Oil well control

Last updated

As technology has advanced, more modern drillers have better control of the overall well. H104.jpg
As technology has advanced, more modern drillers have better control of the overall well.

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.

Contents

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). [1] [2] 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. [3]

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. [4]

Importance of oil well control

1904 oil well fire at Bibi-Eibat (near Baku, Azerbaijan). Oil well burning in Bibi Eibat.JPG
1904 oil well fire at Bibi-Eibat (near Baku, Azerbaijan).

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. [5] [6]

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. [6] 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. [6] [7]

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. [8]

The formula for calculating hydrostatic pressure in SI units (N/m2) is:

Hydrostatic pressure = Height (m) × Density (kg/m3) × Gravity (m/s2). [9]

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. [10] [11]

To convert these units to SI units, one can use:

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). [12]

Formation pressure

Schematic cross-section of general types of oil and gas resources and the orientations of production wells used in hydraulic fracturing. Schematic cross-section of general types of oil and gas resources and the orientations of production wells used in hydraulic fracturing.jpg
Schematic cross-section of general types of oil and gas resources and the orientations of production wells used in hydraulic fracturing.

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 formation

Normally 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 pressure

As 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 pressure

Subnormal 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. [12] [13] [14] [15]

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:

S = ρb× D×g

where

g = acceleration due to gravity
S = overburden pressure
ρb = average formation bulk density
D = 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

ρb = φρf + (1 – φ)ρm

where

φ = rock porosity
ρf = formation fluid density
ρm = rock matrix density [16] [17]

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:

  1. Pump into the formation. This will require a pressure in the wellbore greater than formation pressure.
  2. The pressure in the wellbore must also exceed the rock matrix strength.
  3. And finally the wellbore pressure must be greater than one of the three principal stresses in the formation. [18] [19]

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. [20]

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. [21] [22] [23]

Shut-in drill pipe pressure

Shut-in drill pipe pressure (SIDPP), which is recorded when a well is shut in on a kick, is a measure of the difference between the pressure at the bottom of the hole and the hydrostatic pressure (HSP) in the drillpipe. During a well shut-in, the pressure of the wellbore stabilizes, and the formation pressure equals the pressure at the bottom of the hole. The drillpipe at this time should be full of known-density fluid. Therefore, the formation pressure can be easily calculated using the SIDPP. This means that the SIDPP gives a direct of formation pressure during a kick.

Shut-in casing pressure (SICP)

The shut-in casing pressure (SICP) is a measure of the difference between the formation pressure and the HSP in the annulus when a kick occurs.

The pressures encountered in the annulus can be estimated using the following mathematical equation:

FP = HSPmud + HSPinflux + SICP

where

FP = formation pressure (psi)
HSPmud = Hydrostatic pressure of the mud in the annulus (psi)
HSPinflux = Hydrostatic pressure of the influx (psi)
SICP = shut-in casing pressure (psi)

Bottom-hole pressure (BHP)

Bottom-hole pressure (BHP) is the pressure at the bottom of a well. The pressure is usually measured at the bottom of the hole. This pressure may be calculated in a static, fluid-filled wellbore with the equation:

BHP = D × ρ × C,

where

BHP = bottom-hole pressure
D = the vertical depth of the well
ρ = density
C = units conversion factor
(or, in the English system, BHP = D × MWD × 0.052).

In Canada the formula is depth in meters x density in kgs x the constant gravity factor (0.00981), which will give the hydrostatic pressure of the well bore or (hp) hp=bhp with pumps off. The bottom-hole pressure is dependent on the following:

Therefore, BHP can be said to be the sum of all pressures at the bottom of the wellhole, which equals:

BHP = HSP + SIP + friction + Surge - swab [24] [25]

Basic calculations in oil well control

There are some basic calculations that need to be carried during oil well control. A few of these essential calculations will be discussed below. Most of the units here are in US oil field units, but these units can be converted to their SI units equivalent by using this Conversion of units link.

Capacity

The capacity of drill string is an essential issue in oil well control. The capacity of drillpipe, drill collars or hole is the volume of fluid that can be contained within them.

The capacity formula is as shown below:

Capacity = ID2/1029.4

where

Capacity = Volume in barrels per foot(bbl/ft)
ID = Inside diameter in inches
1029.4 = Units conversion factor

Also the total pipe or hole volume is given by :

Volume in barrels (bbls) = Capacity (bbl/ft) × length (ft)

Feet of pipe occupied by a given volume is given by:

Feet of pipe (ft) = Volume of mud (bbls) / Capacity (bbls/ft)

Capacity calculation is important in oil well control due to the following:

Annular capacity

This is the volume contained between the inside diameter of the hole and the outside diameter of the pipe. Annular capacity is given by :

Annular capacity (bbl/ft) = (IDhole2 - ODpipe2) / 1029.4

where

IDhole2 = Inside diameter of the casing or open hole in inches
ODpipe2 = Outside diameter of the pipe in inches

Similarly

Annular volume (bbls) = Annular capacity (bbl/ft) × length (ft)

and

Feet occupied by volume of mud in annulus = Volume of mud (bbls) / Annular Capacity (bbls/ft). [27]

Fluid level drop

Fluid level drop is the distance the mud level will drop when a dry string(a bit that is not plugged) is being pulled from the wellbore and it is given by:

Fluid level drop = Bbl disp / (CSG cap + Pipe disp)

or

Fluid level drop = Bbl disp / (Ann cap + Pipe cap)

and the resulting loss of HSP is given by:

Lost HSP = 0.052 × MW × Fluid drop

where

Fluid drop = distance the fluid falls (ft)
Bbl disp = displacement of the pulled pipe (bbl)
CSG cap = casing capacity (bbl/ft)
Pipe disp = pipe displacement (bbl/ft)
Ann cap = Annular capacity between casing and pipe (bbl/ft)
Pipe cap = pipe capacity
Lost HSP = Lost hydrostatic pressure (psi)
MW = mud weight (ppg)

When pulling a wet string (the bit is plugged) and the fluid from the drillpipe is not returned to the hole. The fluid drop is then changed to the following:

Fluid level drop = Bbl disp / Ann cap

Kill Mud weight (KMW)

Kill Mud weight is the density of the mud required to balance formation pressure during kill operation. The Kill Weight Mud can be calculated by:

KWM = SIDPP/(0.052 × TVD) + OWM

where

KWM = kill weight mud (ppg)
SIDPP = shut-in drillpipe pressure (psi)
TVD  = true vertical depth (ft)
OWM  = original weight mud (ppg)

But when the formation pressure can be determined from data sources such as bottom hole pressure, then KWM can be calculated as follows:

KWM = FP / (0.052 × TVD)

where FP = Formation pressure. [28]

Kicks

Ixtoc I oil well blowout IXTOC I oil well blowout.jpg
Ixtoc I oil well blowout

Kick is the entry of formation fluid into the wellbore during drilling operations. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. The whole essence of oil well control is to prevent kick from occurring and if it happens to prevent it from developing into blowout. An uncontrolled kick usually results from not deploying the proper equipment, using poor practices, or a lack of training of the rig crews. Loss of oil well control may lead into blowout, which represents one of the most severe threats associated with the exploration of petroleum resources involving the risk of lives and environmental and economic consequences. [29] [30]

Causes of kicks

A kick will occur when the bottom hole pressure(BHP) of a well falls below the formation pressure and the formation fluid flows into the wellbore. There are usually causes for kicks some of which are:

Failure to keep the hole full during a trip

Tripping is the complete operation of removing the drillstring from the wellbore and running it back in the hole. This operation is typically undertaken when the bit (which is the tool used to crush or cut rock during drilling) becomes dull or broken, and no longer drills the rock efficiently. A typical drilling operation of deep oil or gas wells may require up to 8 or more trips of the drill string to replace a dull rotary bit for one well.

Tripping out of the hole means that the entire volume of steel (of drillstring) is being removed, or has been removed, from the well. This displacement of the drill string (the steel) will leave out a volume of space that must be replaced with an equal volume of mud. If the replacement is not done, the fluid level in the wellbore will drop, resulting in a loss of hydrostatic pressure (HSP) and bottom hole pressure (BHP). If this bottom hole pressure reduction goes below the formation pressure, a kick will definitely occur.

Swabbing while tripping

Swabbing occurs when bottom hole pressure is reduced due to the effects of pulling the drill string upward in the bored hole. During the tripping out of the hole, the space formed by the drillpipe, drill collar, or tubing (which are being removed) must be replaced by something, usually mud. If the rate of tripping out is greater than the rate the mud is being pumped into the void space (created by the removal of the drill string), then swab will occur. If the reduction in bottom hole pressure caused by swabbing is below formation pressure, then a kick will occur.

Lost circulation

Lost circulation usually occurs when the hydrostatic pressure fractures an open formation. When this occurs, there is loss in circulation, and the height of the fluid column decreases, leading to lower HSP in the wellbore. A kick can occur if steps are not taken to keep the hole full. Lost circulation can be caused by:

  • excessive mud weights
  • excessive annular friction loss
  • excessive surge pressure during trips, or "spudding" the bit
  • excessive shut-in pressures.

Insufficient density of fluid

If the density of the drilling fluid or mud in the well bore is not sufficient to keep the formation pressure in check, then a kick can occur. Insufficient density of the drilling fluid can be as a result of the following :

  • attempting to drill by using an underbalanced weight solution
  • excessive dilution of the mud
  • heavy rains in the pits
  • barite settling in the pits
  • spotting low density pills in the well.

Abnormal pressure

Another cause of kicks is drilling accidentally into abnormally-pressured permeable zones. The increased formation pressure may be greater than the bottom hole pressure, resulting in a kick.

Drilling into an adjacent well

Drilling into an adjacent well is a potential problem, particularly in offshore drilling where a large number of directional wells are drilled from the same platform. If the drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well will enter the wellbore of the drilling well, causing a kick. If this occurs at a shallow depth, it is an extremely dangerous situation and could easily result in an uncontrolled blowout with little to no warning of the event.

Lost control during drill stem test

A drill-stem test is performed by setting a packer above the formation to be tested, and allowing the formation to flow. During the course of the test, the bore hole or casing below the packer, and at least a portion of the drill pipe or tubing, is filled with formation fluid. At the conclusion of the test, this fluid must be removed by proper well control techniques to return the well to a safe condition. Failure to follow the correct procedures to kill the well could lead to a blowout. [31] [32] [33]

Improper fill on trips

Improper fill on trip occurs when the volume of drilling fluid to keep the hole full on a Trip (complete operation of removing the drillstring from the wellbore and running it back in the hole) is less than that calculated or less than Trip Book Record. This condition is usually caused by formation fluid entering the wellbore due to the swabbing action of the drill string, and, if action is not taken soon, the well will enter a kick state. [34] [35] [36]

Kick warning signs

Deepwater Horizon drilling rig blowout, 21 April 2010 Deepwater Horizon offshore drilling unit on fire 2010.jpg
Deepwater Horizon drilling rig blowout, 21 April 2010

In oil well control, a kick should be able to be detected promptly, and if a kick is detected, proper kick prevention operations must be taken immediately to avoid a blowout. There are various tell-tale signs that signal an alert crew that a kick is about to start. Knowing these signs will keep a kicking oil well under control, and avoid a blowout:

Sudden increase in drilling rate

A sudden increase in penetration rate (drilling break) is usually caused by a change in the type of formation being drilled. However, it may also signal an increase in formation pore pressure, which may indicate a possible kick.

Increase in annulus flow rate

If the rate at which the pumps are running is held constant, then the flow from the annulus should be constant. If the annulus flow increases without a corresponding change in pumping rate, the additional flow is caused by formation fluid(s) feeding into the well bore or gas expansion. This will indicate an impending kick.

Gain in pit volume

If there is an unexplained increase in the volume of surface mud in the pit (a large tank that holds drilling fluid on the rig), it could signify an impending kick. This is because as the formation fluid feeds into the wellbore, it causes more drilling fluid to flow from the annulus than is pumped down the drill string, thus the volume of fluid in the pit(s) increases.

Change in pump speed/pressure

A decrease in pump pressure or increase in pump speed can happen as a result of a decrease in hydrostatic pressure of the annulus as the formation fluids enters the wellbore. As the lighter formation fluid flows into the wellbore, the hydrostatic pressure exerted by the annular column of fluid decreases, and the drilling fluid in the drill pipe tends to U-tube into the annulus. When this occurs, the pump pressure will drop, and the pump speed will increase. The lower pump pressure and increase in pump speed symptoms can also be indicative of a hole in the drill string, commonly referred to as a washout. Until a confirmation can be made whether a washout or a well kick has occurred, a kick should be assumed.

Categories of oil well control

There are basically three types of oil well control which are: primary oil well control, secondary oil well control, and tertiary oil well control. Those types are explained below.

Primary Oil Well Control

Primary oil well control is the process which maintains a hydrostatic pressure in the wellbore greater than the pressure of the fluids in the formation being drilled, but less than formation fracture pressure. It uses the mud weight to provide sufficient pressure to prevent an influx of formation fluid into the wellbore. If hydrostatic pressure is less than formation pressure, then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation, then the fluid in the well could be lost into the formation. In an extreme case of lost circulation, the formation pressure may exceed hydrostatic pressure, allowing formation fluids to enter into the well.

Secondary Oil Well Control

Secondary oil well control is done after the Primary oil well control has failed to prevent formation fluids from entering the wellbore. This process uses "blow out preventer", a BOP, to prevent the escape of wellbore fluids from the well. As the rams and choke of the BOP remain closed, a pressure built up test is carried out and a kill mud weight calculated and pumped inside the well to kill the kick and circulate it out.

Tertiary (or shearing) Oil Well Control

Tertiary oil well control describes the third line of defense, where the formation cannot be controlled by primary or secondary well control (hydrostatic and equipment). This happens in underground blowout situations. The following are examples of tertiary well control:

Shut-in procedures

Using shut-in procedures is one of the oil-well-control measures to curtail kicks and prevent a blowout from occurring. Shut-in procedures are specific procedures for closing a well in case of a kick. When any positive indication of a kick is observed, such as a sudden increase in flow, or an increase in pit level, then the well should be shut-in immediately. If a well shut-in is not done promptly, a blowout is likely to happen.

Shut-in procedures are usually developed and practiced for every rig activity, such as drilling, tripping, logging, running tubular, performing a drill stem test, and so on. The primary purpose of a specific shut-in procedure is to minimize kick volume entering into a wellbore when a kick occurs, regardless of what phase of rig activity is occurring. However, a shut-in procedure is a company-specific procedure, and the policy of a company will dictate how a well should be shut-in.

They are generally two type of Shut-in procedures which are soft shut-in or hard shut-in. Of these two methods, the hard shut-in is the fastest method to shut in the well; therefore, it will minimize the volume of kick allowed into the wellbore. [41]

Well kill procedures

Source: [42] A well kill procedure is an oil well control method. Once the well has been shut-in on a kick, proper kill procedures must be done immediately. The general idea in well kill procedure is to circulate out any formation fluid already in the wellbore during kick, and then circulate a satisfactory weight of kill mud called Kill Weight Mud (KWM) into the well without allowing further fluid into the hole. If this can be done, then once the kill mud has been fully circulated around the well, it is possible to open up the well and restart normal operations. Generally, a kill weight mud (KWM) mix, which provides just hydrostatic balance for formation pressure, is circulated. This allows approximately constant bottom hole pressure, which is slightly greater than formation pressure to be maintained, as the kill circulation proceeds because of the additional small circulating friction pressure loss. After circulation, the well is opened up again.

The major well kill procedures used in oil well control are listed below:

Oil well control incidents - root causes

There will always be potential oil well control problems, as long as there are drilling operations anywhere in the world. Most of these well control problems are as a result of some errors and can be eliminated, even though some are actually unavoidable. Since we know the consequences of failed well control are severe, efforts should be made to prevent some human errors which are the root causes of these incidents. These causes include:

Organizations for building well-control culture

Planning for the control of the well throughout the entire life cycle is crucial for the proper management of resources. Abandoned oil well tank.jpg
Planning for the control of the well throughout the entire life cycle is crucial for the proper management of resources.

An effective oil-well-control culture can be established within a company by requiring well control training of all rig workers, by assessing well control competence at the rigsite, and by supporting qualified personnel in carrying out safe well control practices during the drilling process. Such a culture also requires personnel involved in oil well control to commit to following the right procedures at the right time. Clearly communicated policies and procedures, credible training, competence assurance, and management support can minimize and mitigate well control incidents. An effective well control culture is built upon technically competent personnel who are also trained and skilled in crew resource management (a discipline within human factors), which comprises situation awareness, decision-making (problem-solving), communication, teamwork, and leadership. Training programs are developed and accredited by organizations such as the International Association of Drilling Contractors (IADC) and International Well Control Forum (IWCF).

IADC, headquartered in Houston, TX, is a nonprofit industry association that accredits well control training through a program called WellSharp, which is aimed at providing the necessary knowledge and practical skills critical to successful well control. This training comprises drilling and well servicing activities, as well as course levels applicable to everyone involved in supporting or conducting drilling operations—from the office support staff to the floorhands and drillers and up to the most-experienced supervisory personnel. Training such as those included in the WellSharp program and the courses offered by IWCF contribute to the competence of personnel, but true competence can be assessed only at the jobsite during operations. Therefore, IADC also accredits industry competence assurance programs to help ensure quality and consistency of the competence assurance process for drilling operations. IADC has regional offices all over the world and accredits companies worldwide. IWCF is an NGO, headquartered in Europe, whose main aim is to develop and administer well-control certification programs for personnel employed in oil-well drilling and for workover and well-intervention operations. [46] [47] [48]

See also

Related Research Articles

<span class="mw-page-title-main">Wireline (cabling)</span> Technology used in oil and gas wells

In the oil and gas industry, the term wireline usually refers to the use of multi-conductor, single conductor or slickline cable, or "wireline", as a conveyance for the acquisition of subsurface petrophysical and geophysical data and the delivery of well construction services such as pipe recovery, perforating, plug setting and well cleaning and fishing. The subsurface geophysical and petrophysical information results in the description and analysis of subsurface geology, reservoir properties and production characteristics.

A mud engineer works on an oil well or gas well drilling rig, and is responsible for ensuring the properties of the drilling fluid, also known as drilling mud, are within designed specifications.

Well control is the technique used in oil and gas operations such as drilling, well workover and well completion for maintaining the hydrostatic pressure and formation pressure to prevent the influx of formation fluids into the wellbore. This technique involves the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion. Understanding pressure and pressure relationships is important in well control.

<span class="mw-page-title-main">Casing (borehole)</span> Pipe inserted into a borehole

Casing is a large diameter pipe that is assembled and inserted into a recently drilled section of a borehole. Similar to the bones of a spine protecting the spinal cord, casing is set inside the drilled borehole to protect and support the wellstream. The lower portion is typically held in place with cement. Deeper strings usually are not cemented all the way to the surface, so the weight of the pipe must be partially supported by a casing hanger in the wellhead.

<span class="mw-page-title-main">Wellhead</span> Component at the surface of a well that provides the structural and pressure-containing interface

A wellhead is the component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment.

<span class="mw-page-title-main">Drilling fluid</span> Aid for drilling boreholes into the ground

In geotechnical engineering, drilling fluid, also known as drilling mud, is used to aid the drilling of boreholes into the earth. Used while drilling oil and natural gas wells and on exploration drilling rigs, drilling fluids are also used for much simpler boreholes, such as water wells.

<span class="mw-page-title-main">Blowout (well drilling)</span> Uncontrolled release of crude oil and/or natural gas from a well

A blowout is the uncontrolled release of crude oil and/or natural gas from an oil well or gas well after pressure control systems have failed. Modern wells have blowout preventers intended to prevent such an occurrence. An accidental spark during a blowout can lead to a catastrophic oil or gas fire.

<span class="mw-page-title-main">Blowout preventer</span> Specialized valve

A blowout preventer (BOP) is a specialized valve or similar mechanical device, used to seal, control and monitor oil and gas wells to prevent blowouts, the uncontrolled release of crude oil or natural gas from a well. They are usually installed in stacks of other valves.

<span class="mw-page-title-main">Drill stem test</span>

A drill stem test (DST) is a procedure for isolating and testing the pressure, permeability and productive capacity of a geological formation during the drilling of a well. The test is an important measurement of pressure behaviour at the drill stem and is a valuable way of obtaining information on the formation fluid and establishing whether a well has found a commercial hydrocarbon reservoir.

Underbalanced drilling, or UBD, is a procedure used to drill oil and gas wells where the pressure in the wellbore is kept lower than the static pressure of the formation being drilled. As the well is being drilled, formation fluid flows into the wellbore and up to the surface. This is the opposite of the usual situation, where the wellbore is kept at a pressure above the formation to prevent formation fluid entering the well. In such a conventional "overbalanced" well, the invasion of fluid is considered a kick, and if the well is not shut-in it can lead to a blowout, a dangerous situation. In underbalanced drilling, however, there is a "rotating head" at the surface - essentially a seal that diverts produced fluids to a separator while allowing the drill string to continue rotating.

<span class="mw-page-title-main">Differential sticking</span>

Differential sticking is a problem that occurs when drilling a well with a greater well bore pressure than formation pressure, as is usually the case. The drill pipe is pressed against the wellbore wall so that part of its circumference will see only reservoir pressure, while the rest will continue to be pushed by wellbore pressure. As a result, the pipe becomes stuck to the wall, and can require millions of pounds of force to remove, which may prove impossible. In many cases the drilling fluid (mud) weight is reduced, thus relieving the pressure difference and releasing the stuck pipe string. Should this option be unavailable, as in sour gas wells, a specialty fishing company is called to retrieve the stuck pipe or 'fish'. Many options exist once a fishing company is on site: oil or nitrogen may be pumped down the well, or the fish may be 'washed over' using a carbide shoe on a string of washpipe. Jarring is not usually attempted with differential sticking due to the massive amount of pressure that holds the pipe in place.

<span class="mw-page-title-main">Coiled tubing</span> Long metal pipe used in oil and gas wells

In the oil and gas industry, coiled tubing refers to a long metal pipe, normally 1 to 3.25 in in diameter which is supplied spooled on a large reel. It is used for interventions in oil and gas wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations similar to wirelining. The main benefits over wireline are the ability to pump chemicals through the coil and the ability to push it into the hole rather than relying on gravity. Pumping can be fairly self-contained, almost a closed system, since the tube is continuous instead of jointed pipe. For offshore operations, the 'footprint' for a coiled tubing operation is generally larger than a wireline spread, which can limit the number of installations where coiled tubing can be performed and make the operation more costly. A coiled tubing operation is normally performed through the drilling derrick on the oil platform, which is used to support the surface equipment, although on platforms with no drilling facilities a self-supporting tower can be used instead. For coiled tubing operations on sub-sea wells a mobile offshore drilling unit (MODU) e.g. semi-submersible, drillship etc. has to be utilized to support all the surface equipment and personnel, whereas wireline can be carried out from a smaller and cheaper intervention vessel. Onshore, they can be run using smaller service rigs, and for light operations a mobile self-contained coiled tubing rig can be used.

A well kill is the operation of placing a column of special fluids of the required density into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface. It works on the principle that the hydrostatic head of the "kill fluid" or "kill mud" will be enough to suppress the pressure of the formation fluids. Well kills may be planned in the case of advanced interventions such as workovers, or be contingency operations. The situation calling for a well kill will dictate the method taken.

<span class="mw-page-title-main">Completion (oil and gas wells)</span> Last operation for oil and gas wells

Well completion is the process of making a well ready for production after drilling operations. This principally involves preparing the bottom of the hole to the required specifications, running in the production tubing and its associated down hole tools as well as perforating and stimulating as required. Sometimes, the process of running in and cementing the casing is also included. After a well has been drilled, should the drilling fluids be removed, the well would eventually close in upon itself. Casing ensures that this will not happen while also protecting the wellstream from outside incumbents, like water or sand.

Oilfield terminology refers to the jargon used by those working in fields within and related to the upstream segment of the petroleum industry. It includes words and phrases describing professions, equipment, and procedures specific to the industry. It may also include slang terms used by oilfield workers to describe the same.

In oil or gas well drilling, lost circulation occurs when drilling fluid, known commonly as "mud", flows into one or more geological formations instead of returning up the annulus. Lost circulation can be a serious problem during the drilling of an oil well or gas well.

Oil well cementing equipment are essential for oil and gas exploration and are required oilfield equipment when drilling a well.

Pore pressure gradient is a dimensional petrophysical term used by drilling engineers and mud engineers during the design of drilling programs for drilling (constructing) oil and gas wells into the earth. It is the pressure gradient inside the pore space of the rock column from the surface of the ground down to the total depth (TD), as compared to the pressure gradient of seawater in deep water.

<span class="mw-page-title-main">Cameron ram-type blowout preventer</span>

The Cameron ram-type blowout preventer was the first successful blowout preventer (BOP) for oil wells. It was developed by James S. Abercrombie and Harry S. Cameron in 1922. The device was issued U.S. patent 1,569,247 on January 12, 1926. The blowout preventer was designated as a Mechanical Engineering Landmark in 2003.

References

  1. Lyons, William C.; Plisga, Gary J. (2005). Standard Handbook of Petroleum and Natural Gas Engineering (2nd edition). Elsevier. Online version available at: Knovel=33, pp.4-371 (eBook version).
  2. Oil and Gas glossary, "Kick", "Oil and Gas Field Technical Terms Glossary". Retrieved 8 April 2011.
  3. Schlumberger article, "Well control", "Schlumberger OilField Glossary". Retrieved 9 April 2011.
  4. Oil and Gas glossary, "Primary Well control", "Oil and Gas Field Technical Terms Glossary". Retrieved on 8 April 2011.
  5. 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.
  6. 1 2 3 Jerome Jacob Schubert, "Well control", Texas A&M University MEng Report for well control (December 1995). Retrieved 2011-01-04, p.I-1/2.
  7. 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.
  8. Oil and Gas glossary, "Hydrostatic Pressure", "Oil and Gas Field Technical Terms Glossary". Retrieved 8 April 2011.
  9. Micheal Nelkon & Philip Parker, Advanced Level Physics, 7th Edition, New Delhi, India, CBS Publishers, 1995, pp. 103–105, ISBN   81-239-0400-2
  10. Jerome Jacob Schubert, 1995, pp.1-1, 2.
  11. Schlumberger Limited article,"Hydrostatic pressure", "Schlumberger OilField Glossary". Retrieved 9 April 2011.
  12. 1 2 Jerome Jacob Schubert, 1995, p. 1-2.
  13. Schlumberger Limited article, "Abnormal Pressure", "Schlumberger OilField Glossary". Retrieved 2011-04-09.
  14. Schlumberger Limited article, "UnderPressure", "Schlumberger OilField Glossary". Retrieved 9 April 2011.
  15. Schlumberger Limited article, "Normal Pressure", "Schlumberger OilField Glossary". Retrieved 2011-04-09.
  16. Jerome Jacob Schubert, 1995, pp. 1-3, 4.
  17. 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)
  18. Jerome Jacob Schubert, 1995, p. 1-4.
  19. Rehm, Bill; et al.. (2008). Managed Pressure Drilling, p.23, section 1.8.1 (online version).
  20. Jerome Jacob Schubert, 1995, pp.1-4, 5, 6, 7.
  21. Oil and Gas glossary, "Circulate", "Oil and Gas Field Technical Terms Glossary". Retrieved 8 April 2011.
  22. Schlumberger Limited article,"Circulate", "Schlumberger OilField Glossary". Retrieved 9 April 2011.
  23. Jerome Jacob Schubert, 1995, pp.1-7.
  24. Jerome Jacob Schubert, 1995, pp.1-8, 9, 10.
  25. Rehm, Bill; et al. (2008). Managed Pressure Drilling, p.11, section 1.4.1 (online version).
  26. Jerome Jacob Schubert, 1995, p.2-1.
  27. Jerome Jacob Schubert, 1995, pp.2-1, 2.
  28. Jerome Jacob Schubert, 1995, pp.2-4, 6.
  29. Schlumberger Limited article,"Kick","Schlumberger OilField Glossary". Retrieved 9 April 2011.
  30. IDPT/IPM article, "Basic Well Control", Scribd site. Accessed 10/04/2011, p.3.
  31. Jerome Jacob Schubert, 1995, pp.3-1, 2, 3, 4.
  32. IDPT/IPM article, "Basic Well Control", pp.19/20.
  33. Lyons, William C.; Plisga, Gary J. (2005). Standard Handbook of Petroleum and Natural Gas Engineering, pp.39-41, Chapter 2.
  34. Jerome Jacob Schubert, 1995, pp.4-1-4.
  35. Grace, Robert D. (2003). Blowout and Well Control Handbook. Elsevier. Online version available at: Knovel-72, pp.42/43, chapter 2 (online version).
  36. Rehm, Bill; et al. (2008). Managed Pressure Drilling, pp. 212/213, section 8.6.2 (online version).
  37. IDPT/IPM article, "Basic Well Control", p.7.
  38. Rachain Jetjongjit, "What is Tertiary well control", DrillingFormulas.com, Drilling Formulas and Drilling Calculations. Accessed 2011-04-11.
  39. Rachain Jetjongjit, "What is Primary well control", DrillingFormulas.com, Drilling Formulas and Drilling Calculations. Accessed 2011-04-11.
  40. Rachain Jetjongjit, "What is Secondary well control", DrillingFormulas.com, Drilling Formulas and Drilling Calculations. Accessed 2011-04-11.
  41. Jerome Jacob Schubert, 1995, p.5-1
  42. Rabia, Hussain (1986). Oil well drilling engineering. Springer. pp. 302–311. ISBN   0860106616.
  43. Jerome Jacob Schubert, 1995, pp.6-1-13.
  44. IDPT/IPM article, "Basic Well Control". pp.37/38.
  45. IDPT/IPM training material, "Basic Well Control", Scribd site. Accessed 10/04/2011, p.4.
  46. Kareen Bybee, "Building a Well-Control Culture", Society of Petroleum Engineers, Journal of Petroleum Technology (JPT), archived 2009/01/16, p.73.
  47. IADC, "WellSharp", IADC.org, International Association of Drilling Contractors Well-Control Accreditation Program. Accessed 2018-05-04.
  48. IWCF, "International Well Control forum organization". Accessed 2011-04-12.