Two cases of shut the well in while logging with wire line are as follows;

1. Shut the well in while wireline logging through open BOP without a lubricator.

2. Shut the well in while wireline logging through open BOP with a lubricator installed in the BOP.

Let’s talk about the first case: Shut the well in while wireline logging through open BOP without a lubricator.

First step: Stop logging operation

Second step: Shut the well in by following these procedures;

1. Close annular preventor because we would like to use the annular preventor element to squeeze around the wireline. You may need to increase closing pressure in order to have affective sealing ability if necessary.

2. Open a HCR valve against a fully closed choke manifold valve.

3. Use a trip tank to confirm that flow is stopped and the well is totally shut-in.

4. Inform drilling supervisors

The well sometimes cannot be totally shut in via a closed annular preventor therefore you must consider cutting the wireline and letting it drop then using blind rams to shut the well in instead. If the annular preventor could not seal around the wireline effectively and the wireline cannot be cut and dropped through the Blow Out Preventor (BOP), you may consider using shear rams to cut the wire as the last option.

Let’s talk about the second case: Shut the well in while wireline logging through open BOP with a lubricator installed in the BOP.

First step: Stop logging operation

Second step: Shut the well in by following these procedures;

1. Energize pack off seals at the lubricator. You may need to increase closing pressure in order to have affective sealing ability if necessary.

2. Open a HCR valve against a fully closed choke manifold valve.

3. Use a trip tank to confirm that flow is totally stopped and the well is properly shut-in.

4. Inform drilling supervisors

Ref books: Well Control Books

Shut-In Casing Pressure (SICP): Read and record the shut-in casing pressure (casing gauge).

In order to get the proper pressure reading, the casing gauge should be installed upstream of the closed choke.

Pit Gain: Read and record the pit gain. Pit volume gained is very critical for the maximum casing pressure calculation.

Practically, while tripping out of hole, a trip tank is used to track displace volume in use. The accurate pit gain value can be easily figure out by finding difference between actual volume taken to fill up wellbore and theoretical fill up volume. However, if the active pits are used to record the displacement volume, it will be very difficult to figure out the accurate pit gain. The concept of determining the pit gain is the same as using the trip tank. However, the reason that I say that it is very difficult to get the accurate pit gain because pit volume is too large to record few changes while tripping.

Time: Record the time that the well control situation is occurred and keep an accurate time log for the entire well kill operation

Bit Depth: Record bit depth.

Ref books: Well Control Books

Shut-In Casing Pressure (SICP): Read and record the shut-in casing pressure (casing gauge).

In order to get the proper pressure reading, the casing gauge should be installed upstream of the closed choke.

Shut-In Drillpipe Pressure (SIDP): Read and record the shut-in drillpipe pressure. You must remember that whether you have a float in drilling string or not.

If there is no a float is in the drillstring, the shut in drill pipe pressure can be read directly from the standpipe manifold.

If there is a float in the drillstring, you need to bump the float in order to determine the correct shut in drill pipe pressure. I will write about how to bump float to record the shut in drill pipe pressure later.

Time: Record the time that the well control situation is occurred and keep an accurate time log for the entire well kill operation

Closing Pressure: Record the closing pressure of BOP. In order to prevent well bore fluid leaking through BOP elements, the closing pressure should be high enough.

Pit Gain: Read and record the pit gain. Pit volume gained is very critical for the maximum casing pressure calculation. You should check the volume gained from mud logger and driller in order to get the accurate figure. I don’t recommend you to ask only one person to get this figure. It is better to have another data source to compare with.

After the well is properly secured and all information is gathered, the supervisor on the rig should inform his supervisor to find the proper method to kill the well.

Ref books: Well Control Books

Drilling shut in procedures (3S) – HARD SHUT IN PROCEDURE-

1. Space Out – Stop drilling, pick up drilling sting off bottom and space out to ensure that tool joint is not located at BOP element that we would like to shut the well in.

2. Stop Down – Stop mud pumps

3. Shut In - Close an annular preventer or an uppermost pipe rams. Use trip tank to verify that the flow is stopped and the well is completely shut in. Then inform supervisors as drilling representative, tool pusher, OIM.

Ref book: Well Control Book

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.

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.

Ref book: Well Control Book

If you see a lot of trip gas after circulating out, this situation indicates that the wellbore is almost in a balance condition.

The connection gas occurs because total pressure (hydrostatic pressure + friction pressure) temporarily decreases during making connection. Basically, it means that you lose equivalent circulating density due to pumps off. In addition, the connection could be happened because of swabbing effect when the drill string is worked off bottom prior to making connection.

The connection gas can indicate that pressure between hydrostatic pressure exerted by drilling fluid and formation pressure is almost in balance condition. Therefore, when you see the connection gas, you should consider weighting up mud in the system before resuming drilling operation or tripping operation.

Ref book: Well Control Book

While we are drilling, there is a stable gas reading that is not connected with either bottoms up gas or drilled gas is generally called “Background Gas”. The background gas always shows every time while drilling and it is not a sign of considerable risk to well control situation. Nevertheless, we must always check changes in background gas value because it is able to help recognize underbalance situation while drilling, especially drilling into high pressure zone.

Remember – PLEASE ALWAYS KEEP TRACKING YOUR BACKGROUND GAS

Ref book: Well Control Book

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.

Ref book: Well Control Book

There are several importances of casing as follow;

• To prevent collapse of the borehole

• To confine production to the wellbore

• To provide a flow path for drilling fluid

• To contain formation pressure and prevent fracturing of upper and weaker zones

• To provide an anchor for surface and sub surface equipment

• To provide a high strength flow conduit for drilling fluid to surface and ,with BOP , permit the safe control of formation pressure

• To prevent contamination of fluid in formations

• To exclude water zones from the producing formations

Ref book: Cementing Technology Book