HdBk Drilling FLUIDS

Energy Technology Company Drilling & Completions Fluids & Waste Management Team

Drilling Fluids Handbook

Version 2-09 November 2009

©2009 by Chevron Energy Technology Company All rights reserved. This document is company confidential. 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 Disclaimer The 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.

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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 Drilling Fluids Handbook, Version 2-09

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

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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 Drilling Fluids Handbook, Version 2-09  

 

 

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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

Drilling Fluids Handbook, Version 2-09

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

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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 Drilling Fluids Handbook, Version 2-09  

 

 

Chapter 1: Introduction

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. Energy Technology Company | 1

 

 

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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.

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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 nonaqueous drilling fluids in the North Sea/OSPAR regulated areas.

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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 formation fractures

o

Stuck pipe

o

Reservoir damage due to increased filtrate invasion

to

induced

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.

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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.

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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

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Plastic Viscosity (PV) Rheological measurements are usually made on a 6speed 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

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depict the average solids range of water base and nonaqueous fluids, respectively.

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

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

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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

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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.

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Chapter 2: Drilling Fluid Properties



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

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(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.

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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

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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

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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 nonNewtonian behavior.

Bingham Plastic The Bingham Plastic model is the most common model used to describe the rheological properties of nonNewtonian 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

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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

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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

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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

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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.

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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

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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

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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 watersoluble 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

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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

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Chapter 2: Drilling Fluid Properties 

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.

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Chapter 2: Drilling Fluid Properties

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.

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Chapter 2: Drilling Fluid Properties 

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

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Chapter 2: Drilling Fluid Properties

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 nonconductive; 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

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Chapter 2: Drilling Fluid Properties 

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

1.

Zinc Oxide

NAF

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

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Chapter 2: Drilling Fluid Properties

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:

(VW ) WP  100 VO VW 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:

BP 

100 (VB ) VO VB

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

OP = 100 – Bp

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Chapter 2: Drilling Fluid Properties 

 

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Chapter 2: Drilling Fluid Properties 

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.  Compound/Ion

Anhydrite, Gypsum

CaSO4, CaSO4 · 2H2O / Ca+2, SO4-2

Formation, Commercial gypsum

Ca+2 titration

MgCl2

MgCl2 / Mg+2, Cl-

Formation, Sea water

Total hardness, Cl- titration

Cement, Lime

Ca(OH)2 / Ca+2, OH-

Source

Method of Measurement

Contaminant

Cement, Commercial lime, Contaminated barite

Titration for Ca+2, Pm

Possible Effect on Fluid High yield point High fluid loss High gels Thick filter cake Ca+2 increase High yield point High fluid loss High gels Thick filter cake Total hardness increase pH decrease Pf decrease Cl- increase High yield point High fluid loss Thick filter cake pH increase Pm increase Ca+2 increase

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

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. 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

 

 

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Chapter 2: Drilling Fluid Properties  

Contaminant

Compound/Ion

 

Source

Method of Measurement

 

Possible Effect on Fluid

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

Cement, Lime (cont’d.)

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

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

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

Hydrogen Sulfide

H2S / H+, S-2

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

Treat with gypsum: CO3-2 (mg/L) x0.001 = CaSO4 · 2H2O lbm/bbl and caustic soda: HCO3- X 0.0025 = NaOH lbm/bbl

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

 

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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 Energy Technology Company | 32

Chapter 3: HES Impacts of Drilling Fluids

(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.

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Chapter 3: HES Impacts of Drilling Fluids

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 Energy Technology Company | 34

Chapter 3: HES Impacts of Drilling Fluids

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

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Chapter 3: HES Impacts of Drilling Fluids

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.

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Chapter 3: HES Impacts of Drilling Fluids

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 Energy Technology Company | 37

Chapter 3: HES Impacts of Drilling Fluids

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 sediments decline traditional mineral recovered the most environments with biological activity.

that synthetic base mud levels in much more rapidly than with oil base mud. The areas that rapidly were those in higher energy plenty of aeration, mixing and

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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.

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Chapter 4: Water Base Drilling Fluids

Concentration Fluid Type

Product (lb/bbl)

Fresh water spud fluids

Bentonite

20 - 25

Lime

1–2

Soda ash

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

Salt water

Salt Water Gel

25 - 35

Sea water/ pre-hydrated gel

Bentonite

30 - 40 (Pre-hydrate in freshwater)

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

Caustic Lime

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

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Chapter 4: Water Base Drilling Fluids

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 lowyield 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.

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Chapter 4: Water Base Drilling Fluids

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

34 - 38 sec/qt

Plastic viscosity

5 - 7 cp

Yield point

6 - 9 lb /100 ft2

Gels

4 - 6 lb /100 ft2

Filtrate

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.

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Chapter 4: Water Base Drilling Fluids

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

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Chapter 4: Water Base Drilling Fluids



[Cl–], 5000 freshwater



[HCO3–], [CO3-2] should be minimized

to

10,000

mg/L:

dilute

with

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

LowDensity Solids

Calcium

_

Normal

Normal

High

Normal

_

High

High

High

Normal

Treatment

Increase settling time

Weight too high

Add extender or flocculant Potential bentonitic formation Dilute, add extender

Normal

_

High

Normal

Normal

Normal

_

Low

High

Normal

Dilute, add extender Stop adding bentonite Add extender and bentonite Check solids equipment

Viscosity too high

Viscosity too low

Use solids control equipment

High

_

High

High

Normal

Normal

_

Normal

Normal

Normal

Normal

_

Normal

High

High

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

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Add extender and water Add extender Add soda ash and extender or flocculant

Treat calcium with soda ash

Chapter 4: Water Base Drilling Fluids

Problem

Fluid loss too high

Weight

Viscosity

MBT

LowDensity Solids

Calcium

Treatment

_

Normal

Low

Normal

Normal

Add bentonite and extender

Normal

Normal

Normal

Add SPA, or CMC

Normal

Normal

High

_

_

High

Remove calcium with soda ash or bicarbonate of soda

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

Problem

Viscosity too low

Viscosity too high

HTHP Fluid loss too high

Weight

Viscosity

MBT

LowDensity Solids

Calcium

Treatment

Normal

_

Low

Normal

Normal

Add extender and bentonite

Normal

_

Normal

Normal

Normal

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

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)

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,

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Chapter 4: Water Base Drilling Fluids

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

Fresh

Sea

Water

Water

Fresh water

100

Sea water

~

NaOH/KOH NaCl, % by wt KCl, % by wt

NaCl

KCl

50

50

100

50

50

~

*

*

*

*

~

~

Up to 20%

~

~

~

~

Up to 15%

Bentonite, lb/bbl

10-20

10-20**

10-20**

10-20**

XCD POLYMER™, lb/bbl

~

0.1-0.5

0.1-1.0

0.1-1.0

PAC Regular

0.5-1.0

0.5-1.0

0.5-2.0

0.5-2.0

PAC LV

0.5-1.0

0.5-1.0

0.5-2.0

0.5-2.0

LIGNITE

1.0-6.0

2.0-8.0***

2.0-8.0***

2.0-8.0***

Starch

~

1.5-2.0

1.5-3.0

1.5-3.0

Modified Starch

0.5-6.0

0.5-6.0

1.0-8.0

0.5-8.0

Sodium Polyacrylate (SPA)

0.25-2.0

0.25-2.0

0.25-2.0

0.25-2.0

DESCO™

0.25-5.0

0.25-5.0

0.25-5.0

0.25-5.0

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

Make-Up Water (% by vol.)

Electrolyte

Viscosifier

Fluid Loss (lb/bbl)

Rheology (lb/bbl)

Shale-Control Additives

*

To pH = 10.0

**Pre-hydrated in fresh water ***Pre-hydrated in pre-mix

Table 4-6: Low pH/polymer formulations

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Chapter 4: Water Base Drilling Fluids

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.

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Chapter 4: Water Base Drilling Fluids

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.

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Chapter 4: Water Base Drilling Fluids

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 presolubilize 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, supplemental shale control additives

and

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)

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Chapter 4: Water Base Drilling Fluids

3. Lignite 4. PHPA 5. Starch 6. Supplemental SOLTEX)

shale

control

additives

(e.g.

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

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Chapter 4: Water Base Drilling Fluids

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

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Chapter 4: Water Base Drilling Fluids

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

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Chapter 4: Water Base Drilling Fluids

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. MILR) 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.

PAC™



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.

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Chapter 4: Water Base Drilling Fluids



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

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Chapter 4: Water Base Drilling Fluids

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.

Chloride Concentration Classification

(Cl-), mg/L

Brackish

10,000

Sea Water

~18,000

Saturated Salt Water

>190,000

Table 4-8: Salt water mud classifications

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Chapter 4: Water Base Drilling Fluids

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

10,400

Potassium

375

Magnesium

1,270

Calcium

410

Chloride

18,970

Sulfate

2,720

Carbon dioxide

90

Density ~8.5 lb/gal Table 4-9: Typical sea water analysis

Product

Concentration, lb/bbl

Pre-hydrated Bentonite

30-35

Lignosulfonate

4-6

Caustic Soda

0.2-0.5

Defoamer

As needed

Table 4-10: Sea water mud formulation

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Chapter 4: Water Base Drilling Fluids

Pre-hydrated bentonite procedure: 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 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.

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Chapter 4: Water Base Drilling Fluids

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.

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Chapter 4: Water Base Drilling Fluids



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.

Product

Concentration, lb/bbl

NaCl

110

Pre-hydrated bentonite

10 - 15

PAC

0.5 - 2.0

PAC LV

0.5 - 2.0

Starch

1.5 - 3.0

PHPA

0.25 - 4.0

Defoamer

As required for foam

Lignosulfonate

2.0 - 6.0

Caustic soda

pH = 7.0-8.0

Pre-hydrated lignite

2.0 - 8.0

Table 4-11: Saturated salt fluid formulation

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Chapter 4: Water Base Drilling Fluids

Maintenance 

Add sacked salt to maintain saturation



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

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

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Chapter 4: Water Base Drilling Fluids

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

12 - 20

Lignosulfonate

2-8

Caustic soda

(for pH of 9.5 - 10.5)

Lignite

As needed

High Temperature Polymer Thinner

As needed

High Temperature Fluid Loss

As needed

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

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Chapter 4: Water Base Drilling Fluids

Density, lb/gal

Plastic Viscosity,

Yield Point,

Gel Strengths, lb/100 ft 2

API Filtrate,

cp

lb/100 ft2

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

10sec 10 min

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.

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Chapter 4: Water Base Drilling Fluids



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 dispersion



Minimized bit balling and accretion



Low friction factors for torque and drag reduction



Fairly high rates of penetration



Reduced differential sticking

shale

hydration,

swelling

&

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Chapter 4: Water Base Drilling Fluids



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.

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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

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Chapter 5: Non-Aqueous Fluids

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.

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Chapter 5: Non-Aqueous Fluids

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

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Chapter 5: Non-Aqueous Fluids

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

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Chapter 5: Non-Aqueous Fluids

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

PETROFREETM TM

PETROFREE LV FINAGREEN

TM

SBF Type

Manufacturer

Density, g/mL

Pour Point, o C

Flash Point, o F

Viscosity @ 40 oC, cSt

Ester

Cognis

0.86

-30

354

6

Ester

Cognis

0.86

297

3.2

Ester

Fina

0.85

-30

300

5

AMODRILL 1200

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 130

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

Linear Paraffin

PetroSA

0.79

205

2.8

TM

TM

MOSSPAR H

TM

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Manufacturer

Density, g/mL

Pour Point, o C

Flash Point, o F

Viscosity @ 40 oC, cSt

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

Commercial Name

SBF Type

BAROID ALKANETM

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

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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

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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

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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

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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

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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. EMULSIFIED WATER DROPLET IN OIL

SURFACTANT

HYDROPHILIC HEAD

ORGANOPHILIC TAIL

Figure 5-1: Emulsion

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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 contaminants



Emulsified water is colloidal in size



Overtreatment may increase kinematic viscosity of base fluid



Relatively inexpensive emulsifiers

to

high

temperature

compared

to

and

other

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,

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

or

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 kinematic viscosity of base fluid



Relatively expensive emulsifiers

compared

not to

increase primary

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.

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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).

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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.

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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 bottomhole 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

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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

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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

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

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.

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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

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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.

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Problem

Indications

Causes

1. Inadequate shear Poor emulsion (low ES) stability. Mixing fluid at the mixing plant

Lost circulation

High viscosity

Barite settling. Dull grainy appearance of fluid. Fluid very thin with inadequate yield or gel strength.

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

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

Hydrostatic pressure is greater than formation pressure.

1. High solids content. 2. Water contamination. High PV and YP.

3. Improper OWR/SWR. 4. Excessive clay.

Fill on connections and trips.

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

1. Drilling underbalanced. 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.

Sloughing shale

Torque and drag.

High fluid loss

High HTHP fluid loss with water in filtrate.

1. Low emulsifier concentration.

1. Add emulsifier and lime if needed.

Low electrical stability (ES).

2. Low concentration of fluid loss control additives. 3. High bottom hole temperature.

2. Add fluid loss agents.

Increase in volume of cuttings across shale shakers.

Fill on connections and trips.

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

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

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Problem

Indications

Treatment

Causes

1. Add emulsifier and lime, if needed.

Low emulsion stability (ES)

Dull, grainy appearance to fluid.

1. Inadequate emulsifier concentration.

High HTHP fluid loss.

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)

Water in filtrate. Barite settling. Blinding of shaker screens. Extreme cases can result in water wetting of solids.

Agglomeration of barite on sandcontent test.

Water wetting of solids

Sticky cuttings.

1. Inadequate emulsification.

Blinding of shaker screens.

2. Water or water base fluid contamination.

Barite settling.

3. Supersaturated CaCl2 as evidenced by free salt crystals in the mud.

Dull, grainy appearance of fluid. Low elec. stab. (ES).

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.

1. Add emulsifier. 2. Add emulsifier and lime, if needed. If severe, add wetting agent. 3. Dilute with fresh H2O and add emulsifier.

Free H2O in filtrate.

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

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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.

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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

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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.

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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.

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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 rulesof-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.

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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

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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.

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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

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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 (