Fluid is any substance that flows; e.g. oil, water, gas, and ice are all examples of fluids. Under extreme pressure and temperature almost anything will become fluid. Fluid exerts pressure and this pressure is as a result of the density and the height of the fluid column. Most oil companies usually represent density measurement in pounds per gallon (ppg) or kilograms per cubic meter (kg/m3) and pressure measurement in pounds per square inch (psi) or bar or pascal (Pa). Pressure increases as the density of the fluid increases. To find out the amount of pressure a fluid of a known density exerts for each unit of length, the pressure gradient is used. A pressure gradient is defined as the pressure increase per unit of the depth due to its density and it is usually measured in pounds per square inch per foot or bars per meter.It is expressed mathematically as; pressure gradient = fluid density × conversion factor. The conversion factor used to convert density to pressure is 0.052 in English system and 0.0981 in Metric system.
Hydro means water, or fluid, that exerts pressure and static means not moving or at rest. Therefore, hydrostatic pressure is the total fluid pressure created by the weight of a column of fluid, acting on any given point in a well. In oil and gas operations, it is represented mathematically as; Hydrostatic pressure = pressure gradient × true vertical depth or Hydrostatic pressure = fluid density × conversion factor × true vertical depth .
The figure (not shown) shows two wells, well X and Y. Well X has measured depth of 9800 ft and a true vertical depth of 9800 ft while well Y has measured depth of 10380 ft and its true vertical depth is 9800 ft.To calculate the hydrostatic pressure of the bottomhole, the true vertical depth is used because gravity acts (pulls) vertically down the hole. The figure also illustrates the difference between true vertical depth (TVD) and measured depth (MD).
Formation pressure is the pressure of the fluid within the pore spaces of the formation rock. This pressure can be affected by the weight of the overburden (rock layers) above the formation, which exerts pressure on both the grains and pore fluids. Grains are solid or rock material, and pores are spaces between grains. If pore fluids are free to move, or escape, the grains lose some of their support and move closer together. This process is called consolidation. Depending on the magnitude of the pore pressure, it can be described as being normal, abnormal or subnormal. Normal pore pressure or formation pressure is equal to the hydrostatic pressure of formation fluid extending from the surface to the surface formation being considered. In other words, if the formation was opened up and allowed to fill a column whose length is equal to the depth of the formation, then the pressure at the bottom of the column will be equal to the formation pressure and the pressure at surface is equal to zero. Normal pore pressure is not a constant. Its magnitude varies with the concentration of dissolved salts, type of fluid, gases present and temperature gradient.
When a normally pressured formation is raised toward the surface while prevented from losing pore fluid in the process, it will change from normal pressure (at a greater depth) to abnormal pressure (at a shallower depth). When this happens, and then one drill into the formation, mud weights of up to 20 ppg (2397 kg/m ³) may be required for control. This process accounts for many of the shallow, abnormally pressured zones in the world. In areas where faulting is present, salt layers or domes are predicted, or excessive geothermal gradients are known, drilling operations may encounter abnormal pressure. Abnormal pore pressure is defined as any pore pressure that is greater than the hydrostatic pressure of the formation fluid occupying the pore space. It is sometimes called overpressure or geopressure. An abnormally pressured formation can often be predicted using well history, surface geology, downhole logs or geophysical surveys. Subnormal pore pressure is defined as any formation pressure that is less than the corresponding fluid hydrostatic pressure at a given depth. Subnormally pressured formations have pressure gradients lower than fresh water or less than 0.433 psi/ft (0.0979 bar/m). Naturally occurring subnormal pressure can be developed when the overburden has been stripped away, leaving the formation exposed at the surface. Depletion of original pore fluids through evaporation, capillary action and dilution produces hydrostatic gradients below 0.433 psi/ft (0.0979 bar/m). Subnormal pressures may also be induced through depletion of formation fluids. If Formation Pressure < Hydrostatic pressure then it is under pressured. If Formation Pressure > Hydrostatic pressure then it is over pressured .
Fracture pressure is the amount of pressure it takes to permanently deform the rock structure of a formation. Overcoming formation pressure is usually not sufficient to cause fracturing. If pore fluid is free to move, a slow rate of entry into the formation will not cause fractures. If pore fluid cannot move out of the way, fracturing and permanent deformation of the formation can occur. Fracture pressure can be expressed as a gradient (psi/ft), a fluid density equivalent (ppg), or by calculated total pressure at the formation (psi). Fracture gradients normally increase with depth due to increasing overburden pressure. Deep, highly compacted formations can require very high fracture pressures to overcome the existing formation pressure and resisting rock structure. Loosely compacted formations, such as those found offshore in deep water, can fracture at low gradients (a situation exacerbated by the fact that some of total "overburden" up the surface is sea water rather than the heavier rock that would be present in an otherwise-comparable land well). Fracture pressures at any given depth can vary widely because of the geology of the area.
Bottom hole pressure is used to represent the sum of all the pressures being exerted at the bottom of the hole. Pressure is imposed on the walls of the hole. The hydrostatic fluid column accounts for most of the pressure, but pressure to move fluid up the annulus also acts on the walls. In larger diameters, this annular pressure is small, rarely exceeding 200 psi (13.79 bar). In smaller diameters it can be 400 psi (27.58 bar) or higher. Backpressure or pressure held on the choke also increases bottomhole pressure, which can be estimated by adding up all the known pressures acting in, or on, the annular (casing) side. Bottomhole pressure can be estimated during the following activities;
If no fluid is moving, the well is static. The bottomhole pressure (BHP) is equal to the hydrostatic pressure (HP) on the annular side. If shut in on a kick, bottomhole pressure is equal to the hydrostatic pressure in the annulus plus the casing (wellhead or surface pressure) pressure.
During circulation, the bottomhole pressure is equal to the hydrostatic pressure on the annular side plus the annular pressure loss (APL).
During circulating with a rotating head the bottomhole pressure is equal to the hydrostatic pressure on the annular side, plus the annular pressure loss, plus the rotating head backpressure.
Bottomhole pressure is equal to hydrostatic pressure on the annular side, plus annular pressure loss, plus choke (casing) pressure. For subsea, add choke line pressure loss.
An accurate evaluation of a casing cement job as well as of the formation is extremely important during the drilling of a well and for subsequent work. The Information resulting from Formation Integrity Tests (FIT) is used throughout the life of the well and also for nearby wells. Casing depths, well control options, formation fracture pressures and limiting fluid weights may be based on this information. To determine the strength and integrity of a formation, a Leak Off Test (LOT) or a Formation Integrity Test (FIT) may be performed. This test is first: a method of checking the cement seal between casing and the formation, and second: determining the pressure and/or fluid weight the test zone below the casing can sustain. Whichever test is performed, some general points should be observed. The fluid in the well should be circulated clean to ensure it is of a known and consistent density. If mud is used for the test, it should be properly conditioned and gel strengths minimized. The pump used should be a high-pressure, low-volume test or cementing pump. Rig pumps can be used if the rig has electric drives on the mud pumps, and they can be slowly rolled over. If the rig pump must be used and the pump cannot be easily controlled at low rates, then the leak-off technique must be modified. It is a good idea to make a graph of the pressure versus time or volume for all leak-off tests.
The main reasons for performing formation integrity test (FIT) are:To investigate the strength of the cement bond around the casing shoe and to ensure that no communication is established with higher formations.
To determine the fracture gradient around the casing shoe and therefore establish the upper limit of the primary well control for the open hole section below the current casing.
To investigate well bore capability to withstand pressure below the casing shoe in order to validate or invalidate the well engineering plan regarding the casing shoe setting depth.
It is often helpful to visualize the well as a U-tube as in Figure beside. Column Y of the tube represents the annulus and column X represents the pipe (string) in the well. The bottom of the U-tube represents the bottom of the well. In most cases, there are fluids creating hydrostatic pressures in both the pipe and annulus. Atmospheric pressure can be omitted, since it works the same on both columns. If the fluid in both the pipe and annulus are of the same density, hydrostatic pressures would be equal and the fluid would be static on both sides of the tube. If the fluid in the annulus is heavier, it will exert more pressure downward and will flow into the string, displacing some of the lighter fluid out of the string causing a flow at surface. The fluid level will fall in the annulus, equalizing pressures. When there is a difference in the hydrostatic pressures, the fluid will try to reach balance point. This is called U-tubing, and it explains why there is often flow from the pipe when making connections. This is often evident when drilling fast because the effective density in the annulus is increased by cuttings.
The Equivalent Circulating Density (ECD) is defined as the increase in density due to friction and it is normally expressed in pounds per gallon. Equivalent Circulating Density (when forward circulating) is defined as the apparent fluid density which results from adding annular friction to the actual fluid density in the well.
or ECD = MW +( p/1.4223*TVD(M)
Where; ECD = Equivalent circulating density (ppg), Pa = Difference between annular pressure at surface & annular pressure at depth TVD (psi), TVD = True vertical depth (ft), MW = Mud weight (ppg)
The total pressure acting on the wellbore is affected by pipe movement upwards or downwards.Tripping pipe into and out of a well is one other common operation during completions and workovers. Unfortunately, statistics indicate that most kicks occur during trips. Therefore, understanding the basic concepts of tripping is a major concern in completion/workover operations. Downward movement of tubing(tripping in) creates a pressure that is exerted on the bottom of a well. As the tubing is being run into a well, the fluid in the well must move upward to exit the volume being entered by the tubing.The combination of the downward movement of the tubing and the upward movement of the fluid (or piston effect) results in an increase in pressure at any given point in the well.This increase in pressure is commonly called Surge pressure. Upward movement of the tubing(tripping out) also affects the pressure which is imposed at the bottom of the well. When pulling pipe from the well,fluid must move downward and replace the volume which was occupied by the tubing. The net effect of the upward movement of the tubing and the downward movement of the fluid creates a decrease in bottomhole pressure. This decrease in pressure is referred to as Swab pressure. Both surge and swab pressures are affected by the following parameters:Velocity of the pipe,or tripping speed
Fluid gel strength
Well bore geometry (annular clearance between tools and casing, tubing open ended or closed off)
The faster pipe is tripped, the higher the surge and swab pressure effects will be. Also, the greater the fluid density, viscosity and gel strength, the greater the surge and swab tendency. Finally, the downhole tools such as packers and scrapers,which have small annular clearance, also increase surge and swab pressure effects. Determination of actual surge and swab pressures can be accomplished with the use of WORKPRO and DRILPRO calculator programs or hydraulics manuals.
In well control,it is defined as the difference between the formation pressure and the bottomhole hydrostatic pressure. These are classified as overbalanced, underbalanced and balanced.
It means the hydrostatic pressure exerted on the bottom of the hole is greater than the formation pressure. i.e. HP > FP
It means the hydrostatic pressure exerted on the bottom of the hole is less than the formation pressure. i.e. HP < FP
It means the hydrostatic pressure exerted on the bottom of the hole is equal to the formation pressure. i.e. HP = FP
Cuttings are rock fragments chipped, scraped or crushed away from a formation by the action of the bit. The size, shape and amount of cuttings depend largely on formation type, weight on the bit, bit dullness and the pressure differential (formation versus fluid hydrostatic pressures). The size of the cuttings usually decreases as the bit dulls during drilling if weight on bit, formation type and the pressure differential, remain constant. However, if the pressure differential changes (formation pressure increase),even a dull bit could cut more effectively, and the size, shape and amount of cuttings could increase.
Kick is defined as an undesirable influx of formation fluid into the wellbore. If left unchecked, a kick can develop into blowout (an uncontrolled influx of formation fluid in to the wellbore).The result of failing to control a kick leads to loss operation time, loss of well and quite possibly, the loss of the rig and lives of personnel.
Once the hydrostatic pressure is less than the formation pore pressure, formation fluid can flow into the well. This can happen when one or a combination of the following occurs;Improper hole fill up
Insufficient Mud density
Abnormal formation pressure
Gas cut mud
Poor well planning
When tripping out of the hole, the volume of the steel pipe being removed results in a corresponding decrease in wellbore fluid. Whenever the fluid level in the hole decreases, the hydrostatic pressure exerted by the fluid also decreases and if the decrease in hydrostatic pressure falls below the formation pore pressure, the well may flow. Therefore the hole must be filled to maintain sufficient hydrostatic pressure to control formation pressure. During tripping, the pipe could be dry or wet depending on the conditions. The API7G illustrates the methodology for calculating accurate pipe displacement and gives correct charts and tables. To calculate the volume to fill the well when tripping dry pipe out is given as;
Barrel to fill=pipe displacement(bbl/ft) × length pulled (ft)
To calculate the volume to fill the well when tripping wet pipe out is given as;
Barrel to fill=( pipe displacement(bbls/ft) + pipe capacity(bbls/ft) )×length pulled(ft)
In some wells, monitoring fill –up volumes on trips can be complicated by loss through perforations.The wells may stand full of fluid initially, but over a period of time the fluid seeps in to the reservoir.In such wells, the fill up volume will always exceed the calculated or theoretical volume of the steel removed from the well. In some fields, wells have low reservoir pressures and will not support a full column of fluid.In these wells filling the hole with fluid is essentially impossible unless sort of bridging agent is used to temporarily bridge off the subnormally pressured zone.The common practice is to pump the theoretical fill up volume while pulling out of the well.
The mud in the wellbore must exert enough hydrostatic pressure to equal the formation pore pressure. If the fluid’s hydrostatic pressure is less than formation pressure the well can flow.The most common reason for insufficient fluid density is drilling into unexpected abnormally pressured formations. This situation usually arises when unpredicted geological conditions are encountered. Such as drilling across a fault that abruptly changes the formation being drilled. Mishandling mud at the surface accounts for many instances of insufficient fluid weight. Such as opening wrong valve on the pump suction manifold and allowing a tank of light weight fluid to be pumped; bumping the water valve so more is added than intended; washing off shale shakers; or clean-up operations. All of these can affect mud weight.
Swabbing is as a result of the upward movement of pipe in a well and results in a decrease in bottomhole pressure. In some cases, the bottomhole pressure reduction can be large enough to cause the well to go underbalanced and allow formation fluids to enter the wellbore. The initial swabbing action compounded by the reduction in hydrostatic pressure(from formation fluids entering the well) can lead to a significant reduction in bottomhole pressure and a larger influx of formation fluids. Therefore, early detection of swabbing on trips is critical to minimizing the size of a kick. Many wellbore conditions increase the likelihood of swabbing on a trip. Swabbing (piston) action is enhanced when pipe is pulled too fast. Poor fluid properties, such as high viscosity and gel strengths, also increase the chances of swabbing a well in. Additionally, large outside diameter (OD) tools (packers, scrapers, fishing tools, etc.) enhance the piston effect. These conditions need to be recognized in order to decrease the likelihood of swabbing a well in during completion/workover operations. As mentioned earlier, there are several computer and calculator programs that can estimate surge and swab pressures. Swabbing is detected by closely monitoring hole fill-up volumes during trips. For example, if three barrels of steel (tubing) are removed from the well and it takes only two barrels of fluid to fill the hole, then a one barrel kick has probably been swabbed into the wellbore. Special attention should be paid to hole fill-up volumes since statistics indicate that most kicks occur on trips.
Another cause of kick during completion/workover operations is lost circulation. Loss of circulation leads to a drop of both the fluid level and hydrostatic pressure in a well. If the hydrostatic pressure falls below the reservoir pressure, the well kicks. Three main causes of lost circulation are:Excessive pressure overbalance
Excessive surge pressure
Poor formation integrity
In case of drilling a wildcat or exploratory well(often the formation pressures are not known accurately) the bit suddenly penetrates into an abnormal pressure formation resulting the hydrostatic pressure of mud become less than the formation pressure and cause a kick.
When the gas is circulated to the surface, it expands and reduces the hydrostatic pressure sufficient to allow a kick. Although the mud density is reduced considerably at the surface, the hydrostatic pressure is not reduced significantly since the gas expansion occurs near surface and not at the bottom.
The fourth cause of kick is poor well planning. The mud and casing programs have a great bearing on well control. These programs must be flexible enough to allow progressively deeper casing strings to be set; otherwise a situation may arise where it is not possible to control kicks or lost circulation. Well control is an important part of well planning.
During drilling operations, kicks are usually killed using the Driller’s, Engineer’s or a combination of both called Concurrent Method while forward circulating. The selection of which to use will depend upon the amount and type of kick fluids that have entered the well, the rig's equipment capabilities, the minimum fracture pressure in the open hole, and the drilling and operating companies well control policies. For workover or completion operations, other methods are often used. . Bullheading is a common way to kill a well during workovers and completions operations but is not often used for drilling operations. Reverse circulation is another kill method used for workovers that is not used for drilling.
The aim of oil operations is to complete all tasks in a safe and efficient manner without detrimental effects to the environment. This aim can only be achieved if control of the well is maintained at all times. The understanding of pressure and pressure relationships is important in preventing blowouts. Blowouts are prevented by experienced personnel that are able to detect when the well is kicking and take proper and prompt actions to shut-in the well.