1.660 O.D. API TUBING ............................................................................................................................... 21
1.900 O.D. API TUBING ............................................................................................................................... 22
2.063 O.D. API TUBING ............................................................................................................................... 23
2.375 O.D. API TUBING ............................................................................................................................... 24
2.875 O.D. API TUBING ............................................................................................................................... 25
3.500 O.D. API TUBING TO 60,000 LBS SLACK-OFF ................................................................................. 26
3.500 O.D. API TUBING TO 120,000 LBS SLACK-OFF ............................................................................... 27
4.500 O.D. 12.6/12.75# API TUBING ............................................................................................................ 28
5.500 O.D. 17# API TUBING......................................................................................................................... 29
7.000 O.D. 29# API TUBING......................................................................................................................... 30
SLACK-OFF WEIGHT ON PACKER ..................................................................................................................... 31
1.660 O.D. API TUBING ............................................................................................................................... 321.900 O.D. API TUBING ............................................................................................................................... 33
2.063 O.D. API TUBING ............................................................................................................................... 34
2.375 O.D. API TUBING ............................................................................................................................... 35
2.875 O.D. API TUBING ............................................................................................................................... 36
3.500 O.D. API TUBING ............................................................................................................................... 37
4.500 O.D. 12.6/12.75# API TUBING ............................................................................................................ 38
5.500 O.D. 17# API TUBING......................................................................................................................... 39
7.000 O.D. 29# API TUBING......................................................................................................................... 40
TEMPERATURE EFFECT..................................................................................................................................... 41
1.660 O.D. API TUBING ............................................................................................................................... 44
1.900 O.D. API TUBING ............................................................................................................................... 45
2.063 O.D. API TUBING ............................................................................................................................... 46
2.375 O.D. API TUBING ............................................................................................................................... 472.875 O.D. API TUBING ............................................................................................................................... 48
3.500 O.D. API TUBING ............................................................................................................................... 49
4.500 O.D. 12.6/12.75# API TUBING ............................................................................................................ 50
5.500 O.D. 17# API TUBING......................................................................................................................... 51
7.000 O.D. 29# API TUBING......................................................................................................................... 52
GAS PRESSURE AT SURFACE VS. BOTTOM HOLE PRESSURE ..................................................................... 53
NITROGEN PRESSURE VS. BHP TO 10,000 FT ......................................................................................... 54
NITROGEN PRESSURE VS. BHP TO 20,000 FT ......................................................................................... 55
NATURAL GAS PRESSURE VS. BHP TO 10,000 FT ................................................................................... 56
NATURAL GAS PRESSURE VS. BHP TO 20,000 FT ................................................................................... 57
HYDROSTATIC PRESSURE EXERTED BY FLUID/SAND MIXTURES
On occasion you may be required to operate a tool in the presence of a sand laden slurry.
To properly operate that tool, you will need to know the hydrostatic pressure exerted by a columnof this slurry. The following chart will provide fluid gradient factors needed in making this calculation,
based on the true density of the sand being 22.144 lb/gallon.
Densities of Sand/Fluid Slurries:
#/Gal Slurry = (MW + PSA)÷ [(.0456 x PSA) + 1]
where:
MW = #/gal of fluid
PSA = pounds of sand added per gallon of fluid
Example of Calculation:
The customer tells you he is going to pump 500 bbls of 9.2 #/gal gelled brine adding 2
pounds of sand per gallon of fluid.
#/Gal Slurry = (9.2 + 2) ÷ [(.0456 x 2) + 1]
= 10.264 #/Gal Slurry
Note: This is the fluid density used to calculate hydrostatic pressure.
Calculate fluid gradient = 10.264 x 0.052
= 0.534 psi/ft
NOTE: The chart on the next page depicts the graphical solution to this example.
Use the calculation procedure from the preceding chapter to determine pressures at the tool.
There may be times when you are required to operate a tool without a benefit of a weight
indicator, or the indictor available is not functioning properly. Slack-off charts give the amount of
tubing to slack off to get a pre-determined weight set down on the tool or seal assembly.
Slacking off the tubing, into a well, has three resultant effects on the string:
1. Steel compression
2. Buckling inside casing
3. Friction between tubing & casing
Steel Compression
Steel compresses at the same rate as it stretches. Assuming that steel is perfectly elastic
throughout the range of compression or stretch, if 20,000# stretches a simple six inches, 20,000#
down will also compress the same sample six inches. While this simple principle is involved in
the slack-off charts, it does not completely describe the mechanics of slack-off.
Buckling
Slacking-off weight on drill pipe, or tubing, has a tendency to buckle the string. If there is
space between the tubing and casing, the tubing will buckle outward until it contacts the wall of
the casing. While slacking-off, you lose inches due to steel compression, and you also lose
inches due to the sideways movement of tubing buckling. When tubing buckles inside casing, its
buckled shape follows the contour of the casing forming a corkscrew shape, or helix.
As you can see, the number of inches to slack-off to account for buckling will be dependent
on the tubing OD, the casing ID, and the annular space available to accommodate buckling.From the charts, you will see that 3-1/2 tubing in 7 casing accommodates little buckling, while
2-3/8 tubing in 9-5/8 casing allows for considerably more buckling.
The following ten charts show the number of inches to slack-off to account for steel
compression and buckling; friction is not taken into account.
When you have calculated how many inches to slack-off, you still dont know how much of
this weight will be transferred to bottom. The number of inches to slack-off tells how much weight
has been transferred from the elevators to some point within the well. However, it will not tell you
how much of this weight went into friction, and how much went to bottom.
Example:
Refer to the 2-7/8 Slack-off chart for an example of these calculations.
Temperature Effects on Tubing Length Due to Injecting Cold Fluids
Heated metal expands and cooled metal contracts. In a long string of tubing with a
temperature change over its entire length, this expansion or contraction can be considerable.
Three main areas where temperature effects are prevalent are:
Producing
This subject has been the realm of the tubing anchor. Warmer fluids were brought to surface
through tubing resulting in an elongation of the string. The calculation necessary for this can be
found in the tubing anchor section of this handbook.
More recently, temperature effects have been considered when deep, hot gas wells are
brought on production through the use of TCP (Tubing Conveyed Perforating) guns. Tubing may
be run in at ambient temperature, seated in a seal bore, TCP guns are then fired slightly under-
balanced, and a gas well brought in at 400°F bottom hole temperature. This completion results
in considerable movement over a period of days as the tubing string heats up and expands.Steam
Elongation of tubulars due to the injection of steam can be extreme. This is caused by the
tremendous change in average temperature over a short period of time.
Injecting Fluids
The most common situation for the service tool hand is the injecting of cold fluids (as
encountered during waterfloods, acid treatments, sand-control completions and hydraulic fracturing
treatments) which are almost always colder than the well temperature and tend to shorten the
string. This shortening can pick up a locator seal assembly or rob set down weight from
compression set packer. With a tension-set packer, additional upstrain may shear the safety
release allowing the tool to come loose and leak. In the worst case, additional tension couldexceed the limits of the work string causing the tubing to part.
Results of your calculations can again be inches or pounds, depending on you application of
the formulae. Either way, the first step toward solution is determination of the average temperature
change in the tubing string, when it is cooled to its minimum temperature during the job, and
compare it to the average temperature before the operation began.
To calculate the average temperature of a string of tubing, temperature at both ends of the
string must be known. Average temperature is simply the average of the surface and bottom
hole temperatures. Convention is to take the temperature at the top of the string to be the mean
yearly temperature 30 feet from surface (taken to be 70°F) and the bottom hole temperature.(This can change based upon the region of the world where the well is located.)
To calculate the average temperature of the string during injection, the temperature at the
top of the string is taken to be the same as the temperature of the fluid you are injecting.
Temperature at the bottom of the string will be dependent on three things: fluid temperature,
injection rate, and injection per time period.
The figures on the amount to cool a string for a short duration or low rate job are not available,
however, some empirical data is available and is presented as a guideline:
It is often necessary to calculate the bottom hole pressure for a well displaced with nitrogen
gas. Being a gas, its weight changes with temperature and pressure according to the Perfect
Gas Law
PV = nRT
This formula is presented for your information only to show the linear relationship between
pressure, volume, and temperature. It is not to be used to calculate bottom hole pressure.
The density, and hence the weight, increases with an increase in pressure and decreases
with an increase in temperature.
To present a simplified graph of bottom hole pressure and hydrostatic pressure with differentwellhead pressures, we must assume a surface temperature and temperature gradient. It is well
known that temperatures are not the same in all wells at a specific depth, but an average
temperature is assumed for this graph. This average will be 70°F at surface with a 0.016°F per
foot geothermal temperature gradient. On a 10,000 foot deep vertical well, this would equate to
230°F BHT.
The primary purpose of calculating the bottom hole pressure of a column of nitrogen is to
balance fluids across a packer. To use the chart on the following page, calculate the bottom hole
pressure at the tool (hydrostatic of the column of fluid), read across to the well depth, then down
to get nitrogen pressure at the wellhead. The difference between bottom hole pressure and the
nitrogen pressure at the wellhead is the hydrostatic head of the column of nitrogen gas.
