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PNGE 420

Project 1

October , 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Abstract:

For this project a proposed oil well in the Lipscomb E Morrow Lo field is to be completed with a packer and tubing design. After designing the tubing and packer configuration the forces and length changes associated with the configuration will be calculated. A strength analysis is also used to test the integrity of the design. During the first portion of the project the well will be considered under natural flow. In the next case the well will be considered to be under fracture stimulation. The well is to have 7 ‘’ casing and will be perforated between 9,973’ – 9,981’.

In order to do this tubing and packer configuration must first be chosen based on the constraints of the well casing flowing pressure and other constraints of the well. Once all of the necessary data has been collected the design calculations can commence. All of the forces that are exerted on the packer and tubing will be calculated as well the length changes that are associated with each force. Once this has been completed it will then be possible to determine the total forces and length changes. Lastly the stress associated with the forces placed on the design configuration can be calculated and compared to the design limitations of the tubing and packer.

 

 

 

 

 

Problem Statement:

The objective of this project was to design a packer completion set up based upon a well situated in a field of choice. The forces and length changes of the tubing will be calculated under natural flow and stimulation treatment. The design limitations of the packer and tubing will be tested to ensure the design configuration is safe.

 

 

 

 

 

Geology:

Below is a list of the formations. The producing formation of the well is the Lower Morrow.

 

Base Heebner:            6,176’

Tonkawa Sand:            6,818’

Cleveland Sand:          7,842’

Oswego:                      8,610’

Upper Morrow:           9,428’

Lower Morrow:           9,973’

 

 

 

Location:

The well is located in the Lipscomb E Morrow Lo field located in Hemphill County, Texas

 

 

 

 

 

 

 

 

 

 

 

Packer Selection:

For the design a mechanically set packer will be chosen, with a rating of 10,000 psi, for its ability to be retrieved as well as its tough yet economical design. It should be noted that the casing size of the well is 7’’ and the tubing is 2 7/8’’.

Approach:

In order to develop an approach to solving the design problem the size of the tubing, packer and casing must first be considered.

 

 

 

Once this is completed the areas needed to solve the problem can be calculated as shown below.

 

 

Next consider the production data of the well in order to determine the density of the oil and water mix that will be produced.

 

 

Next all the necessary pressures will be calculated from the following equations.

 

 

 

With this complete the Piston effects can be considered from the following equations.

 

 

 

Next the Buckling Effect can be determined from the following equations

 

 

 

 

Note* n must be calculated in order to determine if the length needs to corrected for the neutral point.

 

 

The next step is to determine the Ballooning Effect from the following equations.

 

 

 

Now the temperature effect will be considered by utilizing the fooling equations below.

 

 

 

The Mechanical Effect will be considered from the following equations. Where Fs (Slack Off Force) will be considered based upon the result of the other forces.

 

 

With all the forces and length changes calculated the sum of each can now be determined from the following equations.

 

 

Last the tubing strength analysis can be done from the following equations.

 

 

 

 

 

Results for Natural Flow:

 

Force (lbs)   Length (in)   Stress (psi)
F1 -880.133   ∆L1 -1.56582   Ss -32872
F2 0   ∆L2 -1.31682   σa 5229.682
F3 5026.318   ∆L3 8.94216   σb -22983.1
F4 25656.55   ∆L4 45.64474   Si 24422.84
Fs -30000   ∆LS -41.8083   So 28027.18
Fp -197.264   ∆Ltotal 9.895938      
Fa -11982.6            
FTJ 66394.1            

 

Results for Fracture Stimulation:

 

Force (lbs)   Length (in)   Stress (psi)
F1 -16923.3   ∆L1 -30.1077   Ss 43829.38
F2 0   ∆L2 -22.8339   σa -5909.92
F3 -13987.7   ∆L3 -24.8851   σb 8029.619
F4 -51313.1   ∆L4 -91.2895   Si 29002.34
Fs 40000   ∆LS 88.5568   So 20983.39
Fp -42224.1   ∆Ltotal -80.5593      
Fa -28905.9            
FTJ 91497.64            

 

Conclusion:

In conclusion the design limitations will be briefly discussed. The results indicate that the tubing chosen, N80* 7.8 #/ft OD 2.875 in ID 2.323 in will sufficient for the pressures and forces (summarized above) associated with the well. The strength of the tubing is 80,000 psi, the Collapse rating is 13,890 psi, the Burst Rating is 13,440 psi, and the Tension Strength is 180,300 lbs. since all of the stresses calculated are less than 80,000 the tubing should be strong enough to sustain the stress of natural flow as well as fracture stimulation. It should however be noted that this project focuses around one producing formation. However, it is most likely that we as students will encounter a more complex well configuration that encompasses many producing formations which will greatly increase the complexity of the design configurations. Therefore a life-long lesson should be taken away from this project that one should always design the tubing, packer and other equipment to encounter forces not immediately foreseen in the initial design process.

References:

 

  • Class Notes for Production Engineering (Dr. H.I. Bilgesu, PNGE 420 Fall 2010)
  • Railroad Commission of Texas, Oil & Gas Well Records, http://www.rrc.state.tx.us/
  • Halliburton Packer Catalog http://www.halliburton.com/public/cps/contents/Books_and_Catalogs/web/CPSCatalog/Sect_06_Packers.pdf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appendix A: Forces and Length Changes Due to Production under Natural Flow

 

Initial Conditions

 

Fluids:                          9.5 ppg inside tubing

9.5 ppg inside annulus

 

Temperature:              180˚ F Bottomhole

70˚ F Wellhead

 

Pressure:                     Casing 0 psi

Tubing 0 psi

 

Final Conditions

 

Fluids:                          7.11 ppg inside tubing

9.5 ppg inside annulus

 

Temperature:              180˚ F Bottomhole

180˚ F Wellhead

 

Pressure:                     Casing 1950 psi

Tubing 1630 psi

 

 

 

 

 

 

 

 

Piston Effects

 

 

 

 

Buckling Effect

 

 

 

 

 

 

 

 

 

 

Since  the length does not need to be corrected for the neutral point.

 

 

 

Ballooning Effect

 

 

 

 

 

 

 

 

 

 

Temperature Effect

 

 

 

 

 

 

 

 

Mechanically Applied Effect

 

 

 

 

Total Forces and Length Changes

 

 

 

 

Tubing Strength Analysis

 

The tubing chosen for the design was N80* OD 2.875 in ID 2.323 in 7.8 lbs/ft. The Yield Strength is 80,000 psi with a Burst Pressure of 13,440 psi, a Collapse Pressure of 13,890 psi, and Tensional Strength of 180,300 lbs.

 

Burst and Collapse Forces

 

Resultant Pressure of top of casing = 1,950 psi – 1,630 psi = 320 psi

Resultant Pressure of bottom of casing = 6,877 psi – 5,317 psi = 1,560 psi

Since the Collapse Pressure is 13,890 >> 1,560 and 320 the design is adequate.

 

Tension Force at Top Joint

 

 

 

Since 180,300 lbs > 66,394 lbs the design is adequate.

 

Stress due to Slackoff Weight

 

 

Since the tubing yield strength is 80,000 the design is adequate.

 

Stress at the Inner Wall of Tubing due to Pressure and Temperature

 

 

 

Since 24,423 psi < 80,000 psi the design is adequate.

Stress at the Outer Wall of Tubing due to Temperature and Pressure

 

 

Since 28,027 psi < 80,000 psi the design is adequate.

 

 

Appendix B: Forces and Length Changes Due to Fracture Stimulation

 

Initial Conditions

 

Fluids:                          7.11 ppg inside tubing

9.5 ppg inside casing

 

Temperature:              180˚ F Bottomhole

180˚ F Wellhead

 

Pressure:                     Casing 1,950 psi

Tubing 1,630 psi

 

Final Conditions

 

Fluids:                          12.2 ppg inside tubing

9.5 ppg inside casing

 

Temperature:              70˚ F Bottomhole

70˚ F Wellhead

 

Pressure:                     Casing 2,400 psi

Tubing 6,500 psi

 

 

 

 

 

 

 

Piston Effects

 

 

 

 

Buckling Effect

 

 

 

 

 

 

 

 

 

Since  the length does not need to be corrected for the neutral point.

 

 

 

 

Ballooning Effect

 

 

 

 

 

 

 

 

 

 

Temperature Effect

 

 

 

 

 

 

 

 

 

Mechanically Applied Effect

 

 

Total Forces and Length Changes

 

 

 

 

Tubing Strength Analysis

 

The tubing chosen for the design was N80* OD 2.875 in ID 2.323 in 7.8 lbs/ft. The Yield Strength is 80,000 psi with a Burst Pressure of 13,440 psi, a Collapse Pressure of 13,890 psi, and Tensional Strength of 180,300 lbs.

 

Burst and Collapse Forces

 

Resultant Pressure of top of casing = 6,500 psi – 2,400 psi = 4,100 psi

Resultant Pressure of bottom of casing = 12,827 psi – 7,327 psi = 5,500 psi

 

Since the Collapse Pressure is 13,890 >> 5,500 and 4,100 the design is adequate.

 

Tension Force at Top Joint

 

 

 

 

 

Since 180,300 lbs > 91,497 lbs the design is adequate.

Stress due to Slackoff Weight

 

 

Since 43,829 pai < 80,000 psi the design is adequate.

 

Stress at the Inner Wall of Tubing due to Pressure and Temperature

 

 

 

Since 29,002 psi < 80,000 psi the design is adequate.

 

Stress at the Outer Wall of Tubing due to Temperature and Pressure

 

 

 

Since 20,983 psi < 80,000 psi the design is adequate.

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