HdBk Drilling FLUIDS

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(1)Energy Technology Company Drilling & Completions Fluids & Waste Management Team. Drilling Fluids Handbook. Version 2-09 November 2009.

(2) ©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..

(3) I. . 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.

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

(5) III. 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.

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

(7) 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.

(8) . . Chapter 2: Drilling Fluid Properties . CHAPTER 2: DRILLING FLUID PROPERTIES This section covers the drilling fluid properties reported on the daily mud check and how they may be related to current or potential hole problems. When guidelines are presented, it must be remembered that all situations are different and adjustments to the guidelines must be made. For instance, when an influx of gas or formation fluid into the wellbore occurs, the fluid density is usually increased to create a hydrostatic pressure overbalance with the formation. Using another example, when drilling a highly deviated well and torque or drag is an issue, this may indicate the hole is not being properly cleaned, so the yield point may be elevated or a sweep program is initiated. There may also be times when problems occur and it is not so easy to determine what drilling fluid properties need to be changed and potentially optimized. A troubleshooting guideline table for common fluid contaminants and treatment is included as Appendix 2-1.. Mud Weight or Density Mud weight or density is the most important fluid property for balancing and controlling downhole formation pressures and promoting wellbore stability. Mud densities may be measured and reported in pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), or grams per milliliter (g/mL), and conversion factors between the measurements are listed in Table 2-1.. Energy Technology Company | 2.

(9) Chapter 2: Drilling Fluid Properties. 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.. Energy Technology Company | 3.

(10) . . Chapter 2: Drilling Fluid Properties . 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.. Energy Technology Company | 4.

(11) Chapter 2: Drilling Fluid Properties. 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.. Energy Technology Company | 5.

(12) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 6.

(13) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 7.

(14) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 8.

(15) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 9.

(16) . . Chapter 2: Drilling Fluid Properties . 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.. Energy Technology Company | 10.

(17) 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. Energy Technology Company | 11.

(18) . . Chapter 2: Drilling Fluid Properties . (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.. Energy Technology Company | 12.

(19) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 13.

(20) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 14.

(21) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 15.

(22) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 16.

(23) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 17.

(24) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 18.

(25) Chapter 2: Drilling Fluid Properties. 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.. Energy Technology Company | 19.

(26) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 20.

(27) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 21.

(28) . . Chapter 2: Drilling Fluid Properties . 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. Energy Technology Company | 22.

(29) Chapter 2: Drilling Fluid Properties. 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. Energy Technology Company | 23.

(30) . . 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.. Energy Technology Company | 24.

(31) 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.. Energy Technology Company | 25.

(32) . . 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. Energy Technology Company | 26.

(33) 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. Energy Technology Company | 27.

(34) . . 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. Energy Technology Company | 28.

(35) 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. Energy Technology Company | 29.

(36) . . Chapter 2: Drilling Fluid Properties . . Energy Technology Company | 30.

(37) . . 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. . . Energy Technology Company | 30 .

(38) 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). . Energy Technology Company | 31 . . .

(39) 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.

(40) 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.. Energy Technology Company | 33.

(41) 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.

(42) 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. Energy Technology Company | 35.

(43) 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.. Energy Technology Company | 36.

(44) 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.

(45) 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. Energy Technology Company | 38.

(46) 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.. Energy Technology Company | 39.

(47) 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. Energy Technology Company | 40.

(48) 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.. Energy Technology Company | 41.

(49) 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.. Energy Technology Company | 42.

(50) 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. Energy Technology Company | 43.

(51) 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. Energy Technology Company | 44. Add extender and water Add extender Add soda ash and extender or flocculant. Treat calcium with soda ash.

(52) 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,. Energy Technology Company | 45.

(53) 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. Energy Technology Company | 46.

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