De9 drillingfluids

Drilling Fluids CONTENTS INTRODUCTION 1.1 Functions of a Drilling Fluid 1.2 Types of Drilling Fluid 1.3 Historical Development of Drilling Fluids 1.4 Composition of Mud FIELD TESTS ON DRILLING FLUIDS 2.1 Mud density 2.2 Viscosity 2.3 Gel Strength 2.4 Filtration 2.5 Sand Content 2.6 Liquid and Solid Content 2.7 pH Determination 2.8 Alkalinity 2.9 Chloride content 2.10 Activity(aw) 2.11 Cation Exchange Capacity WATER BASED MUD 3.1 Clay Chemistry 3.2 Additives to WBM’s 3.3 Special Types of Water Based Muds 3.3.1 Inhibited Muds 3.3.2 Brine Drilling Fluid OIL-BASED MUDS 4.1 Water in oil emulsions 4.2 Wettability control 4.3 Balanced activity 4.4 Viscosity control 4.5 Filtration control SOLIDS CONTROL 5.1 Solids Control Equipment 5.2 Solids Control Systems Learning Objectives: Having worked through this chapter the student will be able to: General: • List and describe the functions of drilling fluids and the properties which influence the capability of the fluid to achieve these functions • Describe the most important properties of drilling fluids • Describe the principle issues considered when programming a drilling fluid • List the various generic types of drilling fluid and the composition of these fluids Drilling Fluid Testing: • Describe the equipment and procedures used to determine the: density; rheological properties; gel strength; filtration properties; sand content; liquids and solid content; pH; alkalinity; and CEC of a drilling fluid Water Based Muds: • Describe the composition of water based muds • Define the terms: aggregation; dispersion; flocculation; and de-flocculation and describe the ways in which clays will end up in these conditions • Describe the additives used to increase/decrease the: viscosity; density and filtration of WBM • Describe the chemical formulation of inhibited WBM’s Oil Based Muds: • Describe the chemical formulation of oilbased muds • Describe the ways in which the: wettability; activity; viscosity and filtration of OBM can be measured Solids Control: • Describe the principal mechanisms used in solids removal • Describe the operation of: a shale shaker; a desander and desilter and; a centrifuge • Describe the configuration of solids control equipment for weighted and unweighted muds  Drilling Fluids INTRODUCTION Drilling fluid or drilling mud is a critical component in the rotary drilling process Its primary functions are to remove the drilled cuttings from the borehole whilst drilling and to prevent fluids from flowing from the formations being drilled, into the borehole It has however many other functions and these will be discussed below Since it is such an integral part of the drilling process, many of the problems encountered during the drilling of a well can be directly, or indirectly, attributed to the drilling fluids and therefore these fluids must be carefully selected and/or designed to fulfil their role in the drilling process The cost of the mud can be as high as 10-15% of the total cost of the well Although this may seem expensive, the consequences of not maintaining good mud properties may result in drilling problems which will take a great deal of time and therefore cost to resolve In view of the high cost of not maintaining good mud properties an operating company will usually hire a service company to provide a drilling fluid specialist (mud engineer) on the rig to formulate, continuously monitor and, if necessary, treat the mud 1.1 Functions and Properties of a Drilling Fluid The primary functions of a drilling fluid are: • • • • • Remove cuttings from the Wellbore Prevent Formation Fluids Flowing into the Wellbore Maintain Wellbore Stability Cool and Lubricate the Bit Transmit Hydraulic Horsepower to Bit The drilling fluid must be selected and or designed so that the physical and chemical properties of the fluid allow these functions to be fulfilled However, when selecting the fluid, consideration must also be given to: • The environmental impact of using the fluid • The cost of the fluid • The impact of the fluid on production from the pay zone The main functions of drilling fluid and the properties which are associated with fulfilling these functions are summarised in Table 1, and discussed below Institute of Petroleum Engineering, Heriot-Watt University  Function Physical/Chemical Property Transport cuttings from the Wellbore Yield Point, Apparent Viscosity, Velocity, Gel Strength Density Prevent Formation Fluids Flowing into the Wellbore Maintain Wellbore Stability Cool and Lubricate the Bit Transmit Hydraulic Horsepower to Bit Density, Reactivity with Clay Density, velocity, Velocity, Density, Viscosity Table Function and Physical Properties of Drilling Fluid a Remove cuttings from the Wellbore The primary function of drilling fluid is to ensure that the rock cuttings generated by the drilllbit are continuously removed from the wellbore If these cuttings are not removed from the bit face the drilling efficiency will decrease It these cuttings are not transported up the annulus between the drillstring and wellbore efficiently the drillstring will become stuck in the wellbore The mud must be designed such that it can: • Carry the cuttings to surface while circulating • Suspend the cuttings while not circulating • Drop the cuttings out of suspension at surface The rheological properties of the mud must be carefully engineered to fulfil these requirements The carrying capacity of the mud depends on the annular velocity, density and viscosity of the mud The ability to suspend the cuttings depends on the gelling (thixotropic) properties of the mud This gel forms when circulation is stopped and the mud is static The drilled solids are removed from the mud at surface by mechanical devices such as shale shakers, desanders and desilters (see Section below) It is not economically feasible to remove all the drilled solids before re-circulating the mud However, if the drilled solids are not removed the mud may require a lot of chemical treatment and dilution to control the rheological properties of the mud For a thorough treatment of the rheology of drilling fluids refer to the chapter on Drilling Hydraulics b Prevent Formation Fluids Flowing into the Wellbore The hydrostatic pressure exerted by the mud colom must be high enough to prevent an influx of formation fluids into the wellbore However, the pressure in the wellbore must not be too high or it may cause the formation to fracture and this will result in the loss of expensive mud into the formation The flow of mud into the formation whilst drilling is known as lost circulation This is because a certain proportion of the mud is not returning to surface but flowing into the formation  Drilling Fluids The pressure in the wellbore will be equal to: P = 0.052 x MW x TVD where, P = hydrostatic pressure (psi) MW = mud density of the mud or mud weight (ppg) TVD = true vertical depth of point of interest = vertical height of mud column (ft) The density of the mud may be expressed in either of the following units: To obtain the following Units of density multiply the Units in the first colom by: S.G psi/ft ppg S.G 1.0 2.31 0.12 psi/ft 0.433 1.0 0.052 ppg 8.33 19.23 1.0 Table Conversion of Commonly used Units of Density Example: A mudweight of 12 ppg is equivalent to a mudweight of 12 x 0.052 = 0.624 psi/ft A mudweight of 1.4 S.G is equivalent to a mudweight of 1.4 x 0.433 = 0.606 psi/ft The mud weight must be selected so that it exceeds the pore pressures but does not exceed the fracture pressures of the formations being penetrated Barite, and in some cases Haemitite, is added to viscosified mud as a weighting material These minerals are used because of their high density: Mineral Silica (Sand) Ca CO3 Barite Haemitite Density (S.G.) 2.5 2.5 4.2 5.6 The relatively high density of Barite and Haemitite means that a much lower volume of these minerals needs to be added to the mud to increase the overall density of the mud This will mean that the impact of this weighting material on the rheological properties of the mud will be minimised When drilling through permeable formations (e.g sand) the mud will seep into the formation This is not the same as the large losses of fluid which occurs in fractured formations, discussed above As the fluid seeps into the formation a filter cake will be deposited on the wall of the borehole Some fluid will however continue to filter through the filter cake into the formation The mud and the filtrate can damage the productive formations in a number of ways The loss of mud can result Institute of Petroleum Engineering, Heriot-Watt University  in the deposition of solid particles or hydration of clays in the pore space The loss of filtrate can also result in the hydration of clays This will result in a reduction in the permeability of the formation In addition to damaging the productivity of the formations the filter cake can become so thick it may cause stuck pipe The ideal filter cake is therefore thin and impermeable c Maintain Wellbore Stability Data from adjacent wells will be useful in predicting borehole stability problems that can occur in troublesome formations (eg unstable shales, highly permeable zones, lost circulation, overpressured zones) Shale instability is one of the most common problems in drilling operations This instability may be caused by either one or both of the following two mechanisms: • the pressure differential between the bottomhole pressure in the borehole and the pore pressures in the shales and/or, • hydration of the clay within the shale by mud filtrate containing water The instability caused by the pressure differential between the borehole and the pore pressure can be overcome by increasing the mudweight The hydration of the clays can only be overcome by using non water-based muds, or partially addressed by treating the mud with chemicals which will reduce the ability of the water in the mud to hydrate the clays in the formation These muds are known as inhibited muds d Cool and Lubricate the Bit The rock cutting process will, in particular with PDC bits, generate a great deal of heat at the bit Unless the bit is cooled, it will overheat and quickly wear out The circulation of the drilling fluid will cool the bit down and help lubricate the cutting process e Transmit Hydraulic Horsepower to Bit As fluid is circulated through the drillstring, across the bit and up the annulus of the wellbore the power of the mud pumps will be expended in frictional pressure losses The efficiency of the drilling process can be significantly enhanced if approximately 65% of this power is expended at the bit The pressure losses in the system are a function of the geometry of the system and the mud properties such as viscosity, yield point and mud weight The distribution of these pressure losses can be controlled by altering the size of the nozzles in the bit and the flowrate through the system This optimisation process is discussed at length in the chapter on Drilling Hydraulics It is possible that in order to meet all of these requirements, and drill the well as efficiently as possible, more than one type of mud is used (e.g water-based mud may be used down to the 13 3/8" casing shoe, and then replaced by an oil-based mud to drill the producing formation)  Drilling Fluids Some mud properties are difficult to predict in advance, so the mud programme has to be flexible to allow alterations and adjustments to be made as the hole is being drilled, (e.g unexpected hole problems may cause the pH to be increased, or the viscosity to be reduced, at a certain point) 1.2 Types of Drilling Fluid The two most common types of drilling fluid used are water based mud and oil based mud These muds will be discussed in detail in Section and below but as a general statement, Water-based muds (WBM) are those drilling fluids in which the continuous phase of the system is water (salt water or fresh water) and Oilbased muds (OBM) are those in which the continuous phase is oil WBM’s are the most commonly used muds world-wide However, drilling fluids may be broadly classified as liquids or gases (Figure 1) Although pure gas or gas-liquid mixtures are used they are not as common as the liquid based systems The use of air as a drilling fluid is limited to areas where formations are competent and impermeable (e.g West Virginia) The advantages of drilling with air in the circulating system are: higher penetration rates; better hole cleaning; and less formation damage However, there are also two important disadvantages: air cannot support the sides of the borehole and air cannot exert enough pressure to prevent formation fluids entering the borehole Gas-liquid mixtures (foam) are most often used where the formation pressures are so low that massive losses occur when even water is used as the drilling fluid This can occur in mature fields where depletion of reservoir fluids has resulted in low pore pressure Drilling Fluid Liquids Gas/Liquid Mixture Gas Foam Air Water Based Mud Freshwater Mud Oil Based Mud Salt Sat Mud Inhibited Mud KCL-PHPA Mud Polyol Muds Full Oil Mud Invert Emulsion Mud Pseudo Mud Silicate Mud Figure Types of Drilling Fluid Institute of Petroleum Engineering, Heriot-Watt University  Water based muds are relatively inexpensive because of the ready supply of the fluid from which they are made - water Water-based muds consist of a mixture of solids, liquids and chemicals Some solids (clays) react with the water and chemicals in the mud and are called active solids The activity of these solids must be controlled in order to allow the mud to function properly The solids which not react within the mud are called inactive or inert solids (e.g Barite) The other inactive solids are generated by the drilling process Fresh water is used as the base for most of these muds, but in offshore drilling operations salt water is more readily available Figure shows the typical composition of a water-based mud 1.0 0.8 0.6 Clays + 5% (Active solids) Sand, limestone etc + 5% (Inactive low density solids) 0.4 Barite 5-10 % (Inactive high density solids) 0.2 Water + 80% (Fresh or salt water) 0.0 Figure Composition of typical Clays, watersand, -based mud etc + 3% 1.0 0.8 0.6 1.0 Salt + 4% Barite + 9% Clays, Water +sand, 30% etc + 3% 0.4 0.8 + 4% Salt Oil 50-80% 0.2 0.6 Barite + 9% 0.0 0.4 Water + 30% Oil 50-80% 0.2 0.0 Figure Composition of typical oil-based mud The main disadvantage of using water based muds is that the water in these muds causes instability in shales Shale is composed primarily of clays and instability is largely caused by hydration of the clays by mud containing water Shales are the most common rock types encountered while drilling for oil and gas and give rise to more problems per meter drilled than any other type of formation Estimates of worldwide, nonproductive costs associated with shale problems are put at $500 to $600 million annually (1997) In addition, the inferior wellbore quality often encountered in shales may make logging and completion operations difficult or impossible Over the years, ways have been sought to limit (or inhibit) interaction between WBMs and water-sensitive formations So, for example the late 1960s, studies of mud-shale reactions resulted in the introduction of a WBM that combines potassium chloride (KCl) with a polymer called partially-hydrolyzed polyacrylamide – KCI Drilling Fluids PHPA mud PHPA helps stabilize shale by coating it with a protective layer of polymer The role of KCI will be discussed later The introduction of KCI-PHPA mud reduced the frequency and severity of shale instability problems so that deviated wells in highly water-reactive formations could be drilled, although still at a high cost and with considerable difficulty Since then, there have been numerous variations on this theme, as well as other types of WBM aimed at inhibiting shale In the 1970s, the industry turned increasingly towards oil-based mud, OBM as a means of controlling reactive shales Oil-based muds are similar in composition to water-based except that the continuous phase is oil In an invert oil emulsion mud (IOEM) water may make up a large percentage of the volume, but oil is still the continuous phase (The water is dispersed throughout the system as droplets) Figure shows the typical composition of OBM’s OBM’s not contain free water that can react with the clays in the shale OBM not only provides excellent wellbore stability but also good lubrication, temperature stability, a reduced risk of differential sticking and low formation damage potential Oil-based muds therefore result in fewer drilling problems and cause less formation damage than WBM’s and they are therefore very popular in certain areas Oil muds are however more expensive and require more careful handling (pollution control) than WBM’s Full-oil muds have a very low water content (