1. Why Is It Getting Harder To Inject – Is It Just Skin Damage Or Is The Disposal Neighborhood Becoming Too Crowded? Presented by: Ken Johnson Environmental Engineer (214) 665-8473 Johnson.ken-e@epa.gov EPA Region 6 May 6, 2015

2. What Makes Injection Well Pressure Change When Injecting? Total Well Bottom Hole Pressure Response = Static Reservoir Pressure + Wellhead Pressure + ∆P hydrostatic wellbore column - ∆P wellbore friction loss - ∆P completion skin factor pressure drop -∆P reservoir rock pressure drop + ∆P reservoir boundary pressure increase Think about it as a dynamic system of pressure responses with some taking longer to influence well behavior than others! 2

3. The “Inner” and “Outer” Limits Outer Limits  Occur out in the reservoir away from the well  Examples  Offset injection and production wells  Drastic change in reservoir rock and fluid properties  Faults or pinchouts  Natural fractures Inner Limits  At or around the wellbore  Examples:  Wellbore friction loss  Completion skin factor  Wellbore hydrostatic column 3

4. Injection Well / Disposal Zone “System” – “Inner Limits”  Have an immediate impact on injection pressure  Tubing Friction Loss Combination of injection rate, tubing ID, and tubing roughness or friction factor Smaller tubing means more friction loss  Skin effect (S) due to completion conditions Changes from test to test Shows up as any pressure drop downstream of gauge location but upstream of reservoir rock Negative skin factor means a “system enhancement”  Gives the effect of a larger wellbore  Examples - hydraulic fracture, acid treatment, coiled tubing cleanout, or reperforating Positive skin factor means a “system restriction”  Results in a smaller effective diameter for wellbore  Examples - clogged perforations, invaded zone immediately around the wellbore by dirty fluid, partial penetration, well fill, or poor perforating job 4

5. Injection Well / Disposal Zone “System” – “Inner Limits” cont.  Wellbore hydrostatic column  Contolled by wellbore fluid density and depth of completion zone  Wellhead injection pressure  Constrained by permit conditions  Constrained by plant disposal needs, site storage capacity and pumping equipment 5

6. Inner Limit Pressure Losses  Tubular Friction Loss- Hazen-Williams Correlation  Several other options – empirical correlation from well-specific testing, Colebrook equation  ∆P friction = 0.433*L*(4.52*Q 1.85 )/(C 1.85 *d 4.87 ) in psi Q is rate in gpm, L is pipe length in ft, C is pipe roughness coefficience, d is inside pipe diameter in inches  Skin Factor, S  ∆P skin = 0.87*m*S = 0.87*(162.6*Q*β*µ/k*h)*S in psi Kh/µ is transmissibility in md-ft/cp, Q is rate in bpd  Skin pressure drop is rate dependent! 6

7. Injection Well/Disposal Zone “System” – “Outer Limits”  Have a long term impact on injectivity  A. Pressure drop through reservoir rock Long term timeframe – hours, days, months or years Function of: opermit conditions and actual operational needs oreservoir nature and rock and fluid properties  B. Reservoir boundaries or restrictions Make it more difficult to inject long term – months or years Offset injection wells oCan be any class of injector completed in the same reservoir oInfluence depends on a combination of reservoir properties (k, h, φ, c t, μ w ), distance, and injection rate Fault or pinchout or reduced net thickness 7

8. Two Kinds of Pressure Buildup Reservoir Models – Analytical or Finite Difference Analytical  Describe reservoir fluid behavior with single analytical equation  E.g., Radial diffusivity equation; Hydraulic vertical fracture; and dual porosity  Reservoir properties’ variability limited or constant  Easier to set up and run  Allow for combinations of various inner (at well) and outer (in reservoir) boundary conditions  E.g., skin, fracture, sealing fault (from SPE 10043) Finite Difference  Use a grid to break reservoir up into discrete reservoir volume “blocks”  Differential equations describing fluid flow between blocks solved with numerical solution methods  Handle complex reservoir geology, fluid and rock properties and well conditions in more detail  More difficult to set up  Can be computationally intensive (From SWIFT Manual) 8

9. Analytical Modeling for Long Term Reservoir Pressure Behavior  May be easier to set up and run than a finite difference (gridded) model  No issues with computational demands for a large number of grid blocks  Assumes constant reservoir rock and fluid properties  K, h, viscosity, compressibility, and porosity are all constant  Flat or constant dip reservoir  Faults usually modeled as sealing and infinitely long  Can use streamlines for faults  Can be run with or without skin effects at primary injection well  Available as a stand alone tool or as part of well test analysis software  Examples – Pansystem, TRANS II, SAPHIR, PIE, PHIST/Interact, DuPont Pressure Buildup Model, ect 9

10. Analytical Reservoir Model: “Kitchen Sink” Equation for Pressure Buildup at any Reservoir Point 10 Accounts for reservoir properties, multiple wells, boundaries, and rates at any point in the reservoir at any time! Requires a method for calculating Ei, the exponential integral Skin factor has no impact on pressure buildup away from the injection well! Multiple offset injectors have a “stacking” or group impact on reservoir pressure buildup Faults are modeled as “image” wells and have the effect of an offset injection well

11. Finite Difference Modeling for Reservoir Pressure Behavior  Handle geology and fluid and rock property issues more rigorously than an analytical model  Structural dip allowed  Varying net thickness  Varying permeability (if data available)  Can place faults in model as mapped with limited extents  Adjusts for reservoir fluid property changes with temperature and pressure (sometimes)  May handle multiphase conditions CO2, natural gas, brine, oil injection or withdrawal  Can handle many offset wells  Examples – SWIFT, ECLIPSE, BOAST, Sensor, INTERSECT, GEM, IMEX, ect.  Finite Element Models used as part of well test analysis software can also do some of this  PanMesh, SAPHIR, ect. 11

12. Injection Well Data “Clues” Without the Fancy Models  Review of Disposal Zone Geology – Know the “neighborhood”  Are faults present and if so, how far away?  Is reservoir thickness thinning away from the well?  What other injectors are within 10 miles of yours in the same interval?  Are new injectors being completed in your disposal zone?  Review Pressure Transient Tests – Falloffs and Injectivity  Look at skin factor Is it becoming more positive? Identify sources of positive skin  Is kh/u changing or remaining consistent? Flow profile change due to fill or completion modifications  Are boundaries present on test plots?  Plot flowing and static bottom hole pressure measurements yearly to identify trends Correct flowing bottom hole pressures for skin effects Use a common subsea datum for plotting 12

13. Injection Well Data “Clues” Without the Fancy Models cont.  Review Radioactive Tracer Surveys  Is fill depth rising and covering portions of completed interval?  Is flow profile consistent from year?  Is fluid staying in the injection interval?  Review Operational Data  Injection Pressures and Volumes can be used to assess behavior Continuous monitoring for Class I wells Monthly program reported operating data available for Class II wells  Prepare Operational Data Diagnostic Plots 4 types of plots: oRaw Data (pressure and volume); Operating Gradient; Hall Integral and Derivative; and Silin Slope Plot oFits operational data to a flow behavior model  Identify skin changes, induced fracturing, boundaries oCan be done in Excel 13

14. Monitoring Plots  Raw Operational Data  Plot daily volume and average pressure versus date  Look at trends  Hall Plot with Derivatives  Requires measure, estimate or assumption of static reservoir pressure  Can show increased ease of or difficulty of injection  Can show long term boundary effects or increasing skin effects  Operating Gradient Plot  More useful for Class II wells to see if fracture gradient is being exceeded 14

15. Example Operational Data Plots 15

16. Operating Gradient Plot 16

17. How to Build a Hall Integral with Derivatives Plot  X axis is W i, cumulative water injection in units of barrels  Y axis has 2 functions associated with it:  Hall integral, H i = Ʃ (P wf -P static )*Δt where P wf is average bottom hole injection pressure over a time increment of Δt oThe time increment can be hours, days, weeks, or months An injection volume associated with the time increment is added to obtain a W i value on the X axis  Hall derivative, D i1 = (H i2 -H i1 )/(Ln(W i2 )-Ln(W i1 )) H i2 -H i1 represents the difference between successive Hall integral values Ln(W i2 )-Ln(W i1 ) represents the difference between successive cumulative water injection values 17

18. Anatomy of a Hall Integral with Derivatives Plot 18 Ease of injection increases when Hall Derivative response falls below the Hall Integral response Ease of injection decreases when derivative is above integral enhanced injectivity From Yoshioka et al 2008

19. Example Hall Integral with Derivatives Plot 19

20. Let’s Look at 2 Hypothetical Injection Well Situations  Reservoir Conditions:  P static = 1500 psi  k = 100 md; h = 100 ft; Φ = 30%; μ = 0.5 cp; c t = 6x10 -6 psi -1  Scenario 1: “THE OPEN RANGE NEIGHBORHOOD”  Permit life = 10 years; Maximum Q = 300 gpm (10,285 bpd); S= 0; rw = 0.292 ft (7 in. casing)  Annual 100 hour falloffs at end of each year  No other injectors in the neighborhood, No faults present  Scenario 2: “ THE OVER DEVELOPED NEIGHBORHOOD ”  Injector 1 same conditions as scenario 1  1 sealing fault 2 miles away from injector 1  4 offset injectors on opposite side of injector 1 from the fault All offset injectors at 200 gpm i2 starts after 2 years 2 miles away; i3 starts after 3 years at 3 miles away; i4 starts at 5 years 4 miles away; and i5 starts at 6 years and 7 miles away 20

21. Scenario 1 – Injector 1 Flowing and Static Pressures from Falloffs over 10 Years 21

22. Scenario 1 – Hall Plot 22

23. 23 Scenario 2 Layout – Lots of “Neighbors” 2 miles 8 miles I2 I3 I4 I5 Facility Injector 1 mile Sealing Fault 3 miles

24. 24 Scenario 2 – Injector 1 Flowing and Static Pressures from Falloffs over 10 Years

25. Scenario 2 – Hall Plot 25

26. So How Far Away Does An Offset Injector Have To Be To Affect My Well? Requires a combination of time, reservoir conditions, rate, and distance Let’s look at an example: An injector is located 5 miles from my facility, has operated for 10 years, and generally injects around 5000 bpd (145.8 gpm) How long before it impacts my well? Reservoir conditions: k= 100 md, 100 ft net thickness, c t = 8 x 10 -6 psi -1, μ= 1cp, Ф=30%, offset rw=0.3 ft, and 10 years of offset well operation Using a dimensionless variable approach from SPE Monograph 5, Appendix C to calculate pressure buildup effects: t D =0.0002637*k*Δt/(Ф*μ*c t *r w 2 ) t D =0.0002637*(100 md)*(87,600 hrs)/(0.30*1 cp* 8 x 10 -6 psi -1 *(0.3 ft) 2 ) = 10,069,450,000 26

27. Offset Injector Effects cont. r D =r/r w r D =(5 miles*5280 ft/mile)/(0.3 ft)=88,000 t D /r D 2 =10,069,450,000/(88,000) 2 =1.381 P D =1/2(Ln(t D /r D 2 )+0.80907) P D =1/2(Ln(10,069,450,000/(88,000 2 ))+0.80907) P D =1/2(Ln(1.381)+0.80907)=0.5659 Offset Injector ΔP at your injector =141.2*Q*β*P D *μ/(k*h) Offset Injector ΔP at your injector =141.2*5000 bpd*1 STB/RB*0.5659*1cp/(100md*100ft) Offset Injector ΔP at your injector =39.9 psi 27

28. How Do I Monitor My Injector’s “Neighborhood?”  Know the geology of your well’s “neighborhood”  Identify faults – where, orientation, and how far away  Know who your injector “neighbors” are  Monitor who else is completing injectors in the same correlative interval within several miles of the facility  “Neighborhood extent” is a function of time, rate, distance, and reservoir conditions  Know your petition pressure buildup demonstration value  Plot and track falloff annual injection and static bottom hole pressures Used to verify petition compliance with pressure buildup model Can identify upward trend in static reservoir pressure 28

29. How Do I Monitor My Injector’s Condition cont.  Review recent annual radioactive tracer surveys to identify changes at wellbore  Profile change  Change in fill levels  Review recent annual falloff results  Assess any changes in kh/u and S Note if S is increasing  Use operational data to assess well behavior  Hall Integral with Derivatives plot can identify changes in ease of injectivity Can reflect impact of both boundary effects and skin factor changes 29

30. Summary  An injection well’s injection pressure is the net of several responses  Some are at the wellbore and others out in the reservoir  Reservoir or “outer limit” pressure response components can take weeks, months, or years to impact a well’s injecting bottom hole pressure  Faults  Offset wells  Wellbore or “inner limit” pressure response components have an immediate impact on bottom hole injection pressure  Skin factor change  Increased tubing size  Additional net thickness perforated 30

31. Summary cont.  Use Available Tools and Information to Assess Injectivity Changes  Falloffs for static and injection pressures Critical for active petition compliance Know the pressure buildup limit in the petition model  Tracer surveys for profile conditions  Operational data diagnostic plots for long term injection behavior  Area geology to identify faults  Monitor offset injection well activity in same injection zone for several miles around facility Can lead to need for a reissuance 31

32. References  “Transient Well Testing,” SPE Monograph 23, Medhat Kamal, 2009  “Advances in Well Test Analysis,” SPE Monograph 5, R.C. Earlougher Jr., 1977  “Well Testing,” SPE Textbook Series Vol.1, John Lee, 1982  “Real Time Performance Analysis of Water-Injection Wells,” SPE Paper 109876-MS, Izgec and Kabir, 2007  “Identification and Characterization of High-Conductive Layers in Waterfloods,” SPE Paper 123930-PA, Izgec and Kabir, 2011  Cameron Hydraulic Data: Ingersoll-Rand Company, Westaway, C.R. and A.W. Loomis, 1977  Managing and Minimizing Potential Impacts of Injection- Induced Seismicity From Class II Disposal Wells: Practical Approaches, EPA UIC NTW Report, February 2015, http://www.epa.gov/r5water/uic/ntwg/pdfs/induced- seismicity-201502.pdf http://www.epa.gov/r5water/uic/ntwg/pdfs/induced- seismicity-201502.pdf 32