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DRILLING FLUIDS COURSE MANUAL

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CONTENTS

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I. INTRODUCTION ………………………………………………………………...

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I.1 COURSE OBJECTIVES ………………………………………………………...…. I.2 FUNCTIONS OF DRILLING FLUIDS ……………………………………..……..

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II. FACTORS TO CONSIDER IN DRILLING FLUID SELECTION …………………

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II.1 WELLBORE STABILITY ………………………………………………….……. • Physical Stresses ………..………………………...……………………... • Fluid Imbibition ……………………………………………………….…. II.2 DRILLING AND CLEANING THE HOLE ………………………………...…… • Rate of Penetration ……………………………………………………….. • Cuttings Transport / Hole Cleaning ..…………………………...………… - Vertical Wellbores ….…………………….……….…………… - Deviated Wellbores .…………………………………...……….. II.3 HYDRAULICS ….……………………………………….……………………….. II.4 OTHER FACTORS ..……………………………………………………..……….. • Damage to Productive Zones ..…………………………………………… • Corrosion ..………………………………………………………………... • Lubricity ..………………………………………………………………… • Gas Hydrate Suppression ..………………………………………………..

III. DRILLING FLUID SELECTION ..…………………………..………….………… III.1 INHIBITIVE WATER BASE MUDS ..……………………………….………….. • Clay Chemistry ..………………………………………………………….. • KCl & other Inhibitive Additives ..…………………...…………………... • Lime Muds ..……………………………………………...………………. • Silicate Muds ..……………………………………………………………. • Cationic Polymer, Calcium Chloride Muds ……………………………… III.2 INVERT EMULSION OIL AND SYNTHETIC BASE DRILLING FLUIDS …...

IV. WATER BASE DRILLING FLUID SYSTEMS ………………………………….. IV.1 Properties and Additives …………………………………………………………..

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Mud Density …………………………………………………..…………………… Viscosity / Gellation ……………………………………………………..………… Alkalinity ………………...………………………..………………………………. Filtration / Fluid Loss Control ………………………………..……………………. Inhibition ………………………………………………………………..…………. Rheology Modification …………………………………………………………..… Lubricity …………………………………………………..……………………….. Corrosion …………………………………………………………..……………….

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• Contaminants …………………………………………………...…………... IV.2 Water Base Mud Systems …………………………………………………………

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Dispersed / Non Inhibitive Muds ………………………………..………………… Dispersed Inhibitive Muds ………………………………………………..……….. Non-dispersed Water Base Muds ………………………………….………………

V. INVERT EMULSION MUD SYSTEMS …………………………………………... V.1 Properties and Additives …………………………………………………………... • Density ………………………………………….………………………… • Viscosity / Gellation ……………………………………………………… • Alkalinity …………………………………………………………………. • Fluid Loss Control ………………………………………………………... • Inhibition …………………………………………………………………. • Base Fluids ……………………………………………………………….. • Emulsifiers ………………………………………………….…………….. • Oil Wetting ……………………………………………………………….. V.2 Mud System Formulation ………………………………………………………….

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DRILLING FLUIDS COURSE MANUAL: DLG:10/02

I. INTRODUCTION: I.1 COURSE OBJECTIVES: The overall objective of this Course is to give Unocal Drilling personnel an enhanced knowledge and understanding of Drilling Fluids. It is not intended to teach anyone to be a Mud Engineer, rather to give skills that will be useful in routine, day to day work. Drilling Engineers need to know how to choose a Fluid for a particular well. Drilling Foremen need to know whether a Fluid is performing adequately, and being run correctly. Both need to be able to converse with Mud Supply Company personnel from an informed perspective. Unocal expects drilling personnel at all levels to make decisions that are based on informed analysis. Completion of this course should expand the knowledge base, and facilitate that process. The specific Course Objectives are to give Unocal Drilling Personnel • A better understanding of the relationship of Drilling Fluids to the overall drilling operation. • An understanding of Drilling Fluids in terms of Function and Formulation. • Knowledge of the factors involved in the selection and design of a Drilling Fluid System for a particular well or project. • An understanding of cost effectiveness in the selection and evaluation of Drilling Fluids. The ultimate aim in Drilling Fluid Design and Engineering is to provide a borehole where all drilling related operations can be undertaken as desired, with hole condition and stability taken for granted. If this can be achieved, the drilling operation can be streamlined to save time, resulting in reduced overall drilling costs. The following has already been achieved: • Stopped routine wiper trips. • No wiper trips during or after logging runs, even after 3 – 5 days. Standard practice is to rig down wireline and run casing. • Stopped pulling to the shoe to make rig repairs, as in changing swivel packing. • In Indonesia they no longer move the drill string during well control operations. It is hoped and expected that the student will take away from the course all of the following: • A better understanding of the relationship of Drilling Fluids to the overall Drilling Operation. • An understanding of Drilling Fluids in terms of Function and Formulation. • A knowledge of the Factors involved in the selection and design of a Drilling Fluid System for a particular well or project. • An understanding of Cost Effectiveness in the selection and evaluation of Drilling Fluids. I.2 FUNCTIONS OF DRILLING FLUIDS: The first and most important principle that everyone should learn and understand about Drilling Fluids is that they should be Designed and Formulated on the basis of Performance Requirements or FUNCTION, not to meet any specific set of Properties. Drilling Fluid design and selection starts with defining the Functions that are required of the fluid. A Formulation is then chosen, usually in lab testing, which will give the desired performance. The Formulation is then further refined in the Field. Only at that stage should the Properties be considered. Essentially, if the mud is working, then the properties must be correct. If the Fluid is not performing adequately, then the correct approach is to alter the Formulation. It 6

is true that most Mud Systems used are tried and tested, and the average properties well known, but Properties are the end of the process, not the beginning.

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This is a shift in focus from the way most Supervisors, or even most Mud Engineers are used to working. Mud Programs are written specifying the desired Mud Properties. Muds are commonly run on a trial and error basis. Treatments to the mud are made in small additions of product, trying produce the desired property range, like adding salt to soup. This leads to over, or undertreatment. It is seldom satisfactory, and often results in unnecessary cost. The assumption is made that if the properties given on the mud report match the numbers given in the Mud Program, then all is well. This may not be the case. Mud Property checks are important for tracking changes to the mud. They should be use for monitoring the trends in the mud properties to give early warning of changes, not for dictating treatment to the mud. Nevertheless, the two things work together. The point is that when a mud check indicates that treatment is needed, the treatment should be based on a knowledge of the mud’s formulation, and treatment should be based on an adjustment to that formulation. • • •

The first step to understanding Drilling Fluids then, is to understand the Functions required of these Fluids. Secondly comes the Formulation, the Products and concentrations used to achieve the desired Functions. Lastly we will examine the resulting Mud Properties and what they mean.

NOTE: A section on basic chemistry, to a level which will enable understanding of the chemical terminology used, is included at the end of this Manual.

II. FACTORS TO CONSIDER IN DRILLING FLUID SELECTION: •

WELLBORE STABILITY: Balancing, or overcoming the Physical and Chemical forces present in the borehole.

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DRILLING AND CLEANING THE HOLE: ROP, Cuttings Transport in Vertical Holes and Deviated Holes.

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HYDRAULICS: Rheology and Frictional Pressure Losses / ECD.

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OTHER: Avoid Damage to Productive Zones, prevent Drill Pipe Corrosion, Lubricity, and suppression of Gas Hydrates, and handle High Temperatures and / or Pressures.

II.1 WELLBORE STABILITY: Wellbore stability is, at the most basic level, a matter of understanding the various forces effecting the borehole. Ignoring these forces and leaving them unbalanced will lead to failure of the rock, and possible loss of the borehole. One of the most important aspects of Drilling Fluid design is in selecting physical and chemical properties for the Mud, which will satisfy or counter these Forces. The factors involved can be broken down as follows: • PHYSICAL STRESSES: • FORCES CAUSING WATER IMBIBITION, LEADING TO ROCK FAILURE : - CLAY MINEROLOGY / ELECTROCHEMICAL FORCES: - OSMOTIC FORCES, DUE TO FORMATION WATER SALINITY:

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PHYSICAL STRESSES: Drilling a hole through a rock formation interrupts the pattern of stresses present within the rock. These stresses have both horizontal and vertical components, and are generally present due to the vertical loading, or overburden load, upon a given point within the rock. They are present both in the rock matrix, as well as being transmitted to the interstitial fluids trapped within the formation. In the normal deposition, compaction and diagenesis of sediments, a gradually increasing overburden load, forces fluid (seawater) out of the compacting clastic material. Granular sediments, such as sand and silt take up the weight of this overburden load by grain to grain contact and the integral strength of the grains. Clay type rocks on the other hand are composed of flat platelet and rod shaped materials, and the matrix tends to be compressible. In all sedimentary rocks, the fluids will start out under a hydrostatic pressure related to their depth of burial, and specific gravity. Normal formation pore pressure can be said to be equal to the hydrostatic pressure of seawater. The hydrostatic pressure of the formation fluids will be counteracting, or having a buoyancy effect on the load of sediments pressing down from above. In examining the stresses present within the rock, it should be obvious that the overburden load is partially countered by the pore pressure of fluids within the rock. The remaining overburden load will be taken up by the solid particles that make up the rock. Within claystones and shales, the clay particles are initially oriented in a random manner. They are reactive, are hydrated, and the rock includes a lot of ions dissolved in the interstitial fluid. There are therefore electrochemical forces resisting the re-alignment of the clay particles into nicely aligned flat layers. Compaction is a slow process of increasing load from above, re-alignment of clay particles, and gradual expulsion of fluid from the rock, with resulting decrease in porosity and increase in density. In this process if excess fluid is trapped in the rock, the formation water may take up more than its share of the overburden load, and by definition, be abnormally pressured. Abnormal pressuring of a rock always refers to the pore pressure or the pressure of the included fluids within the rock. In shallow formations it may be due to rapid burial. In deeper shales, it is commonly caused through diagenesis of montmorillonites to Illite, releasing bound water, as will be discussed in the section on clay mineralogy. From the driller’s perspective, increasing pore pressure in a shale will be coincidental with increasing porosity and decreasing density. The rock will therefore drill faster. It will contain more fluid, and if some of the fluid is gas, more gas will be released from the drill cuttings into the mud. Background gas will increase. If an abnormally pressured rock is drilled underbalanced, pore fluids will try to expand and relieve pressure into the borehole. Initially increased torque and drag will occur, and eventually failure of the rock and sloughing. To prevent the rock from failing mechanically at the borehole (sloughing or caving), and to prevent fluids within permeable zones from flowing into the borehole, a sufficient pressure must be maintained by the drilling fluid to at least balance the fluid, or pore, pressure within the rock. Balancing the physical stresses that effect wellbore stability then, are simply a matter of adjusting the Mud Weight.

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FLUID IMBIBITION: The physical stresses within subsurface rock formations, when left unsatisfied, lead to direct failure of the rock. FLUID IMBIBITION is a more indirect process. The majority of rocks drilled in the petroleum exploration process, (roughly 70 %), are shales, that is rocks composed of clay minerals. Smectite clays, of which Montmorillonite (or Bentonite) is the most common example, have unsatisfied electrochemical forces causing them to desire to hydrate, that is to adsorb water into the clay lattice. Other clays, such as Illite, Chlorite and Kaolinite may also be present, and also hydrate, but to a lesser degree. Hydration of the rock causes swelling, and failure. A second cause of Fluid Imbibition by sedimentary rocks is Osmotic Force. Marine sedimentary rocks are made up of particles of clay, silt, and sand, which have accumulated in a marine environment. Compaction of these sediments in the process of forming rock, leads to the expulsion of much of the seawater contained within the sediment. Nevertheless, some of this salty fluid is retained. Quite early in the compaction process, in claystones / shales, the paths by which water can move through the rock become too small for salts to move through, and these ions become trapped. Some movement of water on a molecular level continues, so there is a tendency for shales to gradually get saltier with time. When two aqueous fluids having different salinities are exposed to each other, there is a tendency for the less salty fluid to dilute the more salty fluid, due to Osmotic Force. When a hole is drilled through a shale, if the Drilling Fluid contains less salt than the shale, there will be a tendency for water to migrate into the shale. This will cause swelling and failure of the rock.

IT IS IMPOSSIBLE TO PREVENT HYDRATION OF SHALE FORMATIONS WHEN USING A WATER BASED DRILLING FLUID. This is because, while Osmotic Forces may be overcome by adding salt to the mud, there is no way to counter the Clay Mineral Hydration force, when drilling with a water based fluid. Further, water may be sucked into the formation from Invert Emulsion Oil and Synthetic base muds, if an inadequate water phase salinity is run. The degree of water adsorption and consequent swelling due to unsatisfied charges on the Clay Mineral depends on the type of clay. Montmorillonites can adsorb in the range of 0.5 grams of water / gram of dry clay, resulting in a doubling of the volume of the rock. Other types of clay minerals would adsorb less. Osmotic hydration on the other hand results in a much higher volume of water being drawn into the rock, something in the region of 10 g of water / gram dry clay, resulting in a 20 fold increase in volume is common. (Darley & Gray, Composition and Properties of Drilling and Completion Fluids, 1988). It should be obvious that these factors need to be taken into consideration when planning a Drilling Fluid Program, particularly if planning to use a water base mud. II.2 DRILLING AND CLEANING THE HOLE: The choice of Drilling Fluid will effect the potential Rate of Penetration. Drilling Fluid Properties are also critical to Hole Cleaning. It is useful to have an understanding of the mechanisms involved both in selecting and designing the Fluid for a specific well, and in getting the most out of the Fluid being used.

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RATE OF PENETRATION: The understanding of the relationship of Drilling Fluid properties and Fluid Hydraulics, to ROP has evolved considerably over the years. This relationship varies considerably between conventional roller cone bits, and the more modern PDC drag bits. The ROP is of course proportional to the strength or hardness of the rocks, but within that limitation are factors that we can influence to enhance the drilling rate. With conventional bits, as the cones of the bit roll around, the teeth penetrate the rock at the face of the bit, chipping loose cuttings. Each cutting must then be removed from below the face of the bit by the jetting action of the mud, to begin its journey up the hole. Rate of penetration is directly related to the size of the chipped cuttings and how fast they can be removed from below the bit, exposing new formation to the bit teeth. It has been demonstrated that drilling is fastest when air / or gas is used as the drilling fluid. This is because underbalance promotes rock failure, as mentioned above. Next comes water, and finally mud. Drilling underbalanced is only practical in certain, very limited situations. Drilling without viscosity or fluid loss is again only practical in limited situations. Since neither air/gas nor water, in most cases, can satisfy the majority of requirements for a Drilling Fluid. It is useful to understand the mechanisms involved and possibly minimize the detrimental effect that mud may have on the ROP. When the tooth of a bit penetrates the rock, ideally the rock fractures, and a chip is formed. As the differential pressure between the Drilling Fluid and the rock increases, the less likely the rock is to fail in a brittle manner when penetrated by the bit tooth. As differential pressure increases, the rock is effectively strengthened, and once this differential pressure exceeds about 500 psi, shales tend to deform in a plastic manner, and the bit tooth may penetrate the rock without creating a chip. Assuming drilling in an overbalanced condition is necessary in most circumstances, the fastest drilling occurs when differential pressures between the mud and the formation are maintained below 200 psi. After a chip of rock is formed, it does not immediately pop free and start up the hole, but tends to be held against the bottom of the hole by the differential pressure of the mud. It stays there until mud or mud filtrate penetrates the fracture below the chip and equalizes the pressure. Muds with low filtration rates, higher viscosities and higher solids contents have lower relative ROPs. This is the reason that drilling with conventional tooth bits, with Oil base muds, with their characteristically low fluid loss, tends to be slower than with water base muds. Once the chip is loose, the jetting action of the mud blasts it away from the face of the bit. Muds that exhibit better shear thinning action, i.e. that have lower viscosities under high shear conditions, have a better jetting effect. A low solids content is also important. The jetting effect is also directly related to the flow rate of the mud. With conventional bits it has been found that there is a limit to the useful pump rate, beyond which ROP does not seem to increase, and with too much flow the face of the bit may in fact be eroded away. This limit is in the neighborhood of 50 gpm / inch of bit diameter. This may be in conflict with hole cleaning requirements.

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It has been found that jetting is most effective when 50% - 75% of the total circulating pressure of the system is taken up pumping the mud through the bit jets. This requires careful jet selection, and it is often difficult to achieve due to pump limitations. With modern PDC bits, the mechanism is different. Where with a conventional bit the tooth penetrates the rock and creates a chip, the cutters on a PDC bit penetrate the rock, and then drag around, scraping out cuttings. The cuttings cannot stay in place because the cutter is continuously moving laterally, so “chip hold down” by the mud is no longer a factor. The cuttings are blasted away from the face of the bit, again by mud flow, to start up the hole. The 50 gpm / inch of bit diameter flow rate limit does not apply, and it becomes desirable to flow the maximum volume possible across the face of the bit. (Note: there is an upper limit to flow rates. At extremely high pump rates the bit may be hydraulically held slightly off bottom, reducing cutting efficiency. Also evidence of bit erosion from mud flow is occasionally seen.) High differential pressures still have a deleterious effect on penetration due to the effect of somewhat strengthening the rock, but not to the same degree as with conventional bits. The low fluid loss of Oil based muds has no effect on ROP with PDC bits, and in fact the combination of PDC bits and oil or synthetic base mud provides the highest ROPs of any conventional system. This synergy is largely due to the “oil wetting” effect of the mud. A layer of oil is maintained on the cutters, preventing clays from sticking to the bit. With water muds, pressure of the bit cutter against the clay, dehydrates a layer of clay just at the face of the cutter. Clay sticks to the cutters, choking them and effecting the ability to penetrate new formation, thereby reducing drilling efficiency. •

CUTTINGS TRANSPORT / HOLE CLEANING: The discussion here is a compilation of a number of cuttings transport studies performed in various laboratory facilities, coupled with our experience. A list of the papers from which much of this information was derived is given at the end of the section. The discussion on cleaning deviated holes is necessarily the more detailed, as this subject is more considerably complex. The transportation of the cuttings from bit to surface has always been one of the main functions of drilling fluids. The relationship of mud rheology to cuttings transport in vertical holes has been understood for a long time. In deviated holes however, other factors aside from the “carrying capacity” of the mud come into play. Difficulties in cleaning high angle holes are common, and can cause serious problems, such as packing off, getting stuck, and subsequent loss of time. There has been quite a lot of work done in recent years to try and better understand the mechanism of cuttings transport in deviated holes, and the factors involved have now been well identified, if not perfectly understood. HOLE CLEANING IN VERTICAL WELLS: Effectively there are only two factors to consider in carrying cuttings out of vertical wellbores. The first is ANNULAR VELOCITY and the second is MUD RHEOLOGY. With regards to ANNULAR VELOCITY, when it comes to cleaning the hole, the rule is “THE FASTER THE BETTER”, but we are constrained by other factors such as pump limits, and also potential hole erosion. Fortunately the rheology of all viable drilling fluids can be adjusted to clean any hole we might want to drill, within the annular velocity limits.

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With regards to RHEOLOGY, in the most basic terms, the rule is: THICKER IS BETTER as far as cuttings transport by a mud, in a vertical hole is concerned. Again there are limits. There are other factors to consider in drilling fluid design, other than hole cleaning, for example high YP’s directly contribute to high Equivalent Circulating Densities and one must be balanced against the other. In deviated wells matters are considerably more complicated and high Yield Points do not necessarily contribute to better cuttings transport, in fact, the reverse may be the case. CUTTINGS TRANSPORT IN DEVIATED WELLBORES: The following factors are generally accepted to influence cuttings transport, and therefore cleaning, of deviated wellbores: • Inclination of the Wellbore • Annular size • Rate of Penetration • Fluid Velocity • Mud density • Mud rheology • Pipe rotation • Eccentricity of the Drill Pipe • Cuttings properties (size, density) • Geometry of the wellbore (washouts & rugosity). We do not have control over most of these factors when it comes to cleaning a particular hole, however it is probably well to consider how each contributes to, or helps to alleviate, the problem. INCLINATION OF THE WELLBORE: It has been determined that with any inclination of the wellbore in excess of 10° from the vertical, cuttings transport in the annulus will be effected by the inclination of the hole. From 10° to somewhere between 30° - 40°, cuttings will gravitate to the low side of the hole, and slide back down – even with the pumps on. At angles above this a bed of cuttings will be formed on the low side of the hole, but may slide down hole to some degree with the pumps off. In one lab test, with OBM, the cuttings were seen to slide down a tube inclined to 70°. (This is unlikely at that angle in an actual wellbore because of the rugosity of the hole.) Further it has been demonstrated in the lab and confirmed in the field with carefully controlled tests, that at angles up to 55° hole cleaning is best achieved with laminar flow, good Low Range (not Yield Point) rheology properties, and vigorous pipe rotation. At angles above 55°, turbulent flow cleans best. ANNULAR SIZE: It has been generally observed that larger holes are much harder to clean than small ones. The critical size in practice seems to be the 12-1/4”, and larger, holes. 81/2”, and smaller usually aren’t a problem. The reason almost certainly has to do with annular flow rates and the depth of the cuttings bed formed. A consideration might be to use larger drill pipe in the larger hole sizes, if hole cleaning is a problem. It has been proven experimentally, that there will be a cuttings bed formed in any hole of over approximately 30° - 40° in inclination. Whether the cuttings bed becomes a problem to the drilling operation depends on the height, or thickness of the layer of cuttings, and whether or not the BHA can be pulled through it without dragging cuttings up into a plug and packing off. Our experience in the smaller holes is that the cuttings beds are fairly thin (and 13

composed of mostly fine well ground up cuttings). In general, when pulling out of the hole, the cuttings are able to flow back past the BHA and bit.

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(This of course depends a lot on the cross sectional area of BHA and bit. The aggressive drag type bits are a lot better in this regard than the old full hole types with narrow flow channels.) In larger holes, the layer of cuttings remaining on the low side of the hole is often thick enough to cause problems. RATE OF PENETRATION: This is fairly obvious, but has been confirmed in the lab tests. The greater the cuttings injection rate into the mud stream, the greater will be the transport and removal problem for a given set of conditions and mud properties, so hole cleaning will be more difficult at higher ROPs. FLUID VELOCITY: Annular velocity has been found by all researchers to be the most important factor in cleaning inclined wellbores. There appears to be a critical velocity for each set of conditions (hole angle, annular size, mud rheology, etc), below which cuttings fall to the low side and form a cuttings bed; and above which the cuttings bed is eroded away and carried out of the hole. MUD DENSITY: Research has shown that increased mud weights contribute more to hole cleaning than does mud rheology. In the research literature, the experimentation with mud weights were with differences of two or three pounds per gallon, but we have found that even going from 9 – 10 ppg makes a difference. Drill cuttings have a nominal density of 21 lb/gal. In a 10 lb/gal mud then, they will have an effective density of 11 lb/gal. Still quite heavy, and likely to settle quickly, even out of a moving mud stream. In a 16 lb/gal fluid on the other hand, the effective density of the cuttings will be only 5 lb/gal. Effectively much lighter, and easier to move. This doesn’t mean we should drill all deviated wells with extra mud weight however, because the negative aspects of being overbalanced outweigh the hole cleaning benefits. These minuses include: 1. A greater chance of differential sticking – especially with logging tools. 2. A reduction in ROP (even with PDC bits) due to rock strengthening and chip hold down. 3. Increased invasion into the reservoir, especially into depleted zones, with resulting formation damage. 4. Increased potential for lost circulation. HIGH WEIGHT SWEEPS: This is a technique which utilizes the beneficial effect of higher mud density in transporting cuttings out of deviated holes, without the downside associated with drilling considerably overbalanced. The idea is to “float” the cuttings out of the hole, so the heavier the sweep (within reason), the better. 50 – 100 bbl (min. 200 ft in the annulus) of 16 lb/gal mud makes a very effective sweep. The pipe should be rotating as the sweep is pumped to help stir up any cuttings beds. There is the potential problem that frequent heavy sweeps can gradually raise the density of the whole mud system. Coarse-grind (screenable) barite is now available for high weight sweeps. We have found the frequent pumping of Hi Weight Sweeps to be the single most effective factor contributing to removal of cuttings from high angle holes

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MUD RHEOLOGY: For many years this has meant Plastic Viscosity and Yield Point. The Yield Point, or more importantly the YP/PV ratio, is essential in minimizing cuttings slip during transport in vertical wells. On the other hand the research, as well as our experience, shows that the Yield Point has little relevance to cuttings transport in a deviated well. Research has found that raising or lowering the YP of fluids has little effect on cuttings transport, or may have the opposite effect to what would be expected: that lower YP’s seemed to work better. While initial research suggested that mud rheology, within limits, had little relevance to cuttings transport in deviated wells, more recent work has discovered that rheology is important. (Also this is one of the few variables which can be readily adjusted while drilling a well). What has been noted is that while the Yield Point value doesn’t relate directly to carrying capacity in a deviated well, the Low Range viscosity numbers are important: the rheometer readings at 3, 6, and 100 RPM. (We have a number which we report which we call LOW RANGE RHEOLOGY, which is equal to 2 x 3 RPM – 6 RPM, and which seems to give us a good guideline.) A good rule of thumb is to have a low range rheology equal to, or greater than, the hole size (in inches). It has also been noted that decreasing the YP while increasing the low range numbers is of particular benefit. Much laboratory work has been done comparing fluids made up with XC Polymer to ones formulated using HEC or PAC. (These fluids are used because they are relatively clear so you can see what is going on in the plastic tubes researchers use.) The XC fluids, having excellent low range properties, were vastly superior to the other fluids, although they had similar PV & YP numbers. Additives are now available for Oil and Synthetic base muds, which specifically enhance the low range rheology, without effecting the viscosity at higher flow rates. In practice we have found that maintaining a LR of 14-15 works best in 12-1/4” holes, and 10 + is recommended for 8-1/2” holes. PIPE ROTATION: Pipe rotation is the main factor in keeping the cuttings stirred up, (breaking up cuttings beds already formed), and getting the cuttings back into the main flow stream and moving up hole. Generally the faster the better is the rule, although again there are practical limits. A second factor is that the rotating pipe, lying on the low side of the hole, acts as a grinding mill, breaking large cuttings into a size more easily transported out of the hole. The effect of rotation on the cuttings has to do with a property called “viscous coupling”, rather than any mechanical action of the pipe on the cuttings. The rotating pipe drags at the mud in contact with it, and because of the viscosity of the mud a swirling effect is created which helps to stir up the cuttings and even scour the low side of the hole. This effect is maximized by increasing the Low Range Rheology, and this synergism is probably the main reason that LR Rheology is important. It should be noted that in causing the mud to swirl horizontally around the rotating drill pipe, there will be a resistance to the mud flowing up the hole. This will increase circulating pressure losses in the annulus, and thus increase the ECD. The faster the RPM, the greater the effect.

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ECCENTRICITY OF THE DRILL PIPE: In a vertical hole the pipe is fairly well centered in the hole, but whether it is centered or off to one side (eccentric), doesn’t appear to have any effect on cuttings transport. In deviated wells on the other hand, it is one more factor that has an influence on whether a cuttings bed is formed, or stirred up and carried out of the hole. Research has found that rotating the pipe about 20 % up off the low side of the hole works best for stirring up the cuttings. Unfortunately we can’t control just where the pipe sits in the borehole. On bottom, where the pipe is stabilized, it is more or less centered in the hole. Above the stabilizers, the BHA and drill pipe will lay on the low side of the hole up to where the transitional section from deviated to vertical occurs in the well, where tension will lift the pipe up to the high side. There will be no cuttings bed formed along the stabilized BHA, however above the BHA, with the string on the low side – mud flow is mostly above the pipe, encouraging cuttings to settle, to the point where they can completely bury the pipe. Pipe rotation kicks the cuttings back up into the mud stream, but it is evident that some means of mechanically holding the pipe up from the low side of the hole would vastly improve cuttings transport. One researcher in fact suggested that not much more can be done with flow rates and fluid properties. Mechanical hole wipers, which may be installed at intervals in the string, are now available, and are reputed to work well. CUTTINGS PROPERTIES: Researchers who experimented with different density cuttings found that the greater the density, the greater the tendency to settle out, and the harder to remove. There was some difference of opinion among those who tried different sized material on whether it is easier to transport large cuttings than fine or vice versa, (depending mostly on the lab apparatus used in the test). Overall though it was considered that the bigger cuttings are harder to transport. We can’t confirm or deny this from experience, but as the hole gets deeper we get less of the larger cuttings. Most likely this is due to grinding of the cuttings, and not transport efficiency. The mechanism of cuttings transport or retention has everything to do with mud flow. In general, all cuttings whether large or small will gravitate to the low side of the hole. As long as they are in a fast moving stream of mud they will be carried along. This fast moving stream will be in the middle of the annular section above the drill pipe (in most of the hole). Along the walls of the hole itself, due to friction, there will be a layer of mud that is barely moving. As the cuttings fall to this layer they will no longer be transported and will settle out forming a cuttings bed. The fine cuttings will form a slurry type layer and create a new “low side” of the hole, with a slow moving layer of mud just above it. More cuttings accumulate until the flow rate above the cuttings bed reaches a critical number (or most likely goes turbulent) whereupon the bed starts to erode. All things being equal an equilibrium state will be reached where cuttings will be depositing and eroding at the same time and the bed remains relatively stable. It was suggested in one paper that the large cuttings could protrude through the slow moving layer of mud, up into the fast moving stream, and get tumbled along. More likely they are just carried farther each time because of larger surface area, until they ultimately are circulated out or are caught and ground up by the pipe. All the above theory ignores the pipe rotating around stirring things up, but probably explains the basic mechanism of how cuttings beds are formed.

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GEOMETRY OF THE WELLBORE: Finally, the nature and condition of the hole can effect cuttings transport. Cuttings accumulate in washouts, mostly due to reduced annular velocity. The rugosity or irregularity of the hole caused by rotating a bent mud motor also effects how cuttings accumulate in the hole, but this probably just changes the angle of repose, (the angle at which the cuttings bed stops sliding down the hole when the pump is turned off). SUMMARY: All things being equal, for a given set of conditions, hole size, angle, etc., the factors influencing hole cleaning, (which can be controlled), in order of importance are: 1. Annular Velocity 2. Pipe Rotation 3. Rate of Penetration 4. Cuttings Size 5. Mud Density 6. Mud Rheology NOTE: We have found that, when drilling with oil and synthetic base drilling fluids, increasing the water phase salinity has been helpful in minimizing problems with cuttings beds. Soft cuttings tend to pack together in cuttings beds, and are hard to stir up and get moving. Hard, dehydrated cuttings on the other hand, are easily stirred up and moved. Water phase salinities of +/- 350,000 ppm work well. HOLE CLEANING REFERENCES 1. Oil Muds in Large-Diameter, Highly Deviated Wells: Solving the Cuttings Removal Problem. Seeberger, Matlock, & Hanson, SPE/IADC 18635, 1989. 2. Cuttings Transport Research for Horizontal Wells, Drilling & Completion Fluids Technical Forum. Adapted from an article by Terry Hemphill, Nov. 93. 3. Transport of Cuttings in Directional Wells. Martin, Georges, Bisson, SPE/IADC 16083, 1987.

4. Hole Cleaning in Large, High-Angle Wellbores. Rasi, SPE/IADC 27464, 1994. 5. Experimental Study of Cuttings Transport in Directional Wells. Tomren, Iyoho, Azar, SPE Drilling Engineering, Feb. 86.

6. The Effects of Mud Rheology on Annular Hole Cleaning in Directional Wells. Okranjni, Azar, SPE Drilling Engineering, Aug. 1986.

7. Development of Models for Drill Cuttings Transport in Inclined Wells Based on Deposition: Critical Velocity Concept. Saeed Bin-Haddah, U. of Tulsa Master’s Thesis, 1988. II.3 HYDRAULICS: Hydraulics is defined as “the physical science and technology of the static and dynamic behavior of fluids”. In this Course we are concerned with pumping Drilling Fluids from the mud tanks, through surface lines and hoses, down the drill string, and circulating it back up the annulus. A certain increment of pressure is required to move the mud through each section of the circulating system. The sum total of these circulating pressure losses is the pressure read on the pump pressure gauge. The pressure required to circulate a fluid through a particular section of pipe or hose, depends on cross sectional area and length of the tubular section, the physical properties of density and rheology of the fluid, and the flow rate. In a Drilling Fluid, the Rheology defines the flow properties of that fluid. It is not within the scope of this Course go into Hydraulics Calculations. The intention is to introduce students to the relationship of the physical properties of Drilling Fluids to pressure losses in the circulating system.

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RHEOLOGY: Rheology has to do with the deformation of substances under stress. In drilling this boils down to how Drilling Fluids flow, and the energy required to move them at a certain rate. Different types of fluids exhibit different characteristics under different rates of shear. Newtonian fluids, such as water and oils behave in a linear manner in laminar flow. In drilling terms, this means that when you pump water, the pump pressure plotted on a graph, will increase in a straight line as the pump rate increases. (This is true up to the critical rate where the fluid goes turbulent.) Pump rate, or flow rate, is the rate of shear, while pump pressure is related to the shear stress, or the resistance to the applied force. Viscosity =

shear stress shear rate

For true Newtonian fluids the viscosity is constant at any rate of shear. Non Newtonian fluids, (also referred to as plastic fluids), are those that require a significant amount of stress to initiate flow. Drilling Fluids are of this type. Drilling Fluids are also sometimes referred to as pseudoplastic, meaning that they are shear thinning, that is their viscosity decreases at higher rates of shear. Thin fluids require less pressure to move, whereas thick fluids are better for carrying cuttings. The net viscosity of a Drilling Fluid has two components. The first has to do with the viscosity of the carrier fluid itself, whether it be water, oil, or some type of synthetic fluid, together with the physical concentration of solids within that fluid. The second component of viscosity has to do with the interaction of colloidal particles within the fluid, such as clays and polymers. Viscosity measurements on muds are done using a Marsh Funnel. This method measures overall viscosity, but gives little indication about the flow properties of the fluid, or of the physical properties of the fluid from which the viscosity is derived. The Flow Properties of Drilling Fluids are measured by means of a Rheometer. Stress readings are taken at various rheometer speeds, usually 3, 6, 100, 200, 300, & 600 RPM. Most drilling fluids exhibit near Newtonian behavior at shear rates between 300 and 600 RPM on the rheometer. For this reason, two common mud properties, Plastic Viscosity and Yield Point have been defined by the relationship of the rheometer readings at 600 and 300 RPM to each other. PLASTIC VISCOSITY = 600 RPM reading - 300 RPM reading YIELD POINT = 300 RPM - Plastic Viscosity Unfortunately at no place in the circulating regime in normal drilling operations do the flow rates / shear rates fall into this range. Flow rates in the drill string are normally above this range, and flow rates in the annulus well below it. Measurement of the two properties is extremely useful however because they tell us something about the physical properties of the mud contributing to viscosity, and also how the flow properties of the mud will effect circulating pressure losses. The Plastic Viscosity is related to base fluid viscosity, and the physical concentration of solids in the mud. High Plastic Viscosities will require high circulating pressures for fluids in turbulent flow, such as within the drill string, and through the bit.

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High Plastic Viscosities are obviously undesirable. They are a property of the mud, but serve no useful purpose as a component of viscosity. High mud weights and high PV’s go hand in hand, but an increasing PV trend with a constant mud weight is an early warning sign of an increase in drill solids contamination, or worse, an increase in ultra fines, in the mud. Yield Point is a measure of reactivity or interaction between the colloidal particles in the mud. These include reactive clays, and polymers. This is the useful component of viscosity, enabling the fluid to carry cuttings out of the hole. Frictional pressure losses for fluids in laminar flow are effected by this particular interaction, therefore the YP is directly related to pressure losses in the annulus and Equivalent Circulating Density. The higher the YP, the higher the ECD. In general Drilling Fluid rheologies should be designed utilizing products that enhance Low Range rheology. II.4 OTHER FACTORS TO CONSIDER WHEN SELECTING & DESIGNING DRILLING FLUIDS. AVOIDING DAMAGE TO PRODUCTIVE ZONES: As a drill bit cuts a permeable zone, and fresh virgin rock is exposed to the drilling fluid, there is initially a spurt of whole mud into the pores of the rock. If the particle size distribution of the solids in the mud is good, mud solids will almost instantly bridge the pore throats. Whole mud will not penetrate more than a few millimeters at most into the rock, and a filter cake will quickly be formed, restricting the flow of filtrate into the formation. With most modern drilling fluids, damage is restricted to a thin layer just within the borehole wall, having no effect on later production of the well. Nevertheless, reservoir damage does occur due to Drilling Fluids, and it is a good idea to understand the potential problems. Damage may be caused by one of the following factors: • • •

Hydration of clays within the reservoir rock, due to the chemical nature of the filtrate, resulting in reduction of permeability. Pore throat plugging by ultra fine solids, either from the Drilling Fluid, or dislodged from within the formation. Chemical reactions caused by the filtrate: oil wetting of the reservoir, emulsions, precipitation of salts.

When considering fluid loss of mud filtrate into a reservoir, both the quantity and the chemical nature of the filtrate must be considered. The usual approach is to try and reduce filtration, as measured in an API filter press on the surface, to a minimal number, and hope for the best. Regardless of how low the API or HTHP fluid loss is maintained, filter loss into permeable rocks can never be totally stopped. Therefore, the chemistry of the filtrate is of primary importance. Consider the nature of a sandstone reservoir rock. The rock will be made up of grains of quartz, of sand and silt size, and there will generally be some clay minerals as well. Fluids, such as seawater and hydrocarbons fill the pore space around the clastic particles that make up the rock. Pumping filtrate into this pore space is likely to disturb the equilibrium within the rock, particularly if the filtrate is chemically very different from the existing interstitial fluids. Fresh water filtrates are very damaging, particularly filtrates from high pH muds. The reason is that fresh water promotes both crystalline and osmotic hydration of any clays found within the rock, causing them to swell and plug off permeability, or disintegrate and become mobile. 20

Hydrogen ions promote and accelerate this process. The old high pH, freshwater / lignosulfonate muds were the worst muds that could be used when it comes to reservoir damage, (or borehole stability for that matter). High chloride / polymer muds are better, but filtrate volumes are usually higher. The “spurt loss” on polymer muds tends to be high, and free polymer is likely to enter the pore throats. These particles may cause plugging. Invert emulsion oil and synthetic fluid based drilling fluids have filtration rates many orders below that of water base muds. The filtrate is all oil, and therefore will not react with formation clays. There is the possibility that emulsifiers used in these fluids, which will be contained in the filtrate, may promote emulsion blockages within the reservoir. There is also a concern, in some cases that oil mud filtrates promote oil wetting of the reservoir rock, inhibiting the ability of hydrocarbons to flow through the pore throats. These factors seem to be of relatively minor concern in most cases. On return permeability tests, oil base fluids universally give the best results. Lignosulfonates dissolved in the mud filtrate can precipitate out of solution, within the formation, as pH is lowered by mixing with formation water. Salts dissolved in formation fluids may be caused to precipitate by chemicals found within the mud filtrate. Particulate plugging of pore throats is probably the main factor in formation damage. This may be caused by any very fine material from the mud being forced into the pores of the rock. Polymers could be a problem, although these are generally tied up with clays in the mud and would tend to bridge off and form a filter cake, rather than invade the formation. Ultra fine drill solids and degraded barite are a more serious problem. It is useful to monitor the particle size distribution of field muds, particularly those such as oil muds, which are used over and over. Proper attention to solids control, and adequate dilution are necessary to prevent a build up of ultra fines. Some mud additives have been shown to cause reservoir damage. In particular the asphaltine / gilsonite additives sometimes added to oil based muds for filtration control are particularly bad. These tend to deform under pressure and temperature, and can squeeze into the pores of the rock, rather than bridging over, and their use should be avoided. Finally there is the concern of the dislodging and mobilizing fine particles already present within the pore throats of the rock, and these later “log-jamming”, to plug off permeability. The rate of filtrate invasion is obviously the main contributing factor. High spurt losses, coupled with high differential pressures between mud and formation, will contribute to this type of damage. DRILL PIPE CORROSION: When two dissimilar metal are placed in an electrolyte, a battery is formed. Metal is eroded away from one, and deposited on the other. Electrochemical activity is also induced if electrodes of the same metal are placed in solutions of different ionic activity, and connected by a wire. These are known as concentration cells. A third type of electrochemical cell is set up by differences in oxidizing potential. Any or all of these conditions may be present with a drill string in a water based drilling fluid, particularly one containing inhibitive ions. Slight differences in the mineralogy of the steel in the string leads to electrolysis. Scale and things like wiper rubbers on the pipe create concentration cells. Water based drilling fluids, and particularly polymer muds tend to trap air to some degree. Hydrogen, especially from hydrogen sulfide can lead to hydrogen embrittlement, with hydrogen ions concentrating at stress points in the steel until failure occurs. 21

Acid conditions promote corrosion. CO 2 gas and the action of bacteria on some mud products produce acids, or corrosive byproducts. Increasing pH reduces corrosion and bacterial action, and reacts out CO2, but is not always viable when drilling reactive formations. Brine packer fluids can also be a source of corrosion to tubulars, and should be treated prior to being put in place. Techniques for minimizing corrosion include raising pH, using oxygen scavengers, and adding amine type products to the fluid to coat steel components and reduce reactivity. The Drilling Mud Service Companies supply Products, and corrosion monitoring equipment. LUBRICITY: Lubricity is generally not a problem with oil or Synthetic base muds. High torque can be a problem in some water based drilling fluids, mainly those with a low solids content. Solid particles within drilling fluids are the main source of lubricating properties. Emulsified fluids act as finely divided particles and have the same effect. Diesel oil added to water base mud has an initial lubricating effect, not from the properties of the oil, but as a particle within the fluid. Diesel is a poor lubricity additive, as it quickly breaks down into ultra fine particles and loses the effect. In any case, diesel is no longer acceptable for environmental reasons. Lubricants for WB muds are available from the Drilling Fluid Supply companies. SUPPRESSION OF GAS HYDRATE FORMATION: Gas hydrates are solid mixtures of gas and water, which react to form a rigid lattice type structure. They form, usually at the seabed, due to a combination of high hydrostatic pressures, and low seabed temperatures. High fluid velocities, and pressure pulses may also contribute to hydrate formation. They may form above the freezing temperature of water. Hydrates can plug choke & kill lines when circulating out a kick, making pressure monitoring difficult, or totally blocking circulation. They may even prevent movement of the drill pipe. Suppression of Gas Hydrate formation centers on reducing the amount of free water in the mud. Any additive that reduces the freezing point of water may be used. In drilling fluids this usually means adding salt or low molecular weight glycol to the mud system. Systems should be designed for the particular pressure / temperature conditions which will be encountered. Oil and Synthetic base muds, which have high CaCl 2 water phase salinities will not exhibit hydrate formation problems. Hydrates can however form in these muds if the water phase salinity is too low. This should not be a problem in any Unocal operation.

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III. DRILLING FLUID SELECTION: The process of selecting a Drilling Fluid for a particular application starts with a full consideration of all the factors discussed in the first section. This process should include examining well records from nearby wells, looking at the type of drilling fluid used, and any fluid related problems which might have been experienced. This could range from slow ROP’s to Hole Stability issues, to Reservoir Damage. At the most basic level the Fluid should only be designed to do what is required, and no more. Is viscosity required, mud weight, filtration control, etc.? For example, for riserless drilling offshore, seawater alone will often suffice. Spud muds may require viscosity, but very little else. It is both unnecessary and bad economics to use a sophisticated polymer Drilling Fluid, when gel and water will do the job. Having said that, the ultimate Drilling Fluid at this time, the Fluid of choice for all applications (other than surface hole) is a properly formulated, Synthetic Fluid based, Invert Emulsion mud. On a scale of 1 to 10, with SBM being 10, the best water based drilling fluid might be a 3. SBM should always be the first choice, however there are situations which preclude the use of oil muds, and where a water base mud must be considered. Government Regulations, due to environmental concerns, may preclude the use of Synthetic Base Drilling Fluids. Logistical and economic concerns may also come into play. Shallow wells, with smaller rigs, which may not have adequate facilities, particularly in environmentally sensitive areas may best be drilled with water based fluids. Finally, there are areas that uniquely do not have hole stability problems. The formations drilled may have an abnormally low fraction of the reactive clays, and may be drilled trouble free with water muds. Some formations are integrally strong enough, and the nature of the reservoirs such that drilling with air, or gas is best. These are special cases and have to be dealt with as such. They are the exceptions to the rule. In areas where SBM may not be used, but which require an inhibitive drilling fluid, the best Drilling Fluid which can be chosen, regardless of Mud Company propaganda, is still a Potassium Chloride / PHPA polymer mud system. The various fluids and other factors important to drilling fluid selection are discussed in detail below. III.1 INHIBITIVE WATER BASE FLUIDS: All inhibitive mud systems use a combination of additives to try and minimize the hydration of formation clays. As discussed in the previous section, there are two separate mechanisms involved in the hydration of clay based rocks. These are firstly the Crystalline Hydration Forces due to the nature of the clay minerals, and unsatisfied charges within their lattice structure. Secondly there are Osmotic Forces - related to the concentration of ions within the rock. These are from the seawater environment in which it was originally deposited. Osmotic forces are largely satisfied by the addition of chlorides to the mud, to a level in excess of the salinity of the formation. The Crystalline, or Clay Mineral Hydrational Forces are not so easily satisfied, and in fact the only way to completely prevent hydration is to eliminate water from the borehole. Osmotic forces have a magnitude in the hundreds of pounds per square inch, whereas crystalline hydrational forces are in the thousands of psi. 23

CLAY CHEMISTRY: A brief discussion of Clay Chemistry is appropriate at this stage to enhance understanding of the factors involved in designing an inhibitive water based drilling fluid. All clays are reactive to some degree. That is they will adsorb water and hydrate. Swelling clays (Smectite family) are those that desire to draw water into the clay lattice itself. The basal plane of the clay is charged so that water molecules bond strongly, in molecular layers, to the surface of the clay. Water is associated with the clay surface in a hexagonal coordination, which causes it to be compressed roughly 3% in relation to free water. In water base drilling fluids this is important because the compressed - bound water has a higher viscosity, and this adds to the viscosifying effect when bentonite is added to water. This is also important in the generation of abnormal pressures within shale formations, as Smectite clays alter to Illites through the diagenetic process, releasing bound water. Exchangeable cations, such as Sodium, Calcium, Potassium, etc. are attracted to, and associate with, the basal surfaces of Smectite clays. They are termed “exchangeable” because each may be readily replaced in association with the clay, by one of higher energy. This usually means that divalent cations will replace monovalent cations in the following reaction series. H+ > Ba++ > Sr++ > Ca++ > Cs++ > Rb+ > K+ > Na+ > LiHydrogen is at the top. Most of these ions bond strongly with the clay surface competing with water, however the ions sodium and lithium only weakly associate with the clay, and are readily dislodged. Clays, such as Sodium Montmorillonite, where sodium is the primary exchangeable cation present, have the highest swelling potential. This is because sodium itself will readily hydrate, and also because it is weakly associated with the clay, and easily displaced. These clays will hydrate to the extent that the individual clay platelets will disassociate and disperse completely in water. Thus they are excellent for producing viscosity, at relatively low concentrations, in water base drilling fluids. They also can cause us considerable problems when present in the formations we have to drill. The two most common types of clay encountered in sedimentary rocks are clays of the smectite family, and the Illites. Both these clay types have a mica structure, in that the mineral forms into individual layers of potentially infinite extent. Layers are stacked on top of one another and only weakly bond together, so may be readily separated. Each layer is formed of three sheets. Two sheets composed of silicon and oxygen, associated in a tetrahedral orientation, with a sheet composed of aluminum or magnesium and hydroxyl ions associated in an octahedral configuration sandwiched in between. The bonding of the three sheets is through shared oxygen atoms. Other substitutions are possible, and these define the different individual minerals within the family group. For the purposes of this course, only the most basic situation will be discussed. Aluminum is trivalent (Al +3), whereas magnesium is divalent (Mg +2). Where magnesium substitutes for aluminum in the middle sheet, this middle layer becomes charge deficient, with a net negative charge. It is this charge deficiency that causes the exchangeable cations to be attracted to the surface of the clay, and which draws water in between the clay layers, causing the clay lattice to swell. The orientation of the atoms in the outer sheets is such that the basal surface of each clay layer is composed of oxygen atoms. Layers stacked together are only bonded by molecular attraction, with no chemical (covalent) bonding, and thus cleave fairly readily along the basal plane. That factor coupled with their charge deficiency makes them readily hydrate and swell. 24

In the drilling situation, efforts to stabilize these clays center on trying to provide an ion, or ions, to the clay, which will associate with the clay surface and satisfy the deficient charges. The efforts have not been particularly successful, because as the charge deficiency is in the middle layer, it is extremely difficult to satisfy and fully stabilize these clays. The use of potassium, from potassium chloride has been the most successful element, for the following reason. In the outer / basal sheets of these clays, the oxygen / silicon tetrahedra associate together in such a way that the sheet is not solid, but rather forms a lattice of tetrahedra surrounding hexagonal holes in the sheet. Hydrated Potassium ions are the right size to fit into these holes, allowing them to associate more with the middle sheet in the clay, and effectively neutralize the net charge manifested on the basal surface of the clay. It is interesting to note that the difference between Smectite and Illite clays is the presence of potassium associated with the clay surface, so that illites do not have a swelling crystal lattice. Other clays present to some extent in sedimentary rocks, or of some importance to the drilling industry are Hectorite, Kaolinite, Chlorite, Attapulgite, and Sepiolite. Hectorite is a Smectite clay with higher temperature applications than bentonite (Sodium Montmorillonite). Kaolinite is a mica type clay, but having only two sheets in each layer, the sheets and layers bond together very strongly, and Kaolinite does not readily hydrate. Chlorite is a more complex member of this group, where again the charges between the layers are balanced and there is only a low net charge, the clay being only slightly reactive. Other clays, such as Attapulgite and Sepiolite have a more rod-like structure. Substitution of atoms within the structure is rare, and therefore there is a low surface charge potential. So far, the discussion has centered on the forces on the basal surface of clays which have a mica type structure, that is the forces on the surface of the clay sheets. Clays encountered in the drilling operation however are not in infinitely continuous sheets, but rather in broken clumps of limited lateral extent, many layers thick. Where the individual layers have been broken, bonds between the elements of the clay are broken, and thus these clay edges will have unsatisfied charges. The charges are both negative and positive. These charges are present in all clays, whether swelling types or not, so all clays will have a tendency to hydrate to some degree. These hydrational forces are separate and distinct from the Osmotic Forces, due to ions within all clays deposited as sedimentary formations. When considering shale hydration, borehole instability, and mud design to counter the problem, neither force should be forgotten. As stated above, attempts to satisfy the Crystalline Hydrational Forces of clays with water base muds, has centered around using additives in the mud which bond to the unsatisfied charges on the clays. A congruent approach has been to attempt to coat the clays which something that will reduce water contact, and inhibit hydration by that means. Various polymers have been used for quite a long time now, and they have been found to be beneficial in reducing clay hydration and cuttings dispersion. The best of these at present is PHPA. PAC, and the various starch products are also good. These polymers are anionic, that is they have negative charges, and bond to positive sites on the broken edges of the clay particles. They compete with water in this role, and reduce hydration of the clay. Although they may, to some degree, film on the surface, and delay the hydration of Smectite clays, they can in no way satisfy the basal charges on the clay responsible for the greatest amount of hydration and swelling.

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KCL: The best water base drilling fluid combination to date has been in the KCl / PHPA drilling fluids. The advantage to using potassium chloride is that not only do you have potassium to take care of the Crystalline hydrational force, but you also have the chloride to balance the osmotic forces. 10 % KCl muds work very well, as long as the Smectite content of the formation is below around 15 – 20 %. Not only are KCl / polymer muds highly inhibitive, they are relatively simple to formulate and run, and good for many applications. Other additives that may be equally as inhibitive as KCl do not lend themselves readily to easily managed drilling fluids. Unfortunately the way the EPA chooses to do their toxicity testing, limits the concentrations of KCl that may be added to a drilling fluid, and its use has been severely curtailed in United States offshore areas. New water base mud systems are developed, and trotted out accompanied by a great deal of sales hype, by the Drilling Fluids Supply companies on a fairly regular basis. Most of these are basically the same old thing, under new names, and the whole process is largely a marketing exercise, part of the unending struggle between competitors for some kind of an edge. Usually they are touted as the answer to the Oil Field’s prayer for a water base Drilling Fluid that will equal the performance of the Invert Emulsion oil muds. We should be wary of these promotions. Despite all the claims, nothing comes close to SBM in performance, and none of the additives used to date has been as satisfactory as KCl. It should be useful however to examine some of the more common inhibitive additives, or systems based on inhibitive additives, being used in recent times. These are not listed in any order of preference or supposed performance benefit. Note that with all these additives, including potassium, reaction time is a factor in formation and cuttings stabilization. The clays are likely to hydrate to some degree before the reaction with the inhibitor takes place to a sufficient degree to stabilize the clay. The only way to eliminate hydration is to eliminate water from the borehole. With water base muds there will always be hydration, swelling and degradation of the formation. What these inhibitive water base mud additives attempt to do is reduce the rate or amount of hydration, to a degree that we have time to drill a hole and get casing set. GLYCOLS: Glycols were introduced as Drilling Fluid additives in the early 1990’s. They were touted primarily as clay stabilizers, and lubricants. Glycols are polar liquids, so disperse readily in water. The Glycols used in drilling fluids are high molecular weight liquids which dissolve in water base muds under ambient surface temperatures, but become insoluble at elevated temperatures downhole. Elevated salinities also effect their solubility. Their behavior is somewhat intermediate between water and oil. The glycol to be used on a particular job will be selected so that it is in solution with the mud at flowline temperatures, or cooler, but will separate out at downhole temperatures. Solubility under surface conditions minimizes loss due to evaporation. Undissolved glycol is said to adsorb strongly onto reactive clay surfaces, competing with water, and reducing hydration. Undissolved glycol particles in the drilling fluid also add to lubricity. Just how effective a relatively low concentration of glycol, present as fine droplets within a water continuous solution, might be at competing with the water in being attracted to the clay is open to question. The use of glycol is claimed to be of some benefit in reducing problems with formations containing swelling clays, and glycols are commonly included as a component of inhibitive water base mud systems currently in use.

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Glycols are said to have an “oil wetting” ability on steel. They are claimed to help reduce bit and BHA balling problems, and improve the performance of PDC bits with water base muds. The glycols used for shale stabilization should not be confused with ones used for Gas Hydrate suppression. Those are low molecular weight fluids, whereas the glycols used for shale inhibition are high molecular liquids. Glycols must be carefully selected so that they exhibit this property of “inverse solubility” under just the right conditions. If the glycol is in solution downhole it is of little use, and if not in solution in the pits, it will evaporate. Glycol can cause undesirable rheology increases in the presence of reactive clays, so drill solids must be maintained at a minimum. Downhole rheologies of the mud may be quite different from those measured at the surface. Foaming of the mud will be a problem, and must be taken into consideration. Glycols are added at 4 – 6 % by volume, and therefore the quantities required add some logistical concerns. They are expensive, in water base mud terms. AMINES: The amine type additives used in drilling fluids combinations of alcohol and an amine, and water. Amines are formed by substituting hydrocarbon groups for the hydrogen in Ammonia (NH4). Hydrogen in the alcohol bonds to the oxygen atoms on the clay surface competing with water, and the positively charged Nitrogen atoms of the amine help to neutralize the unbalanced charges of the clay. As they react strongly with any clays, they react not just with the borehole wall and the cuttings, but also with bentonite, and drill solids in the mud. This promotes flocculation of these clays, and can adversely effect the properties of the drilling fluid. Many of these systems are run without the addition of bentonite in the initial mix, to try and avoid this problem, relying on picking up some clays from the drill cuttings. Amines are toxic, so as with KCl, the relative concentration of these products, which may be carried in a water base mud, is limited. These products are generally used in combinations with PHPA, Glycol, and NaCl in current inhibitive water base mud formulations. LIME MUDS: Lime muds have come in and out of fashion over the years. They are roughly half as inhibitive as good KCl muds. They have the advantage that they can be run at much higher mud weights than is possible with KCl. They went out of fashion back in the 1950’s because of temperature limitations, but with modern high temperature additives, these problems have largely been overcome. The mechanism of clay stabilization employed is to provide free Calcium ions as the exchangeable cation in the system. Calcium is a divalent cation, which will strongly replace sodium in sodium montmorillonites, creating a less swelling type of clay. Calcium montmorillonites are much less swelling than sodium montmorillonites because the calcium has a much higher bonding energy, and attaches quite strongly to the clay surface. The ion is too large to fit the holes in the lattice, so can never completely balance the charge within the clay, as can potassium. On the other hand, calcium is divalent, that is it has a double charge, and bonds with two particles of clay at one time. 27

The effect is that clay particles are drawn together in a face to face orientation, bonded by the calcium ions. The clay will still hydrate to some degree, but much less than in the sodium form. This aggregation effect of calcium upon reactive clays is a mixed blessing. Where it tends to inhibit the swelling of formation clays, and the dispersion of drill cuttings, it also gradually converts the sodium bentonite, added to the mud for yield point and gel strengths, into calcium bentonite, which does not work well at all. The initial effect of calcium on a sodium bentonite is to promote flocculation, and aggregation. The mud can have severe viscosity humps, if not run properly. These calcium / clay aggregates do not work well to form an impermeable filter cake, so fluid loss can be a problem, particularly at higher temperatures. Some of the early muds tended to dehydrate and solidify. Most of the early problems with these fluids have now been overcome. New acrylate thinners are very effective at preventing rheological problems, even at high temperatures. Modern polymers are much less calcium sensitive than the early starches, and many are stable at quite high temperatures, imparting good fluid loss control in these muds. They are still somewhat more difficult to run than conventional polymer muds, and not as inhibitive. The alkalinity of the mud must be monitored closely. Calcium solubility is controlled by the alkalinity. One advantage they have is that in aggregating clay solids, they tend to have quite low rheologies, once the breakover to a calcium system is achieved. Higher mud weights than may be used with a PHPA or other polymer mud are therefore practical. Other cations have been used in additives for water base mud systems, with the same principle as calcium in lime muds. BHI’s Alplex, an aluminum complex is one such. SILICATE MUDS: Silicate muds were used as far back as the 1930’s to drill water sensitive clay formations. They have gone in and out of favor, because although they work well for the specific job of drilling an in-gauge hole through reactive clay formations with a water base mud, the are chemically complex, and in the past, not well understood. Understanding has improved over the years, but the system is still a complex one to run and requires superior mud engineering to be successful. Basically these muds use soluble sodium or potassium silicate to provide inhibition. These monosilicates will polymerize rapidly in solution to form negatively charged oligomers. In the pH range 11 – 12 continued polymerization is halted, because the oligomers repel each other. Solutions supplied for drilling fluids contain oligomers that are small enough to penetrate the shale micropore structure as mud filtrate is drawn in by hydrational forces. Within the surface of the shale, pH is diluted by formation fluids, and the oligomers loose their repulsion for each other and coagulate to form silicate gels. These gels then react with free polyvalent cations, such as Calcium and Magnesium that may be present within the rock, to form insoluble precipitates. This gelled / precipitated silicate then forms a physical barrier to further hydration of the rock. Essentially the surface of the borehole becomes sealed with a silicate film. There is some indication that this silicate film could act as an osmotic membrane, however to be truly useful, the salinity of the mud would have to be raised to a much higher level than is possible with a monovalent salt such as NaCl, or KCl, even at saturation. Silicate muds have been dusted off and tried in the past few years in areas where environmental regulations preclude the use of SBM. 28

They have successfully been shown to drill near gauge holes through difficult, reactive formations. It is unlikely they will come into general use however because the sensitive chemistry of these systems limits their application. The pH of these muds must be maintained between 11 and 12. Silicate depletion can be a problem and must be monitored carefully, and maintained.. Such things as CO 2, Calcium, and Magnesium readily react with the silicate, and deplete the system. Drilling cement and anhydrate can deplete the system. Drilling cement with a silicate mud can be very expensive. Although the mud produces a gauge hole, cuttings remain soft, while at the same time being quite large. Being soft, there is a tendency for them to ball together, if given the opportunity. The larger cuttings are more difficult to lift out of the hole, so sweeps may be required to ensure proper hole cleaning. Cuttings left downhole will eventually ball up the BHA. Silicate drilling fluids have an inherent high Plastic Viscosity. At higher mud weights, rheologies become excessive. Good solids control is necessary to prevent a build up of drill solids. They have temperature limitations similar to polymer muds. Lubrication of the drill string may be a problem. Due to the high pH requirements of the system, conventional WB mud lubricants cannot be used. The silicate has a strong affinity for steel, and so lubricants tend to be displaced by the silicate, reducing their effectiveness. High torque can be a problem. Polyglycols are generally run in silicate systems to improve lubricity, and have been demonstrated to be effective. CATIONIC POLYMER SYSTEMS / CALCIUM CHLORIDE MUDS: These two are fairly exotic, and are only mentioned to give an idea of the range of water base mud systems that have been tried. It has already been explained that reactive clays are predominantly negatively charged. Most polymers used in drilling fluids are also negatively charged, and can only interact on the few positively charged sites on the broken edges of clays. They can only inhibit water getting to the clay, if they can film around the clay in competition with water, something of a tall order if the clay is basically repelling the polymer. Cationic, or positively charged polymers on the other hand can react with both the basal surface of the clay, and the clay edge, and therefore are much more able to film on the clay surface and reduce hydration. Cationic polymers have been used in clear workover and completion fluids for some time, but have not been considered practical in normal drilling fluids because of rheological and fluid loss control issues. Cationic polymer muds have been developed in the past few years, and run successfully with good results. They are however difficult to run, very sensitive to solids and in the end, probably not really superior to other water base systems, so they have not caught on. Calcium chloride systems are another exotic type of water base mud. Calcium chloride is so aggressive that it tends to flocculate clays and polymers normally used in water base muds so strongly that the particles settle out. Both calcium (as in lime muds), and chloride will suppress clay hydration, so a drilling fluid made up with calcium chloride should, theoretically be highly inhibitive. Again, systems have been developed in recent years, using cellulosic viscosifiers and non-ionic polymers for viscosification and fluid loss control. The mud has been used to drill successfully, but has a low solids tolerance, and is difficult to run. It can probably be considered still in the developmental stages.

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In general it can be said that the majority of water based drilling fluids will have temperature and mud weight limitations. III.2 INVERT EMULSION OIL AND SYNTHETIC BASE DRILLING FLUIDS: These Drilling Fluids overcome most, if not all the limitations of water based mud systems. Diesel or mineral oil, or a Synthetic Base fluid forms the continuous phase in the mud, so no water comes in contact with the formation. They can be formulated to dehydrate shales and will actually promote and increase shale stability with exposure time. The muds have a high solids tolerance, and therefore can be run at much higher mud weights than most water base mud systems. They have excellent lubricating properties, and are much less likely to cause damage to potential producing intervals than most water base muds. Finally, due to the calcium chloride in the water phase of these muds, they naturally suppress gas hydrate formation. The real advantage of these drilling fluids is the fact that the continuous phase of the fluid is not water. Everything stays oil wet, formation clays do not hydrate, cuttings remain intact, and a film of oil coats the BHA and cutters on PDC bits, preventing balling and enhancing ROP. Possibly, of even greater importance is the capacity of these fluids to be formulated to actually dehydrate wet clay formations and cuttings, improving their stability. It is important to understand, first the benefit of dehydrating wet clays, and second the mechanism involved. There has been a long-standing school of thought, particularly in the Gulf Coast region of the United States, that it is a bad thing to have the mud suck water out of wet clay type formations. It is accepted that, if the shale takes water from the mud and hydrates, instability of the borehole will result. It is also thought however, that removing water from the shale may lead to dehydration and instability. It is therefore quite common to see muds run at, or close to, a “balanced” activity. That is, designed to be neutral in regards to water movement in or out of the formation. Our experience has shown this thinking to be misguided at best. We have seen that there is every advantage to running high water phase salinities, and aggressively dehydrating clays. The mechanism used in invert emulsion drilling fluids for removing water from a clay depends on the generation of an osmotic force in the mud sufficient to overcome both the osmotic forces, as well as some of the crystalline hydration forces present within the clay formation. Osmosis is defined as “the diffusion of fluid through a semipermeable membrane from a solution with a low solute concentration to a solution with a higher solute concentration until there is an equal concentration of fluid on both sides of the membrane”. The key factor here is the presence of a semipermeable membrane. Essentially this means a membrane which is porous, but in which the holes are small enough to filter out large molecules. In drilling fluid terms, the osmotic membrane is something that allows pure water molecules to pass through, but retains ions. The emulsifier film surrounding water droplets in an invert emulsion drilling fluid is such a membrane. To re-state the definition then, it simply means that when two fluids having different ionic concentrations are separated by an osmotic membrane, there will be a force generated, which will drive water molecules to migrate from the less concentrated solution, through the membrane, into the more concentrated solution. This “Osmotic Force” is directly proportional to the difference in concentration and type of ions present within the two fluids separated by the membrane.

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The membrane forms a barrier to the migration of ions. This is where oil muds differ from water base muds. In water base muds, it is important to have sufficient salt in the mud to over come the tendency for water to flow from regions of lower to higher ionic concentration. There is however, no barrier to stop the migration of ions between the drilling fluid and the clays in the formation, and there is certainly no way to suck water back out of the formation. Since the emulsifier film surrounding water droplets in an oil mud acts as a semipermeable membrane, separating this water from the water in the formation, there will be an osmotic force generated across this membrane, unless the activity, or ionic concentration is equal on both sides. If the water phase salinity of the mud is low, water will be drawn into the formation. On the other hand, it is possible to increase the water phase salinity of the mud to an extent where the osmotic force generated is sufficient to overcome even the crystalline hydration forces of the clay, and pull water from the formation. Calcium chloride is used for this purpose. Any soluble salt can be added to the water phase of an oil mud, but of the common readily available ones, Calcium Chloride has the highest activity and is capable generating enough osmotic force to overcome crystalline hydrational forces. Calcium Chloride Osmotic Pressure Sodium Chloride Osmotic Pressure (ppm) (psi)* (ppm) (psi)* 52,600 500 55,000 670 100,000 1,100 105,000 1,400 182,000 3,000 149,000 2,200 250,000 5,800 189,000 3,200 307,000 9,400 226,000 4,300 357,000 13,900 268,000 (sat.) 5,800 400,000 16,100 456,000 24,400 *Calculated for an oil mud opposite a freshwater shale @ 25°C (after Baroid manual.)

TEMPERATURE AND PRESSURE CONCERNS: Two other important considerations in the process of drilling fluid selection for a particular project are temperature and mud weight requirements. Most polymers have temperature limitations of between 250 – 300 degrees Fahrenheit. High temperature water base formulations have been developed. Polymers capable of withstanding temperatures up to 400° are available for special applications, but in general polymer muds are for low temperature applications. The inhibitive polymer fluid required to drill reactive sediments in the upper part of the hole, is unlikely to continue to be viable at bottom hole temperatures above 300°. A higher temperature formulation will be necessary, using quite different products. It may not be possible to convert from one to another, or it may just be expensive. Polymer muds in general have a relatively low tolerance for solids. They are limited to mud weights of around 16 lb/gal. Water base mud formulations capable of higher mud weights are possible, but they do not have the over all advantages of polymer muds as water base drilling fluids. Oil and synthetic base drilling fluids can be formulated to be stable to temperatures in excess of 400° F, and mud weights of over 20 lb/gal. The difference between a low temperature and a high temperature formulation is mainly one of degree. Higher emulsifier, and higher fluid loss additive concentrations are required at higher temperatures. 31

The fluid can be altered from one suitable for low temperature applications, to a high temperature formulation merely by increasing product concentrations in the active mud system. The high product concentrations required at elevated temperatures, coupled with high concentrations of weight material needed for high mud weights, can result in high rheologies. These muds are difficult to run. All things considered however, oil based muds will be better in extreme situations than any water base mud. ECONOMICS: Drilling Fluid cost should always be considered in terms of the overall cost of the whole operation. For example, if a hole section that would normally take a week to drill with a water based mud can be drilled in two or three days with SBM, the extra cost of the SBM in relation to WBM can easily be justified by the savings in overall operational costs. The situation where this may not be the case is on extremely low budget operations, where the daily operational costs are very low in relation to the cost of a synthetic base fluid system. This is where the extra logistical considerations and handling costs involved with SBM may come into play. The bottom line however is that drilling fluid costs should never be considered separately from overall operational costs. The potential cost saving benefits to an operation of selecting a high performance drilling fluid should always be considered. It is usually false economy to try and save money on the mud. Cost effectiveness, rather than just cost, should be the determining factor in deciding which drilling fluid system to use. ENVIRONMENTAL CONSIDERATIONS: Needless to say, the protection of the environment is of prime concern to everyone. It is always our aim to do nothing by means of our drilling operations that will do lasting or permanent damage to the environment. An understanding of the environmental impact of all aspects of drilling operations has gradually evolved in recent times. One consideration is concentration of activity. For example a practice followed on one exploration well, isolated and in deep water may be unlikely to have any detrimental environmental impact whatsoever, where the same practice in a producing field, near shore would be environmentally devastating. Present activities are governed by our own desire to do the right thing, as well as government regulations that limit what is allowed. It is probably adequate to satisfy government regulations in these matters, and all drilling fluid design is limited to what is allowed. This sometimes means that the most effective product, or system cannot be used. For example potassium chloride has fallen into disuse for environmental reasons, even though it is inexpensive and highly effective. In terms of oil base muds there has been a learning curve. Diesel and crude oils contain aromatic hydrocarbon substances that are toxic, particularly to marine life. Mineral oils, having low aromatic contents were used for a time, however cuttings beds from wells drilled using mineral oil muds were also found to be toxic to seabed life, even after long periods of time. The focus in recent times has been on the use of Synthetic Fluids. These behave like oils, but are synthesized, and contain no aromatics. While they are considered non-toxic, high concentrations are still harmful to marine life, and we are still undergoing a learning process about their longer-term effects. The current regulations concerning the use of these fluids remain on the conservative side. The satisfaction of environmental regulations does have an economic impact on most drilling operations, and this cost must be considered as part of the big picture when deciding on a drilling fluid system. 32

NOTE: A procedure for running Oil Retention on Cuttings tests is included in the Appendix. PROTECTION OF RESERVOIRS: The causes of reservoir damage by drilling fluids has already been discussed. It is a matter that must be considered in the selection and design process. Freshwater / Lignosulfonate muds are still used in many areas, even though they are known to be highly damaging to reservoir rocks. More important to Unocal operations is understanding the potential of formation damage due to the invasion of fine particles from the mud into the formation. Mud additives that are known to cause reservoir plugging, such as Asphaltine, and Gilsonite fluid loss additives in oil muds should be avoided. Particle size in a drilling fluid is important. The presence of an excess of ultra fine solids is likely to lead to reservoir plugging. Good solids equipment and adequate dilution are necessary. In general, if proper attention is paid to solids control, most commonly used drilling fluids are acceptable. Where reservoir damage is occurring, or is suspected in field wells, specialty Drill-In fluids can be used. Essentially this consists of displacing the hole to a new, clean fluid prior to penetrating the reservoir. When oil base muds are being used, this may simply mean bringing in a newly formulated batch of mud from a mud plant to displace the hole. Water base muds are formulated with special polymers, bridging agents, and usually salts. These have very low solids contents, are designed to bridge quickly and form thin, low permeability filter cakes, and have filtrates that are chemically compatible with formation fluids. 100 % oil fluids have been designed, having low emulsifier concentrations to minimize the possibility of oil wetting of the reservoir rocks. Most of these have a limited application.

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IV. WATER BASE DRILLING FLUID SYSTEMS: IV.1 PROPERTIES AND ADITIVES: All drilling fluid systems consist of a carrier fluid, and additives that perform various functions in conjunction with the fluid, and each other. In water base systems, the base fluid is water. Additives are used to provide properties and to perform corresponding functions, as follows: • • •

Density (Mud Weight): Viscosity / Rheology: Gellation (Gel Strengths):

•

Alkalinity:

•

Fluid Loss Control:

•

Inhibition:

•

Rheology Modification:

• •

Lubricity: Corrosion Control:

Suppress formation pressures. Transport cuttings out of the hole. Form a gel structure when the fluid is static that will suspend weight material and inhibit cuttings settling. Most additives perform best in an alkaline environment. Note that high alkalinities promote the hydration and dispersion of clays. Restricts the invasion of mud filtrate into permeable rocks by forming a thin, low permeability filter cake across the surface of permeable formations. React with clays to reduce their tendency to hydrate and swell. Salts are added to balance osmotic forces. Thinners modify the interparticle forces within drilling fluids. Lubricants reduce drilling torque. Oxygen scavengers, acid gas scavengers, and biocides.

MUD DENSITY: Various materials may be used to add density to a drilling fluid. They may be loosely grouped into soluble and insoluble. Soluble materials are basically the monovalent salts NaCl and KCl. Divalent salts, such as calcium chloride, tend to react to strongly, in an adverse manner, with most common mud additives for them to be useful. They are most commonly used in clear packer and completion fluids, where solids free density is desired. Salts, such as sodium and potassium chloride are not capable of increasing fluid weights past 10 lb/gal, and are generally not considered as weighting materials, but do add density to a mud, and so are mentioned in this section. Barite (barium sulfate) is the most commonly used weighting material. It is cheap, relatively dense, and non-abrasive. Barite has a nominal specific gravity of 4.2 g/cc. Barite is good for mud weights up to 17 – 17.5 lb/gal. Calcium carbonate (limestone) is often added to drilling fluids as a bridging particle or for filtration control. CaCO3 has a specific gravity of 2.7 g/cc, and will increase the mud weight. Mud weights of +/- 12 lb/gal are viable using only CaCO3. Hematite (iron oxide) is commonly used if mud weights above about 17.5 lb/gal are required. Hematite has a density of 5.1 g/cc, and is used for mud weights up to + / - 20 lb/gal. Hematite is relatively abrasive and leads to more frequent change out of pump parts. Hematite also tends to stain the skin and clothing, so is not user friendly. Galena is lead sulfide. It has a specific gravity of 7.4 – 7.7 g/cc, and may be used to formulate drilling fluids up to + / - 30 lb/gal. It is extremely expensive and seldom ever used in the drilling industry.

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Hematite, and particularly Galena are not commonly used materials, and not generally readily available. If a planned well is expected to require hematite as a weighting material it would be advisable to secure adequate supplies prior to commencing the project.

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VISCOSITY / GELLATION: The mechanisms for the creation of viscosity in water based drilling fluids are firstly, the physical concentration of particles suspended in the water. Second, the interactive forces between suspended particles, and finally the viscosity of the water. The primary additive for viscosification and the formation of a gel structure in most drilling fluids, including invert emulsion oil muds is Wyoming Bentonite, a commercial clay which is almost pure Sodium Montmorillonite. This clay is inexpensive, and hydrates readily in fresh water to form colloidal suspensions with excellent viscosities, at relatively low concentrations. The clay particles are negatively charged on their basal surfaces, and may have both negative and positively charged sites on their broken edges. They therefore tend to attract each other in an edge to face orientation, a process known as flocculation, creating a fluid that has Yield Point, and therefore good cuttings carrying capacity. These attractive forces also lead to the formation of a gel structure in stationary fluids, suspending larger particles in the mud, such as weight material, calcium carbonate, etc., and to some extent suspending cuttings, and reducing their settling rate. Water is attracted strongly to the surface of these clays, so that they tend to hydrate and disperse readily. The strength of this attraction is such that water closest to the clay surfaces actually increases in viscosity, increasing the overall viscosity of the mud. Two other clays are sometimes used in water base drilling fluids. They are Attapulgite, and Sepiolite. These are similar clays. They do not have the swelling lattice structure of Montmorillonite, nor the charged basal surface, so are not highly reactive. What they do have is a needle like or rod-like shape, and will disperse in highly saline fluids, imparting viscosity in much the same way the polymers do, by their shape, and concentration, rather than by electrochemical interaction between the particles. They are not good for filtration control. Polymers are also used for viscosification. There are a great number of these, which have various applications in drilling fluids. They may be derived from naturally occurring sources, created as modifications of natural polymers, or synthesized for specific purposes. Naturally the cost of the material increases in direct proportion to the difficulty of producing it. Polymers essentially are long chain molecules. They may be linear or branched. Nearly all of the ones used in drilling fluids are anionic, that is the monomers from which the polymer chain is formed have a net negative charge. Being charged particles, when added to water, these materials hydrate, developing an envelope of water, several molecular layers thick around individual polymer strands. The polymer + water structure is such, that the hydrated polymer particle has a net negative charge, repulsing other hydrated polymer particles. The amount of viscosity created is related to the repulsive forces, and the tangling up of the polymer chains. In a drilling fluid, these negative sites on the polymer chain attract to the positive sites on the broken edges of the clay platelets dispersed in the fluid, vastly increasing their interaction, at much lower concentrations of clay than would otherwise be necessary. Many polymers serve the dual function of viscosifying as well as imparting filtration control to drilling fluids. Viscosification is directly related to the length of the polymer chain. Long chain polymers are used when viscosification and filtration control are required. Short chain polymers are used when filtration control is the primary objective. In general, polymers by themselves can not generate a gel structure in the mud because they do not react with each other. The presence of gel, or bentonite is necessary. There is one polymer however, that does have the capacity to form a gel structure. 36

This is Xanthum Gum, commercially known as XC polymer, a polymer produced by bacterial action on carbohydrates. Usually when a polymer chain is broken by mechanical shearing, the polymer loses its ability to viscosify, as the broken polymer chains cannot link back up. In the case of XC Polymer however, the polymers are thought to form new links in a static fluid, creating gel strengths without needing clay to react with. The common polymers that are used in most water base drilling fluids are the following: •

Starches:

•

CMC:

•

PAC

•

HEC

•

XC

•

PHPA

Various products derived from natural sources. Sensitive to calcium and chloride, low temperature stability, very susceptible to bacterial attack. Used for both viscosity and filtration. Sodium carboxymethyl cellulose. Modified product made from natural cellulose. Used for both viscosity and filtration in fresh water muds. Sensitive to calcium and chloride. Polyanionic cellulose. Derivatives of CMC, are more tolerant of salt and hardness. Used for viscosity and filtration control. Non ionic cellulose polymer. Not effected by hardness, used mainly in completion work. Xanthum gum. Excellent for viscosity, does not impart filtration control. Salt and hardness tolerant. Will develop gel structure. Partially hydrolyzed polyacrylamide. Used for clay encapsulation, viscosity and filtration control. Very sensitive to hardness. Low solids tolerance.

The generic groups above encompass the main products used in drilling fluids. They occur under many different names, depending on supplier. It is theoretically possible to build an almost endless number of different polymers, and there are many around designed for special applications. They are beyond the scope of this discussion. ALKALINITY: Water base drilling fluid additives work better in an alkaline environment. Bentonite hydrates faster and to a greater degree, as do polymers. Some thinners, such as lignosulfonate, are acidic, and only dissolve in alkaline fluids. Alkalinity inhibits corrosion, and bacterial growth in water base fluids. Hydroxyl ions are also used to control the solubility of Calcium in lime muds and control the polymerization of Silicate in silicate muds. The most common additives for alkalinity are Caustic Soda (NaOH), and Potassium Hydroxide (KOH). Caustic soda is used in most water base drilling fluids, while potassium hydroxide is used in Potassium Chloride muds. High alkalinities promote the hydration of formation clays, and the hydration and dispersion of cuttings into the drilling fluid, and may be a substantial factor where borehole instability problems are occurring. High alkalinities may also lead to the precipitation of certain ions in a drilling fluid, removing polymers and clays attached to these ions at the same time, as occurs with cement contamination. Alkalinity measurements are usually referred to in terms of pH, with 7 being neutral and a pH above 7 being alkaline. Most polymer muds are run at a pH of 8.5 – 9.5, while dispersed lignosulfonate muds are run at a pH of 9.5 – 10.5.

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Lime muds are run at a pH of 11.8 – 12.2. The hydroxyl ions in these muds are buffered by the calcium in the mud, and actual free hydroxyl ions, which would promote clay hydration, are in lower concentration than would be expected from the pH. The solution maintains an equilibrium state, where adding extra hydroxyl ions takes some of the free calcium out of solution, creating insoluble lime, and lowering the pH allows more lime to go into solution, freeing both hydroxyl and calcium. The reason for maintaining the pH at +/- 12 is to prevent too much free calcium in the mud, which would cause flocculation, excessive viscosity and excessive fluid loss. Silicate muds require a pH above 11 to prevent the polymerization of the Silicate in the drilling fluid. Typical pH values for these fluids are 11.8 – 12.3. FILTRATION / FLUID LOSS CONTROL: Clay particles in a drilling fluid are plastered against permeable rocks, by differential pressure, to form a filter cake. Flocculated clay particles pack together in random orientations and do not form impermeable filter cakes. High filtration rates push more clay particles to the rock face, forming excessively thick and soft filter cakes, leading to sticky hole. The fluid and fine particle invasion will cause formation damage if the permeable rock is also a reservoir. This is particularly true in the static state, in which quite thick, sticky filter cakes may be formed in high solids muds, even in those having a relatively low fluid loss. Circulating fluids erode away static filter cakes. The earliest approach to filtration control was to use the clay particles in the drilling fluid to create a filter cake. The idea was to deflocculate the clays, neutralizing the positive charges on the broken clay edges, so that the clay platelets would pack tightly together in the same manner as shingles on a roof. These muds required high concentrations of clay to form the filter cake, high concentrations of chemical thinners to neutralize the clays, and high alkalinities to dissolve the thinners. The use of lime or salt for inhibition adds extra ions, and charges that required even higher concentrations of thinners to neutralize. The addition of starches to the fluid enabled filtration control without all the clay and thinner. Muds were formulated with small amounts of flocculated clay to aid viscosification and fluid loss, but the muds could be run at a low solids content. Modern water base drilling fluids rely on polymers for filtration control. In some special applications, graded calcium carbonate may be used as a bridging agent to help control filtration in drilling fluids. It is used where reservoir damage from the drilling fluid is a serious consideration. INHIBITION: section.

Clay reactivity and inhibition have been discussed in detail in the previous

RHEOLOGY MODIFICATION: Rheology modification is usually synonymous with thinning the mud. This may be accomplished by dilution, reducing the physical concentration of particles in the fluid, or by the addition of some chemical thinner to the fluid. Chemical thinners are anionic materials that react with positively charged sites on the broken edges of clay particles. The effect is to increase the net negative charge causing the clay particles to repel each other and disperse. Most thinners are technically low molecular weight, very short chain polymers. Lignosulfonates are still in common use, and are quite functional at low concentrations for modifying rheology, even in non-dispersed polymer muds. They have temperature limitations, and require caustic soda to work, but are otherwise very versatile. 38

The best thinners available at present are very short chain synthetic acrylate polymers. These are usually in liquid suspensions, do not require alkalinity to dissolve, and have very high temperature tolerances, so are excellent for controlling gellation in high temperature water base muds. LUBRICITY: Lubricity was discussed in the previous section. Lubricity in water base muds is related to solids content. Unfortunately low solids muds tend to lack lubricity. Lubricity enhancing additives are available, and are usually proprietary mixtures of various types of vegetable oils. These emulsify as fine droplets within the water phase of the mud and act as fine solid particles rolling around and separating the drill string from the casing and hole. Many polymers improve the lubricating properties of water base drilling fluids. Materials such as graphite, fatty acids, asphalt, fine walnut hulls, glass and Teflon beads have all been used with varying degrees of success. All use the principle of placing a fine solid particle between the moving parts to reduce friction. In selection of a lubricant, consideration should be made to possible formation damage that could be caused by some of the additives recommended for this purpose. CORROSION: Products used in water base muds to control corrosion are usually combinations of oxygen scavengers and biocides. Some products contain amines that film on metal surfaces, reducing water contact, oxidation, and galvanic activity. Ammonium sulfite, and ammonium bisulfite are commonly used oxygen scavengers. Lime may be used to treat out CO 2. Scavengers for H2S are such materials as zinc carbonate and iron oxide compounds. The reaction with zinc carbonate takes place very slowly. The iron oxide compounds are said to work better. CONTAMINANTS: Water base fluids are sensitive to any type of material that increased the ionic activity of the water. Drilling cement contributes calcium and hydroxyl ions to the drilling fluid, causing flocculation of clays, and precipitation of polymers. Anhydrate also contributes calcium. Drilling a salt body contributes sodium and chloride ions, which will react with clays, and cause flocculation. Drill solids are not commonly thought of as a contaminant, but in fact should be considered the worst contaminant of all. Some amount of drill solids are present in all fluids that have been used for drilling, but as their concentration increases the effect can be very damaging to the drilling operation. High drill solids levels reduce ROP, promote thick filter cakes, and can lead to differential sticking of the drill string. Fortunately with the proper use of good modern solids control equipment, the concentration of drill solids in a mud can be kept to levels that are not seriously detrimental. IV.2 WATER BASE MUD SYSTEMS: Water based muds are usually classified into systems based on their physical characteristics. The following types are recognized: • • • •

Dispersed / Deflocculated – non-inhibitive. Inhibitive Dispersed. Non Dispersed – non-inhibitive. Inhibitive non-Dispersed. 39

DISPERSED / NON INHIBITIVE MUDS: These include any type of drilling fluid where filtration control is achieved by means of chemically neutralizing bentonite in the mud so that the clay platelets will pack together and form a thin, low permeability filter cake. The main example of this mud type that might be encountered is the fresh water Lignosulfonate / Lignite system. These systems are formulated from bentonite at +/- 20 lb/bbl, Caustic Soda to pH +/- 10.5, Lignosulfonate at 4 – 6 lb/bbl, and Lignite at 2 – 3 lb/bbl. A small amount of starch is usually added to aid in filtration control. Due to the high chemical concentrations of these muds, they are relatively bullet proof, and were highly favored for a long time as they were easy to run and had stable properties. At the same time the chemical additives attacked all reactive clay solids, promoting hydration and dispersion into the mud. These muds run at high solids contents, and generally have adverse effects on the rate of penetration. They promote dispersion of cuttings into the mud, shale sloughing and hole enlargement. The high pH, fresh water filtrate is highly damaging to any type of reservoir, and Lignosulfonates in the filtrate tend to precipitate out as the filtrate is diluted with formation water, lowering the pH. This causes plugging of pore throats in the rock. These muds characteristically have high plastic viscosities and low yield points, and have poor hole cleaning properties. They are probably the worst mud systems that could possibly be chosen to drill a well. DISPERSED INHIBITIVE MUDS: These are the Lime Muds, Gyp Muds, and similar. The mud relies on a concentration of deflocculated bentonite for viscosity and filtration control, but contains a concentration of cations, which promote inhibition of formation clays, and minimize the dispersion of shale cuttings into the mud. The are moderately inhibitive, and useful in some applications. In general though, there are probably better systems that may be chosen. Seawater / Lignosulfonate muds may also be placed in this category. The use of seawater as a make up fluid goes some way towards balancing osmotic forces between drilling fluid and formation. The bentonite used in the mud must be prehydrated in fresh water. The presence of salt in the mud adds ions, which increase the charges and interparticle forces in the mud, and make it more difficult to completely disperse the clays. Some type of polymer is usually necessary to aid in filtration control. These muds are better than freshwater Lignosulfonates, but only marginally so. NON-DISPERSED WATER BASE MUDS: By definition these are drilling fluids in which the clays are left flocculated or semi-flocculated. Lower concentrations of clay are required, and the muds tend to have a low solids content, and promote faster drilling than dispersed systems. They characteristically have lower plastic viscosities than dispersed, deflocculated fluids. Yield points can easily be adjusted to impart good carrying capacity. A typical make up concentration is 3 – 8 lb/bbl of bentonite. A combination of two or three polymers is used for filtration control and viscosity. Some modern polymer muds are formulated without bentonite, but some clay is always necessary for filtration control. These muds rely on drilled solids for their clay content, not necessarily a good idea.

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A small amount of caustic soda, or potassium hydroxide is used for alkalinity, but as there are no acid type additives, the concentration required is considerably less than with the dispersed muds. Polymer selection depends on function and environment. In fresh water systems starches and CMC are most commonly used, while in inhibitive systems PAC and PHPA are the main polymers used. XCD polymer has special applications for rheology control and may be used in all systems. Low solids / non-dispersed muds are easily formulated to be inhibitive. The common salts, NaCl and KCl are often used, with KCl being the best. Glycols, amines, and other exotic additives are becoming common.

V. INVERT EMULSION MUD SYSTEMS: V.1 PROPERTIES AND ADDITIVES: Emulsions of oil in water are generally considered normal emulsions. Fluids having oil as the continuous component, and with water emulsified within the oil phase, are termed Invert Emulsions. With invert emulsion systems the continuous fluid can be almost any oil that has the right properties. Everything from field crudes to fish oil has been tried. Early oil base muds were not emulsions. Initially use of oil for drilling was in drill-in fluids, to prevent damage to reservoirs. The advantages of oil in terms of reactivity to clay or salt formations was recognized, as well as the superior temperature stability when compared to water mud products. Furthermore the use of oil muds would prevent corrosion, and promote lubricity. Oil had been added to water base drilling fluids for some time, with enhanced performance noted. The advantages, which would be derived from an oil based drilling fluid, were obvious. It remained a matter of finding additives that would impart the properties required of drilling fluids. Water didn’t mix well with the early oil muds, but it was soon realized that Invert Emulsion muds had certain advantages. Emulsified water contributes to viscosity and filtration control. Further, salts can be added to the water to balance hydrational forces in shales, and finally it was realized that by the addition of a divalent salt, such as calcium chloride, in sufficient concentration, water could be sucked out of shales and the rocks strengthened and stabilized. The development of additives has progressed over the years, with many new products coming in just in the last 10 years. The choice of base fluid has gone from crude to diesel, to mineral oil, and is presently centered on various synthetic oils. The important properties of Invert Emulsion muds are much the same as with water base muds, as given below: • • •

Density (Mud Weight): Viscosity / Rheology: Gellation (Gel Strengths):

•

Alkalinity:

Balance formation pressures. Transport cuttings out of the hole. Form a gel structure that will suspend weight material and inhibit cuttings settling through a static fluid. Lime is added for alkalinity. Calcium soap emulsifiers used in many invert emulsion muds require that calcium be added to the mud, as lime to form the emulsion. Lime is also added to most formulations to react out acid gases such as H2S and CO2. 41

•

Fluid Loss Control:

•

Inhibition:

Restrict the invasion of mud filtrate into permeable rocks by forming a thin, low permeability filter cake across the surface of the permeable formation. Oil is the continuous phase. Can be formulated to remove water from clays, improving stability.

DENSITY: Invert Emulsion muds are densified using the same additives as water base muds. A property of oil muds that should be appreciated in relation to mud density is their capacity to expand and contract. The base fluids of these muds are compressible. Muds compress under pressure, and effective densities downhole may be higher than those measured on the surface. Secondly, oils expand and contract with changes in temperature. It is common to see cold mud in the pits after a trip weigh several points more than when the same mud was warm during the drilling interval. The net effect in many cases is that compression downhole is countered by expansion due to temperature, and the two balance out. In deepwater applications the low temperatures and compression work together, so effective fluid densities downhole are always higher than measured at the surface. The use of PWD tools to measure actual downhole effective mud densities is useful with oil muds, and recommended in deepwater applications. A final possibility that exists, in hot holes where the mud is sitting static for some time, is that the mud could expand to the point that the fluid column becomes underbalanced, inducing a kick. VISCOSITY / GELLATION: As with water base muds, the primary additive for viscosification and the formation of a gel structure in invert emulsion drilling fluids is Wyoming Bentonite. The clay is reacted with an amine surfactant, which makes it readily dispersible in oils. The mechanics of viscosification are still similar to water base muds, except that the clay is not hydrated. The particles consequently remain smaller, and there is not the effect of increasing the viscosity of water layers, attracted to the surface of the clay. Creation of viscosity is limited to inter-reactions between the clay particles, and weak interaction with emulsified water. Due to all materials being coated in a film of oil, and not coming into direct contact with each other, viscosity is harder to achieve, and modify. Viscosity development in a newly mixed mud is directly related to the amount of organophyllic clay added, the water to oil ratio, and the amount of shearing the mud has undergone. Shearing is necessary because it breaks the water up into extremely fine particles, disperses the clay, and promotes interaction between the two. Pressure and temperature are important in this process. Hydraulic or mechanical shearing devices that do not pressurize the mud are relatively useless. Specialty additives are currently helping to overcome the viscosity problems that existed with early muds. Additives that give initial viscosity with minimal shearing have been developed. Other additives enhance overall rheology, or just low shear rheology. Many of these newer additives are polymer type materials, and can add viscosity to oil muds in much the same way polymers do in water base muds. Viscosity is more complicated in an Invert Emulsion mud than in a water based one. The base fluid has viscosity, the emulsifiers add to this fluid viscosity, and both are highly effected by changes in temperature. Many base fluids become excessively thick at the cold temperatures encountered in deep water drilling. 42

These aspects need to be considered in designing a fluid for deep-water operations. Unocal’s Ecoflow has been specifically designed to have good cold flow properties. Gellation in oil muds works much the same as gellation in water base muds, but there may be problems in some muds with barite sag if the mud is left stationary in the hole for long periods of time, especially at high temperatures. Increasing the clay content is usually the only solution to this problem. ALKALINITY: Alkalinity in Invert Emulsion muds is not an essential property. It is useful for reacting out acid gasses, but serves no other useful purpose, except to be a measure of the lime content of the mud. Calcium on the other hand is an essential additive in most oil base muds, where the primary emulsifier is a calcium soap. Lime is used as an inexpensive source of calcium that also imparts alkalinity. An excess lime content is therefore maintained in most Invert Emulsion Oil muds to provide calcium for the primary emulsifier, even when acid gasses are not expected. FLUID LOSS CONTROL: Fluid loss control in early oil muds was accomplished by the addition of blown asphalt, which was also used for viscosity. The situation was vastly improved with the introduction of amine treated lignite products, which were readily dispersible in oils and formed thin, low permeability filter cakes without significantly effecting rheology. Just in the last few years, thermoplastic resins / styrene materials have been developed which are highly effective and work at lower concentrations than the older lignite type fluid loss products, enabling lower solids mud systems to be formulated. Asphaltines and gilsonites are still in use, but as discussed in the section on formation damage, these should be avoided. INHIBITION: This refers to the minimizing of reactions between the fluids in the wellbore and shale formations. With Invert Emulsion oil muds, the continuous phase of the fluid is oil; therefore everything is oil wet. Water is not in contact with the formation clays. As mentioned previously, the emulsifier film surrounding the water droplets is a semipermeable membrane and water will be sucked from the mud into the formation by osmotic force, if the ionic activity between the mud and formation is not balanced. Salt must therefore be added to the water phase of an oil mud to prevent this taking place. More importantly by adding sufficient quantities of calcium chloride to invert emulsion muds, it has been demonstrated that water may be removed from the clay. The prevailing opinion on this subject is that it is best to try and “balance” the activity of the mud with the shale, or run a water phase salinity that is biased only slightly to moving water from the shale to the mud. Our experience with water phase salinity has been that higher is better. The main benefit is in hole cleaning. Hard cuttings are much easier to transport out of the hole than soft cuttings, particularly from deviated holes. With high water phase salinities, cuttings are dehydrated rapidly, even from shallow wet formations. A secondary benefit of running high water phase salinities is that there is room for error. It is hard to actually know what salinity level is required to balance the hydrational forces present in shale formations. In the real world, on the rig, cutting things too fine can lead to problems and lost time.

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There is a school of thought, possibly still in existence to some extent, that believes that dehydrating a shale is bad because it will cause the rock to become brittle and fail. In fact sucking water from a shale makes it harder, but there is no evidence to support the theory that it becomes brittle, quite the contrary. Water from the shale is, to some extent, replaced by oil from the mud, so volumetrically the rock remains almost the same. Experience has shown, without a doubt, that high salinities are beneficial, and that increased exposure time actually improves hole condition. With a high salinity Invert Emulsion Drilling Fluid, if there is a hole problem it is almost certain that more mud weight is required. BASE FLUIDS: A number of oils have been used as base fluids over the years. Environmental concerns have limited available choices in recent times. Even with those considerations, the range of fluids available to the Drilling Industry is quite extensive. Factors to consider in the selection of an appropriate fluid for a drilling program include kinematic viscosity, temperature stability, availability and cost, and environmental regulations. Here are some of the fluids that have been used. The list is growing. •

Crude Oil: Field crudes were used in early oil muds. Their properties were not necessarily consistent from one area to another, and they needed to be “weathered” to allow lighter fractions to bleed off prior to use.

•

Diesel Oil / Kerosene: These didn’t have the drawbacks of crude oil, and diesel became the industry standby for many years, until general realization of its adverse environmental impact came to be known.

•

Mineral Oils: There were a number of these produced by different major oil companies. They were all refined to have considerably lower aromatic contents than diesel. Properties varied slightly from fluid to fluid, and some were better than others for formulating drilling fluids. Their use has been curtailed, as considerable environmental impact was still seen from these fluids over time.

•

Esters: The main esters used as drilling fluids have been produced from vegetable oils, particularly palm oil. Esters were initially touted as the answer to the environmental problems associated with Invert Emulsion muds. They have a low inherent toxicity, and readily break down and disappear in the environment. The esters marketed initially had many drawbacks for use as base fluids. First of all alkalinity, as in the lime added to stabilize the primary emulsifier, caused a breakdown of the ester, resulting in toxic compounds. This reaction is greatly accelerated at temperatures above 300° F. A second problem was that this fluid was much more viscous than conventional base fluids, and led to real problems in cold conditions. Formulations used to try and combat the excessive viscosity of the base fluid did not produce the best properties overall in the mud. Additionally these fluids were, and are, very expensive. Many of these problems were overcome by using esters blended with other base fluids. New esters are becoming available with lower fluid viscosities, however they still suffer from a lack of tolerance to alkalinity, and temperature limitations.

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•

Olefins: The olefins used in drilling fluids include Poly Alfa Olefins (PAO), Linear Alfa Olefins (LAO), and Internal Olefins (IO). PAOs are made up of long chain, branched molecules, and for this reason are quite viscous, and not readily biodegradable. They are not particularly good as base fluids in drilling muds. LAOs as the name implies are linear molecules. They have relatively low fluid viscosities and therefore are suitable for use in drilling fluids, but do not score well on toxicity. IOs have higher viscosities than LAOs. They have fair (not good) cold flow properties, but are relatively non toxic, and biodegradable, and are the standard that the EPA has adopted for Synthetic Base Fluids. Most compliant synthetic base fluids used in the United States are blends of IO, and/ or LAO, and an Ester. These fluids are quite expensive.

•

Paraffins: Synthetic paraffins have been around since the Germans invented a process for synthesizing a substitute for diesel oil from natural gas in World War II. They were not among the first fluids of choice when the industry started searching for viable synthetic fluids to meet changing environmental regulations for oil based drilling fluids, because their gas chromatograph signature is very similar to that of diesel. The olefins on the other hand look very different on the GC, and it was thought that this was preferable. Don Van Slyke of Unocal, recognized that paraffin fluids met the definition of “synthetic”, and were potentially more suitable base fluids than the olefins, while at the same time being considerably cheaper. We started using Saraline, and then Ecoflow, a fluid designed specifically to have good cold flow properties for deepwater applications. Ecoflow does not pass the new EPA test for long term biodegradability and therefore has become a non-compliant fluid in United States Federal waters.

EMULSIFIERS: Emulsion stability is one of the most important properties of Invert Emulsion Drilling fluids, yet it is not a property measured directly by any test performed on the mud. Electrical stability is related to emulsion stability, but not a direct measurement of it. The high temperature / high-pressure filtration test is the best way to confirm emulsion stability, but it does not give a measurement of it, just a yes or no answer. The emulsifiers used in drilling fluids are all surfactant materials that form a barrier between water and oil. They attract to and coat the surface of water droplets in the mud with a film that is both polar and non-polar at the same time. The polar component faces inward and attracts strongly to the surface of the water, while the outer surface is made up of non-polar molecules and therefore is oil wettable. The water droplets then become neutral to each other and will not tend to coalesce and separate out of the oil. The primary emulsifiers used for many years are calcium soaps of fatty acids. These products require the addition of calcium to the drilling fluid in the form of calcium hydroxide (hydrated lime), to form the calcium soap emulsifier. Emulsions formed with these products are very strong and long lasting, but take considerable shearing of the mud to fully form. Secondary emulsifiers used in invert emulsion drilling fluids are non-ionic amine type surfactants that help to promote emulsification of water in the oil phase, and also promote oil wetting of solids such as barite. They cannot form tight, long lasting emulsions by themselves, but promote quick emulsification and oil wetting. 45

There are new products that have recently come on the market, which are highly concentrated and function as a single component emulsifier package. These products still require lime, and supplemental wetting agents must be added at higher mud weights. Several “lime-free” emulsifiers are now available also. The development of these was partly driven by Unocal Thailand’s need to be able to monitor CO 2 accurately in the mud logging process, hence the need for a lime free mud. Tests on these emulsifiers show them to be very good, although not as good as the latest concentrated emulsifier products. It should be noted that organo-clays and fluid loss additives used in invert emulsion muds also help to promote emulsion stability. OIL WETTING: Some materials, such as most metals, prefer to be oil wet. Others, such as minerals like barite and clay, prefer to be water wet. In an oil base mud, it is important that everything is oil wet. The main additive to oil muds that requires oil wetting is barite. Secondary emulsifiers are usually formulated to promote oil wetting. Some formulations require the addition of special wetting agents, when these are not present in the emulsifier, or when high concentrations of barite are added. Lecithin is the material usually used in wetting agent products. Barite and water should never be added to the mud at the same time. V.2 MUD SYSTEM FORMULATION: It must be emphasized from the start, that it is highly important to maintain the correct concentration of products in an Invert Emulsion mud. This is important also in water base muds, but not to the degree that it is in oil muds. In particular, emulsifier concentrations are important. Changes in the volume of the system due to barite additions are often overlooked. It is important that all volume increases are noted, and extra emulsifiers, lime, and possibly fluid loss additives, be added to maintain product concentrations in overall pounds of product per total barrels of mud. The first step in designing a formulation for an Invert Emulsion Oil mud is the selection of a base fluid. Secondly would be the determination of the desired oil to water ratio. Drilling fluids are commonly formulated with oil / water ratios in the 70:30 – 80:20 range. Emulsions can be formed with higher water to oil ratios, but do not leave much room for accidental influxes of water into the mud. They would also tend to have higher viscosities. Base fluid costs are a consideration. A mud containing 70 % oil in the liquid phase will be cheaper than one containing 80 % oil in the liquid phase. Oil as a fraction of the mud retained on the cuttings has been another consideration and 50:50 oil / water muds have been tried. These would have very limited application. Higher temperatures and higher mud weights require higher oil to water ratios. At mud weights over 15 lb/gal, and 85:15 – 90:10 ratio is required. High temperature / high weight muds of necessity contain higher concentrations of emulsifiers and filtration control additives. Rheologies tend to become unmanageable. In all these muds emulsified water acts as a solid particle, and therefore increases viscosity. Increasing the oil content helps. Price is usually a bad reason for deciding on the oil / water ratio to be run. Performance should always be the key, but having said that, it is usually cost effective to run lower oil ratios on routine, low mud weight field wells, while going with higher oil to water ratios on exploration wells.

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The procedure for mixing an oil base mud is to add the base oil to a tank, add the emulsifiers, the lime, then other preferentially oil wettable materials, then the water, and lastly the calcium chloride and finally the barite. The organo-clay is sometimes added after the water and before the calcium chloride, because it requires water to yield. Newly mixed oil muds require a high degree of shearing to break the water down into ultra fine droplets, and get it fully emulsified, as well as to develop yield point. If the mud is to be used as dilution for a mud already in use, shearing will take place in the hole. However, when a new mud system is being mixed from scratch, preliminary shearing may help to stabilize initial properties. Shearing systems using centrifugal pumps do not work for invert emulsion muds. Shearing must be done at high pressures. The best method is to use a rig pump, pumping through a jet nozzle or through an adjustable choke. The preferred method of running all muds, but in particular oil muds, is to pre-mix new fluid in a separate tank to the exact formulation desired, and add the new fluid to the active system for dilution. This requires that an extra mud tank be available for pre-mixing new mud, usually not a problem, but something to consider in rig selection. SPACERS: Spacers are always run between Invert Emulsion muds and cement. Cement has a high concentration of water wet solids, while Invert Emulsion muds have a high concentration of oil wetting agents. The mud tries to oil wet the solids in the cement with the result resembling stiff grease. Too thick to be pumpable. Spacers are often run on water to mud, mud to mud, and mud to water displacements, however they are not considered necessary when displacing a light fluid, such as water with a heavier mud. Even going the other way, little advantage is seen to running a spacer. When displacing a water base mud to SBM, a long spacer will help to remove water-wet solids from the hole.

VI. MUD PROPERTIES / MUD REPORTS: VI.1 PROPERTIES COMMON TO ALL DRILLING FLUIDS: • MUD WEIGHT or DENSITY: Mud weight may be measured and reported in pounds per gallon, pounds per cubic foot, or grams per cubic centimeter. Standard API mud balances read in pounds per gallon on one side of the scale, and grams / cc. on the other. Mud balances that can be pressurized, are available for weighing aerated muds. Mud weight is the mud property important in the balancing of downhole formation pressures. Mud density in pounds per gallon may be converted to pounds per square inch / foot by multiplying by 0.052. Mud weights on oil base muds are temperature dependent. Cold muds may weigh several points more than muds at circulating temperature. This is due to expansion / contraction of the oil, and is normal. •

FUNNEL VISCOSITY: The funnel viscosity of a drilling fluid is measured with a Marsh Viscosity Funnel and is defined as the time taken, in seconds, for one quart of fluid to flow from a full Marsh funnel into a viscosity cup.

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The Marsh funnel measures viscosity at only one rate of shear and therefore does not give an accurate picture of the flow properties of a drilling fluid. Nevertheless, it is a simple test and therefore a useful tool for spotting changes in a circulating drilling fluid, particularly with water base muds. With oil base muds, the viscosity of the base fluid is temperature sensitive and the fluid will thin as the mud warms, reducing the funnel viscosity, whereas cold muds may be excessively thick. This reduces the usefulness of this measurement. Nevertheless once a mud has reached circulating temperature it is effective for tracking changes. The Funnel Viscosity of water is 28 sec. / qt., a number handy for checking the accuracy of Marsh Funnels in the field. •

RHEOLOGY: Rheologies (in the field) are measured on either 2 speed or 6 speed rheometers. The rheometer is an instrument where a rotating sleeve surrounds a springloaded bob. The bob is connected to a dial, so that rotation of the bob gives a reading. The rotating sleeve is geared to run at specific speeds. The instrument is designed with a set spacing between the sleeve and the bob and a specified surface area of each, which is active in relation to the other. Tension on the spring is critical so that a deflection of the dial reflects the viscosity of the mud. When the rheometer sleeve is lowered into a mud, the fluid occupies the gap between the sleeve and the bob. Rotating the sleeve will create a frictional drag on the fluid and thus on the bob. Deflection of the bob is proportional to the fluid’s viscosity. At high speeds, the interparticle forces between solids in the mud are largely ineffective, and viscosity is essentially due to the physical concentration of particles in the fluid and collisions between the particles, as well as the base fluid’s viscosity. At lower speeds, viscosity is due more to inter-reactions between active particles in the mud. Two speed rheometers measure at 600 and 300 RPM, while 6 speed units measure at 600, 300, 200, 100, 6, and 3 RPM. With oil muds particularly, it is important to measure rheologies at a set temperature. The API standard is 120° F, but at times this does not accurately reflect the circulating properties of the mud. In hotter muds it is common to run rheologies at 150° F, whereas in deepwater we have using 80°F as the standard. Whichever temperature is selected, it is important to be consistent as the purpose of making regular checks on the mud is to spot changes, or trends that might indicate a potential problem.

•

PLASTIC VISCOSITY: Plastic viscosity reflects the physical concentration of solid particles in the mud. The PV is defined as the rheometer 600 RPM reading – 300 RPM reading. PV will increase with any increase in solids content, whether from barite, drill solids, or others. Emulsified water in an oil mud will also act as a solid and effect PV. Increases in PV at constant mud weights may reflect a degradation of solid particles in the mud into ultra fines. Increasing trends in the plastic viscosity should be noted. Changes in mud temperature on an oil mud will be reflected mainly in the PV reading. The Plastic Viscosity is reduced by dilution to reduce solids concentrations.

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YIELD POINT: The Yield Point is related to interparticle forces between solids in a drilling fluid. Adding clay or polymer viscosifiers to the mud, or increasing interparticle forces increases yield point. These forces are altered in water base muds by changing the ion concentration of the mud. They may be decreased by dilution or by thinners. Thinners are negatively charged particles that neutralize positively charged sites on clay particles. In oil muds YPs are more difficult to achieve, and more difficult to alter. Electrolytes cannot be added to increase flocculation of the clays, since everything is oil wet. In general, thinners are not recommended because their effect is irreversible. Dilution with new pre-mix is preferred. Often dilution has little effect until some critical concentration of clay in the mud is reached, at which time there is a large change in the YP.

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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. Measurements are made on a rheometer using the 3 RPM speed. 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, and a second reading after 10 minutes. In some cases taking a 30 minute reading may be useful. Good drilling fluids should develop a rapid initial gel, but this should remain relatively flat with time. A typical reading in an oil base mud might be 8 / 12. This is considered good. Readings like 3 / 14, or 9 / 55 would be considered progressive, and undesirable in a normal drilling fluid. Highly progressive gel strengths can lead to high initial pressures being required to break circulation after mud in the hole has remained static for a period of time, such as after a trip. They are usually due to of an excess of fine and ultrafine reactive solids in the mud, and indicative that the mud needs dilution. One type of water base mud, known as Mixed Metal Hydroxide or MMH mud, characteristically has very high gellation tendencies. These muds are used mainly for milling operations, but were also tried in horizontal hole drilling.

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LOW RANGE RHEOLOGY: This is not a number commonly included on mud reports, but is a useful indicator of the cuttings transport ability of the mud in high angle holes. The low range rheology is defined as 2 x 3 RPM – 6 RPM readings. Sometimes just the 3 RPM rheometer readings are tracked. The rule of thumb is that the LR rheology should be a number equal to, or larger than the hole size.

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FLUID LOSS: Fluid loss in drilling fluids is measured in either a standard API, or the HTHP filter press. Each press consists of a chamber for the fluid to be tested, with one end being closed off by a lid having a screen across which a piece of filter paper may be placed. The cell is pressured, forcing the fluid against the filter paper. Filtrate forced through the filter paper is collected for 30 minutes, and the quantity measured. The API standard calls for the filtration area to have a 4 inch diameter. The API test is run at a 100 psi differential pressure, and ambient temperature. Readings of 6 – 8 ml / 30 min are typical for modern polymer muds, possibly being reduced to 4 – 6 ml / 30 min for drilling in the reservoir. Drill-In fluids typically have API filtration rates in the range of 2 – 4 ml / 30 min. Properly formulated oil base muds should have a zero API fluid loss. 49

The High Temperature / High Pressure filter press uses a 2 inch diameter filter paper, so volume of fluid recovered in 30 minutes is doubled for reporting purposes. The standard HTHP test is run at a 500 psi differential pressure, at 350° F. It is more common for this test to select a temperature 50° F above the highest bottom hole temperature expected. With water base muds HTHP readings of +/- 25 ml / 30 min are common. This is not a property normally tested for water base muds. The HTHP test is however one of the most important tests that can be run on Invert Emulsion muds. The HTHP result gives not only an indication of fluid loss, but also the best indication available of emulsion condition. Electrical Stability readings can fluctuate considerably. A jump in HTHP is a sure sign of an emulsion stability problem. •

FILTER CAKE: Filter cakes, both in the API and HTHP tests should be relatively thin. Thick filter cakes usually only occur with high static filtration rates and will cause sticky hole.

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SOLIDS CONTENT: The solids content, measured by retorting, is the total solids fraction present in the mud. This includes both soluble and insoluble solids, solid mud additives which are necessary, and drill solids incorporated into the mud from the formations drilled, which are undesirable. The breakdown of the solids into soluble, insoluble high gravity (barite), or insoluble low gravity, may be calculated. “Low gravity solids derived from drilled cuttings are the worst contaminant that may be incorporated into drilling fluids.” That statement may be considered radical at first look because the effect of drill solids on fluid properties is not nearly as dramatic as the effect of cement, or salt on fresh water drilling fluids. Nevertheless, drill solids are being incorporated into the mud during all normal drilling operations, and must be removed in some way, or the mud has to be dumped. The effect of increasing low gravity solids concentrations in drilling fluids is insidious, increasing viscosity, pump pressures, and ECDs. Penetration rates will suffer as the solids content of the mud increases. Filter cakes will become thicker and softer, and differential sticking is likely. Low gravity solids concentrations are extremely important, and should be tracked daily. The upper limit for low gravity solids in a good mud is 5 %, or +/- 50 lb/bbl. 3 – 4 % is ideal. Most muds can tolerate higher LG solids contents, without too great an effect on mud properties, but performance will suffer. One other property that will be seen reported along with HGS / LGS is the ASG, the average specific gravity of the solids in the drilling fluid. Barite has a specific gravity of 4.2, clay and silt = 2.65. ASG gives a quick measure of relative concentrations of low gravity to high gravity solids. Readings of +/- 3.8 or higher are good. Readings below 3.5 suggest that there may be too high a concentration of low gravity solids in the mud.

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VI.2 PROPERTIES SPECIFIC TO WATER BASE FLUIDS: • pH, Pm, Pf / Mf: These properties all relate to alkalinity. pH is a direct measurement of the relative acidity of a fluid. Acidity is due to the concentration of hydrogen ions in the fluid. More hydrogen = more acidic. The pH is an inverse measurement of the hydrogen ion concentration. pH ranges from 1 to 14, with 1 being most acid, 7 being neutral, and 14 being most alkaline. Fluids with a pH above 7 are said to be alkaline, but alkalinity is not necessarily the same thing as pH. Alkalinity is defined as the concentration of water-soluble ions that neutralize acid. These will be substances that will react with hydrogen to form a neutral compound. Essentially there are three groups of substances that may perform this function. They are the hydroxyl ions, carbonate ions, and bicarbonate ions. Hydroxyl is useful and ideally the pH of the mud should be primarily due to the presence of hydroxyl ions. Carbonate and bicarbonate ions may be considered contaminants. High carbonate and bicarbonate alkalinities may cause excessive viscosities and gellation tendencies in water base drilling fluids. Pf and Mf are measurements that are made on filtrates, using indicator solutions, which help to determine which ions are responsible for pH. If the Pf and Mf are roughly equal, the main ion contributing to alkalinity is OH. If Pf and Mf are both high, the carbonate alkalinity is present, and if the Pf is low, and the Mf high, bicarbonate ions are present. There will always be some carbonate and bicarbonate ions, and they are of more concern in high solids muds, such as Lignosulfonates, than in low solids muds. If the Mf is more than a factor of 10 x the Pf, there is excessive carbonate alkalinity. Carbonates are usually treated out with additions of small quantities of lime. The Pm is measured on whole mud rather than just on the filtrate. It is mainly used in lime muds to determine the ratio of insoluble lime in the whole mud to dissolved lime in the filtrate. •

TOTAL HARDNESS: This is a measurement of the total soluble calcium and magnesium ions present in a water base mud filtrate. Excessive hardness will cause flocculation of clays in the mud, effecting filtration rates. Calcium and magnesium also will compete with potassium in reacting and stabilizing formation clays. As both are higher on the reaction series, they will prevent the potassium from fulfilling its function, and should be treated out of KCl muds. Total hardness should be maintained below 200 ppm in most water base drilling fluids, except for lime muds, where it is usually run slightly higher. Total hardness is measured by titration of the filtrate.

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CHLORIDE CONTENT: The chloride content of water base muds is also measured by titration on the mud filtrate. Chlorides are maintained in the mud by the addition of salts such as NaCl and KCl. Chlorides are run sufficient to balance the osmotic forces from ions within clay formations. Seawater contains +/- 19,000 PPM Cl -. Mud salinities of around 30,000 ppm Cl- work reasonable well, if the formation does not contain too much reactive clay. If potassium chloride is used, it is necessary to provide sufficient potassium ions to fully react with the clays. A minimum of 3 % KCl has been recommended. Tests have been run, which show that inhibition increases proportionally with concentration of KCl, up to 10 %, after which the effect tapers off. 51

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METHYLENE BLUE CAPACITY (MBT): Methylene blue is a cationic dye, which strongly attracts to negatively charged sites on clays. Smectite clays have large basal surface areas that are negatively charged, and they have the highest capacity to adsorb methylene blue dye of any clay. The test therefore is a measure of the reactive clay concentration of a water base drilling fluid. Some reactive clay is useful and necessary, but too much can cause problems. Increasing MBTs are usually an indication of an increase in low gravity solids concentrations. In most low solids drilling fluids, MBTs should be maintained at +/- 15 or less, if possible.

VI.3 PROPERTIES SPECIFIC TO INVERT EMULSION DRILLING FLUIDS: • ELECTRICAL STABILITY: The electrical stability of an invert emulsion mud is the voltage necessary to induce current to flow through the mud. The magnitude of this voltage is controlled by a number of factors, including the stability of the emulsion. Oil is an electrical insulator. Oil muds therefore are non-conductive. For electrical current to flow through a mud, the emulsion must be broken, so the current can flow through the water fraction in the mud. The ease or difficulty at which this breakdown may be forced by the Electrical Stability test meter, is related to the strength of the emulsion, but will also be effected by the oil / water ratio of the mud, the degree of shearing, the solids content, temperature, and possibly other factors. There is no specific voltage number that indicates that the emulsion is good or bad. In general, it may be said that electrical stabilities above 150 volts indicate that an emulsion is present. With synthetic base fluids, newly mixed muds usually have an ES of 600 volts, or higher. ES should be tracked for changes, rather than looking for 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. A decreasing ES trend suggests possible emulsion problems and the HTHP filter press should be run. A decreasing ES along with a significant increase in HTHP is a sure sign of a weakened emulsion. •

ALKALINITY / EXCESS LIME: Lime is added to most invert emulsion drilling fluids. Calcium from the lime reacts with fatty acid emulsifiers to form a calcium soap. An excess of lime is usually maintained to insure that enough calcium is available to maintain a strong emulsion. Lime is Calcium Hydroxide, so measuring the alkalinity of the mud indirectly measures the excess lime content. These measurements are made by titration.

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WATER PHASE SALINITY: Water phase salinity is controlled by the addition of calcium chloride to the mud. The salt is dissolved in the water phase of the mud, and therefore the emulsion must be broken if it is desired to measure the salt content. This is accomplished by dispersing the mud in an alcohol, adding an emulsion breaker, and then water. After agitation, the water is tested.

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OIL / WATER RATIO: The fractions of oil and water in a mud are determined by retorting, which also determines the solids content. The oil / water ratio is a ratio of the relative amounts of these to fluids to the total fluid content of the mud, excluding the solids.

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HOT ROLLING TESTS may also be useful in high temperature muds to insure that products will withstand high temperatures in the wellbore during long trips, and logging runs.

SPECIALTY TESTS: All the drilling fluid tests discussed above are performed on the rig with standard testing equipment. In addition there are tests that provide useful information that are only performed in the laboratory, generally either because the complexity of the test makes it impractical to run on a rig, or the equipment used is too delicate, too large, or too expensive to take to the rig. These tests would most likely be run on invert emulsion muds. •

Fann 70 / Fann 75: These two instruments measure rheologies under downhole pressure and temperature conditions. The flow properties of a drilling fluid can change considerably with changes in temperature and pressure. In difficult drilling situations, such as in deep water, it is desirable to fine-tune the mud to the closest rheological tolerances possible. Running periodic checks with these instruments give a better idea of real mud properties. The Fann 75 is essentially an improved, fully programmable version of the Fann 70. On the Fann 70, temperature and pressure settings must be changed manually. On the Fann75 they can be programmed into the machine so that it performs the test automatically. Fann 75 checks are recommended on a regular basis on deepwater muds. They are recommended anytime that the rheological performance of the mud is not satisfactory. Specifically this could be bad hole cleaning, or excessive ECDs.

• PARTICLE SIZE ANALYSIS: A build up of ultra-fine solids in the mud can adversely effect mud performance, and cause reservoir damage. Poor particle size distribution is usually seen on drilling fluids, such as oil muds, which have been used over and over with out adequate dilution. Barite and drill solids in the mud are degraded through continual shearing to ultrafines. As solids are broken up, surface area increases, activity increases and the net result is an increase in viscosity. Regular particle size analysis on invert emulsion muds warns of a shift in particle sizes, which could be a potential problem. In general if the median particle size is in the 50 micron range the mud is probably fine, as long as total low gravity solids are also within range. If median particle size drops to the 10 – 20 micron range, there will be problems.

VII. MUD PROGRAMS: It is usual for a Mud Program to be submitted by the Mud Company supplying the drilling fluid products and engineering service, for each well. The exception to this may be where a standard mud formulation, such as SBM, is used for all wells. In that case a general Mud Guideline document should be prepared to act as a mud program for all wells. Drilling Fluid selection should be based on a thorough evaluation of the functions that will be required of the Fluid. This evaluation should include a look at any offset well data, particularly any problems that might have been encountered, plus a look at any Geological data that is available. This may include age, type, and potential reactivity of formations to be drilled; as well as pore pressure and temperature.

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In the situation where the Mud Company is recommending a Fluid for a particular well or series of wells, the Program should be fully detailed. It should justify the recommendation of a particular Fluid system, and fully explain the components of the system and their functions. It should give recommended mud properties and estimated mud consumption for each interval. There should be a recommended make-up range for the various products recommended, and an estimated total amount of each product to be used. Finally an estimated total cost for each interval, and for the well should be given. A good Mud Program may also include a discussion on solids control, A good Mud Program has the following components: • A brief discussion of the well to be drilled covering any special considerations related to the selection of the recommended Mud System. • A discussion of the Mud System, its functions and cost effectiveness, and why it is particularly suitable for the well to be drilled. • A discussion of the mud products used to make up the recommended Mud System, what each product is, and its function in the System. • A phase by phase breakdown, recommending mud properties and mud formulation for each interval. This should include an estimate of the quantity of mud that will be required to drill the interval, the amount of each product that will be required, and an estimated cost for mud for the interval. • A summary of mud consumption, product requirements, and cost estimates. • A list of products and quantities to be sent to the rig for the well, including contingency items such as lost circulation material. • There should be a discussion on solids control. • If there is a potential for lost circulation, a discussion on the type of lost circulation expected, and recommended cure procedures. There should be a discussion of products and should include recommended make up formulations for LCM pills, and recommended spotting procedures. • A discussion on recommended contingency products, other than LCM. • In a water base mud program, corrosion control should be discussed, and if applicable, a recommendation for corrosion control should be included – corrosion monitoring, products for corrosion control, concentrations and procedures for using the products.

VIII. MUD RECAPS: The Drilling Fluids Recap is the Mud Engineers end of well summary of the use of mud on a particular well. A Recap should have the following elements: •

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A recap should start with a brief well history, followed by a discussion of any mud-related problems that occurred, and recommendations for their remediation. This should include mud consumption, hole problems, lost circulation, etc. These may be on a phase by phase basis. The Recap should give tables showing mud and mud product usage by phase, and mud cost for each phase, as well as a summary of total mud and product consumption and cost. The Recap should also have tables showing Mud Properties on a day to day basis for the whole well. Finally it is common to show graphs of Depth vs. Days, Depth vs. Mud Cost, and Depth vs. Mud Weight.

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IX. MUD RELATED WELL PROBLEMS: IX.1 BOREHOLE STABILITY: Borehole instability due to hydrational swelling, and / or a failure to balance normal pore pressures in shale formations, has already been discussed. It is always correct to assume that if hydrational forces are taken care of in the mud, such as by the use of a high salinity invert emulsion mud, then any hole problems will be due to stresses within the rocks, and can be countered by increased mud weights. It should also be noted that there may be other sources of stress within sedimentary rocks, that is, other than those due to overburden load, which may need to be balanced by mud weight. There are several areas where Tectonic stresses are present, and require mud weights over and above those needed to balance formation pressures, to stabilize the shales. Certain wells drilled in Indonesia, in a normally pressured sequence, required mud weights of 10 lb/gal to stabilize the shales. Ovalization of the borehole is a typical symptom of this type of stress being present. IX.2 LOST CIRCULATION: It should be said that the majority of lost circulation occurrences in normal drilling operations are due to fracturing of brittle formations due to excessive circulating pressures. The exception to this is in drilling carbonate rocks, where the rock matrix is strong enough to support the overburden load without crushing. There may be voids, channels, and even caves within the rock. The two situations are quite different and have to be handled in very different manners. The principles of rock mechanics tell us that a stress field will exist within sedimentary rocks due mainly to the overburden load, but possibly also due to tectonic stresses. There will be a vertical stress component, due to overburden, but there will also be horizontal stress components due to the confining nature of rocks. Sedimentary rocks are made up of both solid, clastic particles, and fluids. The overburden load is supported by a combination of the pressure exerted by the pore fluids, and the strength of the rock itself, due to the arrangement of the clastic particles. If the pressure exerted by the mud against the formation exceeds the least of the vertical or horizontal stress components, plus an increment due to cohesion between particles of the rock, a fracture will be initiated. The equivalent pressure at which this occurs is the fracture strength of the rock. This fracture pressure will always be greater than the pore pressure, and usually less than the total overburden load. In the usual situation, the vertical stress component is higher than the horizontal stresses within the rock, and vertical fracturing occurs. Brittle rocks, such as sandstones will fracture at lower pressures than shales. The horizontal stresses in the rock that resist fracturing increase with depth, because of increasing overburden load. In basic terms then, the deepest rocks in the hole will be the strongest. It needs to be emphasized, and well understood that when lost circulation occurs in the course of normal drilling operations, it will be due to fracturing of the rock at the highest vulnerable place in the hole, usually at the casing shoe, not at the bottom of the hole. Too often lost circulation material is spotted on bottom, when losses are occurring at the shoe. The exception to this will be in producing fields, where reservoir pressures have been depleted. As the pore pressure component of the horizontal stresses within a formation are decreased, the total horizontal stress of the formation is reduced and therefore Fracture gradients in the reservoir will be reduced, and may be lower than fracture gradients higher up the hole.

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It should be understood that with this type of lost circulation, where the rock is actually being fractured by the pressure of the mud, the only real way to stop the loss is to reduce the pressure being applied. Lost circulation materials may have an effect if they can be made to spread out the loading against the formation, but it is a dubious cure at best. A lot of money and time are spent trying to cure fracture losses with LCM, when the only real cure is to reduce pressure against the formation, or seal off the zone with casing. A totally different type of lost circulation occurs when whole mud is being lost into rocks that have actual channels, voids, or fractures in the rock. These do not include fault zones in shales. In deep shales, a fault zone may represent a highly fractured area of rock, but the forces holding the fractures closed will be the same as those present at any other point in the shale. The most usual situation where whole mud is lost into a formation, without exceeding its fracture strength, is in limestones. These may be fossil reefs, or regular limestones, where the matrix of the rock is strong enough to support the load of the overburden without collapsing and closing up any voids in the rock. Fluid will flow into the rock at a pressure just in excess of the pore pressure of the rock. Of course fluid will flow back out, just as easily. There is a real danger of losing circulation, having the annulus drop, and then the well kick. In the worst case scenario, mud will drain into the loss zone, and the annulus will fill with gas. Curing losses of this type can be extremely difficult. Conventional lost circulation material may be ineffective if the flow channels are too large for the LCM to bridge and plug. Cement slurries are an option, but they are often too heavy, and merely flow away into the formation, without curing the loss. Oil / bentonite (Gunk), and organoclay / water slurries may be prepared and are very effective at curing these types of losses. Techniques were developed by Unocal in Indonesia, for drilling lost circulation limestones with synthetic base muds, and curing the losses with organoclay squeezes as they occurred. Formulations and techniques are included in the Appendix of this Manual. IX.3 TERTIARY WELL CONTROL PROBLEMS: Tertiary well control problems refer to those where there is a broken ‘U’ tube. In effect a situation where the pressure required to fracture the formation at some point in the exposed open hole is less than the pressure required to kill a kick in the well. The result is a bleed-in of formation fluid into the annulus, together with a bleed off of mud into the formation. In the severe situation, a cross flow occurs underground, from one formation into another, often termed an “underground blowout”. Tertiary well control situations can usually be managed, if they can be understood. In the most common type of situation, a pressured reservoir zone is penetrated, the well kicks and the casing shoe is too fragile to withstand the pressure required to kill the well. A fracture is initiated at the shoe and mud flows into the formation. Continued efforts to circulate the kick out of the hole using the driller’s method, result in dilution of the mud in the annulus with formation fluids, without effectively killing the well. This can result in serious damage to the mud and potential loss of the hole. In many cases, bridging of the annulus kills the well and everyone breathes a sigh of relief. The well is lost, but the situation is controlled. This is the most expensive and least desirable cure for this problem. In a conventional well control situation, as soon as a broken ‘U’ tube is suspected, it is advisable to re-think the situation, and change tactics. Often it is necessary to improvise. Several tactics are feasible, and may be used. In this situation it is assumed that the kick is from the bottom of the hole and the loss zone is at or near the shoe. If the well can be killed with heavy mud below the loss zone, then this is often an easy fix to the problem. 56

The procedure is to hold an adequate back pressure on the well to prevent further influx, while spotting heavy mud in the annulus from TD back to the shoe or even higher, as fracture pressure conditions allow. To a large degree, this requires bullheading mud into the fracture, but it is expected that any influx will go into the fracture and not be a further problem in the well. If the well is dead, it can be opened up, casing can then be run and cemented. The downside of this technique is that there can be no circulation after the heavy mud has been spotted. If hole stability is a problem, this may not work, but with oil base drilling fluids it is usually very successful. In situations where it is necessary to be able to circulate, or not practical to mix and spot heavy mud in the hole, a barite plug may be used. These are highly effective and have been known to seal off flowing gas. The downside is that the plug must fill at least 200 linear feet of hole and casing cannot be set right on bottom. A discussion and procedure for barite plugs is included in the Appendix. The other situation that may be encountered is where circulation is lost at the bottom of the hole, the annulus cannot be kept full and a zone some distance up the hole kicks. The lost circulation must be addressed prior to killing the well. The best procedure in this case would be to attempt a “Gunk” squeeze to the bottom of the hole and then try and regain circulation. The incidence of this type of tertiary well control situation is rare, but occurs with coral reef reservoirs.

X. RIG MUD SYSTEMS AND EQUIPMENT, SOLIDS CONTROL EQUIPMENT: X.1 FACTORS TO CONSIDER IN RIG SELECTION: • ACTIVE PIT CAPACITY, NUMBER OF PITS, CONFIGURATION: It is usual to have two active mud tanks, in addition to sand traps and reserve / pre-mixing tanks. The best configuration for drilling is to take returns and mix into one tank, and then suck out of another, with the two equalized. Sizes of tanks depend on rig size. Small rigs are usually used to drill shallow wells and do not require the same capacity as a deep-water rig. In general a system with two active mud tanks, and two activereserve mud tanks, for pre-mixing, are a minimal requirement. More volume is always better. This is apart from sand traps and any reserve storage capacity. Pump suctions should be in sumps. • SAND TRAP CAPACITY / CONFIGURATION: Rigs with modern linear motion shakers, do not require the same sand trap / settling capacity of rigs in years gone by. With sufficient fine screen shakers, desanders and desilters, as well as mud cleaners, are redundant. Sand trap capacity can be reduced as it is in fact, dead volume. It is useful to have a minimum of three sand traps. One for settling, one for a mud cleaner suction – if shakers aren’t adequate, and one for a de-gasser. Most rigs have up to 5 sand trap divisions. Equalizers should be configured so the sand traps do not pump dry during connections, with degasser or mud cleaners running. • SLUG PIT: The slug pit should be a minimum of 50 barrels. 80 – 100 is better. • TRIP TANK: Bigger is better. 25 barrels is about the minimum.

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RESERVE MUD CAPACITY: This depends on the rig, and type of wells that are to be drilled and the mud system. If only water base muds are going to be used, probably no additional storage capacity is needed, otherwise capacity should be determined on the basis of displacement requirements. 500 barrels in addition to active, and active reserve is about the minimum required.

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FLOW LINE / FLOW DISTRIBUTION: The ability to drill fast is related to the ability to pump fast, and process cuttings quickly. Poor flow distribution prevents this. There should be a good flow distribution system from flowline to shakers, with flow controlled by something other than butterfly valves. Weir systems work well. CUTTINGS OVERBOARD SYSTEM: It is important that the overboard system for the cuttings is adequate for the hole size and rate of penetration expected. BASE FLUID CAPACITY: Any mixing of Synthetic Base Mud on the rig requires that a certain volume of base fluid be available on the rig. Usually 500 bbl would be the minimum on a small rig, if mud is to be mixed on board. BRINE CAPACITY: Rigs performing completions may need to handle brine, and have brine tanks. Size is related to the volumes needed. MIXING SYSTEM: This includes pumps, hoppers and manifolds. Centrifugal mixing pumps should be 6” x 8” units, with motors capable of pumping heavy mud. Usually 100 HP is minimum, and 12” impellers. Every rig should have two separate mixing manifolds, with separate suction lines into each tank. There should be a minimum of two hoppers, that discharge through separate lines. At the very minimum it should be possible to mix two products independently into the same tank at the same time, or mix in two separate tanks. BULK SYSTEM: The bulk system should be capable of transferring barite to the hopper or surge pod at a high rate. A large number of elbows between bulk tank and surge pod is undesirable. SACK STORE: The amount of storage for mud chemicals on most rigs is something less than ideal. Storage required is based on the minimum amount of reserve mud that might need to be mixed in an emergency, and the turn around time for resuply.

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X.2 SOLIDS CONTROL EQUIPMENT: The importance of good solids control cannot be overemphasized. High drill solids contents contribute to low penetration rates, stuck pipe, and reservoir damage. •

SHALE SHAKERS: Solids control starts with the shale shakers. Ideally there should be sufficient shakers on the rig to be able to handle all the flow desired in 8-1/2” hole over 200 mesh screens. Shale shaker technology has undergone many changes over the years, both in shaker motion and screen design. Much of this technology has been adapted from the mining industry, possibly because they have been in the screening business longer. Initial shaker design consisted of a screen in a frame supported on springs, and a motor at the top of the frame driving a rotating shaft with a weight on one side. The rotating weight caused an elliptical motion of the shaker bed. Being unbalanced, the motion was such that it tended to encourage the movement of cuttings along the screen at the feed end, while having an opposing effect at the discharge end, tending to move the cuttings back to the middle of the screen. Shakers of this type were built with steeply sloping screens, to get the cuttings to move along and off the screen. They were incapable of handling mud flow on screens any finer than 20 or 30 mesh. 58

An advancement to this design was to place the rotating shaft, with the weight, at the center of gravity of the shaker. This resulted in a circular motion of the shaker bed, conveying solids better. Flat bed and multideck shakers were possible and screens up to 80 mesh could be used. The current technology is to use two shafts having counter rotating weights. The weights act in the same direction twice in each rotation, and otherwise cancel each other out. The result is linear motion, with the shaker bed moving back and forth in a straight line, rather than in an circular or elliptical path. This enables a much higher force to be applied to the cuttings, both conveying the cuttings along the screen, and forcing mud through the screen. Shaker beds can now be tilted up at the discharge end, with the cuttings climbing a dry “beach”. Mud removal is considerably better and screens up to 200 mesh may be used. •

HYDROCYCLONES AND MUD CLEANERS: Prior to the introduction of linear motion shakers, the finest screens that could be run on shale shaker were around 80 mesh. These screens could remove solid particles down to +/- 180 microns. The old Rumba shakers with 30 mesh screens removed solids to +/- 540 microns. 200 mesh screens take out solids down to 74 microns, a considerable difference. When coarse screens are run, particularly with water base muds, a lot of fine solids pass through the screens with the mud. These are gradually ground up more and more finely and cause performance problems to the drilling operation. One approach to removing more of these solids is to pump the mud through hydrocyclones. These are cone shaped units, open at the bottom for solids to gravitate out, and at the top for mud to return back to the active system. The mud is pumped into the side of the cone at a high rate, which causes it to spin around the inside of the cone. Heavy particles are thrown to the side of the cone and gravitate down to the small opening at the bottom. The spinning mud forms a vortex in the middle and ascends a return pipe, leading back to the pits. The smaller the diameter of the cone, the faster the mud spins, the higher the force applied to the mud, and the finer the cut. 12” diameter cones are used for removing sand, while 4” diameter cones are used on desilters. A 4” cone is capable of removing solids down to around 40 microns, or a little less. Quite a lot of mud is discarded through hydrocyclones, so they are not practical for use with oil base muds. On the other hand, water base muds, require high dilution rates to control solids, and running the mud through hydrocyclones both helps to clean the fluid, and helps to get rid of excess volume that would otherwise have to be dumped. A downside of pumping the mud through hydrocyclones to clean it, is the fact that centrifugal pumps used to feed the hydrocyclones, also help to degrade the solids into finer and finer particles. An advance on the desander and mud cleaner principle, which enabled their use with oil muds, was the mud cleaner. Where sufficient shakers are available to run the whole circulating volume across fine screens on the shakers, mud cleaners are redundant. However, where coarser screens are in use, processing all the mud with a hydrocyclone, allows a portion of the total circulating system, in which a extra amount of solids has been concentrated, to be screened on very fine screens. Particularly with oil base muds, this saves mud, although it is a much less efficient solids removal method than having the extra shakers. 59

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CENTRIFUGES: Decanting centrifuges are capable of removing all solid particles from a drilling fluid down to 2 microns, that is all solids larger than colloidal size. Actual removal depends on the speed of rotation of the centrifuge bowl, and the time the mud is in the centrifuge. Centrifuge use helps to get rid of ultra fine solids, however only a small portion of the mud is processed, so ultimately dilution will also be required. Practical feed rates on most units are in the range of 40 – 60 GPM. A considerable variety of centrifuging equipment is available today. The best centrifuges have fully and independently, adjustable bowl and conveyor speeds. Increasing bowl speed increases the cut and takes out finer solids. Slowing the conveyor tends to dry out the solids being discharged, but may result in plugging. Speeding up the conveyor moves solids through faster, but throws away more mud with the solids.

X.3 OTHER RIG EQUIPMENT: • HOPPERS: Specialty hoppers, with polyurethane jets and venturis are available. They are very good, especially with polymer muds, where corrosion is a problem. • MIXING SHEARING DEVICES FOR POLYMERS: These devices work on hydraulic shearing principles and are basically used for wetting out and dispersing polymers. They work well for that purpose, and equally well for oil base mud products, but should not be considered a shearing device for Invert Emulsion fluids. • OIL MUD SHEARING DEVICES: Hi pressure is required to shear oil base muds. The best systems come off a rig pump and use a bit with jet nozzles for shearing.

XI. MATERIAL BALANCE CALCULATIONS: The Material Balance equation is the basic building block of most calculations to do with mud, and has uses in other applications as well. It is formula by which all weight / volume calculations are made, and should be understood by everyone. It can be written as follows: Wt1Vol1 + Wt2Vol2 = Wtf x Volf Where: Wt1 is the weight of the first substance or fluid to be mixed together. Vol1 is the volume of the first substance or fluid to be mixed together. Wt2 is the weight of the second substance or fluid to be mixed together. Vol2 is the volume of the second substance or fluid to be mixed together. and: Wtf is the weight of the resulting mixture. Volf is the volume of the resulting mixture. Example: Blend two muds having different weights. Calculate the final mud weight. Blend one tank containing 100 bbl of 10 ppg mud, with a tank containing 200 bbl of 12 ppg mud. (10 ppg x 100bbl) + (12ppg x 200 bbl) = Wtf x Volf 1,000

+

2,400 = Wtf x Volf 3,400 = Wtf x Volf Volf = 100 + 200 = 300 bbl So: Wtf = 3,400 / 300 = 11.33 ppg

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Example: Mix 100 bbl of a 16.5 ppg Barite Plug slurry. How much barite and how much Ecoflow Base Fluid will be required? Water has a specific gravity of 1 gram / cc, and weighs 8.33 lb/gal. To convert the specific gravity of any substance to pounds / gallon, multiply by 8.33. Pounds per barrel = pounds per gallon x 42. Sp.Gr. Ecoflow = 0.79 = 6.58 lb/gal = 276.36 lb/bbl Sp.Gr. Barite = 4.2 = 34.986 lb/gal = 1469.4 lb/bbl Wtf = 16.5 lb/gal = 693 lb/bbl Volf = 100 bbl If Volume of Barite = X, then volume of Ecoflow = 100 – X (1469.4 x X) + (276.39 x (100 – X) = 693 x 100 1469.4X + 27,639 – 276.39X = 69,300 1469.4X – 276.39X = 69,300 – 27,639 1193.04X = 41,661 X = 41,661 / 1193.04 = 34.92 barrels of barite Weight of barite = 34.92 x 1469.4 = 51,311.5 pounds = 513 sacks Volume of Ecoflow = 100 – 35 = 65 bbl Check calculation: (1469.4 x 35) + (276.39 x 65) = Weight of 100 bbl of slurry. 51,429 + 17,965.35 = 69,394.35 pounds Weight of slurry = 69,394.35 lb / 100 bbl = 693.94 / bbl = 16.52 lb/gal Example: Calculate relative amounts of High Gravity and Low Gravity Solids in a mud, based on retort analysis. Mud Weight: 10.2 lb / gal Retort Analysis: Oil: 69.5 % Water: 16 % Corrected Solids: 12.5 % Salt: 2% Calculate: Wt. of 1 bbl of mud = 10.2 x 42 = 428.4 lbs Wt. of oil = 42 x 0.695 = 29.2 gal x 6.6 lb/gal = 192.54 lbs Wt. of water = 42 x 0.16 = 6.7 gal x 8.33 = 55.98 lbs Wt. of Salt = 42 x 0.02 = 0.84 gal x 30 = 25.2 lbs Wt. of Solids = 428.4-192.54-55.98-25.2 = 154.68 lbs / 5.25 gal of solids Calculate: Ratio of HGS to LGS Wt of Barite = 4.2 x 8.33 = 35 lb/gal Wt of LGS = 2.55 x 8.33 = 21 lb/gal (35 x vol of Bar.) + 21 (5.25 - VB) = 154.68 35 VB - 21VB + 110.25 = 154.68 14 VB = 154.68 – 110.25 VB = 44.43 / 14 VB = 3.17 gallons of barite / barrel of mud Wt. of Barite = 3.17 x 35 = 110.95 Vol. of LGS = 5.25 – 3.17 = 2.08 gallons Wt. of LGS = 2.08 x 21 = 43.7 lb / bbl of mud 62

XII. BASIC CHEMISTRY This discussion only covers some very basic chemical definitions, and principles needed to understand the terms, and concepts used in the body of this Manual, and is not intended to be a primer on chemistry. The most basic, chemically unique substance known, one that cannot be made simpler or formed by chemical means is called an ELEMENT. There are in excess of 109 different known elements, and all materials in the Universe are made up of combinations of these elements. COMPOUNDS are formed when two or more elements combine, in set proportions, to form a new substance with unique physical and chemical properties, different from those of the substances from which the compound was formed. The relationship between the elements in a compound, which enable it to form a new stable substance, is called a chemical bond. The smallest particle of a compound that can have a stable independent existence is called a MOLECULE. The smallest unit of an element that can participate in the formation of a molecule is called and ATOM. Atoms therefore are the basic building blocks of all substances, and are the smallest units of matter that can participate in a chemical change. Atoms are known to be composed of three, more simple particles: protons, neutrons and electrons. In form, each atom has a nucleus, made up of the protons and neutrons, and this is surrounded by a “cloud” of electrons. Protons are positively charged, neutrons have no charge, and electrons have a negative charge. Elements differ by the number of protons in the nucleus, Hydrogen 1, Helium 2, Sodium 11, Iron 26, Gold 79, Uranium 92, and so on. In general, there will be the same number of electrons as protons, so that the atom is electrically neutral. There will usually also be the same number of neutrons as protons, but some elements may exist in several forms, having a few more neutrons than protons, and thus a slightly different atomic weight. These are called ISOTOPES of the common form. CHEMICAL REACTIONS between elements involve an energy change and a rearrangement of the electrons surrounding the atoms. This rearrangement generally results in a more stable structure, linking the atoms together to form a Chemical Bond. The chemical bond may be formed in one of two ways. First one atom may give up to, or receive, an electron from another atom. This is known as IONIC BONDING. The atoms associate with each other, but the one giving up the electron looses control over it. The donor atom then becomes positively charged and is known as a CATION, while the atom receiving the electron becomes negatively charged and is called an ANION. Atoms that have lost or gained electrons and therefore carry a positive or negative charge are called IONS. The magnitude of the chemical charge of an ion is the number of electrons lost or gained and is referred to as the VALENCE of the ion. Substances that exhibit Ionic Bonding don’t form into simple molecules, but tend to arrange themselves into a rigid, three dimensional, lattice structure made up of the same ratio of anions to cations in the chemical formula. They generally exist as solids with high melting and boiling points. Examples are salts. 63

Groups of atoms may also lose or gain electrons and become ions. Typical examples are CO 3-2 the carbonate ion, and NH4+ the ammonium ion. The other type of Chemical Bonding which may occur, is where two atoms share one or more electrons. This is called COVALENT BONDING. The more electrons shared, the stronger the bond. In these substances, the bonds holding the individual atoms together are relatively strong, but the molecules formed are comparatively neutral and forces of attraction between them are quite weak. These substances tend to be liquids or gasses. One group of substances having covalent bonding are the Polar Liquids. Water is the most common of these. Glycols also belong in this classification. Different types of atoms have an unequal affinity for electrons. When a covalent bond is formed, the electron distribution is distorted towards the atom with the highest electron affinity. This then results in a molecule that has some areas that are slightly positively charged and other areas that are slightly negatively charged. In the case of water, the oxygen atom has a much higher affinity for electrons than the hydrogen atoms and the electrons are not shared equally. The distribution is distorted towards the oxygen, which thus develops a partial negative charge, while the hydrogens develop a partial positive charge. The polar nature of water causes it to attract to the surface of any substance that is also electrochemically charged. Water molecules will attract to ions and also the surface of clays, sand, etc. The process by which this takes place is known as “water wetting”. Many Ionic substances are soluble in water because the attractive forces between the oppositely charged ions are reduced by water molecules, so that individual ions can separate from the crystal lattice. Each ion in solution is usually surrounded by a shell of water molecules. Common salt is a typical example, where the positively charged sodium ion and the negatively charged chloride ion bond with each other, but in water they disassociate and go into solution, each ion surrounding itself in a shell of water molecules. When water molecules associate themselves with the surface of a charged substance such as a clay particle or an ion and the two become as one, the particle is said to be HYDRATED. Polar liquids, like glycols tend to disperse in water. The reason for this is that molecules of the polar liquid are more strongly attracted to water molecules than they are to each other. Ionic substances tend to dissolve in water if the anion or cation are univalent (single charge). Examples are salts such as NaCl and KCl. Multivalent ionic compounds are insoluble because the attraction between the atoms is too strong for the ions to hydrate. These substances readily water wet however. Barite is an example. Non-polar covalent compounds are generally not soluble in water. Oils are non-polar covalent compounds. These compounds will tend to dissolve other compounds that are not soluble in water. SURFACTANTS are substances that contain both a polar and non-polar group on the same molecule. Surfactants are used as detergents and as emulsifiers. The way emulsifiers work in Invert Emulsion fluids, is that the polar group of the surfactant attracts to water droplets and forms a film surrounding the water droplet within the oil phase of the fluid. The inner surface of this film is polar and therefore bonds with the water. The outer surface of the film is made up of non-polar material, so it is happy to stay dispersed in the oil.

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APPENDIX THE BARITE PLUG: DLG:97

Barite Plugs come under the heading of “Tertiary” Well Control Techniques, that is techniques to be used when a kick cannot be circulated out in the normal manner. Barite Plugs have been described as follows: A Barite Plug is a slurry of barite in fresh water or diesel oil (we would use our synthetic base fluid), which is spotted in the hole to form a barite bridge that will seal the blowout and allow control of the well to be re-established. The plug is displaced through the drill string and, if conditions allow, the string is pulled up to a safe point above the plug. The barite settles out rapidly to form an impermeable mass capable of shutting off high rates of flow. The effectiveness of a barite plug derives from the high density and fine particle size of the barite and its ability to form a tough impermeable barrier. In our application it is conceivable that on one of the exploration wells, while drilling with a native mud in limestone - loosing circulation - we might drill a little too far and encounter a gas sand. We would have no option, but to shut the well in, which would result in an underground blowout. Spotting a barite plug would allow us to set casing down to within a few hundred feet of the sand, and both regain control and salvage the well. A second situation would be in a case where we drill across a fault or otherwise encounter pressure that we cannot hold, whether because of weak formations or a weak casing shoe. Barite plugs have several advantages over cement plugs used in a similar application. Firstly barite will settle through flowing gas and kill and underground blowout. Secondly cement looses its hydrostatic pressure in the gellation stage and allows gas to migrate through it, where barite does not. CEMENT WILL NOT SET UP AND KILL FLOWING GAS. Finally a barite slurry has a lower viscosity than a cement slurry, it can be spotted through the bit and pulled out of without swabbing. The literature states that barite plugs can be mixed at anywhere from 16 - 23 lb / gal. I have spotted plugs from 16.5 ppg to 22 ppg, but found that lighter plugs settle out better, and they are to be preferred. A Contractor manual suggests that the plug should be at least 3 lb / gal over the mud weight and fill 200 ft in the open hole. Baroid suggests 450 ft in the open hole. M-I suggests a minimum 200 sack plug. Whichever guideline is used, the slurry should be heavy enough and the slurry column long enough in the hole, so that hydrostatic pressure is sufficient to kill the well. The plug formed by settling barite becomes added insurance. 65

My experience has been that, although the barite may settle out completely in a pilot test, the solid plug formed in actual practice is only about 50 % of theoretical. The rest of the barite gets suspended at the interface with the mud and doesn’t settle, although it adds to the hydrostatic. I believe that 100 - 200 ft of plug in the open hole is plenty in most situations, but you need to lay a 400 ft long plug to achieve this. There are times when it might be better to lay two plugs, rather than one super large one. In practical terms the slurry should be mixed in a batch mixer, if available, and pumped with the cementing unit. Both mixing and pumping should be at as high a rate as possible to avoid settling. I have never had any problem with settling, but it could happen if pumping was stopped in the middle of the displacement. My notes say to pump and displace the slurry at a minimum of 6 bbl / min. MIXING PROCEDURE IS AS FOLLOWS: Minimum size = 50 bbl pumpable slurry. Water Base Barite Plug: Mix 2 x 35 bbl batches in batch mixer simultaneously, and spot in the open hole. • WATER and BARITE requirements are 0.69 bbl water / barrel of slurry and 450 lb barite / barrel of slurry (0.31 bbl) = 16.5 lb / gal. • Use 2 lb / bbl of liquid thinner: LIQUID THINNER (or equivalent). NOTE: A thinner is absolutely essential in water slurries or the barite won’t settle out to form a hard plug. • For each 35 bbl batch in the batch mixer (25 bbl pumpable), use 24 bbl of drillwater, 10 gal. of Liquid Thinner, weight up to 16.5 ppg with barite (158 sx). Oil Base Barite Plug: • ECOFLOW & BARITE requirements are 0.65 bbl Ecoflow / bbl of slurry and 516 lb barite / bbl of slurry (0.35 bbl) = 16.5 lb / gal. • Add 2 lb / bbl Wetting Agent, or 4 lb / bbl Emulsifier w/ wetting capabilities to the fluid before mixing barite to enhance oil wetting of the barite and promote settling. • For each 35 bbl batch in the batch mixer (25 bbl pumpable), use 23 bbl of Ecoflow, ± 15 gallons of Wetting Agent or 30 gal of Emulsifier. Add barite to a weight of 16.5 lb / gal (181 sx), and pump down the hole. NOTE: It is very important to Pilot Test both water and oil based slurries to establish settling times. (Not all barites are created equal.) Mix the slurry in the HB mixer cup and pour into a 100 ml graduated cylinder. No significant settling should occur in about the first 10 minutes. After 15 minutes the start of a plug of barite should be evident on the bottom of the cylinder when prodded with a stirring rod. This should be up to about 10 % of the barite. In 30 minutes, 30 - 50 % of the barite should be settled, and with 80 100 % of the barite settled in one hour. The rate of settling may be varied by adjusting the amount of thinner in the water base slurry, or wetting agent in the oil base slurry. If it is desired to further slow the settling rate in an oil base slurry, 5 % water can be added in which case Wetting Emulsifier (7 lb / bbl) should be used in preference to Wetting Agent.

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RECOMENDED PROCEDURE FOR ORGANOCLAY SQUEEZE DLG (Revised Sept. 98) NOTE: The objective of this procedure is to produce a 50 : 50 mixture of OBM/SBM and a slurry made up from water and Organophyllic Clay. Once this mixture of slurry and mud is produced, the Organoclay starts to yield and eventually the mixture has a “putty” or modeling clay-like consistency. It is desired to create this mixture in the hole below the bit, and squeeze it into the loss zone you are trying to cure, where it undergoes final swelling and creates a semi-permanent plug of the fractured or vuggular formation. The Organoclay / water slurry is mixed in the Batch Mixer and pumped by the cement unit. It is important that it does not contact any Mud before it exits the bit, or it will start to swell immediately. This should not be a problem if water spacers are used ahead and behind the slurry. MIXING PROCEDURE: The ORGANOCLAY / WATER SLURRY is mixed as follows: For each 10 bbl of slurry: Start with 6.6 bbl of Drill Water Add 37 sx of ORGANOCLAY 1 lb / bbl LIQUID WB THINNER (Polyacryllate) This produces 10 bbl of slurry containing 185 lb/bbl of ORGANOCLAY The Slurry may be mixed in advance, and held in the batch mixer. We have found that MORE SLURRY IS BETTER for successful squeezes. A good recipe for a 50 bbl batch mixer is 25 barrels of Drill water, and 120 – 140 sx of Organoclay, plus ½ - 1 can of liquid Thinner. Add the water, mix half the Organoclay, and add the liquid Thinner, then the remaining Organoclay. This produces 40 – 45 barrels. I would recommend pumping a minimum of 30 barrels. PUMPING PROCEDURE: 1. 2. 3. 4.

Pump 500 linear feet in the pipe of water ahead as a spacer. Pump the desired volume of slurry. Pump 250 linear feet of water behind as a spacer. Displace to the bit with Mud (OBM), using the cement unit, leaving 1 bbl of “water ahead” spacer in the pipe.

NOTE: KEEP THE ANNULUS FULL FROM THE TOP IF NECESSARY WHILE DISPLACING 5. Close the BOP. Line up rig pump on the drill string, cement unit on the annulus. Bullhead an equivalent volume of mud down the annulus with the cement pump, to the barrels of “water ahead” spacer displaced out of the bit. For example if the spacer ahead of the slurry is 10 barrels, 9 will be displaced out of the pipe. Pump 9 bbl of mud down the backside before starting to pump mud down the string. This will insure that mud is moving down the annulus past the bit when the first of the Organoclay Slurry comes out of the bit. 6. Start displacing out of the bit, while continuing to pump into the annulus. Pump at the same rate on both sides. Pump at the slowest rate possible for the rig pumps (+/- 2 bbl/min) to allow the slurry to start yielding as it is pumped into the loss zone.

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NOTE: YOU NEED TO WORK OUT AHEAD OF TIME HOW TO PUMP BOTH TO THE ANNULUS AND DOWN THE PIPE AT THE SAME TIME. It is best to put the cement pump on the annulus because the pumping rate can be controlled more precisely at slow pumping rates. 7. You should see some pressure while squeezing to indicate that you are doing some good. Several hundred PSI is common, however this is a very potent lost circulation cure, and if the loss zone is not too extensive, pressures could be quite high. Hesitation squeezes work well. Stop pumping and let the pressure bleed off, then start again. Use multiple squeezes, pumping the pressure up until it no longer bleeds off when the pumps are shut down. At this point, if some slurry still remains in the pipe, stop pumping. Open the BOP and displace the remaining Organoclay Slurry out of the pipe slowly while pulling up at a rate which keeps the slurry below the bit. (Use the Pump Out schedule.) DO NOT ATTEMPT TO CIRCULATE WITHOUT PULLING PIPE! 8. Establish circulation, bringing the pumps back up slowly to full drilling flow rate. It is a good practice to circulate bottoms up at this point. 9. Wash back to bottom slowly (the Gunk can pack you off), and DRILL AHEAD. DIESEL OIL BENTONITE (GUNK) SQUEEZES: Gunk squeezes are to water base muds what Organoclay squeezes are to Invert Emulsion muds. The procedure is the same, except standard bentonite is added to diesel or base fluid. •

The concentration of bentonite used is higher, 400 lb of bentonite is added per barrel of diesel. 400 lb of bentonite = 0.457 bbl, so yield is 1.457 bbl of slurry / bbl of diesel or SBF. Slurry weight = 11.2 lb/gal.

•

Pump 500 linear feet of diesel or SBF ahead of the GUNK SLURRY, as a spacer, and follow with 250 linear feet behind. It is best to perform the whole operation with the cementing unit. Circulate several barrels of diesel / SBF through the cementing unit, and all lines, before starting to mix bentonite.

•

Displace slurry to bit, keeping hole full by pumping in from the top if necessary. When the slurry reaches the bit, shut the annular, and pump mud (or water) down the annulus with the rig pump, while at the same time displacing the gunk slurry out of the bit, for a 50 : 50 ratio going into the loss zone.

A blend of cement and bentonite may be used, but has to be pre-blended. The usual concentration is 1:1 cement to bentonite. This will give a longer lasting plug, but it requires waiting 12 hours for the cement to set prior to drilling ahead. Procedures given above for the Organoclay squeeze are relevant to the DOB squeeze.

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PROCEDURE FOR MEASURING OIL RETENTION ON CUTTINGS NOTE: Oil retention is the weight of Base Fluid in the mud coating the cuttings, as they come off the shakers or other solids control equipment, to the weight of cuttings (+ mud) being discharged. This may be reported either as % Oil by weight of Wet Cuttings, or % Oil by weight of Dry Cuttings. Obviously the first gives a lower result in the same test. Standard practice in the North Sea is to report results by weight of Dry Cuttings. Elsewhere it is reported by weight of Wet Cuttings. OIL RETENTION AS % BY WEIGHT OF CUTTINGS: • Use a 50 ml Retort. Do not use the retort chamber lid. Fill the top 1/3 of the retort chamber with steel wool. Use Never Seize on the threads. WEIGH THE EMPTY RETORT CHAMBER. NOTE: A BALANCE CAPABLE OF WEIGHING 300 GRAMS WILL BE REQUIRED. •

Fill both halves of the retort chamber with cuttings to be tested, to obtain the maximum sample. Screw the halves together, with the cuttings inside. WEIGH THE CHAMBER WITH THE WET CUTTINGS.

•

WEIGH THE GLASS RECEIVING GRADUATED CYLINDER empty.

•

RETORT THE CUTTINGS. Report the ML of Oil and ML of water. • Weight of Oil = ML Oil x Sp.Gr. of Base Fluid (Ecoflow = 0.79) • Weight of Water = ML of Water x 1 WEIGH THE GLASS CYLINDER WITH THE LIQUID.

• •

After the retort chamber has cooled, WEIGH THE RETORT CHAMBER with dry cuttings.

CALCULATE % OIL BY WEIGHT OF WET CUTTINGS: • Wt. Chamber w/ wet cuttings – Wt. of Empty Chamber = Wt. of Wet Cuttings • Wt. Chamber after retorting – Wt. of Empty Chamber = Wt. of Dry Cuttings • Wt. of Wet Cuttings – Wt. of Dry Cuttings = Weight of Liquid Retorted Off. • Wt. of Glass Cylinder w/ Liquid – Wt. of Cylinder Empty = Wt. of Liquid Recovered. NOTE: WEIGHT OF LIQUID RETORTED OFF MUST BE WITHING 5 % OF WEIGHT OF LIQUID RECOVERED, OR TEST IS INVALID. •

REPORT WEIGHT OF OIL BY WEIGHT OF WET CUTTINGS: = Weight of Oil Recovered ÷ Weight of Wet Cuttings x 100

•

REPORT WEIGHT OF OIL BY WEIGHT OF DRY CUTTINGS: = Weight of Oil Recovered ÷ Weight of Dry Cuttings x 100

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METHYLENE BLUE CAPACITY OF SHALES: The MBC of shales, also known as SHALE FACTOR, is a test for estimating the reactive clay content of a shale. Methylene Blue is a Cationic Dye. The dye will adsorb on the surface of clays, which have a “cation exchange” capability. Clays which attract cations, also attract water, so this is a direct measurement of the “reactivity” of the shale.

Sodium Montmorillonite, in the standard grade used for viscosification of drilling muds, also known as Wyoming bentonite, (gel), has a MBC of 75 – 100, depending on purity. 75 is common. A reading of over 15, on a shale, is considered to be “reactive”. Readings below 5 suggest that all the clays are nonreactive. For example, pure Kaolin will give an MBC of 3. The test simply measures the quantity of dye, which can be adsorbed, by a given quantity of the rock. Results are quoted at milliequvalents of methylene blue dye per 100 grams of shale. The MBC test is adapted from the standard API test for checking the bentonite content of water base drilling fluids. A standard kit, with the methylene blue dye, is usually carried on every rig by the mud engineer.

TEST PROCEDURE: 1. Select specific pieces of shale to be tested. Dry, then pulverize to a fine powder with a mortar and pestle. 2. Weigh ONE (1) gram of sample. Disperse in +/- 100 ml of fresh water. NOTE: the quantity of water has no effect on the test. A 250-ml Erlenmeyer flask is usually used for this test. The test may also be done in a blender. 3. The standard concentration of MB dye is 1 ml = 0.01 meq. Therefore, in this test, 1 ml of MB dye = 1 milliequivalent Methylene Blue Capacity. Check the concentration of the MB solution. 4. Larger samples may be used, with the results corrected back to these concentrations. 5. Add MB dye to the flask in 2 ml increments. Agitate the sample for approx. 1 minute. (Use a rubber stopper & shake the flask). 6. Take a glass stirring rod and, stirring the liquid, take out a drop, and put on a piece of filter paper. A sharp blue dot, composed of dyed particles of clay, indicates that all the dye has been adsorbed by the clay, and the end point has not been reached. 7. Continue adding dye in 2 ml increments, (or more if the approximate end point is known), until, when the drop of sample is placed on the filter paper, a “halo” effect is seen. The halo is a lighter bluish or aqua colored ring, spreading outward from the distinct blue dot of the clay particles. This indicates that the clay has taken up as much dye as it is capable of, and there is now free dye in the solution, to spread into the filter paper. 8. Report the ml of MB dye at the end point. DLG: 8/99

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