2.3 Formation Integrity Testing (FIT, LOT) & MAASP

When drilling proceeds out of a casing shoe into a new hole section, the formation immediately below the shoe represents the geomechanical weak link of the open-hole wellbore. Because overburden stress and rock compaction increase with depth, shallower formations have lower fracture resistance than deeper rocks. If wellbore pressures become excessive during drilling, circulation, or well shut-in, rock failure will almost invariably initiate at the casing shoe. Accurately testing the mechanical strength of the casing shoe formation and establishing the Maximum Allowable Annular Surface Pressure (MAASP) are vital engineering safeguards in well control.

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The Critical Role of the Casing Shoe

After cementing casing, drilling crews drill through the shoe track, cleaning out 5 to 15 feet (1.5 to 5 meters) of new formation. At this point, the well is shut in and tested to confirm two parameters:

1. Cement Seal Integrity: Ensuring no micro-annular channels exist between casing steel, cement sheath, and rock that could allow fluid communication behind casing.
2. Formation Fracture Strength: Determining the maximum hydraulic pressure that exposed rock immediately beneath the shoe can withstand before fracturing.

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Leak-Off Test (LOT) vs. Formation Integrity Test (FIT)

Industry practice employs two distinct testing methodologies:

The Leak-Off Test (LOT) Profile

An LOT uses a high-pressure cementing unit pumping mud at 0.25 to 0.50 bpm into the closed wellbore while plotting surface pressure versus cumulative volume:

1. Elastic Compression: Mud compresses and casing expands elastically. Surface pressure rises in a straight line with volume.
2. Leak-Off Point (LOP): The inflection where the curve deviates from the straight line, signifying rock tensile failure and micro-fracture initiation.
3. Pump Shutdown & Bleed-Off: Pumping stops immediately at LOP. Stabilized shut-in pressure is recorded, and volume is bled back to confirm recovery.

The Formation Integrity Test (FIT)

In an FIT, operators avoid stressing rock to failure. Pumping proceeds slowly to a predetermined target test pressure calculated from the maximum mud weight planned for the section plus a safety margin. Pressure is held for 10 to 15 minutes; if no drop occurs, the shoe is certified for drilling.

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Calculation of Fracture Gradient and Equivalent Mud Weight (EMW)

The surface leak-off pressure ($P_{\text{lot}}$) recorded during an LOT is converted into downhole formation fracture strength:

Equivalent Mud Weight (EMW) Formula

IWCF's formula sheet calls this result the maximum allowable fluid density.

$\text{EMW} = \text{Test MW} + \frac{P_{\text{lot}}}{0.052 \times \text{Shoe TVD}}$

Where $\text{EMW}$ and $\text{Test MW}$ are in ppg, $P_{\text{lot}}$ is surface leak-off pressure in psi, and $\text{Shoe TVD}$ is in feet ($0.052$ conversion factor).

Downhole Formation Fracture Pressure ($P_{\text{frac}}$) & Fracture Gradient ($FG$)

$P_{\text{frac}} = P_{\text{lot}} + (0.052 \times \text{Test MW} \times \text{Shoe TVD}) = 0.052 \times \text{EMW} \times \text{Shoe TVD}$

$FG = \frac{P_{\text{frac}}}{\text{Shoe TVD}} = 0.052 \times \text{EMW} \quad (\text{in psi/ft})$

Calculation Example

A casing shoe is at 8,000 ft TVD. An LOT conducted with 10.0 ppg mud exhibits leak-off at 1,040 psi surface pressure:

1. $\text{EMW} = 10.0 + \frac{1{,}040}{0.052 \times 8{,}000} = 10.0 + \frac{1{,}040}{416} = 10.0 + 2.50 = 12.50\text{ ppg}$
2. $P_{\text{frac}} = 0.052 \times 12.50 \times 8{,}000 = 5{,}200\text{ psi}$
3. $FG = \frac{5{,}200\text{ psi}}{8{,}000\text{ ft}} = 0.650\text{ psi/ft}$

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Maximum Allowable Annular Surface Pressure (MAASP)

MAASP is the highest permissible surface pressure on the casing gauge before the formation at the shoe fractures, assuming the casing column from surface to shoe is filled with fluid of Current MW:

$\text{MAASP} = (\text{EMW} - \text{Current MW}) \times 0.052 \times \text{Shoe TVD} = P_{\text{frac}} - HP_{\text{shoe, current}}$

Dynamic Impact of Mud Weight Changes on MAASP

Because downhole fracture pressure ($P_{\text{frac}}$) is fixed, increasing drilling mud weight increases hydrostatic head inside casing, leaving less allowable surface pressure before the shoe fractures:

Using our previous example ($\text{EMW} = 12.50\text{ ppg}$, $\text{Shoe TVD} = 8{,}000\text{ ft}$):

• With 10.0 ppg mud: $\text{MAASP} = (12.50 - 10.0) \times 416 = 1{,}040\text{ psi}$
• With 11.2 ppg mud: $\text{MAASP} = (12.50 - 11.2) \times 416 = 540.8\text{ psi}$ Raising mud weight by 1.2 ppg reduces surface safety margin from 1,040 psi to 541 psi.

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Critical Operational Limitations of MAASP During Well Kicks

Blindly adhering to MAASP when gas is in the wellbore is a dangerous well control trap.

The Core Assumption of MAASP

MAASP strictly assumes the annulus between surface and casing shoe is completely filled with a continuous, uniform column of drilling mud at Current MW.

Influx Migration Across the Shoe

1. Gas Below the Shoe: When an influx is below the shoe, the casing remains 100% full of mud. MAASP is valid. If shut-in casing pressure ($SICP$) reaches MAASP, the shoe is at immediate risk of fracturing.
2. Gas Above the Shoe (Inside Casing): As gas migrates into casing and expands, low-density gas ($0.1$ to $0.2\text{ psi/ft}$) displaces high-density mud ($0.5$ to $0.8\text{ psi/ft}$), drastically reducing hydrostatic head above the shoe. Surface casing pressure can rise well above calculated MAASP without exceeding shoe fracture pressure.