Oil well control is the management of the dangerous effects caused by the unexpected release of formation fluid, such as natural gas and/or crude oil, upon surface equipment of oil or gas drilling rigs and escaping into the atmosphere. Technically, oil well control involves preventing the formation gas or fluid (hydrocarbons), usually referred to as kick, from entering into the wellbore during drilling or well interventions.
Formation fluid can enter the wellbore if the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation being drilled (pore pressure). Oil well control also includes monitoring a well for signs of impending influx of formation fluid into the wellbore during drilling and procedures, to stop the well from flowing when it happens by taking proper remedial actions.
Failure to manage and control these pressure effects can cause serious equipment damage and injury, or loss of life. Improperly managed well control situations can cause blowouts, which are uncontrolled and explosive expulsions of formation hydrocarbons from the well, potentially resulting in a fire.
Importance of oil well control
Oil well control is one of the most important aspects of drilling operations. Improper handling of kicks in oil well control can result in blowouts with very grave consequences, including the loss of valuable resources and also lives of field personnel. Even though the cost of a blowout (as a result of improper/no oil well control) can easily reach several millions of US dollars, the monetary loss is not as serious as the other damages that can occur: irreparable damage to the environment, waste of valuable resources, ruined equipment, and most importantly, the safety and lives of personnel on the drilling rig.Jerome Schubert, "Managed-Pressure Drilling: Kick Detection and Well Control" Section: "Kick Detection While Drilling", Society of Petroleum Engineers, Journal of Petroleum Technology (JPT), archived 2010/01/15.Jerome Jacob Schubert, "Well control" , Texas A&M University MEng Report for well control (December 1995). Retrieved 2011-01-04, p.I-1/2.
In order to avert the consequences of blowout, the utmost attention must be given to oil well control. That is why oil well control procedures should be in place prior to the start of an abnormal situation noticed within the wellbore, and ideally when a new rig position is sited. In other words, this includes the time the new location is picked, all drilling, completion, workover, snubbing and any other drilling-related operations that should be executed with proper oil well control in mind. This type of preparation involves widespread training of personnel, the development of strict operational guidelines and the design of drilling programs – maximizing the probability of successfully regaining hydrostatic control of a well after a significant influx of formation fluid has taken place.Karen Bybee, "A Well-Specific Approach to the Quantification of Well Control", Society of Petroleum Engineers, Journal of Petroleum Technology (JPT), archived 2010/01/15, p.60.
Fundamental concepts and terminology Pressure is a very important concept in the oil and gas industry. Pressure can be defined as: the force exerted per unit area. Its SI unit is newtons per square metre or pascals. Another unit, bar, is also widely used as a measure of pressure, with 1 bar equal to 100 kilopascals. Normally pressure is measured in the U.S. petroleum industry in units of pounds force per square inch of area, or psi. 1000 psi equals 6894.76 kilo-pascals.
Hydrostatic pressure Hydrostatic pressure (HSP), as stated, is defined as pressure due to a column of fluid that is not moving. That is, a column of fluid that is static, or at rest, exerts pressure due to local force of gravity on the column of the fluid.
The formula for calculating hydrostatic pressure in SI units (N/m2) is: Hydrostatic pressure = Height (m) × Density (kg/m3) × Gravity (m/s2).Micheal Nelkon & Philip Parker, Advanced Level Physics, 7th Edition, New Delhi, India, CBS Publishers, 1995, pp. 103–105,
All fluids in a wellbore exert hydrostatic pressure, which is a function of density and vertical height of the fluid column. In US oil field units, hydrostatic pressure can be expressed as: HSP = 0.052 × MW × TVD, where MW (Mud Weight or density) is the drilling-fluid density in pounds per gallon (ppg), TVD is the true vertical depth in feet and HSP is the hydrostatic pressure in psi. The 0.052 is needed as the conversion factor to psi unit of HSP.Jerome Jacob Schubert, 1995, pp.1-1, 2.Schlumberger Limited article, "Hydrostatic pressure", "Schlumberger OilField Glossary". Retrieved 9 April 2011.
To convert these units to SI units, one can use: 1 ppg ≈ 1 ft = 0.3048 metres 1 psi = 0.0689475729 bar 1 bar = 105 pascals 1 bar = 15 psi
Pressure gradient The pressure gradient is described as the pressure per unit length. Often in oil well control, pressure exerted by fluid is expressed in terms of its pressure gradient. The SI unit is pascals/metre. The hydrostatic pressure gradient can be written as: Pressure gradient (psi/ft) = HSP/TVD = 0.052 × MW (ppg).Jerome Jacob Schubert, 1995, p. 1-2.
Formation pressure
Formation pressure is the pressure exerted by the formation fluids, which are the liquids and gases contained in the geologic formations encountered while drilling for oil or gas. It can also be said to be the pressure contained within the pores of the formation or reservoir being drilled. Formation pressure is a result of the hydrostatic pressure of the formation fluids, above the depth of interest, together with pressure trapped in the formation. Under formation pressure, there are 3 levels: normally pressured formation, abnormal formation pressure, or subnormal formation pressure.Normally pressured formationNormally pressured formation has a formation pressure that is the same with the hydrostatic pressure of the fluids above it. As the fluids above the formation are usually some form of water, this pressure can be defined as the pressure exerted by a column of water from the formation's depth to sea level.
The normal hydrostatic pressure gradient for freshwater is 0.433 pounds per square inch per foot (psi/ft), or 9.792 kilopascals per meter (kPa/m), and 0.465 psi/ft for water with dissolved solids like in Gulf Coast waters, or 10.516 kPa/m. The density of formation water in saline or marine environments, such as along the Gulf Coast, is about 9.0 ppg or 1078.43 kg/m3. Since this is the highest for both Gulf Coast water and fresh water, a normally pressured formation can be controlled with a 9.0 ppg mud.
Sometimes the weight of the overburden, which refers to the rocks and fluids above the formation, will tend to compact the formation, resulting in pressure built-up within the formation if the fluids are trapped in place. The formation in this case will retain its normal pressure only if there is a communication with the surface. Otherwise, an abnormal formation pressure will result.Abnormal formation pressureAs discussed above, once the fluids are trapped within the formation and not allow to escape there is a pressure build-up leading to abnormally high formation pressures. This will generally require a mud weight of greater than 9.0 ppg to control. Excess pressure, called "overpressure" or "geopressure", can cause a well to blow out or become uncontrollable during drilling.Subnormal formation pressureSubnormal formation pressure is a formation pressure that is less than the normal pressure for the given depth. It is common in formations that had undergone production of original hydrocarbon or formation fluid in them.
Overburden pressure Overburden pressure is the pressure exerted by the weight of the rocks and contained fluids above the zone of interest. Overburden pressure varies in different regions and formations. It is the force that tends to compact a formation vertically. The density of these usual ranges of rocks is about 18 to 22 ppg (2,157 to 2,636 kg/m3). This range of densities will generate an overburden pressure gradient of about 1 psi/ft (22.7 kPa/m). Usually, the 1 psi/ft is not applicable for shallow marine sediments or massive salt. In offshore however, there is a lighter column of sea water, and the column of underwater rock does not go all the way to the surface. Therefore, a lower overburden pressure is usually generated at an offshore depth, than would be found at the same depth on land.
Mathematically, overburden pressure can be derived as:
where g = acceleration due to gravity = overburden pressure = average formation bulk density = vertical thickness of the overlying sediments The bulk density of the sediment is a function of rock matrix density, porosity within the confines of the pore spaces, and porefluid density. This can be expressed as
where = rock porosity = formation fluid density = rock matrix densityJerome Jacob Schubert, 1995, pp. 1-3, 4.Rehm, Bill; Schubert, Jerome; Haghshenas, Arash; Paknejad, Amir Saman; Hughes, Jim (2008). Managed Pressure Drilling. Gulf Publishing Company. Online version available at: Knovel-48, pp. 22/23 section 1.7 (online version)
Fracture pressure Fracture pressure can be defined as pressure required to cause a formation to fail or split. As the name implies, it is the pressure that causes the formation to fracture and the circulating fluid to be lost. Fracture pressure is usually expressed as a gradient, with the common units being psi/ft (kPa/m) or ppg (kg/m3).
To fracture a formation, three things are generally needed, which are:
Pump into the formation. This will require a pressure in the wellbore greater than formation pressure. The pressure in the wellbore must also exceed the rock matrix strength. And finally the wellbore pressure must be greater than one of the three principal stresses in the formation.Jerome Jacob Schubert, 1995, p. 1-4.Rehm, Bill; et al.. (2008). Managed Pressure Drilling, p.23, section 1.8.1 (online version).
Pump pressure (system pressure losses) Pump pressure, which is also referred to as system pressure loss, is the sum total of all the pressure losses from the oil well surface equipment, the drill pipe, the drill collar, the drill bit, and annular friction losses around the drill collar and drill pipe. It measures the system pressure loss at the start of the circulating system and measures the total friction pressure.Jerome Jacob Schubert, 1995, pp.1-4, 5, 6, 7.
Slow pump pressure (SPP) Slow pump pressure is the circulating pressure (pressure used to pump fluid through the whole active fluid system, including the borehole and all the surface tanks that constitute the primary system during drilling) at a reduced rate. SPP is very important during a well kill operation in which circulation (a process in which drilling fluid is circulated out of the suction pit, down the drill pipe and drill collars, out the bit, up the annulus, and back to the pits while drilling proceeds) is done at a reduced rate to allow better control of circulating pressures and to enable the mud properties (density and viscosity) to be kept at desired values. The slow pump pressure can also be referred to as "kill rate pressure" or "slow circulating pressure" or "kill speed pressure" and so on.Schlumberger Limited article,"Circulate", "Schlumberger OilField Glossary". Retrieved 9 April 2011.Jerome Jacob Schubert, 1995, pp.1-7.
Shut-in drill pipe pressure