An Overview to IWCF Well Control Certification Course (DRILLER/SUPERVISOR LEVEL)
Day 1
Prepared by: Engr. Muhammad Nauman Awan
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Table of Contents DAY-1 ---- Session - I
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Kick .............................................................................................................................................................. 4 Factors affecting kick severity ..................................................................................................................... 4 Kick labels ................................................................................................................................................... 4 Causes of kicks , Insufficient mud weight , Improper hole fill-up during trips ........................................... 5 Swabbing, Cut mud, Lost circulation ........................................................................................................... 6 Warning signs of kicks ................................................................................................................................. 6 Primary indicator of kicks, Secondary indicator of kicks ............................................................................ 7 Kick detection and monitoring with MWD tools ......................................................................................... 8 Kick identification, Kill-weight mud calculation, Nomenclature ................................................................ 9 Blowout, Causes and Types ....................................................................................................................... 10 Well Control(Primary, Secondary, Tertiary), Equivalent Circulating Density (ECD) .............................. 11 Hydrostatic Pressure .................................................................................................................................. 12 Bottom Hole Pressure (BHP), Formation Pressure, Effect of hydrostatic pressure ................................... 13 Hydrostatic pressure (HSP), Pressure gradient .......................................................................................... 14 Formation pressure(Normally, Abnormal, Subnormal, Overburden) ........................................................ 14 Fracture pressure, System pressure loss, Slow pump pressure (SPP) ........................................................ 15 Shut-in drill pipe pressure (SIDPP), Shut-in casing pressure (SICP) ........................................................ 16 Bottom-hole pressure (BHP) ...................................................................................................................... 16
DAY-1 ----- Session - II .................................................................................................................. 18 Leak off Test (LOT).................................................................................................................................... 18 Maximum Allowable Annulus Surface Pressure (MAASP) ....................................................................... 19 Kick Tolerance, Calculation, Kick Tolerance Example.............................................................................. 19 Top hole drilling ......................................................................................................................................... 21 Major hazards of shallow gas influx ........................................................................................................... 22 Diverter Systems in Well Control ............................................................................................................... 24 Shallow gas control procedure(While Drilling, While Tripping) ............................................................... 25
DAY-1 ----- Session – III ............................................................................................................... 26 Gas Cut Drilling Fluid ................................................................................................................................ 26 Swab and surge effects, Surging, Swabbing ............................................................................................... 26 Trip margin ................................................................................................................................................. 27 Slow circulation rate(SCR) ......................................................................................................................... 27
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Causes of kicks ........................................................................................................................................... 28 Indications of kick – (While tripping, While drilling) ................................................................................ 29 Positive Well Control (kick) Indications(While drilling, While Tripping) ................................................. 31 Drilled Gas .................................................................................................................................................. 32
DAY-1 ----- Session – IV ................................................................................................................ 33 Positive kick signs (While drilling While tripping) .................................................................................... 33 Shut in procedures (Hard Shut-in ,Soft Shut-in) ......................................................................................... 33 Shut-in drill pipe pressure (SIDPP) ............................................................................................................ 34 Shut-in casing pressure (SICP) ................................................................................................................... 35 Maximum Initial Shut-In Casing Pressure (MISICP) , calculate MISICP ................................................. 35 Adjusted maximum allowable shut-in casing pressure ............................................................................... 36 Bringing the pump to kill speed .................................................................................................................. 36 Type of influx ............................................................................................................................................. 38 U-Tube Concept and Importance of U-Tube ................................................................................................ 6
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DAY-1 --------------- Session - I Kick A kick is a well control problem in which the pressure found within the drilled rock is higher than the mud hydrostatic pressure acting on the borehole or rock face. When this occurs, the greater formation pressure has a tendency to force formation fluids into the wellbore. This forced fluid flow is called a kick. If the flow is successfully controlled, the kick is considered to have been killed. An uncontrolled kick that increases in severity may result in what is known as a “blowout.” Factors affecting kick severity Several factors affect the severity of a kick. One factor, for example, is the “permeability” of rock, which is its ability to allow fluid to move through the rock. Another factor affecting kick severity is “porosity.” Porosity measures the amount of space in the rock containing fluids. A rock with high permeability and high porosity has greater potential for a severe kick than a rock with low permeability and low porosity. For example, sandstone is considered to have greater kick potential than shale, because sandstone has greater permeability and greater porosity than shale. Yet another factor affecting kick severity is the “pressure differential” involved. Pressure differential is the difference between the formation fluid pressure and the mud hydrostatic pressure. If the formation pressure is much greater than the hydrostatic pressure, a large negative differential pressure exists. If this negative differential pressure is coupled with high permeability and high porosity, a severe kick may occur. Kick labels A kick can be labeled in several ways, including one that depends on the type of formation fluid that entered the borehole. Known kick fluids include: Gas Oil Salt water Magnesium chloride water Hydrogen sulfide (sour) gas Carbon dioxide If gas enters the borehole, the kick is called a "gas kick." Furthermore, if a volume of 20 bbl (3.2 m3) of gas entered the borehole, the kick could be termed a 20-bbl (3.2-m3) gas kick. Another way of labeling kicks is by identifying the required mud weight increase necessary to control the well and kill a potential blowout. For example, if a kick required a 0.7-lbm/gal (84-kg/m3) mud weight increase to control the well, the kick could be termed a 0.7-lbm/gal (84-kg/m3) kick. It is interesting to note that an average kick requires approximately 0.5 lbm/gal (60 kg/m3), or less, mud weight increase.
Causes of kicks Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure, which causes fluids to flow from the formation into the wellbore. In almost all drilling operations, the operator attempts to maintain a hydrostatic pressure greater than formation pressure and, thus, prevent kicks; however, on occasion the formation will exceed the mud pressure and a kick will occur. Reasons for this imbalance explain the key causes of kicks: 4
Insufficient mud weight. Improper hole fill-up during trips. Swabbing. Cut mud. Lost circulation.
Insufficient mud weight Insufficient mud weight is the predominant cause of kicks. A permeable zone is drilled while using a mud weight that exerts less pressure than the formation pressure within the zone. Because the formation pressure exceeds the wellbore pressure, fluids begin to flow from the formation into the wellbore and the kick occurs. These abnormal formation pressures are often associated with causes for kicks. Abnormal formation pressures are greater pressures than in normal conditions. In well control situations, formation pressures greater than normal are the biggest concern. Because a normal formation pressure is equal to a full column of native water, abnormally pressured formations exert more pressure than a full water column. If abnormally pressured formations are encountered while drilling with mud weights insufficient to control the zone, a potential kick situation has developed. Whether or not the kick occurs depends on the permeability and porosity of the rock. A number of abnormal pressure indicators can be used to estimate formation pressures so that kicks caused by insufficient mud weight are prevented (some are listed in Table 1).
Table 1- Abnormal Pressure Indicators An obvious solution to kicks caused by insufficient mud weights seems to be drilling with high mud weights; however, this is not always a viable solution. First, high mud weights may exceed the fracture mud weight of the formation and induce lost circulation. Second, mud weights in excess of the formation pressure may significantly reduce the penetration rates. Also, pipe sticking becomes a serious consideration when excessive mud weights are used. The best solution is to maintain a mud weight slightly greater than formation pressure until the mud weight begins to approach the fracture mud weight and, thus, requires an additional string of casing. Improper hole fill-up during trips Improperly filling up of the hole during trips is another prominent cause of kicks. As the drillpipe is pulled out of the hole, the mud level falls because the pipe steel no longer displaces the mud. As the overall mud level decreases, the hole must be periodically filled up with mud to avoid reducing the hydrostatic pressure and, thereby, allowing a kick to occur. The two acceptable methods most commonly used to maintain hole fill-up are the trip-tank method and the pump-stroke measurements method. 5
The trip-tank method has a calibration device that monitors the volume of mud entering the hole. The tank can be placed above the preventer to allow gravity to force mud into the annulus, or a centrifugal pump may pump mud into the annulus with the overflow returning to the trip tank. The other method of keeping a full hole—the pump-stroke measurement method—is to periodically fill up the hole with a positive-displacement pump. A flow line device can be installed with the positivedisplacement pump to measure the pump strokes required to fill the hole. This device will automatically shut off the pump when the hole is full.
Swabbing Pulling the drillstring from the borehole creates swab pressures. Swab pressures are negative, and reduce the effective hydrostatic pressure throughout the hole and below the bit. If this pressure reduction lowers the effective hydrostatic pressure below the formation pressure, a potential kick has developed. Variables controlling swab pressures are: Pipe pulling speed Mud properties Hole configuration The effect of “balled” equipment Some swab pressures can be seen in Table 2.
Table 2- Swab Pressures (psig) for a 14-ppg mud 4½ -in. Pipe With Various Hole Sizes and Several Pulling Speeds Cut mud Gas-contaminated mud will occasionally cause a kick, although this is rare. The mud density reduction is usually caused by fluids from the core volume being cut and released into the mud system. As the gas is circulated to the surface, it expands and may reduce the overall hydrostatic pressure sufficient enough to allow a kick to occur. Although the mud weight is cut severely at the surface, the hydrostatic pressure is not reduced significantly because most gas expansion occurs near the surface and not at the hole bottom. Lost circulation Occasionally, kicks are caused by lost circulation. A decreased hydrostatic pressure occurs from a shorter mud column. When a kick occurs from lost circulation, the problem may become severe. A large volume of kick fluid may enter the hole before the rising mud level is observed at the surface. It is recommended that the hole be filled with some type of fluid to monitor fluid levels if lost circulation occurs. Warning signs of kicks Warning signs and possible kick indicators can be observed at the surface. Each crew member has the responsibility to recognize and interpret these signs and take proper action. All signs do not positively 6
identify a kick; some merely warn of potential kick situations. Key warning signs to watch for include the following: Flow rate increase Pit volume increase Flowing well with pumps off Pump pressure decrease and pump stroke increase Improper hole fill-up on trips String weight change Drilling break Cut mud weight Each is identified below as a primary or secondary warning sign, relative to its importance in kick detection. Flow rate increase (primary indicator) An increase in flow rate leaving the well, while pumping at a constant rate, is a primary kick indicator. The increased flow rate is interpreted as the formation aiding the rig pumps by moving fluid up the annulus and forcing formation fluids into the wellbore. Pit volume increase (primary indicator) If the pit volume is not changed as a result of surface-controlled actions, an increase indicates a kick is occurring. Fluids entering the wellbore displace an equal volume of mud at the flowline, resulting in pit gain. Flowing well with pumps off (primary indicator) When the rig pumps are not moving the mud, a continued flow from the well indicates a kick is in progress. An exception is when the mud in the drillpipe is considerably heavier than in the annulus, such as in the case of a slug. Pump pressure decrease and pump stroke increase (secondary indicator) A pump pressure change may indicate a kick. Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. As the flow continues, the low-density influx will displace heavier drilling fluids, and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drillpipe tends to fall and pump speed may increase. Other drilling problems may also exhibit these signs. A hole in the pipe, called a “washout,” will cause pump pressure to decrease. A twist-off of the drillstring will give the same signs. It is proper procedure, however, to check for a kick if these signs are observed. Improper hole fill-up on trips (primary indicator) When the drillstring is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drillstring. Even though gas or salt water may have entered the hole, the well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure.
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String weight change (secondary indicator) Drilling fluid provides a buoyant effect to the drillstring and reduces the actual pipe weight supported by the derrick. Heavier muds have a greater buoyant force than less dense muds. When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase. Drilling break (secondary indicator) An abrupt increase in bit-penetration rate, called a “drilling break,” is a warning sign of a potential kick. A gradual increase in penetration rate is an abnormal pressure indicator, and should not be misconstrued as an abrupt rate increase. When the rate suddenly increases, it is assumed that the rock type has changed. It is also assumed that the new rock type has the potential to kick (as in the case of a sand), whereas the previously drilled rock did not have this potential (as in the case of shale). Although a drilling break may have been observed, it is not certain that a kick will occur, only that a new formation has been drilled that may have kick potential. It is recommended when a drilling break is recorded that the driller should drill 3 to 5 ft (1 to 1.5 m) into the sand and then stop to check for flowing formation fluids. Flow checks are not always performed in tophole drilling or when drilling through a series of stringers in which repetitive breaks are encountered. Unfortunately, many kicks and blowouts have occurred because of this lack of flow checking. Cut mud weight (secondary indicator) Reduced mud weight observed at the flow line has occasionally caused a kick to occur. Some causes for reduced mud weight are:
Core volume cutting
Connection air
Aerated mud circulated from the pits and down the drillpipe
Fortunately, the lower mud weights from the cuttings effect are found near the surface (generally because of gas expansion), and do not appreciably reduce mud density throughout the hole. Table 3 shows that gas cutting has a very small effect on bottomhole hydrostatic pressure.
Table 3- Effect of Gas-Cut Mud On The Bottomhole Hydrostatic Pressure An important point to remember about gas cutting is that, if the well did not kick within the time required to drill the gas zone and circulate the gas to the surface, only a small possibility exists that it will kick. Generally, gas cutting indicates that a formation has been drilled that contains gas. It does not mean that the mud weight must be increased. Kick detection and monitoring with MWD tools During circulation and drilling operations, measurement while drilling (MWD) systems monitor: Mud properties 8
Formation parameters Drillstring parameters The system is widely used for drilling, but it also has applications for well control, including the following:
Drilling-efficiency data, such as downhole weight on bit and torque, can be used to differentiate between rate of penetration changes caused by drag and those caused by formation strength. Monitoring bottomhole pressure, temperature, and flow with the MWD tool is not only useful for early kick detection, but can also be valuable during a well-control kill operation. Formation evaluation capabilities, such as gamma ray and resistivity measurements, can be used to detect influxes into the wellbore, identify rock lithology, and predict pore pressure trends.
The MWD tool enables monitoring of the acoustic properties of the annulus for early gas-influx detection. Pressure pulses generated by the MWD pulser are recorded and compared at the standpipe and the top of the annulus. Full-scale testing has shown that the presence of free gas in the annulus is detected by amplitude attenuation and phase delay between the two signals. For water-based mud systems, this technique has demonstrated the capacity to consistently detect gas influxes within minutes before significant expansion occurs. Further development is currently under way to improve the system’s capability to detect gas influxes in oil-based mud.
Some MWD tools feature kick detection through ultrasonic sensors. In these systems, an ultrasonic transducer emits a signal that is reflected off the formation and back to the sensor. Small quantities of free gas significantly alter the acoustic impedance of the mud. Automatic monitoring of these signals permits detection of gas in the annulus. It should be noted that these devices only detect the presence of gas at or below the MWD tool.
The MWD tool offers kick-detection benefits, if the response time is less than the time it takes to observe the surface indicators. The tool can provide early detection of kicks and potential influxes, as well as monitor the kick-killing process. Tool response time is a function of the complexity of the MWD tool and the mode of operation. The sequence of data transmission determines the update times of each type of measurement. Many MWD tools allow for reprogramming of the update sequence while the tool is in the hole. This feature can enable the operator to increase the update frequency of critical information to meet the expected needs of the section being drilled. If the tool response time is longer than required for surface indicators to be observed, the MWD only serves as a confirmation source. Kick identification When a kick occurs, note the type of influx (gas, oil, or salt water) entering the wellbore. Remember that well-control procedures developed here are designed to kill all types of kicks safely. The formula required to make this kick influx calculation is as follows: .................... (1) Where gi = influx gradient, psi/ft; gmdp = mud gradient in drillpipe, psi/ft; and hi = influx height, ft. The influx gradient can be evaluated using the guidelines in Table 1.
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Table 1- Influx Gradient Evaluation Guidelines Although psidp and psic can be determined accurately for Eq. 1, it is difficult to determine the influx height. This requires knowledge of the pit gain and the exact hole size Kill-weight mud calculation It is necessary to calculate the mud weight needed to balance bottomhole formation pressure. “Kill-weight mud” is the amount of mud necessary to exactly balance formation pressure. It will be later shown that it is safer to use the exact required mud weight without variation Because the drillpipe pressure has been defined as a bottomhole pressure gauge, the psidp can be used to calculate the mud weight necessary to kill the well. The kill mud formula follows: .................... (2) Where ρkw = kill-mud weight, lbm/gal 19.23 = conversion constant Dtv = true vertical-bit depth, ft ρo = original mud weight, lbm/gal.
Nomenclature Dtv
= true vertical depth, bit depth, ft
gi
= influx gradient, psi/ft
gmdp
= mud gradient in drillpipe, psi/ft
hi
= influx height, ft
ρkw
= kill mud weight, lbm/gal
ρo
= original mud weight, lbm/gal
psic
= shut-in casing pressure, psi
psidp
= shut-in drillpipe pressure, psi
Blowout 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. Cause of blowouts Reservoir pressure
When hydrocarbons are concentrated in a trap, an oil field forms, from which the liquid can be extracted by drilling and pumping. The down hole pressures experienced at the 10
rock structures change depending upon the depth and the characteristic of the source rock. This is called Reservoir pressure
Formation kick
The downhole fluid pressures are controlled in modern wells through the balancing of the hydrostatic pressure provided by the mud used. Should the balance of the drilling mud pressure be incorrect then formation fluids (oil, natural gas and/or water) begin to flow into the wellbore and up the annulus (the space between the outside of the drill string and the walls of the open hole or the inside of the last casing string set), and/or inside the drill pipe. This is commonly called a kick. Types of blowouts Well blowouts can occur during the drilling phase, during well testing, during well completion, during production, or during work over activities. 1. Surface blowouts Blowouts can eject the drill string out of the well, and the force of the escaping fluid can be strong enough to damage the drilling rig. In addition to oil, the output of a well blowout might include sand, mud, rocks, drilling fluid, natural gas, water, and other substances. 2. Subsea blowouts Subsea wells have the wellhead and pressure control equipment located on the seabed. They vary from depths of 10 feet (3.0 m) to 8,000 feet (2,400 m). It is very difficult to deal with a blowout in very deep water because of the remoteness and limited experience with this type of situation. 3. Underground blowouts An underground blowout is a special situation where fluids from high pressure zones flow uncontrolled to lower pressure zones within the wellbore. Usually this is from deeper higher pressure zones to shallower lower pressure formations. There may be no escaping fluid flow at the wellhead.
Primary Well Control Primary Well Control is hydrostatic pressure provided by drilling fluid more than formation pressure but less than fracture gradient while drilling. If hydrostatic pressure is less than reservoir pressure, reservoir fluid may influx into wellbore. This situation is called “Loss Primary Well Control”. Not only is hydrostatic pressure more than formation pressure, but also hydrostatic pressure must not exceed fracture gradient. If your mud in hole is too heavy causing broken wellbore, you will face with loss circulation problem (may be partially lost or total lost circulation). When fluid is losing into formation, mud level in well bore will be decreased that will result in reducing hydrostatic pressure. In worst case scenario, you will lose the primary well control and wellbore influx or kill will enter into wellbore.
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Secondary Well Control When primary well control is failed, it causes kick (wellbore influx) coming into wellbore. Therefore, this situation needs special equipment which is called “Blow out Preventer” or BOP to control kick. Well, we can call that “Blow out Preventer” or BOP is Secondary Well Control. Please also remember that BOP must be used with specific procedures to control kick such as driller method, wait and weight, lubricate and bleed and bull heading. Without well control practices for using BOP’s, it will just be only heavy equipment on the rig.
Tertiary Well Control Tertiary Well Control is specific method used to control well in case of failure of primary and secondary well control. These following examples are tertiary well control:
Drill relief wells to hit adjacent well that is flowing and kill the well with heavy mud. They use this method to control the well that was firing on the platform. Dynamic kill by rapidly pumping of heavy mud to control well with Equivalent Circulating Density (ECD) Pump barite or gunk to plug wellbore to stop flowing Pump cement to plug wellbore
Hydrostatic Pressure Hydrostatic pressure is created by fluid column. The pressure exerted by a fluid at equilibrium at a given point within the fluid, due to the force of gravity. Two factors affecting hydrostatic pressure are mud weight and True Vertical Depth. So this post will demonstrate how to calculate hydrostatic pressure in different oilfield units. 1. Calculate hydrostatic pressure in psi by using mud weight in PPG and feet as the units of True Vertical Depth. Hydrostatic pressure equation: HP = mud weight in ppg x 0.052 x True Vertical Depth (TVD) in ft Example: mud weight = 12.0 ppg True Vertical Depth = 10,000 ft HP = 12.0 ppg x 0.052 x 10,000 ft HP = 6,240 psi 2. Calculate hydrostatic pressure in psi by using pressure gradient in psi/ft and feet as the units of True Vertical Depth. Hydrostatic pressure equation: HP = Pressure gradient in psi/ft x True Vertical Depth (TVD) in ft Example: Pressure Gradient = 0.5 psi/ft True Vertical Depth = 10,000 ft HP = 0.5 psi/ft x 10,000 ft HP = 5,000 psi 12
3 Calculate hydrostatic pressure in psi by using mud weight in lb/ft3 and feet as the units of True Vertical Depth. Hydrostatic pressure equation: HP = 0.006944 x mud weight, lb/ft3 x TVD, ft Example: mud weight = 80 lb/ft3 true vertical depth = 10,000 ft HP = 0.006944 x 80 lb/ft3 x 10,000 ft HP = 5,555 psi 4. Calculate hydrostatic pressure in psi by using mud weight in PPG and meters as unit of True Vertical Depth. Hydrostatic pressure equation: HP = mud weight, ppg x 0.052 x TVD in meters x 3.281 Example: Mud weight = 12.0 ppg true vertical depth = 5000 meters HP = 12.0 ppg x 0.052 x 5000 x 3.281 HP = 10,237 psi
Bottom Hole Pressure (BHP) The bottom hole pressure is sum of all the pressure acting on the bottom hole. We can describe the statement before as the following equation; Bottom Hole Pressure (BHP) = Surface Pressure (SP) + Hydrostatic Pressure (HP)
Formation Pressure The pressure at the bottom of a well when it is shut in at the wellhead. The pressure of the subsurface formation fluids, commonly expressed as the density of fluid required in the wellbore to balance that pore pressure. A normal pressure gradient might require 9 lbm/gal, US [1.08 kg/m3], while an extremely high gradient may need 18 lbm/gal, US [2.16 kg/m3] or higher.
Effect of hydrostatic pressure with different density fluids in the hole The pressure at a given depth in a static liquid is a result the weight of the liquid acting on a unit area at that depth plus any pressure acting on the surface of the liquid.
The pressure due to the liquid alone (i.e. the gauge pressure) at a given depth depends only upon the density of the liquid ρ and the distance below the surface of the liquid h.
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.
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The formula for calculating hydrostatic pressure in SI units (kg/m²) is: Hydrostatic pressure = Height (m) × Density (kg/m³) × Gravity (m/s²). 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. To convert these units to SI units, one can use:
1 ppg = ≈ 119.8264273 kg/m³ 1 ft = 0.3048 meters 1 psi = 0.0689475729 bar 1 bar = 105 pascals
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/meter. The hydrostatic pressure gradient can be written as: Pressure gradient (psi/ft) = HSP/TVD = 0.052 × MW (ppg).
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 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. 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. 14
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.
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 g = acceleration due to gravity
S = overburden pressure
D = vertical thickness of the overlying sediments
ρb = average formation bulk density
The bulk density of the sediment is a function of rock matrix density, porosity within the confines of the pore spaces, and pore fluid density. This can be expressed as
ρb = φρf + (1 – φ)ρm φ = rock porosity
ρf = formation fluid density
ρm = rock matrix density
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 (kg/m) or ppg (kPa). 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.
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.
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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. 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 FP = formation pressure (psi)
HSPinflux = Hydrostatic pressure of the influx (psi)
HSPmud = Hydrostatic pressure of mud in the annulus (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, 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:
Hydrostatic pressure (HSP) Shut-in surface pressure (SIP) 16
Friction pressure Surge pressure (occurs when transient pressure increases the bottom-hole pressure) Swab pressure (occurs when transient pressure reduces the bottom-hole pressure) Therefore BHP can be said to be the sum of all pressures at the bottom of the well hole, which equals:
BHP = HSP + SIP + friction + Surge - swab
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DAY-1 --------------- Session - II Leak off Test Leak off Test is conducted in order to find the fracture gradient of certain formation. The results of the leak off test also dictate the maximum equivalent mud weight that should be applied to the well during drilling operations. Leak off Test (LOT) guide line procedures are as follows (note: this is just only guide line. You may need to follow your standard procedure in order to perform leak off test): 1. Drill out new formation few feet, circulate bottom up and collect sample to confirm that new formation is drilled to and then pull string into the casing. 2. Close annular preventer or pipe rams, line up a pump, normally a cement pump, and circulate through an open choke line to ensure that surface line is fully filled with drilling fluid. 3. Stop the pump and close a choke valve. 4. Gradually pump small amount of drilling fluid into well with constant pump stroke. Record total pump strokes, drill pipe pressure and casing pressure. Drill pipe pressure and casing pressure will increase continually while pumping mud in hole. When plot a graph between strokes pumped and pressure, if formation is not broken, a graph will demonstrate straight line relationship. When pressure exceeds formation strength, formation will be broken and let drilling fluid permeate into formation, therefore a trend of drill pipe/casing pressure will deviate from straight line that mean formation is broken and is injected by drilling fluid. We may call pressure when deviated from straight line as leak off test pressure. Note: the way people call leak off test pressure depends on each company standard practices. Leak off test pressure can be calculated into equivalent mud weight in ppg as formula below: Leak off test in equivalent mud weight (ppg) = (Leak off test pressure in psi) ÷ 0.052 ÷ (Casing Shoe TVD in ft) + (current mud weight in ppg) Pressure gradient in psi/ft = (Leak off test pressure in psi) ÷ (Casing Shoe TVD in ft) Example: Leak off test pressure = 1600 psi Casing shoe TVD = 4000 ft Mud weight = 9.2 ppg Leak off test in equivalent mud weight (ppg) = 1600 psi ÷ 0.052 ÷ 4000 ft + 9.2ppg ppg = 16.9 Pressure gradient = 1600 ÷ 4000 = 0.4 psi/ft 4. Bleed off pressure and open up the well. Then proceed drilling operation.
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Maximum Allowable Annulus Surface Pressure (MAASP) Maximum Allowable Annulus Surface Pressure is an absolute upper limit for the pressure in the annulus of an oil and gas well as measured at the wellhead.
Calculation: The Maximum Allowable Annular Surface Pressure (MAASP) equals the formation breakdown pressure at the point under consideration minus the hydrostatic head of the mud/or influx in the casing. During well control operations the critical point to consider is the casing shoe. MAASP = Formation Breakdown Pressure - Head of mud in use Or MAASP = (E.M.W - MWMUD) x 0.052 x Shoe Depth (TVD) E.M.W = Equivalent mud weight at which formation breaks at shoe MWMUD = Mud Weight During the process of controlling and circulating out an influx, several stages can be distinguished in calculating the MAASP. However, the MAASP is only significant while the casing is full of fluid. For pre-kick calculation purposes, the value of the MAASP shall be revised whenever the hydrostatic head of mud in the hole changes.
Kick Tolerance Kick Tolerance is defined as the maximum kick volume that can be taken into the wellbore and circulated out without fracturing the formation at weak point (shoe), given a difference between pore pressure and mud weight in use. It is the maximum volume of gas kick in barrels that we are able to successfully shut the well in and circulate the kick out of hole without breaking formation strength at shoe depth or overcoming the weakest anticipated facture pressure in wellbore. In order to calculate kick tolerance, we need to assume Kick Intensity (ppg), the depth that kick will happen, mostly is TD. The kick intensity is the difference between the formation pressure and current mud weight used in the wellbore. When you see the kick tolerance noted in the drilling programs from town, drilling engineers normally calculate kick intensity at TD.
Kick Tolerance Calculation 1. Determine kick intensity 2. Determine maximum allowable shut in casing pressure (MASICP) 3. Determine influx height with this following equation
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4. Calculate influx volume at BHA based on the influx height Influx volume at BHA, bbl = Kick Height, ft x Annular Capacity of BHA and Hole, bbl/ft 5. Calculate influx volume at shoe base on the influx height Influx volume at shoe, bbl = Kick Height, ft x Annular Capacity of DP and Hole, bbl/ft 6. Calculate influx volume at the bottom based on the influx volume at the shoe by applying Boyle’s Law Influx volume at bottom, bbl = (Influx volume at shoe x Leak off test pressure at shoe) ÷ (Formation pressure, psi) Formation pressure can be calculated from well TVD and maximum anticipated formation pressure. 7. Compare both figures. The smaller figure is the Kick Tolerance. For more understanding, please determine kick tolerance with following data; Possible maximum formation pressure = 12.5 ppg Planned TD mud weight = 12.0 ppg Casing shoe = 6,500’MD/5,500’ TVD Leak off test at casing shoe = 14.7 ppg Hole depth = 10,100’MD/9,500’TVD Bit = 12-1/4” BHA = 850 ft Average OD of BHA = 6.5” Drill pipe size = 5” Influx gradient (gas) = 0.11 psi/ft 1. Kick intensity = 12.5 – 12.0 = 0.5 ppg 2. Maximum Allowable Shut in Casing Pressure (MASICP) ** some people may call maximum allowable initial shut in casing pressure**. = (14.7 – 12.0) x 0.052 x 5,500 = 772 psi
3. Influx height: 4. Calculate influx volume at BHA based on the influx height
annular capacity between hole and BHA = 20
Annular capacity between hole and drill pipe = ( 12.252 – 52) ÷ 1029.4 = 0.1215 bbl/ft Influx volume at BHA, bbl = (0.1047 x 850) + (0.1215 x 171) = 109.8 bbl 5. Calculate influx volume at shoe base on the influx height
Annular capacity between hole and drill pipe = Influx volume at shoe, bbl = 0.1215 x 1021 = 124.1 bbl
6. This volume is a reference at shoe; therefore, you need to convert it to the bottom hole condition. Boyle’s gas law is utilized in order to get the figure at the bottom hole. P1 x V1 = P2 x V2 For this case, you need to use the maximum pressure at shoe which is the Leak Off Test pressure because it is the maximum value before you will break the wellbore. Rearranging the equation, you will get like this. Influx volume at bottom, bbl = Influx volume at shoe x Leak off test pressure at shoe ÷ Formation pressure, psi Influx volume at shoe = 124.1 bbl Leak off test pressure = 0.052 x 14.7 x 5,500 = 4,204 psi Formation pressure = 0.052 x 12.5 x 9,500 = 6,175 psi Influx volume at bottom, bbl = (124.1 x 4, 204) ÷ (6175) = 84.5 bbl 7. We need to compare 2 cases and the smaller figure is the kick tolerance of the well. 1st case: 109.8 bbl 2nd case: 84.5 bbl Therefore, the kick tolerance is 84.5 bbl. Conclusion: With the following information, the maximum kick that the well can take and personnel can circulate it out of hole without breaking formation is 84.5 bbl.
Top hole drilling It’s a method to drill top hole (shallow depth) using diverter. Where shallow casing strings or conductor pipe are set, fracture gradients will be low. It may be impossible to close the BOP on a shallow gas kick without breaking down the formation at the shoe. If a shallow gas kick is taken while drilling top hole then the kick should be diverted.
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Drilling shallow sand too fast can result in large volumes of gas cut mud in the annulus and cause the well to flow, also fast drilling can load up the annulus increasing the mud density leading to lost circulation and if the level in annulus drops far enough then well may flow.
1. When drilling top hole a diverter should be installed and it is good practice to leave the diverter installed until 13 3/8″ casing has been run. An automatic diverter system should first:a) Open an alternative flow path to overboard lines. b) Close shaker valve and trip tank valve. c) Close diverter annular around drill pipe. d) If there are two overboard lines then the upwind valve should be manually closed. 2. If any indication of flow is observed while drilling top hole, close diverter immediately as the gas will reach surface in a very short time and it is inadvisable to attempt a flow check. 3. Suggested diverting procedure in the event of a shallow gas kick. a) Maintain maximum pump rate and commence pumping kill mud if available. b) Space out so that the lower safety valve is above the drill floor. c) With diverter line open close shaker valve and diverter packer. d) Shut down all nonessential equipment, if there is an indication of gas on rig floor or cellar area then activate deluge systems. e) On jack-up and platform rig monitor sea for evidence of gas breaking out around conductor. f) If mud reserves run out then continue pumping with sea-water. g) While drilling top hole a float should be run. This will prevent gas entering drill string if a kick is taken while making a connection. It will also stop backflow through the drill string on connections.
Major hazards of shallow gas influx Shallow gas is defined as any hydrocarbon-bearing zone which may be encountered at a depth close to the surface or mud line. Generally it is not possible to close-in and contain a gas influx from a shallow zone because weak formation integrity may lead to breakdown and broaching to surface / mud line. Shallow Hazard No. 1: Shallow Gas (and Shallow Water Flows) If shallow gas of a large enough quantity is encountered unexpectedly during drilling operations, a blowout might occur. The driller has interest in shallow gas from mud line to 3,000 feet and below. Shallow trapped gas areas can be avoided by changing the wellsite location, or if required, and only if the frac gradient is sufficient, can be penetrated by cementing a string of casing firmly above the gas zone, increasing mud weight to penetrate through the gas zone, and continue the drilling operation. Gas that is trapped in the shallow sediments usually originates from deeper gas reservoirs but can also come from biogenic activity in the shallow sediments. Shallow gas can only be confidently interpreted from high resolution seismic data that has been digitally processed and displayed in true amplitude 22
Our experience with shallow water flows (SWF) is similar to shallow gas. In the case of water flow, the problem to drilling is it can be water under very low over-pressure, usually in an area of rapid sediment deposition, but there are exceptions. Our recommendations regarding SWF is to not let even a small flow develop. Another aspect, yet not fully understood is the long term effect of a casing/asset set through a potential shallow water flow zone. Shallow Hazard No. 2: Near Surface Faults Near surface faults can create surface anomalies hazardous to jack-up and drilling rigs including anchors and guy-wire bases. The fault plane itself can pass gas from a deeper gas zone and if not controlled, a blowout will occur. The ocean bottom is unstable around fault traces. Casing should not be terminated in or near a fault zone because shear strength (frac gradient) of the sediments in the fault zone is much less than "non-faulted" sediments. In deep water and to improve the resolution of faults, time or depth migration of the digitally processed high resolution seismic data is recommended. Shallow Hazard No. 3: Sediment Strength Both slightly hard sediments and slightly soft sediments can create problems to drilling operations. Jack-up rigs require ample leg penetration for stabilization for high shear capacity for their legs. If leg penetration is too deep, the well may not be drilled because the limit of penetration is the leg length. The water depth, the leg penetration, and the required air gap (for insurance and safety purposes) must add up to less than the leg length available. If this is greater, then the well cannot be drilled and another drill rig or drillship should be chosen. Prediction of jack-up leg penetration is based on the first good seismic reflector deeper than 20 feet below mud line. This reflecting horizon can be interpreted from seismic data. Correlation to known engineering data from local soil borings or leg penetration depth provide a more accurate estimate. Anchor systems, including primary and piggy-back anchors, require at least 20 - 25 feet (thickness) of mud for adequate shear strength. If a hard silt, sand, limestone, coral reef, or salt is encountered shallower than 25 feet within the anchor's path, the anchor will slide along the layer and not "dig in". This situation calls for additional piggy-back anchors to be set in order for the combined shear strength of all anchors to provide adequate tension carrying ability by the total anchoring system. High resolution geophysical can be used to determine anchoring conditions. Shallow Hazard No. 4: Old Rivers and Glaciers Old river channels can be filled with clay, porous material, mud, gravels, and/or boulders. Any channel is potentially hazardous and should be planned for in the wellsite location and drilling plan. Lost circulation in channels has cost the industry greatly in the North Sea and the Gulf of Alaska, especially due to glacial boulder channels causing high bit torque and lost circulation at shallow depth. Channels are interpreted from high resolution data.
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Shallow Hazard No. 5: Water Bottom Anomalies Steep bottom slopes create sediments bottom stability problems for both jack-ups and drillships. Water bottom features such as mud lumps, trenches, faults scarps, pockholes, ridges and depressions can be interpreted from high resolution seismic data. The vertical exaggeration in high resolution records makes the identification of water bottom hazards and accurate description of the seafloor possible. Shallow Hazard No. 6: Man-made Objects Man-made objects exist wherever man travels. These include pipelines, debris, wrecks and cultural items that can be detected with multi-sensor geophysical surveys. Each must be avoided. Car bodies, garbage and schools of fish are commonly also seen on high resolution records and have been misinterpreted by even the most experienced analyst.
Diverter Systems in Well Control The diverter is an annular preventer with a large piping system underneath. It is utilized to divert the kick from the rig and it can be used when the conductor pipe is set. It is not used if you drill riser less. The large diameter pipe typically has two directions diverting the wellbore fluid out of the rig (see the figure below for more understanding).
The diverter should be used only when the well cannot be shut in because of fear of formation breakdown or lost circulation. Use of the diverter depends on the regulations and operator policies. The diverter is normally installed on a conductor casing with large diverter pipe pointing to a downwind area. Typically, the selective valves located at each diverter line can be operated separately so the personnel on the rig can divert the flow into the proper direction. It is designed for short periods of high flow rate but it cannot hold a lot of pressure. With high flow rate, the erosion can be happened easily so the bigger of diverter line the better. Additionally, the straight diverter lines are the most preferable.
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SHALLOW GAS CONTROL PROCEDURE Use of diverter system should be brought into practice to control the shallows gas kicks. Shallow Gas control While Drilling When any warning sign of a kick has been observed, immediately stop rotary, raise the kelly until tool joint is above rotary. Stop pumps and check for any flow. Open diverter line valves, depending upon wind direction. Close diverter packer. Circulate out with available drilling fluid at maximum possible pump rate. Remove the non-essential personnel from rig floor. Shallow gas control While Tripping Set pipes on slips. Install FOSV and close it. Open diverter line valves depending upon wind direction. Close diverted packer. Connect Kelly or circulating head. Open FOSV Circulate out with available fluid.
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DAY-1 --------------- Session - III Gas Cut Drilling Fluid Drilling Fluid that has become entrained with gas from previously drilled gas bearing formation which in turn lowers the drilling fluid density and hydrostatic head of the drilling fluid column.
Swab and surge effects Swabbing is when bottom hole pressure is reduced below formation pressure due to the effects of pulling the drill string, which allows an influx of formation fluids into the wellbore. When pulling the string there will always be some variation to bottom hole pressure. A pressure loss is caused by friction, the friction between the mud and the drill string being pulled. Swabbing can also be caused by the full gauge down hole tools (bits, stabilisers, reamers, core barrels, etc.) being balled up. This can create a piston like effect when they are pulled through mud. This type of swabbing can have drastic effects on bottom hole pressure.
Surging Surging is when the bottom hole pressure is increased due to the effects of running the drill string too fast in the hole. Down hole mud losses may occur if care is not taken and fracture pressure is exceeded while RIH. Proper monitoring of the displacement volume with the trip tank is required at all times. Swabbing Swabbing is a recognized hazard whether it is “low” volume swabbing or “high” volume swabbing. A small influx volume may be swabbed into the open hole section. The net decrease in hydrostatics due to this low density fluid will also be small. If the influx fluid is gas it can of course migrate and expand. The expansion may occur when there is little or no pipe left in the hole. The consequences of running pipe into the hole and into swabbed gas must also be considered.
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Trip margin Trip margin is an increment of drilling mud density to provide overbalance so as to compensate the swabbing effect while pulling out of hole. You can quickly calculate how much trip margin required by this following simple equation. Trip Margin = Mud Yield Point ÷ [11.7 x (Hole diameter – Drill pipe diameter)] Trip Margin (PPG) = (Margin needed (Psi) – Present Margin (Psi))/ (0.052xTVD (ft)) The unit of each parameter is as follows; Trip Margin in ppg (pound per gallon) Mud Yield Point in lb/100 sq ft Hole diameter in inch Drill pipe diameter in inch Let’s try to determine the trip margin with the following information. Mud Yield Point = 12 lb/100 sq ft Hole diameter = 10 inch Drill pipe diameter = 5 inch Trip Margin = 12 ÷ [11.7 x (10 – 5)] = 0.2 ppg
Slow circulation rate Slow Circulation Rate is a circulation rate which will be used in well kill operation. Typically, slow circulation rate pressure (SCR) is recorded from each particular flow rate and the pressure represents pressure loss of the system while circulating. Since there are so many pressure gauges on the rig, you may get confused on the figures. In order to be at the same page for every personnel on the rig, the SCR should be recorded by the pressure gauge that we will use for killing the well. There are a lot of reasons why we should kill the well with slow rate rather than a drilling rate as follows:
• To minimize friction pressure • To allow time to weight up mud if you use wait and weight method • To reduce pressure on surface equipment • To allow degasser to separate gas from the mud • To reduce needs for fast choke operation • To allow personnel to think if something goes wrong Let’s get an idea how to get pre-recorded SCR.
1. Turn pump on at slow speed as 10, 20, 30 and 40 spm 2. Record pressure without rotating or moving drillstring 3. Each pressure recorded at particular pump speed is SCR. 27
Please always remember that SCR that you take for each time representing pressure loss at that time. I don’t recommend you to use it to estimate the initial circulating pressure. Let’s me explain why – There are some errors in pre-recorded SCR which can make you in a trouble. • Pre-recorded SCR may not reflect current pressure due to drilling mud properties change. • The depth of pre-recorded SCR is not the same as the current drilling depth. • SCR may be changed due to unknown condition down hole as BHA mechanism, plugged jets, etc. How can we get ICP without using pre-recorded SCR? In order to get the initial circulating pressure, you just simply bring the pump up to speed by holding casing pressure constant until you reach kill rate. Additionally, you will be able to calculate the actual SCR by calculation. Let’s take a look at the equation below. ICP = SIDPP + SCR Where; ICP is Initial Circulating Pressure. SIDPP is Shut In Drill Pipe Pressure. SCR is Slow Circulation Rate pressure. Therefore, SCR = ICP – SIDPP If you would like to check SCR, the following time is when you should check SCR. • Check before drilling out of casing shoe • Check after tripping back to the bottom • Check when mud properties are changes • Check at least two times each shift at the drilling depth at that time
Causes of kicks A “Kick” or “Wellbore Influx” is undesirable flow of formation fluid into the wellbore and it happens when formation pressure is more than hydrostatic pressure in wellbore. Several causes of Kick (Wellbore Influx) are listed below: 1. Lack of knowledge and experience of personnel (Human error) – Lacking of well-trained personnel can cause well control incident because they don’t have any ideas what can cause well control problem. For example, personnel may accidentally pump lighter fluid into wellbore and if the fluid is light enough, reservoir pressure can overcome hydrostatic pressure. 2. Light density fluid in wellbore - It results in decreasing hydrostatic pressure. There are several reasons that can cause this issue such as • Light pills, sweep, and spacer in hole • Accidental dilution of drilling fluid • Gas cut mud
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3. Abnormal pressure – If abnormally high pressure zones are over current mud weight in the well, eventually kick will occur. 4. Unable to keep the hole full all the time while drilling and tripping. If hole is not full with drilling fluid, overall hydrostatic pressure will decrease. 5. Severe lost circulation – Due to lost circulation in formation, if the well could not be kept fully filled all the time, hydrostatic pressure will be decreased. Lost circulation usually caused when the hydrostatic pressure of drilling fluid exceeds formation pressure. There are several factors that can cause lost circulation such as • Mud properties – mud weight is too heavy and too viscous. • High Equivalent Circulating Density • High surge pressure due to tripping in hole so fast • Drilling into weak formation strength zone 6. Swabbing causes reducing wellbore hydrostatic pressure. Swabbing is the condition that happens when anything in a hole such as drill string, logging tool, completion sting, etc is pulled and it brings out decreasing hydrostatic pressure. Anyway, swabbing can be recognized while pulling out of hole by closely monitoring hole fill in trip sheet.
Indications of kick - While tripping If an overbalance existed prior to pulling out of hole, then the only reasons for the well to flow are: ·swabbing; ·failure to keep the hole full; ·losses induced by surge pressures. Early detection of kicks off bottom can be achieved by observing whether the hole is taking the proper amount of fluid during roundtrips. This can be achieved by pumping across the flow riser with the trip tank (also called possum belly) which will give an immediate indication of gains or losses. Trip tank fluid levels observed during roundtrips should be recorded on a dedicated trip sheet and compared to previous roundtrips. This is the most accurate method of checking if the hole is filling-up correctly. If swabbing is observed, but the well does not flow, the string should be run back to bottom carefully and the possible influx should be circulated out. If the well shows any indication of flow, the well must be closed in and the string should be stripped back to bottom, because it is more complicated to handle a kick with the bit off bottom as compared to killing a well with the bit on bottom. If severe losses are experienced, followed by a kick (i.e. when running in too fast) LCM pills should be squeezed into the loss zone formation via the annulus at such a rate as to prevent the influx rising up the annulus. The losses should be cured before the remaining influx is circulated out. An inside BOP and RH Kelly cock complete with lifting arms must always be available on the drilling floor and be ready for immediate use. If the well starts to flow whilst tripping pipe, the Kelly cock should be installed and the well closed-in. Do not attempt to run the bit back to bottom with the well still open, since this may lead to excessive kick volumes and make well control much more difficult, if not impossible. The correct procedure is to close in the well at 29
first indication of flow. Closed-in pressures will be much lower and will leave more options open during further well control operations.
Indications of kick - While drilling The possible well control (kick) indications are as follows; Change in drilling breaks (ROP change) – If the differential between formation pressure and hydrostatic pressure created by drilling mud decreases, there is possibility to increase rate of penetration because the hold down effect is decreased. Increase drag and torque – Increasing in drilling torque and drag are usually noticed while drilling into over pressured shale formation because under balance hydrostatic pressure exerted by drilling fluid column cannot to hold back the formation intrusion into wellbore. Shale normally has low permeability so formation fluid will not come into wellbore. Anyway, if we drill ahead pass high shale pressure into over pressured high permeability zones such as sand or carbonate, the formation fluid will flow into wellbore resulting in kick. This is very important to record frequently drilling torque and drag because it could be your well control indicator. Decrease in Shale Density – Typically, shale density will increase as we drill deeper. If we see decrease in shale density, it may indicate that your well is in underbalance condition because high pressure zones (abnormal pressure) develop within large shale section. Practically, density of shale must be measured frequency and plot against drilling depth. You can see from a chart if there is any deviation in trend that could be an indication of change in pore pressure. Increase in cutting size and shape – Pieces of formation may break apart and fall into wellbore because of underbalance situation. Because rocks pieces broken by underbalance condition are not ruined by bit, they will be more angular and bigger than normal cutting. Larger of cutting size will be result in difficulty to circulate them out of wellbore, hence, there will be more hole fill and torque and drag will increase. In addition, without a proportional increase in ROP (rate of penetration), cutting volume coming over shale shakers will increased noticeably. Decrease in d-Exponent Value - Normally, trends of d-Exponent will increase as we drill deeper, but this value will decrease to lower values than what we expect in transition zones. By closely monitored d-Exponent, d-Exponent chart will be useful for people on the rig to notify the high pressure transition zones. Read and understand about d-Exponent and learn how to calculate d-Exponent and normalized dExponent (corrected d-Exponent) Change in Mud property- Without any chemical added into drilling fluid system, its property change due to increasing in water and/or chloride content indicates that formation fluid enters into the wellbore. For some drilling mud, when salt water enters into the wellbore and mix with drilling fluid, the mud viscosity will increase. In water base mud with low Ph salt saturated, the mud viscosity will decrease because of water
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from formation mixing with mud. On the other hand, water contamination in oil base mud will result in viscosity increases. Increase in Temperature from Returning Mud - By observing trend of temperature coming from mud return, temperature trend showing deviation from the normal temperature trend can be an indication of abnormal pressure zones, especially while drilling into transition zones. There are some factors that you need to account for when you try to evaluate mud temperature changes as listed below; Surface temperature conditions Elapsed time since tripping Mud chemicals used Wellbore geometry Circulating rate Cooling effect when drilling fluid flows through a long riser (deep water consideration) Increase in trip, connection and/or background gas – Gas in mud, normally called gas cut mud, does not be a sign of a well flowing because it could be gas coming from formation. Nonetheless, personnel on the rig should keep in mind as a possible kick indicator. Hence, flow show and PVT (pit volume total) must be closely monitored. Gas in the mud can come from one or more of the reasons listed below: Drill into a formation that contains gas or hydrocarbon. Temporally reduce in hydrostatic pressure due to swabbing effect. Pore pressure in a formation is greater than the hydrostatic pressure provided by drilling fluid in a wellbore.
Positive Well Control (kick) Indications Positive well control (wellbore influx) indications mean indications showing almost 100% kick (wellbore influx) into wellbore. We can classify the positive indicators the following categories.
Positive Well Control Indicators While drilling Increase in flow show – Without any increasing in flow rate in, increase in return flow indicates something coming into wellbore while drilling. Therefore, flow show instrument provided by the rigs or service companies must be checked and calibrated frequently. Increase of active pit system (Pit gain) - Because drilling fluid system on the rig is a closed system, increasing in flow show without adjusting flow rate in will cause pit gain in a pit system. Nowadays, with high technology sensors, detecting change in pit level is easily accomplished at the rig site. However, visually check the pit level is importance as well for double checking figure from the sensors. Sometimes, change in pit level may be detected after the increase in flow show because it takes more time to accumulate volume enough to be able to detect by pit sensors. Continue flowing while the pumps are off – When pumps are turned off, bottom hole pressure will decrease due to loss of equivalent circulating density (ECD). If there is any flow coming after pumps off, it indicates formation influx into wellbore. 31
Positive Kick Indicators While Tripping Trip log deviation such as short fill up while tripping out and excess pit gain while tripping in. For tripping operation, it is very important to have a filling system via trip tank that provides continuous hole fill all time. With utilizing that system, we can compare fluid that is filled in or returned from wellbore with steel volume of tubular (drill pipe, drill collar, BHA, tubing, casing, etc). If drilling fluid volume is less than theoretical pipe displacement while tripping out or more return fluid while running in, you need to flow check and monitor the well. • If flow check indicates wellbore influx, crew must quickly shut the well in. • If flow check does not show any influx, drill string must be run back to bottom in order to circulate at least bottom up to ensure hole condition. Positive flow when pipe is static. Every time that pipe in static condition. Trip tank with correct filling system must be monitored all time by both rig personnel and mud logger. If volume in trip tank increases, personnel must confirm flow check and prepare to shut the well in.
Drilled Gas While drilling, there will be a certain amount of the gas in cuttings entering into drilling fluid when we drill through porous formations that contain gas. The gas showing on the surface due to drilling through formations is called “Drilled Gas”. When gas from the cutting comes into drilling fluid, it will expand as it is circulated out of hole, hence, you will see the gas from the monitors at the flow line. Even though we have overbalance hydrostatic pressure exerted by mud column, gas showing on the surface by this mechanism always happens. You cannot rise mud weight up to make it disappear. Drilled gas should be recorded in mud log chart against formation identification. In addition, the gas unit should represent changes in drilling rate (rate of penetration) through porous formation. Practically, if we see a lot of drilling gas, we should stop drilling and attempt to circulate gas until it reaches to an acceptable level prior to drilling ahead.
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DAY-1 --------------- Session - IV Positive kick signs Positive well control (wellbore influx) indications mean indications showing almost 100% kick (wellbore influx) into wellbore. We can classify the positive indicators the following categories. Positive Well Control Indicators While drilling Increase in flow show – Without any increasing in flow rate in, increase in return flow indicates something coming into wellbore while drilling. Therefore, flow show instrument provided by the rigs or service companies must be checked and calibrated frequently. Increase of active pit system (Pit gain) - Because drilling fluid system on the rig is a closed system, increasing in flow show without adjusting flow rate in will cause pit gain in a pit system. Nowadays, with high technology sensors, detecting change in pit level is easily accomplished at the rig site. However, visually check the pit level is importance as well for double checking figure from the sensors. Sometimes, change in pit level may be detected after the increase in flow show because it takes more time to accumulate volume enough to be able to detect by pit sensors. Continue flowing while the pumps are off – When pumps are turned off, bottom hole pressure will decrease due to loss of equivalent circulating density (ECD). If there is any flow coming after pumps off, it indicates formation influx into wellbore. Positive Kick Indicators While Tripping Trip log deviation such as short fill up while tripping out and excess pit gain while tripping in. For tripping operation, it is very important to have a filling system via trip tank that provides continuous hole fill all time. With utilizing that system, we can compare fluid that is filled in or returned from wellbore with steel volume of tubular (drill pipe, drill collar, BHA, tubing, casing, etc). If drilling fluid volume is less than theoretical pipe displacement while tripping out or more return fluid while running in, you need to flow check and monitor the well. • If flow check indicates wellbore influx, crew must quickly shut the well in. • If flow check does not show any influx, drill string must be run back to bottom in order to circulate at least bottom up to ensure hole condition. Positive flow when pipe is static. Every time that pipe in static condition. Trip tank with correct filling system must be monitored all time by both rig personnel and mud logger. If volume in trip tank increases, personnel must confirm flow check and prepare to shut the well in.
Shut in procedures For the drilling industry especially when we talk about well control, there are 2 types of shut in which are Hard Shut-in and Soft Shut-in. Hard shut in: It means that while drilling choke line valves (HCR) are in the closed position; it will be opened after the well is shut in. The hard shut-in is the fastest method to shut in the well; therefore, it will minimize volume of kick allowed into wellbore. 33
Soft Shut In: It means that while drilling, the choke line valves (HCR) are in the opened position. When the well control situation is occurred, you shut in BOP and then close choke valves to shut in the well. The soft shut in procedure allows fluid to flow through the surface choke line before the well will be completely shut in. This is the bad part of the soft shut in procedure because it doesn’t minimize the size of the wellbore influx. The shut in procedure is the company specific procedure. You need to follow your company policy to shut in the well. Anyway, I personally recommend “HARD SHUT IN PROCEDURE” because it allows me to shut well in as quickly as possible and kick volume entering into a well bore will be minimized. Please also remember that less volume of kick you have in the well bore, the less problem you will see when you attempt to kill the well.
Shut in pressure interpretation The equilibrated reservoir pressure measured when all the gas or oil outflow has been shut off.
Shut in drill pipe pressure Pressure of the drilling fluid on the inside of the drill stem. It is used to measure the difference between hydrostatic pressure and formation pressure when a well is shut in after a kick and the mud pump is off and to calculate the required mud-weight increase to kill the well. 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 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)
Maximum Initial Shut-In Casing Pressure (MISICP) Maximum Initial Shut-In Casing Pressure (MISICP) or Maximum allowable shut in casing pressure is the initial shut-in casing pressure that will exceed formation strength at the casing shoe resulting in broken formation at the shoe. 34
How can we know and calculate the MISICP? Leak off Test (LOT) will tell you the maximum pressure which the shoe can withstand before breaking formation at the shoe. The LOT is the combination of surface pressure and hydrostatic pressure therefore you can apply this principle to calculate the MISICP. The MISICP formula is listed below: MISICP, psi = (LOT, ppg – Current Mud Weight, ppg) x 0.052 x TVD of shoe, ft Please see the example demonstrating how to calculate the MISCIP by using the following information: LOT = 15.0 ppg Current mud weight = 10.0 ppg Casing shoe depth = 4526’MD/4200’TVD MISICP, psi = (15 – 10) x 0.052 x 4200 MISICP = 1,092 psi
Adjusted maximum allowable shut-in casing pressure You calculate the maximum initial shut-in casing pressure (MISICP) based on the original mud weight before you start drilling ahead. Once you drill deeper, you may increase mud weight. With new mud weight, you are not able to use the MASICP calculated by the initial weight because higher mud weight will reduce the MASCIP. The formula below demonstrates you how to adjust the MASICP with new mud weight. Adjusted MASICP = Leak off pressure – [Shoe TVD x (MW2 – MW1)] x 0.052 Where; Adjusted MASCIP = maximum allowable shut-in casing pressure in psi Leak off pressure = pressure you get when you perform leak off test in psi Shoe TVD = true vertical depth of casing shoe in ft MW2 = current mud weight in ppg MW1 = original mud weight in ppg Let’s learn about it via this example. Casing shoe depth is at 5000’MD/4500’TVD. Leak off test is performed with 9.5 ppg and the leak off pressure is 1000 psi. The current operation is drilling ahead with 12.0 ppg. Determine the adjusted MASCIP with current mud weight. Adjusted MASICP = 1000 – [4500 x (12.0 – 9.5)] x 0.052 Adjusted MASICP = 415 psi
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If you take a kick with 12.0 ppg mud in hole, you maximum allowable surface casing pressure is only 415 psi.
Bringing the pump to kill speed 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. 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. To maintain bottom hole pressure during kill operation, two methods exist. First, by reducing choke manifold pressure by an amount equal to a known CLFL (adjusting choke manifold pressure to SICP -CLFL), the effect of the CLFL is negated. This is accomplished by reducing the original SICP by the amount of CLFL while bringing the pumps to speed. Once kill rate pressure has been established, the choke operator switches over to the drill pipe gauge and follows the drill pipe pressure graph in the usual way.
Fig-1
Fig-2
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(Fig-1 description) PUMP AT KILL RATE WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase Or secondly, given a choke manifold configuration with separate pressure gauges for choke and kill lines, it is possible to utilize the kill line (shut off down-stream of the gauge outlet to prevent flow, thus eliminating friction) as a pressure connection to a point upstream of any potential CLFL (known or unknown). If the kill line gauge in this instance is kept constant while bringing the pump to speed, the effect of CLFL is eliminated. Note the advantages of the second method: 1. The gauge reading choke manifold pressure will show a decrease after pump is up to speed. The amount of this decrease is equal to the CLFL. 2. No pre-calculated or pre-measured CLFL information is required. 3. The kill line gauge can be subsequently used like the choke manifold pressure gauge on a surface stack for the purposes of altering pump rates or problem analysis. (Fig-2 description)PUMP AT KILL RATE HOLDING CONSTANT KILL LINE PRESSURE READING CHANGE IN BHP = 0 psi increase The pressure provided by the rig pump is the sum of all of the individual pressures in the circulating systems. All the pressure produced by the pump is expended in this process, overcoming friction losses between the mud and whatever it is in contact with: • Pressure loss in surface lines • Pressure loss in drill-string • Pressure loss across but jets • Pressure loss in annulus Pressure losses are independent of hydrostatic and imposed pressures. Pressure losses in the annulus acts as a “back pressure” on the exposed formations, consequently the total pressure at the bottom of the annulus is higher with the pump on than with the pump off. Circulating bottom hole pressure = Static bottom hole pressure + Annulus pressure losses The total pressure on bottom can be calculated and converted to an equivalent static mud weight which exerts the same pressure. Equivalent Mud Wt (ppg) = (APL + Pmuda) ÷ 0.052 ÷ TVD Equivalent Mud Wt E.C.D = Mud Wt in use + APL/(0.052 X TVD) APL = Annulus Pressure Loss Pmuda = Hydrostatic Mud Pressure in Annulus Circulating pressure will be affected if the pump rate or the properties of the fluid being circulated are changed.
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OR
Circulating Rig Pump Pressure
Type of influx You can use influx height to estimate type of influx. The following equation is used for estimating type of influx:
Note: You can prove the equation by using the U-tube concept. Influx weight in ppg
Current mud weight in ppg
SICP stands for Shut in Casing Pressure in psi.
Influx height in ft
SIDPP stands for Shut in Drill Pipe Pressure in psi. Once you know weight of influx, you can compare with these figures below to determine type of influx. 1 – 3 ppg most likely gas influx. 3 – 7 ppg most likely oil kick or combination between gas and oil kick 7 – 9 ppg most likely water influx
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With these given information, please determine type of influx. Shut in casing pressure = 1050 psi Shut in drill pipe pressure = 750 psi Height of influx = 450 ft Current Mud Weight = 14.0 ppg
Influx weight = 1.2 ppg According to the criteria above, the influx is most likely gas kick.
U-Tube Concept and Importance of U-Tube We can likely use the behavior of one of the fluid columns to describe behavior regarding what is happening in another side of fluid column, if two fluid columns are connected at bottom. Basically, this situation is simply described in common oil filed name as “U Tube”. In oil field especially drilling business, “U Tube” can be considered as a string of pipe (drill pipe and tubing) is in a wellbore and fluids are able to pass inside of string of pipe (drill pipe and tubing) and the annulus (area between wellbore and string of pipe). The figure below demonstrates “U Tube” in our drilling business.(Fig-1 description)
Fig-1
Fig-2
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Why is U-Tube very important? It is very vital to keep a basic concept of U-Tube in mind. If there are two different fluids between inside of string and annulus, fluids always flow from a higher pressure area to a lower pressure. If the system is NOT closed, lighter fluid will be flown out and it will be stopped when system pressure is stabilized (see figure Fig-2). If the system is closed, pressure must be the same at the bottom point where both sides of Utube are connected. Therefore, drill pipe pressure and casing pressure (annulus pressure) will be responded based on fluid in each side and formation pressure at bottom hole (see figure below).
Please always remember that U-Tube concept can be widely applied in many drilling and workover application such as well control, cementing, etc.
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