Predicting Wellbore Dynamic-Shock Loads Prior to Perforating SPE

Transcription

1 Predicting Wellbore Dynamic-Shock Loads Prior to Perforating SPE Jack Burman/Exploitation Technologies, LLC/SPE; Martin Schoener-Scott, Cam Le, and David Suire/Halliburton/SPE

2 Agenda Software Overview Validation Example Case Histories Comparing the Cases Conclusions 2

3 Dynamic-Shock Modeling Software Simulation software that focuses on dynamic loading of tubulars, packers, casing and other completion equipment. Inception 2003 SPE

4 Other SPE Papers SPE OTC

5 Physics Based Model Tool burn Navier-Stokes equation transient mixed-phase compressible fluid flow in well Transient Bernoulli choke flow for perfs Fracture mechanics frac initiation and propagation Wave equation elastic solids in equipment string Transient layered Darcy flow formation Tubing, Packers, etc. Energized Zone Energy Source (Perf Gun) Possible Surface Over or Under-Pressu re Wellbore Fluids Fluid Motion In/Out of Perfs/Fracs Fluid motion in Well, Tubing 5 Basic Wellbore Geometry

6 Dynamic Failure Modes Tubing - Comp and Tension - Burst and Collapse - Bending Packer - Axial Loads - Differential Failure Casing - Burst Guns - Comp and Tension - Burst and Collapse Bridge Plug/Sump - Axial Loads - Differential Failure 6

7 Dynamic Loads Tubing - Solid loads above and below packer - Drag inside and outside Packer - Pressures - Solid loads Casing - Pressures Bridge Plug/Sump - Pressures Guns - Solid load - Pressures internal and external - Drag inside and outside 7

8 Validation Example Model Matching New Gun System

9 High Speed Gauge 1-11/16 OD x 50 (22 lbs) Additional 17 with Shock Mitigator 30,000 psi (peak), 30,000 psi (static) +/-50,000 G s of Acceleration 4,000,000 data points 150 C Sampling Rate (High, Intermediate, and Slow Speeds) 115,000 data points/second, and down to one sample every 10 seconds 9

10 5 ¾ 18spf HSD Mirage RDX What dynamic loads are to be expected during gun detonation? 10

11 Well 1 Initial overlay with original geometry 11

12 Well 1 Overlay with update geometry 12

13 Well 1 Overlay with adjusted gun remnant and permeability 13

14 Well 2 Initial overlay 14

15 Well 2 Overlay with adjusted gun remnant and permeability from well 1 15

16 Well 1 Pre-Job Model Post-Job Model 257 kips downward 206 kips downward 273 kips upward 395 kips upward 16

17 Well 2 Pre-Job Model Post-Job Model 174 kips downward 138 kips downward 391 kips upward 273 kips upward 17

18 Lessons Learn New gun system characteristic of retaining explosive energy in these conditions Loads were over predicted in initial models Longer gun assembles can be run without much concern To match FastGauge Data in late time adjustment to perm was require to match the actual reservoir response Confirm by feedback from customer's production data 18

19 Case Histories

20 Location Gulf of Mexico, East Breaks (EB) and Garden Banks (GB). EB GB Geographic distribution of 2008 discoveries by water depth 20

21 Shrouded Firing Head Time Delayed Firing Head High Strength Shroud Double Pin Connector 6 ½ Gun System 14spf 21

22 GB Case 1: Stage 1 motion, packer load, tubing compression, and tension Packer Packer movement Movement Tubing movement 9 5/8 in. packer 1-10 ft pup joint 3 ½ in #/ft P-110 tbg Below packer safety joint 1-10 ft pup joint 3 ½ in #/ft P-110 tbg 3 ½ in. fill disc assembly 1-30 ft joint 3 ½ in #/ft P-110 tbg Shrouded firing head assembly Top shot 19750ft. 43 ft loaded 6 ½ in 14 spf RDX Super Hole Sump packer 10 ft below bottom shot BHP 10000psi PBTD 246 ft below bottom shot Packer loading - 319k Tubing compressive loading 345k 22

23 Case 1: Stage 1 pressure at specific locations (nodes) in the wellbore Bottom perforations 9 5/8 in. packer 1-10 ft pup joint 3 ½ in #/ft P-110 tbg Below packer safety joint 1-10 ft pup joint 3 ½ in #/ft P-110 tbg 3 ½ in. fill disc assembly 1-30 ft joint 3 ½ in #/ft P-110 tbg Shrouded firing head assembly 43 ft loaded 6 ½ in 14 spf RDX Super Hole Sump packer 10 ft below bottom shot PBTD 246 ft below bottom shot Top perforations Differential pressure at the packer 1700psi 23

24 Case 1: Stage 1 average pressure in perforated interval Peak pressure in perforated interval 15268psi Initial wellbore pressure Formation pressure 9 5/8 in. packer 1-10 ft pup joint 3 ½ in #/ft P-110 tbg Below packer safety joint 1-10 ft pup joint 3 ½ in #/ft P-110 tbg 3 ½ in. fill disc assembly 1-30 ft joint 3 ½ in #/ft P-110 tbg Shrouded firing head assembly 43 ft loaded 6 ½ in 14 spf RDX Super Hole Sump packer 10 ft below bottom shot PBTD 246 ft below bottom shot 24

25 GB Case 2: Stage 3 Iteration 2 9 5/8 in. packer 3-10 ft joint 3 ½ in #/ft P-110 tubing Below packer safety joint 6-10 ft joint 3 ½ in #/ft P-110 tubing 3 ½ in. fill disc assembly Shrouded firing head assembly Top shot 21509ft 60 ft loaded 6 ½ in. 14 spf RDX Super Hole Frac pack packer 10 ft below bottom shot with packer plug installed 25

26 EB Case 3: Iteration 1 initial proposed BHA 9 5/8 in. packer 1-10 ft pup joint 3 ½ in.12.95#/ft P-110 tbg 3 ½ in. fill disc assembly 1-30 ft joint 3 ½ in #/ft P-110 tbg Shrouded firing head assembly Top shot 7500ft MD 30 ft loaded 6 ½ in. 14 spf RDX Super Hole PBTD 84 ft below bottom shot 26

27 Case 3: Iteration 2 with addition of BPSJ and tubing 9 5/8 in. packer 1-30 ft joint 3 ½ in.12.95#/ft P-110 tbg Below packer safety joint 1-30 ft joint 3 ½ in #/ft P-110 tbg 3 ½ in. fill disc assembly Shrouded firing head assembly Top shot 9102ft 30 ft loaded 6 ½ in. 14 spf RDX Super Hole PBTD 84 ft below bottom shot Compressive 8,990-8,991 Bending in 8,990-8,992 27

28 Case 3: Iteration 3 with additional 60 ft of tubing& all tubing joints where changed to 10 ft pup joints 9 5/8 in. packer 6-10 ft pup joint 3 ½ in.12.95#/ft P-110 tbg Below packer safety joint 3-10 ft pup joint 3 ½ in #/ft P-110 tbg 3 ½ in. fill disc assembly 3-10 ft pup joint 3 ½ in #/ft P-110 tbg Shrouded firing head assembly 30 ft loaded 6 ½ in. 14 spf RDX Super Hole PBTD 84 ft below bottom shot 28

29 Slide 28 AS1 This doesn't seem clear. Adrienne Silvan, 5/5/2011

30 Comparing Case 1 Stage 1 with Case 3 Iteration 2: Pressures at Selected Nodes 15,400 psi 21,600 psi 1,700 psi differential at packer 3,200 psi differential at packer Case 1 Stage 1 Case 3 Iteration 2 29

31 Comparing Case 1 Stage 1 with Case 3 Iteration 2: Average Pressures in Perforated Interval 15,268 psi 15,246 psi 9,994 psi reservoir 5,878 psi reservoir Case 1 Stage 1 Case 3 Iteration 2 30

32 Comparing Case 1 Stage 1 with Case 3 Iteration 2: Rat Hole 246 ft 84 ft Case 1 Case 3 31

33 Comparing Case 1 Stage 1 with Case 3 Iteration 2: Summary Higher peak pressures Higher packer differential Lower BHP Less rat hole volume 32

34 Conclusions An experienced modeler can predict dynamic behavior during a perforating event. Dynamic behavior is not always intuitive. Eliminate potential problems before execution. 33

35 Burning Questions What Do You Think 34