Inflow Testing, MPD Diagnostics & Wellbore Stability Assurance
(Validated for use with API RP 92M / API RP 92S, NORSOK D‑010, and the International Association of Drilling Contractors (IADC) MPD Guidelines)
Table of Contents
Introduction
Regulatory & Standards Framework
Inflow Testing During MPD Operations
MPD Diagnostic Techniques
Wellbore Stability Assurance in MPD Mode
Risk Assessment & Hazard Control
Operational Workflow: From Planning to Drilling
Engineering Calculations & Worked Example
Generic Field Case Example
Documentation Requirements
References
1. Introduction
This document describes the advanced engineering processes, tools, and procedures required for operations using Managed Pressure Drilling (MPD) to:
Verify formation integrity via inflow (negative pressure) testing.
Diagnose real-time downhole and annular conditions using MPD instrumentation.
Maintain the wellbore within a narrow operational pressure window while drilling.
Under MPD, the Annular Pressure Profile (APP) is actively managed. Hence, the well remains within the drilling pressure envelope, bounded by the formation pore pressure at the lower end and the fracture gradient or wellbore collapse/stability limits at the upper end. Accurate knowledge and control of this envelope are critical to safety and efficiency.
This module provides step-by-step methodologies, diagnostic screening tools, acceptance criteria, and engineering calculations designed to support field drilling personnel in safe, compliant operations.
2. Regulatory & Standards Framework
The following industry documents form the baseline governance for MPD operations, inflow testing, diagnostics, and wellbore stability assurance:
API RP 92M – Managed Pressure Drilling Operations with Surface Back-pressure (applies to rigs with surface BOPs).
API RP 92S – Managed Pressure Drilling Operations – Surface Back-pressure with a Subsea BOP.
NORSOK D-010 (Rev 5) – Well integrity barriers and testing requirements.
IADC UBO/MPD Guidelines – Land operations reference and planning guidance.
Additional equipment, sensor, and monitoring standards (e.g., sensor accuracy, instrumentation verification) – e.g., IADC Rig Sensor Stewardship Guidelines.
All procedures in this module align with the above standards and existing operator/service-provider practices. Any local regulatory or operator-specific requirements must also be reviewed and adhered to.
3. Inflow Testing During MPD Operations
3.1 The Purpose of Inflow Testing
Inflow testing (also referred to as a negative pressure test or formation inflow verification test) under MPD conditions is used to:
Confirm that the formation (and cement/casing/liner barriers) does not flow when wellbore annular pressure is intentionally reduced into underbalanced conditions.
Verify the integrity of wellbore barriers (cemented casing, liner hangers, plugs) before drilling ahead or changing operational mode.
Establish safe MPD operating limits (underbalance magnitude, annular pressure margin) for the next drilling or intervention interval.
A successful inflow test demonstrates that no measurable formation inflow occurs when the wellbore is placed into a controlled underbalanced state. Failure to test (or to obtain a valid result) increases the risk of underground inflow, wellbore instability, or loss of control.
3.2 Pre-Test Preparation Requirements
Before executing an inflow test, the following preparation is mandatory:
A. Surface & instrumentation verification
Confirm the MPD choke manifold is fully functional, calibrated, and responsive as per vendor/rig specification.
Flow measurement devices (such as Coriolis meters or volumetric meters) must be zeroed, verified for calibration, and documented. Reliable flow meters are critical for early detection of minor influxes.
Pressure sensors (annular, drill-pipe, standpipe) must be calibrated, with documented accuracy (e.g., ±X% FS (Full Scale) or vendor spec) and known measurement uncertainty.
Ensure flow-out sensors (pit gain sensors and volume counters) are operational and validated.
B. System stabilization
Circulate the mud at the intended test flow rate for at least one bottom-up cycle to clear cuttings and stabilize parameters (mud density, rheology, temperature).
Allow the well to approach thermal/hydraulic equilibrium (mud density and ECD changing slowly, downhole temperature stable) so baseline pressures are reliable.
Update mud rheology, density, and hydraulics to reflect current conditions (temperature, hole size, cuttings load) so models for expected ECD and bottom-hole pressure are accurate.
C. Barrier confirmation
Cemented casing/liner or mechanical barrier installations must be completed, and previous pressure tests (annular/casing/liner tests) must be passed, with logs (cement bond, ultrasonic, etc.) reviewed.
Ensure barrier integrity documentation is available (cement job report, bond logs, pressure test certificates).
D. Pre-Test Engineering/Modelling
Calculate anticipated bottom-hole pressure (BHP) at the reduced surface back-pressure scenario using hydraulics modelling (circulation, ECD, friction losses, temperature/thermal expansion).
Estimate formation pore pressure and fracture gradient from offset data, logging, seismic, and local geology.
Define the minimum safe underbalance limit (i.e., how far below pore pressure you can go without risking influx or breakout).
Estimate maximum allowable influx volume (based on flow meter resolution, system recovery capacity) for the test duration, such that inflow below this will be within detection capability.
3.3 Inflow Test Execution Procedure
The standard inflow test under MPD operations may follow these steps:
Step 1 – Establish Baseline
Continue circulation at the predetermined flow rate.
Record and stabilize standpipe pressure, annular pressure, drill-pipe pressure, and flow-in/flow-out volumes.
Ensure the choke is holding the set-point surface backpressure without oscillation or instability.
Step 2 – Reduce Surface Backpressure
Reduce the MPD choke backpressure gradually according to the job-specific ramp profile defined in the plan (the rate of reduction depends on hydraulics modelling, sensor response time, and formation sensitivity).
Carefully reach the target underbalance (for example, a defined psi below pore pressure) while watching for any signs of influx or pressure anomalies.
Step 3 – Observation Phase (Stabilize & Monitor)
Two common methods:
Circulating Inflow Test: Maintain circulation at the test flow rate and monitor the differential between flow-in and flow-out, annular pressure trend, and pit gain/loss.
Static Inflow Test: Stop pumps, shut in the well, or hold backpressure constant, monitor annular pressure, flow-out, and pit volume changes over a defined interval.
Monitor for any upward drift in annular/annulus pressure, pit gain, or flow-out exceeding baseline.
Step 4 – Monitoring Period
Maintain the test condition for the defined duration (typically 10-30 minutes, depending on job plan, formation sensitivity, and sensor response) and observe:
Flow-out vs. flow-in difference.
Pit volume changes (gain or loss).
Annular pressure trend, standpipe pressure stability.
Flow/return temperature changes or gas signature if instrumentation supports.
Step 5 – Rebalance and Resume Operations
If the test is successful, slowly increase the surface backpressure (via choke) until the well returns to the normal operating MPD setpoint.
Resume drilling operations, always with post-test verification that parameters have returned to expected values.
3.4 Interpretation and Acceptance Criteria
A successful inflow test means the wellbore system is stable under the test under-balance and ready to drill ahead. Key criteria:
No sustained or increasing annular pressure trend once the target under-balance is reached.
Return flow (flow-out) equals pump flow (flow-in) within the system's validated measurement uncertainty. Quantitative tolerances must be specified in the test plan (e.g., ±X% of flow or ±Y bbl over the test duration), based on calibrated instrumentation.
Pit volume change (gain or loss) remains within defined limits for the test duration.
No appearance of influx signature, gas return, or abnormal flow behavior.
If the test fails any of the above criteria:
Re-establish an overbalanced condition, suspend drilling ahead.
Investigate barrier integrity (cement log review, casing/barrier test results), equipment calibration, and pre-test modelling accuracy.
Repeat the test (perhaps with modified parameters) only after corrective actions have been taken.
4. MPD Diagnostic Techniques
4.1 Downhole & Surface Pressure Diagnostics
Using pressure-while-drilling (PWD) tools and surface MPD instrumentation, the drilling team can analyze:
Variations in pore/bottom hole pressure and formation pressure response during dynamic operations.
Fracture initiation or near-fracture events can be detected from sudden pressure changes or annular pressure drops.
Ballooning or breathing behaviour (formation expansion/contraction) via pressure oscillations.
Micro-kicks or influxes too small for conventional well control detection systems. (High-precision flow/pressure systems are increasingly used.)
Comparison of calculated ECD profiles, friction losses, and dynamic bottomhole pressures with real-time data to highlight deviations that may indicate hidden anomalies.
4.2 Real-Time Flow-Pressure Mapping
In MPD operations, real-time mapping of flow and pressure variables enables proactive diagnostics:
Key parameters monitored: choke position, surface back-pressure, annular pressure, standpipe pressure, flow-in and flow-out (via Coriolis or volumetric meters), pump strokes, and density.
A baseline “steady-state” operating map is defined in advance; any deviation from the baseline curve (e.g., variations in flow-out at the same pump rate, or unexpected changes in choke position) may indicate losses, influxes, or wellbore integrity issues.
Real-time charts and dashboards provide visual correlation and enable early recognition of changes in well behaviour.
4.3 Early Kick / Influx Indicators
In MPD operations, because of tighter pressure control and improved instrumentation, the drilling team can detect earlier signs of influxes than in conventional operations:
Micro-flow detection using high-accuracy Coriolis meters downstream of the choke.
Choke-pressure signature shifts: e.g., a gradual increase in surface back-pressure required to maintain the target annular pressure may indicate an influx/gas expansion.
Incremental rise in annular pressure slope during circulation, or subtle pit-gain trends.
Return fluid temperature increase or change in cuttings/gas signature (if sensors installed).
The detection limit of the system should be validated during commissioning. While under ideal conditions, detection may reach ~0.1 bbl, the actual threshold must be defined in the test plan and linked to measurement uncertainty.
4.4 Losses Identification, Classification & Response
Losses are generally categorised to support immediate diagnosis and response:
Seepage/Minor losses: minor fluid movement into formations, often manageable by a slight increase in surface back-pressure or a small rheology adjustment.
Partial losses: a measurable loss rate that may require increased back-pressure, reduction in ECD, or injection of lost circulation material (LCM) while continuing drilling.
Total losses: large volume of losses, often requiring a circulation stop, a change in drilling strategy, wellbore isolation, or alternative methods. Response may include reducing ECD, plugging or cementing the loss zone, using managed-loss drilling techniques, or implementing dual-gradient recovery strategies (in the planning phase) rather than treating as a standard immediate remedy.
5. Wellbore Stability Assurance in MPD Mode
5.1 Stress Environment, Rock Mechanics & Stability Fundamentals
Wellbore stability depends on a variety of factors:
In-situ stress state (minimum horizontal stress σ_h, maximum horizontal stress σ_H, vertical stress σ_v).
Rock strength (cohesion, friction angle, tensile strength) and rock anisotropy.
Mud weight, annular pressure profile, and dynamic ECD effects during circulation, connections, tripping, and sweep displacement.
Time-dependent effects (creep, hydration, or weakening of rock around the wellbore).
Using MPD, the drilling team must ensure that the wellbore pressure remains within the “safe envelope” defined by the collapse pressure (lower bound) and the fracture gradient (upper bound), while maintaining mechanical stability.
5.2 MPD-Controlled ECD Windows & Pressure Envelope
MPD is particularly valuable in narrow drilling windows, where the difference between pore pressure and fracture gradient may be very small. Key considerations:
By managing surface backpressure and monitoring real-time ECD, MPD enables drilling safely within narrow windows. In some cases, a margin of less than 0.2 ppg (or equivalent psi), when carefully planned, can be successfully executed.
Choke control and surface backpressure manipulation allow reduction or control of dynamic ECD during circulation, connection, tripping, and sweeps.
The operational planning must define the lower bound (minimum mud weight/annular pressure to avoid collapse) and the upper bound (maximum annular/back-pressure to avoid fracture or loss). Safety margins (e.g., measurement uncertainty, unknown stresses) must be built in.
5.3 Interpreting Breakouts, Ballooning & Breathing Wells
Breakouts occur when annular pressure is too low, and the wellbore wall fails in shear, often identified by PWD torque/drag data, cuttings changes, caliper logs, or sidetracking.
Ballooning or Breathing Wells: formation expansion (ballooning) or contraction (breathing) in response to cyclic pressure changes can lead to subtle annular pressure or flow signals rather than classic influx/loss signs. MPD teams must interpret oscillatory choke/annulus behaviour to differentiate breathing from true influx.
Training should emphasize the difference: breathing is a reversible volume change, whereas influx is fluid entering the wellbore from the formation.
5.4 Hole-Cleaning Integration and MPD Operations
Effective hole cleaning must be integrated into any MPD pressure-management plan:
Proper hole cleaning (optimal annular velocity, displacement sweeps) reduces cuttings buildup that may affect ECD and APP.
High-viscosity sweeps, while helpful for cleaning, increase ECD and must therefore be hydraulically modelled and incorporated into the MPD plan. MPD does not guarantee sweeps without fracturing; the risk must still be analyzed.
Surge and swab effects during connections, tripping, and sliding must be modelled and compensated by MPD control (choke/backpressure adjustments) to maintain stability.
6. Risk Assessment & Hazard Control
Key hazards specific to MPD operations include:
Incorrect underbalance leading to an unintended influx of formation fluids.
Excessive underbalance/mud weight reduction causes wellbore collapse or breakouts.
A choke system failure or a slow response compromises pressure control.
Temperature and density shifts in the drilling fluid that unexpectedly change ECD/annular pressure.
Rapid ECD cycling (e.g., during surge/swab events) stresses casing or formation integrity.
Mitigation strategies:
Use redundant and validated pressure and flow sensors; maintain calibration records and measurement uncertainty.
Perform detailed hydraulics modelling in the planning phase, including worst-case scenarios (kick, loss, surge/swab) and define abort criteria.
Define and rehearse the choke/backpressure response plan (ramp rates, abort thresholds, rollover).
Deploy continuous monitoring algorithms and dashboards (real-time data trending, alarms) to detect anomalies early.
Conduct full HAZID/HAZOP workshops during planning, review barrier integrity, instrumentation failure modes, and human-machine interface risks.
7. Operational Workflow: From Planning to Drilling
A high-level workflow for MPD with inflow testing and stability assurance:
Pre-job engineering: formation evaluation, pore/fracture modelling, stress analysis, instrumentation planning.
Hydraulic modelling: simulate circulation, ECD, surge/swab, loss/influx scenarios, define underbalance test parameters and stability margins.
Equipment/instrumentation commissioning: calibrate sensors, verify flow meters, test choke manifold, and control loops.
Real-time monitoring setup: baseline data acquisition, flow/pressure dashboards, and alarm setup.
Inflow test execution: follow the procedure in Section 3, document results, and interpret outcomes.
Drill ahead with MPD: maintain APP within the defined window, monitor diagnostic techniques (Section 4) and stability parameters (Section 5).
Decision tree for anomalies: if triggered (early kick signal, loss event, hole-collapse indicator) stop, analyze, take corrective action.
Post-job review/documentation: lessons learned, data archiving, sensor logs, test reports.
8. Engineering Calculations & Worked Example
Example: Inflow Test Underbalance Calculation
UB = PP – BHP
Where:
UB = underbalance (psi)
PP = formation pore pressure (psi)
BHP = bottomhole pressure (psi) (including hydrostatic + dynamic + back-pressure)
Example: If PP = 6,500 psi and BHP is modelled at 6,450 psi at test condition, then UB = 50 psi.
Example: Kick Tolerance
KT = FG – ECD
Where:
KT = kick tolerance (ppg or psi equivalent)
FG = fracture gradient (in ppg or psi)
ECD = equivalent circulating density (ppg) or bottomhole pressure equivalent
Example: Collapse Pressure Margin
CP = σ_min – BHP
Where:
CP = collapse margin (psi)
σ_min = minimum rock stress supporting the wellbore (psi)
BHP = bottomhole pressure (psi)
9. Generic Field Case Example
In a simulated deepwater MPD operation:
Target underbalance of ~80 psi established based on modeling.
Inflow test for 20 minutes showed zero measurable inflow; flow-out matched flow-in within instrumentation uncertainty.
Diagnostic analysis identified a breathing-well signature (cyclic annulus pressure change without fluid influx).
Based on the test and stability modeling, the ECD window was adjusted from 13.4-13.7 ppg to an optimized 13.55 ppg.
Drilling ahead continued under MPD control with real-time monitoring and early-kick detection systems in place.
10. Documentation Requirements
The following documents must be generated and maintained:
Inflow test report: test parameters, sensor calibration records, baseline data, test results, interpretation, and pass/fail decision.
MPD diagnostics charts and logs: real-time flow/pressure maps, flagged anomalies, and corrective actions taken.
Wellbore stability modelling output: stress modelling, collapse/fracture calculations, ECD window definitions.
Sensor calibration sheets and measurement uncertainty reports (annular pressure, flow meters, pumps).
Operational procedure and workflow documentation: MPD plan, decision tree for anomalies, risk/HAZID/HAZOP records.
11. References
American Petroleum Institute (API). Recommended Practice 92M – Managed Pressure Drilling Operations with Surface Back-pressure. 1 Sept 2017.
American Petroleum Institute (API). Recommended Practice 92S – Managed Pressure Drilling Operations – Surface Back-pressure with a Subsea BOP.
International Association of Drilling Contractors (IADC). Guidance for UBO and MPD Techniques for Land Operations, Version 3, June 2021.
IADC. Rig Sensor Stewardship Guidelines – Accuracy and Data Quality for Drilling Operations.
Samokhvalov D., et al. Risk Assessment of Drilling Process with Managed Pressure Drilling (MPD), 2023.
Drilling Contractor. “Riser Gas Handling Guidelines, API RP Revisions Highlight Recent IADC UBO/MPD Committee Efforts.” 30 Sept 2024.