Chapter VIII Packer and Tubing Forces Types of

Chapter VIII Packer and Tubing Forces

Types of Packers • Retrievable • Packer body, slips and rubber packing elements are rigidly attached to the tubing string • Can unseat and move • Permanent • Set into casing with wireline • Sealing elements on tubing

Retrievable Packers • Weight set • Tension set • Hydraulically set

Weight-set Packers • Simplest • Slips point down preventing movement • J-slot prevents movement until at depth • Rotate tubing to disengage Jslot then apply downward force (weight) to compress sealing element

Permanent Packers • Run in on wireline • Charge fired to set slips • Slips point up AND down preventing movement • Can also be set using tubing and hydraulic pressure • Tubing seals to inside with sealing sub

Forces acting on Packer-Tubing Systems • Tubing movement occurs or forces are induced when the following changes are made to the well – – – Running the packer Placing the well on production Swabbing the well Acidizing the well Fracing the well • After the packer is set each subsequent operation must be evaluated against the original setting conditions • Exceeding the original setting forces might cause: – Retrievable packer to move – Sealing sub to slide out of permanent packer

Forces acting on Packer Body • Pressure changes in the tubing or the annulus will result in forces being applied to the packer body • Pressure is the SAME at the packer (hydrostatic) BUT the dimensions of the top and bottom of the packer body are different. • Let’s examine this condition: – Assume a well with a weight-set packer is being acidized – Packer was set with 7000 lbs of downward force (weight-set) – Casing annulus pressure acts on the top of the packer crosssection – Tubing pressure acts on the bottom of the packer cross section – See next slide/

Top of packer is 14. 81 sq in cross section Bottom of packer is 16. 11 sq in cross section

When the packer was set the tubing and annulus contain 9 lb/gal saltwater For a packer set at 6, 500 ft this results in a hydrostatic pressure in the annulus of 3042 psi 9 lb/gal X 0. 052 X 6500 ft = 3042 psi At this pressure the top of the packer has a force of: 3042 psi X 14. 81 sq in = 45, 052 lbs At the same pressure the bottom of the packer has a force of 3042 psi X 16. 11 sq in = 49, 007 lbs This 3, 955 lb difference is buoyancy in the UP direction

When we acidize the well we pump acid down the tubing with the packer set. The acid weighs 6. 9 lb/gal The acid changes the tubing hydrostatic pressure to: 6. 9 lb/gal X 0. 052 X 6, 500 ft = 2, 332 psi Assuming we pump the acid at 1000 psi at the surface the total pressure at the bottom of the tubing is: 2, 332 psi + 1000 psi = 3, 332 psi. The annulus remains unchanged at 3, 042 psi because the packer is set

Let’s now look at the force on the packer DOWNWARD force is: 7, 000 lbs + (3, 042 psi X 14. 81 sq. in. ) = 7, 000 + 45, 050 = 52, 050 lbs UPWARD force is: 3, 332 psi X 16. 11 sq. in. = 53, 680 lbs The resulting total force on the packer is the DIFFERENCE and pointe UP = 1, 630 lbs

BUT we set the packer with 7, 000 lbs of DOWNWARD force Clearly the packer will UNSEAT at 1, 630 lbs of UPWARD FORCE What can we do? 1) Apply 8, 630 lbs in the downward direction from the surface (might buckle the tubing) – BAD idea 2) Apply 583 psi to the casing annulus to achieve the same 8, 630 lbs in the downward direction 583 psi X 14. 81 sq. in = 8, 630 lb

FORCES ACTING ON TUBING Forces are caused by pressure and temperature changes Four main causes of forces on tubing • Piston Effect (pressure pushes sealing sub out of permanent packer) • Pressure (Helical) Buckling (Corkscrew of tubing shortens length) • Ballooning Effect (expansion of tubing diameter shortens length) • Temperature Effect (lower temp shortens tubing hotter temps lengthen tubing)

Piston Effect and Pressure (Helical) Buckling mainly concern Permanent Packers Ballooning Effect and Temperature Effect mainly concern Retrievable Packers

Forces change length of tubing Same mechanism as a spring. Pull on spring and it lengthens. Release tension and spring returns to original length Description of this effect is called: Hooke’s Law F = -kx where F is force, k is spring constant and x is the length This is for ONE DIMENSIONAL objects (long and skinny)

Elastic and Plastic Deformation Hooke’s Law only works for elastic deformation Pull the spring too hard and it will NOT return to original length = plastic deformation F plastic elastic Pull too hard and break Longer than before stretch x

For three-dimensional solids Hooke’s Law changes STRESS = F/A (equivalent of force) STRAIN = ∆L/L (fractional change in length) STRESS = -E x STRAIN (lbs) (sq. in. ) (in) E = Young’s Modulus (psi) For steel = 3 x 107 psi

Example: 10’ long steel rod being pulled on with 1000 lbs force that has a cross section of 1 sq. in. (about the size of your index finger) 1000 ft rod pulled by 1000 lbs would stretch by 0. 4”

If we look at the acidizing job described in the text (Figure 8. 9): Initial conditions Packer set at 14, 400 feet Tubing and annulus filled with 9 lb/gal saltwater No PUMP pressure on either tubing or casing Acidizing conditions Annulus – no change to fluid – 2, 500 psi pump pressure Tubing – 9. 5 lb/gal acid pumped at 6, 000 psi on surface

Piston Effect Change in length due to pressure difference above and below the packer: -116. 6” About 10 feet.

Helical (pressure) Buckling Change in length due to “squirm” in the tubing -33. 1” About 3 feet.

Ballooning Change in length due to “bulge” in the tubing (like a balloon) -24. 3” About 2 feet.

Temperature Effect (Thermal Expansion) Where β is the Coefficient of Thermal Expansion For steel β = 6. 9 x 10 -6 Take note of these expansion joints when looking at piping runs

Back to the acid job: 74 °F 70 °F We work with the AVERAGE temperature of the tubing: Before Tavg = 182 °F After Tavg = 80 °F = 10. 1 feet = - 121. 6 in 290 °F Before 90 °F During

Total length change of tubing during acid job: = -111. 6 – 33. 1 – 24. 3 – 121. 6 = -290. 6” = -24. 2 feet

Anchored Tubing is latched to the packer Or Packer is retrievable In BOTH cases the length change you calculate is converted into a FORCE using the defining equation for the Young’s Modulus PISTON EFFECT and HELICAL BUCKLING are IGNORED

becomes

Back to our Acidizing Example If tubing is latched: Calculated change in length (ignoring piston effect and helical bucking) is: ∆L = -29. 3 -121. 6 = -145. 9 This means that the force on the tubing (tension) is

Back to our Acidizing Example The weight of the tubing is given by: W = 14, 400 ft x 6. 5 lb/ft : (tubing weight from table) = 93, 600 lbs The tension pulls UP on the tubing at the bottom of the well BUT the tension pulls DOWN at the tubing hanger Recall that if this were a weight set packer set with a force of 7000 lbs the 45, 000 tension force would pull the packer free of the casing.

Back to our Acidizing Example At the tubing hanger then: The total force on the tubing is: 45, 900 + 93, 600 = 139, 000 lbs The yield strength is only 145, 000 lbs which is too close to the edge.

Permanent Packer Calculations 1) If the tubing is NOT latched then ∆L must be calculated to make sure you have enough sealing sub length. 2) Temperature changes cause length changes and all such changes need to be calculated using ∆T expression 3) Prevent helical buckling by applying pressure to the casing annulus