Pump Pressure and Pump Stroke Relationship

There are relationships between pump pressure and pump stroke that you really need to understand and be able to determine pump pressure after adjusting new pump stroke.

Mud Pump (OilfieldPix.com, 2017)

There are 2 formulas used to determine pump pressure as shown in the detail below:

1st formula for estimating new circulating pressure (simple and handy for field use)

New circulating pressure in psi = present circulating pressure in psi x (new pump rate in spm ÷ old pump rate in spm) 2

Example: Determine the new circulating pressure, psi using the following data:
Present circulating pressure = 2500 psi
Old pump rate = 40 spm
New pump rate = 25 spm
New circulating pressure in psi = 2500 psi x (25 spm ÷ 40 spm) 2
New circulating pressure = 976.6 psi

2nd formula for estimating new circulating pressure (more complex)

For the 1st formula, the factor “2” is used but it’s just the round up figure. If you want more accurate figure, you need to figure out an exact figure. So the 2nd formula has one additional formula to calculate the factor based on 2 pressure readings at different pump rate.  Please follow these steps to determine new circulating pressure

1. Determine the factor ”n” and  the formula to determine factor “n” is below:

Factor (n) = log (pressure 1 ÷ pressure 2) ÷ log (pump rate 1÷pump rate 2)

2. Determine new circulating pressure with this following formula.

New circulating pressure in psi = present circulating pressure in psi x (new pump rate in spm ÷ old pump rate in spm) n

Note: factor “n” comes from the first step of calculation.

Example: Determine the factor “n” from 2 pump pressure reading
Pressure 1 = 2700 psi at 320 gpm
Pressure 2 = 500 psi at 130 gpm
Factor (n)   = log (2700 psi ÷ 500 psi) ÷ log (320 gpm ÷ 130 gpm)
Factor (n) = 1.872

Example: Determine new circulating pressure by using these following information and the factor “n” from above example:
Present circulating pressure = 2500 psi
Old pump rate = 40 spm
New pump rate = 25 spm
New circulating pressure, psi = 2500 psi x (25 spm ÷ 40 spm) 1.872
New circulating pressure = 1037 psi

Please find the Excel sheet used to calculate new circulating pressure based on pump pressure and pump stroke relationship.

Ref books: Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Drill pipe pulled to lose hydrostatic pressure

You previously learn about hydrostatic pressure lose due to pulling out of hole . This post will use the same concept but we will determine how many feet of drill pipe pulled to lose certain amount of hydrostatic pressure in well bore.

The calculations below have 2 cases of pulling out of hole, pull dry and pull wet. They are different in calculation because amount of drilling fluid out of hole is different. Please follow and understand each case of calculation.

#1: How many feet of pipe pulled DRY to lose certain amount of hydrostatic pressure

Feet = (hydrostatic pressure loss in psi x (casing cap in bbl/ft – pipe displacement in bbl/ft)) ÷ (mud weight in ppg x 0.052 x pipe displacement in bbl/ft)

Example: Determine the FEET of dry drill pipe that must be pulled to lose the overbalance using the following data:

Hydrostatic pressure loss = 200 psi
Casing capacity = 0.0873 bbl/ft
Pipe displacement = 0.01876 bbl/ft
Mud weight = 12.0 ppg
Ft = 200 psi x (0.0873 – 0.01876) ÷ (12.0 ppg x 0.052 x 0.01876)
Ft = 1171 ft
You need to pull 1171 ft of dry pipe to lose 200 psi hydrostatic pressure.

#2: How many feet of pipe pulled WET to lose certain amount of hydrostatic pressure

Feet = hydrostatic pressure loss in psi x (casing capacity in bbl/ft – drill pipe capacity in bbl/ft – drill pipe displacement in bbl/ft) ÷ {mud wt in ppg x 0.052 x (pipe displacement in bbl/ft + (% of volume in drill pipe out of hole ÷ 100) x pipe capacity in bbl/ft)}

Example: Determine the feet of WET pipe that must be pulled to lose the overbalance using the following data:

% of volume in drill pipe out of hole = 100
Hydrostatic pressure loss = 200 psi
Casing capacity = 0.0873 bbl/ft
Drill pipe capacity = 0.01876 bbl/ft
Drill pipe displacement = 0.0055 bbl/ft
Mud weight = 12.0 ppg

Feet = 200 psi x (0.0873 – 0.01876 – 0.0055 bbl/ft) ÷ {12.0 ppg x 0.052 x (0.0055 + (100÷100) x 0.01876 bbl/ft)}
Feet = 832.9 ft
You need to pull 833 ft of wet pipe to lose 200 psi hydrostatic pressure.

Please find how many feet of drill pipe pulled to lose certain amount of hydrostatic pressure in well bore.

Ref books: Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Formation Temperature Calculation

Formation temperature is one of the most critical parameters in drilling and workover operation and it varies by true vertical depth of wellbore.

The following formula shows relationship between formation temperature and true vertical depth of well.

Formation temperature = (ambient surface temperature ) + (temperature gradient x  Well TVD)

Where:

Formation temperature in F (Fahrenheit)

ambient surface temperature in F (Fahrenheit)

temperature gradient in F/ft (Fahrenheit / ft)

Well TVD in ft

Example: The temperature gradient in a specific area is 0.015 °F/ft of depth and the ambient surface temperature is 90 °F.

Determine the estimated formation temperature at a TVD of 12,000 ft:

Formation Temperature, °F = 90 °F + (0.015 °F/ft x 12,000 ft)

Formation Temperature, °F = 90 °F + 180 °F

Formation Temperature = 270 °F (estimated formation temperature)

Please find the Excel sheet used for estimating formation temperature.

Ref books: Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Hydraulic Horse Power (HHP) Calculation

Hydraulic Horse Power is a measure of the energy per unit of time that is being expended across the bit nozzles. It is commonly calculated by this equation, HHP=P*Q/1714, where P stands for pressure in pounds per square in., Q stands for flow rate in gallons per minute, and 1714 is a conversion factor necessary to yield HHP in terms of horsepower. Bit manufacturers often recommend that fluid hydraulics energy across the bit nozzles be in a particular HHP range, for example 2.0 to 7.0 HHP, to ensure adequate bit tooth and bottom-of-hole cleaning (the minimum HHP) and to avoid premature erosion of the bit itself (the maximum HHP).

Hydraulic Horse Power (HPP) formula:

 

HHP= (P x Q) ÷1714

where;

HHP = hydraulic horsepower
P = circulating pressure, psi
Q = circulating rate, gpm

Example : Determine Hydraulic Horse Power with these following data:

circulating pressure = 3500 psi
circulating rate = 800 gpm
HHP= (3500 x 800) ÷1714
HHP = 1633.6

Please find the Excel sheet for calculating Hydraulic Horse Power (HHP)

Ref books: Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Hydrostatic Pressure (HP) Decreases When POOH

When pulling out of hole, volume of steel will be out of hole and mud volume will replace the steel volume.  If we don’t fill hole, hydrostatic pressure will decrease. There are 2 cases of pulling pipe which are pull dry and pull wet. Each condition is different in calculation concept because mud volume to displace pipe volume is different.

This topic shows you how to calculate hydrostatic pressure loss for both cases of pulling pipe, pull dry and pull wet. Moreover, there is the Excel sheet for calculating pressure decrease due to pulling out of hole.

Case#1: When pulling DRY pipe

When pulling dry, we will consider volume of steel out of hole only.

Step 1: Determine Total Pipe Volume

Step 2: Determine Hydrostatic Pressure Decrease

Example: Determine the hydrostatic pressure decrease when pulling DRY pipe out of the hole:

Number of stands pulled = 10
Pipe displacement = 0.0055 bbl/ft
Average length per stand = 91 ft
Casing capacity = 0.0873 bbl/ft
Mud weight = 12.0 ppg

Step 1: Determine of pipe displacement in Barrels = 10 stands x 91 ft/std x 0.0055 bbl/ft displaced
Barrels displaced = 5.01 bbl
Step 2: Determine HP, psi decrease = 5.01 barrels x 0.052 x 12.0 ppg ÷ (0.0873 bbl/ft – 0.0055 bbl/ft)
Hydrostatic pressure decrease = 38.2 psi

Case#2: When pulling WET pipe

When pulling wet, we will consider volume of steel out of hole and volume of mud in drillpipe as well. Therefore, pulling wet will decrease hydrostatic more than pulling dry pipe.

Step 1: Barrels displaced = number of stands pulled per stand in ft
x average length x {pipe disp inbbl/ft + {(% volume in drill pipe out of hole ÷ 100) x pipe cap in bbl/ft)}

Step 2: Determine hydrostatic pressure in psi decrease = barrels displaced x 0.052 x mud weight, ppg ÷ ((casing capacity in bbl/ft) – (Pipe disp in bbl/ft + pipe cap in bbl/ft))

Example: Determine the hydrostatic pressure decrease when pulling WET pipe out of the
hole:

% of volume in drill pipe out of hole = 100
Number of stands pulled = 10
Pipe displacement = 0.0055 bbl/ft
Average length per stand = 91 ft
Pipe capacity = 0.01876 bbl/ft
Mud weight = 12.0 ppg
Casing capacity = 0.0873 bbl/ft

Step 1: Barrels displaced = 10 stands x 91 ft/std x {(.0055 bbl/ft + (100 ÷ 100) x 0.01876 bbl/ft)}
Barrels displaced = 22.08 bbl

Step 2: hydrostatic pressure in psi decrease = 22.0766 barrels x 0.052 x 12.0 ppg ÷ ((0.0873 bbl/ft) – (0.0055 bbl/ft + 0.01876 bbl/ft))
HP decrease, psi = 218.52 psi

Please find the Excel sheet for calculating pressure decrease due to pulling out of hole.

Ref books: Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.