Well control

The 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 acts as a fluid. Fluids exert pressure, and this pressure comes from the density and height of the fluid column. Oil companies typically measure density 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 with fluid density. To find out the amount of pressure fluid of a known density exerts per unit length, the pressure gradient is used. The pressure gradient is defined as the pressure increase per unit of 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;

${\displaystyle pressuregradient=fluiddensity*conversionfactor}$.

The conversion factor used to convert density to pressure is 0.052 in Imperial 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

${\displaystyle Hydrostaticpressure=pressuregradient*trueverticaldepth}$

or

${\displaystyle Hydrostaticpressure=fluiddensity*conversionfactor*trueverticaldepth}$.

The true vertical depth is the distance that a well reaches below ground. The measured depth is the length of the well including any angled or horizontal sections. Consider two wells, X and Y. Well X has a measured depth of 9,800  ft and a true vertical depth of 9,800  ft while well Y has measured depth of 10,380  ft while its true vertical depth is 9,800  ft. To calculate the hydrostatic pressure of the bottom hole, the true vertical depth is used because gravity acts (pulls) vertically down the hole.[2]

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, while 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.[3] Depending on the magnitude of the pore pressure, it is described as normal, abnormal or subnormal.[4][5]

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 more 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 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 area's geology.

Bottom hole pressure is used to represent the sum of all the pressures being exerted at the bottom of the hole. The pressure is imposed on the walls of the hole. The hydrostatic fluid column accounts for most of the pressure, but the 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 further increases bottom hole pressure, which can be estimated by adding up all the known pressures acting in, or on, the annular (casing) side. Bottom hole pressure can be estimated during the following activities

An accurate evaluation of a casing cement job as well as of the formation is important during the drilling and subsequent phases. The Information resulting from Formation Integrity Tests (FIT) is used throughout the life of the well and for nearby wells. Casing depths, well control options, formation fracture pressures and limiting fluid weights may be based on this information. To determine formation strength and integrity, a Leak Off Test (LOT) or a Formation Integrity Test (FIT) may be performed.

The FIT is: a method of checking the cement seal between the casing and the formation. The LOT determines the pressure and/or fluid weight the test zone below the casing can sustain. The fluid in the well must be circulated clean to ensure it is of a known and consistent density. If mud is used, it must 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.[7]

The main reasons for performing FIT are:[8]

• 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 test the well engineering plan regarding the casing shoe setting depth.

It is often helpful to visualize the well as a U-shaped tube. 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, fluids create hydrostatic pressure 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, pushing some of the lighter fluid out of the string, causing a flow at the surface. The fluid level then falls in the annulus, equalizing pressures. Given a difference in the hydrostatic pressures, the fluid will try to reach a balanced point. This is called U-tubing, and it explains why there is often a 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.[9]

The Equivalent Circulating Density (ECD) is defined as the increase in density due to friction, normally expressed in pounds per gallon. Equivalent Circulating Density (when forward circulating) is defined as the apparent fluid density that results from adding annular friction to the actual fluid density in the well.[10]

${\displaystyle ECD=MW+{\frac {P_{a}}{0.052*TVD}}}$ 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)

When the drilling mud is under static condition (no circulation), pressure at any point is only due to drilling mud weight and is given by:-

Pressure under static condition =

0.052 * Mud weight (in ppg) * TVD (in feet)

During circulation, the pressure applied is due to drilling mud weight and also due to the pressure applied by the mud pumps to circulate the drilling fluid.

Pressure under circulating condition

= Pressure under static condition

+ Pressure due to pumping at that point or pressure loss in the system

If we convert pressure under circulating condition in the annulus to its density equivalent it will be called ECD

Dividing the above equation by 0.052*TVD into both sides:-

ECD = (Pressure under static condition + Annular pressure loss) / (0.052 * TVD)

ECD = MW + Annular pressure loss / (0.052 * TVD)

using (Pressure under static condition = 0.052 * TVD * MW)

During trips (up/down) the drill string acts as a large piston, when moving down it increases the pressure below the drill string and forces the drilling fluid into the formation which is termed as surge. Similarly, while moving up, there is a low-pressure zone created below the drill string, which sucks the formation fluid into the wellbore, which is called swab.

The total pressure acting on the wellbore is affected by pipe movement upwards or downwards. Tripping pipe into and out of a well is another 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 entering a well, the fluid in the well must move upward to exit the volume consumed 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 throughout the well. This increase in pressure is commonly called Surge pressure.

Upward movement of the tubing (tripping out) also affects the pressure at the bottom of the well. When pulling pipe, the fluid must move downward and replace the volume occupied by the tubing. The net effect of the upward and downward movements creates a decrease in bottom hole pressure. This decrease in pressure is referred to as Swab pressure. Both surge and swab pressures are affected by:[11]

• Velocity of the pipe, or tripping speed
• Fluid density
• Fluid viscosity
• Fluid gel strength
• Well bore geometry (annular clearance between tools and casing, tubing open-ended or closed off)

The faster pipe moves, the greater the surge and swab effects. The greater the fluid density, viscosity and gel strength, the greater the surge and swab. Finally, the downhole tools such as packers and scrapers, which have small annular clearance, also increase surge and swab 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, differential pressure is defined as the difference between the formation pressure and the bottom hole hydrostatic pressure.[12] These are classified as overbalanced, underbalanced or balanced.

• Overbalanced – The hydrostatic pressure exerted on the bottom of the hole is greater than the formation pressure. i.e. HP > FP

• Underbalanced – The hydrostatic pressure exerted on the bottom of the hole is less than the formation pressure. i.e. HP < FP

• Balanced – 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 drill bit. The size, shape, and amount of cuttings depend largely on formation type, weight on the bit, bit sharpness and the pressure differential (formation versus fluid hydrostatic pressures). The size of the cuttings usually decreases as the bit dulls during drilling if the weight on bit, formation type and the pressure differential, remain constant. However, if the pressure differential changes (formation pressure increases), even a dull bit could cut more effectively, and the size, shape, and amount of cuttings could increase.

Deepwater Horizon drilling rig blowout, 21 April 2010

Kick is defined as an undesirable influx of formation fluid into the wellbore. If left unchecked, a kick can develop into a blowout (an uncontrolled influx of formation fluid into the wellbore). The result of failing to control a kick leads to lost operation time, loss of well and quite possibly, the loss of the rig and lives of personnel.[13]

During drilling, kicks are usually killed using the Driller's, Engineer's or a hybrid method called Concurrent, while forward circulating. The choice will depend on:

• the amount and type of kick fluids in the well
• the rig's equipment capabilities
• the minimum fracture pressure in the open hole
• 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 while drilling. Reverse circulation is another kill method used for workovers that are not used for drilling.[16]

• Blowout (well drilling)
• Blowout preventer
• Oil well
• Oil well control