18.2 Shut-In Pressure Interpretation in Horizontal Wells

Shut-In Pressure Interpretation in Horizontal Wells

The difference between casing and drillpipe pressure reflects the difference between the two fluid-column heads when the pressure paths communicate and the gauges share a common datum. It is not a direct fluid-composition or hazard measurement in either a vertical or a horizontal well.

An influx confined to a flat lateral replaces little vertical mud head. Consequently, even a substantial gas influx can give $SICP\approx SIDPP$. Equal readings must not be used to conclude that the influx is water or that the well is safe.

The Standard Communicating U-Tube Model

Assume a static well on bottom, clean original mud in the drillstring, no isolated gauge or unaccounted float/trapped pressure, and the influx confined to the flat lateral. There is no additional migration overpressure, loss or crossflow in this calculation. Correct gauge elevations and any subsea fluid heads before comparing readings.

DRILLSTRING                         ANNULUS
Communicating SIDPP                 Communicating SICP
+ known drillstring head            + actual annular head
           \\                         /
            Same bottomhole pressure

Flat lateral: influx has little vertical head effect.
This model can give SIDPP approximately equal to SICP.

Pressure Balance

For the specified formation-pressure calculation: $P_{\text{form}}=SIDPP+0.052\rho_mTVD$ On the annular side: $P_{\text{form}}=SICP+P_{\text{hyd,ann}}$ For a discrete influx with known vertical extent $h$ replacing original mud: $SICP-SIDPP=(G_m-G_i)h=0.052(\rho_m-\rho_i)h$

In a truly flat lateral, measured influx length does not create that vertical extent: use the actual elevation and fluid profile. The ideal axial hydrostatic contribution for $\Delta TVD=0$ is zero. Small departures from horizontal or gas extending into the build section change the result.

For scale only, an 8.5-inch bore is $8.5/12=0.708$ ft across. A 0.708 ft vertical replacement with mud at 12.0 ppg and an assumed gas density of 2.0 ppg would change head by: $0.052(12.0-2.0)\times 0.708=0.368\text{ psi}$ This illustrates a small head effect; it does not establish the actual influx height or predict an exact gauge difference. A long sloping interval can have a much larger surveyed vertical extent than its bore diameter.

Avoid the Saltwater Diagnosis Trap

A small $SICP-SIDPP$ difference does not identify water. Even in a vertical well, the difference depends on both density contrast and influx vertical height; a small gas influx and a taller liquid influx can produce similar differentials. In a flat lateral, the near-zero vertical extent makes that comparison especially uninformative.

SIDPP 500 psi; SICP 505 psi
          |
          +--> Check pressure paths, datums and fluid profiles
          +--> Review pit gain, flow and survey information
          +--> Keep gas expansion and handling in the plan

Do not infer water, harmless returns or permission to bypass gas handling.

Prepare the Actual Return System

If the influx is gas, its volume can increase substantially as absolute pressure falls during circulation toward surface. Changes in mud properties, gas solubility, friction and temperature also affect the observed trends. Constant TVD does not guarantee a constant casing-pressure or pit-volume trace, and heel arrival is not an automatic exponential expansion event.

The supervisor must:

1. Reject an unsupported liquid-only diagnosis based on nearly equal gauges.
2. Prepare the approved pressure-controlled return route and gas-handling system for the potential gas load, including mud-gas separator limits where that equipment is used.
3. Brief the choke operator on the selected control method, anticipated fluid-front positions and formation/equipment limits.
4. Compare actual flow, volumes and pressures with the model throughout circulation. Investigate discrepancies rather than waiting for a prescribed pressure spike.

Pit Gain, Flow and Pressure: Use the Evidence Together

Pit gain is an important indication of an influx and supplies the standard kill-sheet volume estimate. It is not the sole measure of severity. Pressure, flow, fluid properties, available formation margin and equipment limits also govern the response. Transfers, losses, compressibility, ballooning and gas dissolved in oil-based mud can complicate the relationship between measured gain and downhole influx volume.

FULL-ANNULUS EQUIVALENT LENGTH
Given: gain 30 bbl; annular capacity 0.0459 bbl/ft
Equivalent length = 30 / 0.0459 = 653.6 ft MD

This is the length if the influx occupies the full annular area.
A high-side gas layer can extend farther.
Neither MD length is a vertical hydrostatic height in a flat lateral.

Worked Calculation: Equivalent Lateral Length

For an 8.5-inch hole and 5-inch drillpipe: $C_{ann}=\frac{8.5^2-5.0^2}{1029.4}=0.04590\text{ bbl/ft}$ A 25 bbl influx gives: $L_{eq}=25/0.04590=544.7\text{ ft MD}$ Retain this useful displacement-length estimate, but do not label it the exact length of a segregated ribbon. Use segment capacities if the hole or string dimensions change. Determine vertical elevation from the survey and the assumed fluid distribution.

Why Lateral Length Cannot Replace Vertical Height

Under a valid discrete-influx model: $G_i=G_m-\frac{SICP-SIDPP}{h}$ Here $h$ is the influx's vertical extent in the pressure-balance model. Only in a uniform vertical full-annulus slug model is $h=V/C_{ann}$. In a flat lateral, the near-zero vertical extent makes gradient inference unreliable; MD length cannot repair that problem.

Assume mud at 12.0 ppg ($G_m=0.624$ psi/ft), SIDPP 500 psi, SICP 510 psi and the 25 bbl equivalent length of about 545 ft. The incorrect substitution gives: $G_{wrong}=0.624-10/545=0.60565\text{ psi/ft}$ $\rho_{wrong}=0.60565/0.052=11.65\text{ ppg}$ The arithmetic is correct but the inferred density is invalid: 545 ft MD is not the vertical height. It does not establish a liquid influx or rule out gas. A usable gradient estimate requires a known vertical fluid profile and valid communicating pressures, not merely waiting until a nominal stroke count places all gas in vertical hole.

Worked Supervisory Scenario: Horizontal Shut-In

Given a well at 9,400 ft TVD and 19,800 ft MD, original mud 10.8 ppg, a valid recorded SCR of 550 psi at 30 spm, SIDPP 410 psi, SICP 412 psi and a 22 bbl gain:

1. A two-psi differential does not establish saltwater. Confirm gauge communication, fluid profiles and survey data, and prepare the approved pressure-controlled return route for possible gas.
2. With clean original mud in the communicating string and no excess pressure, the standard kill-density estimate is: $KMW=10.8+\frac{410}{0.052\times 9400}=11.639\text{ ppg}$ At an upward one-decimal calculation precision, this is 11.7 ppg. Check the chosen density and displacement against the pressure window.
3. The standard ICP calculation is $550+410=960$ psi. Actual startup must account for significant annular losses and any subsea CLF; do not blindly hold the original surface casing reading where those losses develop.
4. Prepare a geometry-dependent kill plan with measured pump output and actual string/annular volumes. The data given do not establish heel-arrival strokes or a gas flow peak. Track actual returns and keep the gas-handling system within its qualified limits.

A quiet initial pressure trace is compatible with an influx in the lateral. It provides no reason to delay control or to route unknown potentially gas-bearing returns directly over the shakers.