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Drilling Calculations -Slug Calculations
Barrels of slug required for a desired length of dry pipe. 
Slug vol, bbl = slug length, ft x drill pipe capacity, bb/ft.
Step 1
Hydrostatic pressure required to give desired drop inside drill pipe:
HP, psi = mud wt, ppg x 0.052 x ft of dry pipe.
Step 2
Difference in pressure gradient between slug weight and mud weight:
psi/ft = (slug wt, ppg - mud wt, ppg) x 0.052
Step 3
Length of slug in drill pipe:
Sluglength,ft = pressure,psi / difference in pressure gradient,psi/ft.
Step 4
Volume of slug, barrels:
Example: Determine the barrels of slug required for the following:
Desired length of dry pipe (2 stands) = 184 ft.
Mud weight = 12.2 ppg.
Slug weight = 13.2 ppg.
Drill pipe capacity = 0.01422 bbl/ft.
4-1/2in.-16.6 lb/ft
Step 1
Hydrostatic pressure required:
HP, psi = 12.2 ppg x 0.052 x 184ft.
HP = 117psi
Step 2
Difference in pressure gradient, psi/ft:
psi/ft = (13.2 ppg - 12.2 ppg) x 0.052
psi/ft = 0.052
Step 3
Length of slug in drill pipe, ft:
Slug length, ft = 117psi / 0.052
Slug length = 2250ft
Step 4
Volume of slug, bbl:
Slug vol, bbl = 2250ft x 0.01422bbl/ft
Slug vol = 32.0bbl

Weight of slug required for a desired length of dry pipe with a set volume of slug.

Step 1
Length of slug in drill pipe, ft:
Slug length, ft = slug vol, bbl / drill pipe capacity, bbl/ft.

Step 2
Hydrostatic pressure required to give desired drop inside drill pipe:
HP, psi = mud wt, ppg x 0.052 x ft of drill pipe.

Step 3
Weight of slug, ppg:
Slug wt, ppg = HP, psi / 0.052 / (slug length. ft + mud wt, ppg)
Example: Determine the weight of slug required for the following:

Desired length of dry pipe (2 stands) = 184 ft.
Mud weight = 12.2 ppg.
Volume of slug = 25 bbl.
Drill pipe capacity = 0.01422 bbl/ft.
4- 1/2in.-16.61b/ft

Step 1
Length of slug in drill pipe, ft.
Slug length, ft = 25 bbl / 0.01422bbl/ft.
Slug length = 1758 ft.

Step 2
Hydrostatic pressure required:
HP, psi = 12.2 ppg x 0.052 x 184 ft.
HP = 117psi.

Step 3
Weight of slug, ppg:
Slug wt, ppg = 117psi / 0.052 / (1758ft + 12.2ppg)
Slug wt, ppg = 1.3ppg + 12.2ppg.
Slugwt = 13.5ppg.

Volume, height, and pressure gained because of slug:

a) Volume gained in mud pits after slug is pumped, due to W-tubing:
Vol, bbl = ft of dry pipe x drill pipe capacity, bbl/ft.

b) Height, ft, that the slug would occupy in annulus:
Height, ft = annulus vol, ft/bbl x slug vol, bbl.

c) Hydrostatic pressure gained in annulus because of slug:
HP, psi = height of slug in annulus, ft x difference in gradient, psgft between slug wt and mud wt.

Example: 
Feet of dry pipe (2 stands) = 184 ft.
Slug volume = 32.4 bbl.
Slug weight = 13.2 ppg.
Mud weight = 12.2 ppg.
Drill pipe capacity = 0.01422 bbl/ft.
4- 1/2in. - 16.6 lb/ft.

Annulus volume (8-1/2in. by 4-1/2in.)= 19.86.6 bbl/ft.

a) Volume gained in mud pits after slug is pumped due to U-tubing:
Vol, bbl = 184 ft x 0.01422 bbl/ft.
Vol = 2.62 bbl.

b) Height, ft, that the slug would occupy in the annulus:
Height, ft = 19.8ft/bbl x 32.4 bbl.
Height = 641.5 ft.

c) Hydrostatic pressure gained in annulus because of slug:
HP , psi = 641.5ft (13.2 - 12.2) x 0.05
HP, psi = 641.5ft x 0.052
HP = 33.4 psi.

English units calculation
Barrels gained pumping slug, bbl
= (bbl slug pumped x slug wt, ppg / mud wt, ppg) - bbl slug.

Example: Determine the number of barrels of mud gained due to pumping the slug and determine the feet of dry pipe.

Mud weight = 12.6 ppg.
Slug weight = 14.2 ppg.
Barrels of slug pumped = 25 barrels
Drill pipe capacity = 0.01776bbl/ft.

Barrels gained = (25bbl x 14.2 ppg / 12.6 ppg) - 25 bbl
= 28.175 - 25
= 3.175 bbl

Determine the feet of dry pipe after pumping the slug.
Feet of dry pipe = 3.175 bbl + 0.01776bbl/ft
Feet of dry pipe = 179feet.

Metric calculation
liters gained pumping slug = (liter slug pumped x slug wt, kg/l / mud wt, kg/l) - liter slug
S. I. units calculation
m³ gained pumping slug = (m³ slug pumped x slug wt, kg/m³) - m³ slug

Surface controlled subsurface safety valve SCSSV

 Surface controlled subsurface safety valves acts as a fail safe  system to prevent any uncontrolled release of reservoir fluids in the event of a surface disaster. It is always installed as a vital component in the completion and it is considered as a primary barrier. SCSSV is hydraulically actuated throughout a continuous / discontinuous control line from a control panel, a control station, topsides at the surface.

We have two main types of SCSSV: tubing retrievable TRSCSSV which require a rig for intervention in case of failure and wireline retrievable SCSSV which could be set an retrieved by wireline. SCSSV are designed to sustain the well shut in pressure, different designs are available in the market but the flapper type is the the common one incorporating a metal to metal seal.

What is Drilling Ton-Mile (TM)?/ Slip and Cut

Drilling Ton-Mile is the work of drilling line that is commonly measured as the cumulative of the load lifted in tons and the distance lifted or lowered in miles. When the predetermined ton-mile limit is reached, drilling contractors will perform slip and cut drilling line to prevent drilling line fatigue.

When drilling line is spooled on and off a drawworks drum during operation as drilling a well, running casing, coring, etc.The drilling line get worn out; therefore, drilling contractors must cut old section and replace with new section of drilling line at specific period based on ton mile calculation.

The most worn area is the end of drilling line where is constantly spooled over the draw works drum. A section of drilling line, typically around 100 ft, is cut then the drilling line is re-attached to the draw works drum and the amount cut off is spooled back on the drum. This operation is called “slip and cut drilling line”.

Note: Ton-mile is the important figure that must be recorded correctly. However, the most important is to visually inspect drilling line all time to see if there is any worn out wire. If you see the worn out line, you need to cut the drilling line even though the drilling line does  not reach ton-mile limit yet.

All types of ton-mile service should be calculated and recorded in order to obtain a true picture of the total service received from the rotary drilling line. 

Differential Sticking Causes Stuck Pipe

Differential Sticking is one of the most common causes of pipe stuck. It can happen when there is differential pressure (overbalance pressure) pushing a drillstring into filter cake of a permeable formation.

Four factors causing the differential sticking are as follows:

Permeable formation as sand stone, lime, carbonate, etc.

Overbalance – typically mud weight in the well is more than formation pressure. More overbalance in the wellbore, more chance of getting differential sticking.

Filter cake – Poor and thick filter cake increases chances of sticking the drill string.

Pipe movement – if the drillstring is station for a period of time, the filter cake will tend to develop around permeable zones and the drillstring. Therefore, potential of getting differentially stuck is increased.

Warning signs when you get stuck due to differential sticking

• There are high over balance between wellbore and formation. Especially, when there is highly depleted formation, the chance of getting differentially stuck is so high.

• Torque, pick up and slack off weight increase when the drill string is being moved. Once it happens, you may not be able to pull or rotate pipe.

Stuck identification for differential sticking

• Drill string is in station for a period of time. The differential sticking is happened when there is no pipe movement for long time.

• Circulation can be established without increasing in pressure.

• BHA is across the permeable zone.

Let’s see how much differential force from this situation

Formation pressure = 3800 psi

Hydrostatic pressure =4500 psi

Cross area of stuck pipe = 1500 square inch

 

You can determine how much differential force based on a following formula:

Force = Differential Pressure x Cross Section Area

Where

Force is in lb.

Differential pressure is in psi.

Cross section area is in square inch.

Force = (4500 – 3800) x 1500

Force = 1,050,000 lb

This is massive !!!

If we assume a coefficient friction of 0.5, you can determine how much tension you need to free the pipe by this following formula:

From the basic of physic, F= coefficient friction x N

where:

F is force to pull.

N is reactive force.

For this scenario, N is equal to differential force.

F = 0.5 x 1,050,000 = 525,000 lb

You need overpull of 525,000 lb to fee the pipe from this situation. This is still massive 

What should you do for this situation?

1. Apply torque into drill string and jar down with maximum allowable trip load

2. Jar up without apply torque in the drill string.

3. Spot light weight pill to decrease hydrostatic pressure. If you want to the light weight pill, you must ensure that the overall hydrostatic pressure is more than formation pressure. Otherwise, you will face with a well control situation.

Preventive actions are as follows:

1. Do not use too high mud weight

2. Do not stop moving string for a period of time, especially, when the BHA is across formations.

3. Keep mud in good shape. Under specification drilling mud will create thick mud cake which can be a big impact for the differential sticking.

4. Minimize length of BHA and use spiral drill collar and heavy weight drill pipe to reduce contact area.

What is a trip tank?

Trip Tank is a small metal tank with small capacity about 20-40 bbls with 1 bbl divisions inside and it is used to monitor the well. There are several operations that we can use the trip tank to monitor the well as follows;

1. Trip Out Of Hole (TOOH): While tripping out of hole, the trip tank is used to track volume of mud replacing volume of drill string. The volume of mud should be equal to displacement volume of any kind of tubular tripped out of hole.

2. Trip In Hole (TIH): While tripping in hole, the drilling string (bit, BHA and drill pipe) is ran back in the hole, the trip tank must be use to keep track volume gain. The expected volume gain should be equal to the displacement volume of whole string.

3. Flow check: The trip tank is utilized to determine well condition in order to see if the well is still under static condition.

The importance of trip tank is as follows:

1. Provide sufficient hydrostatic pressure to prevent influx from reservoir. When TOH, mud hydrostatic will be lost because mud volume must substitute drill pipe volume pulled out of hole. If hydrostatic pressure decreases too much, influx from reservoir can come into the hole and make a trouble in well control. For this reason, mud in trip tank must be filled into hole to maintain hydrostatic pressure.

2. Kick Indicator: Volume of mud from the trip tank is pumped in the hole can be an indicator that relates to a situation occurring in wellbore as kick. If the volume of mud measured by trip tank is less than the expected volume of drill pipe volume tripped out of hole, the suspect problem is kick because volume of kick substitutes volume of mud.

The circulation system while tripping

I would like to show the circulation system while tripping out of hole therefore you will be more understanding about how trip tank works.

While Tripping Out of Hole (TOH), a trip tank pump will circulate mud into a bell nipple in order to keep the hole full all the time and the over-flow mud will return back to the trip tank. Once every stand is pulled, the mud volume in the well will decrease because the drill pipe is pulled out of hole. Since the trip tank pump is always run while tripping, the annulus will be full all the time (see figure below).

How Does a Top Drive Work

Used to rotate the drill string during the drilling process, the top drive is a motor that is suspended from the derrick, or mast, of the rig. These power swivels boast at least 1,000 horsepower that turn a shaft to which the drill string is screwed. Replacing the traditional Kelly or rotary table, the top drive lessens the manual labor involved in drilling, as well as many associated risks.

A top drive is comprised of one or more electric or hydraulic motors, which is connected to the drill string via a short section of pipe known as the quill. Suspended from a hook below the traveling block, the top drive is able to move up and down the derrick. Many times, slips are still employed on a rotary table to ensure the drill string does not fall down the well.

Chosen both for increased safety and efficiency, top drives provide several key benefits:

• A top drive is capable of drilling with three joints stands, instead of just one pipe at a time.
• Top drives typically decrease the frequency of stuck pipe, which contributes to cost savings.
• A top drive allows drillers to more quickly engage and disengage pumps or the rotary while removing or restringing the pipe.
• Top drives are also preferable for challenging extended-reach and directional wells.

Reducing risk and increasing safety during the drilling process, top drives remove much of the manual labor that was previously required to drill wells. Many times, top drives are completely automated, offering rotational control and maximum torque, as well as control over the weight on the bit.

Top drives can be used in all environments and on all types of rigs, from truck-mounted units to the largest offshore rig. Although top drives can be used on both onshore and offshore rigs, there are some differences between the two. For example, on an offshore rig, the top drive travels up and down the vertical rails to avoid the mechanism from swaying with the waves of the ocean.