Mud Gas Analysis
GeoMark’s Mud Gas Isotope lab, trusted for more than 20 years, delivers fast, reliable gas analysis from wells worldwide, and helps operators solve critical challenges related to reservoir connectivity, compartmentalization, and fluid migration. By measuring carbon isotopes (δ¹³C) in real-time for hydrocarbon gases (C₁–C₅), this service provides a detailed fingerprint of gas origin, maturity, and alteration across the wellbore.
These insights allow customers to determine whether multiple zones are in communication, identify vertical or lateral fluid discontinuities, and better understand charge timing and sealing efficiency.
Key Benefits:
Rapid & Cost‑Effective Screening
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Using gas composition logs up to C6+ (including He and H₂), they quickly flag hydrocarbon zones, enabling efficient drilling and low-cost sampling
Source & Maturity Insights
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Carbon and hydrogen isotopes of methane through pentane, plus CO₂, reveal whether gas is biogenic or thermogenic, assess thermal maturity, and identify mixing
Reservoir Connectivity
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Isotopic correlation between wells helps confirm if zones are connected or separate by comparing stable gas signatures
Wetness & Helium Detection
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Distinguishes between dry gas, condensate, or oil zones and includes helium analysis
Advanced Technical Outcomes:
Overpressure Identification
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Isotopic “rollover” patterns in C2 and C3 can indicate overpressured zones, a proxy for high productivity in plays like Barnett or Haynesville
Permeability & Fracturing Markers
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Comparing isotopic differences between mud gas (free gas) and headspace gas (adsorbed) can pinpoint zones of higher permeability or fracturing
Mixing & Migration Patterns
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Case studies, such as Gulf of Mexico fields, demonstrate how isotopic fingerprinting can map fluid migration paths and mixing of Jurassic, Cretaceous, and Tertiary gases
Case Studies: Leveraging Mud Gas Isotopes and PVT Data to Unlock Working Pressure in Unconventional Plays
Client Challenges:
In unconventional plays, understanding working pressure, the operating pressure range that defines producibility and phase behavior is key to optimizing well placement, completion design, and production forecasting. Yet direct pressure measurements are sparse, and traditional PVT data often doesn’t extend across the full range of maturity or fluid variability present in shale plays.
To address this gap, we integrated its Mud Gas Isotope Analysis with an extensive PVT and Geochemical Database to build a more complete picture of working pressures across major basins. Our method combined: Mud Gas Isotopes (δ¹³C of C₁–C₅): to assess thermal maturity, source facies, and mixing events. Compositional PVT Analysis: to define phase envelopes, bubble point and dew point pressures, and evolving fluid types. Reservoir Pressure Estimates: sourced from well tests, PVT reports, and proprietary interpretations. Geochemical Inputs: including TOC, Ro, and biodegradation levels to tie fluid evolution to source rock context.
