Salt Water Disposal Well — Injection Pressure Fundamentals
UIC Class II rules, frac-gradient limits, Darcy radial flow, Hall plot transmissivity, and induced-seismicity awareness.
1. UIC Class II framework
EPA's Underground Injection Control (UIC) program — codified in 40 CFR Parts 144–148 — classifies disposal wells into six classes. Class II covers wells that inject brine and produced water from oil & gas operations. Most SWD wells are operated under primacy by the state oil & gas regulator (RRC in Texas, OCD in New Mexico, OCC in Oklahoma, etc.).
Class II wells must meet five requirements: (a) authorized by permit, (b) injection below the deepest USDW (Underground Source of Drinking Water), (c) mechanical integrity demonstrated by periodic test (5-yr typical), (d) injection pressure below fracture pressure (typically capped at 0.90 × frac gradient), and (e) monitoring of annulus pressure and injection rate.
2. Frac gradient and BHP limits
Frac gradient Gfrac (psi/ft) is the pressure at which the injection formation will fracture. It depends on depth, rock type, and tectonic stress; typical values:
| Formation | G_frac (psi/ft) |
|---|---|
| Shallow sand (< 3,000 ft) | 0.55 – 0.65 |
| Deep sandstone | 0.65 – 0.75 |
| Shale | 0.70 – 0.85 |
| Tight carbonate | 0.75 – 0.95 |
| Overpressured zone | 0.85 – 1.0+ |
The maximum allowable bottom-hole pressure (BHP) is:
EPA's recommended safety factor SF = 0.90; some states allow 1.00 (i.e., right up to frac pressure) with a documented step-rate test (SRT). Going above SF triggers a permit modification and may require induced-seismicity monitoring.
3. Pressure stack to surface
Surface injection pressure is whatever the pump must supply to deliver fluid at the required BHP after subtracting hydrostatic and adding friction:
Hydrostatic head:
For deep wells, hydrostatic frequently exceeds the required BHP, so the well is "on vacuum" at the surface — pump only needs to overcome friction. Shallow or low-permeability wells run high surface pressure because the hydrostatic head is too small to push fluid into the formation.
4. Darcy radial inflow
Steady-state radial flow from a wellbore into a homogeneous reservoir (oilfield units):
For injection, ΔP = PBHP − Pe (positive — push fluid in). Solve for BHP given a target injection rate. Useful relationships:
- Injectivity index II = q / ΔP (BWPD/psi). Typical SWDs run 10–50 BWPD/psi; below 5 indicates poor formation or high skin.
- kh transmissivity = k × h (mD·ft). The single most useful reservoir descriptor; a 50 mD × 80 ft sand gives kh = 4,000 mD·ft, a "good" SWD.
- Skin s: 0 for ideal well, +5 to +20 for damaged, −1 to −3 for acidized. A 5-unit reduction in skin can cut required ΔP by 30–50%.
5. Hall plot and step-rate test
The Hall plot (Hall, 1963) is a field method to estimate kh of a working SWD without shutting in. Plot cumulative injection ∫(P − P_static) dt on the y-axis vs. cumulative volume ∫q dt on the x-axis. In steady-state radial flow, the slope is:
An increasing slope means worsening skin (scale or fines damage); a decreasing slope means improving injectivity (fracture extension or pseudo-acidizing by the brine itself).
The step-rate test (SRT) is the most reliable way to find frac pressure directly. Inject at progressively higher rates (typically 6 steps over 4 hours) and plot stabilized BHP vs. rate. The plot is two straight lines: the lower-slope line is matrix injection; the higher-slope line is post-frac. The intersection is the fracture extension pressure — your operating limit.
6. Tubing friction
For a typical 3-1/2" tubing at 5,000 BWPD, fluid velocity is ~7 ft/s and friction loss is ~50–80 psi per 1,000 ft. The Darcy-Weisbach equation with Haaland's explicit friction factor:
Where the constant 771.9 = 2·gc·12 with gc = 32.17 lbm·ft/lbf·s² (unit conversions for inches → feet and pound-mass-force balance).
If friction is a meaningful fraction of surface pressure (> 10%), upsizing tubing pays back fast — going from 2-3/8" to 3-1/2" tubing at the same rate cuts friction by ~75%.
7. Induced seismicity
The Oklahoma and West Texas earthquake clusters of 2014–2020 demonstrated that large-volume SWD injection into basement-adjacent formations can pressurize critically-stressed faults and trigger earthquakes (typically M2.5–M5.0). Modern SWD permits in seismically-active areas include:
- Volume caps (often 25,000–40,000 bbl/day per well) and pressure caps below SF = 0.90.
- Avoidance of injection within 5,000–10,000 ft of basement.
- Real-time seismic monitoring with a "traffic light" protocol — yellow at M2.0 (reduce volume), red at M3.0 (shut in).
- Mandatory pressure-decline tests to confirm injection-pressure response is stable.
8. References
- 40 CFR Parts 144–148 — Underground Injection Control program.
- EPA UIC Class II — Permitting and operational guidance.
- Hall, H. N. (1963). "How to analyze waterflood injection well performance." World Oil, Oct 1963.
- Earlougher, R. C. (1977). Advances in Well Test Analysis, SPE Monograph 5.
- Bourdarot, G. (1998). Well Testing: Interpretation Methods, Editions Technip.
- Ellsworth, W. L. (2013). "Injection-Induced Earthquakes." Science 341.
- Texas Railroad Commission — Disposal Well Rules (16 TAC §3.9).