Background Gas (BGG): Mud Gas Logging and Hydrocarbon Show Evaluation

Key Takeaways

• Gas detection equipment and units in the mud logging unit: The mud logging unit (MLU) is a trailer or skid-mounted facility positioned at the rig site connected to the mud return line, containing the gas extraction and analysis equipment, drilling parameter sensors, and the computerized data acquisition and display system. The total gas detector uses a flame ionization detector (FID): a hydrogen flame burns the gas sample, ions produced by hydrocarbon combustion are collected by a charged electrode, and the ion current is proportional to the hydrocarbon concentration. FID output is measured in gas units (GU), where 1 GU = 1 ppm methane equivalent by volume in the degasser headspace gas. The chromatograph (typically a Shimadzu or Perkin-Elmer gas chromatograph with FID detector) separates individual hydrocarbons using a capillary column; components are quantified as ppm in the mud gas sample. Calibration of the TCG detector and chromatograph uses certified gas standard mixtures (typically 100 ppm CH4 in nitrogen). Data are recorded at 0.5-1.0 m drilling depth intervals (tied to the driller's depth system via the weight-on-bit sensor) and archived in the LAS (Log ASCII Standard) format for delivery to the operator. Common BGG baseline values in WCSB formations: Cretaceous non-reservoir shale 5-50 GU (low background), Viking or Cardium sand with residual gas 100-500 GU, Montney silty shale during penetration 200-2,000 GU, Duvernay over-pressured shale 500-5,000 GU. A sustained BGG increase of 5× baseline or greater while drilling ahead is a primary indicator of a significant hydrocarbon-bearing zone requiring formation evaluation.
• Gas ratio analysis for fluid type classification: The most powerful use of chromatograph data in mud logging is gas ratio analysis — calculating dimensionless ratios of hydrocarbon components that classify formation fluid type independently of the absolute gas concentration. The key ratios are: (1) Wetness ratio: W = (C2 + C3 + C4 + C5) / (C1 + C2 + C3 + C4 + C5) × 100%. W < 2% = dry gas; W 2-10% = wet gas; W 10-40% = condensate; W > 40% = oil. (2) Balance ratio: B = C1 × C4 / (C2 × C3)2. B > 1 = oil-associated gas; B < 1 = gas condensate. (3) Character ratio: Ch = C1 / C2. Ch > 100 = biogenic or dry thermogenic gas; Ch 10-100 = thermogenic gas; Ch < 10 = very wet gas or near-critical fluid. (4) Pixler ratio: plotted on a Pixler diagram (Ch1 vs W) with regions defining dry gas, wet gas, condensate, and oil fluid types. These ratios are plotted against depth and compared to the drilling rate (ROP), lithology from cuttings analysis, and formation temperature to identify pay intervals. In the WCSB Montney, typical gas ratios indicate a gas condensate fluid (W = 25-45%, B = 0.3-0.8), while a Cardium oil zone shows W > 40% with low C1/C2 characteristic of a light oil associated gas. Ratio analysis also identifies non-hydrocarbon contamination: H2S appears as an anomalous corrosion sensor response concurrent with gas increase; CO2 affects chromatograph baselines and is identified by an infrared CO2 sensor in the MLU.
• Connection gas and trip gas as kick indicators in WCSB operations: Connection gas (CG) is the transient increase in gas detected at surface when the circulation pumps are shut down to make a pipe connection. During normal drilling with the pumps running, the annular pressure (hydrostatic column + friction pressure) keeps the wellbore overbalanced relative to formation pore pressure — preventing formation fluid influx. When the pumps stop for a connection, the friction component of annular pressure disappears (typically 200-800 kPa reduction), reducing the effective overbalance. If the formation is close to balanced or underbalanced with pump friction accounted for, this pressure reduction allows a small slug of formation gas to enter the annulus during the connection period (typically 8-15 minutes for a WCSB rotary drilled stand). This gas slug arrives at surface 1-3 circulating hours after the connection was made, producing a characteristic spike on the TCG trace. Normal connection gas in a balanced well is 1-3× background gas; connection gas 5× or greater background indicates that the formation is very close to balanced or that a small influx occurred. Per AER Directive 036, a connection gas greater than 10× background triggers a well flow check before continuing drilling. Trip gas (TG) is the gas spike measured when the drill string is pulled out of hole: swabbing the pipe out of the wellbore reduces wellbore pressure momentarily, potentially inducing formation fluid influx. AER Directive 036 mandates that trip gas measurements be logged and that flow checks be conducted before tripping through any formation showing sustained BGG above 500 GU or connection gas consistently 5× background.
• Lag time correction and depth synchronization: A fundamental challenge in mud gas logging is the time delay between when gas enters the mud at the bit and when it arrives at the degasser at surface — the "lag time" or "bottoms-up time." Lag time varies with annular volume, pump output, and wellbore geometry: for a 3,000 m vertical Montney well with 5-inch drill pipe in a 12-1/4 inch hole, pumping 1,000 L/min, the annular volume is approximately 38 m3 and the lag time is 38 min. To correctly assign gas readings to the depth of penetration rather than the depth being drilled at the time of detection, mud loggers must subtract the lag time from the detection time and reference the gas reading to the bit depth at the lagged moment. Modern MLU software performs this correction automatically using a Pumps On/Off signal and real-time pump stroke counts to track the annular volume precisely. Failure to apply lag correction results in gas peaks being mapped to shallower (later-drilled) depths than their true source, misleading formation evaluation and potentially causing a real kick to be attributed to a non-reservoir zone while actual reservoir penetration appears quiet on the log. On horizontal wells with 2,500 m lateral length and reduced annular clearance (6-3/8 inch bit, 5-inch DP), lag times can reach 2-3 hours, making lag correction especially critical for correctly attributing gas anomalies to specific geological zones in the horizontal section.
• BGG in sour service: H2S monitoring requirements under AER Directive 036: When drilling formations known or suspected to contain hydrogen sulfide (H2S) — including Devonian carbonate reservoirs (Nisku, Leduc, Slave Point formations), deep Cretaceous Mannville gas zones, and some Montney intervals in the Dawson Creek area — the mud logging unit must incorporate dedicated H2S monitoring equipment supplemental to the hydrocarbon gas detectors. H2S is not detected by the FID (which responds only to combustible hydrocarbons) but is highly toxic at concentrations above 10 ppm (WCSB regulatory limit for H2S in workplace air under Alberta OHS Code Part 11). H2S monitors at the shale shaker (ambient air sensor), mud logging unit gas inlet, and rig floor (personal H2S monitor worn by all personnel) must be calibrated and operational before drilling within 500 m of any known H2S-bearing formation, per AER Directive 036 sour service drilling requirements. BGG traces for sour wells include both the hydrocarbon TCG trace and a concurrent H2S concentration trace (in ppm, measured by electrochemical cell or colorimetric detector). If H2S is detected at the shaker above 10 ppm, AER Directive 036 requires immediate muster and H2S emergency response procedures, including possible well shut-in if concentration is rising. Most WCSB sour wells are drilled with an H2S contingency plan approved by the AER under Directive 056 (Energy Development Applications) that specifies emergency response zone radii and evacuation procedures based on worst-case H2S release rate calculations.