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Introduction: Basic Well Completion Concepts lec ( 1 )
Porosity
Porosity is the fraction of the total volume of the rock that is pore (non rock) space or void and not made of solid pieces of the formation. It will be filled with a gas, water or hydrocarbon or two or more at the same time. Porosity will range from a high of 40-50% in some marginally consolidated chalk formations to a low of near zero in some of the evaporites (anhydrite). The average porosity of producing reservoirs ranges from about 515% in limestones or dolomites, 10-25% in sandstones and over 30% in many of the chalk formations. In most unconsolidated formation, porosity depends upon the grain size distribution; not on the absolute size of the grain itself. Porosity can be in the order of 35-40% if all grains are close to the same size, but in most cases where a wide range of grain sizes are available, the porosity will be between 15-25%. Severe cases of formations with mixtures of large and very small grains may have porosities less than 15%.Lower porosities, such as 10% or less, are usually the result of chemical modification of the pore structure, i.e., recementation, precipitation of additional minerals, or leaching and reprecipitation. In some cases, the very consolidated sandstones with overgrowth of quartz may have porosities down to near zero. Geologists further subdivide porosity into several descriptive classifications that help engineers describe the flow of fluids through the formation and into the wellbore. The major classifications are briefly described in the following paragraphs.
- Matrix porosity or intergranular porosity - the porosity between the grains of the formation.
- Vug porosity - porosity in the solution chambers that may range from a tenth of a millimeter to voids larger than a basketball.
- Fracture porosity - the void space created within the walls of an open natural fracture.
- Micro porosity - the voids between the clay platelets or particles. Although a large micro porosity
strong cohesive forces.
The matrix porosity is referred to as the primary porosity and most other porosities are secondary. Usually, the pore space described by natural fractures and vugs are produced or swept very early (flush production) and their continuing use becomes as a conductive pathway to the wellbore. Long term production rate estimates are usually based upon the reserves in the matrix except in very large fields where solution porosity (vugs) is very extensive. Porosity values derived from neutron or sonic logs are usually used alone with other log information and well observations to establish whether a section of rock is “pay.” Although the use of porosity in this manner is common, it can also be very misleading. Obviously, porosity is not a “stand along” value for establishing the quality of ‘pay.” Shales, for example, have porosities of 30% or more but lack the conductive pathways (permeability) to make them economic except where fractured gas-rich shales
exist in massive sections. The location and type of porosity has a great affect on the performance of a well. Relying totally on a log derived porosity, especially in a carbonate, may provide unexpected low production or may result in missing productive intervals. The occurrence of lime muds, a low porosity deposit common within limestones may isolate porosity and result in much lower effective porosities than reported with a log. Fossils,
Saturation
The fraction of pore space containing water is called the water saturation and usually denoted by an Sw. The remaining fraction of the pore space that contains oil or gas is called hydrocarbon saturation Sh. The simple balance sh = 1 - Sw accounts for all of the pore space within a rock. In almost every porous formation, there is at least a small amount of water saturation. Usually when the sediments were laid down, the matrix materials were dispersed in water. As the hydrocarbon entered the porous formation, water was displaced from many of the pores, although the displacement process is not efficient enough to move all the water. This displacement process, whether it was oil displacing
water over geologic time, or water displacing oil during water drive or water flooding, results in a lower saturation of the fluid being displaced. If a very large amount of the driving fluid is displaced, the quantity of the initial fluid reaches a point, usually a few percent of the pore space, where it cannot be reduced further. This level of fluid is the irreducible saturation of that fluid. Therefore, an irreducible water saturation, S,,,i, is the saturation of water in the core that cannot be removed by migration of hydrocarbon. This water or oil, Soil may be trapped in the small pores, held by high capillary attraction, or bound to clays as a surface layer or in the clay lattice.
Permeability
fine-grained sediments with small pores have lower permeabilities. Porosity does not always relate directly to permeability. Materials such as shales and some chalks may have very high porosities but low permeability because of lack of effective connection of the pores.
Permeability to oil, water and gas may be different because of viscosity differences and other influences such as wetting and the issue of the thickness of the liquid coating on the pore wall. Oil wet formations are usually thought to be less permeable to the flow of water than water wet formations because the molecular thickness of the oil coating is thicker than that of water. This leaves less pore space for fluids flow. When more than one phase exists in the pore, relative permeability relationships govern the flow.
Relative Permeability
The effects of relative permeability explain many of the problems involved in formation damage and reduction of flow from a formation, either on initial production or after treating with a material which severely oil wets the formation. As will be pointed out in the chapter on formation damage, problems with relative permeability include a significant drop in permeability to the saturating fluid as trace amounts of a second, immiscible phase are introduced in the flowing liquid. Reductions of up to 80% of initial permeability are common when saturation of an immiscible phase is increased from zero to approximately 20 or 25%. It is this significant reduction in permeability that explains much of the damage behind overtreatment with an oil-filming chemical, such as an oil-based drilling mud, or the use of highly absorptive surfactants or solvents. The surface of the rock also plays an important part since the charge of a surfactant controls the attraction to a particular formation face. It must be remembered that severe wettability problems such as the absorption of cationic materials onto sandstones and the absorption of anionic materials onto limestones can play a significant role in permeability reduction. The reduction from this coating or wetting may be severe and can be long-lasting, depending on the tenacity of the coating. Matrix cleanup of this type of wetting is imperative to fully restore the flow capacity of the formation.Cleanup of this type of damage must take into account both the stripping of the relative permeability influencing layer and the type of rock surface to which it is adsorbed.
Natural Fractures
Natural fractures are breaks in the fabric of the rock caused by a wide variety of earth forces. These natural fractures may have widths of a few thousandths of an inch to a tenth of an inch or more. Natural fractures generally have a common direction that corresponds to forces generated by a significant geologic event in the area such as folding, faulting, or tectonic forces. Where solution etching or cementation forces are active, the fractures may be widened into extensive vugs with permeabilities of hundreds of darcies or filled completely with precipitated minerals. Stylolites or gouge filled fractures are examples of these behaviors. Natural fractures influence flush production or high initial production rate that diminishes quickly after bringing on a new well or the start of flow in a well that has been shut-in. Although they serve as conductive pathways for oil or gas production, they also will transmit water at a much faster rate than the formation matrix, leading to early breakthrough of water or other type floods and sweep problems in reservoir engineering.
Reservoir Pressure
The pressure that the reservoir fluids exert on the well at the pay zone is the reservoir pressure. In single pay completions with little or no rat hole (extra hole below the pay), the reservoir pressure is the bottom hole pressure, BHP. The initial reservoir pressure is the pressure at the time of discovery. Flowing bottom hole pressure is pressure exerted as the result of a drawdown (differential pressure produced by flowing the well). Shut-in pressure is the stable pressure reached after the well has been shut in long enough to come to equilibrium. Shut-in pressures are often quoted as a function of time. The initial pressure is usually a function of depth of burial but may be modified by other forces at thetime of burial or at a later time. Driving pressure may be supplied by a number of mechanisms depending upon the characteristics of the oil and the surrounding geologic and physical forces. The general types of reservoir drive forces (to the limit of general interest in well completions) are:
1. Solution gas drive - a volumetric displacement where all the driving energy or pressure is supplied by gas expansion as the pressure is reduced and the gas comes out of solution. In reservoirs “above the bubble point”, all the gas is dissolved in the oil and there is no free gas. In these reservoirs, there may be a volume change of the oil as the pressure drops and gas breaks out of solution. Reservoir pressure decreases with fluid withdrawals.
2. Gas Cap - a volumetric displacement where the oil is “below the bubble point”, i.e., there is free gas or gas saturation in the pores and there may be a gas cap. Reservoir pressure decreases with fluid withdrawals.
3. Water drive -water influx into the reservoir from edge, bottom or water injection wells can provide very consistent drive pressure to a reservoir. Like the oil, the water moves through the most permeable pathways of the formation towards the pressure drop produced by removal of fluids. The water pushes part of the oil in front, entering some of the pores and displacing the oil. Oil production continues long after the breakthrough of water at the producing well since the formation may contain a number of streaks that have permeability differences an order of magnitude or more. Reservoir pressure may remain the same or drop with fluid withdrawals, depending upon how fast the incoming water replaces the withdrawn fluids.
4. Reservoir compression through compaction in poorly consolidated, high porosity reservoirs is also a “method” of supplying driving energy but it usually generates serious problems in the reservoir. In these reservoirs, which may often be initially over pressured, the reservoir fluids are aoverburden load supporting element. Withdrawal of the fluids requires the matrix of the formation to support more of the load from the overlying sediments (overburden). In some poorly consolidated or weak formations, the matrix compresses under the load, leading to lower porosity and a continued pressure on the remaining fluids. Although this is a definite form of pressure maintenance, when the porosity is decreased, the permeability also is reduced. Compaction of the pay in massive sections may also lead to subsidence of several feet at the surface -- a critical problem for some offshore rigs and sea level land fields.
5. Pressure maintenance or sweep projects using water or gas are our methods of increasing recovery. These processes come with many of the same advantages and limitations as their natural counterparts.
Pressures
To a workover engineer, pressure can be a powerful tool or a nightmare. The difference is in how pressure control is handled. The following "short list" of pressures and pressure related terms presents an idea of what and how pressures are important to the workover.
1. Reservoir Pore Pressure - The pressure of the reservoir fluids, often expressed as a gradient in psilft. The initial reservoir pressure is the pressure at the time of discovery. Fluid withdrawals from a reservoir are made by lowering the pressure in the wellbore. The flow of fluids toward the low pressure creates zones of lower pressure or pressure gradients extending into the reservoir. The reservoir pressure can only be measured at the wellbore in a new well or in a well that has experienced complete buildup.
2. Flowing Bottom Hole Pressure -This pressure is measured at the productive zone during flow. A value of flowing bottom hole pressure is usually reported with a flow rate or a choke setting. A change in the flow rate will change the flowing bottom hole pressure.
3. Drawdown - Drawdown is the pressure differential set by the difference of the reservoir pressure and the flowing bottom hole pressure.
4. Flowing Tubing Pressure - A surface measurement of the pressure in the tubing, prior to the choke, at a particular flow rate. It is equal to the flowing bottom hole pressure minus the hydrostatic pressure exerted by the fluids in the tubing. Because of entrained gas production and gas breakout as the well is produced, it is rarely possible on liquid/gas producers to accurately calculate the flowing bottom hole pressure from the flowing wellhead pressure. Only when the composition of the fluid in the tubing is known can the down hole pressure be calculated.
5. Shut-in Surface Pressure - Any pressure measured at the surface immediately after a well is shut-in will change as bottom hole pressure builds up toward reservoir pressure and the fluids in the tubing come to an equilibrium. Surface measured shut-in pressures are useful in some buildup tests to assess the productivity of a well.
6. Productivity Index - The productivity index is a measurement of well flow potential. It is a term generated from a delivery plot of flow rate and pressure from a particular well. It is commonly expressed as a potential flow rate per pressure drop such as barrels per day per psi. By multiplying the PI by the intended drawdown, a flow rate of the well can be predicted. The PI is established by test on the well. It changes with time.
7. Fracture Breakdown Pressure - A measurement of what pressure is required to hydraulically fracture the rock. The breakdown pressure is usually attained from drilling data, breakdown tests, or fracture stimulations. It is usually expressed as a gradient of pressure per unit of formation depth such as psi/ft.
8. Fracture Extension Pressure -The pressure necessary to extend the fracture after initiation. Like fracture breakdown pressure, it is relevant to a particular well or field.1. Reservoir Pore Pressure - The pressure of the reservoir fluids, often expressed as a gradient in psilft. The initial reservoir pressure is the pressure at the time of discovery. Fluid withdrawals from a reservoir are made by lowering the pressure in the wellbore. The flow of fluids toward the low pressure creates zones of lower pressure or pressure gradients extending into the reservoir. The reservoir pressure can only be measured at the wellbore in a new well or in a well that has experienced complete buildup.
2. Flowing Bottom Hole Pressure -This pressure is measured at the productive zone during flow. A value of flowing bottom hole pressure is usually reported with a flow rate or a choke setting. A change in the flow rate will change the flowing bottom hole pressure.
3. Drawdown - Drawdown is the pressure differential set by the difference of the reservoir pressure and the flowing bottom hole pressure.
4. Flowing Tubing Pressure - A surface measurement of the pressure in the tubing, prior to the choke, at a particular flow rate. It is equal to the flowing bottom hole pressure minus the hydrostatic pressure exerted by the fluids in the tubing. Because of entrained gas production and gas breakout as the well is produced, it is rarely possible on liquid/gas producers to accurately calculate the flowing bottom hole pressure from the flowing wellhead pressure. Only when the composition of the fluid in the tubing is known can the down hole pressure be calculated.
5. Shut-in Surface Pressure - Any pressure measured at the surface immediately after a well is shut-in will change as bottom hole pressure builds up toward reservoir pressure and the fluids in the tubing come to an equilibrium. Surface measured shut-in pressures are useful in some buildup tests to assess the productivity of a well.
6. Productivity Index - The productivity index is a measurement of well flow potential. It is a term generated from a delivery plot of flow rate and pressure from a particular well. It is commonly expressed as a potential flow rate per pressure drop such as barrels per day per psi. By multiplying the PI by the intended drawdown, a flow rate of the well can be predicted. The PI is established by test on the well. It changes with time.
7. Fracture Breakdown Pressure - A measurement of what pressure is required to hydraulically fracture the rock. The breakdown pressure is usually attained from drilling data, breakdown tests, or fracture stimulations. It is usually expressed as a gradient of pressure per unit of formation depth such as psi/ft.
9. Friction Pressure - When fluids are flowed at high rates through a conduit, there is a resistance to flow caused, at least partly, by friction of the fluids at the boundaries of the conduit and by turbulence (mixing) of the fluids. Whether the conduit is pipe or a fracture, friction represents a back pressure. Friction is expressed as pressure at a rate for a unit length of a particular conduit.
10. Bubble Point Pressure - In a reservoir that contains an undersaturated oil, there will be no gas cap. As the pressure is drawn down, the solution gas will break out of solution. Because of relative permeability and saturation concerns, the occurrence of reaching the bubble point usually coincides with a drop in production.
Pressure Differential
Pressure differential is probably the most important pressure during drilling, completion, workover and production. The differential pressure between the wellbore and the formation dictates which direction fluids will move and at what rate they will move. Additional controls such as reservoir permeability and native and injected fluid viscosity also have an affect, as does the presence of solids in the wellbore fluid when the pressure differential is toward the formation. In general, drilling pressure differential should be as low as possible to minimize formation damage and the amount of fluid invasion from wellbore fluids. However, during any drilling, completion or workover operation, the pressure differential must be toward the wellbore (higher pressure in the wellbore than in the reservoir) when well flow is not wanted. Maintaining pressure differential is the same as maintaining well control. Certain conditions, such as intentional or accidental swabbing caused by swab cups or large-diameter tools, can create low pressures at the bottomhole, even with a column of high pressure fluid above the swab or tool. It is the rate of movement and the diameter difference between the object in the hole and the inside of the hole itself that determine the swab or underbalance loads. Each step of a drilling, completion or workover operation, particularly when tools or equipment are removed from the hole, should be examined to determine if swab loads can unbalance the pressure differential and swab fluids into the wellbore. During production, pressure differential toward the wellbore is essential for fluid flow. Columns of standing liquids, excessive backpressures or large amounts of solids in the fluids in the wellbore willact as a check valve, severely limiting production flow into the well. The study of pressure differential and pressure drop is commonly done using a nodal analysis program. These programs compute pressure drops and backpressures on a system, and help identify
those points that may be bottlenecks to good production practices. There are many instances of wells, some even with large-diameter tubing where the tubing has been found to be a “choke” on the production from the well. Changing out the tubing to a larger size in many cases has doubled production from a high capacity well.
Well Temperature
The reservoir at static conditions has a shut-in or reservoir temperature that is characteristic of the depth times the geothermal gradient for that area. A 13,000 ft deep reservoir in one part of the world may have a bottom hole temperature of 1 6OoF, while a similar depth reservoir in a hotter geothermal area may be 360°F.As the well flows, the bottom hole temperature will drop depending on the type and amount of gas and the pressure drop. The cooling is produced by the expansion of gas. Temperature reductions low enough to freeze water may form ice or “hydrates” in some gas wells while wells with a smaller ratio of gas to liquids will flow hot to surface.
Fluid Properties
The composition of the fluid in the formation, at various points in the tubing and at the surface have major affects on the performance of the well and the selection of production equipment. The following terms are required knowledge to describe the fluid and their changing nature.
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1. Gas-oil-ratio, GOR, the amount of free gas associated with the oil production. The gas may ordinarily be in solution or free gas as in a reservoir with a gas cap. When the gas volume is expressed as a function of the total liquids, the value is the gas-liquid-ratio, GLR. Wells with GLRs above 8000 are considered gas wells, while those with a GOR less than 2000 are labeled oil wells. The wells in between 2000 and 8000 are combination wells. The actual GOR value is usually measured at the surface, its value downhole changes with pressure.
2. Water-oil-ratio, WOR, is the amount of water being produced in ratio to the oil production.
3. Bubble point refers to the pressure that a free gas phase will form in an undersaturated oil. The significance is the addition of another phase that, most likely, will lower the relative permeability.
4. Dew point is the pressure and temperature at which the light hydrocarbon gases, Cs-C,, begin to condense into a liquid. The addition of another phase will lower relative permeability.
5. Cloud point is the temperature in an oil system where paraffin crystals appear (cj8 + fraction begins to solidify).
6. Pour point is the temperature below which the oil will no longer pour.
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1. Gas-oil-ratio, GOR, the amount of free gas associated with the oil production. The gas may ordinarily be in solution or free gas as in a reservoir with a gas cap. When the gas volume is expressed as a function of the total liquids, the value is the gas-liquid-ratio, GLR. Wells with GLRs above 8000 are considered gas wells, while those with a GOR less than 2000 are labeled oil wells. The wells in between 2000 and 8000 are combination wells. The actual GOR value is usually measured at the surface, its value downhole changes with pressure.
2. Water-oil-ratio, WOR, is the amount of water being produced in ratio to the oil production.
3. Bubble point refers to the pressure that a free gas phase will form in an undersaturated oil. The significance is the addition of another phase that, most likely, will lower the relative permeability.
4. Dew point is the pressure and temperature at which the light hydrocarbon gases, Cs-C,, begin to condense into a liquid. The addition of another phase will lower relative permeability.
5. Cloud point is the temperature in an oil system where paraffin crystals appear (cj8 + fraction begins to solidify).
6. Pour point is the temperature below which the oil will no longer pour.
High Temperature and High Pressure Wells
Wells with pressures over 0.6 psi/ft and temperatures over 300°F are often referred to as HTHP wells
or high temperature, high pressure wells. These wells account for less than 1% of the total wells
drilled, but may cost 5% or more of the total expenditures for drilling and completions. The risk, reward
and cost can all be very great in these types of wells. Very special workover and completion operations
are necessary to adequately complete and produce these wells.
or high temperature, high pressure wells. These wells account for less than 1% of the total wells
drilled, but may cost 5% or more of the total expenditures for drilling and completions. The risk, reward
and cost can all be very great in these types of wells. Very special workover and completion operations
are necessary to adequately complete and produce these wells.
FUNCTIONS OF A DRILLING FLUID lec ( 1 )
There are a number of functions of a drilling fluid. The more basic of these are listed below:
1. Balance formation pressure
2. Carry cuttings and sloughings to the surface
3. Clean beneath the bit
4. Cool and lubricate bit and drill string
5. Seal permeable formations
6. Stabilize borehole
7. Corrosion control
In addition to these functions, there are several other functions with which the drilling fluid should not interfere:
1. Formation evaluation
2. Completion operations
3. Production operations
Clearly, these lists of functions indicate the complex nature of the Clearly, these lists of functions indicate the complex nature of the role of drilling fluids in the drilling operation. It is obvious that compromises will always be necessary when designing a fluid to carry out these functions, which in some cases require fluids of opposite properties. The most important functions in a particular drilling operation should be given the most weight in design of the drilling fluid.
Many of these functions are controlled by more than one mud property and should be discussed in more detail.
The density of drilling fluid must be such that the hydrostatic pressure exerted by the mud column will prevent flow into the wellbore. This is the first requirement of any drilling fluid and it must be provided for before considering any other mud property or function.
The equation for calculating hydrostatic pressure is:
Hydrostatic Pressure, psi = (depth, ft.)(mud weight, lb./gal)(0.052) Pressure control would be rather simple if it consisted only of balancing the hydrostatic and formation pressures in the static condition. However, pressure is required to cause a fluid to flow This pressure is dissipated in frictional losses along the entire flow path.
Consequently, the total pressure at any point in a circulating system is the sum of the hydrostatic pressure at that point and in the circulating pressure drop from that point to the exit point.
Under normal circulating conditions, the pressure at any given point in the hole is the sum of the hydrostatic pressure at that point and the circulating pressure drop from that point to the flow line. An example of circulating pressures at various points in the system is seen in
Figure 1.
When pipe is run into the hole, the pipe displaces fluid, causing it to flow up the annulus. This is analogous to circulating the fluid and pressure calculations can be made in the same manner. When pipe is being pulled from the hole, the mud falls under its own weight to fill the void volume left by the pipe. The mud flowing down the annulus under gravity develops a flowing pressure drop that subtracts from the hydrostatic pressure. The total pressure at any point in the annulus is the hydrostatic minus the flowing pressure drop from the surface to that point in the annulus.
Figure 2
illustrates pressure profiles under swab, static, or surge conditions. The difference in total pressure at any depth between the hydrostatic and swab or surge lines is the pressure drop caused by pipe movement.
Obviously, if a formation pressure is greater than the wellbore pressure under swab conditions, the formation fluid will flow into the well when the pipe is pulled. If the fracture pressure of a formation is less than the pressure at that depth under surge conditions, the
formation will be fractured while running the pipe and lost circulation will occur. These factors must be taken into account when establishing the required density of a mud.
Normally the mud density will be run slightly higher than required to balance the formation pressure under static conditions. This allows for a safety margin under static conditions and offsets the same amount of negative swab pressure. If the swab effect is still greater
than the overbalance, it must be reduced by slower pipe pulling speeds. This is necessary because further increases in mud density would cause problems in the areas of lost circulation, decreased penetration rates, and differential pressure sticking. The hole must
be filled when pulling pipe to replace the volume of the pipe.
Otherwise, the reduction in hydrostatic pressure will allow the well to flow.
By the same token, if the surge or the circulating pressure drop causes the total pressure to exceed the fracture pressure of a formation, the pipe running speed or the circulating rate must be decreased enough to prevent fracturing from occurring. When it becomes impossible to meet minimum and maximum pressure requirements at realistic pipe moving speeds or circulating rates, it is time to case the hole.
There are at least two different ways of calculating the annular pressure loss while circulating a mud. One method is to measure or predict the mud flow properties under downhole conditions and knowing the circulation rate and hydraulic diameter, calculate
directly the annular pressure drop.
This method has several weaknesses. First, an accurate knowledge of the flow properties of the mud is usually not available. This is especially true of water-base muds, which tend to gel with time when static in the hole and gradually decrease in viscosity when sheared. Such a mud may have a considerably higher gel strength and yield point initially after breaking circulation than under normal circulating conditions. Annular pressure drop calculations using flow line measurements of mud properties will yield pressure losses that
are less than actual when the mud is gelled downhole.
A second problem with annular pressure drop calculations is in knowing the hole diameter. If the hole is washed out, the pressure drop will be less than calculated; if a filter cake is deposited, the diameter will be decreased and the pressure drop greater than calculated. We are normally faced with estimating the average hole diameter in order to calculate pressure drop. The clearance between pipe and hole is very critical to pressure drop when this clearance is small. For this reason we need an accurate estimate of hole size around the drill collars. Fortunately, this is the part of the hole that should be least washed out and has the thinnest filter cake. A third factor that leads to inaccuracy in annular pressure drop
calculations is how well the pipe is centered in the hole. Our calculation procedure assumes perfect centering. This is usually not the case. The pressure drop in the annulus is greatest when the pipe is centered and is least when the pipe is lying against the wall.
This means that we tend to calculate a pressure drop which is higher than actual.
In general, this method of determining annular pressure loss is accurate for oil muds, which are not susceptible to temperature elation and which tend to keep the hole in gage. The method is not so accurate for water muds and especially for those which have high
gel strength at bottom hole temperature.
A second and more accurate method for determining annular pressure losses employs the use of an accurate standpipe pressure measurement. The pressure drop down the drill string and through the bit can be accurately calculated with a Reed Slide Rule and
subtracted from the standpipe pressure. The difference is the pressure drop up the annulus. This method is also quite useful while breaking circulation and until "bottoms up" has been obtained. During this period, the flow properties of the mud downhole are unknown and changing rapidly. This makes the direct calculation of annular pressure drop quite inaccurate. After breaking circulation, the annular pressure drop will decrease for a period of time. This is due to "shearing down" the gel structure of the mud. However, the shear rate in the annulus is not high enough to break all flocculation bonds and the “bottoms up” mud will
remain abnormally high in viscosity. As this mud becomes cooler, as it is circulated up the hole, the viscosity will begin to increase. When the “bottoms up” mud is somewhere in the upper half of the hole, the pressure drop may begin increasing. If the circulation rate is not
decreased, a pressure drop greater than that required to initiate circulation may occur.
A detailed analysis of pressure drop calculations is given in Appendix A. Remember that these are calculations and the answers are only as good as the input data. Always try to determine how the most probable errors in the input data will affect your answer and how this will affect the drilling operation.
The ability to lift particles of various sizes out of the hole is one of
the most important functions of a drilling fluid. This is the only way
that the rock which is drilled or which sloughs from the wall is
carried out of the hole. In a 121/4-inch hole, about 130 pounds of
earth material must be removed for every foot of hole drilled. In fast
drilling an enormous amount of drilled cuttings are entering the mud
system. The mud circulation rate must be high enough to prevent an
excessive increase in mud density or viscosity.
Drilling a 12 ¼-inch hole at 3 feet per minute while circulating a 9
lb./gal mud at 10 bbl/min will result in a mud density increase in the
annulus to 9.5 lb./gal. If the drilled solids are fine and further
dispersed into the mud, a substantial increase in viscosity will result.
The combination of these two effects may cause the equivalent
circulating density of the mud in the annulus to exceed the fracture
gradient and cause loss of circulation. The circulation rate can be
increased to minimize the increase in density and viscosity due to
the influx of solids, but this will also cause an increase in equivalent
circulating density. If this ECD is also higher than fracture gradient,
then the drilling rate must be decreased.
It is possible, for short periods of time, to obtain such high drilling
rates in soft shales that cuttings cannot be wet and dispersed fast
enough to prevent them from sticking together and forming "balls" or
"slabs". For this reason, it is necessary to watch not only the long
time average drilling rate but also the instantaneous rates. A
procedure for calculating annular mud density increase due to drilled
solids influx is given in Appendix A.
Another, more common type of carrying capacity problem is the
ability of the fluid to lift the cuttings or sloughings and carry them out
of the hole. This problem is often difficult to detect because some of
the smaller cuttings come out while the larger ones remain in the
hole. If the hole is beginning to slough, the amount of shale coming
across the shaker will appear to be normal, but large amounts may
be collecting in the hole. Sometimes the appearance of the cuttings
will indicate poor hole cleaning. If the cuttings are rounded, it may
indicate that they have spent an undue amount of time in the hole.
The condition of the hole is usually the best indicator of hole
cleaning difficulty. Fill on bottom after a trip is an indicator of
inadequate cleaning. However, the absence of fill does not mean
that there is not a hole cleaning problem. Large amounts of cuttings
may be collecting in washed-out places in the hole. Drag while
pulling up to make a connection may also indicate inadequate hole
cleaning. When the pipe is moved upward, the swab effect may be
sufficient to dislodge cuttings packed into a washed-out section of
the hole. The sudden dumping of even a small amount of material is
often enough to cause severe drag or sticking.
Hole cleaning is a more severe problem in high-angle holes than in
vertical holes. It is not only more difficult to carry the cuttings out of
the hole, but they need to settle only to the low side of the hole
before causing problems. Consequently, more attention should be
paid to hole cleaning requirements in directional holes.
The ability of a fluid to lift a piece of rock is affected first by the
difference in density of they rock and the fluid. If there is no
difference in densities, the rock will be suspended in the fluid and
will move in a flow stream at the same velocity as the fluid. As the
density of the fluid is decreased, the weight of the rock in the fluid is
increased and it will tend to settle. The shear stress of the fluid
moving by the surface of the rock will tend to drag the rock with the
fluid. The velocity of the rock will be somewhat less than the velocity
of the fluid. The difference in velocities is usually referred to as a
slip velocity. The shear stress that is supplying the drag force is a
function of shear rate of the fluid at the surface of the rock and the
viscosity of the mud at this shear rate. A number of other factors
such as wall effects, inter-particle interference, and turbulent flow
around the particles make exact calculations of slip velocity
impossible. However, equations for estimating slip velocities are
shown in Appendix G. These equations give a rough idea of the size
range that can be lifted under a given set of conditions.
In general, hole cleaning ability is enhanced by the following:
1. Increased fluid density
2. Increased annular velocity
3. Increased YP or mud viscosity at annular shear rates.
It should be noted that with shear thinning fluids it is sometimes
possible to decrease annular velocity, increase the yield point, and
also increase the hole cleaning. This is done in order to minimize
hole erosion. Where viscosity is sufficient to clean the hole, the
annular velocity should be maintained below that for turbulent flow in
order to minimize annular pressure drop and hole erosion. This, of
course, is not possible when drilling with clear water where high
velocities and turbulent flow are usually necessary to clean the hole.
annular velocity should be maintained below that for turbulent flow in
order to minimize annular pressure drop and hole erosion. This, of
course, is not possible when drilling with clear water where high
velocities and turbulent flow are usually necessary to clean the hole.
Cleaning Beneath
the Bit
Cleaning beneath the bit appears to require mud properties almost
opposite from those required to lift cuttings from the hole. In this
case we want the mud to have as low a plastic viscosity as possible.
Since the fluid shear rates beneath the bit are at least 100-fold
greater than in the annulus, it is possible to have low viscosities at
the bit and sufficient viscosity in the annulus to clean the hole. A
mud that is highly shear-thinning will allow both functions to be
fulfilled. Flocculated mud and some polymer muds have this
characteristic.
Since cleaning beneath the bit relates to penetration rate, all other
factors that relate to penetration rate (such as density, hydraulics,
etc.) should be considered simultaneously.
Cooling and
Lubricating
Cooling and lubricating the bit and drill string are done automatically
by the mud and not because of some special design characteristic.
Muds have sufficient heat capacity and thermal conductivity to allow
heat to be picked up down hole, transported to the surface, and
dissipated to the atmosphere.
The process of
circulating cool mud
down the drill pipe
cools the bottom of the
hole. The heated mud
coming up the annulus
is hotter than the earth
temperature near the
surface and the mud
begins to heat the top
part of the hole. This
causes the
temperature profile of
the mud to be different
under static than
under circulating
conditions, as shown
in Figure 3.
The maximum mud temperature when circulating is cooler than the
geothermal bottom-hole temperature. The point of maximum
circulating temperature is not on bottom but about a third of the way
up the hole. These facts are important to remember when attempting
to predict mud behavior downhole. A mud additive which is not
completely stable at the geothermal bottom-hole temperature may
perform adequately at the circulating temperatures. If flocculation
due to temperature begins to occur during circulation, as evidenced
by increases in yield point and gel strength at the flow line, then we
can be assured that severe gelation will occur as the mud heats up
after circulation is stopped.
In addition to cooling the well bore, the circulating mud also removes
frictional heat and supplies a degree of lubrication. Cooling is
especially important at the bit where a large amount of heat is
generated. Sufficient circulation to keep the temperature below a
critical point is essential in using a diamond bit.
Lubrication is a very complex subject and especially as it applies to
the drilling operation. If a mud does not contain a great deal of
abrasive material such as sand, it will supply lubrication to the drill
string simply because it is a fluid that contains solids that are softer
than the pipe and casing. Attempts to improve this basic lubricating
quality of a mud are usually ineffective and expensive. Probably far
greater benefits can be realized by keeping the abrasive content of a
mud as low as possible.
Hole symptoms such as excessive torque and drag, which are often
associated with the need for a lubricant in the mud, are often caused
by other problems such as bit or stabilizer balling, key seats, and
poor hole cleaning. Sometimes materials sold as lubricants relieve
these symptoms, but not as cheaply or effectively as a more specific
solution to the problem.
The success or failure of a lubricant is related to its film strength in
relation to the contact pressure at the surface being lubricated. If the
lubricating film is "squeezed out", then the lubricant has apparently
failed. A material that appears to be a good lubricant in a test at low
contact pressure may fail in actual application due to higher contact
pressures, higher rotating speed, etc. The only good test of a
lubricant is under the exact conditions that exist where lubrication is
desired. Unfortunately, these conditions are not known downhole.
Lubrication should not be confused with attempts to reduce
differential pressure sticking. These are two different problems.
Additives sold as lubricants will probably do very little to relieve
differential pressure sticking if used in the concentrations
recommended for lubrication.
1. Balance formation pressure
2. Carry cuttings and sloughings to the surface
3. Clean beneath the bit
4. Cool and lubricate bit and drill string
5. Seal permeable formations
6. Stabilize borehole
7. Corrosion control
In addition to these functions, there are several other functions with which the drilling fluid should not interfere:
1. Formation evaluation
2. Completion operations
3. Production operations
Clearly, these lists of functions indicate the complex nature of the Clearly, these lists of functions indicate the complex nature of the role of drilling fluids in the drilling operation. It is obvious that compromises will always be necessary when designing a fluid to carry out these functions, which in some cases require fluids of opposite properties. The most important functions in a particular drilling operation should be given the most weight in design of the drilling fluid.
Many of these functions are controlled by more than one mud property and should be discussed in more detail.
Pressure Control
The density of drilling fluid must be such that the hydrostatic pressure exerted by the mud column will prevent flow into the wellbore. This is the first requirement of any drilling fluid and it must be provided for before considering any other mud property or function.
The equation for calculating hydrostatic pressure is:
Hydrostatic Pressure, psi = (depth, ft.)(mud weight, lb./gal)(0.052) Pressure control would be rather simple if it consisted only of balancing the hydrostatic and formation pressures in the static condition. However, pressure is required to cause a fluid to flow This pressure is dissipated in frictional losses along the entire flow path.
Consequently, the total pressure at any point in a circulating system is the sum of the hydrostatic pressure at that point and in the circulating pressure drop from that point to the exit point.
Under normal circulating conditions, the pressure at any given point in the hole is the sum of the hydrostatic pressure at that point and the circulating pressure drop from that point to the flow line. An example of circulating pressures at various points in the system is seen in
Figure 1.
When pipe is run into the hole, the pipe displaces fluid, causing it to flow up the annulus. This is analogous to circulating the fluid and pressure calculations can be made in the same manner. When pipe is being pulled from the hole, the mud falls under its own weight to fill the void volume left by the pipe. The mud flowing down the annulus under gravity develops a flowing pressure drop that subtracts from the hydrostatic pressure. The total pressure at any point in the annulus is the hydrostatic minus the flowing pressure drop from the surface to that point in the annulus.
Figure 2
illustrates pressure profiles under swab, static, or surge conditions. The difference in total pressure at any depth between the hydrostatic and swab or surge lines is the pressure drop caused by pipe movement.
formation will be fractured while running the pipe and lost circulation will occur. These factors must be taken into account when establishing the required density of a mud.
Normally the mud density will be run slightly higher than required to balance the formation pressure under static conditions. This allows for a safety margin under static conditions and offsets the same amount of negative swab pressure. If the swab effect is still greater
than the overbalance, it must be reduced by slower pipe pulling speeds. This is necessary because further increases in mud density would cause problems in the areas of lost circulation, decreased penetration rates, and differential pressure sticking. The hole must
be filled when pulling pipe to replace the volume of the pipe.
Otherwise, the reduction in hydrostatic pressure will allow the well to flow.
By the same token, if the surge or the circulating pressure drop causes the total pressure to exceed the fracture pressure of a formation, the pipe running speed or the circulating rate must be decreased enough to prevent fracturing from occurring. When it becomes impossible to meet minimum and maximum pressure requirements at realistic pipe moving speeds or circulating rates, it is time to case the hole.
There are at least two different ways of calculating the annular pressure loss while circulating a mud. One method is to measure or predict the mud flow properties under downhole conditions and knowing the circulation rate and hydraulic diameter, calculate
directly the annular pressure drop.
This method has several weaknesses. First, an accurate knowledge of the flow properties of the mud is usually not available. This is especially true of water-base muds, which tend to gel with time when static in the hole and gradually decrease in viscosity when sheared. Such a mud may have a considerably higher gel strength and yield point initially after breaking circulation than under normal circulating conditions. Annular pressure drop calculations using flow line measurements of mud properties will yield pressure losses that
are less than actual when the mud is gelled downhole.
A second problem with annular pressure drop calculations is in knowing the hole diameter. If the hole is washed out, the pressure drop will be less than calculated; if a filter cake is deposited, the diameter will be decreased and the pressure drop greater than calculated. We are normally faced with estimating the average hole diameter in order to calculate pressure drop. The clearance between pipe and hole is very critical to pressure drop when this clearance is small. For this reason we need an accurate estimate of hole size around the drill collars. Fortunately, this is the part of the hole that should be least washed out and has the thinnest filter cake. A third factor that leads to inaccuracy in annular pressure drop
calculations is how well the pipe is centered in the hole. Our calculation procedure assumes perfect centering. This is usually not the case. The pressure drop in the annulus is greatest when the pipe is centered and is least when the pipe is lying against the wall.
This means that we tend to calculate a pressure drop which is higher than actual.
In general, this method of determining annular pressure loss is accurate for oil muds, which are not susceptible to temperature elation and which tend to keep the hole in gage. The method is not so accurate for water muds and especially for those which have high
gel strength at bottom hole temperature.
A second and more accurate method for determining annular pressure losses employs the use of an accurate standpipe pressure measurement. The pressure drop down the drill string and through the bit can be accurately calculated with a Reed Slide Rule and
subtracted from the standpipe pressure. The difference is the pressure drop up the annulus. This method is also quite useful while breaking circulation and until "bottoms up" has been obtained. During this period, the flow properties of the mud downhole are unknown and changing rapidly. This makes the direct calculation of annular pressure drop quite inaccurate. After breaking circulation, the annular pressure drop will decrease for a period of time. This is due to "shearing down" the gel structure of the mud. However, the shear rate in the annulus is not high enough to break all flocculation bonds and the “bottoms up” mud will
remain abnormally high in viscosity. As this mud becomes cooler, as it is circulated up the hole, the viscosity will begin to increase. When the “bottoms up” mud is somewhere in the upper half of the hole, the pressure drop may begin increasing. If the circulation rate is not
decreased, a pressure drop greater than that required to initiate circulation may occur.
A detailed analysis of pressure drop calculations is given in Appendix A. Remember that these are calculations and the answers are only as good as the input data. Always try to determine how the most probable errors in the input data will affect your answer and how this will affect the drilling operation.
Hole Cleaning
The ability to lift particles of various sizes out of the hole is one of
the most important functions of a drilling fluid. This is the only way
that the rock which is drilled or which sloughs from the wall is
carried out of the hole. In a 121/4-inch hole, about 130 pounds of
earth material must be removed for every foot of hole drilled. In fast
drilling an enormous amount of drilled cuttings are entering the mud
system. The mud circulation rate must be high enough to prevent an
excessive increase in mud density or viscosity.
Drilling a 12 ¼-inch hole at 3 feet per minute while circulating a 9
lb./gal mud at 10 bbl/min will result in a mud density increase in the
annulus to 9.5 lb./gal. If the drilled solids are fine and further
dispersed into the mud, a substantial increase in viscosity will result.
The combination of these two effects may cause the equivalent
circulating density of the mud in the annulus to exceed the fracture
gradient and cause loss of circulation. The circulation rate can be
increased to minimize the increase in density and viscosity due to
the influx of solids, but this will also cause an increase in equivalent
circulating density. If this ECD is also higher than fracture gradient,
then the drilling rate must be decreased.
It is possible, for short periods of time, to obtain such high drilling
rates in soft shales that cuttings cannot be wet and dispersed fast
enough to prevent them from sticking together and forming "balls" or
"slabs". For this reason, it is necessary to watch not only the long
time average drilling rate but also the instantaneous rates. A
procedure for calculating annular mud density increase due to drilled
solids influx is given in Appendix A.
Another, more common type of carrying capacity problem is the
ability of the fluid to lift the cuttings or sloughings and carry them out
of the hole. This problem is often difficult to detect because some of
the smaller cuttings come out while the larger ones remain in the
hole. If the hole is beginning to slough, the amount of shale coming
across the shaker will appear to be normal, but large amounts may
be collecting in the hole. Sometimes the appearance of the cuttings
will indicate poor hole cleaning. If the cuttings are rounded, it may
indicate that they have spent an undue amount of time in the hole.
The condition of the hole is usually the best indicator of hole
cleaning difficulty. Fill on bottom after a trip is an indicator of
inadequate cleaning. However, the absence of fill does not mean
that there is not a hole cleaning problem. Large amounts of cuttings
may be collecting in washed-out places in the hole. Drag while
pulling up to make a connection may also indicate inadequate hole
cleaning. When the pipe is moved upward, the swab effect may be
sufficient to dislodge cuttings packed into a washed-out section of
the hole. The sudden dumping of even a small amount of material is
often enough to cause severe drag or sticking.
Hole cleaning is a more severe problem in high-angle holes than in
vertical holes. It is not only more difficult to carry the cuttings out of
the hole, but they need to settle only to the low side of the hole
before causing problems. Consequently, more attention should be
paid to hole cleaning requirements in directional holes.
The ability of a fluid to lift a piece of rock is affected first by the
difference in density of they rock and the fluid. If there is no
difference in densities, the rock will be suspended in the fluid and
will move in a flow stream at the same velocity as the fluid. As the
density of the fluid is decreased, the weight of the rock in the fluid is
increased and it will tend to settle. The shear stress of the fluid
moving by the surface of the rock will tend to drag the rock with the
fluid. The velocity of the rock will be somewhat less than the velocity
of the fluid. The difference in velocities is usually referred to as a
slip velocity. The shear stress that is supplying the drag force is a
function of shear rate of the fluid at the surface of the rock and the
viscosity of the mud at this shear rate. A number of other factors
such as wall effects, inter-particle interference, and turbulent flow
around the particles make exact calculations of slip velocity
impossible. However, equations for estimating slip velocities are
shown in Appendix G. These equations give a rough idea of the size
range that can be lifted under a given set of conditions.
In general, hole cleaning ability is enhanced by the following:
1. Increased fluid density
2. Increased annular velocity
3. Increased YP or mud viscosity at annular shear rates.
It should be noted that with shear thinning fluids it is sometimes
possible to decrease annular velocity, increase the yield point, and
also increase the hole cleaning. This is done in order to minimize
hole erosion. Where viscosity is sufficient to clean the hole, the
annular velocity should be maintained below that for turbulent flow in
order to minimize annular pressure drop and hole erosion. This, of
course, is not possible when drilling with clear water where high
velocities and turbulent flow are usually necessary to clean the hole.
annular velocity should be maintained below that for turbulent flow in
order to minimize annular pressure drop and hole erosion. This, of
course, is not possible when drilling with clear water where high
velocities and turbulent flow are usually necessary to clean the hole.
Cleaning Beneath
the Bit
Cleaning beneath the bit appears to require mud properties almost
opposite from those required to lift cuttings from the hole. In this
case we want the mud to have as low a plastic viscosity as possible.
Since the fluid shear rates beneath the bit are at least 100-fold
greater than in the annulus, it is possible to have low viscosities at
the bit and sufficient viscosity in the annulus to clean the hole. A
mud that is highly shear-thinning will allow both functions to be
fulfilled. Flocculated mud and some polymer muds have this
characteristic.
Since cleaning beneath the bit relates to penetration rate, all other
factors that relate to penetration rate (such as density, hydraulics,
etc.) should be considered simultaneously.
Cooling and
Lubricating
Cooling and lubricating the bit and drill string are done automatically
by the mud and not because of some special design characteristic.
Muds have sufficient heat capacity and thermal conductivity to allow
heat to be picked up down hole, transported to the surface, and
dissipated to the atmosphere.
The process of
circulating cool mud
down the drill pipe
cools the bottom of the
hole. The heated mud
coming up the annulus
is hotter than the earth
temperature near the
surface and the mud
begins to heat the top
part of the hole. This
causes the
temperature profile of
the mud to be different
under static than
under circulating
conditions, as shown
in Figure 3.
The maximum mud temperature when circulating is cooler than the
geothermal bottom-hole temperature. The point of maximum
circulating temperature is not on bottom but about a third of the way
up the hole. These facts are important to remember when attempting
to predict mud behavior downhole. A mud additive which is not
completely stable at the geothermal bottom-hole temperature may
perform adequately at the circulating temperatures. If flocculation
due to temperature begins to occur during circulation, as evidenced
by increases in yield point and gel strength at the flow line, then we
can be assured that severe gelation will occur as the mud heats up
after circulation is stopped.
In addition to cooling the well bore, the circulating mud also removes
frictional heat and supplies a degree of lubrication. Cooling is
especially important at the bit where a large amount of heat is
generated. Sufficient circulation to keep the temperature below a
critical point is essential in using a diamond bit.
Lubrication is a very complex subject and especially as it applies to
the drilling operation. If a mud does not contain a great deal of
abrasive material such as sand, it will supply lubrication to the drill
string simply because it is a fluid that contains solids that are softer
than the pipe and casing. Attempts to improve this basic lubricating
quality of a mud are usually ineffective and expensive. Probably far
greater benefits can be realized by keeping the abrasive content of a
mud as low as possible.
Hole symptoms such as excessive torque and drag, which are often
associated with the need for a lubricant in the mud, are often caused
by other problems such as bit or stabilizer balling, key seats, and
poor hole cleaning. Sometimes materials sold as lubricants relieve
these symptoms, but not as cheaply or effectively as a more specific
solution to the problem.
The success or failure of a lubricant is related to its film strength in
relation to the contact pressure at the surface being lubricated. If the
lubricating film is "squeezed out", then the lubricant has apparently
failed. A material that appears to be a good lubricant in a test at low
contact pressure may fail in actual application due to higher contact
pressures, higher rotating speed, etc. The only good test of a
lubricant is under the exact conditions that exist where lubrication is
desired. Unfortunately, these conditions are not known downhole.
Lubrication should not be confused with attempts to reduce
differential pressure sticking. These are two different problems.
Additives sold as lubricants will probably do very little to relieve
differential pressure sticking if used in the concentrations
recommended for lubrication.
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