hdbk drilling fluids

Drilling Fluids Handbook

Energy Technology Company

Drilling & CompletionsFluids & Waste Management Team

Version 2-09November 2009

©2009 by Chevron Energy Technology CompanyAll rights reserved. This document is company confi dential. No part of this handbook shall be reproduced, stored in a retrieval system or transmitted by any means – electronic, mechanical, photocopying, recording or otherwise – without written permission from Chevron.

Warning and DisclaimerThe information presented herein is believed by Chevron ETC to be accurate. However, no representations are made concerning this information to any user and none shall be implied. Under no circumstances shall Chevron ETC or its responsible personnel be liable for any damages, including without limitation, any special, incidental or consequential damages, which may be claimed to have resulted from the use of any information contained herein.

I

Drilling Fluids Handbook, Version 2-09

Table of Contents

CHAPTER 1: Introduction

Introduction ................................................................................. 1

CHAPTER 2: Drilling Fluid Properties

Mud Weight or Density ............................................................ 2

Funnel Viscosity ........................................................................ 5

Rheology ..................................................................................... 5

Filtration / Fluid Loss Control ............................................... 16

Solids Content ........................................................................... 19

Properties Specific to Water Base Fluids .......................... 22

Properties Specific to Non-Aqueous Drilling Fluids ....... 26

CHAPTER 3: HES Impacts of Drilling Fluids

Drilling Fluids Health and Safety .......................................... 33

Environmental Impacts of Drilling Fluids and Cuttings .. 34

CHAPTER 4: Water Base Drilling Fluids

Spud Muds ................................................................................ 39

Low Solids Non-Dispersed Fluids (LSND) ........................... 41

Low pH/Polymer Fluids ........................................................ 45

KCI/Polymer Fluids ................................................................ 50

Salt Water Fluids .................................................................... 55

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CHAPTER 4: Water Base Drilling Fluids (Cont’d.)

Sea Water Muds ..................................................................... 56

Saturated Salt Water Fluids ................................................ 58

Lignite/Lignosulfonate ......................................................... 60

High Performance Water Base Drilling Fluids .................. 63

CHAPTER 5: Non-Aqueous Fluids

Base Fluids ............................................................................... 66

Internal Phase .......................................................................... 73

Viscosifiers ............................................................................... 74

Emulsifiers ................................................................................ 75

Fluid Loss Additives ............................................................... 78

Weighting Agents .................................................................... 79

Gas Solubility .......................................................................... 80

Flat Constant Rheology NAF ............................................... 80

Product Safety and Handling .............................................. 82

Displacement Procedures .....................................................83

Logging ..................................................................................... 84

Troubleshooting ..................................................................... 85

CHAPTER 6: Chemistry Concepts

Solubility ......................................................................... 88

Common Drilling Fluid Chemicals ........................................ 92

Osmosis ................................................................................... 105

Thermal Degradation, Oxidation and Hydrolysis .......... 107

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CHAPTER 7: Hole Cleaning

Hole Cleaning Regimes ......................................................... 110

Hole Cleaning in a Vertical Well ........................................... 111

Hole Cleaning in a Deviated or Horizontal Well ............... 113

Best Practices ........................................................................ 124

ECD and Standpipe Pressure Management .................... 128

CHAPTER 8: Solids Control Equipment

Introduction……………………………………………………………………132

Solids Removal Efficiency ................................................... 136

Shale Shaker ........................................................................... 137

Hydrocyclones ........................................................................ 143

Centrifuges ............................................................................. 146

CHAPTER 9: Material Transportation and Handling

Palletized Material ................................................................ 150

Drummed Material ................................................................. 151

Bulk Liquid Materials ............................................................ 152

Bulk Bags ................................................................................ 157

CHAPTER 10: Common Drilling Fluid-Related Problems

Lost Circulation ...................................................................... 161

Stuck Pipe ............................................................................... 183

Barite Sag ............................................................................... 192

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CHAPTER 10: Common Drilling Fluid-Related Problems (Cont’d.)

Wellbore Breathing ............................................................... 198

CHAPTER 11: Fluids-Related Productivity Optimization

Formation Damage ................................................................. 211

Formation Protection ............................................................ 217

Drill-In Fluids ......................................................................... 220

CHAPTER 12: Corrosion and Acid Gases

Introduction………………………………………………………………….230

Oxygen Corrosion ................................................................ 234

Carbon Dioxide (Sweet Corrosion) .................................. 236

Hydrogen Sulfide (Sour Corrosion) ................................. 239

Bacteria-Induced Corrosion .............................................. 243

CHAPTER 13: Gas, Foam, and Aerated Drilling Fluid Systems

Controlling Lost Circulation .............................................. 246

Reducing Formation Damage and Improving Productivity ................................................................................................... 247

Increasing ROP ..................................................................... 248

System Types ........................................................................ 249

References ......................................................................... 267

Chapter 1: Introduction

Energy Technology Company | 1

CHAPTER 1: INTRODUCTION

The Fluids and Waste Management Team's Drilling Fluids Handbook is an effort to capture the knowledge and experience of Chevron ETC personnel, Fluids & Waste Management Team, and Fluids Community of Practice and provide Chevron DSM’s and drilling engineers with practical and applicable information that will help them to plan, analyze, and make decisions on drilling fluids related operations on the rig.

There are a number of fluids handbooks and mud manuals in the industry, but this Handbook is unique in its content and audience. The other handbooks are targeted at mud engineers and, as such, are focused on their specific daily tasks, such as running mud checks and vendor-specific product information. By contrast, the Drilling Fluid Handbook covers what the mud checks are, as well as explains what the results mean to the overall operations. It encompasses fluid-related drilling issues, their causes and the methods of mitigation, and, crucially, how these issues interrelate with the entire drilling operation. The Handbook covers related topics such as HES issues, solids control, drilling optimization, and so on, but from a fluids-centric standpoint, and in a very practical fashion.

We want to provide concrete methods of handling fluids related issues; something that a DSM can use as an easily accessible reference that can assist in making day to day fluids decisions. Many times drilling fluid decisions are left to the service company personnel to the extent that we may miss opportunities by not having the fluids planning, performance evaluation, and problem solving as a fully integrated part of our operations. The hope is that this Handbook will help bridge the gap in a concise and practical way.

Chapter 2: Drilling Fluid Properties


CHAPTER 2: DRILLING FLUID PROPERTIES

This section covers the drilling fluid properties reported on the daily mud check and how they may be related to current or potential hole problems. When guidelines are presented, it must be remembered that all situations are different and adjustments to the guidelines must be made.

For instance, when an influx of gas or formation fluid into the wellbore occurs, the fluid density is usually increased to create a hydrostatic pressure overbalance with the formation. Using another example, when drilling a highly deviated well and torque or drag is an issue, this may indicate the hole is not being properly cleaned, so the yield point may be elevated or a sweep program is initiated. There may also be times when problems occur and it is not so easy to determine what drilling fluid properties need to be changed and potentially optimized. A troubleshooting guideline table for common fluid contaminants and treatment is included as Appendix 2-1.

Mud Weight or Density

Mud weight or density is the most important fluid property for balancing and controlling downhole formation pressures and promoting wellbore stability. Mud densities may be measured and reported in pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), or grams per milliliter (g/mL), and conversion factors between the measurements are listed in Table 2-1.



To Convert Multiply By To Obtain

lb/gal 7.481 lb/ft3

lb/gal 0.119826 g/mL

Table 2-1: Density conversion factors

As most drilling fluids contain at least a little air/gas, the most accurate way to measure the density is with a pressurized mud balance. The pressurized mud balance is similar to the conventional mud balance, but has a pressurized fixed volume sample cup. By pressurizing the sample, any entrained air or gas is compressed to a negligible volume, giving a more accurate fluid density measurement.

The density of a non-aqueous fluid (NAF), also referred to as organic phase fluid (OPF1), is temperature and pressure dependent. Temperature affects the density due to the thermal expansion or contraction of the base oil being used. Base fluid will expand with increasing temperature, resulting in a density decrease. When the temperature of the base fluid decreases, the fluid density will increase. Additionally, when the fluid is subjected to pressure, the base fluid will compress causing an increase in density.

1 Organic phase fluid is the terminology used to describe non-aqueous drilling fluids in the North Sea/OSPAR regulated areas.



The operational impacts of mud weight or density include:

Insufficient mud weight could result in:

o Wellbore instability or collapse – If the hydrostatic pressure exerted by a column of drilling fluid falls below the formation pressure, the wellbore can become mechanically unstable. When in a shale section, instability may be observed by increased torque and drag and/or excessive amounts of shale that may tend to be larger in size than typical drill cuttings. If in an unconsolidated sand section, sloughing sand may become a problem.

o An influx of formation fluids – oil, water (fresh or salt), gas (hydrocarbon bearing or acid type such as H2S/CO2).

Excessive mud weights (i.e. high overbalance compared to formation pressure) could result in:

o Decreased rates of penetration (ROP)

o Lost circulation due to induced formation fractures

o Stuck pipe

o Reservoir damage due to increased filtrate invasion

For NAF’s, the equivalent static density (ESD) will usually be higher than that of a water base fluid of the same density, due to the compression of the base fluid. In some situations this compression in the base fluid and increase in density could result in lost circulation.



Funnel Viscosity

The funnel viscosity of a drilling fluid is measured with a MARSH™ Viscosity Funnel. The MARSH Funnel is designed so that the outflow time of one quart of freshwater (946 cm3) at a temperature of 70° F ±5° F (21° ±3° C), is 26 ± 0.5 seconds.

With all drilling fluids, especially NAF’s, the viscosity of the base fluid is temperature dependent and the fluid will thin as the temperature increases, in turn reducing the funnel viscosity. The limitation of the MARSH Funnel is that the viscosity is measured at only one rate of shear and the sample is not at a constant temperature and therefore does not give an accurate representation of the flow properties of a drilling fluid. However, it is a quick, simple test and provides a tool for spotting changes/trends in a circulating drilling fluid, particularly with water base muds.

Rheology

Rheology is defined as “the study of the deformation and flow of matter”. Rheological measurements of a drilling fluid include plastic viscosity (PV), yield point (YP) and gel strengths. The information from these measurements can be used to determine hole cleaning efficiency, system pressure losses, equivalent circulating density, surge and swab pressures and bit hydraulics. Water base and non-aqueous fluids charts containing typical PV and YP values for various densities are located in Figures 2-1 and 2-2, respectively. It should be noted that these charts do not consider the effects of lost circulation material or bridging agents.



Figure 2-1: Plastic viscosity and yield point range for water base mud

Figure 2-2: Plastic viscosity and yield point range for non-aqueous fluids



Plastic Viscosity (PV)

Rheological measurements are usually made on a 6-speed rotary viscometer. The shear rate is measured at 600, 300, 200, 100, 6, and 3 revolutions per minute (rpm). Plastic viscosity reflects the physical concentration, size and shape of solid particles in the mud in addition to the viscosity of the fluid phase. The PV is calculated as the difference in the 600 and 300 rpm rheometer readings (600 rpm reading – 300 rpm reading). PV will increase with any increase in solids content, whether from barite, drilled solids, or other materials.

A heat cup should be used to adjust the sample to the appropriate temperature as outlined below:

Water Base Mud – Usually 120°F

NAF

o Usually 120 or 150°F

o Deepwater – 80 to 90°F

HTHP Wells – 150°F

There is a direct correlation between high mud weights and high PV’s, but an increasing PV trend with a constant mud weight is usually an early warning sign of an increase in ultra-fine drilled solids in the mud. High plastic viscosities are usually undesirable and increasing trends in the plastic viscosity should be noted.

High PV’s can cause high circulating pressures for fluids within the drill string and through the bit. Decreasing particle size increases surface area, which increases frictional drag. Plastic viscosity is decreased by reducing the solids concentration through dilution or by mechanical separation. As the viscosity of the base fluid decreases with increasing temperature, the plastic viscosity decreases proportionally. Figures 2-3 and 2-4



depict the average solids range of water base and non-aqueous fluids, respectively.

Figure 2-3: Average solids range for water base muds

Figure 2-4: Average solids range for non-aqueous fluids



Emulsified water in a NAF will act like a solid and effectively increase the PV. Changes in temperature of a NAF will also be reflected in the PV reading. For example, PV’s will decrease with increasing temperature and increase with decreasing temperature.

The operational impacts of plastic viscosity are:

Rate of Penetration (ROP) - Any increase in plastic viscosity, whether it is from material such as barite, hematite or calcium carbonate intentionally added to the system or a buildup of fine drilled solids due to inefficient solids control equipment or inadequate dilution rates, may negatively impact the ROP.

Equivalent Circulating Density (ECD) - As the plastic viscosity increases, the ECD will also increase.

Surge and Swab Pressures - When plastic viscosity increases, surge and swab pressures will also typically increase.

Differential Sticking - When increases in plastic viscosity are due to a buildup of fine drilled solids, the propensity for differential sticking will increase, especially in a water base drilling fluid. Along with an increase in PV, there could be a corresponding increase in reactive solids as determined by the methylene blue test.

Yield Point (YP)

Yield point (YP) is a measure of the attractive forces between the colloidal particles in the mud and is defined as the 300 rpm reading minus the PV. These colloidal particles include reactive clays, such as bentonite and polymers that are added to a system, as well as a buildup of fine, clay-rich drilled solids. YP is a useful component



of viscosity and gives an indication of the ability of the fluid to carry cuttings efficiently out of the hole.

The YP value is directly related to the frictional pressure loss of fluids in laminar flow, which are affected by this particular interaction, in turn affecting pressure losses in the annulus and equivalent circulating density. In general, drilling fluid rheology should be designed utilizing products that enhance low shear rate yield point (LSRYP). In this instance, LSRYP does not necessarily imply 6 and 3 rpm readings, but those are the measurements available with the 6-speed rheometer. There are times, especially when drilling large diameter holes (≥12.25 inches), that 6 and 3 rpm readings will be the shear rates that must be controlled because they provide a better indication of the hole cleaning ability of the drilling fluid. Keep in mind that a high YP does not necessarily equate to adequate hole cleaning.

In water base fluids, contaminants such as salt, anhydrite and carbon dioxide, as well as high temperature environments, will increase YP. Additions of lime or caustic soda may also increase YP in water base systems using clay, especially with overtreatment. Contaminants should always be identified and treated as quickly as possible; however, the use of thinners and/or dilution can be an effective temporary solution until the contaminant can be neutralized.

Operational impacts of YP include:

Equivalent Circulating Density (ECD) – As YP increases, there is usually an increase in ECD. When all parameters are equal, the increase in ECD usually is higher when using a NAF than when using a water base mud. This is partially due to the compressibility and kinematic viscosity of the base oil being used.



Hole Cleaning – Usually the larger diameter hole that is being drilled, the higher the YP must be to promote efficient hole cleaning.

Gel Strengths

Gel strength measurements show both the rate and the degree with which reactive particles in a drilling fluid interact in a static fluid to form a gel structure. Gel strengths are important for maintaining the suspension of barite and drill cuttings when circulation is stopped. Measurements are made on a rheometer using the 3 rpm speed and readings are taken after stirring the mud at 600 rpm to break all the gels. A first reading is taken after the mud has been static for 10 seconds, a second after 10 minutes. It is also highly recommended to take a 30 minute reading to be sure the mud is not likely to gel excessively during long static periods like a bit trip.

Water base drilling fluids should develop a low, rapid initial gel strength (10 second), usually just above the 3 rpm value and should remain relatively flat with time. For NAF’s, typical gel strength readings might be 8 (10 second) and 12 (10 minute), represented as 8/12, respectively. Gel strength readings similar to 3 / 30 or 9 / 55 would be considered progressive and undesirable in a normal drilling fluid.

Highly progressive gel strengths can lead to high pump initiation pressures being required to break circulation after mud in the hole has remained static for a period of time, such as after a trip. A progressive 30 minute gel strength reading is indicative of a buildup of fine and ultrafine reactive solids in the mud and indicates that the mud requires dilution and/or treatment.

High gel strengths in water base muds can be the result of chemical contaminants such as cement, lime, anhydrite, gypsum, acid gases such as carbon dioxide



(CO2) and hydrogen sulphide (H2S), salt and bacteria. In NAF’s, high gel strengths are usually the result of a buildup of fine reactive solids or overtreatment with organophilic gelling agents and not chemical contamination.

The operational impacts of gel strengths are as follows:

Surge/Swab Pressures – Highly progressive gel strengths can lead to high pump initiation pressures being required to break circulation after mud in the hole has remained static for a period of time, such as after a trip. These high pump pressures could result in fractures to the formation, inducing lost circulation. In addition to 10 second and 10 minute gel strengths, it is a good practice to run 30 minute gel strengths. The 10 second and 10 minute values may appear acceptable, but the 30 minute value may be progressive in nature and provide a better measure of the effect the fluid condition will have on surge and swab pressure (Figure 2-5). A progressive 30 minute gel strength reading is indicative of a buildup of fine and ultrafine reactive solids in the mud and indicates that the mud requires dilution.

Cuttings Suspension – Drilling fluids that exhibit ultra low gel strengths will not efficiently suspend cuttings. This could lead to fill after trips and connections, drill string pack-off resulting in loss of circulation, as well as cuttings beds in directional holes.

Barite Sag – Low gel strengths can lead to barite sag in weighted fluids. This situation will be evident by large fluctuations in the density of the mud coming out of the hole. This phenomenon is most noticeable in directional wells after a trip.



Figure 2-5: Gel strength development

Rheological Models

Rheological models are used to predict the behavior of drilling fluids under flowing conditions. Examples of the fluid’s behavior in drilling applications include the pressure drop, equivalent circulating density and hole cleaning performance.

The flow behavior of drilling fluids is governed by two flow regimes, namely laminar flow which prevails at low velocities, and turbulent flow that occurs at high velocities. The critical velocity where the flow changes from laminar to turbulent is dependent on pipe diameter, density, and viscosity. It is expressed by a dimensionless number, the Reynolds number, which lies between 2000 and 3000 for most drilling fluids. In the turbulent flow regime, flow is disorderly and flow equations are determined empirically.

Laminar flow is orderly and the pressure-velocity relationship is a function of the viscous properties of the



fluid. The laminar flow equations are based on certain flow models that relate the flow behavior to the flow characteristics of the fluid. Most drilling fluids do not conform exactly to any one of the models, but their behavior can be reasonably predicted by one or more of them. Simply stated, a rheological model is a description of the relationship between the shear stress () and the shear rate (), otherwise known as the consistency curve. The consistency curves for some of the more common models are shown in Figure 2-6.

Figure 2-6: Consistency curves for common flow models

Newtonian

Fluids containing particles no larger than a molecule (e.g. water, salt solution, light oil) can be described by the Newtonian model. These fluids are those in which the



consistency curve is a straight line passing through the origin. The viscosity of a Newtonian fluid is described by the slope of the consistency curve, and remains constant for all shear rates. Because viscosity does not change with rate of shear, it is the only parameter needed to characterize the flow properties of a Newtonian fluid. Nearly all drilling fluids exhibit more complex non-Newtonian behavior.

Bingham Plastic

The Bingham Plastic model is the most common model used to describe the rheological properties of non-Newtonian drilling fluids. This model assumes that the shear stress is a linear function of shear rate once a specific shear stress has been exceeded (the threshold shear stress or yield point). The shear stress divided by the shear rate, at any given rate of shear, is known as the effective or apparent viscosity.

The plastic viscosity and yield point are calculated from conventional viscometer data taken at 600 and 300 rpm. After the PV and YP values have been determined, the model can be used to determine the shear stress at any given shear rate.

Power Law

The Power Law model describes a non-Newtonian fluid in which the consistency curve passes through the origin and can be described by the following exponential equation:

Shear stress = K (shear rate)

Where K = the fluid consistency index and = the power law exponent. The parameter K is the shear strength at a shear rate of 1 sec-1 and corresponds approximately to



the yield point. is a measure of the rate of change of viscosity with shear rate, and is generally inversely proportional to the shear thinning characteristic of the fluid. Most drilling fluids exhibit behavior in between ideal Bingham Plastic and ideal Power Law fluids.

Filtration / Fluid Loss Control

API Fluid Loss Test

The API fluid loss test uses the standard API filter press with a differential pressure of 100 psi and ambient temperature. It can also be referred to as the API low pressure fluid loss test. To obtain correlative results, one thickness of the proper 7.5 cm2 filter paper, WHATMAN™ No. 50, S & S No. 576, or equivalent, must be used. At the end of 30 minutes, the volume of filtrate is measured. Solids in a drilling fluid are deposited against permeable formations by differential pressure forming a filter cake. The most desirable filter cake is one that is thin and impermeable, resulting in a low fluid loss. This test does not simulate downhole conditions. It provides an excellent method for identifying a change in the fluid loss trend, but does not provide any useful information about how the fluid will behave under downhole conditions. The API fluid loss test can be misleading in that the test will show what appears to be a very acceptable fluid loss value with a very thin filter cake at surface conditions. The best fluid loss data will be gained by subjecting the fluid to simulated downhole temperatures and pressures.

The operational impacts of API fluid loss test are:

Torque and drag - High fluid loss values will result in a thick buildup of filter cake across permeable zones. Filter cake buildup will be more severe when a high differential pressure



exists across the zones. Excessive torque may be experienced under dynamic conditions (circulating fluid), although if the cake buildup is not severe, an increase in torque may go unnoticed. Under static conditions, e.g. tripping pipe or logging, the filter cake buildup may be very noticeable, resulting in excessive drag.

Differential Sticking - Flocculated clay particles do not form impermeable filter cakes. High filtration rates deposit more clay particles to the rock face, forming a very soft, thick, mushy filter cake that can be very sticky due to the increased contact area of the drillstring. This situation can often lead to occurrences of stuck pipe, especially in water base muds. This is particularly true in the static state, in which a thick, sticky filter cake may be formed even if the mud has a relatively low fluid loss. Fluids in a dynamic state (circulating) will work to erode a filter cake that formed under static conditions.

Formation Damage - High filtration rates will result in fluid and fine particle invasion leading to solids plugging, impairing production if the permeable rock is also a reservoir.

HTHP Fluid Loss Test

Although exact conditions cannot be simulated at the wellsite, the high temperature high pressure (HTHP) test is a much better indicator of drilling fluid stability under downhole conditions than the API fluid loss test. Like the API test, the HTHP test provides an indication of drilling fluid filtrate lost to the formation under static conditions over a specific period of time.

The HTHP test can be performed at various differential pressures and temperatures. The sample cell is placed in



a heating jacket so the sample temperature can be adjusted to more closely match downhole conditions. It is recommended that the test temperature be run at 25 to 50° F above the current estimated bottom-hole temperature. Performing the test at this temperature will help ensure that the drilling fluid is not being under treated or over treated for the current drilling environment. In addition, the test should be performed at 500 psi differential pressure. Like the API fluid loss test, the HTHP test is run for 30 minutes. Due to the size of the HTHP test cell, the filtration area is 50% that of the API test, therefore the filtrate collected should be doubled to provide the correct result. After the test is complete and the cell is allowed to cool and the pressure relieved, the remaining fluid should be observed for excessive gelation.

Drilling fluids, especially water base, tend to exhibit viscous mud in the cell after the test is completed. This can be due to several reasons, but is typically caused by dehydration of the mud (high filtrate loss) or the fluid contains a high content of reactive clay. Furthermore, the HTHP filter cake should be inspected for thickness and quality. HTHP filter cakes deposited by water base drilling fluids will tend to be thick and tough, where as those associated with NAF tend to be thin and slick. These additional observations can be very helpful when experiencing hole problems.

The presence of water in the filtrate from the HTHP fluid loss test conducted on NAF can be an indicator of a weak emulsion or water-wet solids.

Filter Cake

Solids in a drilling fluid are deposited against permeable formations by differential pressure forming a filter cake. The most desirable filter cake in both the API and HTHP



fluid loss tests is one that is thin and impermeable, resulting in a low fluid loss. The rule of thumb for filter cake thickness is to keep it less than or equal to 2/32 inch. Thick filter cakes usually occur with high static filtration rates and may lead to stuck pipe.

Operational impacts of filter cake include:

Torque/Drag - A buildup of thick filter cake across permeable zones is usually the result of high fluid loss values. Thickness of the filter cake will be more severe when a high differential pressure exists across the zone. Excessive torque may be experienced under dynamic conditions (circulating fluid), although if the filter cake thickness is not severe, an increase in torque may not occur. Under static conditions, e.g. tripping pipe or logging, the filter cake buildup may be very noticeable and detected by excessive drag.

Differential Sticking – As the filter cake becomes increasingly thicker across zones that are permeable and severely overbalanced, the propensity to stick tubulars, regardless of whether it is drillpipe or casing, will be increased. A thick filter cake may develop across zones that may be highly permeable and not too hydrostatically overbalanced, resulting in “wall” sticking.

Solids Content

The solids content, measured by retorting (boiling off the liquid portion), is the total solids fraction present in the mud. This includes both soluble and insoluble drilled solids and soluble and insoluble mud additives; those which are necessary and those which are undesirable.



The breakdown of the solids into soluble (salt), insoluble high gravity (weight material), or insoluble low gravity solids (LGS) may be calculated.

Drilled solids are the worst contaminant that may be incorporated into drilling fluids. That statement may be considered radical at first look because the effect of drilled solids on fluid properties is not nearly as dramatic as the effect of cement or salt on fresh water drilling fluids. Nevertheless, during normal drilling operations, drilled solids will be incorporated into the mud and as a general rule must be reduced to 6-7% by volume.

The effect of increasing solids concentrations in drilling fluids can be very subtle, but will ultimately result in increased viscosity, circulating pressures, ECDs, surge and swab pressures. Penetration rates will suffer as the solids content of the mud increases. Filter cakes will become thicker and softer, increasing the potential for differential sticking.

Drilled solids concentrations are extremely important and should be calculated on a daily basis. The upper limit for drilled solids in a good mud will be dependent upon the type of fluid being used. For weighted fluids, an upper limit of 6-7% or approximately 60 lb/bbl is recommended. Most drilling fluids can tolerate elevated drilled solids contents, without too great an effect on mud properties, but overall performance will be diminished.

Another property that is usually reported along with high gravity solids (HGS) and low gravity solids is the average density of the solids in the drilling fluid. Barite and clay/silt have specific gravities (S.G.’s) of 4.2 and ~ 2.6 mg/L, respectively. Average solids density provides a quick measure of the relative concentrations of low gravity and high gravity solids. Average solids density values of ~ 3.8 or higher are considered acceptable levels. Readings below 3.5 suggest that there may be too



high of a concentration of low gravity solids in the mud. Water base and non-aqueous fluids charts containing the average solids content for various densities are located in Figures 2-3 and 2-4, respectively. It should be noted that these charts do not consider the effects of lost circulation material or bridging agents.

The operational impacts of solids content are:

Rate of Penetration– ROP can be negatively impacted by a high level of solids in the drilling fluid. Solids intentionally added to the fluid, such as barite for density and calcium carbonate for bridging will inhibit ROP, but there is very little that can be done in these situations. Maintaining drilled solids within an acceptable range will be helpful in providing an optimum ROP, provided other parameters such as hydraulics are optimized.

Equivalent Circulating Density– An increase in solids, regardless of whether they are LGS or HGS, will lead to an increase in ECD. Excessive ECD’s can lead to loss of circulation or wellbore breathing. Low gravity solids must be maintained in an acceptable range to minimize the impact of ECD.

Surge/Swab Pressures - High solids contents, especially drilled solids, may lead to excessive surge and swab pressures. A certain amount of drilled solids is necessary to build gel structure for barite and cuttings suspension, but drilled solids that are high and not in line with good practices will cause gel strengths to be excessive leading to unacceptable surge and swab pressures.

Differential/Filter Cake Sticking - Undesirable LGS in the drilling fluid can lead to filter cakes



that are thick, mushy and sticky. This condition may result in a higher propensity for incidents of differential sticking.

Properties Specific to Water Base Fluids

Chemical Properties

The chemical properties of water base drilling fluids are very important and must be analyzed. The drilling fluid chemistry can greatly affect the performance of the fluid in its ability to solubilize organic additives (e.g. lignite, lignosulfonate), promote or inhibit the hydration of bentonite and polymers, control the corrosion rate of tubulars as well as aid in the identification of contaminants like cement, salt and acid gases.

pH

pH is a numerical value of the concentration of hydrogen ions in a solution and is a direct measurement of the acidity or alkalinity of the solution. The pH scale (0 to 14) is an inverse measurement of the hydrogen ion concentration. Therefore, the more hydrogen ions present, the more acidic the substance and the greater the decrease in pH. A pH of 7 is considered to be neutral. Fluids with a pH below 7 are acidic and those above 7 are referred to as basic or alkaline.

Alkalinity is defined as the concentration of both water-soluble and insoluble ions that neutralize acid. Essentially there are three groups of ions that may perform this function. They are the hydroxyl ions (OH-), carbonate ions (CO3

-2) and bicarbonate ions (HCO3-).

Hydroxyl ions are useful and ideally the pH of the mud should be primarily controlled with the presence of hydroxyl ions. Carbonate and bicarbonate ions may be



considered contaminants. High carbonate and bicarbonate alkalinities may cause excessive viscosities and gellation tendencies in water base drilling fluids.

The pH is measured most accurately with a pH meter, not pH paper. Meters should be calibrated daily to ensure the most accurate measurements.

Operational impacts of pH include:

Acid gases (H2S/CO2) – An influx of an acid gas will result in a rapid decrease in the pH. With this rapid drop in pH, the YP, gel strengths and fluid loss values will increase and be very difficult to control in a water base drilling fluid. Additionally, the Pm and Pf will have a corresponding decrease in value.

Carbonates/Bicarbonates – The presence of CO3

-2 and HCO3- will adversely affect the fluid

loss control in water base muds containing a high clay content.

Anhydrite – A decrease in pH could be an indication that anhydrite is being drilled. In this situation, there should be a corresponding increase in the hardness content.

Water Flow – Typically, a decrease in pH will be observed if an influx of water occurs.

Pm

The “phenolphthalein end point of the mud” or Pm provides an indication of the amount of caustic soda, KOH, lime, cement, etc in a water base mud and not just the filtrate. Phenolphthalein will indicate the alkaline end point at a pH of 8.3. The Pm value includes both dissolved and non-dissolved alkalinity in the mud. It is mainly used in lime muds to determine the ratio of



insoluble lime in the whole mud to soluble lime in the filtrate.

The Pm will increase when cement is drilled. The Pm could become very high if the cement is “green”, as a large quantity of the cement will be incorporated into the system instead of being removed by the solids control equipment.

Pf / Mf

The “phenolphthalein end point” (Pf) and “methyl orange end point” (Mf) are measurements that are made on the mud filtrate which help determine ions that are responsible for pH.

If the Pf and Mf are nearly equal, hydroxyl ions (OH-) are mainly contributing to the alkalinity

If the Pf and Mf are both high, then carbonate ions (CO3

-2) are present

If the Pf is low and the Mf is high, bicarbonate ions (HCO3

-) are present

There will always be some carbonate and bicarbonate ions. These ions are more detrimental in high clay content muds than in low clay content muds. If the Mf is more than 10 times the Pf, carbonate alkalinity may be a problem, especially if the LGS clay content is high. Elevated funnel viscosities, yield points and gel strengths may also be present with a carbonate alkalinity. The definitive test for measuring soluble carbonates in mud filtrate is done with a Garrett Gas Train. Carbonates are usually treated out with additions of lime and/or gypsum.



Total Hardness

Total hardness is a measurement of the total soluble calcium (Ca+2) and magnesium (Mg+2) ions present in a water base mud filtrate. Excessive hardness may cause:

flocculation of clays in the mud

inhibition of clay hydration

inhibition of polymer effectiveness

inhibition of treatment chemical effectiveness

high filtration rates

thick/mushy filter cakes

Additionally, calcium and magnesium ions will compete with potassium (K+) ions in reacting and stabilizing formation clays. As both are higher on the reaction series, they will prevent the K+ ion from making the desired clay basal exchange in potassium chloride (KCl) muds and should be precipitated out of the system. This can be done with additions of soda ash or by increasing the pH with caustic soda. If the pH is to be maintained less than 9.5, then bicarbonate of soda (bicarb) can be used instead of soda ash or caustic soda.

Total hardness should be maintained below 300 mg/L in most water base drilling fluids, except for lime muds, where it is usually run slightly higher (~400 mg/L).

Chloride Content

The chloride content of water base muds is measured by titration of the mud filtrate. Chlorides should be monitored and any significant change in the trend should be noted. Changes in the chloride trend could indicate an influx of water (fresh or salt) or penetration of a salt bearing formation.



Chlorides are sometimes maintained in the mud with additions of salts, such as sodium chloride (NaCl) and potassium chloride. Chlorides are maintained in sufficient concentration to aid in shale inhibition. If KCl is being used, it will be necessary to provide sufficient potassium ions to fully react with the clays encountered. A minimum of 3% KCl will be sufficient in most cases. Occasionally, the KCl concentration will need to be increased to as high as 15% to control some highly reactive formation clays.

Methylene Blue Test (MBT)

The methylene blue test (MBT), also known as the cation exchange capacity (CEC) test, uses a cationic dye which strongly attracts to the negatively charged sites on clays. The test provides a measure of the reactive clay concentration (as bentonite equivalent) of a water base drilling fluid in pounds per barrel.

Smectite clays have large basal surface areas that are negatively charged and therefore have the highest capacity to adsorb methylene blue dye of any clay. Some reactive clay is useful and necessary, but too much can lead to problems.

Increasing CEC’s are usually an indication of an increase in drilled solids concentrations. In most low solids drilling fluids, CEC’s should be maintained at ≤15 lb/bbl equivalent or less.

Properties Specific to Non-Aqueous Drilling Fluids

Electrical Stability (ES)

The electrical stability (ES) of a non-aqueous fluid is the voltage necessary to induce current to flow through the



mud. The magnitude of this voltage is controlled by a number of factors but is primarily an indicator of the emulsion stability of the fluid. This test is often referred to as the emulsion stability test. NAF’s are non-conductive; therefore to induce an electrical current to flow through the fluid, the emulsion must be broken, allowing the current to flow through the water fraction in the fluid. The ease or difficulty at which this may occur is dependent on the strength of the emulsion, but may also be affected by the solids content and type, oil/water ratio, degree of shearing, temperature, acid gas contamination and many other factors. Conductive solids, such as some fibrous materials, hematite, and insoluble (excess) salt, will indicate a weak emulsion, but in actuality, the emulsion stability will be sufficient.

The ES should be tracked for changes instead of targeting any specific value. It is normal for the ES to gradually increase as a mud is used. Incorporation of water into the mud, such as from drilling green cement, or from a water kick, may temporarily reduce the ES voltage. In most cases this is not an indication of a problem with the emulsion. There is no specific voltage number that indicates if the emulsion is sufficient or not. If the emulsion is believed to be weak, the HTHP filtration test should be conducted at 25 to 50°F above the bottom-hole temperature. If there is no free water found in the filtrate, the ES is most likely sufficient for the operation.

Alkalinity / Excess Lime

Lime (calcium hydroxide) is added to most non-aqueous drilling fluids to react with fatty acid emulsifiers and form a calcium soap. A quantity of excess lime (3 to 5 lb/bbl) is usually maintained in the system to ensure that enough hydroxide is available to maintain a strong emulsion. Lime is also carried in the system as a first line



of defense for controlling acid gases (CO2 and H2S). If CO2 or H2S is anticipated, the excess lime content should be increased and maintained at 5 to 10 lb/bbl. In the case of H2S, the excess lime content must not be allowed to deplete as the reaction of lime and H2S is reversible and may result in the release of H2S at the surface.

Note: When H2S is anticipated, it is recommended that a scavenger be added to the system (see Table 2-2 below).

Fluid Type H2S Scavenger

Water Base 1. Zinc Oxide

2. Basic Zinc Carbonate

3. Zinc Chelate

4. Iron Oxide

NAF 1. Zinc Oxide

Table 2-2: Recommended H2S scavengers

Water Phase Salinity

Water phase or internal phase salinity is controlled by the addition of a salt to the mud. The salt is dissolved in the water phase of the mud, thereby increasing the salt concentration of the internal phase. The objective of salt additions is to lower the activity by increasing the chloride content of the internal phase to the point where its activity is equal to or less than the formation water, so that water does not move out of the mud and weaken shales. The salt used can be one of a large number that are available, but is usually calcium chloride (CaCl2). The drill cuttings associated with NAF’s are usually hard and brittle. If the cuttings being generated are wet, mushy



and stick together on the shaker screens, the chloride content of the internal phase may need to be increased. This condition may also be the result of water-wet solids. A typical range is usually 25 to 30 wt% CaCl2, but lab tests on offset cores or cuttings can help to determine the concentration needed. This range is also necessary for hydrate prevention in deepwater operations.

Oil or Synthetic:Water Ratio

The fractions of oil or synthetic base fluid and water in a mud are determined by retorting, which also determines the solids content. The oil or synthetic:water ratio (OWR or SWR) is a ratio of the relative percentages of these fluids in the liquid portion of the mud.

Calculations:

The volume % water in the liquid portion of the mud is:

The volume % oil in the liquid portion of the mud is:

OP = 100 - WP The oil:water ratio is: OP:WP

The volume % brine in the oil + brine portion of the mud is:

BO

B

VVV

PB )(100

The volume % oil in the oil + brine portion of the mud is:

OP = 100 – Bp

WO

W

VVV

PW )(100



The oil:brine ratio is: OP:BP

Vw = volume fraction water in the whole mud

VO = volume fraction oil in the whole mud

VB = volume fraction brine in the whole mud

In NAF’s, when the water fraction of the fluid is increased, the plastic viscosity will generally increase, as the water behaves like a

solid in these systems. Additionally, the fluid loss will decrease and the yield point and gel strengths will increase. When water additions are made, emulsifier additions will also be necessary to ensure that a strong emulsion is maintained.

Contaminant Compound/Ion Source Method of

Measurement Possible Effect

on Fluid Course of Action

Anhydrite, Gypsum

CaSO4, CaSO4 · 2H2O / Ca+2, SO4

-2

Formation, Commercial gypsum

Ca+2 titration High yield point High fluid loss High gels Thick filter cake Ca+2 increase

Treat with Sodium carbonate (soda ash): Ca+2 (mg/L) x 0.00093 = Na2CO3 (lbm/bbl) Break over to a gypsum fluid

MgCl2 MgCl2 / Mg+2, Cl-

Formation, Sea water

Total hardness, Cl- titration

High yield point High fluid loss High gels Thick filter cake Total hardness increase pH decrease Pf decrease Cl- increase

Treat with caustic soda, NaOH (pH ≥ 10.0) for moderate contamination, e.g. sea water Mg+2 (mg/L) x 0.00116 = NaOH (lbm/bbl) Treat with additional thinner and fluid loss chemicals Convert to MgCl2 fluid if contamination is severe NOTE: for severe contamination, continued additions of NaOH or Ca(OH)2 will result in unacceptable viscosity increase.

Cement, Lime

Ca(OH)2 / Ca+2,

OH- Cement, Commercial lime, Contaminated barite

Titration for Ca+2, Pm

High yield point High fluid loss Thick filter cake pH increase Pm increase Ca+2 increase

Treat with sodium bicarbonate Ca+2 (mg/L) x 0.00074 = NaHCO3 (lbm/bbl)

Treat with SAPP Ca+2 (mg/L) x 0.00097 = Na2H2P2O7 (lbm/bbl)

Treat with lignite, 7 to 8 lbm/bbl precipitates 1 lbm/bbl Ca(OH)2 to form Ca+2 salt of humic acid

Additional thinner/fluid loss chemicals

Centrifuge to remove contaminant particles

Dilution

Dump if flocculation cannot be controlled

Allow Ca(OH)2 to remain in convert lime fluid or allow Ca(OH)2 to deplete over time

In some cases, use acids such as HCl, phosphoric

Appendix 2-1: Troubleshooting guideline for common fluid contaminants and treatment



Appendix 2-1: Troubleshooting guideline for common fluid contaminants and treatment (continued)

Contaminant Compound/Ion Source Method of

Measurement Possible Effect

on Fluid Course of Action

Cement, Lime (cont’d.)

Treat with soda ash if light contamination Ca+2 (mg/L) x 0.00093 = Na2CO3 (lbm/bbl)

Since effects of pH are often more detrimental to fluid order, chemical treatment should be:

1. Sodium bicarbonate 2. Lignite 3. SAPP 4. Soda ash

Sodium bicarbonate is treatment of choice

Salt NaCl / Na+, Cl-

Formation, i.e., salt dome, stringers, salt water, make-up water

Cl- titration High yield point High fluid loss High gels Thick filter cake Cl- increase

Dilution with fresher water Addition of thinner/fluid-loss chemicals reasonably tolerant of NaCl Convert salt fluid using chemicals designed for salt Presolubilize chemicals where possible Dump if flocculation is too severe for economical recovery

Carbonate, Bicarbonate

CO3-2,

HCO3-

Formation gas, CO2 gas, thermal degradation of organics contaminated barite, overtreatment with soda ash or bicarbonate

Garrett Gas Train, pH/Pf method, Pf/Mf titration

High yield point High 10-min gels High HTHP fluid loss Ca++ decrease Mf increase pH decrease

Treat with lime: HCO3

- (mg/L) x 0.00021 = Ca(OH)2 lbm/bbl and CO3-2 (mg/L) x 0.00043 = Ca(OH)2

lbm/bbl

Treat with gypsum: CO3

-2 (mg/L) x0.001 = CaSO4 · 2H2O lbm/bbl and caustic soda: HCO3- X 0.0025 =

NaOH lbm/bbl

Hydrogen Sulfide

H2S / H+, S-2

H2S from formation gas, thermal degradation of organics, bacterial action

Garrett Gas Train (quantitative). Automatic rig H2S monitor (quantitative). Lead acetate test.

High yield point High fluid loss Thick filter cake pH decrease Pm decrease Ca+2 increase

Course of action to be in compliance with all safety requirements Pretreatment/treatment with basic zinc carbonate Increase pH ≥ 11.0 with Ca(OH)2 or NaOH Condition fluid to lower gels for minimum retention of H2S Operate degasser, possibly with flare Displace with oil-base fluid. Add excess Ca(OH)2 to precipitate S-2 and neutralize acid

Chapter 3: HES Impacts of Drilling Fluids


CHAPTER 3: HES IMPACTS OF DRILLING FLUIDS

Many different types of drilling fluid systems are used in drilling operations and while the fluid’s technical and economic requirements are the main driver, local environmental regulations and waste disposal considerations also determine which type of drilling fluid system will be used.

The choice for a water base mud (WBM) or non-aqueous fluid (NAF) depends on the formation to be drilled and the particular technical requirements needed to drill the well successfully, e.g. temperature, pressure, shale reactivity. A WBM is generally used in the upper hole sections of the well, while a NAF tends to be used in the more technically demanding sections. Non-aqueous fluids are also known as organic phase fluids (OPF) in areas such as the North Sea.

Chevron has adopted Operational Excellence as a key strategy to protect the safety and health of employees, contractors, the general public and the environment. One of the expectations of Operational Excellence is that we will identify and mitigate key environment risks. Fluid and cuttings discharge criteria will be dictated by local and federal regulations, and the local HES team should be able to assist with interpretation of the regulations.

The Chevron Global Upstream Environmental Performance Standard (EPS) relating to drilling operations and waste management can be found under the GU_ES section at the following address:

http://upstreamandgasresources.chevron.com/uc/ oe_hes/oe_processes/gu_processes.aspx

Another reference for drilling fluid usage and waste management is the ETC Drilling Waste Management



(DWM) Handbook. The DWM Handbook describes benefits and advantages of various waste management techniques and processes along with best practices. It can be found at the following address:

http://etc.chevron.com/teamfluidswaste/publications .asp

Drilling Fluids Health and Safety

Occupational exposure to chemicals is a daily occurrence for many workers in the oil and gas industry. All chemicals used in drilling operations should be identified and controlled. This requires an appropriate Material Safety Data Sheet (MSDS) which informs the user of active ingredients in the substance and their health classifications. It also gives a classification of the substance and guidance on its use, transportation and safe handling.

Drilling crews may be exposed to drilling fluids either by skin contact or by inhaling aerosols, vapor and dust. When skin is exposed to drilling fluids the most frequent effects are skin irritation and contact dermatitis. The highest potential for inhaling mist and vapor exists along the flow line from the bell nipple to the shale shakers and mud pits. The preparation and use of drilling fluid systems may generate airborne contaminants in the workplace, including dust, mist and vapor. The potential for inhalation of dust is mainly associated with mixing operations. Refer to the MSDS and ensure that a Job Safety Analysis (JSA) covers the proper handling of chemicals. It is important to use proper personal protective equipment (PPE) (e.g. safety glasses/shield, chemical resistant gloves, dust shield, apron) when handling potentially harmful chemicals such as low/high pH additives and concentrated brines.



The type of exposure is often dependent upon the state of the additive. Most solid additives take the form of fine powders and present an inhalation hazard. Liquid components potentially pose a dermal exposure hazard during fluid formulation and mixing. With liquids, there is also a risk of inhalation exposure where sprays, mists or vapor are formed. The vapor pressure and flash point of base oils are critical to the vapor concentration and fire risk in enclosed spaces, such as around the shale shakers and mud pits. The flash point of whole mud will be greater than that of the base fluid. Lower flash point base fluids are likely to give off greater amounts of vapor with an increased potential for health problems and fire risks.

As drilling fluids are not intended for ingestion, oral exposure is unlikely and negligible as compared to the other routes of exposure. However, oral exposure should not be ignored when contaminated hands are used to handle food or to smoke. Good hygiene practices should always be followed.

Lifting guidelines should be adhered to when manually transporting sack material as well as other heavy products. The use of pre-mixed fluids, smaller sacks and/or automated/mechanical handling systems has been shown to reduce the possibility of injury and exposure. Refer to safe lifting practices/regulations prior to handling products.

Environmental Impacts of Drilling Fluids and Cuttings

The environmental impacts of drilling fluids and cuttings depend upon their chemical composition, treatment and disposal method as well as the receiving environment. For example, high levels of sodium chloride in drilling fluids will have little impact if discharged into a marine



environment whereas discharge of the same drilling fluid into a freshwater stream would have a greater environmental impact.

Onshore Impacts

Onshore environmental issues focus primarily on toxicity, the usability of land, and the potential for contamination of ground water. Onshore treatment methods include bioremediation, solidification/stabilization and thermal desorption. Disposal methods for drill cuttings include reserve pits/burial, landfill and drill cuttings injection. These methods vary in acceptable cuttings characteristics, treatment/disposal rate and cost. Refer to local regulations, the Chevron EPS and ETC Drilling Waste Management Handbook for further guidance.

The primary considerations involved in onshore drilling fluid/cuttings treatment and disposal are the concentrations of heavy metals, salts and hydrocarbons. Most countries and states have regulations regarding treatment and disposal of fluids and cuttings that place limits on these concentrations.

Hazardous metals such as mercury, cadmium, chromium and lead may be present in many of the formations drilled and may also be found in some drilling fluid additives such as chrome lignosulfonate. Heavy metals do not biodegrade and can bioaccumulate in the food chain that may lead to health problems. The most commonly encountered heavy metal is barium (in the form of barium sulphate) from barite weighting agent. However, barium sulphate is highly insoluble in water and has a low mobility in soils preventing ground water leaching. Of more concern are heavy metals such as cadmium and mercury associated with impurities in some sources of barite. Most regions and operators now



specify limits on these heavy metal contaminants of barite.

Salts such as sodium or potassium chloride are often used in drilling fluids for shale inhibition and density control, and can impact soil and water quality. Measurements, such as electrical conductivity (EC), cation exchange capacity (CEC) and sodium adsorption ratio (SAR) can be used to assess the potential impact and necessary treatments.

Excess sodium can replace calcium and magnesium ions in clays creating “sodic” soils. These soils have poor water permeability and soil texture that can adversely affect plant growth. Salt compounds can also inhibit plant growth by limiting their ability to take up water.

Offshore Impacts

The effects of mud and cuttings discharges on the offshore environment depend on the type and amount of fluid on the cuttings, the cuttings settling rate and the local conditions. The location and shape of the cuttings pile depends on the speed and direction of the current and the water depth. For example, environments with high currents tend to erode piles and speed up seabed recovery. Deep water also tends to increase dispersion and limit the heights of piles.

WBM

Most WBM’s have low acute aquatic toxicity and any heavy metals associated with the WBM’s are not bioavailable. Rapid dispersion of the WBM at the point of discharge means they tend to have a low impact on the local environment.



As a general rule, the effects of WBM and cuttings discharges on the seabed are related to the total mass of drilled solids discharged. When WBM and the associated cuttings are discharged to the ocean, the larger particles quickly settle to the sea bed. If discharged at or near the sea surface, the mud and cuttings disperse over a wide area and are deposited as a thin layer. If the cuttings are discharged just above the sea floor (this is sometimes done to protect nearby sensitive marine habitats), the solids may accumulate in a large, deep pile.

Water base muds may contain small amounts of hydrocarbon lubricants to increase lubricity and reduce stuck pipe occurrences. The levels of these lubricants are limited by local regulations. Although small amounts of formation hydrocarbons can be noticeable in a WBM, cuttings usually do not contain sufficient formation hydrocarbons to be harmful to the environment. The oil content of any fluid used to drill a reservoir section should be monitored prior to discharge and if necessary, the cuttings should be contained and shipped to shore for treatment and disposal.

NAF

Whole NAF should not be discharged to the ocean. In some locations, NAF drill cuttings may be treated (e.g. using cuttings dryers) to remove the excess fluid and discharged to the ocean, particularly if the base fluid is synthetic.

Impacts to the water column from discharging NAF cuttings are considered to be negligible because the cuttings settle quickly (i.e. exposure times in the water column are low) and the water solubility of the base fluid is low. Because of their rapid settling and non-aqueous nature, NAF cuttings disperse less readily in the water column than WBM cuttings and do not increase water column turbidity. The NAF fluid and cuttings can affect



the environment mainly by impacting the seafloor. Refer to the Chevron EPS and local regulations for further guidance.

Rates of biodegradation depend upon seafloor conditions (temperature, oxygen availability, sediment type and fluid concentration) as well as fluid type. Crude oil, diesel and other long chain and highly branched hydrocarbons are more difficult for microbes to biodegrade. Short chain hydrocarbon molecules like those used in synthetic base fluids are easier for the bacteria to consume.

Field studies show that synthetic base mud levels in sediments decline much more rapidly than with traditional mineral oil base mud. The areas that recovered the most rapidly were those in higher energy environments with plenty of aeration, mixing and biological activity.

Chapter 4: Water Base Drilling Fluids


CHAPTER 4: WATER BASE DRILLING FLUIDS

Water base drilling fluids have been used extensively since drilling first began. In recent years, their use has diminished, giving way to the use of non-aqueous fluids (NAF’s). This is primarily due to the superior drilling performance and wellbore stability provided by NAF. However, for various reasons, there are some areas where water base drilling fluids remain the fluid of choice. Reasons leading to their continued use over NAF include logistics and cost as well as environmental constraints. Outlined in this chapter are some of the more commonly used water base drilling fluids that are likely to be found in Chevron operations. The common characteristic that most of these fluids have is the fact that they are, at least to some degree, considered inhibitive. It should be recognized that the formulations included are generic and should be engineered for each individual application.

Spud Muds

Spud muds are used to initiate drilling operations. These fluids have good hole cleaning characteristics and are capable of being built quickly and cheaply. They are often required to support unconsolidated formations. Table 4-1 shows some typical spud fluid formulations.



Fluid Type Product Concentration

(lb/bbl)

Fresh water spud fluids

Bentonite

Lime

Soda ash

20 - 25

1 – 2

To reduce hardness to below 150 mg/L for bentonite pre-hydration

Salt water Salt Water Gel 25 - 35

Sea water/ pre-hydrated gel

(Mix sea water and pre-hydrated gel 50:50)

Bentonite

Caustic

Lime

30 - 40 (Pre-hydrate in freshwater)

0.5 - 1.0

0.5 - 1.5

Table 4-1: Spud mud formulation

Maintenance

Build fresh volume as hole is drilled.

Add bentonite or alternative viscosifier, e.g. salt water gel, as required for viscosity.

Use water to reduce viscosity. Due to their cost, thinners are not normally used with spud fluids.

Small amounts of lime may be added, along with salt water gel, to increase the yield of the clay in sea and salt water muds.

Contaminants

Usually contaminants are not a problem, but to obtain maximum yield of the bentonite, the hardness should be reduced to less than 150 mg/L. Additionally, as chlorides



increase, the yield of bentonite will decrease. Chlorides (Cl-) and hardness, in the form of calcium (Ca+2) and magnesium (Mg+2), will inhibit the ability of bentonite to absorb water; in turn, reducing its yield (viscosifying ability).

Low Solids Non-dispersed Fluids (LSND)

Low solids non-dispersed fluids are primarily used to obtain improved penetration rates and hole cleaning in areas where conventional gel chemical fluid systems give poor to moderate performance. This type of system uses various materials to extend the yield of the clays, resulting in significantly lower total solids content. Laboratory and field data show a strong correlation between the use of low solids fluids and improved penetration rates. In addition, proper use of these polymer extenders will result in the flocculation of low- yield solids (drilled solids) and optimum effectiveness of solids removal equipment.

Secondary benefits derived from this system include the following:

Reduced water requirements

Lower total transportation cost

Reduced wear on pumps and surface equipment

Improved bit life

Better shale stability

The basic system is freshwater, bentonite, and a bentonite extender (flocculant). The concentration depends upon the suspension properties required for hole cleaning.

Table 4-2 shows a typical LSND formulation and Table 4-3 depicts typical mud properties.



Product Concentration

Bentonite 8 – 14 lb/bbl

Bentonite Extender ( e.g. BEN-EX™)

0.5 – 0.1 lb/bbl

Caustic Soda As needed for pH 9.5

Soda Ash Treat Ca+2 below 150 mg/L

Table 4-2: Typical formulation for LSND Fluids

Property Value

Funnel viscosity

Plastic viscosity

Yield point

Gels

Filtrate

34 - 38 sec/qt

5 - 7 cp

6 - 9 lb /100 ft2

4 - 6 lb /100 ft2

12 - 15 mL

Table 4-3: Typical mud properties for LSND Fluids

If additional filtration control is required, 0.5 to 1.0 lb/bbl (1.4 to 2.8 kg/m3) of a water soluble polyacrylate such as sodium polyacrylate (SPA) may be used.



Maintenance

This system is maintained in the following manner:

For maximum penetration rates, the fluid density should be maintained at 8.8 lb/gal (≤3% solids). Fluid density should not exceed 9.0 lb/gal (6% solids by volume).

The typical amount of bentonite extender required per foot of hole drilled to flocculate drilled solids is as follows (always add the appropriate amount of extender when adding bentonite or barite to the system):

o 2 lb extender for every 500 lb bentonite

o 2 lb extender for every 4000 lb barite

Use available solids control equipment, or dilute with water to control the drilled solids to bentonite ratio at 2:1 or less.

Treat new volume (from water addition) with the extender and chemicals daily.

With weighted fluids, as weight increases, maintain lower bentonite concentration.

Contaminants

Low solids non-dispersed fluids are quite sensitive to chemical contaminants such as Ca+2, Mg+2, Cl– and HCO3

–. In addition, improperly treated drilled solids, and even bentonite and barite, can act as contaminants. The most common problem relating to fluid viscosity is inadequate treatment with an extender.

Specific chemical contaminant levels are as follows:

[Ca+2] maximum, 100 mg/L: treat with soda ash or bicarbonate of soda



[Cl–], 5000 to 10,000 mg/L: dilute with freshwater

[HCO3–], [CO3

-2] should be minimized

Refer to Table 4-4 and Table 4-5 for problems in unweighted and weighted low solids non-dispersed (LSND) fluids respectively.

Table 4-4: Troubleshooting unweighted LSND fluids

Problem Weight Viscosity MBT Low-

Density Solids

Calcium Treatment

Weight too high

_ Normal Normal High Normal

Increase settling time

Add extender or flocculant

_ High High High Normal

Potential bentonitic formation

Dilute, add extender

Viscosity too high

Normal _ High Normal Normal Dilute, add extender

Stop adding bentonite

Normal _ Low High Normal

Add extender and bentonite

Check solids equipment

High _ High High Normal

Use solids control equipment

Add extender and water

Normal _ Normal Normal Normal Add extender

Normal _ Normal High High Add soda ash and extender or flocculant

Viscosity too low

Normal _ Low Normal Normal Add bentonite and extender

Normal _ High Normal Normal Pilot test with extender Add extender or reduce treatment

Normal _ High Normal High Treat calcium with soda ash




Density Solids

Calcium Treatment

Fluid loss too high

_ Normal Low Normal Normal Add bentonite and extender

_ Normal Normal Normal Add SPA, or CMC

_ High Normal Normal High Remove calcium with soda ash or bicarbonate of soda

Table 4-4: Troubleshooting unweighted LSND fluids (continued)


Density Solids

Calcium Treatment

Viscosity

too low

Normal _ Low Normal Normal Add extender and bentonite

Normal _ Normal Normal Normal MBT, due to drilled solids, dilute, add gel and extender

Viscosity too high

Normal _ High Normal Normal Add extender or SPA, or CMC

Normal _ Normal Normal Normal Add extender or SPA, or CMC

Normal _ Normal Normal High Treat with soda ash or bicarbonate of soda (high pH)

HTHP Fluid loss too high

Normal Normal Normal Normal Normal Add bridging or coating agent ( e.g. asphaltics)

Normal Normal Low Normal Normal Add extender and SPA

Normal Normal

High Normal Normal High Remove calcium

Table 4-5: Troubleshooting weighted LSND fluids

Low pH/Polymer Fluids

A low pH/polymer fluid is characterized by the presence of a high molecular weight partially-hydrolyzed polyacrylamide (PHPA) polymer. PHPA acts as a protective colloid. It functions as a shale, cuttings and wellbore stabilizer. By bonding to sites on reactive shale,



PHPA inhibits dispersion of formation solids into the fluid system. PHPA fluids are based upon low solids non-dispersed (LSND) fluid technology. Table 4-6 shows typical Low pH/polymer formulations.

Fresh

Water

Sea

Water NaCl KCl

Make-Up Water (% by vol.)

Fresh water

Sea water

100

~

50

50

50

50

100

~

Electrolyte

NaOH/KOH

NaCl, % by wt

KCl, % by wt

*

~

~

*

~

~

*

Up to 20%

~

*

~

Up to 15%

Viscosifier

Bentonite, lb/bbl

XCD POLYMER™, lb/bbl

10-20

~

10-20**

0.1-0.5

10-20**

0.1-1.0

10-20**

0.1-1.0

Fluid Loss (lb/bbl)

PAC Regular

PAC LV

LIGNITE

Starch

Modified Starch

0.5-1.0

0.5-1.0

1.0-6.0

~

0.5-6.0

0.5-1.0

0.5-1.0

2.0-8.0***

1.5-2.0

0.5-6.0

0.5-2.0

0.5-2.0

2.0-8.0***

1.5-3.0

1.0-8.0

0.5-2.0

0.5-2.0

2.0-8.0***

1.5-3.0

0.5-8.0

Rheology (lb/bbl)

Sodium Polyacrylate (SPA)

DESCO™

0.25-2.0

0.25-5.0

0.25-2.0

0.25-5.0

0.25-2.0

0.25-5.0

0.25-2.0

0.25-5.0

Shale-Control Additives

PHPA, lb/bbl

0.25-1.5

0.25-1.5

0.25-2.0

0.25-2.0

Secondary Shale-Control Additives SOLTEX™, lb/bbl

2.0-8.0 2.0-8.0 2.0-8.0 2.0-8.0

* To pH = 10.0

**Pre-hydrated in fresh water

***Pre-hydrated in pre-mix

Table 4-6: Low pH/polymer formulations



The following are general guidelines for the preparation and maintenance of low pH/PHPA systems.

Methylene Blue Test (MBT)

The low pH/PHPA system provides the best performance with MBT values maintained in the 15 to 20 lb/bbl (42.8 to 57.1 kg/m3) equivalent range. In general, an MBT of less than 20 lb/bbl equivalent is recommended. MBT values above 20 lb/bbl (57 kg/m3) equivalent may result in high rheological values (yield point and gel strengths) and may require dilution or use of a deflocculant.

Gel Strengths

It is common for 10 minute gels to reach 35 lb/100 ft2. Drilling conditions and economics should determine the need to reduce gel strengths. Report initial, 10 minute, and 30 minute gels on all low pH/PHPA systems.

Filtrate pH

Fresh Water System

A filtrate pH of 8.0 to 9.0 is optimum for fresh water systems. Caustic soda or caustic potash additions should be made slowly to avoid a high pH. Carefully add caustic materials to the system through the chemical barrel.

Sea Water System

When hardness reduction is necessary for fluid loss control, a pH of 9.5 to 9.7 should be maintained.



Range for Filtrate Hardness (Ca+2 and Mg+2)

Fresh Water System

Maintain a total hardness level of the fluid at a concentration of 200 to 300 mg/L calcium as this range tends to show the best stability.

Sea Water System

If low rheological and fluid loss values are not necessary, sea water systems may be maintained at natural pH and hardness. This is especially true when the objective of the system is to control gumbo shale.

Filter cake quality and fluid loss control are adversely affected by high hardness (>400 mg/L). Therefore, when sand sections are drilled, the pH of the system may be increased to chemically suppress the hardness level. In sea water, the pH should be raised initially with caustic soda or potassium hydroxide to a maximum value of 9.5 to 9.7. This will precipitate most of the magnesium. Additions of soda ash and/or sodium bicarbonate should then be used to precipitate out calcium to the desired hardness level.

Fluid Loss

The filter cake quality of the PHPA system makes fluid loss values of 10 to 20 mL/30 minutes sufficient in most situations. To determine cake compressibility, fluid loss values should be measured and reported at 100, 200, or 500 psi, and at 7½ and 30 minute intervals. This test will have to be performed in a HTHP fluid loss cell.



Dispersant Additions

Dispersant (e.g. DESCO) may be used in PHPA systems when excess solids cannot be mechanically removed or diluted. Dispersants will deflocculate the reactive clays, resulting in a reduction in funnel viscosity, yield point and gel strengths. Excessive use should be avoided to ensure effective hole cleaning and to prevent mechanical erosion of the wellbore. Small amounts of lignosulfonate can be used in place of DESCO, but care should be taken to not let the pH rise above 10.0. It is best to pre-solubilize the lignosulfonate to protect against increasing the pH above the recommended range.

Mixing Procedures

Fresh Water System

Add the following to the fresh water system:

1. Caustic soda

2. Bentonite (pre-hydrated in fresh water)

3. PHPA

4. Fluid loss additives, deflocculants, and supplemental shale control additives

5. Barite

6. Adjust yield point with xanthan polymer (e.g. XCD POLYMER)

Sea Water, Sodium and Potassium Chloride Brines

Add the following to the sea water/brine:

1. Caustic soda/KOH for pH and hardness control

2. Bentonite (pre-hydrated in fresh water)



3. Lignite

4. PHPA

5. Starch

6. Supplemental shale control additives (e.g. SOLTEX)

7. Adjust yield point with xanthan polymer (e.g. XCD POLYMER)

8. Sodium or potassium chloride to adjust salinity as needed

9. Barite

KCl/Polymer Fluids

The use of potassium (K+) as a base exchange ion to stabilize shales is an accepted practice in many geographic areas worldwide. Its use in the Gulf of Mexico has been greatly restricted due to the toxic effect of potassium on the test species, Mysidopsis bahia shrimp. Potassium is widely used internationally, and comes from many sources, including potassium chloride, potassium carbonate, potassium acetate, and potassium hydroxide.

Major Applications

Drilling soft gumbo (high water content reactive clay structure with elevated cation exchange capacity) formations to prevent bit balling, clay swelling, clay hydration and tight hole problems that are commonly associated with drilling reactive formations.

Drilling hard shale, such as that found in the foothills of Canada and West Texas where



excessive sloughing and borehole enlargement are common problems. This is not to be mistaken for tectonically stressed formations, as the system will not alleviate the problems associated with these types of formations.

Drill-in or workover fluids where the pay zone contains water sensitive clays intermixed with the producing formation.

Functioning as the first line of defense for all swellable formation clays.

Potassium is an effective clay swelling/hydration inhibitor, where the concentration of potassium to achieve the desired result is often a function of the shale being drilled.

To accomplish maximum inhibition with potassium, it must be the intervening ion within the fluid phase of the drilling fluid. As an example, it would require a minimum of 18 lb/bbl of potassium chloride in sea water before the potassium ion became the dominant ion as opposed to magnesium, calcium, sodium and the other cations indigenous to naturally occurring sea water.

Potassium Sources

KCl is most often used to supply the major source of potassium. In most drilling applications, a 3% to 5% concentration (10.7 to 18.1 lb/bbl) is sufficient to provide inhibition of clay swelling and hydration, though there are many areas of the world which require 7% to 10% concentration.

A secondary source of potassium is potassium hydroxide which is sometimes used as an alkalinity agent. Generally, KOH is used in such low concentrations that the K+ ion contribution is insignificant. The primary benefit in using KOH instead of NaOH is that potassium



competes with sodium for ion exchange sites. A general rule of thumb is to target a ratio of 3:1 of K+:Na+. Approximately 1.4 lb of KOH is required to get the same pH effect as one pound of NaOH. KOH provides approximately 2,440 mg/L of K+ ion for each pound per barrel added.

Viscosifiers

Materials used as viscosifiers in potassium-based systems include:

Pre-hydrated bentonite

1. Fill pit with fresh water

2. Add 0.5 to 1.0 lb/bbl soda ash

3. Add 0.25 to 0.5 lb/bbl caustic soda

4. Add 30 to 35 lb/bbl bentonite

5. Add 4 to 6 lb/bbl lignosulfonate

6. Allow to hydrate 4 to 24 hours

7. Agitate if possible with shear pump

Xanthan gum (e.g. XCD POLYMER)

Guar gum (modified)

Hydroxyethylcellulose (HEC)

The combination of 5 to 10 lb/bbl pre-hydrated bentonite plus 0.25 to 1.5 lb/bbl XCD POLYMER has been a commonly used viscosifying treatment. In some cases, because of shortages or economic constraints, guar gum and HEC have been used as viscosifiers. Although these products will increase viscosity, they do not increase carrying capacity. Therefore they are considered unsatisfactory substitutes and will require elevated



bentonite concentrations to provide adequate hole cleaning.

Filtration Control Agents

High filtration is characteristic of these fluids and almost any attempt to establish control will result in some deflocculation.

Materials used to reduce filtration are:

Starch - In concentrations of 2 to 3 lb/bbl, starch produces reduced filtration rates (15 to 20 mL) with no appreciable deflocculation. To lower filtrate to the 5 mL range, 6 to 8 lb/bbl of starch are required. When using starch in muds having a salt concentration below saturation or a pH below 11.5, a high dose of biocide will be required to prevent fermentation.

Polyanionic Cellulose (PAC Regular) (e.g. MIL-PAC™ R) is an effective filtration control agent in KCl systems (0.25 to 2.0 lb/bbl). It may exhibit a deflocculating effect on rheological properties which could drastically reduce yield point to plastic viscosity ratio.

Carboxymethyl Cellulose (CMC) - CMC provides filtration control, although it is not as effective as PAC.

Secondary Shale Stabilizers

Occasionally, the primary method for shale stabilization, namely using the potassium ion, does not provide adequate stability. In this situation, one of the following secondary shale stabilizers should be considered.



Amines

Glycols

Asphalts

Polymers

Table 4-7 indicates a typical KCl/polymer formulation.

Product Concentration, lb/bbl

Pre-hydrated Bentonite 5 - 10

Potassium Chloride (KCl) 10 - 70

Caustic Potash (KOH) 0.25 - 0.75

XCD POLYMER 0.25 – 1.5

PAC 0.25 – 4.0

Starch 2 – 8

Biocide 0.5

Barite As Needed

Table 4-7: KCl/polymer formulations

This base fluid typically exhibits an extremely high yield point and a relatively high filtration rate. For example:

PV = 5 cp

YP = 35 lb/100 ft2

Filtrate (API) = 10 to 25 mL/30 min



Limitations

There are many areas in the world where successful potassium applications have been documented; however, there are other areas, such as in the highly kaolinitic shales of northern South America and West Africa, where failures are also well documented.

The use of potassium for inhibition when drilling kaolinitic shales is strongly discouraged due to the destabilizing effect of the potassium ion on kaolinite.

Salt Water Fluids

Salt water muds are generally used for shale inhibition, drilling salt sections and controlling hydrates in deepwater drilling. As outlined in Table 4-8, these fluids can be categorized based on chloride content as sea water, salt water or saturated salt water muds.

Classification Chloride Concentration

(Cl-), mg/L

Brackish <10,000

Salt Water >10,000

Sea Water ~18,000

Saturated Salt Water >190,000

Table 4-8: Salt water mud classifications



Sea Water Muds

Brackish water and sea water are often used as make-up water for spud fluids on inland barge and offshore drilling operations, primarily because of their availability and shale inhibition characteristics.

Sea Water Composition

The analysis of a typical sea water sample is shown in Table 4-9. A generic sea water mud formulation is depicted in Table 4-10.

Constituent mg/L

Sodium

Potassium

Magnesium

Calcium

Chloride

Sulfate

Carbon dioxide

10,400

375

1,270

410

18,970

2,720

90

Density ~8.5 lb/gal

Table 4-9: Typical sea water analysis


Pre-hydrated Bentonite 30-35

Lignosulfonate 4-6

Caustic Soda 0.2-0.5

Defoamer As needed

Table 4-10: Sea water mud formulation



Pre-hydrated bentonite procedure:








This mixture is generally added to the sea water at an initial concentration of 25% to 30% of circulating volume, then added as required while drilling. A defoamer may be required to control foaming.

Maintenance

As drilling progresses, it is usually necessary to disperse or deflocculate solids and lower fluid loss. The addition of 3 to 6 lb/bbl of lignosulfonate, 1.5 to 3 lb/bbl of lignite, 0.25 to 1.0 lb/bbl of PAC and caustic soda are added as required for a 1.0 to 1.5 Pf (pH 10.0 to 10.5). These concentrations should provide good rheology and a fluid loss value in the 4 to 8 mL range.

To aid filtration control and cake quality, bentonite should be maintained (by methylene blue test) in the 15 to 25 lb/bbl range. Sea water fluids require substantially greater additions of caustic soda for alkalinity control. This is due in part to the loss of hydroxyl ion by reaction with magnesium. PAC Regular, PAC LV, lignosulfonate and lignite are normally used for filtration control.



Saturated Salt Water Fluids

Application

Saturated salt water fluids are generally limited to drilling operations encountering thick salt formations and for hydrate control in deepwater applications. Saturated salt fluids are prepared by adding NaCl to water up to saturation and then adding appropriate viscosifiers and fluid loss control agents.

High density (high salt content) produced brines can be used to prepare these fluids. However, produced heavy brines may contain high concentrations of hardness (calcium and magnesium). As a result, saturated salt fluids are usually run without pH control as the caustic will react with magnesium to form Mg(OH)2, a gelatinous material which will plug shale shakers and detrimentally affect the rheology of the system. In such cases, saturated salt fluids can be run at a neutral pH. Under these circumstances, the addition of lignosulfonate and pre-hydrated lignite should not be made, as they require an alkaline pH to function properly.

Characteristics

A saturated or near-saturated NaCl (or KCl) brine base is normally utilized.

Good mixing conditions (high shear) or circulating times are required to develop good suspension properties.

Exhibits high gel strengths and yield point.

Starch begins to degrade at temperatures above 225°F (107°C). PAC Regular PAC LV may be used as a supplemental filtration control agent in these higher temperature applications.



Starch fermentation is generally not a problem if the system is saturated with salt, or if the pH is 11.5 or above. However, to ensure against starch fermentation, a suitable biocide should be added. Bacteria resistant starches can be substituted for conventional starches as these products do not normally require initial treatment with a biocide.

Higher alkalinities are less corrosive and, where Pf ≥ 1.0, reduce the tendency to foam.

Salt water fluids have a tendency for foaming. Additions of a defoamer will be needed to help reduce foaming problems.

Solids contents (retort analyses) of these fluids should be corrected to compensate for the effect of soluble salts.

Table 4-11 shows a saturated salt fluid formulation.


NaCl

Pre-hydrated bentonite

PAC

PAC LV

Starch

PHPA

Defoamer

Lignosulfonate

Caustic soda

Pre-hydrated lignite

110

10 - 15

0.5 - 2.0

0.5 - 2.0

1.5 - 3.0

0.25 - 4.0

As required for foam

2.0 - 6.0

pH = 7.0-8.0

2.0 - 8.0

Table 4-11: Saturated salt fluid formulation



Maintenance

Add sacked salt to maintain saturation

Utilize pre-hydrated bentonite for viscosity/ filtration control. Pre-hydrated bentonite procedure:








PAC and/or starch for filtration control

Lignite/Lignosulfonate

Freshwater lignite/lignosulfonate fluids are commonly employed for drilling in areas where formations contain high concentrations of bentonite that are easily dispersed, causing elevated viscosities and rheological properties. They provide rheological control and afford a degree of inhibition to drilled solids. These systems are relatively inexpensive and not difficult to maintain. Table 4-12 represents a typical freshwater/sea water lignosulfonate fluid formulation. The typical properties are shown in Table 4-13.

Limitations

Lignite/lignosulfonate fluids do not provide good shale stability and exhibit poor contaminant tolerance. A high



concentration of drill solids or chemical additions could lead to excessive gel structures. Additionally, some of the additives can break down and cause fluid contamination, i.e. carbonate.

Applications

Lignite/lignosulfonate fluids are used to drill a variety of formations. They can be weighted up to 18 to 19 lb/gal, provided low gravity solids are in a minimal range. As mud weight is increased, the bentonite concentration should be decreased.

The pH range for proper control of these systems is 9.5 to 10.5 and the calcium ion (Ca+2) concentration should be maintained below 300 mg/L. Salinity below 10,000 mg/L is tolerated well, but salinity above 25,000 mg/L may require dilution with fresh water for optimal system control.

These systems are stable to temperatures of ~350°F. Generally, chrome lignosulfonates and chrome modified lignites tolerate higher temperatures. A typical lignite/lignosulfonate formulation system and resulting properties are outlined in Table 4-12 and Table 4-13, respectively.

Product Concentration (lb/bbl)

Bentonite

Lignosulfonate

Caustic soda

Lignite

High Temperature Polymer Thinner

High Temperature Fluid Loss

12 - 20

2 - 8

(for pH of 9.5 - 10.5)

As needed

As needed

As needed

Table 4-12: Fresh water/sea water lignite/lignosulfonate fluid formulation



Density,

lb/gal

Plastic Viscosity,

cp

Yield Point,

lb/100 ft2

Gel Strengths, lb/100 ft2

10sec 10 min

API Filtrate,

mL/30 min

9 8-12 6-10 2-4 4-10 8-12

12 15-20 10-14 2-4 4-10 4-8

Table 4-13: Typical properties of lignite/lignosulfonate systems

Maintenance

Add lignosulfonate daily or per tour to control yield point and gel strengths. Treatment ranges between 0.5 and 1.0 lb/bbl will be sufficient for average penetration rates if a good solids removal program is utilized. Discontinue lignosulfonate additions as the temperature approaches 350 F.

Bentonite should be added as necessary to maintain desired filtration rates and give the necessary suspension properties. Bentonite should be pre-hydrated, if possible, prior to adding to the active system. Water additions are required to maintain the plastic viscosity in the desired range. Depending on the fluid density, both lignosulfonate and water are usually required.

Drilled solids may cause excessive problems with fluid rheology and should be kept as low as possible with mechanical control devices and water. Decrease the low gravity solids concentration of the fluid as the density is increased.



When operating in a CO2 environment, use lime additions to neutralize the effects of the acid gas.

Use of polymer-treated lignite fluid loss additives and/or synthetic high temperature polymers is recommended as temperatures approach 350 F.

High Performance Water Base Drilling Fluids

The goal of having a water base drilling fluid that provides the drilling performance approaching that of a NAF has resulted in the development of a class of fluids known as high performance water base muds (HPWBM’s).

HPWBM’s are typically used in place of NAF for the following reasons:

Environmental concerns outweigh the need for drilling performance

The use of NAF is unfeasible due to logistics

High potential for loss circulation

There are a number of these systems available. They are all similar in that they contain additives that provide:

Superior shale stability

Suppressed shale hydration, swelling & dispersion

Minimized bit balling and accretion

Low friction factors for torque and drag reduction

Fairly high rates of penetration

Reduced differential sticking



Reduced losses in depleted sands

Historically, the most common approach to shale inhibition, i.e. increasing shale stability and minimizing shale hydration in water base muds, has been to use a chloride component, such as sodium chloride or potassium chloride. Although many of the HPWBM’s still use this mechanism, they also utilize polymers (both long and short chains) that adsorb on the surface of the clays, limiting dispersion and somewhat slowing water uptake. This approach to shale inhibition includes materials that plug shale pores and physically block water uptake, as well as possibly establishing partial membranes between the mud and shale formation. In addition to using new shale inhibitors, most of these systems will have an additive to enhance rates of penetration. As might be expected, the cost associated with these systems is significantly higher than the cost of conventional water base systems.

Chapter 5: Non-Aqueous Fluids


CHAPTER 5: NON-AQUEOUS FLUIDS

Non-aqueous fluids (NAF’s) are defined as drilling fluids which have oil as the continuous external phase. Each system is typically composed of base fluid, brine, emulsifier, lime, organophilic clay (viscosifier), fluid loss additive and weighting material. NAF’s are invert emulsions. The external phase is oil and the internal emulsified phase is water. Typically, oil:water ratios for inverts range from 95:5 to 50:50. The emulsified phase is almost always a brine; calcium chloride (CaCl2) being the usually preferred salt.

Because the advantages frequently outweigh the disadvantages, as shown in Table 5-1, NAF’s continue to be used in difficult drilling environments and in special applications.

Advantages Disadvantages

Shale stability and inhibition

High penetration rate

Temperature stability

Lubricity

Resistance to chemical contamination

Gauge hole in evaporative formations (salt)

Solids tolerance

Reduced tendency for stuck pipe

Reduced fluid density drilling

Reduced cement cost

Flexibility

Reduced stress fatigue

Corrosion control

Reuse

Hydrate prevention

High initial cost per barrel

Reduced kick detection/gas solubility issues

Fluid compressibility

Pollution control/environmental issues/disposal problems

Rig cleanliness

Hazardous vapors/special skin care for personnel required

Effect on rubber parts

Fire hazard

Special logging tools required

Table 5-1: Advantages and disadvantages of NAF



Conventional invert emulsion fluids are formulated with the same basic products. Each system is typically comprised of:

External phase base fluid - diesel, mineral or synthetic oil

Internal phase brine - water containing CaCl2, NaCl, glycerin, glycol, acetates

Viscosifiers - organophilic clay or polymer

Wetting agents

Lime

Emulsifiers

Fluid loss additives - asphalt, gilsonite, polymer

Weight material - barite, hematite, calcium carbonate

The quantities and concentrations of each will be dependent upon the application and desired properties. For example, when formulating a low density invert, the internal phase water fraction will be much higher than that for a high density formulation.

Base Fluids

Base fluids (the continuous phase) are hydrocarbon oils and are typically the largest component by volume of an invert emulsion system. The continuous oil phase is the phase into which everything else is mixed. Base fluids are nonpolar, low-surface-energy/tension liquids that interact with mineral solids. This characteristic is the basis for the use of NAF’s as non-reactive, inert drilling fluids. Hydrocarbon base fluids will not solvate or swell clays, which makes them ideal for drilling hydratable shale.



The most widely used base fluids have been diesel, mineral oil, and synthetic oils. The choice of base fluids is driven by performance, environmental regulations, availability, and price. The two environmental considerations that are usually addressed are the acute toxicity to aquatic organisms as the cuttings coated with NAF fall though the water column and the long term impact on the seabed as the NAF biodegrades.

Properties that affect performance and should be considered when selecting base fluids are:

Kinematic viscosity - Viscosity describes a fluid's internal resistance to flow and may be thought of as a measure of fluid friction. Kinematic viscosity is usually recorded at 40o C (104o F) and as a general rule, base fluids with lower kinematic viscosities are more desirable and provide superior performance.

Flash point - Defined as the temperature at which oil vapor ignites upon passing a flame over the hot base fluid. The base fluid selected should have a flash point that is higher than the maximum expected flowline temperature.

Pour point - Defined as the temperature at which the base fluid ceases to flow. The base fluid should have as low a pour point as possible, especially for deepwater drilling and storage in cold climates.

Diesel Oil

Historically, the most widely used and least expensive base fluid has been diesel, but due to environmental concerns its use has diminished in recent years. Diesel contains aromatics, sulfur and nitrogen compounds which have enough toxicity to adversely affect many



aquatic organisms. The aromatics, branched paraffins and cycloparaffins in diesel biodegrade very slowly. Offshore discharge of cuttings covered with diesel is banned nearly everywhere and onshore disposal creates HES concerns and liability.

Mineral Oil

Mineral oils are petroleum-derived hydrotreated refinery streams that contain lower concentrations of aromatics, sulfur and nitrogen compounds than diesel. The most highly treated mineral oils are called enhanced mineral oils (EMO’s) and they are very low in troublesome compounds. Mineral oils are composed primarily of a complex mixture of straight-chain paraffins, branched paraffins and cycloparaffins. Good mineral oils have low toxicity and good drilling performance, but they all tend to be fairly slow to biodegrade due to the branched and cyclic materials.

Synthetics

Synthetics are produced by the reaction of specific purified chemicals, as opposed to mineral oils and diesel, which are produced by purification of petroleum through distillation. Drilling fluids made with synthetic oils perform comparably to, and in some cases may exceed the performance of mineral oil and diesel oil systems.

Although the purchase costs of synthetic base fluids (SBF) exceed those for diesel and mineral oils, the cost disadvantage is overcome if drill cuttings from wells drilled with SBF can be discharged onsite, thus saving transportation and disposal costs.

Due to their purified molecular structure, synthetic fluids can resolve many environmental problems associated with diesel and mineral oils. Trends show that synthetic



base drilling fluids are usually much less toxic and more biodegradable under aerobic (with air) and anaerobic (without air) conditions, and produce fewer hazards in handling than diesel and mineral oil base fluids. However, how less toxic and biodegradable depends on the structure and composition of the SBF.

The various synthetic base drilling fluids currently used in the field are classified according to the chemical composition of their base fluids and routinely identified by the generic chemical name. These various types of synthetic base fluids have a wide range of chemical properties and drilling performance. Examples of commercial synthetic base fluids and their key properties are shown in Table 5-2. The four types of synthetic base fluids most widely used today are esters, linear alpha olefins, internal olefins, and linear paraffins.

Table 5-2: Commercial names and properties of synthetic base fluids

Commercial Name

SBF Type Manufacturer Density, g/mL

Pour Point, oC

Flash Point, oF

Viscosity @ 40 oC, cSt

PETROFREETM Ester Cognis 0.86 -30 354 6

PETROFREE LVTM Ester Cognis 0.86

297 3.2

FINAGREENTM Ester Fina 0.85 -30 300 5

AMODRILL 1200TM Linear Alpha

Olefin Ineos

Oligomers 0.78 -9 255 2.25

ALPHATEQ (SN 1890)TM

Linear Alpha Olefin

Ineos Oligomers

0.78 -18 241 1.87

ISOTEQTM Internal Olefin CP Chem 0.79 -10 245 3.6

AMODRILL 1000TM Internal Olefin Ineos

Oligomers 0.79 -24 279 3.09

BIOBASE 130TM Internal Olefin Shrieve 0.79 -15 250 2.9

SARALINE 185VTM Linear Paraffin Shell MDS 0.78 -27 192 2.6

ESTEGREEN Linear Paraffin Sasol 0.76 -6 194 2

MOSSPAR HTM Linear Paraffin PetroSA 0.79

205 2.8



Commercial Name

SBF Type Manufacturer Density, g/mL

Pour Point, oC

Flash Point, oF

Viscosity @ 40 oC, cSt

BAROID ALKANETM

Linear Paraffin Sasol 0.77 -8 176 2.05

SARAPAR 147TM Linear Paraffin Shell MDS 0.77 12 248 2.5

SARAPAR 103TM Linear Paraffin Shell MDS 0.73 -18 167 1.6

Table 5-2: Commercial names and properties of synthetic base fluids (continued from page 69)

Esters

Fatty acid esters used in drilling muds are derived from fatty acids and alcohols and are commonly known as esters. In one manufacturer’s product, the fatty acid component of the ester-based material used for NAF’s is derived from vegetable oils. The key to the performance characteristics is the proper selection of the hydrocarbon chain length on either side of the ester functional group. These side groups are selected to minimize fluid viscosity, maximize hydrolytic stability, and minimize toxicity.

Esters contain oxygen in the structure. The two oxygens create an active carbon site in the ester molecule which is susceptible to attack of either acid or basic-type reactants. The result is a fragmentation of the ester to give the corresponding alcohol and carboxylic acid. It is the breakdown process which affords the ester type SBM such a rapid biodegradation rate in both laboratory tests and seabed conditions. In a drilling situation, concerns regarding the use of esters focus around high



temperature applications, cement contaminations, and acid gas influx. Some new esters have been chemically designed to have greater thermal stability and to be more resistant to acid or base hydrolysis.

Linear Alpha Olefins

IO’s (internal olefins) and LAO’s (linear alpha olefins) essentially are from similar chemistry. These synthetics are derived from alpha olefins via catalytic polymerization of ethylene molecules. The alpha olefins are further modified to give IO’s. The structural difference between IO and LAO products is that the double bond is in the terminal position in the LAO, while the double bond is between two internal carbon atoms in the IO structure.

LAO’s tend to stack more closely together because of their uniform linear structure. This phenomenon results in higher pour points for LAO’s as compared to IO’s with the same molecular weight. Because of the intrinsically higher pour points, LAO’s having viscosities useful in drilling fluids are necessarily of lower molecular weight. These lower molecular weights result in lower flash points and greater acute toxicity than with IO’s.

LAO’s range in molecular weight from approximately 112 (C8H16 ) to 280 (C20H40). This mixture of LAO’s is distilled to give distinct cuts of individual LAO’s or blends of LAO’s. Therefore, the term LAO C14C16 is a blend of C14H28



and C16H32 LAO’s; likewise, the C16C18 LAO is a blend of C16H32 and C18H36.

Internal Olefins

IO’s are synthesized by isomerizing LAO’s (isomerization changes a molecule’s structure but not its atomic composition). IO molecular structures are less uniform than those of LAO’s. This lack of uniformity results in lower pour points than LAO’s having the same number of carbon atoms. The inherently lower pour points of the IO molecular structure allows for the use of higher molecular weight molecules, which results in lower acute toxicities, lower bioaccumulation potential and lower volatility than LAO’s. The internal double bond of the IO gives rise to additional structural isomers (cis and trans), which do not allow the molecules of the IO to pack together as uniformly on cooling; therefore, the pour point of the IO is lower than that of the LAO.

Linear Paraffins

Linear paraffins are similar in structure to olefins with two exceptions; they lack the double bond that is characteristic of the olefin, and their carbon chain length distribution is broader than the distribution of olefins. Linear paraffins can be manufactured by either a purely synthetic route or by a multi-step refinery process that includes hydrocracking and the use of a molecular sieve. The latter linear paraffins are classified as mineral oils according to the generally-accepted EPA definition. Synthetic linear paraffins are made from methane gas in



the Fischer-Tropsch GTL (gas-to-liquids) synthesis process. This process results in a mixture of linear paraffin molecules including n-paraffins and slightly branched (methyl and dimethyl) paraffins.

Linear paraffins have several distinct advantages over other synthetic base oils. They are much less expensive than esters and olefins, at about 1/3 the cost. This lower cost is a result of the relatively low operating cost of the GTL process and the low cost of natural gas compared to ethylene, fatty acids and alcohols. Chevron has an IP position with worldwide patent coverage on linear paraffins. They have been used extensively in Chevron drilling operations since 1996, including drilling in Thailand, Indonesia, Vietnam, Brazil, U.S. GOM, Australia, Angola, Nigeria, Azerbaijan, and Bangladesh. Linear paraffins are recommended as the base fluid when considering biodegradation, in particular, bioremediation projects involving composting or landfarming. Linear paraffins have been shown in comparative tests to aerobically biodegrade faster than mineral oils, olefins and esters.

Internal Phase

The most commonly used internal phase in NAF drilling muds is brine water. Calcium chloride is the most predominantly used salt although sodium chloride, sea water and other brines are occasionally used. The concentration of salt is selected to minimize reactivity with drilled formations. Recently, other components such



as acetates have been used as the internal phase due to environmental considerations. The choice is dictated by the formation, economics and disposal method to be employed.

Viscosifiers

Organophilic Clays

Organophilic clays are excellent gelling agents in oil and excellent at suspending weighting materials. They are relatively inexpensive but have only moderately good thermal stability. While organophilic bentonite is the most common, hectorite, attapulgite and sepiolite are also used. Bentonite and hectorite are platelet clays that will increase viscosity, yield point and build a thin filter cake to aid in reducing the fluid loss. In contrast, sepiolite and attapulgite are rod-like clays that increase the gel structure of the fluid but will have very little effect on the viscosity or fluid loss characteristics of the fluid.

When choosing the appropriate organophilic clay, a decision must be made as to whether temperature stability or clay efficiency (maximum viscosity under low shear mixing conditions) is the most important criteria. When drilling in a high temperature environment, clay that exhibits a high tolerance to thermal degradation is required. When mixing a new fluid at a liquid mud plant, a more efficient clay may be desirable. As clay efficiency increases, the concentration required to achieve the desired properties is reduced.

Polymers

A number of polymers are available for use in NAF’s. These polymers increase fluid carrying capacity and



extend the viscosity temperature stability to 500 oF (260 oC). These types of polymers viscosify the external phase (base oil) of the drilling fluid. They include: elastomeric viscosifiers, sulfonated polystyrene polymers, styrene acrylate, fatty acids and dimer-trimer acid combinations. Some of these polymers serve a dual purpose as both viscosifiers and fluid loss control additives. The effectiveness of any particular polymer will change with the type of base fluid in which it is used.

Emulsifiers

To formulate stable water in oil mixtures, the use of surfactants is required. Surfactants lower surface tension and emulsify the internal water phase and “oil wet” solids. The most common example of a surfactant is soap. Surfactants orient at the oil/water interfaces, lowering surface tension. Surfactants also form a barrier around the emulsified dispersed droplet (Figure 5-1) and in essence, mechanically stabilize the interface, preventing droplets from coalescing or breaking.

Figure 5-1: Emulsion

EMULSIFIED WATER DROPLET IN OIL

HYDROPHILIC HEAD

SURFACTANT

ORGANOPHILIC TAIL

SURFACTANT

ORGANOPHILIC TAIL



There are numerous manufacturers of emulsifiers worldwide. Emulsifier chemistries for the different manufacturers will vary, as some have proprietary formulations. Minor changes to formulations and different sources of raw materials can greatly affect product performance.

In practice, emulsifiers are classified as either “primary” or “secondary”, depending on the desired application.

Primary Emulsifiers

Primary emulsifiers are identified by the following characteristics:

Generally very powerful, fatty acid based

Requires lime to activate and build a stable emulsion

Builds tight emulsion

Very tolerant to high temperature and contaminants

Emulsified water is colloidal in size

Overtreatment may increase kinematic viscosity of base fluid

Relatively inexpensive compared to other emulsifiers

When using primary emulsifiers, there are several considerations that must be taken into account. It is important to know the activity of the product and the carrier fluid/solvent should be environmentally acceptable for the area in which it is being used. The product activity is the amount on a percentage basis of active available product or it can also be viewed as the amount the product has been “watered down”. Typically,



most premium emulsifiers, whether primary or secondary, will have an activity of 65 to 70%.

Secondary Emulsifiers

Secondary emulsifiers are identified by the following characteristics:

Typically not fatty acid based, e.g. imidazoline, amides

Does not require lime to activate

Provides a “relaxed” filtrate, e.g. HTHP filtrate values of 12-15 mL/30 minutes

Overtreatment usually does not increase kinematic viscosity of base fluid

Relatively expensive compared to primary emulsifiers

Caution should be exercised when selecting an emulsifier for a particular application. In general the following guidelines should be used:

When possible, use only a “classic” secondary emulsifier. These emulsifiers contain very little or no fatty acid that require lime for activation. Primary emulsifiers that require lime build very tight emulsions (i.e. high ES readings), reduce the HTHP fluid loss, and increase the kinematic viscosity of the base fluid. Any one of these effects or a combination of them could be detrimental to penetration rates.

Use the secondary emulsifier until bottom-hole temperatures dictate the addition of a primary emulsifier. When this occurs, use the primary emulsifier as a supplement to the secondary.

Do not over treat with the secondary emulsifier.



All the major drilling fluid vendors will provide primary emulsifiers. Many will provide secondary emulsifiers that will require lime to activate, but not all will have a “classic” secondary emulsifier offering that does not require lime. Additives such as EZ MUL NT™ (Halliburton Fluid Services) and CARBO-MUL HT™ (Baker Hughes Drilling Fluids) are examples of classic secondary emulsifiers that do not require lime.

Fluid Loss Additives

A freshly built NAF will inherently have a certain amount of built in fluid loss control at lower temperatures, depending on the type and concentration of emulsifier used. Generally speaking, lower HTHP fluid loss values will be achieved as the percent water in the fluid increases. However, these mechanisms for reducing or controlling HTHP fluid loss should not be relied upon at elevated temperatures. As temperatures increase, fluid loss control is achieved through the use of asphalts, gilsonites, amine treated lignites or polymer type materials.

Asphalt

Powdered, air-blown asphalt is used as a primary fluid loss additive for drilling at elevated temperatures. The asphalt particles swell and deform, effectively plugging pores in the filter cake. Caution should be exercised when using asphalt, as excessive solubility of the material will lead to extremely viscous fluids at low temperatures. Treatments can range up to 15 lb/bbl (42.8 kg/m3).



Gilsonite

Gilsonite is a naturally occurring hydrocarbon solid. Being naturally oil-wet, it easily disperses into NAF’s. Gilsonite exhibits different softening points when heated. When heated, the particles soften and deform, plugging pores in the filter cake. High softening point gilsonite provides HTHP filtrate control up to the 400 oF (204 oC) range. Caution should be exercised when using gilsonite, as it behaves like a fine solid in the fluid and can lead to extremely viscous fluids at low temperatures. Treatments will range up to 15 lb/bbl (43.1 kg/m3).

Amine Treated Lignite (ATL)

Superior quality amine treated lignite provides good high pressure, high temperature filtration properties to about 450 oF (232 oC). Variations in base materials and reaction conditions result in a wide quality range for these materials.

Polymers

Oil insoluble polymers are used for extreme high temperature filtration control. The most common is a methylstyrene/acrylate copolymer, commonly referred to as PLIOLITE™. Other products will use maleic anhydride and rosin blends and others will use blends of styrene butadiene.

Weighting Agents

There are several methods of increasing the density of NAF’s. Usually, barite (barium sulfate) is used to increase the density of drilling fluids. Other weighting agents are hematite (iron oxide), manganese tetraoxide (e.g.



MICROMAX™) and calcium carbonate. These weighting materials increase the density of the external phase of the fluid. An alternative method of controlling fluid density is achieved by altering the composition and activity of the internal phase, but the effect is very minimal.

Gas Solubility

Detection of gas kicks while drilling with a NAF is more difficult because of the solubility of gas in the base fluid. The degree of solubility is dependent on:

Composition of the formation gas Composition of the base fluid used Pressure Temperature

Even a low volume influx that goes undetected will rapidly expand when it reaches the surface and cause unloading of fluid from the hole. This reduces bottom-hole pressure, allowing additional gas to enter the wellbore, and potentially resulting in an uncontrollable situation (blowout). The key to well control in NAF is quick detection and handling of the influx. The problem lies in that the normal surface responses to gas kicks are dampened because of the solubility of the gas in the base fluid. The rig crews must be aware of the differences in responses to gas kicks in NAF’s and be prepared to detect small changes in pit levels, flow rates, and flow checks.

Flat/Constant Rheology NAF

Planning and operations with NAF’s are complicated by the inherent variation with temperature and pressure of the kinematic viscosity of the base fluids used in the



external phase. This is usually observed as a thinning or thickening of the mud at downhole temperatures and pressures. Unfortunately, this also results in deviation from the planned equivalent circulating densities (ECD's) as operations vary, particularly when resuming circulation with cold mud from the surface following a period without pumping. The effect is especially pronounced in deepwater operations where there is a large temperature variation between the cool fluid in the riser and the hot fluid at the bit. This not only results in different circulation pressures, but the change in gel strength can be problematic. These changes in fluid properties can cause wellbore instability and/or fracturing of the formation.

To mitigate this drilling hazard, a number of companies have developed additive packages that try to counteract the change in rheological properties as the temperature and pressure change downhole. Typically, one set of additives help keep the fluid from thickening at cooler temperatures, while another will mitigate the thinning effect at higher temperatures. These mud systems are termed "flat" or "constant" rheology fluids.

The creation of a truly constant rheology is complicated by the fact that temperature and pressure tend to have the opposite effect on the viscosity of drilling fluids. Furthermore, a vertical well and a horizontal well, drilled to the same measured depth, will have a different temperature-pressure relationship. When constant rheology systems are measured at different temperatures and pressure, more steady properties are seen as compared to a conventional system.

Design of constant rheology systems is somewhat different than conventional systems, as the surface properties more closely resemble the downhole properties. As a result, these fluids appear thin and there have been concerns about the hole cleaning ability of these systems. To address these concerns, constant



rheology systems typically boast enhanced low shear rate viscosities, which allow for good hole cleaning properties while still exhibiting the flow properties of a thin fluid.

Constant rheology systems offer the promise of lower ECD's and more dependable fluid properties regardless of the stage of the operation or shut down time, which would reduce the chance of fluid related non-productive time (NPT). The difference in design and difficulty in properly capturing their performance in traditional fluid modeling has made their justification difficult in some cases, but as these systems become more common, wider adoption may be expected.

Product Safety and Handling

Use proper precautions for employee protection when handling all chemical products used in NAF’s. The use of an appropriate respirator, gloves, goggles, and apron is recommended. Obtain and refer to material safety data sheets (MSDS) before product use. The liquid NAF products usually contain flammable or combustible liquids and must not be stored around heat, sparks, or open flames. Do not reuse empty containers.

Special Rig Equipment and Precautions

Observe the usual precautions for handling NAF’s including:

Prepare rig to contain spills from shakers, drips from flow lines, etc

Use pipe wipers during trips



Use high-speed, linear motion shakers capable of processing 110% of the fluid volume at the smallest screen size anticipated

Pits should be covered to prevent rain water contamination

Disconnect all water valves around the pits to prevent accidental water contamination

Clean shaker screens and fluid cleaner screens with a bucket of base fluid and an air gun

Do not use plastic or phenolic resin materials for lost circulation as these materials are detrimental to the stability of the system

Use steam cleaners to assist with clean up or heated high pressure washers

Use absorbent materials (e.g. OIL DRY™) to assist the containment and dry up spills

Recover spilled fluid with fluid vacuum systems

Displacement Procedures

Displacement can occur either in cased or open hole, but cased hole displacements are preferred. Before displacement, all pits and lines should be as clean as possible. The trap doors on the pits can be packed with barite to help prevent leaking.

The water base fluid to be displaced must be thinned to reduce yield point and gel strengths. This reduction helps achieve a good displacement and prevent contamination of the NAF.

A water spacer of sufficient volume to occupy 500 to 1000 feet of annular space should be used to chase the water base fluid up the hole.



A base oil spacer of the same size is used when displacing a NAF fluid with a water base fluid.

During displacement, the drillpipe should be rotated and reciprocated, if possible. Use a high pump rate to help prevent channeling. After displacement begins, the pumps must not be shut down.

The total pump strokes must be calculated for the spacer to come around to the shaker. This calculation helps locate the interface. Bypass the shakers and remove the water base fluid to a reserve or waste pit when on land or discharge overboard when offshore if environmental regulations permit. Any contaminated NAF should be isolated and treated. If contamination is severe, it may be more cost effective to dispose of the fluid.

Logging

The use of a NAF drilling fluid can impact and complicate logging operations. The first impact is that invasion of NAF into the formation will distort resistivity log interpretation, especially in oil reservoir zones. This makes good quality filter cake even more important and efforts should be made to minimize the amount of time that the formation is exposed to the NAF fluid. The continuous NAF phase also affects logging as the fluid has different fundamental properties than water; the biggest differences being an extremely high resistivity and different sonic impedance.

NAF’s do not conduct electricity like water base muds, and as a result, spontaneous potential (SP) logs do not work. Laterolog logs (such as FMI) will only work where tools have direct contact with the formation, which in practice means where the pads touch the wellbore, leading to less borehole coverage. Typically, induction logs are used in a NAF, and care must be taken when comparing these measurements to those from other



resistivity tools as they will have different depths and volumes of investigation.

The difference in fluid density and bulk modulus between water base mud and NAF will lead to a different speed of sound in the fluids. As a result, in processing, proper environmental inputs are required to give correct results on sonic logs. It is important to note that some density logging while drilling (LWD) tools use ultrasonic measurements to correct for standoff, and unless the correct fluid type is entered, an incorrect standoff will be calculated, leading to an error in measurements.

Finally, water salinity is often an environmental correction for nuclear measurements. Loggers need to be aware that salinity can be reported. Remember that many processing programs require the salinity to be reported as a fraction of the entire fluid, while the mud report will show the salinity of a NAF fluid for only the water phase. This needs to be correct to account for the entire fluid volume or the processing will include a much higher salt concentration than really exists.

Troubleshooting

Table 5-3 contains a guide for troubleshooting NAF’s, including typical indicators of problems encountered and suggested treatments.



Problem Indications Causes Treatment

Mixing fluid at the mixing plant

Poor emulsion (low ES) stability.

Barite settling.

Dull grainy appearance of fluid.

Fluid very thin with inadequate yield or gel strength.

1. Inadequate shear

2. Cold temperatures 3. Poor wetting of barite 4. Too high electrolyte

content. Usually greater than 350,000 ppm

5. Surfactant contamination possible if CaCl2 brine has been previously used as a completion or workover fluid

1. Maximize shear. 2. Lengthen mixing time. 3. Add barite. Add

emulsifier. If severe, add small amounts of wetting agent.

4. Dilute back with fresh water. After emulsion is formed, can add more CaCl2 to obtain desired activity.

5. Pilot test with known CaCl2 brine to determine if problem does exist.

Lost circulation

Decrease in visible surface (pit) volume. Reduced flow line volume.

Hydrostatic pressure is greater than formation pressure.

Add bridging agents (e.g. calcium carbonate, fiber, nut plug). Never add phenolic resin materials. Reduce mud weight if possible.

High viscosity

High PV and YP.

1. High solids content. 2. Water contamination.

3. Improper OWR/SWR.

4. Excessive clay.

1. Dilute with new base fluid. Maximize solids control efficiency. Add emulsifiers.

2. Add emulsifiers. If severe, add wetting agent.

3. Dilute with new volume of base fluid.

4. Dilute with new volume of base fluid/add wetting agent.

Sloughing shale

Fill on connections and trips.

Torque and drag.

Increase in volume of cuttings across shale shakers.

1. Drilling under- balanced.

2. Excessive fluid loss. 3. Aw too low.

1. Increase mud weight. 2. Add emulsifiers. Add

fluid loss control agents.

3. Adjust salt content of internal phase to match formation activity.

High fluid loss

High HTHP fluid loss with water in filtrate.

Low electrical stability (ES).

Fill on connections and trips.

1. Low emulsifier concentration.

2. Low concentration of fluid loss control additives.

3. High bottom hole temperature.

1. Add emulsifier and lime if needed.

2. Add fluid loss agents.

3. Add more emulsifier and lime, if needed to increase electrical stability.

Table 5-3: Troubleshooting NAF systems guide for pilot testing



Problem Indications Causes Treatment

Low emulsion stability (ES)

Dull, grainy appearance to fluid.

High HTHP fluid loss.

Water in filtrate.

Barite settling.

Blinding of shaker screens.

Extreme cases can result in water wetting of solids.

1. Inadequate emulsifier concentration.

2. Super-saturated with CaCl2.

3. Water influx from formation or leakage from surface equipment.

4. Addition of fresh fluid from mixing plant.

5. Insoluble sodium chloride (NaCl)

1. Add emulsifier and lime, if needed.

2. Dilute back with fresh H2O and add emulsifier.

3. Add emulsifier and lime , if needed.

4. Maximize shear. Check electrolyte content (the higher the content, the difficult it is to form the emulsion)

5. Dilute back with fresh H2O and add emulsifier.

Water wetting of solids

Agglomeration of barite on sand-content test.

Sticky cuttings.

Blinding of shaker screens.

Barite settling.

Dull, grainy appearance of fluid.

Low elec. stab. (ES).

Free H2O in filtrate.

1. Inadequate emulsification.

2. Water or water base fluid contamination.

3. Supersaturated CaCl2

as evidenced by free salt crystals in the mud.

1. Add emulsifier.

2. Add emulsifier and lime, if needed. If severe, add wetting agent.

3. Dilute with fresh H2O and add emulsifier.

Table 5-3: Troubleshooting NAF systems guide for pilot testing (continued)

Chapter 6: Chemistry Concepts


CHAPTER 6: CHEMISTRY CONCEPTS

Drilling fluids are complex mixtures of chemicals such as water, clays, salts, polymers, surfactants, organic liquids and solids. When drilling fluids are circulated downhole, they enter an area of high pressure and temperature. This environment is much like a reaction vessel in a chemical plant, and chemical changes to the drilling fluid invariably take place. Therefore, formulating and maintaining drilling fluids requires some chemistry knowledge in order to move drilling fluids engineering from an “art” towards a science. This chapter contains only basic explanations and examples of the central chemistry concepts encountered in drilling fluids.

Solubility

It is well known that things like sugar and salt dissolve in water, but what exactly happens as the material disappears? Salt is made up of sodium (Na+) and chloride (Cl-) ions held together by ionic bonds. When sodium chloride dissolves, these ionic bonds are broken. As the sodium and chloride ions move between the water molecules, the hydrogen bonds holding the water molecules together are also broken. Because water molecules are polar, by definition they have a positive end and a negative end. In this example (depicted in Figure 6-1), the negatively charged ends of water molecules are strongly attracted to the positively charged Na+ atoms and they cluster on all sides until the Na+ is solvated and floating free in solution. Likewise, the same reaction occurs as the partially positively charged hydrogen ends of the water molecules associate with the negatively charged chloride ions.



Figure 6-1: Solid sodium chloride dissolving in water

Dissolving polymers, glycols, amine-based shale inhibitors, surfactants, etc. into water follows a similar path. Water molecules cluster around the polar parts of the molecule until its soft “shell” of water floats it free into solution. Materials like high molecular weight polymers might not go into true solution, but become hydrated enough to disperse evenly in water and perform their intended functions in a drilling fluid.

Saturation/Free Water

Materials such as methanol are miscible with water in all proportions, but most drilling fluid related chemicals reach a saturation point, or maximum solubility limit. When a chemical reaches its saturation point, the soluble solid stops dissolving in the solution and remains as a precipitate. For example, at room temperature sodium chloride (NaCl) will dissolve in water up to a little over 26 wt%, whereas potassium chloride (KCl) will only reach a little over 24 wt%. Solutions of calcium chloride (CaCl2) become saturated at just over 40 wt%. The most soluble of the salts are the formates, with potassium formate



saturating at 76 wt%, and cesium formate reaching 83 wt%. On the other end of the scale, gypsum/anhydrite only dissolves enough to release about 800 ppm of calcium ions into solution. Calcium carbonate (CaCO3), a common pore bridging solid added to drilling fluids, will only release about 3 ppm of soluble calcium into solution at normal water base mud pH. CaCO3 readily dissolves in acid, which makes it ideal for drill-in fluids for open-hole completions where the filter cake must be removed.

The term free water describes the amount of water in a solution (or drilling fluid) that is not already being used to keep other things dissolved. Everything that dissolves in water has a “water-demand”, which is an amount of water that must loosely attach to the material to carry it into solution. Free water becomes critical in drilling fluids that carry a great deal of dissolved solids. For example, a saturated salt mud used to drill through a salt/halite interval has almost all of its water tied up; keeping the salt and polymers in solution and keeping the barite and drill solids water wet. When all the free water is tied up, any further chemical additions (even thinners) will cause the viscosity of the drilling fluid to go up very quickly because the chemical cannot dissolve and remains a solid.

Water Phase Activity

Water phase activity is a concept that frequently comes up in conjunction with shale stability (see “Osmosis” below). The activity of an aqueous solution is a relative measure of how easily water evaporates from the solution. Activity is measured by determining the relative humidity (water vapor) in the air space of a closed container of a solution. Evaporation is fairly quick from a container of pure water, but the more salt, etc.



dissolved in a solution, the slower the evaporation rate because the water molecules are bound to the solutes and less “free” to evaporate. Pure water is assigned an activity of 1.0. A saturated sodium chloride solution has an activity of about 0.76, and saturated calcium chloride has an activity of about 0.38. Shales average approximately 10 to 20% water content and usually have activities in the 0.60 to 0.98 range.

Effect of Temperature

Normally, as the temperature of water increases, additional amounts of a given material can be dissolved. For example, a saturated salt drilling fluid can dissolve additional formation salt at elevated downhole temperatures, which then comes back out of solution on shaker screens or in the pits when the mud cools down. There is one exception to this trend. Some non-ionic surfactants exhibit a “cloud point” or upper temperature solubility limit. An example of this would be glycol, which is sometimes used as a shale inhibitor.

Effect of Salt

Everything hydrates more poorly in solutions containing salt. This is favorable when the goal is to limit cuttings dispersion and hole washout when drilling clay-rich shales. The downside is the difficulty in getting full yield out of mud chemicals when they are added to a salty water base fluid. When building new mud, it is preferable to hydrate all of the clays and polymers in fresh water, prior to adding any salts.



Like Dissolves Like

“Like dissolves like” is an old chemistry rule-of-thumb that points out that polar solvents like water and methanol dissolve polar and ionic materials like sugars, salts, small alcohols and amines. Conversely, non-polar solvents like gasoline, xylene and diesel will only dissolve non-polar materials like wax and asphalt. Of course, as with any rule-of-thumb, there are exceptions. Materials like butyl alcohol will somewhat dissolve in both polar and non-polar solvents. These materials are referred to as “mutual solvents” and can help with certain problems, such as removing trapped water from a clay-rich reservoir sandstone.

Common Drilling Fluid Chemicals

Detailed knowledge of chemicals is usually unnecessary for successful drilling fluids engineering, but a few rules-of-thumb can be useful. Some of these include:

Anything water soluble enough to dissolve in a water base mud has enough polar or charged sites to be attracted to clay surfaces. This means that the material will adsorb on cuttings and be steadily depleted from the mud. The tendency to adsorb also means the material is likely to adsorb onto reservoir rock and may change its wettability (see “Surfactants” section) or cause other formation damage. Chemicals with multiple charges or polar sites may sometimes bridge clay platelets and cause a significant mud viscosity increase or gellation.

Chemicals that have a weak spot like an oxygen or nitrogen atom in the middle are usually not suitable for high temperature (300 oF) drilling



fluids. These sites are vulnerable to oxidation and hydrolysis.

Soluble calcium (Ca+2) and carbonate (CO3-2) ions

will precipitate to form calcium carbonate (limestone), such as when lime is used to treat carbonates out of a drilling fluid. Conversely, if calcium chloride completion brine is used in a carbonate rich reservoir containing carbon dioxide (CO2) gas, extensive formation damage is likely. Carbonate ions in a drilling fluid or formation brine usually come from dissolved CO2. The CO2 can be from the formation or can be generated by mud chemical degradation or bacterial action.

Soluble calcium ions are usually detrimental to water base drilling fluids. Clays are readily flocculated by soluble calcium since each ion’s two positive charges can attract and bridge two clay particles. When this bridging is extended throughout a fluid it can cause huge viscosity increases, and the flocculated clays tend to make poor quality filter cakes. Also, polymers, surfactants, etc. which have negatively charged carboxylate groups (e.g. CMC’s, PAC’s, acrylates) can be precipitated by a similar association with calcium’s two positive charges. Of course, some drilling fluids are based on calcium (gypsum, lime, calcium chloride), but they require special deflocculants and low cation exchange capacities (CEC’s). Magnesium (Mg+2) and other divalent ions (two positive charges) associate less strongly with clays and carboxylate chemicals and usually present less of a problem. The maximum preferred calcium level for many mud chemicals is 300-400 ppm. The most common treatment is to precipitate the calcium with a carbonate ion source like soda ash. Note: Trying



to treat calcium below 100 ppm can sometimes lead to detrimental side effects.

Common Chemical Types

Polyglycols - Polyglycols are a large family of compounds used for shale inhibition, lubricity and ROP enhancement. At molecular weights of a few hundred to a couple of thousand they are either water soluble or water dispersible.

Amines - Amines are nitrogen bearing compounds of the general formula N-R3, where R is an organic group. Amines tend to be surface active and some of their uses are reducing corrosion by coating steel, adsorbing on clays to make them oil-wet for use in non-aqueous fluids (NAF’s), and shale inhibition.

Amides - Amides are also surface active nitrogen-based compounds and have a general structure of R-CO-N-R2. Common usages include acrylamide-based polymers or copolymers for cuttings encapsulation/preservation, and polyamide emulsifiers in NAF’s.

Phosphates - Soluble phosphates such as sodium acid pyrophosphate (SAPP) and tetrasodium pyrophosphate (TSPP) are used as low temperature (<150 oF) water base mud thinners and calcium removers.

Alcohols - The term alcohol refers to any molecule with a (-OH) group. Many mud products contain -OH groups (CMC, PAC, xanthan gum, lignosulfonate) as part of complex structures, but one simple alcohol used in mud as a defoamer is octanol.

Silicone - Silicones are any of a number of siloxane polymers. Common uses in water base drilling fluids include defoaming and lubrication.



Graphite - Graphite is a multi-layered all-carbon compound that is used occasionally in water base mud for lubrication, and extensively in NAF’s as a lost circulation control additive.

Common Salts

NaCl Sodium chloride

KCl Potassium chloride

CaCl2 Calcium chloride

BaSO4 Barium sulfate, barite

CaCO3 Calcium carbonate, limestone, marble, calcite

Fe2O3 Iron oxide, hematite

FeO.TiO2 Iron titanium oxide, ilmenite

Ca(OH)2 Calcium hydroxide, lime,

NaHCO3 Sodium bicarbonate, bicarb

Na2CO3 Sodium carbonate, soda ash

Na2H2P2O7 Sodium acid pyrophosphate, SAPP

NaOH Sodium hydroxide, caustic, caustic soda

KOH Potassium hydroxide, caustic potash

Ca2SO4 Calcium sulfate, anhydrite, gyp/gypsum (water in crystal)

NaBr Sodium bromide

CaBr2 Calcium bromide

ZnBr2 Zinc bromide

HCOOK Potassium formate, potassium salt of formic acid

HCOONa Sodium formate, sodium salt of formic acid

HCOOCs Cesium formate, cesium salt of formic acid



pH

pH is a mathematical function which expresses how acidic or alkaline a solution is on a simple 0 to 14 scale (Figure 6-2).

Figure 6-2: pH scale with examples

Water base drilling fluids are maintained on the alkaline side of the scale in order to reduce corrosion on drillstring and casing, as well as to avoid the low pH flocculation of clays. Slightly alkaline pH (7.5 to 9.0) drilling fluids are recognized as producing better cuttings stability and less hole washout than fluids with higher pH’s. Hydroxyl ions (OH-) are very dispersive to shale, so the higher the pH, the greater the hole washout and the greater the tendency for cuttings to “dissolve” before reaching the surface. However, some mud additives like lignite and lignosulfonates are more soluble and work better at higher pH’s (≥9.5).

Some types of formation damage are attributable to pH. Most reservoir brines are slightly acidic (pH 4 to 6) due to dissolved acid gases like carbon dioxide and hydrogen sulfide (H2S), and because some crude oils contain small amounts of natural carboxylic acids. Most reservoir drill-in fluids and coring fluids are run only slightly alkaline (pH 7.5 to 8.5) because above approximately a 9.2 pH, a number of damaging effects take place.



Bicarbonate ions begin to convert to carbonate ions in appreciable quantities and can be readily precipitated as calcium carbonate (limestone), reducing permeability.

Any natural carboxylic acids in the crude oil will be ionized at high pH and become active surfactants that can generate and/or stabilize emulsions.

At high pH, any pore lining clays are more likely to be mobilized by either regular dispersion or by silica dissolution, which increases rapidly above pH 9.2. These mobile fines will eventually bridge off at a pore throat and sharply reduce permeability.

The solubility of some common compounds in relation to pH is shown in Figure 6-3. The distribution of CO2, bicarbonate and carbonate ions as a function of pH in fresh water and sea water is shown in Figure 6-4.

Figure 6-3: Solubility in relation to pH for some common compounds (International Drilling Fluids – Technical Manual for Drilling Completion and Workover Fluids, 1982)



Figure 6-4: Distribution of carbon dioxide, bicarbonate ions and carbonate ions in fresh water and sea water as a function of pH (International Drilling Fluids – Technical Manual for Drilling Completion and Workover Fluids, 1982)

An elevated pH can also lead to the degradation of certain chemicals. For example, when fresh cement is drilled with a partially hydrolyzed polyacrylamide (PHPA) mud, the resulting high pH can hydrolyze (cleave with water) the amide group and release significant amounts of ammonia at the flow line. Also, some of the synthetic base fluids that are used as ROP enhancers contain esters which can be hydrolyzed into the original fatty acid and alcohol.



Polymers

Polymers are long chain molecules formed by chemically joining one or more small monomers together over and over (see Figure 6-5). Besides straight chains, polymers can be branched and/or crosslinked, which modifies their properties.

Figure 6-5: Simple alternating copolymer

The function of a polymer in a drilling fluid is strongly related to its chain length and the nature of the monomers. Short chain polymers (2,000 to 12,000 molecular weight) work well as thinners while polymers with molecular weights from about 40,000 to 100,000 are frequently good fluid loss control additives. Polymers above 500,000 provide additional viscosity.

Some common polymers for water base drilling fluids are show in Table 6-1.

Table 6-1: Common polymers for water base drilling fluids

Material Source Application

Xanthan gum Bacterially produced Viscosifier, especially for low shear rate rheology

Polyanionic cellulose (PAC) Chemically modified (water soluble) cellulose – frequently from cotton

Different grades used for both fluid loss control and viscosity

Carboxymethyl cellulose (CMC)

Similar to PAC, but less chemical modification

Grades for fluid loss control and viscosity



Material Source Application

Sodium polyacrylates Synthetic Grades for thinning and for fluid loss control

Partially hydrolyzed polyacrylamide

Synthetic Used to improved cuttings integrity, but some versions also give significant viscosity

Guar gum Plant seeds Viscosity

Starch Corn, potato, rice Fluid loss control

Lignosulfonate Lignin from trees, modified to be water soluble

Thinner

Hydroxyethylcellulose (HEC) Ethylene oxide modified cellulose

Viscosifying brines and fluid loss control

Table 6-1: Common polymers for water base drilling fluids (continued)

Polymers derived from natural sources (e.g. cellulose, bacteria, wood pulp) are frequently more cost effective than their synthetic counterparts, but because they have weak spots like oxygen in their backbones they begin to thermally degrade when the downhole temperature exceeds a critical value.

A few commonly accepted thermal limits are seen in Table 6-2.



Product Thermal Limit, oF

Guar gum 150

Starch 225

Xanthan gum 275

CMC 275

PAC 275

Lignosulfonate 325-350

Polyacrylates 400

Table 6-2 – Some drilling fluid polymer thermal limits

Most drilling fluid polymers are supplied as dry powders and require extra care when mixing. Dry polymers are slow to hydrate and fully disperse. This is particularly true of higher molecular weight materials used for fluid loss control and viscosity. Very slow addition rates through the hopper are recommended. There are a number of high-shear mixing devices that can be built into or added just downstream of the hopper. The best of these devices will improve hydration rates, maximize yield, and improve the effectiveness of each sack of material. Conversely, shearing can be taken too far. Some long chain polymers like PHPA and xanthan gums can be shear-degraded to shorter chains. A certain amount of shear-degradation happens just from the mud passing through the mud pumps and bit nozzles, but a few shear devices can strongly increase the degradation.

Many drilling fluid polymers and water base mud chemicals are made water soluble by the presence of



carboxylate groups. These groups each have one negative charge. Soluble calcium has two positive charges and can react with two carboxylate groups sharply reducing the water solubility of the complex. Because of this incompatibility it is usually a good idea to keep the soluble calcium in a water base mud below about 300 to 400 ppm. Trying to reduce the soluble calcium level to near zero can lead to secondary problems so the best compromise is to target a few hundred parts per million.

Surfactants

Surfactants are used for a very wide range of applications in drilling fluids, including reducing bit-balling, emulsifying brine into a NAF, shale inhibition, casing cleaning spacers before cementing, and oil-wetting solids in a NAF. This section will cover a few illustrations.

Surfactants are molecules that have two distinct parts; a water soluble “head” and an oil soluble “tail” (see Figure 6-6).

Figure 6-6 : Simple surfactant molecule diagram

Oil soluble “tail”

Water soluble “head”



Solvency

One of the main roles of surfactants is solvency, or cleaning oily material off of surfaces. For example, how does a surfactant spacer clean NAF off of a casing string so cement can form a good bond? Since surfactants have both hydrophilic (water-loving) and lipophilic (oil-loving) portions they tend to migrate to interfaces like an oil-water interface where each half of the molecule can be in its preferred environment. In this case, the surfactants in the water base spacer readily partition their lipophilic tails into the oil on the casing, leaving their water soluble heads in the water phase. When a great many surfactant molecules gather in the oil droplet the large number of water-soluble “heads” sticking out of the droplet makes it water-dispersible (see Figure 6-7) so it can be floated off of the steel and carried away by the rest of the spacer.

Figure 6-7: Oil droplet solubilized into water

Water

Water Water

Water



Oil-Wetting & Water-Wetting Surfactants

Another interface where surfactants tend to accumulate is at metal or rock interfaces with oil where the water-soluble head of the surfactant is attracted to charged sites on the surface of the metal or mineral. Most metals and minerals are naturally water-wet, but with a surfactant hydrophile firmly attached to the solid surface, the lipophilic tail is forced to lay near the surface, changing the surface to oil-wet. An oil wetting surfactant is useful:

When barite and drilled solids in a NAF need to be oil-wet to keep the mud rheology stable

When filming amines from water base muds adsorb on metal surfaces and slow down corrosion rates

When surfactants coat a bit and bottom-hole assembly and reduce bit balling

However, oil-wetting is detrimental to a producing formation. Oil is most easily produced from a porous matrix when it can slide on a film of water attached to the rock. When oil-wetting surfactants from the filtrate of a NAF adsorb on reservoir rock they can make the near-wellbore region oil-wet, substantially reducing relative permeability.

Emulsifiers

Forming emulsions is another important function of surfactants. The most familiar application is emulsifying calcium chloride brine into a non-aqueous drilling fluid to help with fluid loss control, rheology and shale control. The emulsifying surfactants form a very tight skin on the tiny brine droplets (5 to 10 microns) and keep them stabilized and dispersed in the continuous oil phase.



Emulsions have also been used in water base drilling fluids. It is not as common as it once was, but diesel or other base fluid was added to water base muds to help with shale stability, ROP and bit-balling. These products work better when not emulsified, but since drilling fluids go through very high shear rates and usually contain some surface active material, emulsification eventually occurs.

Emulsions can be detrimental to producing zones. When the mud filtrate invading a formation contains surfactants, an emulsion can form with the oil or formation brine. These emulsions are usually highly viscous and can impede oil production.

Thinning

Thinners are usually short-chain polymers which have numerous negatively charged groups that are attracted to the charges on clay edges. However, surfactants also frequently carry negative charges (or at least partially negative charges for non-ionic surfactants) and can substantially thin dirty, non-dispersed muds. Even moderately surface active materials like sulfonated asphalts can cause unexpected thinning. As always it is recommended to pilot test major additions to a drilling fluid system.

Osmosis

Osmosis relates to the movement of water through a semi-permeable membrane. In this application a membrane is called semi-permeable if its openings are so small that only water molecules can move through it and not larger materials like salt ions, alcohols, polymers, etc. If two bodies of water with different salinities are separated by a semi-permeable membrane



then water will spontaneously move through the membrane to try to equalize the two salinities. An example of this would be handling high salinity completion brine without gloves. Skin cell walls are semi-permeable, so when they are exposed to high salinity brine, water rushes out of the skin cells, leaving the skin very dry and chapped (wear your protective equipment!).

Non-Aqueous Fluids (NAF’s)

The highest percentage of footage drilled in the oilfield is through shales. Shales tend to become unstable when exposed to water, so one preferred feature of a drilling fluid is that it prevents water from being available to shales. In NAF’s this happens because the external phase is an oil and the brine phase is very tightly emulsified. The emulsifying surfactants pack so tightly on the outside of the brine droplet that they form an excellent approximation of a semi-permeable membrane. If the salinity/activity (see “Water Phase Activity” above) of the brine phase is lower than the activity of the shale then any water movement will be from the shale into the drilling fluid, thereby preserving the strength of the shale.

Water Base Muds

Shales have long been thought to behave somewhat like a semi-permeable membrane because their pores are so small (tens of angstroms), and because of the highly charged surfaces of clays. However, research has established that salt ions can move in and out of shales with little hindrance (perhaps 5 to 10% restriction as compared to 100% for a true semi-permeable membrane). Several approaches have been tried to improve the membrane efficiency of water base drilling



fluids. The mechanisms are not fully understood, but improvements can be made by sharply reducing the permeability of the shale (using silicates, starch/amine reactions, etc), and also by depositing chemicals in the pore systems (using methyl glucoside, polyglycols, aluminum complexes, etc.). While shale stability can be greatly improved with these systems, they may not perform as well as oil muds on rate of penetration, lubricity, temperature stability, etc.

Thermal Degradation, Oxidation and Hydrolysis

An old chemistry rule-of-thumb states that chemical reaction rates roughly double for each 10oC of temperature increase. As might be expected, the side effects of chemical reactions in drilling fluids are rarely positive.

Oxidation

Familiar forms of oxidation include iron rusting and things like a freshly cut apple or potato turning brown. In a drilling fluid, dissolved or entrained oxygen reacts with organic additives like polymers, lignite or surfactants, changing their properties. In extreme cases like high temperature high pressure (HTHP) wells some of the oxidation will be carried all the way to the production of CO2. CO2 dissolved in a drilling fluid will lower its pH potentially leading to problems with viscosity if the CO2 is not treated out with lime or some other source of calcium. In addition to the effects on pH, signs of oxidation could include a drop in polymer viscosity and difficulty controlling fluid loss.



Hydrolysis

Hydrolysis means “to cleave with water”, and it is a common chemical degradation pathway in water base drilling fluids. A simple example is shown in Figure 6-8. The molecule is cut into two parts with part of the water molecule (OH) going with one half and the remaining hydrogen going with the other half.

Figure 6-8: Starch chain cut by hydrolysis

Polymers like starch, guar, xanthan gum, CMC’s and PAC’s with similar polysaccharide (sugar) backbones are readily cut apart by hydrolysis, especially at high temperature and high pH. To some degree, surfactants, lignite, asphalts, etc. are all susceptible to oxidation.

An example for NAF’s is the hydrolysis of the esters used to make environmentally friendly muds. The high pH water (calcium chloride brine and lime), combined with temperatures above 300 to 325 F will hydrolyze the ester back to its original components (a fatty acid and an alcohol), as depicted in Figure 6-9.

Figure 6-9: Hydrolysis of a typical ester base fluid molecule

C17 - C - O - C - C – C4

O C C

Typical Ester Base Fluid

H - O - C - C - C4 C C

C17 - C - O-1

O heat, high pH

+ Fatty Acid

2-Ethylhexyl Alcohol

O CH2OH

H H

H

H

O O

H OH

OH

OCH2OH

H H

H

H

HOH

OH

OCH2OH

H H

H

H

O

H OH

OH

OCH2OH

H H

H

H

HOH

OH

OH HO

+ Heat, High pH

H2O

Chapter 7: Hole Cleaning


CHAPTER 7: HOLE CLEANING

The transport and removal of drilled cuttings, formation rock, cement and other solid material in the wellbore is one of the most fundamental parts of drilling operations. A well cannot be successful if the rock drilled is not displaced from the wellbore. Furthermore, for efficient well construction, the drilled formation must be removed in a timely and consistent manner. Failure to effectively transport the cuttings can result in a number of drilling problems including:

Excessive over pull on trips

High drag and rotary torque

Stuck pipe

Hole pack-off

Formation fracturing and breakdown

Slow ROP

Lost circulation

Trouble running casing

Primary cementing failures

Not only does poor hole cleaning contribute to some of the largest sources of drilling non-productive time (NPT), but it can ultimately lead to damage of the reservoir formations and a decrease to well productivity. Therefore, it is crucial that hole cleaning be properly addressed in the well planning phase and fluid formulation, as well as best practices being implemented and cuttings transport being monitored throughout drilling. It is also worth noting that some of the properties and practices that help with hole cleaning can be detrimental to other parts of the drilling operations



by increasing standpipe pressure and equivalent circulating density (ECD), and all aspects must be considered. Designing parameters for hole cleaning should not be done in such a way that other sources of non-productive time are inadvertently caused.

For a discussion of the rheological models and terms described in this chapter, refer to the “Rheological Models” section of Chapter 2.

Hole Cleaning Regimes

The mechanics of moving cuttings and solids out of the wellbore vary significantly depending on the inclination of the wellbore. In a vertical wellbore, the cuttings have no place to settle aside from the bottom of the hole. As the rotation of the bit and BHA can usually stir these up into the annular flow, cuttings transport is mainly a function of ensuring the annular velocity is greater than the particle slip velocity. In deviated wells, cuttings will have a tendency to settle to the low side of the hole and form cuttings beds. These cuttings may move uphole through the bulk flow, but may also slump back when circulation stops; causing pack-offs and drilling problems, as well as generally increasing torque and drag. In horizontal holes, cuttings beds are almost certain to form, and effective hole cleaning relies on a combination of factors such as flow rate, drillstring rotation, and drilling fluid properties. An idealization of the different hole cleaning regimes can be seen in Figure 7-1. The strategies and practices involved in good hole cleaning obviously vary in these different environments, so they will be examined individually.



Figure 7-1: Hole cleaning regimes as a function of inclination and annular velocity (Courtesy of DTA Drilling Fluids Manual)

Hole Cleaning in a Vertical Well

Vertical and near vertical wells are defined as having less than 30° inclination, although as the well approaches 30°, some of the problems associated with deviated wells may be encountered. In a vertical environment, the main factor determining hole cleaning is the slip velocity of the cuttings compared to the average annular velocity. If the annular velocity is the greater of the two, cuttings will rise while circulating. As the slip velocity is a function of the mud properties and the annular velocity of the flow is a function of the



pumping rate, these are the parameters to focus on in vertical hole cleaning.

When the pumps are off, the gel strength of the drilling fluid can prevent the settling of cuttings. It should be noted that cuttings may fall back, and normally this is not an issue at the bit/BHA as the higher local annular velocities and rotation will generally move cuttings back into suspension. More problematic can be locations where there is a change in annular diameter, such as at casing points or at the sea floor when using a riser.

Particle Slip Velocity and Settling

During circulation, cuttings will have a natural tendency to sink due to their density. This tendency is counteracted by the flow of the drilling mud and viscous forces acting against particle movement. If the settling tendency is greater than the force of the flow and viscous forces, the particle will not be transported out of the hole.

Stokes' Law for creeping flow in a Newtonian fluid with oilfield units is:

138

where vsl is the particle slip velocity and µ is the fluid viscosity, ds is the particle diameter, s is the density of the particle, and f is the fluid density or mud weight.

The Moore correlation for Power Law type fluids at intermediate Reynolds numbers with oilfield units is:

2.90.

. .

where µa is the apparent viscosity, a function of the fluid behavior index "n" and the fluid consistency index "k".



There are many more complex methods for calculating cuttings slip velocity that incorporate particle geometry, more sophisticated non-Newtonian fluid models, and so on, but the general trends remain the same. The methods to reduce slip velocity are:

Increase fluid viscosity. The higher the drilling fluid viscosity, the lower the slip velocity due to viscous effects on the cuttings.

Increase mud weight. As the mud density approaches the cuttings density, the slip velocity will drop due to increased cuttings buoyancy.

Decrease cuttings diameter. The smaller the cuttings, the lower the slip velocity due to increased suspension forces.

The gel strength required to suspend a spherical particle in a non-Newtonian fluid is (in oilfield units):

10.4

where g is the gel strength and ds is the particle diameter. There is a direct correlation between the required gel strength and the cutting diameter. The smaller the cuttings, the easier they are to suspend. It should be noted that Newtonian fluids, such as some spud muds, water or brines, do not have a gel strength and thus, particles will settle if flow is stopped as long as the cuttings have a higher density than the fluid surrounding them.

Hole Cleaning in a Deviated or Horizontal Well

At an inclination of greater than roughly 30°, the mechanisms of cuttings transport become significantly more complex. When pumping is not continuous and gel strength formation is not instantaneous, cuttings will fall



for some period after the cessation of circulation. In a vertical hole, this means they may fall back some distance, but in a deviated hole, they may settle on the low side of the hole. Through this process, cuttings beds can develop, and the formation, transportation, and erosion of these beds are complex and time dependent. The formation and dissipation of cuttings beds are time dependent processes which greatly complicate modeling. Typically, hole cleaning programs calculate the steady state flow rate at which the formation and removal of cuttings beds is equal. This does not account for the movements of the cuttings during the pump’s off time. As a result, many more drilling parameters come into play to maintain good hole cleaning in a deviated environment, and best practices and lessons learned are significantly more important.

Factors Affecting Hole Cleaning

Hole cleaning is an issue to be considered in all hole sizes and all inclinations. The fundamental factors affecting the ability of the drilling fluid flow to transport cuttings are:

Annular velocity

Pipe rotation

Rate of penetration

Mud density

Mud rheology

Hole geometry

Cuttings properties

It should be noted that these parameters are interrelated and their effects on hole cleaning can vary significantly. Despite the complexity, it is important to



understand the impact of each parameter to determine the best remedial actions and preventative measures.

Annular Velocity

The term annular velocity refers to the mean velocity bulk flow, that is, the average speed of the drilling fluid in the space between the drillstring and wellbore wall. In general, changing annular velocity has the single strongest effect on hole cleaning. Without circulation towards the surface, it is not possible to remove drill cuttings. If annular velocity is lower than the slip velocity of particles, they will not be transported out of the hole. In deviated and horizontal environments, the flow transports cuttings and erodes cuttings beds. Thus, in most wells, the first response to poor hole cleaning may be to increase the pump rate, assuming that the resulting standpipe pressures and ECD are acceptable.

Although annular velocity refers to the average fluid velocity, it should be noted that this is not the velocity of all of the fluid in the annular cross-section. Figure 7-2 shows laminar velocity profiles between the drillstring and the wellbore wall (in this case representing 5-inch drillpipe in a large riser). Three fluids are shown; all have the same average velocity, but different rheological properties. It can be seen that there may be areas toward the edges where the local fluid velocity is less than a given slip velocity. In these cases, the particles will fall back until they are agitated into the center of the flow where they can be transported upwards. This is the reason that optimizing rheological properties for hole cleaning is an important aspect of hole cleaning, as will be discussed later.

In a deviated or horizontal well, the velocity profile will tend to be different due to pipe eccentricity. This results in larger areas of lower flow rates, which can lead to more cuttings dropping out of the flow and laying on the



low side of the hole in cuttings beds. In these cases, it is sometimes impractical to increase the flow rates to the amount required to sufficiently erode the cuttings and clean the hole. Other parameters would be better adjusted, such as pipe rotation or mud properties.

Figure 7-2: Annular velocity profiles for different rheologies at the same average annular velocity

As the flow rate increases, the average annular velocity increases linearly, as does the velocity profile until turbulent flow is initiated. Turbulence is initiated when the fluid velocity, in conjunction with the fluid properties and hole geometry, is sufficiently so high that the fluid can no longer flow in a smooth laminar pattern. Turbulence causes wide and constant fluctuations in the local velocities and this makes turbulent flow quite effective in transporting cuttings, especially in deviated holes. Unfortunately, turbulent flow results in a higher frictional pressure drop. In larger hole sizes (above 8 1/2



inches) the required flow rates (which are increased by pipe laying on the low side of the hole) are often prohibitive from a surface pressure and formation fracture standpoint. Additionally, turbulent flow has a higher propensity to cause formation erosion and washout.

Pipe Rotation

Rotation of the drillstring induces the fluid surrounding it to revolve in the same direction. At the edge of the pipe, the speed will be the same as the drillstring, and at the wellbore wall, it will be zero. This rotational velocity profile can be seen in Figure 7-3. It should be noted that this example assumes a centered pipe. If the pipe is eccentric, the profile will vary according to the angle relative to the direction of the pipe.

Figure 7-3: Change in fluid rotational velocity from edge of 5" drillstring to edge of 12.25" wellbore with 120 RPM pipe rotation



In a vertical well with centered pipe, rotation will spin particles outward in a centrifugal manner. This movement will not aid in hole cleaning and might actually be detrimental as cuttings tend to move toward the lower local velocity areas near the wellbore wall. At this point they would begin to settle when their slip velocity exceeds the local flow rate. Fortunately, the vibrations and chaotic movements that occur in drilling operations mean that this does not continuously occur and particles reenter the higher speed flow and continue to move to the surface.

In deviated or horizontal environments, the situation is quite different. The drillstring is usually eccentric and cuttings beds have often formed on the low side where the pipe is. Here, pipe rotation is crucial to ensure good hole cleaning. The rotation of the pipe tends to kick up settled particles into the higher speed flow, allowing them to be transported. Without pipe rotation, it can sometimes be extremely difficult to transport cuttings sufficiently to avoid pack-offs and stuck pipe. Additionally, the smaller annular space caused by larger cuttings beds can result in higher ECD’s and standpipe pressure. When planning wells with extended horizontal sections, the use of rotary steerable tools is recommended as the prolonged periods without rotation associated with sliding can cause a great deal of hole cleaning problems.

The optimum pipe speed required to aid in hole cleaning is a function of cuttings properties, ROP, flow rates and hole geometry. However, while increasing surface RPM will tend to improve hole cleaning, there is a point of diminishing returns. With increased pipe rotation, drill cuttings and particles in the fluid will generally tend to be ground up more. This leads to fine drilled solids which may be difficult to remove from the fluid and a shift in the size distribution of lost circulation materials. Furthermore, excessive pipe rotation may lead to



damaging downhole vibrations and stick-slip, which can cause NPT from tool failure and worsen wellbore stability. Thus, choosing the appropriate surface rotation can be complicated and is best done in conjunction with downhole shock measurements. While pipe rotation alone is insufficient to ensure good hole cleaning in deviated, horizontal and extended reach wells, it is a crucial tool to prevent NPT.

Rate of Penetration

The concentration of cuttings in the fluid, assuming no settling out, is a direct function of particle slip velocity, ROP, flow rate, and hole geometry.

1

where fs is the solids concentration, BS is the bit diameter, ROP is the rate of penetration, C is a unit conversion factor, vs is the particle slip velocity, va is the average annular velocity, and Q is the surface fluid flow rate.

The cuttings concentration is important as it influences ECD, standpipe pressures, fluid rheological properties, as well as the ability to clean the hole. It can be seen from this equation that by increasing the hole size (bit size or using a hole opener), ROP, or slip velocity, it will increase the concentration; while increasing the flow rate will reduce it.

In general, uncontrolled, high ROP can lead to hole cleaning difficulties, pack-offs and other sources of NPT. So, it is important to ensure that operating parameters are sufficient to remove the cuttings generated by a given ROP. It is usually recommended to control the ROP such that the cuttings concentration remains below four or five percent.



Mud Density

The density of the drilling fluid has a direct effect on the slip velocity of particles due to buoyancy forces. As a result, with high mud weights, lower flow rates are required to achieve good hole cleaning. It should be noted that this applies primarily to vertical holes. Unless the mud weight approaches the cuttings density, cuttings beds will still form in inclined wells and pipe rotation is required to ensure transport of cuttings out of the well.

Fluid Rheological Properties

As described by the slip velocity equations, increasing viscosity tends to improve hole cleaning. Generally, it is the low-end rheology properties that help provide good hole cleaning, but this can be complicated by how properties are reported. Plastic viscosity (PV) and yield point (YP) numbers are normally based on calculations made using FANN dial readings at the 300 and 600 rpm speeds. In large hole sizes, the fluid may not be subjected to the same shear rates as those represented by these viscometer rpm speeds. That said, it is still easy to see that an increase in PV and YP will tend to help hole cleaning, specifically with a high YP to PV ratio. The situation is more difficult with Power Law fluids. Instead of PY and YP, the rheology is described by "k" and "n" parameters which are less intuitive. The effect of varying these can be seen in Figure 7-4 where three different fluids flow at the same average flow rate and same pressure drop. Nevertheless, it can be seen that fluids with a higher 'k" and lower "n" will tend to have a more flattened velocity profile, which allows more of the annular space to experience flow above the particle slip velocities.



Figure 7-4: Velocity profiles for 3 Power Law fluids at the same flow rate and pressure drop

Another representation of flow, the Herschel-Buckley model, adds another parameter “0”which allows for better prediction of fluid properties. The hole cleaning behavior of fluids represented by this model is somewhat easier to predict since the 0 parameter is a good indicator of hole cleaning ability. However, raising 0 too high can lead to problems with the higher shear rate rheologies (i.e. high PV’s) and result in unacceptable ECD’s.

Hole Geometry

For a given flow rate, the larger the annular space between the drillstring and the wellbore wall, the lower the average velocity. This fact dictates the need for higher flow rates to ensure good hole cleaning in larger hole sections. It also should be remembered that the



addition of tools that enlarge the borehole behind the bit, such as hole openers or underreamers, will create the need for higher flow rates.

Discontinuities in hole geometry are often trouble areas where cuttings can build up. At the base of the casing shoe in deviated wells, cuttings being transported on the low side can be caught in a low energy area and form beds that are difficult to remove. If care is not taken while pulling through the shoe, pack-offs or stuck pipe can occur. Risers also present a challenge, as there can be a very large difference between the casing ID and the riser ID. Cuttings flowing upwards into the riser can end up settling on the base, where there is not effective flow to move them. Booster pumps are the primary tool to deal with this challenge. They inject flow at the riser base in deepwater drilling and aid in the transport of cuttings into the main flow.

Cuttings Properties

The size, shape, and density of a cutting or any solid particle in the annulus affect the force required to move it. This can cause problems when entering a new formation or using a new bit type, as the change in cuttings can result in hole cleaning problems despite maintaining drilling parameters which were previously adequate.

Cuttings dimension is normally measured as the “effective diameter” and cuttings can range from a very fine, coffee grounds size, to a significant fraction of the bit size in fast underbalanced drilling. Cuttings are often assumed to be spherical in order to simplify modeling their behavior, but in practice cuttings are usually irregular. Generally, the less spherical the cutting, the slower it will settle. The common “diameters” that are used in hole cleaning simulations are between 1/4-inch and 1/2-inch, although engineers are encouraged to look



at the size of the cuttings coming over the shakers to provide a check, with the understanding that cuttings will usually be ground down by drillpipe rotation. The larger the cutting diameter, the higher the slip velocity and the more difficult it is to transport the particle out of the hole. Additionally, the type of bit and cutting action impacts the cutting size. Bits that grind the formation, such as those that are diamond impregnated, tend to produce finer cuttings than bits with roller cones that gouge the formation.

Cuttings density reflects the rock that is being drilled. Often the porosity and any fluids in the rock are ignored, as the pore structures are assumed to be crushed in the drilling process. With extremely large cuttings, the effect of porosity may not be negligible. As the density of the rock increases, greater annular velocities are required to clean the hole.

A summary of the effects of various parameters on hole cleaning is shown in Table 7-1.

Table 7-1: Summary of parameter effects on hole cleaning

Parameter Effect of Increase in Parameter on Hole Cleaning

Annular Velocity Improves hole cleaning. Primary parameter to affect hole cleaning in vertical environments.

Pipe Rotation Minimal impact in vertical wells, important in deviated wells and very important in horizontal wells.

Rate of Penetration Increases cuttings concentration, which may require increasing other parameters.



Parameter Effect of Increase in Parameter on Hole Cleaning

Mud Density Decreases slip velocity.

Rheological Properties (PV,YP)

Improves hole cleaning, but may increase ECD.

Hole Geometry (gap between pipe and annulus)

Reduces annular velocity requiring higher flow rates, increased pipe rotation, and/or altered rheological properties.

Cuttings Properties (cuttings size)

Larger cuttings have higher slip velocity, but are easier to remove with shakers.

Table 7-1: Summary of parameter effects on hole cleaning (continued)

Best Practices

There is no magic formula for hole cleaning that covers all situations. Because circulation is never continuous through an entire section, the time dependent nature of cuttings transport ensures that every well is different. Good hole cleaning requires proper planning and preparation, but must also include continuous monitoring to ensure success. The simplest way is to watch the volume and rate of cuttings coming over the shakers. Changes in this trend can indicate a failure to clean the hole. If the volumes are different than a similar offset well, then perhaps cuttings are not being transported adequately. Downhole pressure while drilling (PWD) tools can help monitor hole cleaning in vertical sections, as the suspended particles will increase the bottom-hole pressure. A continuous increase in the pressure may indicate that the cuttings concentration is increasing. Surface torque and hook load can be used to



evaluate the buildup of cuttings beds. Comparing the drag tripping in and out can show the accumulation of drilled solids and suggest that additional sweeps or hole cleaning trips may be needed.

Hole Cleaning Sweeps

One of the most basic tools used to clear out excessive cuttings is to pump a sweep of fluid with different properties than the normal drilling fluid. Ideally, this sweep will pick up cuttings that are not being adequately transported to surface. Most commonly, sweeps are of a higher density (often 3 to 4 ppg higher) and sometimes higher viscosity than the drilling fluid. This is most effective in vertical wells, as the viscosity difference can quickly lead to flow separation in an inclined well.

The effectiveness of sweeps can be seen when a large slug of cuttings comes over the shakers. If the volume of cuttings seems inadequate or other signs of excessive cuttings are observed, repeated sweeps may be attempted, although the first sweep should be completely circulated out prior to the next sweep.

Short Tripping and Wiper Trips

Making periodic short trips has proven helpful in controlling problems created by cuttings beds in the high angle portion of the well. Tripping through the bed can help to ensure that the bottom-hole assembly and bit can be pulled through it, and the action agitates the bed allowing some of the cuttings to be picked up when circulation begins. When sliding with a downhole motor, short trips are sometimes used to clean up the section that was not drilled with pipe rotation.

Wiper trips are usually longer pre-planned trips which involve circulation and pipe rotation. These trips work



through recently drilled sections and attempt to mobilize as much of the cuttings beds as possible. Many times there is a hole cleaning program that dictates a wiper trip after a given number of hours or distance drilled, although sometimes a wiper trip may be needed based on increasing torque and drag and inadequate cuttings returns on surface.

Short trips and wiper trips can be quite helpful in assisting hole cleaning when beds have built up, but as the time spent is essentially non-productive, they should be used when appropriate and not as a cure-all or replacement for good hole cleaning practices while drilling. Time spent on trips is also extra time that the hole is open, which can lead to a number of time delayed problems, such as wellbore instability, shale swelling, and formation damage from deeper invasion. Thus, it is important to realize when a cleaning trip is needed, and when it can be avoided.

Drillstring Rotation

It is well understood that pipe rotation in deviated and horizontal wellbores, especially with sizes less than 17 1/2 inches is greatly beneficial. The question is: What is the optimal pipe rotation speed? A general industry rule-of-thumb suggests at least 120 RPM in larger hole sizes. Some have pushed for more aggressive speeds of up to 200 RPM. As with many aspects of drilling, the optimum RPM is usually only found through experience. Higher rotation speeds do help, but can lead to downhole shocks, tool failure, and NPT. Low pipe rotation may lead to poor hole cleaning, pack-offs, and time lost to wiper trips. Proactive monitoring of downhole shocks, adjustment to drilling parameters like weight-on-bit (WOB) and RPM, and attention to the cuttings volume and type coming over the shakers provide the best way to optimize drillstring rotation.



Flow Rates

While it is relatively straight forward to calculate the required flow rate to clean a vertical hole, horizontal wells are more problematic. A number of industry computer programs and models exist, but as a starting point, the some broad industry rules-of-thumb for extended reach wells are shown in Table 7-2.

Hole Size Recommended Flow Rates

17 1/2"

At least 1000 to 1200 gpm. As frictional pressure drop tends to be quite low in this large hole size, pump rates are often the maximum allowable for the pumps.

12 1/4" Aim for 900 to 1000 gpm as ECD allows. For lower flow rates, monitor hole conditions and be prepared for wiper trips.

8 1/2" 400 to 600 gpm depending on ECD and pressures. Watch for standpipe pressure spikes that might be warnings of potential pack-offs.

6" Flow rate is often dictated by pressure and ECD limitations. If possible, use 250 to 300 gpm.

Table 7-2: Recommended flow rates for cleaning various hole sizes

Prior to Tripping Out of Hole

It is usually a good practice to make sure that the hole is clean prior to tripping out, as this can help to avoid pack-offs and stuck pipe. Before tripping out, circulate the hole at the normal flow rate until the shakers are clean, while rotating and reciprocating the drillpipe. This might



require as many as three bottoms-ups, depending on the hole angle and hole size. Table 7-3 contains some typical numbers of bottoms-ups required.

Hole Angle ( in degrees) 8 .5 in. 12.25 in. 17.5 in.

0 – 10 1.3 1.3 1.5

10 – 30 1.4 1.4 1.7

30 – 60 1.6 1.8 2.5

> 60 1.7 2.0 3.0

Table 7-3: Recommended numbers of bottoms-ups prior to tripping for various hole sizes

ECD and Standpipe Pressure Management

While considering how best to clean the hole, it is important to remember that the majority of parameters that increase hole cleaning also result in an increase in the frictional pressure drop, which in turn leads to higher standpipe and bottom-hole pressures. Fracturing the formation because of increased ECD is not the desired outcome of trying to improve hole cleaning.

It can be seen from Table 7-4 that care must be taken not to limit operations through the increase in pressure while trying to improve hole cleaning. That being said, a pack-off due to poor hole cleaning will also increase pressures.



Parameter Effect of Increase in Parameter on Pressures

Annular Velocity

Directly increases pressures. Bottom-hole pressure effect is somewhat less if pipe is eccentric or in large hole sizes, but standpipe pressure will still increase.

Pipe Rotation Can cause a small increase in pressures.

Rate of Penetration Increases cuttings concentration, which causes higher fluid density and higher pressures.

Mud Density Increases hydrostatic pressures.

Rheological Properties (PV,YP)

Tends to increase pressures.

Hole Geometry

(gap between pipe and annulus)

Larger gap reduces the pressure drop in the annulus, but pressure drop in the drillpipe stays the same.

Cuttings Properties

(cuttings size)

Smaller cuttings are harder to remove with solids control equipment which leads to increasing drill solids in the mud. This increases density and especially fluid viscosity leading to higher pressure.

Table 7-4: Summary of parameter effects on standpipe and bottom-hole pressures

Monitoring Pressure While Drilling

The simplest pressure measurement is at the standpipe. This number is an indication of the total pressure drop, minus the surface system to the pumps. The most



important aspect of standpipe pressure is to ensure that it remains below the rating of surface equipment. Sudden changes in pressure while other parameters are constant are indications of drilling problems. A sudden increase can be a result of a pack-off, a blocked bit nozzle, a stalled downhole motor, and so on. A sudden decrease may indicate there is a washout around the drillpipe.

In many operations a PWD tool is included in the BHA and real-time data is transmitted via the measurement while drilling (MWD) tool to surface. These tools can be very useful, but care must be taken in their interpretation. Downhole ECD measured by the PWD tool is often used as a proxy for hole cleaning. The tool measures pressure, and if an increase in pressure is due to an increase in cuttings concentration, then this is directly related to hole cleaning. This works best in a vertical well. In a horizontal well, poor hole cleaning will lead to the formation of cuttings beds. If the cuttings are not suspended in the mud, they will not add to the density and thus, the PWD tool will not give the same indication of the formation of cuttings beds, as this will only measure the change in annular size from cuttings beds.

PWD measurements are not always rapidly updated; the data points may measure from a few seconds to a few minutes apart. This makes PWD measurements somewhat problematic for rapid response, as a pressure spike in a single data point might be considered noise, and a few more data points may be required for confirmation. This may take a few minutes, at which point a serious problem may have developed. Additionally, alteration of drilling parameters, especially surface pipe rotation, can also affect ECD and care must be taken to differentiate the cause of a change in the ECD trend.



Many PWD tools also store recorded data at a much higher sampling rate. Unfortunately, these data are not available until the tool is back on surface and the data are then dumped to the computers. While not helpful for real-time decisions, careful review of these data, compared to surface data, can help to build experience in correlating surface measurements, such as flow rate, standpipe pressure and cuttings returns to downhole measurements. This can allow for more confidence in future runs when diagnosing hole cleaning problems.

Chapter 8: Solids Control Equipment


CHAPTER 8: SOLIDS CONTROL EQUIPMENT

Solids control equipment is utilized on the rig to remove undesirable solids from the drilling fluid system. There are many types of solids control equipment, but main types of solids control equipment, in order of flow from the bell nipple, are shale shakers, hydrocyclones and centrifuges. Additional components that can be added to the process flow, such as flocculation systems, will enhance solids removal efficiency (SRE) and in turn, improve the quality of the drilling fluid.

The overall goal of solids control at the rig is to remove drilled solids from the mud system as these solids, at high concentrations, can degrade drilling performance. In order to maintain the desired range of drilled solids in a mud system, solids control equipment and/or dilution are required.

SRE directly impacts dilution rates, which can have a detrimental effect on overall fluid and fluid related cost; not to mention potential non-productive time (NPT). The lower the overall SRE, the higher the required dilution rate will be to maintain drilled solids in the desired range. When dilution fluid, either water or non-aqueous fluid (NAF), is added to the system, three costs are incurred simultaneously:

Dilution cost

Fluid additive cost

Disposal cost

Economic savings attributed to improved penetration rates and reduced NPT, although valuable, usually are not considered to be the only justification for utilizing improved solids control equipment. In many cases, the economic advantages due to reduced dilution and



disposal costs are more than enough to justify expenditures for additional equipment.

Dilution, although effective, can be a very expensive method to control solids. The following formula can be used to calculate dilution requirements to maintain a known percentage of drill solids in the mud system:

dsd ds

ds

VV V

T

Where Vd = Dilution volume

Vds= Volume of drilled solids to be diluted

Tds = Target drilled solids (volume fraction)

The formation being drilled and the drilling fluid used often dictate the type of solids control equipment needed to remove drilled solids from the fluid, in turn, maximizing SRE. There are two types of solids present in an active mud system, drilled solids and solids incorporated into drilling fluid additives. These solids, as related to solids control, can be broken down into four categories. The major categories of solids are outlined in Table 8-1, along with corresponding particle sizes in microns (µm), types of particles and the solids control equipment needed to remove them from the system.



Category Size (µm)

Types of Particles Solids Control Equipment

Colloidal <2 Bentonite, clays, ultra-fine drilled solids

N/A

Silt 2 – 74 Barite, silt, fine drilled solids

Desilter, Centrifuge

Sand 74 – 2,000

Sand, drilled solids Shale Shaker, Desander

Gravel >2,000 Drilled solids, gravel, cobble

Shale Shaker

Table 8-1: Solids classifications

Each category of solids control equipment is capable of removing solids in a particular particle size range, as indicated in Table 8-2. Correct configuration and application of the solids removal equipment could significantly reduce drilling fluid cost, as well as the overall drilling cost.



Sh

ake

r M

esh

R

eq

uir

ed

no

n/a

n/a

n/a

n/a

20

0

140

100

50

35

18

10

Sh

ale

S

ha

ker

no

no

no

no

no

yes

yes

yes

yes

yes

yes

yes

Hy

dro

cycl

on

e 1

2”

con

e (

De

san

de

r)

no

no

no

no

yes

yes

yes

yes

yes

yes

n/a

n/a

Hy

dro

cycl

on

e 6

” co

ne

(D

esa

nd

er)

no

no

no

yes

yes

yes

yes

yes

yes

yes

n/a

n/a

Hy

dro

cycl

on

e

4”

con

e (

De

silt

er)

no

no

yes

yes

yes

yes

yes

yes

yes

yes

n/a

n/a

Ce

ntr

ifu

ge

no

yes

yes

yes

yes

n/a

n/a

n/a

n/a

n/a

n/a

n/a

Pa

rtic

le

Dia

me

ter

(µm

)

<2

>5

15

20

40

74

105

149

27

5

50

0

100

0 (

1mm

)

20

00

Pa

rtic

le

Ty

pe

Co

lloid

al

Silt

San

d

Gra

vel

Tab

le 8

-2: E

quip

men

t pa

rtic

le s

ize

rang

e re

mov

al c

apab

ility



here are numerous factors that affect the capability of solids control equipment to efficiently remove particles in a particular size range. The most common are:

Capacity and feed rate

Drilling fluid type (inhibition, viscosity, base fluid type)

Equipment performance

As previously shown, the main components of solids control equipment are primary/secondary shakers, mud cleaners, desilters, desanders and centrifuges (Figure 8-1).

Figure 8-1: Process flow of solids control equipment (Courtesy of Derrick Equipment)

Solids Removal Efficiency

SRE depends on a number of factors such as equipment type and equipment operating parameters. For instance,



shale shaker efficiency is related to g-force, frequency, stroke length, retention time, drilling fluid properties, cuttings characteristics.

In general, the more inhibitive the drilling fluid used, the higher the SRE that can be obtained. The practical limit to the SRE when drilling with water base mud is approximately 85%. It is possible to have an SRE of 90% or higher when using NAF.

The optimum SRE (SREoptimum) can be calculated by using the following formula:

100 1

1

Where Sc is the solids concentration (volume fraction) in the discarded stream from the solids control equipment.

Shale Shaker

The shale shaker can be regarded as the “first line of defense” in the solids removal system. It uses a simple, reliable method of removing large amounts of coarse drilled solids from the circulating system. When operational and correctly maintained, a shale shaker can provide consistent removal of solids from the fluid system.

An adequate number of shale shakers should be installed to process the entire circulating rate, with the goal of removing as many drilled solids as is economically feasible. Since the shale shaker is regarded as the most important piece of solids control equipment, the most efficient shale shakers and screens should be selected, especially when the goal is to achieve optimum economic performance of the solids control system. Figure 8-2 depicts flow rate capacity versus mud weight ranges of 10 to 18 lb/gal for various API screen mesh sizes of a



generic shaker. It should be noted that shaker performance may improve or reduce the flow rate.

Figure 8-2: Flow rate capacity versus mud weight for various API screen numbers

The flow across the shaker screen should be such that mud is covering at least 75% of the entire shaker. For example, a four-panel shaker should have mud across at least three screens. Also, when using more than one shaker, it is important to ensure equal flow distribution to each shaker.

Shale shaker performance is a function of the following:

Vibration pattern and dynamics

Deck size and configuration

Shaker screen characteristics

Mud rheology

Solids loading rate



There are four basic motions available for oilfield shakers:

1. Circular motion – a uniform round motion (Figure 8-3)

Figure 8-3: Circular motion

2. Elliptical motion– a non-uniform oblong motion (Figure 8-4)

Figure 8-4: Elliptical motion



3. Balanced elliptical motion – a uniform oblong motion (Figure 8-5)

Figure 8-5: Balanced elliptical motion

4. Linear motion – a balanced elliptical motion with aspect ratio of infinity to one (Figure 8-6)

Figure 8-6: Linear motion

Of the four types, linear motion shakers are best suited for standard oilfield use due to the ease of attaining a higher g-force (6 to 8). Balanced elliptical shakers typically have a lower g-force (up to 20% lower in balanced elliptical motion) than that of linear motion shakers.



The most important variable associated with shale shakers is screen selection, which will define the flow capacity and solids removal efficiency. Historically, screen sizes and labeling have been inconsistent and sometimes misleading across manufacturers and vendors. The American Petroleum Institute (API) has established API RP 13C, Recommended Practice on Drilling Fluids Processing Systems Evaluation, Testing and Labeling Procedure for Shale Shaker Screens to address this issue. It provides guidelines for screen sizing and a uniform, accurate and easy screen labeling procedure.

Shaker troubleshooting can be problematic at times as the source of the problem could be from adjustments to the drilling fluid and/or the mechanics of the shaker. Referring to shaker mechanics, it is important to check the sand content, especially if the problem occurs with only one shaker. As shakers can successfully remove >74 µm particles, only “trace” sand should be measured. If there is more than a “trace” amount, the problem can be caused by one or more of the following:

Shaker screen(s) worn – This can be identified with increased amounts of sand over time when verified by the sand content test. With this problem, there may or may not be noticeable wearing at one or more shaker screens. If this is true, repair or replace the worn screen(s).

Shaker screen(s) undersized – As the average particle size of the solids the in drilling fluid decreases over circulation time, the particles tend to remain in the mud system if not initially screened out. When this occurs, the rheology will increase and can be verified by plastic viscosity (PV) values increasing over time. “Screening up” by increasing the API screen number can



alleviate this problem. This API number is related to the corresponding ASTM mesh sieve.

A troubleshooting guide (Table 8-3) also identifies other mechanical problems associated with shakers:

Problem/ Observation

Possible Cause Solution

Cuttings not conveying to the discharge end in a uniform manner

Incorrectly installed or tensioned screens

Install screens according to manufacturers. Maintain tensioning system as per manufacturer recommendations.

Poor cuttings conveyance in one area of a screen, often whirl pooling

Missing or worn screen support such as channel cover, cross and side supports

Replace missing or worn channel covers as needed. Replace cross and side supports as needed.

Cuttings tend to move towards one side of the shaker

Unlevel installation or worn float mounts/isolation springs. Improper replacement part(s)

Replace worn, degraded, weakened part with correct manufacturers recommended part(s)

Table 8-3: Shaker troubleshooting guide

If all shakers suddenly become problematic, the source of the problem moves from shaker mechanics to the drilling fluid, with the following possible causes:



Water-wet solids – NAF cuttings adhere to the screens and blinding occurs. A high temperature high pressure (HTHP) fluid loss test can identify if water is in the filtrate. If so, the drilling fluid chemistry should be addressed or “screen down” using a lower API Screen number.

Lost circulation material (LCM) blinding – Increased mud losses off the shaker discharge when utilizing fine LCM. If the LCM is necessary, “screen down” so the screens do not plug. Another alternative is to choose a LCM that has a specific gravity (SG) lower than that of the base fluid, use coarse screens on the shaker and add a mud cleaner with fine screens (API 170 to 200 mesh). The LCM will be removed for reuse by the hydrocyclone and the drilling fluid can then be screened by the shaker of the mud cleaner.

WBM polymer screen coating – WBM’s with long chain polymers have a tendency to coat fine mesh three layer shaker screens. Use coarser screens (screen down) or change out for two layer screens. These are available from the original equipment manufacturer (OEM) as well as non OEM. However, two-layer screens have a reduced life over multi-layer screens.

Hydrocyclones

Technology improvements with shaker screens and centrifuges have somewhat lessened the need for hydrocyclones at the rigsite. However, there are still areas where hydrocyclones are very important. Hydrocyclones convert fluid pressure into velocity and centrifugal forces, allowing up to 300 g-forces internally.



Oilfield hydrocyclone sizes are typically available from 4 to 12 inches diameter, where the smaller the diameter, the finer the particle size that can be removed. Hydrocyclones are primarily utilized as desilters and desanders. Desilters (4” diameter) can be mounted over the top of a shale shaker (commonly referred to as a mud cleaner) and are capable of a +20 µm separation. Desanders (10” to 12” diameter) on the other hand, are typically used in a stand-alone set up and are capable of a separation of up to approximately +74 µm.

In unweighted water base muds, hydrocyclones are a cost-effective method of removing fine solids that cannot be removed by shale shakers outfitted with API 100 mesh or coarser screens. As hydrocyclones will remove silt sized particles (e.g. barite), it is not advisable to utilize with fluid weights above 12 lb/gal for desanders/desilters without a mud cleaner. The devices will strip out valuable weighting agents as well as discard large quantities of whole mud. This may not be economical unless there is a desire to reduce the mud weight.

Expected feed rates will vary by vendor, but typically range from 50 to 75 gpm per cone for desilters, to approximately 500 gpm per cone for desanders. Most hydrocyclone manufacturers specify 75 feet of head pressure, which equates to 3.9 times the mud weight as derived in the following formula:

p = 0.434 (feet of head) (fluid S.G.)

where p is the feed line (head) pressure in psig

Additionally, hydrocyclones should be sized to process ≥120% of the maximum expected mud flow rate (Figure 8-7).



Figure 8-7: Hydrocyclone setup

For a 10 lb/gal mud, the feed line pressure gauge should read 39 psig for 75 feet of head. If the pressure is not obtained, there are several adjustments that can be made in order to be more closely matched with the manufacturer’s recommended head pressure:

Adjust plumbing to remove unnecessary elbows, tees and valves

Check centrifugal pump/impeller for system compatibility and wear

Remove cones until correct head pressure is achieved (be sure to plug opening)

Check centrifugal pump/impeller for proper impeller sizing

The solid/liquid portion spiraling downward and out of the cone (underflow) should have a spray or umbrella shaped discharge indicating the cone is not loaded. The inside stream moving up at a high velocity, toward the overflow, will suck air with the stream in the vortex portion of the hydrocyclone, causing a slight vacuum to occur at the center of the cone.



Rope discharge may occur when the solids concentration of the fluid being processed is higher than what the hydrocyclone can process, which can lead to plugging. Corrective action for rope discharge consists of opening up the underflow and ensuring that the discharge opening is free and clear of obstructions. Reoccurring issues with rope discharge are indicative that the solids loading to the hydrocyclone needs to be reduced, by means of increasing the number of cones in the desilter bank and/or by using finer mesh screens on the shale shaker.

Centrifuges

An oilfield decanting centrifuge is a separation device which utilizes g-force to enhance the settling of particles from liquid and is capable of removing all solids larger than 10µm, based on the settling principle of Stokes Law. Unlike a shale shaker, centrifuge separation is based primarily on density, not particle size. However, the centrifuge, like all other pieces of solids control equipment, is limited to a certain feed rate as well as the percent of solids discharge allowed in the effluent before plugging begins. Therefore, placing equipment upstream of the centrifuge to remove larger solids will allow the centrifuge to remove a larger percentage of smaller solids closer to the 10µm range.

A centrifuge (Figure 8-8) separates solids from liquid fed into a bowl; rotating at a high speed by imparting high centrifugal forces (1,000 g-forces minimum recommended) on the solids laden mud system.



Figure 8-8: Centrifuge cutout diagram

The feed stream is pumped into the vertical center of the conveyor via an inlet feed tube. The mud exits the feed tube and enters an acceleration chamber housed inside the conveyor, then exits the chamber through feed ports and enters the bowl area. At this point, the slurry is exposed to high g-forces created by the rotation of the bowl, where the high g-forces cause sedimentation of the feed stream solids. The rotating conveyor has flights similar to the threads of an auger where the solids are transported up the conical section of the bowl and out of the liquid. 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 the shaft. The 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 epicentric ports at the opposite end.

There are three major categories for centrifuges and they are identified by the height of the bowl; small (<14” diameter), medium (15 – 16” diameter) and large (>16” diameter) bowls. A centrifuge is capable of processing only a fraction of the total mud system volume. In general, the larger the centrifuge bowl, the more



throughput volume can be processed. The flow that each centrifuge can process varies with solids loading/mud weight, as well as the target percent solids removal desired. The average volume throughput capacity for a small bowl centrifuge is 10 to 90 gpm, a medium bowl is 30 to 140 gpm and a large bowl is 60 to 180 gpm when processing fluid densities from 16.0 lb/gal down to 8.34 lb/gal, respectively. Fluid densities greater than 16.0 lb/gal contain too high a concentration of insoluble solids for the centrifuge to process. In time, the solids drop out of the mud at a much faster rate than the scroll can displace; leading to plugging or fusing of the scroll to the bowl.

Centrifuges are utilized in various configurations, namely as single or dual stage. For centrifugation to be successful, it is advisable to utilize a minimum of API 140 mesh screens upstream at the shaker. In single stage, the centrifuge processes a portion of mud and is used to remove solids that pass through the shaker and/or hydrocyclone.

Single stage centrifugation with weighted WBM’s will typically involve a single centrifuge where the solids laden effluent is discarded and replaced with clean fluid comingled with the solids collected in the underflow.

Dual stage, or barite recovery mode, utilizes two centrifuges in series. The first centrifuge removes barite at lower g-forces (600 to 900) for a fluid with regular rheological properties and the second centrifuge removes low gravity drill solids.

Over time, centrifuges have evolved to be more “oilfield proof”, allowing them to be able to be transported and improve separation efficiency. However, problems still arise where the centrifuge can arrive on location or be utilized for a long period of time which reduces the viability and centrifuge life. Some common problems are, but not limited to, the following:



Bearing failure

Discharge plugging/bypassing

Wear of wetted parts (feed tube, solid discharge inserts, flight strips)

Excess vibration

Scroll flight wear

Bowl/scroll fusion (pack-off)

Rolling plug

Wear of wetted parts

Through routine maintenance and running within manufacturer specified guidelines, the above listed issues can be mitigated. The centrifuge operates with less mechanical error when shutdown and startup are limited (reducing on/off times), such as with 6 to 8 hours of daily run time versus on/off per hour. The bearings should be lubricated according to manufacturer specifications to eliminate overheating that could lead to bearing failure (do not over lubricate), as well as be protected from vibration or movement when in transport (mainly with land applications).

Other potential problems can occur with incorrect feed rates, excess solids and incorrect differential speed. These issues can lead to numerous problems, ultimately leading to centrifuge failure. Check with the manufacturer to ensure proper maintenance and operational guidelines and specifications.

Chapter 9: Material Transportation and Handling


CHAPTER 9: MATERIAL TRANSPORTATION AND HANDLING

The need to transport and handle drilling fluids or fluid products is common to all drilling operations. Materials can be transported and handled by a number of different methods. It is important to follow local regulations and guidelines for material transportation and handling of drilling fluids and products. The proper handling of materials can increase efficiencies, reduce waste (both packaging and product), and ensure the safety of personnel who will be handling the materials.

Depending on the complexity of the operation and capabilities of the rig, handling methods will vary by project. Whether used for drilling, completion, cementing, etc., materials may be available in bulk, drummed, palletized or in big bags, i.e. 2,000 lb bulk sacks. Each method of packaging will have advantages or disadvantages, depending on the specific application and local regulations. A thorough evaluation of the operational needs, rig capabilities and logistics should be done prior to determining the most appropriate packaging in which to receive products.

Palletized Material

Most drilling fluid products are transported to the wellsite on stacked and shrink wrapped pallets. This type of method for material handling is the most common for small or moderate quantities. However, there are several HES concerns associated with palletized material, including:

Manual handling – Materials are supplied in sacks of various weights and sizes, typically depending



on the bulk density and their usage requirements. Because of their size and weight, some of these materials are bulky and awkward to move by hand. This could obviously result in injury to the handler if proper safety precautions are not followed; although the manual handling of supplied sacks can be more manageable when compared to drummed materials.

Material breakage & waste – Unprotected palletized material will often contain broken sacks, especially on the corners where the material may come into contact with material on adjacent pallets during handling.

Packaging waste – Each sack of material contains packaging that must be disposed of.

Environmental liability – Drummed material, in particular, presents a huge potential for environmental liability. Years after disposal in landfills, residual materials left in drums could subject Chevron to significant financial liability.

Drummed Materials

When a drilling rig does not have bulk liquid handling facilities, it is common for the fluid additives to be supplied in drums. Drums will come in various sizes, depending on the type of material being transported. Drum composition is usually steel, but molded plastic is sometimes used, especially if the material is corrosive. The disadvantages of drum use outweigh the advantages.

Disadvantages include:

Manual handling – Drums should not be manually handled. Special handling precautions are



necessary and require alternate methods to add the liquid to the system. Equipment that may be necessary includes forklifts, drum slings, drum pumps, overhead cranes, etc. Because of their size and weight, drummed materials are more difficult and awkward to move by hand than sacked materials. This could result in injury to the handler if proper safety precautions are not followed.

Drum Disposal – Typically, drums must be washed out, rinsed, and crushed prior to disposal. This cost can run close to $50 per drum, including the disposal of the wash fluid. Drum disposal should meet local regulations and Chevron best practices.

Environmental – The future economic liabilities associated with landfills and disposal sites could be very costly to Chevron. It is a well known practice that when it comes to clean-up and reclamation of these sites, the waste generator with the largest financial resources will be held responsible and will incur the largest expense for the clean-up.

Regardless of how drummed material is handled, the operation should be conducted safely and within the Chevron “Tenets of Operation”.

Bulk Liquid Materials

The use of bulk liquid additives is becoming more prevalent. New build rigs are making provisions in the design stage to be able to efficiently handle liquid bulk products. Existing rigs are undergoing modifications or placing tanks on the top deck to allow the use of bulk



additives. There are a number of advantages to using bulk materials, including:

Efficient Chemical Use – The use of bulk material eliminates left over partial drums. The expense of partial drums can be three-fold; the material has been purchased, it may then need to be disposed of and the drum will separately need disposal. The bottom line is, “you only pay for the material that is used”.

Handling – The handling of bulk materials is much easier and safer than the handling of drums. The number of crane lifts associated with the use of bulk materials should be reduced over that of drums.

Packaging Waste – There is no packaging waste associated with using bulk liquid material.

Environmental – The potential environmental liability associated with the use of drums is eliminated.

There are a number of different vendors with a variety of liquid bulk handling setups. Some use a prefabricated manifold (Figure 9-1) that is designed into the rig when built, while others utilize a portable manifold (Figure 9-2). The type of manifold used will be dependent on the needs and capabilities of the drilling rig.



Figure 9-1: “Prefabricated” manifold bulk liquid system (Courtesy of Vortex Ventures)

Figure 9-2: “Portable” manifold bulk liquid system (Courtesy of R & D Technologies)



Regardless of the type of manifold being used, the transport of material to the rig is relatively standard. Materials will be shipped to the rig in tote tanks (Figure 9-3), sometimes referred to as intermediate bulk containers (IBC’s). Typical materials transported and used in tote tanks are emulsifiers for non-aqueous fluids (NAF’s) and spotting fluids for stuck pipe.

Figure 9-3: Tote tank

By definition, a tote tank or IBC is a container used for the transport and storage of fluids and bulk materials. The construction of the IBC container and the materials used are chosen depending on the application, i.e. there are various types available in the market:

Foldable (collapsible) Plastic composite Polycage Steel Stainless steel



Tote tanks range in size but are generally between 24 and 52 inches (610 mm and 1320 mm) in height. The length and width of a tote tank are usually 42 inches and 48 inches (1067 mm and 1219 mm), respectively, but will be dependent on the specific country's pallet dimension standard. Depending upon the size, tote tank capacity can be anywhere from 110 gallons to 550 gallons. Common dimensions and capacities are listed Table 9-1.

Tote tanks should have pallet-like bases so that they can be easily moved with forklifts and should be designed to stack vertically.

Table 9-1: Common tote tank capacities and dimensions

Size Capacity Gallons/Inch

42” x 48” wide

24” high 110 gallons 8.57 gallons/inch

42” x 48” wide


42” x 48” wide


42” x 43” wide


42” x 48” wide


42” x 48” wide




Size Capacity Gallons/Inch

42” x 53” wide


42” x 48” wide


Table 9-1: Common tote tank capacities and dimensions (continued)

It is recommended that tote tanks used for offshore applications should meet minimum requirements such as those outlined for offshore Gulf of Mexico (GoM) use unless more stringent requirements are in place.

Bulk Bags

Some rigs have active fluid systems of 15,000 to 25,000 barrels, which require a large amount of chemical additions on a daily basis. Fluid systems of this size cannot be maintained through conventional methods, such as utilization of 50 and 100 lb sacks. Therefore, bulk bag systems are beneficial when the use of large quantities of a material, in a relatively short period of time, is anticipated. Materials such as salt for completion fluids, bentonite when drilling surface hole, and barite for major weight-ups are a few examples of when bulk bags would be warranted. Bulk bags, depending upon the bulk density of the material, can hold anywhere from 1400 lbs (lime) to 4000 lbs (barite) of product.

Common to all bulk bag systems is a support structure that will hold a fully loaded bulk bag and a hopper system to deliver material (Figure 9-4). Some systems made for disposable bags have a spear to puncture the



bag and start the flow of material. Other systems have an automated valve system which allows material to be metered into the system.

Figure 9-4: Bulk bag handling system (Courtesy of Vortex Ventures)

Bulk bag systems have a number of advantages:

Safety – The potential for injury is reduced since the handling of 50-100 lb sacks is eliminated. There is minimal dust and chemical exposure to personnel.



Handling – The handling of dry bulk materials is much easier as the number of crane lifts associated with the use of bulk materials is reduced. Materials are able to be mixed faster with less manpower required to perform the work.

Packaging Waste – Packaging waste associated with using dry bulk materials is reduced or even eliminated. Most bulk bags are disposable, although reusable bags are available. Bulk bag use can eliminate the need to dispose of 40 to 80 paper sacks and the associated shrink wraps and pallets.

Storage – Products packaged in bulk bags have fewer tendencies to leak or become damaged when being transported or stored.

Some of the disadvantages are:

Depending on the bulk bag system used, partially used bags may be difficult to handle.

Due to the size and handling requirements of bulk bag systems (i.e. forklifts/cranes), they are typically located on an upper deck. Often times, due to limited deck space and load limitations, bulk bag systems cannot be used.

Bulk bag systems have a number of safety issues that should be recognized and addressed:

Sunlight and Heat - Bulk bags will rapidly deteriorate with exposure to ultraviolet (UV) light. When exposed to sunlight for several months (~3), the bulk bag material will partially degrade into a powder. Best practices dictate



that they are stored in the shade or covered with a tarp. Additionally, the bag should be dated when loaded. When the 3-month deadline is approaching, the original bag should be picked up and lowered into a new bag. The straps should be cut off of the old bag and the current date sprayed on the new bag, starting the next 3-month life span.

Lifting Strap Design - Some bulk bags have lifting loops/straps sewn into the top of the bag. This bag design is not the most desirable to employ. A better design is one where the straps go around and support the base of the bag.

Weight Lifts Safety Factors - Typical lift safety factors are in the range of 5:1 to 6:1. It should be noted that these safety factors will be reduced under the following conditions:

o Extended exposure to ultraviolet light

o Normal wear due to handling

o Excessive lifts – Move bags on pallets when possible

Chapter 10: Common Drilling Fluid-Related Problems


CHAPTER 10: COMMON DRILLING FLUID-RELATED PROBLEMS

During drilling operations, a number of drilling fluid-related issues can arise. Some of these are specific to the type of system being employed and others can occur with any drilling mud. This chapter addresses some of the most common and important issues, how they impact operations, and how to prevent and mitigate them. Lost circulation and stuck pipe account for a large portion of fluids-related non-productive time (NPT), and through better understanding of their mechanisms there is an opportunity to improve drilling efficiency and reduce costs. Barite sag is a topic of concern for weighted fluids and requires proper planning to prevent. Typical indications that allow for the detection and treatment of barite sag will also be discussed. Wellbore breathing is an often discussed, but not fully understood phenomenon. Failure to distinguish it from other drilling problems can lead to lost time. While not every fluids related problem is covered in this section, this is an attempt to cover four of the biggest sources of trouble.

Lost Circulation

Lost circulation, or lost returns, is the partial or total loss of circulating fluid from the wellbore to the formation. It is the loss of whole fluid, not simply filtrate, to the formation. Losses can result from either natural or induced causes and can range from a few barrels per hour to hundreds of barrels within minutes. Lost circulation is one of drilling’s biggest expenses in terms of rig time and safety. Uncontrolled lost circulation can result in a dangerous pressure control situation and loss of the well. Additionally, losses into a reservoir formation



can damage productivity by displacing native fluids, changing wettability and blocking pore throats with drilled solids.

The frequency and severity of natural and induced losses vary around the world and are dependent on both the geology and the drilling conditions. As the industry continues to develop existing fields, more drilling takes place through zones depleted by prior production, making losses more frequent and problematic.

Lost circulation can be broadly classified into two major categories based on the cause of the loss:

Natural losses occur in formations with natural permeability, usually voids or fractures.

Induced losses occur in an induced fracture, caused when hydraulic forces within the wellbore exceed the formation strength.

Natural Losses

Natural losses can occur within three formation types:

Losses into high matrix permeability formations (gravels and coarse sands)

Formations with conductive natural fractures or faults

Vugular or cavernous formations

Matrix Permeability

High permeability formations are encountered as a matter of course in drilling. Formations with matrix permeability which result in lost circulation include mainly shallow coarse sands, gravels and micro-fractured carbonates.



The key to solving losses to matrix permeability is to first bridge the largest openings in the formation with rigid granular LCM materials, and second, seal the bridged opening with deformable fibrous and flaked LCM materials. Effective bridging agents must be sized to match the matrix pore openings.

Natural Fractures

Naturally occurring fractures and faults can be found in any type of formation. They are commonly found in tectonically disturbed areas surrounding salt domes and along mountain fronts. In such areas, it is generally accepted that lost circulation is a matter of fact and preparations to handle such problems are made a standard part of drilling plans. Natural fractures can be widened by excessive hydraulic pressure. They then behave as induced fractures.

Vugular/Cavernous Formations

Vugular or cavernous structures form as portions of the formation and are dissolved or decomposed over geologic time. The voids generally form in dolomite or limestone formations and can range in size from small “worm-hole” networks to extremely large caverns. Poorly compacted, buried reefs may also contain large conductive voids. Lost circulation which occurs in a cavernous formation can be the most difficult type to overcome. The size of the voids and the total volume can make it difficult to bridge the opening or fill the voids with any lost circulation material pill or cement plug. In addition, these voids often exist filled with water or hydrocarbons which can interfere with certain remedial techniques.



Losses to caverns are generally very large and are frequently preceded by “drilling breaks” as the bit drops through the void. Losses to caverns require either filling the entire void or plugging the cavern near the wellbore, a task that can range from very difficult to nearly impossible. In many cases, drilling through a cavern will require either tolerating the loss or using an alternative technique, such as air drilling or mud-cap drilling.

Induced Losses

Induced losses result from the creation and extension of fractures by the drilling operation. Induced fractures result when the equivalent circulating density (ECD) of the drilling fluid exceeds the fracture gradient. This causes the formation to part, opening a fracture. Unlike natural losses which first occur at the bit, induced fractures occur in the weakest exposed formation. Induced fractures happen when the ECD is increased, while weighting up, tripping, drilling too fast, or as the result of a mud ring or other situation causing a temporary pressure surge that breaks down a weak formation. The location of the fracture is often closer to the casing shoe than the hole bottom. This attribute of induced fractures complicates the identification of the loss zone and the placement of materials designed to combat the problem.

Because fracture gradient changes with rock type, some formations are more sensitive to induced fractures than others. Depending upon depth, the fractures created will either be horizontal or vertical. If the depth is 2500 feet or less, horizontal fractures are usually produced. At depths over 3500 feet, fractures are usually vertical. Because horizontal fractures require lifting the entire overburden, they are typically limited to shallow depths. Vertical fractures occur without lifting the overburden,



and they can be created at much lower pressures over the fracture pressure.

Depending upon the situation, natural and induced fractures are easily extended and difficult to seal without reducing the hydrostatic pressure. The propagation pressure is generally much less than the pressure that would be required to initiate the fracture. Consequently, fracture losses, once initiated, are difficult to control.

Induced fracturing is probably the most troublesome because it can occur in almost any formation type. It is more difficult to control or prevent fluid losses to induced fractures because, as the fracture extends or reopens, any seal that may have been formed is destroyed.

Fracture Initiation

Induced fractures are created by excessive pressure in the annulus and occur most often when weighting-up, tripping, drilling too fast or killing a kick. High fluid weight, excessive ROP, surge pressures, and annular restrictions contribute to this problem. The drilling fluid density should not be greater than that required to control formation pressures. The ROP should be controlled at a rate which keeps the ECD below the fracture pressure by a safe level.

A good practice to follow, prior to making a bit trip, is to circulate bottoms-up prior to stopping circulation. Particularly after fast drilling, the fluid will be loaded with cuttings which increase fluid density, rheological properties, and static gellation, thus, increasing the pressure required to break circulation, as well as increasing the potential for lost circulation when tripping into the hole. The use of successive, thin turbulent and viscous sweeps improves the cuttings removal



efficiency, particularly in deviated and horizontal wellbores.

Excessive pipe running speeds should be avoided. Maximum safe pipe running speeds should be established. Frequent circulation breaks when going into the hole can reduce circulation initiation pressure, and the drillpipe should be rotated just prior to breaking circulation. This movement will reduce fluid gel strength, thus reducing the pressure required to break circulation. The last few joints of drillpipe should be circulated down to wash any accumulated cuttings from the hole bottom.

Fracture Propagation

Propagation occurs when the high pressure conditions that originally caused the fracture to occur are not corrected. Every effort should be made to reduce downhole hydraulic pressure and seal the fracture with proper treatment. While squeezes may aggravate the situation by forcing the fracture to open further, they deposit LCM within the fracture. Once the squeeze pressure is relaxed, the fracture can close and seal on the LCM.

Once a fracture has been sealed, it should be protected from being reopened by keeping the hydrostatic pressure as low as is safely possible. If the fracture is reopened, the seal is broken and must be re-established to prevent further fluid losses.

Preventing Drilling Induced Fractures

Both fracture initiation and propagation can be minimized by reducing the pressure that the formation is exposed to from the drilling fluid in the annulus. This can be done by:

Reducing mud weight



Reducing annular pressure losses by thinning the drilling fluid or reducing the pump rate

Improving hole cleaning

Controlling ROP

Reducing annular restrictions and balling

However, no action of this type should be undertaken without considering its effect on other functions. For example, if the cause of the surge is poor hole cleaning, thinning the drilling fluid may not be the best solution to implement.

Severity of Loss

The severity of the loss can be an important indicator of not only the type of treatment required, but also the size of the treatment. Numerous lost circulation remedies have failed simply because the treatment size did not match the severity of the loss. The industry has a convention that quantifies losses according to severity, ranked by the loss rate while circulating. Table 10-1 lists a classification according to loss rate.

Note: Non-aqueous fluids (NAF’s) are more expensive and their lost circulation problems are more difficult to solve, therefore, lower loss rates are used.

Volume Severity Formation Type

< 25 WBM (< 10 NAF) Seepage Porous, permeable sands

25 to 100 WBM (10 to 30 NAF)

Partial Coarse sands and gravels

> 100 WBM (> 30 NAF) Severe Cavernous or vugular formations

Table 10-1: Loss rate classification (units are barrels per hour)



Treatment of Lost Circulation: Planning and Preparation

Proper planning is important to the success of resolving lost circulation problems expediently. Not only does a variety and sufficient quantity of specialty products need to be in the rig inventory, but local stock points should be aware of their required inventory. A minimum rig inventory of products for use in combating lost circulation should be established at the outset. Logistics should be considered in each case.

Rig crews need to be trained to respond to losses correctly. Otherwise, losses of sometimes expensive drilling fluid can become excessive. A list of instructions should be posted such that each crew member is aware of their individual responsibility. The crews should be well versed in the type of equipment and any special configurations that may be necessary to address the situation. Spud meetings should be held to address the responsibility of each member of the crew, plus any fluid loggers and fluid engineers that will be assigned to the well.

Any special equipment requirements such as tanks, lines, pumps, etc. should be determined. Storage facilities for premixed slurries (pills or squeezes) should be available to minimize rig time losses. Hole surveying equipment (e.g. temperature recording, spinner survey) should be available to locate the loss zone if necessary.

It is very important to consider the bit nozzle sizes and downhole tools when choosing LCM types and concentrations. Most measurement while drilling (MWD) and logging while drilling (LWD) tools are rated for a maximum LCM size and at times by concentration. Failure to consider these bottlenecks may result in damaged tools, plugged bit nozzles and the necessity to trip out of the hole.



Guidelines for Restoring Circulation

1. Determine the loss rate and record the characteristics of the loss (Is loss associated with an increase in ECD, increase/decrease in ROP, change in formation, crossing a fault? Is it sensitive to ECD or pump rate? Is this the first loss or a reoccurring loss?). Maintain and review a record of previous lost circulation events and treatment effectiveness.

2. Determine the most probable cause or type of loss.

3. Determine the most likely location of the loss zone.

4. Choose a treatment and volume matched to the type and rate of the loss.

5. Apply the treatment adjacent to the loss zone using the best possible spotting technique.

6. Consider tripping to remove small nozzles and using a cementing pump if this will permit a better suited remediation technique.

7. Make sure a blend of sizes and materials is used to totally seal and cure losses once a bridge or plug is established.

8. Keep pipe moving while dealing with lost circulation to prevent differentially stuck pipe.

9. Make sure treatments which must be “cured” are allowed enough time to set up.

10. If circulation is not restored, progress in an orderly manner to the next more potent remedy.

11. If circulation cannot be restored, proceed to an alternative drilling technique which tolerates the lost circulation situation, such as floating mud cap, drilling blind, flow drilling, aerated mud, foam, or air/gas drilling.



The following recommendations are generalized for all geographic locations and should be evaluated for use in a particular area based on the individual situation. The products listed are generally the most effective size and type and can be changed for a similar material depending on what is available.

Seepage Losses (< 25 bbl/hr WBM or <10 bbl/hr NAF)

Note: For seepage losses in the production interval, calcium carbonate is the recommended LCM due to its acid solubility. Rock wool or cellulose fibers, used in conjunction with calcium carbonate, are also acceptable.

1. Reduce mud weight and ECD, if possible.

2. Mix LCM and drill ahead:

Mix 5 to 10 sacks per hour fine LCM for 2+ circulations. Mica is recommended, or it may be substituted with any one of the following; cellulose, nut shells, LCM blend, or calcium carbonate (medium d50 ≅ 35 to 50 microns). If seepage continues, increase LCM particle size and quantity, and use a blend of materials. Mix 10 to 20 sacks per hour of a combination of medium nut shells, fine cellulose and fine mica for 2+ circulations. Should seepage continue, change shaker screens to coarse (such as API 20) mesh and treat entire system with 15 to 25 lb/bbl fine LCM blend – mica, nut shells, and cellulose (or use sacked LCM blend).

Note: If the drilling fluid is unweighted and/or contains little bentonite or fluid loss control additives, mix 4 to 8 sacks per hour of fine calcium carbonate and 1 to 2 sacks per hour bentonite.

3. Spot LCM pill, pull up and wait:



If seepage continues and is unacceptable, spot pill on bottom and pull up and wait two to four hours. Pill should contain 25 to 50 lb/bbl medium LCM blend – mica, nut shells, and cellulose (or use sacked LCM blend); with WBM, use >20 lb/bbl bentonite. Also, spot LCM pills in open hole prior to trips.

4. Use techniques for partial losses:

If seepage continues and is unacceptable, continue with treatments described for partial losses.

Partial Losses (25 to 100 bbl/hr WBM or 10 to 30 bbl/hr NAF)

Natural Loss Zones

1. Reduce mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology (be sure to still provide adequate hole cleaning), trip in hole slower, break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit / BHA, mud rings, cuttings beds, etc.

2. Mix LCM and drill ahead.

3. Change shaker screens to coarse mesh and treat entire system with 15 to 25 lb/bbl fine LCM blend; mica, nut shells, and cellulose (or use sacked LCM blend).

Note: If the drilling fluid is unweighted and/or contains little bentonite or fluid loss control additives, also mix 4 to 8 sacks per hour fine calcium carbonate and 1 to 2 sacks per hour bentonite.




If partial losses continue, spot pill on bottom and pull up and wait 2 to 4 hours. Pill should contain 25 to 50 lb/bbl medium LCM blend (for WBM use >20 lb/bbl bentonite), 10 to 30 lb/bbl medium and coarse nut shells, 5 to 15 lb/bbl fine mica, and 3 to 10 lb/bbl fine cellulose (or use sacked LCM blend). Also, spot LCM pill in open hole prior to trips.

If partial losses continue, spot larger volume viscous pill using larger particle size LCM. Spot on bottom and pull up and wait 2 to 4 hours.

Pill should contain 35 to 70 lb/bbl medium and coarse LCM blend (for WBM, use >20 lb/bbl bentonite), 20 to 40 lb/bbl coarse nut shells, 10 to 20 lb/bbl coarse mica, and 5 to 10 lb/bbl medium cellulose (or use sacked LCM blend). Also, spot LCM pill in open hole prior to trips.

5. Spot settable plug:

Select settable plug based on static loss rate, required plug strength and differential pressure, and formation type as described in Figure 10-1 and in the “Settable Plugs” section later in this chapter. Widely applicable, effective, treatments would be diesel oil, bentonite, and two parts cement (DOB2C) and activated latex for fractures and vugular zones, or crosslinked polymers with LCM (such as X-LINK™, POLY-PLUG™ and BLEN SQUEEZE™ for matrix losses).

6. Use techniques for severe losses. If partial losses keep occurring, continue with treatments as described for severe losses.

Induced Fracture Loss Zones

1. Reduce mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology (be sure to maintain adequate hole cleaning), trip in hole slower,



break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit / BHA, mud rings, cuttings beds, etc.


Spot LCM pill adjacent to the most probable loss zone (weakest shale below the casing shoe) and pull up and wait four to six hours.

Pill should contain 35 to 70 lb/bbl medium and coarse nut shells or coarse and extra-coarse calcium carbonate. Also, spot pills prior to trips.

If partial losses continue, spot a larger volume pill using a blend of LCM. Spot on bottom and pull up and wait 4 to 6 hours.

Pill should contain 35 to 70 lb/bbl medium and coarse LCM blend (for WBM, use >20 lb/bbl bentonite), 20 to 40 lb/bbl medium and coarse nut shells, 10 to 20 lb/bbl coarse mica, and 5 to 10 lb/bbl medium cellulose (or use sacked LCM blend). Also, spot LCM pill in open hole prior to trips.

3. Spot and squeeze a high fluid loss pill: If partial losses continue and are unacceptable, use (DIASEAL MTM), attapulgite, or other high fluid loss pill spotted adjacent to the most probable loss zone (weakest shale below below the casing shoe) and use the hesitation squeeze method to develop and hold pressure.

If high fluid loss squeeze holds for a period of time and then breaks down, use high fluid loss pill, like DIASEAL M, formulated with cement and LCM spotted adjacent to the most probable loss zone (weakest shale below the casing shoe) and use the hesitation squeeze method to develop and hold pressure. When



adding cement to a high fluid loss squeeze, use only ¾ the normal amount of DIASEAL M, and use 1 to 1.4 sacks cement and 20 lb/bbl of conventional LCM like medium nut shells. For NAF systems, use oil or synthetic base DIASEAL M

squeeze first, then try water base DIASEAL M squeeze, being careful to keep it isolated from the main system with spacers.

4. Spot settable plug:

Select settable plug based on static loss rate, required plug strength and differential pressure, and formation type as described in Figure 10-1 and in the “Settable Plugs” section later in this chapter. Widely applicable effective treatments would be in DOB2C, thixotropic cement and activated latex.

5. Use techniques for severe losses: If partial losses continue and are unacceptable, continue with treatments described for severe losses.

Severe Losses (>100 bbl/hr WBM or >30 bbl/hr NAF)

Note: The techniques used for fighting “severe losses” are not effective unless they are placed adjacent to the loss zone. For this reason, it is especially important to correctly evaluate the location of the loss zone.

1. Reduce mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology (be sure to maintain adequate hole cleaning), trip in hole slower and break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit/BHA, mud rings, cuttings beds, etc.




Spot large volume viscous pill using coarse LCM blend. Spot on bottom and pull up and wait 2 to 4 hours.

Pill should contain 35 to 70 lb/bbl medium and coarse LCM blend (for WBM, use >20 lb/bbl bentonite), 20n to 40 lb/bbl COARSE nut shells, 10 to 20 lb/bbl coarse mica, and 5 to 19 lb/bbl medium cellulose (or use sacked LCM blend). Also, spot LCM pill in open hole prior to trips.

3. Spot special lost circulation pill:

Natural Loss Zones

Select settable plug based on static loss rate. Required plug strength and differential pressure, and formation type as described in Figure 10-1 and in the “Settable Plugs” section later in this chapter. Widely applicable effective treatments would be DOB2C and activated latex for fractures and vugs, or crosslinked polymers with LCM (such as X-LINK, ULTRA-SEAL, POLY-PLUG and BLEN SQUEEZE for matrix losses).

Induced Fractures

Spot and squeeze a high fluid loss slurry, such as Diaseal M or attapulgite adjacent to the most likely loss zone (weakest shale below the casing shoe). Use the hesitation squeeze method to develop and hold pressure. Unless the loss occurred in conjunction with a change in ROP, which would identify the loss zone, do not assume the loss zone is on the bottom.

If the high fluid loss pill fails, proceed to a settable plug selected from Figure 10-1 and in the “Settable Plugs” section later in this chapter. Widely applicable effective treatments would be DOB2C, activated latex, and resin-coated sand for induced fractures.



4. Spot “hard” pill:

If severe losses continue, spot hard pill such as DOB2C, magnesium cement, resin-coated sand, latex, silicate/cement, etc.

5. Use alternative drilling technique:

If severe losses continue and are unacceptable, use alternative techniques which tolerate the problem and allow drilling to continue. These alternative techniques include: floating mud cap, drilling blind, aerated mud, foam, mist and air drilling.

6. Set casing or a liner once the loss zone has been completely drilled.

Settable Plugs

The term “settable plugs” is used here to describe lost circulation techniques which use slurries that gel or solidify to seal a loss zone. These types of slurries include crosslinked polymers, cements, gunk pills (like diesel oil and bentonite (DOB), diesel oil, bentonite, and cement (DOBC), sodium silicate-calcium chloride, latex-calcium chloride, resin-BENGUM™, and FLEX PLUG™), coated sand type slurries. Not included in the settable plug category are conventional LCM, barite plugs, and high fluid loss squeezes like DIASEAL M.

The determination of which of these settable plugs should be used is not simple and depends on a number of factors. The most universally applicable settable slurries are the gunk type DOBC and DOB. When spotting gunk type slurry, the pumping ratio should be started at a high ratio of mud-to-gunk for about half of the volume to allow the slurry to invade the formation. It should then be changed to a lower ratio of mud-to-gunk to provide a higher viscosity to stop the loss.



The most important factors when selecting a settable plug are the non-circulating static loss rate and the plug strength required. The following discussion and Figure 10-1 are intended to help determine which of these materials is most applicable to a given situation.

Figure 10-1: Decision chart for selecting a settable plug

Static Loss Rate and Mud Contamination

Many of the settable plug slurries are not effective and will not set up if they are contaminated with mud, especially NAF. For this reason, it is important to evaluate the non-circulating “static loss rate” to determine if mud contamination is probable. With high



static losses, it is important to slow the loss rate when spotting a slurry so that it is not washed away by subsequent losses. Two techniques which work best with high static loss rates are, 1) gunk type slurries placed with variable ratio pumping schedules or 2) a two-slurry spotting technique where one slurry, like silicate or LCM, is intended to slow the losses and the other slurry, like cement, is designed to form an effective long lasting seal.

Slurries that would not work well with high losses while being placed or once placed include crosslinked polymer slurries and conventional cements. Settable slurries which can tolerate a moderate degree of contamination include magnesium based cements, silicate or latex slurries activated by calcium chloride, resin coated sand, and thixotropic cements. Settable slurries which are most effective in situations with high non-circulating static losses are gunk slurries and combinations of silicate or latex followed by cement.

Differential Pressure and Plug Strength

Many of these settable plugs do not develop high strength or withstand high differential pressure. Many of these products may work initially, but will fail if exposed to high differential pressure.

Crosslinked polymer plugs form a soft rubber-like strength and would be good choices for partial and matrix losses, but will fail if exposed to high differential pressures. Gunk type slurries vary in strength from low strength DOB to higher strength BENGUM and FLEX PLUG to very strong DOBC. Silicate pills do not exhibit resistance to differential pressure, while latex pills provide good plug strength. Cements have high plug



strength but are difficult to place, especially when static loss rates are high.

Treatment Preparation

Many lost circulation materials require specialized mixing procedures. Contact the supplier before using the material to obtain the detailed mixing instructions. Follow the instructions precisely. Certain standard procedures apply in almost every lost circulation case.

These include:

1. Identifying the type, location, and severity of the loss.

2. Reviewing the field history to determine what has worked in the past.

3. Selecting the treatment type.

4. Verifying the hole volume, bit nozzle sizes and maximum LCM concentration for downhole equipment.

5. Estimating the volume of material to be pumped.

6. Identifying the need and availability of materials, tanks and other equipment that may be necessary to prepare spacers and LCM pills.

7. Ensuring that any additional equipment required (e.g. pumping units, proportional blenders) is on location and in operating condition.

8. Thoroughly cleaning the mixing tanks to prevent contamination. Purging the mixing equipment and lines of unwanted fluids prior to mixing.

9. Ensuring that the prepared lost circulation pill is isolated from the rest of the drilling fluid system until use.



Upon approaching a known loss zone, a separate mixing pit should be kept available for mixing pills and slugs. If the anticipated loss will be severe, a pit capacity of at least 100 barrels is required. A pre-mixed slurry with up to 80 lb/ bbl LCM should be prepared and kept agitated in the pit.

Treatment Placement

Many treatments will require specialized pumping procedures. The service company should be contacted for detailed instructions on the placement of the material. That being said, certain procedures can apply to almost every situation. These include the following:

1. Review the placement requirements of the treatment.

2. Prepare a plan to implement the placement procedure.

a. Establish how the material will be delivered downhole (i.e. by a pumping unit or with the rig equipment) and rig up.

b. If mixing on the fly is required, establish how that will be done and the rates at which it will occur.

c. Determine if fluid other than that required to keep the hole full will be pumped from the surface into the annulus and rig up as needed. Prepare to squeeze.

3. Once the placement has begun:

a. Continue until the LCM is completely displaced from the drillpipe. Count pump strokes.



b. Monitor surface volumes for changes. Any changes should correlate to the volume of material pumped (as indicated by pump strokes).

c. Monitor pipe and casing pressures to reduce the possibility of induced losses and to verify the displacement of the LCM from the pipe.

4. Squeeze as recommended by the supplier of the product or technical specialist.

5. Pull the drillpipe clear of the calculated top of the pill by at least 100 bbls of hole volume or pull into casing.

6. Wait the required time for the treatment to react and take effect.

7. When the hole stands full, pressure the annulus to 50 psi. If the pressure holds, slowly increase the pressure to the equivalent of 1.0 lb/gal over the mud weight at the loss zone. If the annulus will not hold pressure, try another pill.

8. Maintain the pressure for 2 to 3 hours.

9. If the pressure holds, circulate the hole. If it doesn’t, try another pill with a larger size and higher concentration of LCM.

10. Wash or drill out.

11. Depending upon the LCM composition, the residue will either have to be diverted and removed from the circulating system or incorporated into the drilling fluid.

Reasons for Failure to Cure Lost Circulation

The most common reasons for failing to cure lost circulation are:



1. The location of the loss zone is not correctly identified. Improperly placed corrective measures fail to reach the zone or are diluted below effective levels before the zone is reached. If repeated treatments are not effective and the loss zone is not known definitively, run a survey to determine the loss zone.

2. Methods and techniques are not systematically matched to the type cause and severity of the loss zone.

3. The appropriate remedy is not applied quickly enough.

4. Records describing the details of the loss and the materials and techniques applied are not kept. Each occurrence and “lessons learned” should be documented in a systematic manner. Lost circulation records and detailed reports on an individual well or experiences within an area are invaluable for developing an appropriate remedy.

5. The pill or plug was contaminated by mud, preventing proper setting. Balanced column methods and special plug spotting techniques should be used for all remedies which are adversely affected by mud or formation fluids.

6. The squeeze pressure for the remedy was too high; induced fractures were formed in a weak formation. The imposed surface pressure plus the hydrostatic pressure should not exceed the overburden pressure of ~1.0 psi/ft.

7. Pumping ratios wrong for gunk. For gunk-type slurries, the pumping ratio of mud-to-gunk is critical to obtaining loss zone penetration, then sufficient viscosity to stop the loss so that plug strength can develop.



8. Reluctance to use nonstandard remedies such as soft or hard plugs, high fluid loss squeeze techniques, or to drilling blind through the loss zone and setting pipe.

Lost Circulation Workflows

Appendix 10-1, on page 209, provides guidance for determining the type of loss zone which is essential for determining the most likely location of the loss zone.

Appendix 10-2, on page 210, provides guidance for resolving lost circulation. It is based upon standard industry practices and focuses on “generic” technology. While every lost circulation problem may not be cured by following the chart, it provides a starting point for the immediate treatment of the problem.

Stuck Pipe

Stuck pipe during drilling operations can occur for a variety of reasons such as hole collapse, inadequate hole cleaning, pulling the pipe into an under-gauge hole or by differential sticking. Regardless of the reason, failure to remedy stuck pipe will result in the necessity to part the drillpipe. At this point, fishing can be attempted, but most often, cementing and a sidetrack are necessary. Obviously, stuck pipe should be avoided as much as possible and treated to prevent expensive non-productive time. The primary indication of stuck pipe is the inability to move the drillstring. This is usually associated with the inability to rotate the pipe, and often circulation is difficult or impossible. Simply using the maximum over-pull to try and free the pipe is often counterproductive, resulting in a thoroughly stuck pipe which would require a side track. It is important to use good drilling practices to avoid stuck pipe, and if stuck,



determine the cause and apply the appropriate remedial procedures. While stuck, it is important to try and retain the ability to circulate and keep pipe mobility, as this will allow most of the effective remedial actions to take place.

The most common causes of stuck pipe can be broken down into two general categories: differential sticking and mechanical:

Differential pressure sticking (wall sticking)

Mechanical

o Keyseating

o Wellbore geometry

o Formation-related wellbore instability

o Inadequate hole cleaning

Differential Pressure Sticking

Differential pressure sticking is caused by a higher pressure in the annular fluid than the formation pore space. The result of this imbalance is the tendency for fluid to be drawn into the formation. This flow also pulls drillstring components to the borehole wall. This action can only happen in the presence of a porous and permeable formation. Most drilling fluid formulations include components designed to build a filter cake on the borehole wall. One effect of this is to prevent hydraulic communication between the annular fluid and formation fluid. As a result, a perfect, impermeable filter cake will eliminate the risk of differential stuck pipe. Unfortunately, this is rarely achieved in practice due to factors such as poor filtration control, thick filter cake, mechanical removal of the filter cake through pipe movement, and the time required to form the filter cake after drilling new formation.



Differential pressure sticking is usually indicated when the pipe cannot be rotated or reciprocated but full circulation at normal pressure can be established. Conditions contributing to the likelihood of differential pressure sticking are:

High formation permeability

High positive differential pressure

Hole angle

Poor mud filtration properties

The relative geometry of the pipe and the wellbore

Period of time the drillstring remains immobile

The degree of drill collar stabilization (Configuration of drill collars may also be important.)

Poor particle size distribution in the mud leading to formation of a thick, high permeability filter cake

Stuck pipe from differential sticking, unlike being mechanically stuck, usually cannot be removed by working the pipe free. Differentially stuck pipe will normally require the spotting of specialized fluids across the problem zone to aid in freeing the pipe. If the spotting fluid is not successful, then a washover job may be required to free the pipe.

The force (pull) needed to free a differentially stuck pipe is given by:

∆

where ∆p is the pressure differential between the annular fluid and the pore pressure, A is the contact area between the drillstring and filter cake, and f is the



friction factor of the drillstring-filter cake interface. Preventative and remedial measures center on lowering the values of ∆p, A, and f.

Prevention of Differential Sticking

Drill with mud density as low as practical (reduces ∆p)

Maintain a good, thin compressible filter cake (reduces reduces ∆p, A, and f)

Keep hole as straight as possible (reduces A)

Keep solids content of mud as low as possible (reduces ∆p, A, and f)

Keep static drillstring time to a minimum (reduces f, the static f is higher than the dynamic f)

Use lubricants (reduces f)

Avoid long strings of large drill collars (reduces A)

Use stabilizers or spiral drill collars (reduces A)

Use a NAF (reduces f)

From a drilling fluid design standpoint, two of the most important things to focus on are the formation of a good filter cake and mud weight. The parameter typically used as an indicator of good filter cake quality is a low filtration rate. An often overlooked point regarding low filtration rates is the effect of temperature and pressure. Low API filtrate values do not necessarily mean that filtration rates will be low downhole at increased temperature and pressure. The drilling fluid should be tested routinely at elevated temperatures and pressures to determine filter cake compressibility. The high temperature high pressure (HTHP) fluid loss test is



recommended for this. When drilling through potentially problematic zones, care should be taken to maintain the mud weight at the low end of the acceptable range and by not allowing it to drift higher.

Remedial Measures for Differential Sticking

In spite of all precautions, stuck pipe still occurs. It is often possible to free the stuck pipe through one of the following common methods:

Working/jarring it loose, applying torque and tension to try to work the pipe free

Reduction of hydrostatic pressure by spotting or u-tubing a column of fluid of lower density than the muds in use, such as water or oil

Spotting a pill designed to reduce the friction between the drillstring and filter cake

Determine the stuck point and spot a diesel oil (or other environmentally-friendly oil) pill or surfactant and leave in place to soak for some time (These pills break up the filter cake, reducing the contact area.)

If all else fails, parting the drillstring at a higher depth, setting a cement plug and sidetracking may be necessary. Initially, mineral oil or diesel were primarily used in pill formulations, but over the years a number of more sophisticated (and environmentally-friendly) products have been developed. These pills are most effective when used as quickly as possible after getting stuck. It is often advisable to raise the pill to approximately the same density as the drilling fluid to minimize migration of the pill in the hole. Once free, it is important to build the filter cake back up, minimize exposure time of smooth, large diameter drillstring components (e.g. drill collars, MWD/LWD tools), and keep the mud weight as low as possible to prevent getting stuck again in the same zone. As zones of differential



sticking are sometimes loss zones, the use of LCM treatments should be considered and the problem area should be noted when preparing for cementing.

Mechanically Stuck Pipe

The drillstring can become immobile due to the physical blockage of pipe movement for a number of reasons. This is usually caused by an object or objects blocking the way, such as cuttings, junk or cement, or a geometrical configuration of the well that causes additional side forces and higher overpull.

Keyseating

A keyseat is caused by the drillpipe cutting or wearing a slot into the side of the borehole. The drill collars, being larger than the drillpipe, can become wedged into this slot and then stuck. The drillstring is usually stuck while pulling out of the hole. The drill collars are pulled into the key seat and stuck. Keyseating is exacerbated by:

The number and severity of doglegs

Length of time that the uncased section of the wellbore is left exposed, especially in terms of rotating hours and number of trips

The relative size between the drillpipe tool joints and the drill collars (Very large collars are less likely to pull into a keyseat and become stuck, than are collars that are just slightly larger than the tool joint outside diameter.)

Rapid transition from a formation that is prone to wash out to one that remains close to gauge, or the reverse (The washed out section no longer provides support for the adjacent formation and thereby concentrates the wall stress exerted by the drillpipe.)



Keyseating problems can sometimes be avoided by drilling with a stiff BHA which tends to minimize the chance of severe doglegs, using keyseat wipers properly positioned in the string, and designing a wellpath that minimizes high doglegs in problematic formations.

Wellbore Geometry

When designing a wellpath, it is important to consider the need to move the BHA and other large diameter components through the drilled hole. High bend motors, in-gauge stabilizers and LWD tools, and more extreme well paths can create a situation where the BHA drift diameter is very close to the borehole size. In such cases, even a small amount of cuttings or formation swelling can prevent the BHA from pulling back out through the formation. The addition of reamers can help, but they will increase torque as well as increase cuttings load. If problems are encountered or are expected, carefully watching micro-doglegs in sliding intervals is important. Reaming through these areas can help limit trouble spots. It is important not to just look at the dogleg over the length of a stand, but to consider the micro-doglegs that most reduce drift diameter.

Formation Instability

The shape and diameter of the borehole is not necessarily static over time. Reactive shales, formation breakout, and moving salts are a few examples of mechanisms that can result in a change of the well that may cause stuck pipe. Additionally, formation instability can result in cavings and hole collapse that result in a sizeable amount of cuttings-like material entering the annular fluid. The prevention of formation instability is a separate topic, but generally it is controlled by correct mud weight, mud water salinity, and good drilling



practices. If the instability causes a change in borehole shape, the stuck pipe problems are similar to wellbore geometry. If cavings occur, the situation is analogous to inadequate hole cleaning, as described next.

Cuttings Accumulation

The drillstring can become stuck when drilled cuttings are not adequately removed from the hole. This type of sticking is usually accompanied by loss or partial loss of circulation caused by “packing off”. In a vertical well, this tends to occur after fast drilling has loaded the annular space with cuttings, followed by a sudden stop in activity. At this point, the cuttings may settle; forming a blockage if left long enough. In deviated wells, the situation is more complex. Above a certain inclination (often stated as 35°), cuttings beds will form on the low side of the wellbore. If these beds become too large or are pulled through too fast, the pipe may become stuck.

To prevent pipe sticking due to cuttings accumulation:

Always follow good drilling practices, including proper drillpipe rotation speed, circulation after kelly down, wiper trips, monitoring the cuttings coming over the shakers, etc.

Provide proper training for the driller and mud engineer to identify when cuttings are accumulating downhole, necessitating additional wiper trips and circulating times, as well as the adjustment of mud properties.

Maintain drilling fluid properties capable of good hole cleaning and general wellbore stability.

Maximize rotary drilling, especially for high angle holes (>35°). The use of a rotary-steerable system can greatly assist in this.



Ensure proper selection of casing points to minimize exposure time of formations to drilling fluids.

Maintain sufficient mud density in pressured zones.

When planning a high angle well, ensure that the rig can handle the operational requirement of flow rate, pipe rotation, etc. that will be required, as this may be more than what a rig drilling is capable of.

When the stuck pipe is caused by debris or cuttings accumulation, the typical actions to free the pipe consist of rotating, reciprocating and attempting to break circulation. Usually, hydraulic force is the most effective method of breaking up a serious cuttings related pack-off. It is not always necessary to "blast" free. Often, a steady flow will erode the cuttings buildup. The effectiveness of this can be monitored by watching the standpipe pressure. If the pressure slowly drops for a given flow rate, then the blockage is being worn down.

Junk, Cement, and Collapsed Casing

A number of other materials can become lodged in the borehole, preventing pipe movement: broken off pieces of the bit or BHA, a piece of cement falling back and collapsed casing. Sometimes these can be drilled or reamed out or a sidetrack may be necessary. It is important to recognize the sources of stuck pipe, as most of the typical fluids remedies will not assist in these situations.



Impact on Torque and Drag

As the primary indicators of stuck pipe are increased torque and/or drag, it is important to closely monitor these parameters during drilling. The following chart (Figure 10-2) shows some of the most common causes of stuck pipe and other downhole problems, identified by their impact on torque and drag.

Figure 10-2: Impact of downhole problems on torque and drag

Barite Sag

Under certain circumstances, the weighting material in drilling fluids can separate and settle. This phenomenon is referred to as barite sag and it can cause significant variations in mud density. These variations include both decreases and increases in fluid density. A decrease in mud weight, or light spot by itself is not a clear indicator of barite sag. Although it is most often a problem in non-



aqueous drilling fluids, barite sag has been observed in all types of weighted muds.

These density variations can cause a number of drilling problems, including:

fractured formation and lost circulation

stuck pipe

pack-offs and loss of the ability to circulate

wellbore instability

well control issues

additional cost from the related NPT and mud conditioning

These problems can be particularly pronounced in directional and extended reach wells because the variation in fluid density can cause larger swings in equivalent static and circulating densities.

Barite sag occurs when inert weight material particles (e.g. barite, hematite) settle and form an ultra-high density slurry or a barite “bed” on the low side of the hole. Generally, barite beds can form in wells that are deviated 30° or more and are drilled with mud weights greater than 12 lb/gal (1.4 kg/L). At angles up to about 75°, the beds can slump (slide or flow toward the bottom of the hole). After a trip, subsequent mud circulation reveals a wide variance in mud weight.

Barite sag is commonly associated with static conditions during periods of no circulation, but sag can also occur in dynamic flow conditions, especially with low annular velocities. Additionally, if barite has already settled out in a deviated well, the beds can slump back and cause stuck pipe or pack-offs even after the fluid properties have been adjusted.



In vertical wells, drilling fluid gel strength can prevent the initiation of sag by suspending the particles while circulation is ceased. In a deviated environment, the situation is complicated by "Boycott settling". This phenomenon is caused by rapid settling of heavier particles which causes heavy mud to drop to the low side of the hole and lighter mud to rise to the top.

The problem of barite sag in NAF can be exacerbated by high temperatures which tend to thin the fluid and decrease low shear rate yield points (LSRYP’s). Furthermore, low viscosity clean muds and wells with low annular velocities are more susceptible to sagging. Certain activities such as running casing/liners, tripping pipe at slow speed and logging, can induce sag by creating a low shear environment. This environment breaks gels but does not provide enough energy to keep the barite suspended.

Sag can also occur in drilling fluids which are stored at surface for extended periods of time. This can be made worse on ships where the rocking motion will prevent the formation of gel strength, thus allowing the barite to fall out. Proper tank agitation is the key to preventing this problem.

Barite Sag Detection

Accurate and timely detection of barite sag is important to allow for treatment and mitigating practices before serious drilling problems and related NPT occur. As with most fluids-related drilling problems, monitoring trends during operations is key to successful determination of a problem. The following parameters should specifically be watched for indications of barite sag:

Mud weight - After trips, mud weight in and out should be measured (at least every 15 min) while circulating bottoms-up. The typical “fingerprint”



of barite sag is a roughly sinusoidal shape (see Figure 10-3). When circulating bottoms-up, light mud is followed by heavy mud, then by the original-weight mud. The heaviest mud weight usually occurs at bottoms-up. In HTHP applications, mud weight adjustment for temperature is recommended. Use of a pressurized balance helps obtain good data with gas-cut mud.

Standpipe pressure - Fluctuations in standpipe pressure may occur as slugs of light and heavy mud pass through the bit nozzles and other restrictive parts of the circulating system. Also, higher standpipe pressures may indicate if annular sag pack-off is occurring.

Torque and drag - High torque and overpull can indicate that barite beds are forming on the low side of the hole.

Mud losses and gains - Unexpected losses may occur in deviated wells as heavy mud in the annulus reaches near-vertical sections of the well and rapidly increases hydrostatic pressure. The opposite effect can occur with light mud, which could cause the well to flow. Care must be taken to differentiate this effect from wellbore ballooning.



Figure 10-3: Mud weight variations indicate sag after trip. (Courtesy of M-I SWACO)

Drilling Fluid Guidelines to Prevent and Treat Barite Sag

Elevated low-shear rheology and gels help reduce sag. Clay-based rheology modifiers may be more effective than fatty acid products in freshly built NAF’s. For some muds used in deepwater applications, the rheology adjustments to counteract effects of low temperatures can exacerbate sag.

Maintain adequate yield stress. The LSRYP, measured at the lowest speed available on the FANN 35 viscometer, is a good indicator for sag-related rheological properties. For most wells, LSRYP should be maintained above the 7 to 15 lb/100 ft2 (3 to 7 Pa) range. Larger hole sizes typically require higher LSRYP values. Maintain low shear rate viscosity (measured with a BROOKFIELD™ viscometer) at 0.1 rpm in the 20,000 to 30,000 cp range.

Carefully monitor mud weight after dilution. Base oil additions thin NAF’s, and increase sag



potential. Rheology modifiers can compensate for viscosity loss; however, some rheology modifiers require a sufficient amount of water to be available.

Maintain proper surfactant concentration. Wetting agent levels in non-aqueous fluids must be sufficient to prevent barite agglomeration. Overtreatment should be avoided to prevent undesirable reductions in viscosity.

Exercise care with fluid loss additives. Under certain circumstances, sag problems can be aggravated by viscosity reductions caused by fluid loss control additives, typically in WBMs.

Operational Best Practices for Barite Sag

Measure fluid density while circulating bottoms-up to identify sag fingerprint. Compare the expected ECD to downhole measurements (erratic deviations can be an indicator of sag). Watch for pump pressure variations when operational parameters are constant.

Maintain flow at designed rates. Barite sag is often a dynamic settling problem in which beds are formed during periods of low circulation rates. Long periods at low flow rates exacerbate sag, even if other key variables are within proper limits. Beds should be removed prior to tripping out using high flow rates and rotary speeds.

In cases of severe sag, especially when coupled with a low fracture gradient at the casing shoe, it may be necessary to stop circulating, trip out and stage back in. The goal would be to prevent lost circulation when heavy mud from the bottom is above the shoe.



Minimize time between trips. Beds formed under dynamic conditions can slump during static periods. Beds formed at medium angles slump faster, but beds in the 60° to 75° range can be considerably thicker and give more problems. It may be necessary to stage in the hole if there are extended periods between trips.

If possible, minimize sliding time and maximize pipe rotation. For a given set of conditions, sag is least likely to occur when the pipe is rotating at greater than 75 rpm and eccentric. Sag is worst when the drillpipe is stationary and eccentric. Pipe rotation can minimize bed formation and even help remove existing beds. Completing rotary wiper trips often is beneficial after extended periods of sliding.

Properly condition mud prior to cementing. Avoid overtreatment of the mud to reduce viscosity prior to running casing and/or cementing. Excessive dilution dramatically increases the likelihood of sag.

If extensive periods of static conditions are expected due to logging or other activity, consider conditioning the mud to give better properties for preventing sag.

Wellbore Breathing

Wellbore breathing, also referred to as wellbore ballooning, can be associated with either induced or naturally occurring fractures, and is normally associated with non-aqueous drilling fluids. Wellbore breathing is troublesome for drilling operations due to the increase in non-productive time. NPT related to wellbore breathing is usually due to monitoring for flow on connections,



interpreting fluid losses while drilling, and identifying kicks.

While drilling ahead, if ECD exceeds the fracture initiation (induced fractures) or fracture opening pressure, drilling fluid flows from the wellbore and is “temporarily lost” into these fractures. These fractures may continue to propagate and grow, resulting in very large volume losses. When the pumps are turned off and the hydrostatic pressure in the annulus decreases to the equivalent static density (ESD), the fractures will begin to close and this “temporarily lost” fluid will flow back into the wellbore, displacing fluid from the well. In most cases, the volume of fluid lost will be very close to, if not the same as, the volume of fluid that flows back into the well with the pumps off.

When the pumps are shut down, fluid can flow from the wellbore for an extended period of time (30 minutes or more) and volumes gained can be in excess of 200 to 300 barrels. For this reason, the flow can often be mistaken as a kick. If the flow is assumed to be due to a kick, it should be circulated out using the Drillers Method. If wellbore breathing is the cause of flow from the well, increases to the mud density should be avoided. Because the consequences of misinterpreting a wellbore breathing event can be severe, it is essential that the cause of the fluid influx be clearly understood.

The risk of wellbore breathing increases as an interval is drilled deeper. If the mud weight is increased to manage wellbore stability, the combined effect of higher mud weight and ECD may push the wellbore pressure very close to the fracture initiation pressure at its weakest point in the interval, typically the casing shoe, but it could be anywhere in the wellbore. If this occurs, the pressure may be sufficient for a network of fine fractures to develop, without the fractures opening sufficiently to cause severe lost circulation.



Alternatively, the increasing pressure may be enough to propagate existing fractures. These fractures will then take fluid from the wellbore, giving the impression that lost circulation is occurring. When circulation is stopped, the pressure in the wellbore decreases and the fractures are able to close, displacing the “lost” mud back into the wellbore and giving the impression that the well is flowing. Managing to stay within the available pore pressure-fracture gradient window, without initiating breathing, lost circulation, or well control, is a major challenge, particularly on deepwater projects.

Wellbore Flow-Back Characterization – Fingerprinting Techniques

Wellbore flow-back fingerprinting techniques not only help identify the onset of breathing, but also determine the extent of the breathing and fluid influxes. Procedures are available that allow the severity of breathing to be reduced and lost circulation avoided. Wellbore breathing is often a precursor to lost circulation. Consequently, if breathing is identified, steps should be taken to mitigate the breathing in order to avoid lost circulation and reduce NPT.

Annular pressure while drilling (APWD) data can clearly show when a well is breathing. For a well that is not breathing, the ECD trace from the tool on a connection is square. When the pumps are off and the fluid is not moving, the ECD will rapidly drop to the ESD value. Conversely, when the pumps are turned on and fluid movement is initiated, the ESD rapidly increases to the drilling ECD value previously observed, prior to the connection. When a wellbore is breathing, a gradual pressure decrease is observed in the annulus as the fluid is squeezed back into the wellbore from the fractures



during a connection. When the pumps are on, the ESD value gradually increases to the previous ECD value while the fractures are again being injected with drilling fluid. These scenarios are illustrated in Figure 10-4.

Figure 10-4: Annular pressure profiles for non-breathing and breathing wellbores

The main drawback to the use of downhole APWD tools is the limited number of pressure data points that can be retrieved in real-time. If only a few data points are transmitted, it can be very difficult to say with any confidence that a square or curve pressure profile exists. For this reason APWD tools most often identify wellbore breathing in recorded mode which is processed after the tool is back on surface. Unfortunately, this means that the identification can only be made after the fact, following a trip.

The following procedure provides a method to fingerprint and monitor the wellbore for the onset of breathing:



1. Ensure all surface equipment is configured for drilling ahead purposes.

2. After displacing to NAF:

a. Circulate at the drill ahead flow rate

b. Shut down pumps

c. Record time for flow to decrease to zero and total volume gained in the active system from the time the pumps are shutdown

3. Repeat this procedure if a formation integrity test (FIT) or leak off test (LOT) is performed after the displacement. If FIT/LOT was performed prior to displacement, proceed directly to step 4. The times and volumes recorded in steps 2 or 3 will serve as the baseline for a stable, non-breathing well.

4. On each connection and flow check, record the time required for flow to decrease and the total volume gained.

a. Should the time increase or the volume increase, the wellbore may be breathing. The flow rate from the well must be decreasing with time.

b. Should flow from the well increase with time or remain constant, the well is flowing and well control procedures should be initiated.

5. If gas is observed on bottoms-up after connection and the well appears to be breathing, determine if the well is under-balanced using the following procedure:

a. Note strokes for bottoms-up

b. Apply slow circulating rates for 30 minutes and record strokes



c. Resume normal drill ahead flow rates and continue circulating until bottoms-up cycle is complete

d. If no gas is present, then previous gas shows are associated with breathing

e. If gas is present, well is under-balanced

When drilling ahead, and a baseline flow-back trend has not been established, a first time flow-back occurrence should be treated as a kick and circulated out by the Driller’s Method to identify whether an influx of formation fluid has occurred.

Never assume “wellbore breathing”!

A second method used to identify wellbore breathing utilizes real-time resistivity measurements. Depending upon whether the pumps are on or off, deep and shallow resistivity traces will show different characteristics. For a wellbore exhibiting breathing, fluid is forced into the fractures with the pumps on. When the pumps are off, fluid is forced out of the fractures. The resistivity profiles can thus determine if non-aqueous drilling fluid is forced beyond the diameter of the wellbore. An example of the resistivity traces is given in Figure 10-5. Care should be taken with this approach to ensure that the source of this log response is not due to filtrate invasion.



Figure 10-5: Real-time resistivity trace showing shallow penetration of SBM after fracture initiation

A third method for identifying wellbore breathing involves fingerprinting the flow back profile of the drilling fluid during connections. This procedure should be applied while drilling out the cement at the start of the interval and carried through on each subsequent connection for the rest of the interval. Characterizing the flow back profile while drilling the cement provides an opportunity for recording the flow back for a cased hole, where fluid influxes cannot occur and wellbore breathing has not been initiated. It is important that the drill ahead flow rate be used in order to represent the conditions expected, once exposed formation is being drilled. This reference curve can be used throughout the interval to determine when breathing is initiated and its severity. The objective here is to record the volume of flow back mud and the time for the flow to decrease to zero.

Importantly, this technique can also be used to identify a fluid influx from the formation. Under breathing conditions, the observed flow out of the well should begin to decrease and approach zero over time. Depending on the severity of the breathing, this process



can occur over a very long time (flow times exceeding 1 hour have been reported), leading to a large increase in NPT. This extended flow back time can also give the impression that the well is flowing. If in fact the well is flowing, an increase in the rate of flow out of the well should be observed at some point during the connection. It is not possible for the flow back rate to increase if the well is simply breathing. When using water base mud, if the well is actually flowing, lighter fluid will be brought into the annulus and the flow should begin to increase due to the lower hydrostatic head. If using a NAF, gas will dissolve into the fluid and an increase in flow will usually not be detected until the gas reaches its “bubble point” and comes out of solution when it is circulated up the hole. An example of the fingerprinting technique being used to identify a kick is given in Figure 10-6.

Figure 10-6: Fingerprinting technique for characterizing flow back profiles on connections and identifying wellbore breathing and kicks



When wellbore breathing is occurring, the shape of the flow back profile should remain the same, but the total volume of fluid returned to the active pit system should increase and the time required to achieve zero flow may also increase.

The volume of mud returned on a connection can also be dependent on the flow rate immediately prior to shutting down for a connection or flow check. For this reason it is important to characterize the initial reference flow back profile at the expected drill ahead flow rate. Modifications to the surface equipment configuration while drilling can also change the reference profile. If this occurs, a new reference profile should be generated.

Breathing with Gas

One major issue that occurs with wellbore breathing, and one that greatly adds to the confusion, is the presence of gas in the mud that is circulated back to the surface. If the apparent losses occur in sands or at the interface between sand and shale, the fluid that flows into the fractures may come into contact with hydrocarbons, specifically gas. In this instance the entire volume that flows into the fractures may then contain a significant level of gas when circulated back to the surface. In this instance, is easy to assume that this gas is due to the well being under-balanced and a kick occurring.

In order to identify if the gas is due to the well flowing or absorbed gas associated with breathing, the following procedure can be applied. After a connection has been made, circulate the mud at a reduced flow rate for 30 minutes before resuming full circulation. This will allow gas-free mud to pass through the open hole section without entering fractures. Track the strokes required for the mud to reach the surface. If there is no gas present in the mud once it reaches the surface, then it



can be assumed that the previously recorded gas is related to mud (containing gas) re-entering the wellbore from fractures (breathing) and not a kick. If gas is still present, then it is most likely that the well is under-balanced and the mud weight should be increased. The reduced flow rate should inhibit the fractures from re-opening and inducing breathing, ensuring that the mud does not enter and then flow back out of the fractures. The objective with the slow flow rates is to pass a minimum of 500 ft of mud through the annulus without opening fractures that may be present.

Solutions for Managing Wellbore Breathing

Curing breathing is a definite challenge when drilling with NAF. Laboratory testing and field data suggest that a combination of resilient graphitic carbon (RGC) and calcium carbonate (CaCO3) will provide some degree of healing to the fractures. Laboratory testing on fractured cores indicate that fracture re-opening pressures can be increased when RGC is placed in the fracture. If RGC is successfully placed in a fracture, when the fracture closes the product is able to deform without breaking down, thus maintaining its ability to stay in place and continue to bridge once pressure is re-applied to the fracture.

Additional methods for reducing or eliminating breathing through reducing wellbore pressures include:

1. Reduce mud weight (if possible)

2. Reduce flow rate in order to lower the ECD

3. Reduce the fluid rheology to lower the ECD

4. Reduce the rate of penetration

For options 2, 3 and 4, consideration must be given to the effect that changing these parameters will have on



other aspects of the operation. It may also be necessary to adjust other parameters if either of these options is applied.

It is important to realize that a clear distinction between wellbore breathing and formation fluid influxes can be the difference between a successful well and loss of the interval. In order to combat these situations, different responses are required. If wellbore breathing is misinterpreted as a kick and the mud weight is increased, lost circulation can develop. If a kick is misinterpreted as wellbore breathing and the mud weight decreased or simply maintained, the consequences are obvious. For these reasons it is critical to have clear, agreed upon strategies in place to deal with wellbore breathing should it develop. Good communications are important to ensure that the casing and cementing planner and operators are aware that the well is breathing, as it is likely that the well will be static prior to their arrival.

The procedure for understanding the difference in resistivity traces is outlined in SPE paper number 67742 “How to Diagnose Drilling Induced Fractures in Wells Drilled with Oil-Based Muds with Real-Time Resistivity and Pressure Measurements”.



Appendix 10-1: Identifying type and location of loss

Normal Drilling

Is lossdownhole?

Is casingworn, leaking?

Is casingshoe cement

holding?

Fix surface system leak

Fix hole in casing

Squeeze casing shoe

NO

YES

YES

NO

YES

Did loss occur suddenly while tripping,raising mud weight/ECD, drilling fast,or with annular restriction (balling,tight hole)?

Induced Fracture in weakest zonejust below casing shoe or belowannular restriction

Confirming Features: ECD is near fracture gradient Loss rate is sensitive to changes

in ECD/circulation rate Mud loss is recovered with

reduced mud weight/ECD Loss not experienced on adjacent

wells Initial loss rate is maximum loss

rate Not associated with drilling break Often occurs at formation change

from shale to sandstone

YESDid a change in ROP, torque,etc. accompany the loss?

Gradual Loss:Did loss start gradually,then increase with depthto a maximum?

YES

NO

NO

Losses to natural matrixpermeability or micro-fracturesnear bottom

YES

Confirming Features: Occurs in high permeability sands gravels,

and fractured formations Not sensitive to increas/decrease in ECD Occurs most often in low solids muds Starts gradually and increases with depth

Abrupt Loss:Is formation carbonate suchas limestone or dolomite?

NO

Losses to natural vugs orcaverns or highly fractured

limestone on bottom

YES

NO

Confirming Features: Sudden loss while drilling, often

severe Usually associated with limestone/

dolomite Usually associated with change in

ROP or torque (bit may drop) Loss rate sensitive to changes in

ECD LCM not very effective

Confirming Features: Loss occurs with a change in ROP Loss occurs with a change in formation

Loss to natural fracturesor fault on bottom

Is fault or natural fracturedinterval anticipated orpossible?

YES

Is mud weight nearfracture gradient?

NO

YESNO



Appendix 10-2: Decision chart for treating loss circulation

<>

Seepage Loss< 25bbl/hr WBM< 10 bbl/hr OBM

Reduce Mud Wt.& ECD, if possible

Success?

NO

Mix 5-10 sacks per hourfine LCM & drill ahead

Success?

Treat system with 15-25 lb/bbl fine LCM blend and drillahead

Success?

Spot pill w/25-50 lb/bblmedium LCM blend;

Pull up and wait

Success?

See Partial Loss

NO

NO

NO

YES

YES

YES

YES

Normal Drilling

Partial Loss25 - 100 bbl/hr WBM10 - 30 bbl/hr OBM

Natural Loss ZonesInduced Fracture

Loss Zones


Reduce Mud Wt.& ECD if possible

Success? Success?

Treat system with 15-25lb/bbl fine LCM blend &drill ahead

Spot pill w/35-70 lb/bblmed. & course granularLCM; Pull up and wait

Spot pill w/25-50 lb/bblmedium LCM blend;

Pull up and wait

Spot high fluid losspill and squeeze

Success? Success?

Success? Success?

Spot Settable Plug (figure 1-5)

Success?

See Severe Loss

NO NO

YES YES

YES YES

YES YES

NO NO

NO NO

YES

NO

Severe Loss> 100 bbl/hr WBM> 30 bbl/hr OBM


Success?

Spot pill w/35-70 lb/bbl medium & coarseLCM blend: Pull up and wait

Success?

Natural Loss Zones Induced Fractures

Spot Settable Plug(See figure 1-5)

Spot high fluidloss pill and

squeeze

Success? Success?

Spot hard pill DOB2C, magnesiumcement, silicate-cement, resin coated

sand, etc (See Figure 1-5)

Success?

Use alternative technique mudcap, drilling blend,aerated mud, foam, mist, air drilling or set casing

YES

YES

NO

NO

NO NO

Chapter 11: Fluids-Related Productivity Optimization


CHAPTER 11: FLUIDS-RELATED PRODUCTIVITY OPTIMIZATION

The productivity of a well is not just a function of the reservoir properties, but also the manner in which it has been drilled and completed. To achieve optimum productivity, it is important to ensure that the fluids used in the operation do not impair the potential economic future of the well. The purpose is not just to drill a well, but to maximize hydrocarbon recovery. It is therefore critical to ensure that the drilling, drill-in, workover, and completion fluids do not irreversibly damage permeability, porosity and alter the native formation wettability.

A non-damaging fluid is a clean fluid that induces little or no loss of the natural permeability of the pay zone targeted for development, while providing superior hole cleaning and easy clean-up. In addition to being both safe and providing an economical benefit for the application, it must be compatible with the native fluid of the reservoir to avoid precipitation of salts or production of emulsions, which would damage well productivity.

Formation Damage

Formation damage can be defined as any restriction to the flow of oil or gas from the formation to the wellbore. Any restriction to flow around the wellbore reduces the maximum flow potential and possibly the ultimate hydrocarbon recovery. Formation damage may be the result of physical, chemical, or bacterial alteration of the producing formation. Formation damage includes permeability or porosity impairment, skin damage, and decreased well production. The skin value of a well is a dimensionless factor that rates the production efficiency



of a well. This factor compares the actual well productivity to the theoretical well productivity. A positive skin value indicates damage that is impairing well productivity and a negative skin value indicates enhanced productivity, usually a result of a stimulation treatment.

Causes of Formation Damage

The mechanisms of formation damage from invading fluid generally include:

Plugging of pore throats on the face of the formation by a filter cake during drilling

Dispersion of clays or other minerals contained in the rock matrix

Dislodgement of fine particulates contained within the pore spaces (fines migration)

Swelling of pore space clays causing blockage

Emulsion formation

Change in rock wettability

Narrowing of fine pore spaces (capillaries) through adsorption of water-soluble polymers

Water-blocking

Chemical precipitation of solution salts

Presence of sulfate-reducing or slime-producing bacteria and byproduct precipitates

Formation damage usually takes place during drilling and/or completion operations and is a very significant contributor to the evolution of positive skin in the well. This results in suboptimal production rates and it could even result in loss of reserves.



During drilling, the density of the drilling fluid is usually maintained to give a hydrostatic pressure greater than the formation fluid pressure to prevent a possible well blow-out. While drilling, as new formation is exposed by the drill bit, fluid is forced into the formation by the positive differential drilling fluid column pressure. Drilling fluid particles smaller than the pore throat openings migrate into the formation during spurt loss, but they rapidly bridge on the pore throats in the near wellbore formation. Particles larger than the formation pores accumulate at the formation face, initiating a filter cake buildup. The invasion of whole drilling fluid is stopped quickly by the filter cake and only filtrate is allowed to penetrate the formation.

A second type of solids plugging can occur when fine drilled solids or drilling fluid additives penetrate the formation to depths beyond the near wellbore region. These solids migrate into an ever increasing number of radial passageways. When the well is flowed during production, if the particles do not pass through the entry route in reverse, they are likely to become lodged in narrow passageways and block further fluid flow.

Solids plugging can also occur from the swelling or migration of clays or non-clay minerals within predominantly sandstone formations. Montmorillonites and mixed-layer clays are typical examples of swelling clays. In the presence of water fresher than that originally contained in the pore space, montmorillonites with a high content of sodium can swell to many times their original volume. This swelling will shrink pore openings, reducing porosity and permeability. While smectites are the principal types of swelling clays, illites can swell when they coexist with smectites. Kaolinite has a platelet structure similar to smectite clays, but exhibits little or no swelling characteristics. This group of clays can be mobilized by the infiltration of fluids with flow rates high enough to carry the fine particles away



from the pore surfaces. These mobilized fines then migrate until they are trapped at pore restrictions (the pore throats), thus reducing the permeability of the rock. Mobilization, migration, and retention of clays and other fine particles have been recognized as a major formation damaging factor in sandstone formations. If these fines are trapped near the wellbore, very significant production losses occur because of the reduction in the number of total flow paths into the borehole.

A secondary source of solids that cause formation damage is the precipitation of insoluble salts or suspended colloidal particulates; created when completion or workover fluids contact incompatible connate water. For example, when calcium brines come in contact with connate water containing CO2, insoluble calcium carbonate (CaCO3) may precipitate and plug near wellbore pore spaces. In addition, due to their physical and chemical properties, heavy brines or non-aqueous drilling fluid filtrates may cause the precipitation of high viscosity asphaltenes and paraffins from in-situ hydrocarbons.

Formation damage may also be the result of a change in the nature of the fluid wetting the surface of the pore space, i.e., a wettability change. Because of the chemical makeup of the sands and clays that compose the majority of the world’s producing formations, water has a greater affinity for the exposed solid surfaces than oil. However, if the hydrocarbon has been oxidized or otherwise contains polar groups, such as carboxyls, amines, amides, sulfonates, and thiols, the partial polarity of the hydrocarbon may actually be such that it is attracted to the rock surface. Water is displaced and the formation rock becomes oil-wet. When the formation wettability changes, it does not do so uniformly; i.e., some of the pore surfaces remain water-wet and some become oil-wet. Because the relative permeabilities of water and oil are different, a zoning effect results and



hydrocarbon productivity is impaired. The formation is more permeable to oil when the formation is water-wet because the oil flows through the center of the pores that compose the larger flow channels while water stays in the narrower channels and along the rock surfaces. Conversely, the formation is more permeable to water when the formation is oil-wet because the water is not restrained by its affinity for the polar surfaces of the rock and is less viscous that the oil. Thus, the interface between these two zones has the potential to form a water blockage. The relative permeability for oil and water as a function of water saturation (Sw) is shown in Figure 11-1.

Figure 11-1: Relative permeability curves for oil and water in a water-wet formation

Wettability changes can be caused by the presence of surfactants in the drilling, completion, or workover fluids. Additives such as detergents and lubricants in water



base drilling fluids and oil-wetting agents in non-aqueous fluids are the most likely causes of wettability changes. Excessive use of surfactants in completion fluids may also change the natural wetting of the formation rock.

The natural tendency of water to wet polar surfaces contributes to another formation damage mechanism called water-block (Figure 11-2). Capillary pressure promotes the displacement of oil by water but resists the displacement of water by oil. In most reservoirs, native pressures are great enough to overcome capillary pressure. However, in low pressure and tight, low permeability formations, the capillary pressures resisting displacement of water by oil may be significant enough to cause permanent impairment. The problem of water-block is especially serious in the near-wellbore region, where the pressure drop of the oil/water interface approaches zero. The probability of water-block increases as the volume of fluid lost to the formation increases.

Figure 11-2: Depiction of water-block (Courtesy of Baker Hughes Drilling Fluids)

Another cause of capillary impairment is in-situ emulsification of in-place oil with completion/workover



fluids. Concentrated salt solutions have an inherent tendency to form emulsions with crude oil even in the absence of surfactants. Stable emulsions are formed by mixing normally immiscible fluids at high shear rates. Because the viscosity of oil/brine emulsions is very high, their movement through the rock is severely restricted. As the emulsion droplets become trapped in the capillary pore spaces (emulsion block), the effective permeability of the formation rock is impaired.

Water soluble polymers used for viscosity and filtration control may adsorb onto the rock matrix in pore spaces and reduce the flow channels available for hydrocarbon movement. Removal of these polymers is difficult both because of the strong attraction and because the polymers are not mutually soluble in water and hydrocarbons.

Formation Protection

It is advisable to follow some generally accepted practices to prevent formation damage during drilling, completion and workover operations. First, filtered brine usually reduces the chance of introducing foreign particles into the formation and causing water sensitive clays to swell. Second, use of a laboratory tested and selected surfactant helps reduce the chance of emulsion formation, wettability change, and fines migration. Lastly, the selection of a chemically compatible drilling, completion and workover fluid reduces the probability of insoluble salt precipitation.

Of the potential mechanisms to prevent formation damage, the most significant is the prevention of fluid loss to the formation. This is sometimes accomplished by increasing the low shear rate viscosity (LSRV) of the fluid. Because the flow rate in porous media is inversely proportional to viscosity, increasing the viscosity of the



fluid at bottom-hole conditions can significantly reduce the loss of fluid to the formation. The most common practice for minimizing fluid loss to the formation is to use a combination of increased viscosity and salt or calcium carbonate particles to bridge the pore spaces on the formation face. A properly designed fluid loss pill can be removed by flowing the well back. These particular bridging agents are acid soluble and therefore can be removed by acid treatment if they are not removed by washing or production of the well.

Best practices for preventing formation damage during workover operations include:

Select formation-compatible completion or workover fluids. Incompatible fluids can cause shale swelling and precipitation of salts and minerals which block pore throats.

Use only filtered (clean) brines to minimize formation damage. Insoluble solids in the brine will invade the production zone and damage permeability.

The primary cause of formation damage during workover operations is the invasion of fine solids and debris from downhole operations, such as near perforation, milling and scraping. Minimizing fluid loss can prevent the entry of these fines into the formation.

Fluid loss control pills that are properly formulated clean up easily from perforations and result in minimal formation damage. Using poorly formulated pills may lead to severe damage due to persistent filter cakes that require high lift-off pressures. The loss of filtered, compatible fluids into the reservoir during completion or workover operations has



little effect on future productivity when the formation has relatively high permeability.

Tight formations can also be damaged by loss of fluid and are most likely to be damaged by invasion as they have small pores and high capillary pressures. They are therefore more difficult to clean up than high permeability reservoirs.

In non-fractured wells, viscous pills, in combination with minimum fluid densities, can be used to control fluid loss to an acceptable level. However, to more effectively minimize fluid loss, properly sized bridging materials must be added to the viscous pill to seal the formation.

In fractured wells, both coarse and fine solids may cause irreversible damage. To stop the loss of fluid, special care must be taken to ensure that bridging materials added to the fluid loss pill contain materials coarse enough to bridge the fractures at the formation face.

Fluid loss pills for use inside screens should be carefully designed to bridge inside the screen and not penetrate into the screen element. Failure to do so could result in plugging of the screen and/or gravel pack.

When working with less than salt saturated fluids, it is a good practice to use an antibacterial agent (biocide) to inhibit the growth of slime producing bacteria so that these bacteria are not introduced into the producing formation.



Best practices for preventing formation damage during drilling operations include:

Utilization of a properly designed drill-in fluid. Elements include:

o Inhibitive fluid (brine or NAF)

o Properly sized, acid soluble bridging agents

o Minimize fluid loss with starch or polymers

o Minimize commercial clay usage with polymer viscosifiers

o Neutral to slightly alkaline pH (8.3 to 9.0)

Drill-In Fluids

A drill-in fluid (DIF) is a combination of a drilling and completion fluid specially formulated to maximize the productivity index of a producing well. It must maintain the desired properties of an acceptable drilling fluid (i.e. density, viscosity, shale stability and fluid loss control) as well as completion fluid characteristics (i.e. clean, non-damaging to the wellbore and the internal pore structure of the producing zone) (Table 11-1).



Drill-In Fluid

Drilling Completion

ROP

Wellbore stability

Hole cleaning

Solids removal

Lubricity

Inhibition

Formation Damage

Clay hydration

Fines migration

Incompatible water

Solids plugging

Emulsions

Table 11-1: Desired drill-in fluid attributes

There are three main categories of drill-in fluids that are commonly utilized:

1. Water base: sized calcium carbonate or clear brine

2. Non-aqueous: synthetics (invert or 100% base oil)

3. Foam: nitrogen, air or gas (with or without additives)

The DIF must reduce/mitigate formation damage by removing and/or lessening the quantity of additives which are responsible for solids buildup in the pore space/throats. The drill-in fluid must also be compatible with the chemical nature and permeability of the formation, as well as offer good hole cleaning. Completion type (open or cased hole) is the primary factor in the fluid selection (Table 11-2).



Primary Concerns

Drill-In Fluid Clean-Up and Stimulation

Pre-Drilled Liner Completion

good bridging and filter cake quality are needed to prevent solids from entering pore network

ease of filter cake removal as the scraping tools cannot be used

bridging particles are required for filter cake quality

acid soluble or breaker degradable polymer additives

calcium carbonate or sized salt can be cleaned up easily

either acid wash or brine with polymer breakers

Pre-packed or Premium Screen Completions

weight materials and bridging agents from conventional drilling fluids can potentially block these devices

use either ultrafine or soluble bridging agents

biopolymer-based fluid provides elevated, low shear rate rheology for hole cleaning

fluid loss achieved with polymeric or starch additives

sized salt or calcium carbonate bridging agents

either acid wash or polymer breakers

Table 11-2: Drill-in fluid selection for completion type



Primary Concerns

Drill-In Fluid Clean-Up and Stimulation

Open Hole Gravel Pack Completion

weight materials and bridging agents from conventional drilling fluids can potentially block these devices

use either ultrafine or soluble bridging agents

hole stability during gravel pack

biopolymer-based fluid provides elevated, low shear rate rheology for hole cleaning

fluid loss achieved with polymeric or starch additives

sized salt or calcium carbonate bridging agents

either acid wash or polymer breakers

Table 11-2: Drill-in fluid selection for completion type (continued)

A suitable DIF should build a filter cake on the face of the formation, but not enter too far into the formation pore space/throat. This can be accomplished with the addition of sized particles of durable, easily remediated, bridging additives into the fluid system. It is recommended that the particles be chosen so that bridging can be effective; typically at least a one third diameter of the mean pore throat diameter and a wide particle size distribution (PSD). In addition to reducing formation damage, another benefit is that an optimal PSD, coupled with tight filtration control, will significantly reduce differential sticking tendencies while drilling.



Special consideration for drill-in fluid formulation should be given in order to achieve a low filter cake lift-off pressure during production initiation (Figures 11-3 and 11-4).

Figure 11-3: Proper filter cake deposited at the face of the formation with minimum penetration

Figure 11-4: Improperly designed bridging agents resulting in filter cake penetration into pore structure

The DIF filtrate should contain good shale inhibition qualities to prevent shale swelling within the pore



throats, which creates a potential for formation damage. The brines used with the DIF formulation should also be compatible with the completion fluid. Important factors for optimum filtration control are as follows:

Low spurt loss

Low total filtrate loss

Thin filter cake

Compatibility with minerals and fluids in the rock

It is important to utilize high quality products, specifically polymers and starches. Bridging agents should meet specified PSD requirements and be tested prior to usage. QA/QC procedures should be in place to ensure the quality of products meet the desired specifications.

Laboratory testing is recommended for optimization of the DIF formulation and should be based on known reservoir parameters such as lithology (sand/shale), bottom-hole pressure/temperature and average pore throat diameter. For bridging optimization, the expected pore throat diameter of the formation interval should be used to identify the concentration and PSD of bridging agents necessary to reduce filtrate and solids invasion into the reservoir. The effectiveness of the bridging agents should be tested in the laboratory with a permeability plugging apparatus (PPA).

The order in which DIF products are added (Table 11-3) is important to ensure proper yielding while reducing the concentrations necessary to achieve recommended properties.



Sample Mixing Procedure

Order of Addition

Product Role in DIF

1 Soda Ash Removal of Ca+2

2 KOH pH Control - Buffer

3 XCD Polymer

Viscosifier

4 KCl Shale Inhibitor

5 Biocide Bacteria Growth Reducer

6 Starch Filtration Control

7 CaCO3 Weighting/Bridging Agent/LCM

Table 11-3: DIF mixing order example

A generic DIF formulation is shown in Table 11-4 and provides typical concentrations of fluid products. It should be noted that most drill-in fluids are formulated for a specific application, and therefore products and concentrations may vary.



Sample DIF Formulation

Soda Ash 0.5 lb/bbl

KOH 0.5 lb/bbl

KCl 7 lb/bbl

XCD Polymer 2 lb/bbl

Biocide 0.1 lb/bbl

Starch 7 lb/bbl

CaCO3 Fine 10 lb/bbl

CaCO3 Medium 10 lb/bbl

CaCO3 Coarse 10 lb/bbl

Table 11-4: DIF formulation example

Magnesium oxide (not shown above in formulation) has been used to dramatically improve the temperature stability of various starch fluid loss products when added to drill-in fluids.

Fluid measurements particularly important for DIF applications (Table 11-5) include pH for inhibition of bacteria growth, low shear rate viscosity (LSRV) to ensure polymer yield/concentration for hole cleaning, retort measurements for drilled solids concentration and a laser-type particle size analyzer/sieve tester for PSD. The LSRV can be measured using a BROOKFIELD™

viscometer with appropriate spindle size for fluid viscosity range. The BROOKFIELD viscometer is not a common testing instrument seen at a drilling rig;



therefore it is a requested item and is typically utilized for QA/QC testing in the laboratory environment.

Sample WBM DIF Properties

MW 8.8 – 9.0 lb/gal

PV <10 cp

YP 20 – 30 lb/100ft2

RPM 3/6 10 – 12

LSRV (0.3 RPM) 25,000 – 30,000 cp

pH 9.0 – 10.0

% Insoluble

Solids, weight max < 2% by weight

Table 11-5: WBM DIF properties example

Careful attention should be paid to bridging agent additions for maintenance, as particle sizes will diminish with each circulation. Typically, maintenance is carried out by adding the larger particle size range, in lieu of a more blended sizing as in the initial formulation.

It is recommended to use additional shearing devices and/or pre-mix tanks for initial makeup, as well as product additions to limit fish-eyeing of the starch and polymers while also increasing the yield of each. This will also reduce the overall cost by minimizing the concentration of polymer needed to achieve and maintain recommended LSRV and mud properties. In areas where only a standard rig hopper is available with



no upgrading potential, it is recommended to decrease the rate of addition to reduce fish eying.

Any drilled solids that remain in the mud system after circulation increase the potential for formation damage. The best choice to reduce the insoluble solids content is using whole mud dilution when the percent insoluble by weight exceeds 2 wt%. The second best option is using solids control equipment on the rig to allow for the highest solids control efficiency as possible. This can be achieved with screening up to as fine as possible (API 140+ mesh) on shaker screens.

Chapter 12: Corrosion and Acid Gases


CHAPTER 12: CORROSION AND ACID GASES

Corrosion can be defined as the chemical or electrochemical reaction between a material, usually a metal, and its environment that produces a deterioration of the material and its properties. In other words, corrosion is the result of chemical or electrochemical reactions which return refined metal to its original form. A refined metal will always attempt to revert to its original state. However, proper care of a refined metal will extend its useful life. In short, corrosion will be decreased by keeping the metal clean and protected. Corrosion and its effects impact every aspect of the drilling, completion and production process.

Corrosion can be caused by several different mechanisms, including dissolved gases, galvanic currents generated on metal surfaces by electrochemical cells, stray currents and bacterial action. Since it is basically an electrochemical process, an electrical circuit must be established for corrosion to occur.

The best analogy for electrochemical corrosion is a battery circuit which is composed of four primary parts:

Anode – This is the equivalent to the negative electrode of a battery and the point where metals dissolve or go into solution

Cathode – The battery equivalent of the positive pole where hydrogen is produced

Conductor - There must be a coupling or electrical bridge between the anode and cathode to complete the circuit allowing the electrons to flow



Electrolyte - An “electrical potential” difference between the anode and cathode must exist when immersed in an electrolytic medium

The anode and cathode exist on the drillpipe itself. The drilling fluid can serve as the electrolytic medium, and the coupling is created by the drillpipe steel. The potential difference is created by the crystalline structure and different metals used in the drilling pipe alloy, or as a result of scale formation.

Several factors, including temperature, pressure, pH, and dissolved salts affect the rate at which corrosion proceeds. Most of these factors are interrelated and have a synergistic effect on the corrosion rate. The basic relationships are as follows:

Temperature

o As temperature increases, the rate of corrosion increases. If all other factors remain constant, the corrosion rate doubles for each 20 to 50 oF increase in temperature.

o Temperature decreases the solubility of corrosive gases (O2, CO2, H2S), thus decreasing the corrosiveness of the fluid. Note that “solubility” refers to the solubility of gas at surface pressure, and does not include chemical reactions of gases such as carbon dioxide (CO2) and hydrogen sulfide (H2S) with the fluid.

Pressure

o As pressure increases, the solubility of most corrosive gases will increase.

o When the fluid is pumped downhole, entrained or trapped air in the fluid



quickly goes into solution as the pressure increases.

o This dramatically affects the oxygen content of the fluid, which increases its corrosivity.

pH

o In general, corrosion rate decreases as pH increases.

o At ambient temperatures, corrosion rates rapidly decrease as the pH increases.

o As pH is increased above 10.5, very little additional reduction in corrosion rate is obtained. For pH values below 4.0, ferrous oxide (FeO) is soluble. As a result, the oxide dissolves as it is formed, rather than depositing on the metal surface to form a film that would inhibit corrosion. At a high pH, there is an increase in the rate of the reaction of oxygen with Fe(OH)2 (hydrated FeO) in the oxide layer to form the more protective ferric oxide (Fe2O3), which forms a “skin” on the metal surface, reducing the potential for corrosion.

Dissolved salts

With increasing salt concentration, conductivity rises, thus increasing corrosion rate.

However, increasing salt concentration reduces oxygen solubility, in turn decreasing corrosion rate.

The overall effect is a short-lived rise in corrosion rate due to conductivity. In the case of



chloride salts, corrosion rate rises until the chloride concentration reaches approximately 18,000 mg/L. Above this range, as chloride concentration increases, oxygen solubility and corrosion rate decrease.

Corrosion rates are calculated from corrosion coupons which are strategically placed in the drill string. The coupons are a known weight and are normally placed in the crossover sub above the drill collars and/or in the kelly saver sub or mud saver sub. The coupons should be run in the drill string for at least 40 hours. The time a coupon is run must be accurately reported to be able to determine the actual rate of corrosion.

The weight of material lost per square area in a given period of time will give the rate of corrosion. Rates may be reported as pounds per square foot per year (lb/ft2/yr), kilograms per square meter per year (kg/m2/yr), or in mils per year (mpy), which is actually a thickness reduction (Table 12-1). A mil is defined as one thousandth of an inch.

Rate lb/ft2/yr kg/m2/yr mpy

Acceptable 0 – 2 0 - 10 0 - 50

Moderate 2 – 4 10 - 20 50 - 100

High 4 – 6 20 - 30 100 - 150

Severe >6 >30 >150

Table 12-1: Corrosion coupon corrosion rate ranges

Multiple coupon runs are necessary to give an accurate corrosion rate. One run will give two data points and will



indicate a linear rate of corrosion. This is not always an accurate representation of what is really occurring. The type of corrosion indicated is also very important. If uniform corrosion has taken place, weight loss numbers may be a valid indicator of corrosion severity; however, pits may completely penetrate a coupon with little weight loss, incorrectly indicating a low corrosion rate. Corrosion coupons come in various sizes and metallurgies; therefore, it is important to have the proper ones available.

Oxygen Corrosion

Many water base drilling fluids in use today are more corrosive than those used in the past. Low solids non-dispersed (LSND) and low pH polymer fluids will tend to be more corrosive due to the elevated quantities of oxygen associated with the systems and the limited use of lignosulfonates. Used in sufficient quantities, lignosulfonate acts as an oxygen scavenger. If it is not being used, it is advisable to monitor the O2 level in the mud and use a high quality oxygen scavenger. It has been shown that dissolved oxygen levels exceeding 1.0 mg/L accelerate corrosion.

Oxygen enters a drilling fluid system at many points:

Shale shakers and hoppers

Cascading drilling fluids

Surface guns

Suction leaks

Centrifugal pumps

Desanders and desilters

When associated with CO2 and H2S, as little as five parts per billion O2 can greatly accelerate corrosion. In



general, oxygen corrosion affects the drillpipe, casing, pumps and surface equipment. This corrosion commonly occurs under residual mud when pipe is stored in other restricted areas, such as drillpipe protector rubbers. Poorly functioning pipe wipers are often overlooked as a cause of oxygen corrosion. These wipers may leave mud streaks on the drillpipe which dry and set up a potential corrosion cell. Localized cells are formed where steel is in contact with aerated solutions at one place and with oxygen deficient solutions in another.

Oxygen corrosion is a reaction that will occur where iron, water and oxygen are present. The reaction at the anode occurs under reducing conditions, usually under mud, rust or other barriers. Oxygen is required at the cathode to supply OH- for the continuation of the reaction at the anode. The reaction that occurs is a two-step process resulting in ferrous hydroxide deposition at the cathode.

In general, as water gets colder, the solubility of oxygen increases. For example, in fresh water, 14.6 mg/L O2 are soluble at 32°F (0°C) compared to 7.8 mg/L at 86°F (30 oC). Therefore, during winter months, corrosion rates in water base fluids may increase because of increased O2 solubility, due to decreasing temperature at the surface. It should be noted that studies from a closed loop dynamic simulation of downhole conditions show that oxygen concentrations downhole are not reduced by increased temperature. This is because the system is closed and the oxygen cannot escape to the atmosphere.

The course of action that reduces the amount of oxygen that enters the drilling fluid should be the initial step in alleviating the potential for oxygen corrosion to occur. Submerging hopper and mud gun discharges below the mud will minimize the oxygen content of the drilling fluid. The fluid’s pH should be maintained at the highest practical level to reduce corrosion levels. To chemically remove oxygen from the drilling fluid, a sulfite oxygen



scavenger is recommended. Oxygen will be removed by the oxidation of sulfite (SO3

-2) to sulfate (SO4-2).

The sulfite scavenger should be injected directly into the pump suction line for maximum effectiveness. A minimum sulfite concentration of 100 ppm should be maintained at the flowline. Should corrosion rates be excessive, the sulfite content may need to be increased to a range of 250 to 300 ppm.

Caution: The sulfate formed by the reaction of oxygen and sulfite creates a potential food source for sulfate reducing bacteria. Sulfate reducing bacterial generate H2S, which will also cause corrosion to occur.

Carbon Dioxide (Sweet Corrosion)

Carbon dioxide (CO2) corrosion, sometimes referred to as sweet corrosion, is attributed to the following:

Carbon dioxide intrusion which occurs as a gas kick

Slow bleed-in of carbon dioxide while drilling

Entrapment of atmospheric carbon dioxide in the mud at the surface and circulated downhole

Formation waters containing bicarbonate (HCO3-)

or carbonate (CO3=)

Bacterial or thermal degradation of fluid additives

Contamination of barite or bentonite

Sweet corrosion refers to a condition where no iron sulfide corrosion by-product occurs from the result of a sour gas (H2S) type corrosion. Carbon dioxide can enter into the wellbore from the formation and reach the surface as a gas or react completely with the water phase of the drilling fluid before reaching the surface.



The solubility of CO2 in the water component depends upon the partial pressure of the CO2 entrained in the mud. The partial pressure of an ideal gas (most gases are ideal at ambient conditions) in a mixture is equal to the pressure it would exert if it occupied the same volume alone at the same temperature. The total pressure of a gas mixture is the sum of the partial pressures of each individual gas in the mixture. The greater the partial pressure, the greater the solubility of CO2 and the greater the severity of the corrosion that occurs as a result.

Carbon dioxide corrosion can cause severe pitting (worm-eaten appearance) and sharp cracks in fatigue areas. When water is present, CO2 dissolves, forming carbonic acid, which is a weak acid corroding steel just like any other acid. The corrosion product is iron carbonate (siderite) scale. Carbon dioxide can also cause embrittlement, resulting in stress corrosion cracking.

The quantity of carbon dioxide present to cause corrosion is a function of pH due to the CO2/HCO3

-/CO3-2

equilibria. As pH decreases, HCO3- converts to carbonic

acid (H2CO3) and corrosion increases. Conversely, as the pH rises, the minerals in the water will precipitate and could become scale-forming, leading to a decrease in corrosion. This rise in pH may be accomplished with a reduction in the system pressure, which allows CO2 to come out of solution.

Generally, an increase in pressure will increase the solubility of CO2 in water and an increase in temperature will decrease the solubility of CO2 in water. Dissolved minerals act as a buffer, preventing the reduction of pH in water containing CO2, thereby influencing the rate of corrosion in a given system.

Detecting carbon dioxide in water base drilling fluid is not always easy, as it will depend upon the quantity of



reactive solids present in the fluid, but it can be identified by several means:

Reduction in pH

Increase in rheology values and fluid loss

Increase in HCO3- and CO3

= content

Identification by gas detection equipment

Iron carbonate, magnesium carbonate, or calcium scale on the drillpipe

Increased corrosion rates

Small influxes of CO2 into water base muds can be neutralized with caustic soda and lime or gypsum while maintaining a pH of 10.0 or higher is an easy, cost-effective treatment method.

Where a CO2 influx has become severe or where neutralization requires large treatments, several steps will be necessary to minimize the corrosive effect on the drillstring:

If possible, raise the fluid density to stop the influx.

Treat with caustic soda and lime to neutralize the acid gas and treat system with a scale inhibitor to prevent scale deposition.

Monitor alkalinities and pH periodically to ensure that carbonates are precipitated and solubility of carbon dioxide is minimized.

Polymer-type thinners will act to sequester metals and soluble calcium may appear low or unavailable.

Detecting carbon dioxide tends to be more difficult in non-aqueous fluids (NAF’s) than water base drilling fluids and is not dependent upon the quantity of reactive solids present in the fluid, but CO2 can be identified by several means:



Reductions in alkalinity and excess lime

Electrical stability (ES) could decrease

Identification by gas detection equipment

Corrosion rates associated with carbon dioxide in NAF should be extremely low due to the non-conductive properties of the non-aqueous fluid. Even though corrosion rates are low, it may be desirable to treat the CO2 contamination to minimize the detrimental effects to the fluid properties (e.g. emulsion stability, fluid loss). Additions of lime will react with the CO2, neutralizing the effects on the fluid. It should be noted that the by-product of this neutralization is calcium carbonate. Therefore, if large quantities of CO2 are being neutralized, an increase in rheology and solids content should be expected.

Hydrogen Sulfide (Sour Corrosion)

H2S is a colorless gas that is extremely toxic and corrosive. H2S can wreak havoc on mud systems, affecting viscosity, fluid loss and overall mud properties. In very low concentrations it has a rotten egg odor and causes eye and throat irritation. HsS can also be lethal when exposure concentrations exceed 1,800 ppm for 1 to 2 minutes.

Hydrogen sulfide is associated with gas intrusion, makeup water and bacteria. Thermal degradation of water base drilling fluid additives will also contribute minor amounts. When dissolved in water, hydrogen sulfide is a weak acid and becomes corrosive. In the presence of CO2 or O2 and water, hydrogen sulfide becomes severely corrosive due to the driving voltage increase of the resulting corrosion cell.

Iron sulfide and atomic hydrogen are the typical products of these reactions. The iron sulfide scale



produced by this reaction will adhere to the steel surfaces as a black scale. This in turn produces a galvanic action between the steel and sulfide scale which causes deep pitting.

Hydrogen sulfide can cause severe weakening of a steel pipe by a process called hydrogen embrittlement. The atomic hydrogen released in the above reaction can enter the steel matrix where it can combine with the steel and cause it to become brittle. Hydrogen atoms evolved from H2S can penetrate into the steel structure, especially along stress cracks, and combine to form molecular hydrogen or react with carbon compounds in the steel. This molecular hydrogen tends to blister ductile steel and crack high strength steel. Short exposure times to hydrogen sulfide can cause permanent weakness in the pipe, even after it has been removed from the H2S environment. Steels with yield strengths below approximately 90,000 psi are nearly immune to sulfide cracking. A high resistant chrome (HRC) of less than 22 grade is usually in this range.

Hydrogen sulfide solubility is very dependent upon pH and its disassociation increases with an increase of pH. Optimum disassociation level is obtained at approximately 7.0 pH. As the pH increases, the concentration of existing hydrogen sulfide will decrease to a very low level. Tubular cracking tendencies are also drastically reduced if the pH is maintained above 10.0.

It is important that H2S be detected quickly and accurately, as small amounts can be lethal to human life. Detection of hydrogen sulfide in water base drilling fluids can be done by several methods. If there is a possibility of encountering H2S, gas detectors or monitors should be installed on the drilling rig to detect unreacted H2S gas at the surface. Additionally, there are two common chemical tests that can be used to determine the total sulfides, both soluble and insoluble, in a drilling fluid. When testing for the presence of sulfides in a water base



drilling fluid, it is extremely important that the filtrate used be as fresh as possible. The filtrate should be taken from a sample of fluid freshly collected at the flowline. Exposure of the fluid or filtrate to the atmosphere should be minimal, as this reduces the accuracy of the test.

There are two tests that can be performed to identify H2S in the drilling fluid, Hach and Garrett Gas Train (GGT) tests. The Hach test is used to detect hydrogen sulfide in the acid form, or as soluble sulfides in makeup water, filtrate or mud. As previously seen, the concentration of H2S will decrease as the pH increases. Therefore, the test is performed in an acid environment to measures H2S as a gas. The GGT can be used to analyze soluble and insoluble sulfides in the mud filtrate. The test uses a controlled CO2 flow from a gas cartridge to force H2S from an acidized sample of fluid or filtrate.

If hydrogen sulfide gas is encountered or expected to be encountered when using a water base system, the pH of the mud should be maintained above 10. At an elevated pH, H2S is converted to soluble sulfide, which exhibits a reduced tendency to cause hydrogen embrittlement. Additions of caustic soda and lime should be used to increase the pH above 10. Do not use caustic soda alone, because caustic reacts to form sodium sulfide (Na2S), which is extremely soluble, and H2S may be released from the fluid if the pH drops. Lime is recommended instead because it forms calcium sulfide (CaS) which is only slightly soluble and will precipitate from the system. However, since soluble sulfides are corrosive and will revert back to H2S if a reduction in pH occurs, do not rely on this approach for total control. An H2S scavenger should be added to the system, in addition to increasing the pH.

A number of H2S scavengers, utilizing different chemistries, are commercially available and are listed below:



Basic Zinc Carbonate (2ZnCO3·3Zn(OH)2) - normally used as an H2S scavenger in water base systems. The reaction of zinc carbonate with sulfides is irreversible, forming insoluble zinc sulfide (ZnS) and will occur within a pH range of 3.4 to 14. Approximately 1 lb/bbl (2.85 kg/m3) zinc carbonate is needed to remove 500 mg/L of the sulfide ion. If used as pretreatment, no more than 5 lb/bbl (14.27 kg/m3) should be added to the system. It should be noted that the reaction of zinc carbonate with H2S will also form soluble carbonates, which will need to be treated.

Zinc Oxide - an inorganic compound with the formula ZnO. The reaction of zinc oxide with sulfides is irreversible, forming insoluble zinc sulfide (ZnS) and water.

Iron Oxide (Fe3O4) - can be used in water base drilling fluids as an H2S scavenger. The reaction of iron oxide with sulfides produces iron sulfide (FeS). It is specially formulated to have a very high surface area and is very effective when used in a low pH environment. Treatment levels will be dependent upon the pH of the system and the rate of hydrogen sulfide intrusion into the mud system, but will usually be in the range of 10 to 30 lb/bbl. An excess of unreacted iron oxide should be maintained in the mud at all times.

As with water base drilling fluids, detection of hydrogen sulfide in non-aqueous drilling fluids can be done by several methods. If there is a possibility of encountering H2S, gas detectors or monitors should be installed on the drilling rig to detect unreacted H2S gas at the surface. Additionally, the Garrett Gas Train can be used for detecting H2S in NAF’s. Unlike the water base fluids that use filtrate for H2S determination, whole mud is used for H2S determination in NAF’s.



For superior protection of the drill string and tubulars when H2S or any acid gas is anticipated, a NAF is recommended. The main advantage of a continuous oil phase fluid for drilling acid gas-bearing formations is the prevention of the various types of corrosion listed. The non-conductive nature of the NAF inhibits the electrochemical reaction necessary for corrosion to occur. The oil forms a protective oil film on the drillpipe which is not readily removed by the oil-wet solids through an erosion process. The primary precautions taken with the NAF system are to carry an alkalinity above 1 mL of 10 normal sulfuric acid per mL of mud in the “whole mud alkalinity test”, and circulate the fluid through a mud-gas separator and vacuum degasser. Additionally, the use of zinc oxide (ZnO) to scavenge H2S is recommended.

Bacteria-Induced Corrosion

Tubulars can suffer severe corrosion as the result of bacterial action. Microorganisms (e.g. bacteria) contribute to corrosion in different ways. For microorganisms to accelerate corrosion rates, suitable conditions must exist to promote their growth. An ideal environment for bacterial growth includes moisture, minerals, organic matter such as starch and polymers, an energy source and a suitable pH. Some bacteria act as cathodic depolarizers, while others form slimes or growths that shield a portion of the metal and set up oxygen concentration cells.

Microorganisms affecting corrosion are classified according to the presence (aerobic) or absence (anaerobic) of oxygen. In aerobic environments, the species Thiobacillus accounts for most of the corrosion. These bacteria convert sulfur to sulfuric acid, which will stimulate corrosion. Under anaerobic conditions, sulfate reducing microorganisms such as Desulfovibrio can



cause sulfide corrosion. These organisms utilize hydrogen formed by electrochemical corrosion during their growth and reduce sulfate to H2S. Both hydrogen utilization and H2S formation cause increased corrosion rates. This mechanism involves both the direct attack on iron by hydrogen sulfide and cathodic depolarization. In aerated drilling fluids, sulfate reducing bacteria may be found within active corrosion pit areas where the oxygen content becomes low. Anaerobic bacteria can turn the drilling fluid black and produce a rotten egg smell. If sulfate reducing bacteria are present, alterations to the fluid chemistry will be required. Increasing the pH to 10.0 or above, in addition to the use of a bactericide, is recommended.

As a general rule, the use of very high pH muds is not desirable due to the detrimental effect of the hydroxyl (OH-) ion on exposed shale, which could potentially lead to wellbore instability. To prevent bacterial growth from occurring, especially when using water base muds with near a neutral pH (<9.5), pre-treatment of all makeup water with a biocide should be standard practice. In addition, daily additions of biocide should be made to the drilling fluid system and bacterial growth monitored.

A quick reference guide to preventing and treating the various types of corrosion is shown in Table 12-2.



Table 12-2: Quick reference guide for corrosion in drilling fluids

Chapter 13: Gas, Foam, and Aerated Drilling Fluid Systems


CHAPTER 13: GAS, FOAM, AND AERATED DRILLING FLUID SYSTEMS

Gas, foam and aerated fluids are used to drill when annular pressure less than that produced by a column of a normal drilling fluid is desired. While these are forms of under-balanced drilling, they differ from simply drilling with a lower mud weight than the formation pore pressure, as they rely in part or entirely on the use of a gas as a drilling fluid.

The most common reasons for drilling with aerated, foam and gas drilling fluids are:

Controlling lost circulation

Reducing or avoiding formation damage and improving production

Increasing ROP

Controlling Lost Circulation

If the cause of lost circulation is due to the differential pressure between the column of fluid in the annulus and the pore pressure in the formation, then a reduction in the hydrostatic pressure in the annulus will generally result in a reduction in the rate of flow into the formation (losses). If the hydrostatic pressure can be reduced to or below the pore pressure, losses can be stopped entirely. The use of gas to reduce the effective mud weight, or drilling entirely with a gas or foam, can drastically lower the annular fluid density, reducing or eliminating losses. This effect can be understood by looking at the simplest form of the flow equation (Darcy's Law for a linear system, i.e. a lengthwise coreflood).



where q is the flow rate, k is permeability, µ is the fluid viscosity, P1 and P2 are the pressures on either side, and L is the length.

As the difference between P1 and P2 is reduced, the rate of flow drops. Additionally, as this pressure variation is the cause of differential sticking, the reduction in annular pressure can help to alleviate this drilling problem.

Operationally, controlling losses with a reduced density drilling fluid can be done in two ways; using a reduced density system from the beginning of the zone (expecting losses and drilling the entire interval under-balanced), or by having the system on standby and utilizing it only once losses are encountered. With these systems, some gas may enter the formation as bubbles which blocks pore throats, further reducing losses, but potentially impairing productivity and logging.

Reducing Formation Damage and Improving Productivity

As with any under-balanced drilling operation, systems utilizing gases to reduce density can significantly reduce formation damage. This is possible due to the reduction or elimination of drilling fluid invasion into the formation. Without invasion, native permeabilities remain undisturbed and the formation's original wettability is unchanged. Fine particles in the drilling mud do not enter the formation to plug pore throats and precipitation from chemical interactions is avoided. As a result, the well’s skin factor is significantly reduced and higher production is possible. Additionally, the wells may require less stimulation to bring them on line, saving



time and cost. These effects are particularly pronounced in lower permeability formations, especially with gas. The difference may not be so evident in higher permeability or fracture formations, or wells that undergo hydraulic fracturing.

Increasing ROP

One of the advantages of drilling with a lower density fluid is the improvement in the rate of penetration. This occurs with all fluids, not just ones utilizing gases. But, with the low densities achievable with gases, the increase in ROP can be very significant. The increase is due to the reduction in the confined compressive strength of the rock. The confined compressive strength can be described as a measurement of the hardness of the rock, which takes into account the pressures surrounding it. By reducing the annular pressure, the confined compressive strength is decreased. The impact of this can be seen in the following equation, which comes from the Chevron Specific Energy Rate of Penetration (SeROP) model.

13.33 µ N

DBCCS

EFFM WOB1AB

where ROP is the rate of penetration, µ is the bit coefficient of sliding friction, N is the bit RPM, DB is the bit diameter, EFFM is the bit mechanical efficiency, CSS is the compressive confined stress, WOB is the weight on bit, and AB is the borehole area.

Reducing the mud weight by even a few pounds per gallon below the pore pressure can result in doubling or more of the ROP. Care must be taken in such situations to ensure good hole cleaning, as the cuttings load will



dramatically increase because the hole cleaning capacity of aerated fluid, foam, or pure gas system is significantly less than that of a conventional fluid. More than one well has encountered a cuttings pack-off after not adjusting drilling practices to compensate for higher ROP.

System Types

Systems utilizing gases can be broken into three categories: aerated drilling fluids, foam systems, and dry gas (air and gas drilling). Table 13-1 provides a brief description of the systems and applications.

System Description Applications

Aerated drilling fluid

Air/nitrogen is added into drilling mud. The liquid is the continuous phase.

The air bubbles expand in the annulus, reducing hydrostatic pressure.

Few or no additives are required.

Shallow wells with low pressure formations

Unconsolidated or weak formations

As a contingency for normal operations to control losses

Foam A polymer and/or bentonite slurry is mixed with compressed air to form a continuous bubble phase.

Foaming additives are necessary to create and maintain the system.

Less phase separation than aerated fluids, while achieving lower densities.

Can be used in place of air drilling in water bearing formations or larger hole sizes.

Dry gas (air drilling)

High volumes of air/gas are pumped. Little or no fluid is in the system.

Used for extremely low pressure formations

Typically for slim hole applications

Cannot tolerate water

Table 13-1: Gas, foam and aerated system descriptions and applications



Aerated Drilling Fluids

Aeration refers to the introduction of air into a fluid. In the context of drilling operations, aeration is the use of a compressor unit to create high pressure gas which is injected into a drilling mud. Two gases are primarily used: air and nitrogen. Both will be discussed in this section, but the generic term “air” will be used to denote both, unless otherwise specified.

The aeration of a drilling fluid is one of the simplest ways to control losses, reduce formation damage, and increase ROP. The air is injected into the flow system, usually at the standpipe, resulting in bubbles in the liquid flow. As air is compressible and the flow line pressure is significantly higher than atmospheric pressure, the bubbles are quite small and do not significantly affect the density of the fluid in the drillstring. As the bubbles reach the annulus, the pressure reduces and the bubbles expand. This in turn causes the effective mud weight to drop. Additionally, as the bubbles expand the bulk flow rate of the mud increases. For example, if 300 gallons of air are injected per minute into the standpipe where the mud flow rate is also 300 gallons per minute, the total flow rate of the aerated fluid will be just over 300 gallons per minute in the standpipe, but almost 600 gallons per minute at the bell nipple. It should be noted that at higher air injection rates and/or significant hole deviation, separation can occur between the air and liquid phase. The result is the alternation of slugs of air and liquid arriving at the surface.

Aerating fluid is most effective in shallow wells and very significant drops in ECD can be seen for air injection rates within the range of standard units.

Figure 13-1 shows the effect of aeration on equivalent circulating density for an example well. An 8.5-inch hole size is assumed and the liquid flow rate is 300 gpm for a 9 ppg drilling mud. The graph shows various air injection



rates, ranging from 300 to 3,000 gpm of air (1:1 ratio to 10:1 ratio of air to liquid). This is in the range of a standard size compressor unit. It can be seen that at shallow depths, the effect is quite pronounced, even at relatively modest air flow rates. As depth increases, the effectiveness of the aeration diminishes rapidly, and at 10,000 feet, even at the highest flow rate, less than a 2 ppg reduction is seen.

Figure 13-1: Equivalent circulating density for example well

Equipment

The equipment required to adapt a normal drilling rig to aerated operations is relatively simple and can usually be obtained, or in some cases fabricated, without too much difficulty. The main items are as follows:

Rotating Head: A rotating head is needed to divert pressurized mud, otherwise flow may



come up the BOP onto the rig floor. A drilling rub is stabbed into on the rotating head to create the necessary seal. High and low pressure rotating heads are available and should be properly sized to the intended operations.

Closed Flow Ditch: This is required to prevent spillage of the aerated fluid over the location. This can have baffle plates installed, allowing it to operate as a "Poor-boy degasser".

Possum Belly Cover: Installed on top of the possum belly. It is used to contain the high pressure mud when returns approach. This prevents a spray of mud that could pose a safety hazard.

Flow “Y” Connection: Should be designed to reduce the vibration where air is injected into the mud on the standpipe. A smooth collision is needed in this system so that vibration will be reduced which will help on the wear on the pump and eliminate the pop-off from falsely releasing.

Air Compressor: Usually a standard air/nitrogen compressor unit offered by many service vendors. Care should be taken to acquire a unit with specifications that meet the required flow rates at standpipe pressures.

Drillpipe Check Valve: Used to hold the back pressure in the drill string, eliminating the pipe from U-tubing.

Drillpipe Bleed off: Used to release the pressure in the drillpipe below the check valve.

Drillpipe Stabbing Cone: The cone is used to stab the drillpipe through the rotating head rubber.

Gas Hog: Installed to increase the efficiency of breaking the air out of solution.



Modification may be needed on certain parts of the rig, including upgrading the pop-off valves, installing dresser sleeves, and so on. In some cases, when only a small amount of aeration is desired, air can be sucked in through a rig hopper, avoiding the need for a compressor and associated equipment.

Determining the density of the fluid to determine downhole pressures can be problematic due to the gas in the mud. The use of a pressurized mud balance can give an accurate measurement. If one is not available, ensure that the fluid sample is mixed or stirred until as much air as possible is removed from the mud before measuring the density.

The use of an aerated drilling fluid is either throughout an entire section, or brought in to combat specific losses. If aeration is being used throughout the section, all equipment needs to be in place before drilling begins. At each connection, the injected air needs to be turned off prior to breaking the connection. This is an important safety point and good communication is vital between the injector personnel and the rig crew. If a removable drillpipe check valve is being placed in the drillpipe, it needs to be moved to the new stand to be drilled. If aeration is a contingency for losses, all of the equipment, except for the injection unit and rotating head, may be rigged up at the beginning of a job. When severe losses are encountered, some time may be needed to prepare additional mud volumes before proceeding. During this time, the injection unit can be rigged up to the standpipe and the driller can stab into the rotating head rubber. As operating procedures are different than with normal drilling, a safety meeting should be held to ensure that there is proper management of change, good communication and that all appropriate practices are followed.



Aerated Mud Properties

The required fluid properties vary depending on the application and depth of the well. Density, solids content, gel strengths, and plastic viscosity must all be controlled at low and constant values. The yield point will depend on the type of fluid being used, but should be in a proper range with respect to the plastic viscosity. Yield point control is required in order to allow the air to be removed when it reaches the surface. Injection pressures will remain low if hydrostatic pressure and system pressure losses are maintained at low values. As well depth increases, controlling hydrostatic and system pressure losses becomes more important in order to avoid surpassing the capabilities of the air equipment. Maintaining a pH above 10 will assist in corrosion control. However, higher pH could cause polymer precipitation or cuttings dispersion, depending on the type of mud being used.

Common Aerated Fluid Types

Some common fluids used in aerated drilling are low-solids and non-dispersed (LSND) muds and salt muds. LSND muds are especially good with aerated drilling muds because they offer shear thinning properties which give low circulating pressures. Their major drawback is a tendency to disperse cuttings at a high pH, so care must be exercised when selecting additives in order to prevent dispersion. Potassium chloride muds are very successful in solving unstable shale problems in air-liquid circulating systems. Potassium hydroxide should be used for pH control. Fluid loss control may be obtained by using polyanionic cellulose. The major disadvantage of salt water muds is a higher corrosion rate compared to fresh water muds. Removal of entrained air or gas from a salt water mud can be difficult. Table 13-2 lists some typical additives in an aerated system. It should be noted that



aerated systems can function with no additional additives beyond the initial mud formulation, but in some cases, adjusting mud properties is important to produce good results.

Additive Function Typical Concentration (lb/bbl)

Bentonite Provides viscosity and wall cake

3 to 12

Partially hydrolyzed polyacrylamide (PHPA)

Creates viscosity and shale stability

0.5 to 1.5

Polyanionic cellulose polymer (PAC)

Fluid loss control

.5 to 1.5

Lime Inhibits corrosion

0.8 to 1.5

Foaming agent To initial aeration

As needed, this is option if returns are problematic

Table 13-2: Typical additives in an aerated system

Some common issues with aerated fluid include hole cleaning, intermittent returns, corrosion, HES risks of flowable hydrocarbons, logging, downhole tools, and cementing.



Hole Cleaning

Air entrained in the fluid can affect the rheological properties of the mud, reducing its effectiveness at hole cleaning. Some basic remedies include increasing the yield point of the mud through gel additives and polymers. Foamers can be added to get a more foam-like flow, but these can lead to cavitation problems with the mud pumps, as all of the bubbles may not break out of solution. Higher ROP’s and intermittent flow can exacerbate the situation. Controlled drilling is recommended, and the volume of cuttings coming over the shaker needs to be monitored. This takes some experience to see what the normal volume of cuttings is per stand, especially if flow is intermittent. Once this is established, the amount of time circulating per connection can be modified to match cuttings returns. It should also be remembered that cuttings are likely to fall back during connections, so care should be taken not to pull into a tight spot once the connection is made.

Intermittent Returns

As the bubbles of air expand in the annulus, it is possible for them to form large slugs of gas. This is more problematic in deviated wells, where gravity separation can occur, and with higher air flows. The lower the gel strength and yield point, the more likely this is. The slugs of air can be seen on surface as periods of no returns followed by large volumes of mud and cuttings coming at once. This sudden volume of mud can be quite dramatic and even mistaken for a kick if no one is expecting it. A covered possum belly and enclosed flow ditch are very important in these situations to prevent large volumes of mud spill on the location, thus causing an HES hazard. Thought must be given to how the higher flow rate will be dealt with at the shakers. When a large volume of liquid overwhelms the shaker capacity, it must be



properly contained, even if that just means spilling directly into the pits.

Another situation that can arise in a high permeability loss zone is localized charging of the formation with fluid. Typically, this happens when aeration is used only after losses have occurred. Initially, the annular pressure is too high and fluid flows into the formation. As the fluid level drops and the air is injected into the system, the annular pressure reaches the point where the localized formation pressure is high enough to start returning fluid back into the annulus. As the amount of fluid pumped into the loss zone may significantly exceed the total hole volume, once returns begin the fluid capacity of a small rig may be overwhelmed. In this case, flow must be diverted to the pit or some alternative short term storage, such as a vacuum truck.

Corrosion

The injected air contains oxygen and carbon dioxide, both of which are corrosive. The corrosive effect is a function of the exposure time and volume of air pumped. Various chemical additives may be added to prevent corrosion, either by neutralizing the oxygen in the mixture (oxygen scavenger) or by coating the pipe. Additionally, scale inhibitors may be added. Maintaining a pH above 10 will tend to help control corrosion, but care must be taken so that an overly high pH does not cause cuttings dispersion. If the aerated portions of wells are short in nature and inspections are regular and rigorous, it may be possible to operate without additional additives, as long as caution is exercised.

Flowable Hydrocarbon Zones

If an air-based aerated fluid is used to drill through a formation that bears flowable hydrocarbons, there is the



possibility of creating a combustible mixture. With a rotating bit and drillpipe, an ignition source is also present. Obviously, this is a very dangerous situation and should be avoided. In the planning phase of a well using air, all formations that could be drilled through should be analyzed to ensure that they do not have the potential to create this hazardous situation. If there is a chance or even the possibility of a chance, air should be replaced with nitrogen.

Logging

An aerated drilling fluid can cause some issues when logging. The bubbles entrained in the fluid can enter the formation or remain in the fluid during logging. This can significantly impact some logs such as sonic and neutron logs. If aerated fluids have been used in a section that is being logged, it is important to inform the logger and the formation evaluation personnel involved. Pumping unaerated fluid just before the logging can alleviate some of the log interference, but bubbles in the formation may still cause issues. In lost circulation situations where aeration has been used, it can be difficult to maintain the fluid column high during a wireline logging run. If fluid can be pumped in, that may be an option, otherwise the logging operation must be run as fast as safely possible to ensure that the borehole at the formation of interest is still full of fluid, as most logging sensors require fluid in order to function properly.

Downhole Tools

An aerated fluid can pose problems to some downhole tools. Most MWD tools that send a signal through the drilling fluid cannot tolerate more than a few volume percent air before the transmission begins to degrade.



The use of EMAG™ MWD tools is a way of avoiding this. Otherwise, this may be a limiting factor in directional wells. Downhole motors come in a variety of configurations that can tolerate aeration all the way to the point of being powered by only air. Pre-job planning is important to ensure that the directional drilling service provider can meet the required equipment specifications.

Cementing

As with any other under-balanced drilling operation, cementing jobs can be problematic. Various solutions exist, including foam and reduced density cement formulations. These can be effective in some situations, but as aeration has been used to combat severe losses, these expensive cements may just be pumped into the formation. In such cases, sometimes it is necessary to simply pump a large volume of cheap cement and, if cement is not seen at surface, pump a top job to meet well requirements.

Nitrogen in Aerated Fluid Applications

Nitrogen can be used instead of air in the aeration of a drilling fluid. It functions in the same way as air and, since the majority of air is nitrogen, very similar density reductions are possible. Nitrogen offers a few key advantages over air in aeration applications.

Nitrogen is not flammable. This means that it can be used when drilling through hydrocarbon-bearing formations that would otherwise prevent an unacceptable HES risk. Care must be taken at the surface to separate, treat, and/or dispose of the hazardous formation gas.



Nitrogen is not corrosive. As a result, corrosion additives are not necessary. This makes nitrogen the gas of choice when corrosion concerns are critical or when pipe and casing may be exposed to gas for extended periods.

Nitrogen does have one significant drawback: cost. While a compressor unit can take air directly from the atmosphere, nitrogen requires pressurized tanks to supply the necessary gas for operations. This is an added expense, although many compressor units can be rigged up to use either air or nitrogen. In many cases, nitrogen is recovered by a degasser, allowing for reuse of the gas, but again this is an extra piece of equipment.

Foam Drilling

Drilling foams utilize a mixture of water, surfactants, polymers and/or bentonite for gel strength and yield point, and sometimes anti-corrosion agents. Foams have a much higher air to liquid ratio as compared to an aerated system and consist of at least 70% gas by volume. This translates to lower pressures and greater under-balance. At the same time, foam systems are far more tolerant to fluid influxes and can transport more cuttings than a pure air or mist system, although salt water and hydrocarbons can damage foam quality. If the foam is properly generated, it will have a very stable continuous phase. This is particularly helpful in deviated wells where flow separation is problematic for aerated fluids. The disadvantage is the specialized equipment needed and associated costs. Foams are typically mixed in a dedicated foaming unit, but the essentials for foam operations are an air compressor, tanks for blending, water, detergent and additives, a detergent solution pump, a foam generator and injection manifold. Logging can also be problematic depending on the tools and



measurements and can limit the use of foams if open hole logs are a requirement.

Properly made up foam should end up having a shaving cream like consistency. On close examination, a honey-comb like structure can be observed. As the foam will have less kinetic energy than normal or aerated fluid, high annular velocities are necessary to transport cuttings out of the wellbore. This often translates to 100 to 200 ft/min near the surface. As a result, air to fluid ratios are in the range of 100:1 to 300:1. Table 13-3 shows a typical formulation for a foam liquid phase.

Additive Concentration (lb/bbl)

Volume % Function

Prehydrated Bentonite 10 to 15 - Builds Foam Structure

Carboxymethylcellulose (CMC)

0.5 - Foam Stabalizer and Drying Agent

Guar Gum 0.2 to 0.5 - Foam Stabilizer

Soda Ash 0.5 to 1.0 - Calcium Treating Agent

Caustic Soda/Caustic Potash

0 to 0.5 - Corrosion Protection

Foaming Agent - 1% Stabilizes Air in Liquid

Potassium Chloride - 3-5% Shale Stabilizer

Filming Amine - 0.5% Corrosion Protection

Table 13-3: Example foam formulation



The quality of foam is important in ensuring good hole cleaning and efficient drilling. Table 13-4 shows some common problems in foam drilling and standard treatments.

Problem Probable Cause Treatment

Quick drop in pressure

Gas has broken through the foam mix, thereby preventing the formation of stable foam

Increase the liquid injection rate and/or decrease the air injection rate

Slow increase in pressure

Increase in cuttings, or fluid from the formation is being carried to the surface

Increase the gas / air injection rates

Fast increase in pressure

Plugged bit or the formation has packed-off around drillpipe

Stop drilling and attempt to regain circulation

Gas blowing free with mist of foam

Gas has broken through the foam mixture, preventing the foam from becoming stable

Increase the liquid injection rate and/or decrease the air injection rate

Thin and watery

Two reasons: 1. Salt water from the formation is diluting the foam 2. Oil from the formation is contaminating the foam

Increase the gas / air injection rates, as well as the % of foaming agent

Table 13-4: Foam drilling problems and treatments

Operationally, foam drilling is similar in many ways to aerated drilling, but it is far rarer to transition from a



normal fluid to a foam fluid in the middle of a section. It is sometimes necessary to transition from air drilling to foam drilling if flowing fluids are encountered, or hole cleaning is inadequate. As with aerated drilling, it is important to make sure that the rig crew is aware of the additional safety concerns, such as ensuring that the foam injection is turned off during connections.

Dry-Gas Drilling (Air Drilling)

Applications for dry-gas drilling are in hard formations where water or oil flows are not likely to be encountered and areas where drill water is scarce. Dry-gas drilling uses compressed air or natural gas to cool and lubricate the bit, to remove the cuttings from around the bit and to carry them to the surface. Dry gas is injected down the drillpipe while drilling and the cuttings are returned to the surface as fine particles. The returns are vented away from the rig in order to minimize the noise and dust. Cuttings are caught by a specially designed screen at the end of the blooey line or a specially designed sample catcher.

In dry-gas drilling operations, the bottom-hole pressure consists of the weight of the gas column, plus the annular and blooey line pressure losses. The sum of these pressures will usually be far less than the formation pressure. Thus, the rate of penetration can be very rapid due to the low hydrostatic pressure. Chip-hold-down is also eliminated, making cuttings release from the bottom of the hole much more efficient. Overall, dry-gas drilling offers economic advantages in high ROP and lower operational costs per foot of hole, as compared to mud drilling. Dry-gas drilling operations require special and careful planning. Gas compressibility is a significant engineering consideration during both planning and drilling phases. Other equally important



considerations are annular velocity requirements and logging suite selections.

Gas annular velocity, rather than fluid rheology, is the primary factor for cuttings transport when drilling with dry gas. The annular velocity necessary to lift cuttings determines the volume of gas that must be circulated. These annular velocities are such that turbulent flow always exists. To lift 3/8 inch to 1/2 inch cuttings, as a general rule, an annular velocity of about 3000 ft/minute is required. Although most air- or gas-drilled cuttings are quite small (dust particle size) when they reach the surface, they are larger when they leave the bottom of the hole. The milling action of the drillstring, impact with other cuttings, and regrinding of large particles at the bit are responsible for pulverizing them.

Logging is another factor to consider when drilling with dry gas. Wellbores containing no fluid other than air or gas can only be surveyed with devices that need no liquid to establish contact with the formation. The Induction Log is the only tool which can measure formation resistivity in such holes. In multiple-zone production, the Temperature Log indicates the relative volumes of gas coming from each zone. The Noise Log may be used to record zones of liquid or gas influx as well as zones of severe loss. A relative amplitude log is recorded and the noise may be monitored at the surface.

Water-bearing formations are the greatest limiting factor to air or gas drilling. Small amounts of water can be tolerated by adding drying agents such as CMC to the dry gas to absorb the water. However, if the cuttings become too moist they will stick together to form mud rings which can block the annulus. If this occurs, loss of circulation, stuck pipe, or even a downhole fire may result.



Air

Air drilling is commonly used in areas where loss of circulation with liquid type muds is a major problem. Air is also used to drill hard, extremely low permeability rock or formations. When drilling gas-bearing formations the risk of downhole fires can be high. The chance of a downhole fire when gas is present is increased if the annulus becomes restricted, thus increasing the pressure below the obstruction. Mud rings can cause this type of problem. The standpipe pressure must be continually monitored in order to detect and prevent an excess pressure buildup. Even an increase in pressure of about 15 psi can cause combustion to occur. Several downhole tools have been designed to help combat fire hazards. The Fire Float and Fire Stop are two of these tools. The Fire Float is installed above the bit as a near-bit protector. Under normal conditions it allows flow of air while drilling, but does not allow back flow of air. If the heat-sensitive ring is melted away by a downhole fire, a sleeve falls and stops air flow in either direction. A Fire Stop unit should be located at the top and midway in the drill collar assembly. It consists of a simple flap retained by a heat-sensitive zinc band. When the melt temperature of the zinc band is exceeded, the flap closes and air flow is halted. A quick rise in pressure at the surface is noted which alerts the crew to the likelihood of a fire.

Volume and pressure requirements must be considered when selecting equipment for an air drilling program. Surface pressure is determined by the total system pressure losses. Atmospheric pressure decreases with increasing elevation and relative humidity decreases with increasing temperature. Equipment requirements for a location which is situated at a high elevation in a hot and dry climate are considerably different than requirements for one which is in a cold, humid climate at



sea level. As a rule of thumb for compressors, there is a 3% loss in efficiency per 1000 ft of elevation.

Natural Gas

Natural gas, rather than air, is used as the circulating medium when reservoirs contain appreciable quantities of gas. Air cannot be used because of the danger of downhole fires. The gas is compressed in the same manner as air, but the return gas must either be flared or collected to be put into a pipeline. Recycling of the gas is not recommended because of the abrasive particles in the used gas which would tend to damage the compressors. Fire and explosion hazards around the rigsite, due to gas leaks, are a constant danger when drilling with natural gas.

References


REFERENCES The following reference information is provided to assist readers in locating supporting information for various sections of this handbook.

CHAPTER 2: Drilling Fluid Properties

"Fluids Facts Engineering Handbook", Baker Hughes Drilling Fluids, 2009.

"Drilling Fluids Course Manual", Unocal, 2002.

"Drilling Fluids Manual", Drilling Training Alliance, Chevron and BP, 2007.

CHAPTER 3: HES Impacts of Drilling Fluids

“Environmental Aspects of the Use and Disposal of Non Aqueous Drilling Fluids Associated with Offshore Oil & Gas Operations”, International Association of Oil & Gas Producers, Report No. 342, May 2003.

“Composition, Environmental Fates and Biological Effect of Water Based Drilling Muds and Cuttings Discharged to the Marine Environment: A Synthesis and Annotated Bibliography”, Jerry M. Neff, Petroleum Environmental Research Forum (PERF) and American Petroleum Institute, January 2005.

“Drilling Fluids and Health Risk Management, a Guide for Drilling Personnel, Managers and Health Professionals in the Oil and Gas Industry”, International Association of Oil and Gas Producers, 2009.

References


CHAPTER 4: Water Base Drilling Fluids


CHAPTER 5: Non-Aqueous Fluids


CHAPTER 6: Chemistry Concepts

“Chemistry Concepts”, Ben Bloys, Chevron ETC, 2004.

CHAPTER 7: Hole Cleaning

"Drilling Fluids Course Manual", Unocal, 2002.



"Applied Drilling Engineering", A.T. Bourgoyne, K.K. Millhelm, M.E. Chenevert, F.S. Young SPE, 1991.

"Drilling Engineering", J.J. Azar, PennWell, 2007.

CHAPTER 8: Solids Control Equipment

“Solids Control Handbook”, Chevron, 1996.

References


CHAPTER 10: Common Drilling Fluid Related Problems

“Lost Circulation Prevention and Mitigation”, Chevron ETC, 2007.



"Applied Drilling Engineering", A.T. Bourgoyne, K.K. Millhelm, M.E. Chenevert, F.S. Young SPE, 1991.

CHAPTER 11: Fluids-Related Productivity Optimization

“Drilling Fluids Manual”, Baker Hughes Drilling Fluids, 1991.

CHAPTER 12: Corrosion and Acid Gases

“Drilling Fluids Manual”, BP and Chevron ETC, 2002.

“Drilling Fluids Manual”, Baker Hughes Drilling Fluids, 1991.

“Manual of Drilling Fluids Technology”, Halliburton Fluid Services, 1996.

“Drilling Fluids Engineering Manual”, M-I SWACO, 1998.

References


CHAPTER 13: Gas, Foam, and Aerated Drilling Fluid Systems

"Aerated Mud in Loss Circulation Zones", Jeff Wood and Ian Harris, Chevron Report for San Joaquin Valley Strategic Business Unit, 2008.


"Baroid Fluids Handbook", Halliburton, 1999.

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