petrophysics · formation pressure
RFT / MDT Fluid Gradient — Repeat Formation Test / Modular Dynamics Test
G = (P₂ − P₁) / (TVD₂ − TVD₁)
click formula to derive ↑
Inputs
psi
ft
psi
ft
Description
Computes the in-situ fluid pressure gradient from two RFT or MDT pressure measurements at different TVDs. The gradient directly identifies the fluid type filling the pore space between the two measurement depths and, when multiple fluid phases are present, the intersection of two gradient lines defines the fluid contact depth.
Variables
| Symbol | Unit | Description |
|---|---|---|
| G | psi/ft | Fluid Pressure Gradient |
| P₁ | psi | Formation pressure measured at TVD1. In canonical units (kPa): 1 psi = 6.89476 kPa. Typical reservoir pressures 3000–20000 kPa. |
| TVD₁ | ft | True vertical depth of the first pressure measurement point, in meters (canonical). Shallower of the two measurement depths. |
| P₂ | psi | Formation pressure measured at TVD2. Should be greater than P1 when TVD2 > TVD1 (deeper = higher pressure for a normal hydrostatic column). |
| TVD₂ | ft | True vertical depth of the second measurement point. Should be deeper than TVD1 so that TVD2 > TVD1. |
Assumptions
- Formation is at hydrostatic equilibrium — no flowing conditions, pressure transients, or depletion between the two measurement points
- Both measurements are in the same fluid phase — if TVD1 is in gas and TVD2 is in oil, the gradient will not represent either fluid individually
Limitations
- Dynamic formation pressure (during flow testing) will not give a true hydrostatic gradient — only static (shut-in) pressures should be used for fluid identification
- In transition zones (capillary-pressure dominated), the gradient changes continuously with depth and a two-point average may misidentify the fluid
Use Cases
- → Oil-water contact (OWC) or gas-oil contact (GOC) identification: Fit two gradient lines (one per fluid phase) through multiple MDT points across a suspected contact; their intersection gives the contact depth to within a few feet.
- → Depletion and communication assessment: Pressure gradients from different reservoir compartments in the same field give the same fluid gradient if connected, but different absolute pressures — gradient matching confirms same fluid with different depletion.
- → Well-to-well pressure and contact comparison: Compare gradients and absolute pressures from new appraisal wells against the discovery well MDT survey to assess lateral continuity and pressure communication across faults.
Related Calculations
Region Notes
Permian Basin
Wolfcamp/Spraberry RFT: brine gradient 0.44–0.46 psi/ft; oil gradient 0.37–0.40 psi/ft. OWC commonly identified at 0.5–5 psi gradient-line intersection; depletion spreads are 200–800 psi across compartment boundaries.
Delaware Basin
Bone Spring and Wolfcamp: oil gradients 0.36–0.40 psi/ft; dense brine 0.45–0.47 psi/ft; high compartmentalization means MDT gradients are essential for mapping OWC.
Gulf of Mexico
GOM gas sands: gradient 0.08–0.12 psi/ft; brine 0.465 psi/ft. Gas-water contacts are very sharp in high-quality deepwater reservoirs; contact depth typically within 2–5 ft of log-based prediction.
Eagle Ford
Eagle Ford oil window: gradient 0.37–0.41 psi/ft; GWC gradient separation 0.10–0.15 psi/ft in gas cap areas. MDT surveys are less common in tight completions but used on key appraisal wells.
North Sea
Viking Graben: Brent Group oil gradients 0.36–0.41 psi/ft; Statfjord sandstone has textbook MDT gradient surveys with OWC at −2500 m TVD SS — used in many SPE case studies.
Global
A well-defined gradient requires at least 15–20 m of vertical separation between measurement points; fewer than ~30–50 m of ΔP per fluid phase makes gradient-line fitting uncertain.
References
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