Trip tank is a small tank which has a capacity of 20 – 50 bbl and its shape is tall and shallow because it can effectively detect volume changes. The trip tank system has the ability to continuously fill the well and take return back to the tank. With this capability, it will keep the hole full all the time and the volume changes either increasing or decreasing can tell the condition of the well.

The diagram (Figure 1) below demonstrates how the trip tank is lined up.

Figure 1 – Trip Tank Line Up To Continuously Fill The Hole

Each trip tank has a pump which will suck the fluid from the tank and pump into the well via the fill up line connected to a bell nipple under the rig floor. The fluid return will flow back via a return line and back to the trip tank. The float in the trip tank is connected to the wire and the position of the float will represent the trip tank volume indicator. What’s more, nowadays several rigs have installed the electronic instrumentation for the accurate volume measurement. This will help personnel on the rig track what is going on the well very quickly and accurately. As you can see, the complete system allows personnel to monitor the well.

 
The trip tank must be maintained in order to avoid solid build up, pump and valve failure, leakage, etc. Moreover, it is very critical to frequently check the float and the electronic instrument to see if they are in good condition.

 
Stripping operation requires a separate trip tank which has very small capacity of 3 to 4 bbl therefore it is not recommended to use the normal trip tank for this operation. The small volume tank, called “strip tank”, has more accuracy and suite for the operation.

How The Trip Tank Monitor The Well For Well Control

Trip Out of Hole

While pulling out of hole, each stand of drillstring pulled out must have the same amount of drilling fluid to replace the drillstring volume. For instant, each stand should take around 0.8 bbl. If you pull 10 stands out of hole, you should see at least 8 bbl of mud volume decrease in the trip tank. If you see the volume displacement less than what it should be, it indicates that the well is swabbed in.

Figure 2 - Trip Tank While Tripping Out

Trip In Hole

While tripping in hole, mud will be pushed out of the well to the trip tank because steel displacement will replace the drilling fluid in the well. The volume displacement should be the same as the steel displacement. If the volume displacement is more than the steel displacement, the well may has some unwanted kick in the well.

Figure 3 - Trip Tank While Tripping In

Flow Check

While flow checking, the volume in the trip tank should be at the same level. There should not be any changes. Increasing volume in the trip tank means the well is flowing. Conversely, if the volume decreases, the well has static loss.

Figure 4 – Trip Tank While Flow Checking

Reference books: Well Control Books

Choke line friction (CLF) is the frictional pressure which is generated while circulating mud through choke or kill line. For surface stack, the choke line friction is negligible because the choke line is short therefore the friction pressure is so small. However, the choke line friction in deepwater operation has a big effect bottom hole pressure. Killing the well without considering the CLF will add excessive pressure and it increases the chance of fracturing formation at casing shoe or anywhere in the well.

Figure 1 is a simple diagram showing the direction of CLF while a normal circulation is performed. The choke line friction will be in the opposite direction of flow which is downwards to the wellbore. This additional friction will increase the bottom hole pressure.

Figure 1 – Direction of Choke Line Friction Pressure

Example: Water depth = 5,000 ft

Shoe depth = 15,000 ft TVD

Hole depth = 25,000 ft TVD

Casing pressure = 300 psi

Current mud weight = 12.0 ppg

Choke line friction pressure @ 25 spm = 400 psi

Neglect annular pressure loss in the well due to low flow rate

Figure 2 - Example of CLF

What is the shoe pressure if we bring pump up to speed without considering CLF?

Figure 2 is the diagram based on the question and you need to add the CLF and casing pressure. Bottom hole pressure at the shoe is calculated by the following equation;

BHP @ shoe = MW + (Casing Pressure + Choke Line Friction) ÷ 0.052 ÷ Shoe TVD

BHP @ shoe = 12.0 + (300 + 400) ÷ 0.052 ÷ 15,000 = 12.9 ppg

Without compensating the CLF, the bottom hole pressure will increase by 0.9 pgg which can possibly break down the shoe.

In order to maintain constant bottom hole pressure, the casing pressure must be compensated by CLF. In the next topic, we will discuss how to measure CLF and maintain the bottom hole pressure while bring the pump up to speed.

Reference books: Well Control Books

You need to watch the VDO below. It demonstrated the situation before the blowout was occurred.

These are some possible root causes which contributes to this situation.

• Improper hole fill
• Lack of properly tracking the trip sheet
• Incompetent crew
• Full Openning Safety Valve and IBOP were not properly prepared to stab in. The crew were looking at them when they found out that the flow was coming up from the drillstring.
• No float valve in the drillstring
• Take to long to shut the well in. You can see only 4 minutes before the massive blowout was blowing on the rig floor.
• Lack of well control knowledge and training
• Possible to swab the well in
• What do you think about this well control situation?

Is this preventable?

Please feel free to leave us some comments below.  Additionally, you can learn a lot of well control knowledge from our website – Well Control

Choke Line Friction is one of critical figures that personnel on the rig need to know and this numbers can be determined.

The procedures for the choke line friction determination are as follows;

1. Line up to circulate into choke line

Figure 1 - Line Up

2. Circulate down the choke line and up into riser. This will not add significant pressure to bottom hole. When you measure the pressure you need to know mud density and rheology and it is very important that you wait until you get the stabilized pressure reading.

Figure 2 – Circulate down choke line

3. Record CLF at expected kill rates for well control as 10 SPM, 20 SPM, 30 SPM, etc. This will give you an idea how much CLF at particular flow rate. The table below demonstrates the pre-recorded CLF
Flow Rate (SPM) Choke Line Pressure (psi) Mud Weight (ppg)

Table 1 Pre Recorded CLF

This procedure can be performed any time while drilling and we recommend you to check the CLF when drilling fluid properties have been changed a lot from the previous test. Additionally, you can use the same procedure to measure the frictional pressure at the kill line too.

Reference books: Well Control Books

Choke line friction pressure will increase bottom hole pressure while circulating to kill the well therefore it must be compensated in order to maintain the bottom hole pressure relatively constant. This section will describe how to compensate the choke line friction while bring pump up to speed.

Compensate The Choke Line Friction By Using Casing Pressure Gauge

 At static condition – the bottom hole pressure can be described like this

Bottom Hole Pressure = Hydrostatic Pressure in Annulus + Casing Pressure

Figure 1 – Bottom hole pressure at static condition

At dynamic condition – the bottom hole pressure can be described like this

Bottom Hole Pressure = Hydrostatic Pressure in Annulus + Casing Pressure + Choke Line Friction + Annular Pressure Loss

We will use acronym like this to make it easy.

BHP = HP annulus + CP + CLF + P loss annulus

Since the pumping rate while performing well control operation is not high therefore the pressure loss in the annulus is negligible.

BHP = HP annulus + CP + CLF + P loss annulus

While circulating, CLF will increase therefore CP must be intentionally decreased at the same amount of CLF in order to keep the bottom hole pressure relatively constant.

BHP = HP annulus + ↓CP + ↑CLF

Figure 2 – Bottom Hole Pressure at Dynamic Condition

Let’s look into this example for more understanding. The well is shut in with 500 psi shut in casing pressure and 300 psi shut in drill pipe pressure. The plan is to circulate using 30 SPM.

The table below is the pre-determined CLF.

If we select 30 SPM as a kill rate, you will get 450 psi CLF therefore you need to reduce casing pressure by 450 psi to maintain the bottom hole pressure (see Figure 3).  The casing pressure after the kill rate is fully established will be equal to initial shut in casing pressure minus CLF which is 50 psi.

Figure 3 - Compensate CLF by Reducing CSG pressure

Figure 4 shows simple charts representing the compensated casing pressure while bringing the pump up to kill rate at 30 SPM.

Figure 4 - Chart Showing SPM and Casing Pressure (CP)

Compensate The Choke Line Friction By Kill Line Pressure

This is another way to start circulation with constant bottom hole pressure by using kill line pressure gauge.  Firstly, the circulation path is lined up to the choke line up to surface and the valves in the kill line must be opened just for reading the kill line pressure. Kill line will not be used as a circulation path. At this point, choke and kill like can read pressure separately.

Secondly, the circulation is brought up to kill rate by holding kill line pressure constant. The benefit of using the kill line pressure is that there is no friction pressure at the kill line side because no fluid is circulated through the kill line.  With the maintained kill line pressure, choke pressure will decrease by the amount of CLF at a particular flow rate. The static kill line pressure will maintain the bottom constant bottom hole pressure, like casing pressure gauge on a surface BOP well control. Figure 5 demonstrates the line up and the circulation path.

Figure 5 – Compensate CLF by Using Kill Line Pressure Gauge

For some advanced subsea BOP’s, they are equipped with BOP gauges. The BOP pressure gauge can be used to maintain the bottom hole pressure constant, like the kill line pressure gauge. The process is the same as the procedure when you use kill line pressure gauge but only you monitor the BOP pressure gauge. Figure 6 shows the configuration of CLF compensation using the BOP gauge.

Figure 6 – Compensate CLF by Subsea BOP Pressure Gauge

Reference books: Well Control Books

Choke Line Friction pressure (CLF) has directly affect on the bottom hole pressure while performing well kill operation in a deepwater operation. You may be able to circulate the kick out of the well without breaking the shoe down with the current mud weight however; the well can be fractured when the kill weight mud reaches the surface due to excessive CLF.

How Kill Weight Mud and CLF Will Break the Shoe

When the kill mud is circulated from the bit to surface as per the second circulation of driller’s method, drill pipe pressure is held constant and the choke is gradually opened. Once the choke is in the fully open position, the back pressure due to choking back the well is gone but the CLF is still there. With the heavier weight, the CLF with KWM will be more than the CLF with the original mud. If the hydrostatic pressure is more than the fracture pressure, the formation will be broken down.  Let’s take a look at the following calculation to get clearer picture of this topic.

Example: The well information is listed below;

• Water depth = 5,000 ft
• Shoe depth = 15,000 ft TVD
• Hole depth = 25,000 ft TVD
• Kill mud weight = 12.5 ppg
• Choke line friction pressure @ 25 spm = 500 psi with 12.5 ppg
• Shoe fracture pressure = 13.0 ppg
• Neglect annular pressure loss in the well due to low flow rate

Casing pressure is 0 psi due to fully opened choke,  the shoe pressure be determined by the following calculation process.

Figure 1 - Shoe Pressure with Original Mud Weight

BHP @ shoe = MW + ((Casing Pressure + Choke Line Friction) ÷ 0.052 ÷ Shoe TVD)

BHP @ shoe = 12.5 + ((0+500) ÷ 0.052 ÷ 15,000) = 13.2 ppg (round up figure)

Figure 2 – Shoe is fractured due to Choke Line Friction

Without any surface casing pressure (Figure 2), the bottom hole pressure (13.2 ppg) is still exceed the shoe fracture gradient (13.0 ppg). Therefore, the formation will be broken.  As you can see from the example, the excessive CLF while kill weight mud is coming out to surface can fracture the formation.

How To Prevent the Effect of Choke Line Friction Pressure

There are few ways to prevent this issue as listed below;

• Use the large choke diameter as much as possible – This should be done at the rig selection stage. It will cost additional cost if you want the existing choke line to be upgraded.
• Reduce kill rate – Reduce flow rate will cut down choke line friction due to square relationship. However, the circulating time will increase.
• Circulate both choke line and kill line at the same time – The flow will distribute to both choke and kill line; therefore, this option will still maintain the same flow rate but the frictional pressure is reduced by approximately 75% due to square relationship. There are few disadvantages too. The first one is that without BOP sensor, you need to back off the friction pressure manually and you need to know the frictional pressure by circulating through choke and kill line together. You also have the potential to loss of redundancy if both lines are plugged off.

Reference books: Well Control Books

Formation pressure is important information for well planning and operation because it impacts on several things as well control, casing design, drilling fluid program, pore pressure prediction, etc.  We will discuss about formation pressure in a basic term for drilling personnel.

During an era of sedimentation and erosion, little grains of sediment are constantly building above each other, usually in an environment of full irrigation. As the sediment thickness of the base layer increases, the sediment grains are packed strongly near to each other, and some water is excluded from the small pore spaces. Though, if the pore spaces through the deposit sediments are connected to the top pressure surface, the fluid at any depth in the sediment will be same as that which would be found in a simple column of fluid.

The pressure of fluid in sediment pores would only be reliant on the fluid density in pore space and depth of the pressure measurement (equal to the elevation of the column of liquid). It will also be independent of size of the pore or throat geometry. The pressure of the fluid in the pore space (the pore pressure) can be measured and plotted against depth as shown in Figure 1.

Figure 1 – Pressure Vs Depth Plot

The pressure in the formations to be drilled is often expressed in terms of a pressure gradient as psi/ft. This gradient is consequential from a line passing all through an exacting arrangement of pore pressure and a datum point at surface and is namely the pore pressure gradient (Figure 2).

Figure 2 - Pressure Gradient

When pore throats interconnected through sediment, the fluid pressure at any depth in sediment will be identical of that would be established in a simple column of fluid and consequently the pore pressure gradient is a straight line as illustrated in Figure 1. The tangent of the line is pressure gradient shown in Figure 2.

Representing pore pressure in pressure gradient unit is quite convenient for calculation and easy to present to everybody. If drilling mud density is presented in the same pressure gradient unit, at each depth of interest, you can compare pressure in order to ensure that the well is still in over balance condition. The Figure 3 is a chart showing the pore pressure gradient and mud gradient. The degree of difference between the pore pressure and the mud pressure at any particular depth is overbalance pressure at.

Figure 3 – Overbalance Based on Pressure Plot

Within the pore space of sedimentary formations contain most of the fluids with proportions of salt and known as brines. The dissolved salt matter can vary from 0 – (over) 200,000 ppm. Likewise, pore pressure gradient vary from 0.433 psi/ft (fresh water) to around 0.50 psi/ft. Pore pressure in most geographical areas, the gradient is roughly 0.465 psi/ft with assumption of 80,000 ppm salt concentration. This figure is defined as the normal pressure gradient.

Any pressure formation deviates from the normal pressure gradient is named ‘Abnormal pressures’. The abnormal pressure affects both engineering and operation of drilling. There are several reasons why the abnormal pressure zones are occurred and we will discuss it later on.

Reference books: Well Control Books

During a drill well on paper phase, wells might be planned based on available data from offset wells or nearby areas. This information may deviate from the actual drilling phase due to several reasons therefore it is very critical to have good monitoring and evaluating pore pressure while drilling. The actual pore pressure will dictate where to set the casing, how much the actual mud weight should be, what potential problems are, etc.

The actual reservoir pressure obtained while drilling will be used to determine right mud density in order to ensure an adequate primary well control. Besides the well control, the proper mud weight can help us in several aspects such as minimizing lost circulation and pipe sticking and maximizing a rate of penetration. You can achieve the trouble free drilling operation.

The following indicators can demonstrate abnormally pressured reservoirs;

• Higher porosity
• Higher permeability
• Higher sonic velocity
• Lower shale density and resistivity
• Lower water salinity in formation

The concept of evaluating pore pressure while drilling is to measure the changes in these properties which vary with different lithology and area of drilling. You need to take into account about the lithological variation when interpreting data. Moreover, measuring of these parameters can be used to quantitatively estimate. It will give you the relative information when compared to the overall trend.

Let’s take a look at shale density as an example. The shale density is typically denser over depth; however, a high pressure zone tends to have higher porosity and lower bulk density because the reservoir pressure inside will push the rock grains. While drilling, the shale density should be plotted against the depth because you can see the normal trend. When you see decrease in the shale density trend, it shows you that the abnormally pressured zone is there (see Figure 1).

Figure 1 – Shale Density Plot

Nowadays, Logging While Drilling (LWD) tools are widely used because they can measure reservoir data and send to the surface real time. This will help us closely and accurately monitor the well to see any changes in the parameters. These tools can assist you to make adjustment in mud weight while drilling effectively. If you want precise reservoir pressure, some service companies can provide formation tester service while drilling. It might take time but you will know exactly where you are and how accurate of the pore pressure curve.

Surface real time logging is another way to evaluate the pore pressure and there are some mud logging companies also provides pore pressure analysis. These following changes can be a possible high pressure zone;

• Abnormal change in ROP
• Increase in return line temperature
• Increase in drilling drag and torque
• Increase in cutting size and shape
• Increase in trip, connection and/or background gas
• Decrease in d-Exponent

Conclusion: Monitoring and evaluating the formation pore pressure is the key to achieve drilling free operation especially in unknown areas where you have the limited information. With real time data monitoring both downhole and surface, you can detect changes very quickly and the right decision regarding the mud weight can be made on time. Always listen to the well and you will be fine.

Reference books: Well Control Books

Well control with pipe off the bottom is one of the most serious well control situations because kick below a drillstring can create very complicated situations when compared to a normal well control. This article will teach you about the basic well control when the pipe off bottom.

There are several well control techniques to manage when the kick comes into the well and it is below the pipe;

• Use the Volumetric technique. The volumetric well control to let the gas migrate to surface with the bottom hole pressure nearly constant. This option is applicable when the influx is gas.
• Strip the drillstring back to the bottom. This is applicable with non-migration kicks as water and oil.
• Strip the drillstring utilizing the volumetric well control. This method can be used when you have a gas influx.
• Snub (push) the pipe against the wellbore pressure down to the bottom
• Kill the well off bottom using conventional well control methods as driller’s method and wait and weight. Typically, this is not recommended to use because you won’t get the kick out of the well and you may not be able to determine the kill weight mud correctly.

Since the pipe is off bottom and it is very critical to go back to the bottom to kill the well with the normal well control methods; therefore, there are two special techniques to trip the drillstring back to the bottom which are stripping and snubbing.

Figure 1 - Kick Off Bottom

Snubbing – it is when you push the string through the BOP because the weight of the drillstring is less than the upward force created by wellbore pressure. Typically, the snubbing operation cannot be performed with a normal rig set up. It is required several specialized tools which you don’t normally have on the rig. This operation is normally performed by hydraulic workover units.

Stripping – it is when you trip the string through the BOP, typically annular preventer, when the string weight is more than the upward force pushing up from the well.

The kick is below the bit and this can result in same reading on both drill pipe pressure and casing pressure. You don’t know the correct pressure to determine kill weight fluid because both sides don’t have one single fluid column.

Figure 2 - Same Reading on Both Casing and Drillpipe Pressure

The kick type must be identified in order to determine if the volumetric well control will be applied during the stripping operation. By observing surface pressures, if there is increase in surface pressure, it will most likely be gas influx. On other hands, if there is no change, it is a high possibility to be fluid kick. If you take a gas influx, the volumetric control must be considered for stripping operation.

Stripping drillpipe into the well is required to have an inside blow out preventor in the drillstring. The IBOP will prevent the flow to come up and the forward circulation can be performed. It is very critical that the IBOP is in a good condition prior to using it.

For stripping operation, there are two techniques which are annular stripping and ram combination stripping. The annular stripping is quite simple way to strip into the well but the ram combination is quite complicated and you may have more chance to damage the BOP components. If you have a choice for this kind of operation, we would like to recommend you to use the annular stripping technique.

Before the annular stripping operation, it is recommend reducing the annular operating pressure to allow the drill string to be stripped easily and the annular element does not face excessive pressure when the tool joints are pushed through it. Additionally, it might be helpful to have a surge dampener in the closing line in order to maintain constant closing pressure while the tool joints are being stripped through.

Surface pressure is another factor that can limit the annular stripping. Operating life of the annular element will drastically reduce because of high surface pressure. If the well is shut in with high surface pressure, you are required to reduce surface pressure prior to stripping. There are some options to get the surface pressure down as listed below;

• Bullhead with heavier mud
• Lubricate and bleed if the influx is on surface
• Circulate an influx out if you know that the influx is above the bit

For the next topic, we will discuss into some details of this well control method, the related calculations and procedure.

Reference books: Well Control Books

Shallow gas is one of the most dangerous incidents in well control because you don’t have the BOP set to be able to control the well. Additionally, shallow gas always happens at the shallow depth as surface hole section where you will have a difficulty to control the well. This footage below show you how serious of the shallow gas in an offshore environment.

Sedco 700 Shallow Gas Blow Out 6 June 2009

Additional details about shallow hazards that you need to know.

The shallow hazard is a formation that has the possibility to flow to surface without BOP set to control the well. It can be both water and gas kick and it can be happened at any locations as land drilling, shallow offshore environment and floating operations.

Water Flow as Shallow Hazard

The water shallow hazard is caused by natural or induced overpressure zone(s). Artesian flow, for example, is an overlaying of water sand at a higher elevation which creates a hydrostatic pressure into the lower elevation. What’s more, in the brown fields where water injections are utilized to enhance the production will have higher possibility to have the shallow water kick more than the green fields. In offshore environment, you may see this issue between 200 to 2000 ft below mud line.

Shallow Gas Hazard

The shallow gas is an unexpected gas bearing zone encountered before the rig can set the BOP. It can be extremely prolific like the footage showed before.  It is relatively uncommon occurrence in the land drilling operation because at the top section, the formations are more consolidated with less permeability. The land operation will have less possibility to see the shallow gas than the offshore environment.  The offshore environment will have higher chance to encounter the shallow gas because the shallow section deposits reef and vuggy limestone that can contain gas.

Height of influx will increase when the drillstring penetrates a kick; therefore, hydrostatic pressure decreases and casing pressure increases in order to compensate this situation.

If the casing is maintained constant while penetrating the kick, you will have high chance to take more influx because of underbalance situation (Figure 1). This article will teach you about how to determine pressure increment while penetrating into the kick, what to look for, etc.

Figure 1 – Height of Influx increases when the drillstring penetrates into it.

However, if the constant surface pressure is utilized for the stripping operation, you must account for pressure increment due to height of influx change. The equation below is for calculating the increase in casing pressure.

∆CP = ∆H x (MG – KG)

Where: ∆CP = Increase in casing pressure, psi

∆H = Change in length of influx, ft

MG = Mud Gradient, psi/ft

KG = Kick Gradient, psi/ft

The example below demonstrates how to calculate casing pressure increase.

Hole TD = 12,000’MD/12,000’TVD

Hole size =11.75”

Drill pipe = 5”

Drill collar = 6.5”

Drill collar length = 800 ft

Pit gain = 35 bbl

Mud weight = 12.0 ppg

Kick gradient = 0.3 psi/ft

Figure 2 – Calculation Example for This Situation

Hole capacity = 11.75² ÷ 1029.4 = 0.134 bbl/ft

Kick Height in open hole =35 ÷ 0.134 = 261 ft

Hole and 6.5” drill collar capacity = (11.75² -6.5²) ÷ 1029.4 = 0.0931 bbl/ft

Kick Height in annulus between hole and DC = 35 ÷ 0.0931 = 376 ft

Mud gradient = 12.0 x 0.052 = 0.624 psi/ft

Kick gradient = 0.3 psi/ft

∆CP = ∆H x (MG – IG)

∆CP = (376 – 261) x (0.624 – 0.3)

∆CP = 37 psi

Figure 3 – Casing Pressure Increase Due To Kick Penetration

The increase in casing pressure required for this scenario is 37 psi. This figure tells you that you need to let casing pressure increase by 37 psi in order to compensate to hydrostatic loss.

Practically, you should have the safety factor which is greater than casing pressure increase required for kick penetration and for this case, the safety factor must be more than 37 psi. This will prevent the underbalance situation when the influx is penetrated and you don’t need to worry about the time when the influx penetration will actually happens.

For gas kick, it is impossible to use either the constant pressure method or the volume accounting method because gas will migrate. You must have the method to control the bottom hole pressure and deal with increase in surface pressure due to gas migration. For gas kick, the volumetric control stripping technique must be used. This technique will account for volume of pipe bled back and surface pressure increase. We will discuss this technique separately in a next topic.

Reference books: Well Control Books

In the previous articles, we discuss about the stripping operation and techniques with non-migratable kicks as oil and water kick. This article will focus on the stripping operation with gas influx and we are going to describe some additional considerations that you need to account for. Gas kick is different from the liquid kicks because gas can naturally migrate. The gas migration affects the stripping operation because increase in casing pressure due to gas migration must be taken into considerations.

Gas migration can increase both surface and bottom hole pressure. If pressure increased by gas migration is not handled properly, the well can be fractured and it results in bad complications while performing well control operation.

Figure 1 - Gas Migration Increases Wellbore Pressure

We will need to apply volumetric well control into the stripping operation so the procedure is called “Stripping with Volumetric Control”. This procedure will account for both pressure increased by gas migration and pipe displacement.

There are 3 figures that you need to determine before starting the operation;

Safety Factor – It is the small overbalance pressure to prevent you to be accidentally in underbalanced condition.

Pressure Increment – It is a pressure change for each step for bleeding off.

Mud Increment – It is the mud volume equivalent to Pressure Increment.

We will go through into detailed of the stripping with volumetric control procedure in a next topic.

The critical part of this operation is when the drillstring penetrates into the gas kick because height of gas increased because the annular profile changes. The will result in reduction of hydrostatic pressure. The adjustment must be made in order to compensate for loss of hydrostatic pressure. Additionally, when the drillstring penetrates into the gas kick, a new mud increment, which is based on the calculation of annular volume between ID of casing or wellbore and OD of drillstring, must be used.

With gas in the wellbore, it is quite complicated for time estimation when the drill string will penetrate the gas kick because of gas migration. You must do two calculations in order to accurately estimate the time when the drill string will penetrate the gas kick.

The first step – This is to determine gas migration rate.

Gas migration rate (ft/hr) = ∆SICP ÷ (0.052 x MW x ∆T)

Where;

∆SICP = change in casing pressure, psi

MW = mud weight in hole, ppg

∆T = Time interval of casing pressure change, hr

The second step – The time can be calculated by using the following relationship:

T = (D_gas– D_bit) ÷ (GMR + SS)

Where;

T =Time to penetrate the gas kick, hrs

D_gas = Gas kick depth, ft

D_bit = Bit depth, ft

GMR = Gas migration rate, ft/hr

SS = Stripping speed, ft/fr

Warning - This calculation may not be accurate because the calculation above is based on the known location of gas kick and the gas bubble is all together in one gas kick. If the gas is swabbed, the location of gas kick is possibly at the bottom of the bit.  Gas migration rate may change due to wellbore temperature vs depth. For the practical stand point, you may need to add safety factor which will compensate the decrease in hydrostatic and you use the conservative fluid increment by using the capacity factor around the drillstring.

Please see the following example for the calculation.

Determine gas migration rate and time to penetrate the gas kick based on the following information.

• Shoe depth = 7,000’MD/6,000’TVD
• Hole depth = 10,000’MD/9,000’TVD
• MW = 12.0 ppg
• Bit depth = 7,500 ft
• 5” DP, 19.5 ppf
• 5” DC = 800 ft as BHA
• Pit gain = 35 bbl
• Hole size = 8.5 inch
• Casing ID = 8.835 inch
• SICP = SIDP = 250 psi
• Surface pressure increases to 500 psi in 30 minutes due to gas migration.
• Average stripping speed = 200 ft/hr

Figure 3 – Well Diagram for This Example

Solution

Determine gas migration rate (ft/hr)

Gas migration rate (ft/hr) = ∆SICP ÷ (0.052 x MW x ∆T)

Gas migration rate (ft/hr) = (500 – 250) ÷ (0.052 x 12 x 0.5)

Gas migration rate (ft/hr) = 801 ft/hr

Determine length of 35 bbl gas kick in 8.5” hole and top of gas kick

Length (ft) = Kick volume (bbl) ÷ Hole capacity (bbl/ft)

Hole capacity (bbl/ft) = 8.5² ÷ 1029.4 = 0.0702 bbl/ft

Length (ft) = 35 ÷ 0.0702 = 499 ft

It means that top of kick is about 499 ft from the bottom.

Top of gas kick = 10,000 – 499 = 9,501 ft

Determine time to penetrate kick

T = (D_gas– D_bit) ÷ (GMR + SS)

T = (9,501– 7,500) ÷ (801 + 200)

T = 2 hrs

Based on the given information, it will take a total of 2 hours to penetrate the gas kick.

Reference books: Well Control Books

This article will teach you about the stripping procedure for non-migrating kick. This procedure is used to strip to desired depth but it won’t account for volumetric bleed therefore it is mainly applicable for stripping with non-migrating kicks as water or oil.

The stripping procedures are as follows;

Figure 1 – Stripping to the bottom with non-migrating kick

1. Calculations

• Determine whether the drillstring weight is over the pressure force pushing upwards.
• Determine how many feet that you need to strip to penetrate the kick
• Determine pressure increase when the drillstring penetrate the kick. You can read more details about this topic here –xxxxx
• Determine safety factor. If you plan to use the constant surface pressure method for the stripping operation, the safety factor added into the system must be sufficient to compensate the effect of influx penetration.
• Determine volume bleed back per stand if you plan to use the volume accounting method.

2. Stab a safety valve (full opening safety valve) and follow by an IBOP valve.

Figure 2 - Stab a safety valve and IBOP

3. Ensure no leakage between connections.

4. Adjust the closing pressure to allow the stripping operation.

5. Strip the drillstring into the well until you get the desired safety factor. While stripping, small volume of fluid leakage around the pipe is a good sign because the closing pressure is not too much but the leak must stop when the stripping operation is stopped.

Figure 3 – Stripping with adjusted closing pressure

6. Strip to the required depth based on your selected method. You have a choice to use either the volume accounting or the constant surface pressure. You can read more details about these two methods from this article “Stripping Methods for Non Migration Kicks When There is an Off Bottom Well Control”.

Reference books: Well Control Books

With gas kick in the well, the conventional stripping method is not application because it won’t account for the gas migration and expansion; therefore, the special stripping procedure, Stripping with Volumetric Control, will be utilized for this case. This procedure is designed to strip the drill string back into the well with gas influx while the bottom hold pressure is maintained nearly constant.

 Figure 1 - Stripping With Volumetric Control

The Stripping with Volumetric Control procedures are as follows;

1. Calculations

• Determine whether the drillstring weight is over the pressure force pushing upwards
• Select required Pressure Increment (PI)
• Select Safety Factor (SF)
• Determine Mud Increment (MI)

Mud Increment (MI) is calculated by the following equation

Where;

MI = Mud Increment (MI), bbl

PI = Pressure Increment (PI), psi

ACF = annular capacity factor, bbl/ft

MW = mud weight, ppg

• Determine how many feet that you need to strip to penetrate the kick. This calculation must be account for gas migration and stripping speed. You can read more details here -
• Determine pressure increase when the drillstring penetrate the kick. You can read more details about this topic here –Kick Penetration For Stripping Operation

2. Stab a safety valve (full opening safety valve) and follow by an IBOP valve.

Figure 2 – Stab a safety valve and IBOP

3. Ensure no leakage between connections.

4. Adjust the closing pressure to allow the stripping operation.

5. Strip the drillstring into the well until the casing pressure increase by Safety Factor (SF) + Pressure Increment (PI). No bleeding off during the step#4.

6. Maintain constant casing pressure by bleeding off fluid while stripping until the difference between the drillstring displacement and the actual mud bled back equals to Mud Increment (MI).

7. Strip into the well without bleed off fluid until the casing pressure increases by Pressure Increment (PI).

8. Repeat step#6 and #7 until the drillstring penetrates the gas kick. Once the gas kick is penetrated, you need to allow casing pressure increased by pre-determined figure. This is will be your new casing pressure. Practically, you can add the pressure increase caused by the kick penetration into the safety factor and use the mud increment based on the volume between drillstring and the casing. This will be the conservative way which can prevent you to be in an underbalanced condition.

9. Strip into the desired depth by repeating step#6 and #7.

Reference books: Well Control Books

This section will discuss some practical stand points of the stripping operation with and without volumetric control. Additionally, this will summarize some key points for both methods of stripping for off bottom well control.

General Practical Considerations

Stripping operation requires accurate measurement of fluid bled off therefore it is very critical to have a small trip tank or a stripping tank for the operation. Furthermore, when the drillstring is stripped deeper, you might need to fill the pipe. You need to ensure that the volume filled up will not create any confusion with the bleed of volume. There are some cases when personnel don’t track the volume properly and finally the kick is unintentionally introduced into the wellbore.

Once you identify that you need to strip to the bottom, the stripping operation should be conducted as soon as possible. Gas kick at the deeper depth of the well will have a little expansion therefore you can minimize the expansion effect. In some cases, the drillstring can be successfully stripped back to the bottom before the first mud increment is reached. This will minimize the complication caused by the gas expansion.

Stripping Without Volumetric Control

Stripping to bottom using Non Volumetric Control is applicable for non-migrating influx such as oil and water kick and it has less complexity than the stripping with volumetric control. Since the kick does not migrate, there will be no increase in surface pressure and the concept of stripping is to control bottom hole pressure while a drillstring is stripped into a shut-in well. There are two methods that you can use as follows;

1. Volume accounting method – the concept of this method is to bleed of the fluid at the same volume as the drillstring displacement stripped into the well.
2. Constant casing pressure method – the concept of the method is to maintain casing pressure constant during the stripping operation but it requires pressure compensation when the drillstring penetrate the influx. Therefore, it is recommended that you add the safety factor that must be more than the pressure increase due to the kick penetration in order to control the bottom hole pressure. If the safety factor is added into the system properly at the beginning of the operation, the well will still be in an overbalanced condition after the string penetrates into the kick.

Stripping With Volumetric Control

Stripping with volumetric control is more complex than the first method because it deals with gas migration. What’s more, there are several small things that you need to consider such as changing in mud increment when the string penetrates the gas bubble, time to penetrate kick, etc. There are also several unknown values associated with the calculation so it makes the operation quite difficult.

In order to be more practical with this stripping method, you need to get rid of the time to penetrate to the bubble and there are two practical ways to do.

Safety Factor – The first way is to add the pressure increase due to kick penetration into the safety factor at the early step of the operation. The safety factor will prevent the additional kick when the gas kick in penetrated. You can estimate the required safety factor here –

Conservative mud increment – Mud Increment (MI) (MI) is calculated by the following equation

Where;

MI = Mud Increment (MI), bbl

PI = Pressure Increment (PI), psi

ACF = annular capacity factor, bbl/ft

Before you penetrate the kick (the influx is below the bit), ACF is calculated based on hole capacity but once the drillstring penetrates the kick, the ACF is  calculate based on the capacity between around the drillstring.

In order to make the MI more practical, it is recommended to determine the MI based on the ACF around the drillstring and use this one figure for entire operation. The MI will be less than the one that is calculated when the gas kick is below the bit therefore the wellbore will be slightly overbalanced.

Reference books: Well Control Books

This example demonstrates the calculations and the steps of the stripping with volumetric control so it will help you understand about what calculations required are and how to perform the stripping with volumetric control.

Gas kick at the bottom but the drillstring is out of bottom. The kick is introduced while pulling out of hole and the following information below is the well information.

• Pit gain = 30 bbl
• Shut in Drill Pipe Pressure = 400 psi
• Shut in Casing Pressure = 400 psi
• Current mud weight = 11.0 ppg
• Casing shoe depth = 6,000’MD/6,000’TVD
• Hole TD = 9,000’MD/9,000’TVD
• Hole size = 12.25”
• Casing ID = 12.5”
• Drill pipe size = 5”, 19 ppf
• BHA consists of 6.5” drill collar
• Length of BHA = 800 ft
• Average pipe per stand = 94 ft
• Rate of increase in casing pressure = 150 psi in 1 hour
• Assume gas density = 2 ppg ( 0.104 psi/ft)

Figure 1 – Well Diagram

The decision is made to strip to the bottom. Safety Factor and Pressure Increment are 100 psi.

Assumption: Gas kick at the bottom

Kick Height

Kick height = kick volume ÷ hole capacity

Hole capacity = 12.25² ÷ 1029.4 = 0.1458 bbl/ft

Kick height = 30 ÷ 0.1458 = 206 ft

The top of gas kick is at 8,974 ft (9,000 – 206) before it migrates.

Figure 2 – Top of Kick

Gas Migration Rate

Gas migration rate, fph = (Rate of increase in casing pressure, psi/hr) ÷ (0.052 x MW)

Gas migration rate, fph= 150 ÷ (0.052 x 11.0)

Gas migration rate = 262 fph

Figure 3 – Gas Migration

Mud Increment

Mud Increment (MI) is calculated by the following equation

Where;

MI = Mud Increment (MI), bbl

PI = Pressure Increment (PI), psi

ACF = annular capacity factor between casing and drillstring, bbl/ft

MW = mud weight, ppg

ACF = (12.5² – 5²) ÷ 1029.4 = 0.1275 bbl/ft

Mud Increment (MI) = 22.3 bbl

Metal Displacement per Stand

Metal Displacement (bbl) = (OD² x Average Length) ÷ 1029.4

Metal Displacement (bbl) = (5² x 94) ÷ 1029.4

Metal Displacement (bbl) = 2.3 bbl

Stripping with Volumetric Control Procedures

1. We determine the Safety Factor (SF), Pressure Increment (PI) and Mud Increment (MI) as per the calculated shown in the above section
2. Strip into the well until the casing pressure increase is equal to Safety Factor (SF) + Pressure Increment (PI) which is 200 psi. At this stage, the overbalance is 200 psi (100 + 100) and there is no bleeding back volume. From this example, we strip 2 stands to reach this point.

Figure 4 – Strip to get SF + MI

Figure 5 – Strip to get SF + MI Diagram

3. Hold casing pressure constant and bleed off fluid volume while stripping in hole. For this step, we need track the actual volume bled back which is equal to volume bled off minus pipe displacement.

Figure 6 – Bleed off volume while stripping

Let’s take a look at Figure 6, the stand#3 bleeds 2 bbl and the metal displacement is 2.3 bbl. Therefore, you will have only 1.7 bbl of mud bled off. The overbalance reduces to 192 psi because 1.7 bbl of mud is out of the wellbore. You need to strip in until the total bled minus total stripped is equal to 22 a target mud increment which is 22.3 bbl.

Figure 7 – Bleed off while stripping until the mud increment is reached.

According to Figure 7, you need to strip a total of 12 stands in order to reach the target MI at 22.3 bbl and this point will have only 100 pis over balance.

Figure 8 – Stripping until the MI is reached.

4. Strip in a shut in well until the safety factor is reach. At this example, we strip in to get additional 100 psi so the casing pressure will be 700 psi and the overbalance is 200 psi.

Figure 9 – Stand#13 stripped in a shut in well

Figure 10 – Strip in a shut in well until 100 psi is reached (700 psi surface pressure)

5. We will continue step#3 and step#4 until the drillstring reaches the bottom or the desired depth. Then you can carry on the conventional well control methods as driller’s method, wait and weight etc.

Figure 11 – Continue Stripping by repeating step#3 and step#4

Figure 12 – Strip to desired depth

Reference books: Well Control Books

Temperature has an effect on brine density so it is very critical to compensate loss of density due to temperature. Higher wellbore temperature will reduce the brine density more.  The calculation below demonstrates how to determine brine weight to mix on surface in order to get required brine density at a wellbore condition.

Brine weight with temperature correction equation is listed below;

Brine Density to Mix = Brine Density at Average Wellbore Temp + (Average Wellbore Temp – Surface Temp) x Weight Loss Factor

Where;

Brine Density to Mix = ppg

Brine Density at Average Wellbore Temp = ppg

Average Wellbore Temp = F

Surface Temp = F

Weight Loss Factor = ppg/F

Weight Loss Factor can be found in the table below;

Determine the weight of brine that you need to mix on surface based on the following information.

Surface temperature = 90 F

Wellbore temperature at TD = 300 F

Density of brine required for this well = 10.0 ppg

Solution

Average Wellbore Temp = (Surface Temperature + Wellbore Temperature) ÷ 2

Average Wellbore Temp = (90 + 300) ÷ 2= 195 F

According to the table, the weight loss factor for this case is 0.0025 ppg/F. This figure is selected because the desired weight is 10.0 ppg.

Brine Density to Mix = Brine Density at Average Wellbore Temp + (Average Wellbore Temp – Surface Temp) x Weight Loss Factor

Brine Density to Mix = 10 + (195 – 90) x 0.0025

Brine Density to Mix = 10.26 ppg

The brine density on surface must be 10.3 ppg (round up figure) to suit with this condition.

Reference books: Well Control Books

Correct initial circulating pressure is very important for well control operation because the correct ICP figure will tell you about the balance point while circulating the influx out using Driller’s method. Many people get confused when they try to get the right ICP because they tend to forget about a safety factor that is added while bring the pump to speed. Hence, the ICP with unintentionally added safety margin may fracture formations downhole because people will tend to add more safety factor while circulating. It means that excessive safety factor added into the system will make the well control operation worse.

The example below will demonstrate you how to establish correct ICP

Well shut in after the influx is detected.

Stabilized shut in casing pressure = 600 psi

The float is bumped and the SIDPP is 450 psi

Figure 1 – Pressure at Shut-In Condition

The pump is brought up to speed at 30 SPM for well kill operation by holding casing pressure constant

Casing pressure = 700 psi

Drill pipe pressure = 1,300 psi

Figure 2 – Pressure after Pump is brought to Speed.

Is 1,300 psi the correct Initial Circulating Pressure (ICP)?

The answer is NO.

If you don’t watch the pressure carefully, you will maintain the 1,300 psi as circulating pressure and you may be add safety factor over this figure. You can see that you may end up having extra safety factor which may cause formation fracture.

Look at casing pressure in Figure 2. It shows 700 psi which is 100 psi over the stabilized casing pressure (600 psi) when the well is shut in. The 100 psi represents an overbalanced therefore the circulating pressure at 1,300 psi must be subtracted with the overbalance in order to get the correct ICP

Initial Circulating Pressure (ICP) = Drill Pipe Pressure – Overbalance

Initial Circulating Pressure (ICP) = 1,300 – 100 = 1,200 psi

Figure 3 – Correct ICP

Always Know Overbalance

Reference books: Well Control Books

Mud leg provides hydrostatic pressure in order to prevent mud going through the separator into the rig. If the pressure in the mud gas separator exceeds hydrostatic pressure provided by mud leg, gas blowing through situation will be happened. Once blow-through occurs with a mud gas separator, it is very difficult to stop this situation until the mud leg column is re-established.

Figure 1 illustrates mud-blow through. The pressure that will create blow-through can be calculated by determining hydrostatic pressure of mud leg.

Figure 1 – Blow Through Situation

The equation below demonstrate the blow-through pressure.

Hydrostatic Pressure from Mud Leg = 0.052 × Mud Weight× Mud Leg

Where;

Hydrostatic Pressure from Mud Leg in psi

Mud Weight in ppg

Mud Leg in ft

Use the following data to calculate which pressure would blow-through occur.

Mud Leg = 20 ft

Mud Density in a mud gas separator = 13.0 ppg

Vent line length = 150 ft

Mud gas separator height = 25 ft

Solution

Only mud leg and mud density will be used in the calculation.

Figure 2 – Mud Gas Separator Information

Hydrostatic Pressure from Mud Leg = 0.052 × 13.0 × 20

Hydrostatic Pressure from Mud Leg = 13.5 psi

It means that if it is required 13.5 psi in this mud gas separator to overcome the hydrostatic pressure and gas blow-through will be occurred.

Reference books: Well Control Books

This short VDO will show you how fast of the kick blowing out to the surface.

We don’t know detail about it why this was happened but we can learn from this incident.

• Always monitoring the well while drilling
• Be proactive of well control indicators
• Frequent well control drills are recommended to perform.
• Emergency abandon rig drills must be practices often.

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