common-ly dual or triple units, can be used for higher throughput requirements. Cascade shaker arrangements, with scalping shakers installed upstream from the fine screen shakers, can also increase throughput.
THREE-DIMENSIONAL
SCREEN PANELS
To increase screen capacity with-out increasing the size or number of shale shakers, three-dimensional screen panels are available. The design of these 3-D, Pinnacle™ shaker screens:
• Provides even distribution of fluid across the screen surface • Eliminates unwanted fluid loss
near the screen edges
• Improves dryness of solids dis-charge
• Allows the use of finer screens 3-D screen panels increase the
usable screen area of a screen panel by corrugating the screen sur-face, similar to the surface of a pleated air filter or oil filter. 3-D screen panels are most effective when installed as the submerged, feed-end screen on linear-motion shakers to take full advantage of the additional screen area. Past the fluid end point, a three-dimensional screen tends to “channel” the drilled solids and increases solids bed depth and the amount of liquid carried off the screen surface. Using a flat screen at the discharge end of the shaker eliminates chan-neling, increases cuttings dryness, and decreases fluid loss.
STANDARDIZATION
Standardization of screen cloth
designations has been recommend-ed by the API committee on Standardization of Drilling Fluid Materials, in API RECOMMENDED PRACTICE 13E (RP13E), THIRD EDITION, MAY 1, 1993. The pur-pose for this practice is to provide standards for screen labeling of shale shaker screen cloths. The pro-cedures recommended for labeling allow a direct comparison of sepa-ration potential, the ability to pass fluid through a screen, and the amount area available for screen-ing.
The API screen labeling includes of the following:
1. Manufacturer’s designation; 2. Separation Potential and 3. Flow Capacity.
The Manufacturer’s designation contains the individual company’s procedures for naming their screens. It may include the type of screen panel, composition and other data required by the manufac-turer.
The API separation potential is reported in the terms of three “Cut” points. The term “Cut” point is not the same as the traditional cut point. The “Cut” point allows a ranking of a screen’s separation potential that can be used to com-pare screen performance. Three values (D50, D16, and D84) imply the
opening sizes and variation in opening size of the screen.
Flow capacity is the rate at which a shaker can process mud and solids. Under constant conditions, a shale shaker has a flow capacity that depends upon screen conduc-tance and area. The area available for screening is the net unblocked area, in square feet, available for fluid passage through the screen panel. Conductance defines the ease of passage of a fluid through a piece of wire cloth. Conductance is calculated from the mesh count and wire diameters of the screen. Transmittance is the product of conductance times panels area.
These designations give the end user a more accurate assessment of solids removal capability and liquid throughput capacities of competi-tive screens.
3.3
SHALE SHAKERS
The first line of defense for a prop-erly maintained drilling fluid has been, and will continue to be, the shale shaker. Without proper screen-ing of the drillscreen-ing fluid durscreen-ing this initial removal step, reduced effi-ciency and effectiveness of all downstream solids control equip-ment on the rig is virtually assured.
The shale shaker, in various forms, has played a prominent role in oilfield solids control schemes for several decades. Shakers have evolved from small, relatively sim-ple devices capable of running only the coarsest screens to the models of today. Modern, high-perfor-mance shakers of today are able to use 100 mesh and finer screens at the flowline in most applications.
This evolutionary process has taken us through three distinct eras of shale shaker technology and per-formance as shown in Figure 3-12. These eras of oilfield screening development may be defined by the types of motion produced by the machines:
• Elliptical, “unbalanced” design • Circular, “balanced” design. • Linear, “straight-line” design
The unbalanced, elliptical motion machines have a downward slope as shown in Figure 3-12, A. This slope is required to properly trans-port cuttings across the screen and off the discharge end. However, the downward slope reduces fluid retention time and limits the capaci-ty of this design. Optimum screening with these types of shak-ers is usually in the 30–40 mesh (400–600 micron) range.
The next generation of machine, introduced into the oilfield in the late 1960s and early 1970s, pro-duces a balanced, or circular, motion. The consistent, circular vibration allows adequate solids
transport with the basket in a flat, horizontal orientation, as shown in Figure 3-12, B. This design often incorporates multiple decks to split the solids load and to allow finer mesh screens, such as 80–100 square mesh (150–180 micron) screens.
The newest technology produces linear, or straight-line, motion, Figure 3-12, C. This motion is developed by a pair of eccentric shafts rotating in opposite direc-tions. Linear motion provides superior cuttings conveyance and is able to operate at an uphill slope to provide improved liquid retention. Better conveyance and longer fluid retention allow the use of 200 square mesh (74 micron) screens.
Today, shale shakers are typically separated into two categories: Rig Shakers and Fine Screen Shakers.
RIG SHAKERS
The rig shaker is the simpler of two types of shale shakers. A rig shaker (also called “Primary Shale Shaker” or “Coarse Screen Shaker”) is the most common type of solids control equipment found on drilling rigs. Unless it is replaced by a fine screen shaker, the rig shaker should be the first piece of solids control equipment that the mud flows through after coming out of the hole. It is usually inexpensive to operate and simple to maintain.
Standard rig shakers generally have certain characteristics in com-mon (see Figure 3-13):
• Single rectangular screening surface — usually about 4’ x 5’ in size. Some designs have uti-lized dual screens, dual decks and dual units in parallel to provide more efficient solids separation and greater throughput. Depending on the particular unit and screen mesh used, capacity of rig shakers can vary from 100–1600 GPM or more.
• A low-thrust horizontal vibrator mechanism, using eccentric weights mounted above, or central to, the screen basket. • Vibration supports to isolate
the screen basket from its skid.
• Skid with built-in mud box (sometimes called a “possum belly”) and a bypass mecha-nism.
• Method of tensioning screen sections.
Screen sizes commonly used with rig shakers range from 10 to 40 mesh. Figure 3-14 shows the parti-cle sizes separated by these mesh screens. In this graph the area to the left of each line represents solids which are smaller than that mesh size. These would pass through the screen and would not be removed. The area to the right of each line represents solids that are larger than the mesh size and would be removed from the mud.
In Figure 3-14, the area to the
Figure 3-13 Rig Shaker components MUD TANK
(POSSUM BELLY)
LIQUID and FINE SOLIDS DISCHARGE CHUTE MOTOR BELT GUARD VIBRATOR ASSEMBLY
COARSE SOLIDS DISCHARGE SCREEN
BASKET ASSEMBLY
right of the 10 mesh line is con-fined, because it is limited by the size of the page. In actual usage, this area is unlimited. This means that a 10 mesh screen will remove all particles larger than 1910 microns — it doesn’t matter if they are the size of BBs, marbles or baseballs — they will be removed and discarded by a 10 mesh screen. Rig shakers are generally ade-quate for top hole drilling and for shallow and intermediate depth holes when backed up by other solids control equipment. For deep-er holes and when using expensive mud systems, fine screen shakers are preferred.
FINE SCREEN SHAKERS
The fine screen shaker is the more complex and versatile of the two types of shale shakers. Fine
screen shakers remove cuttings and other larger solids from drilling mud, but are designed for greatly improved vibratory efficiency over simple rig shakers. They are con-structed to vibrate in such a way that they can use screens as fine as 150–200 mesh and still give reason-able screen life.
They are versatile pieces of equip-ment and can operate on all types of mud. Figure 3-15 shows the range of particle sizes separated by the screens commonly used with fine screen shakers.
A fine screen shaker can be installed on the rig in one of four ways:
1. Instead of the conventional rig shaker for use from top hole to total depth, if it is of a design capable of using coarse screens as well as fine screens.
2. Placed in series with the rig shaker by tapping into the flow line with a “Y”, thus keeping the rig shaker available as a “scalping shaker”.
3. Replacing the rig shaker after top hole is completed.
4. Downstream from the rig shak-er to accept fluid aftshak-er it passes through the coarse screen shaker (requires secondary pump).
Because fine screen shakers have a wide variety of designs, they have few characteristics in common. The various designs are differentiated by screen orientation and shape, screen tensioning mechanism, placement and type of vibrator and other special features.
Screen Orientation and Shape
refers to the arrangement of the
screen or screens in the unit. Screens are usually rectangular and may be single screens or multiple screens placed in series or in paral-lel, as shown in Figure 3-16.
Single deck, single screens (Figure 3-16 A & B) are the simplest design, with all mud passing over one screen of uniform mesh. This type of shaker requires efficient vibrator mechanisms to function properly under all possible drilling condi-tions and requires high throughput (Conductance) per square foot of screen cloth.
Units with screens placed in par-allel (Figure 3-16 C, D & E) have two or more screen sections acting as one large screen so that no cut-tings can fall between them. All screen sections should be the same mesh, since the coarsest mesh sec-tion determines the unit’s screening ability.
Shakers with screens stacked in series (Figure 3-16 F) have a coarse screen above a finer screen, with the finer screen being the controlling mesh size. The operating theory is that the top screen will remove some of the cuttings from the mud to take part of the load off the bot-tom screen and thereby increase overall screening efficiency.
SCREEN TENSIONING
MECHANISMS
Shakers are designed to use either a hookstrip or a rigid panel screen. Hook strip screens are made with-out a rigid frame and can prematurely fail if installed and allowed to operate with uneven tension. The shaker manufacturer’s instructions for screen installation should be followed, but the follow-ing steps may apply:
• Inspect the supports and
ten-sion rails to be sure they are in good condition and clean • Position the panel on the deck
and inspect the screen to be sure it lays flat
• Install both rails loosely to the hookstrip
• Push one side of the screen against the positioning blocks, if present; and fully tighten the screen against these blocks • Evenly tighten the tension bolts
on the other side
• Torque to the manufacturer’s recommended setting
Rigid panel screen installation should proceed as per the manufac-turer’s instructions. Panel screens can usually be installed or replaced much quicker than a hookstrip screen since the cloth is already pretensioned and the mechanical devices lock the panel with much less manual effort.