Lag Gas

Key Takeaways

• The lag time calculation is the fundamental correction applied to all mud logging data (gas, cuttings, and temperature) to assign measurements made at the surface to the correct formation depth at the time of measurement: the lag time (in minutes) is calculated as the annular volume (the volume of the annulus between the drill string and the borehole wall from the bit to the surface, in barrels) divided by the annular pump rate (the volume of drilling fluid displaced from the annulus per unit time by the surface pump, which equals the surface pump stroke rate multiplied by the pump output per stroke, in barrels per minute); the bit depth at the time of lag-corrected measurement is therefore the actual bit depth when the measurement is made at surface minus the footage drilled in the lag time (the ROP multiplied by the lag time); in a typical deep well with a 10,000-foot vertical depth, a 3-barrel annular volume per 100 feet of depth, and a pump rate of 10 barrels per minute, the lag time at total depth is approximately 3,000 barrels / 10 barrels per minute = 300 minutes = 5 hours, meaning that the gas detected at surface at any moment represents the formation that was at bit depth 5 hours earlier; for highly deviated wells where the annular geometry (drill pipe in borehole) changes significantly along the wellbore trajectory, the lag calculation must account for the changing cross-sectional area of the annulus in the vertical section, build section, and horizontal section, each of which contributes differently to the total annular volume.
• Gas show interpretation from the lag gas curve identifies reservoir intervals by comparing the shape, magnitude, and composition of gas peaks to the background gas level and to the gas expected from the lithology: a good gas show is characterized by a sudden increase in total gas (typically 5-20 times the background level), with a peak shape correlated with a specific drilling interval (the gas peak width corresponds to the formation thickness when the lag time change from the peak transit time is accounted for), with a composition profile (from the chromatograph's C1, C2, C3, iC4, nC4, and C5+ readings) that reflects a thermally mature reservoir gas or a light oil gas cap rather than the C1-dominated biogenic gas of coal or organic shale; the ratio of C1 to total gas (the methane ratio or character ratio) above 0.95 indicates predominantly methane (biogenic or thermogenic dry gas), while lower methane ratios indicate heavier gas with oil association; the wetness ratio (sum of C2-C5 components divided by total gas) above 0.1 indicates wet gas or condensate, and above 0.2 indicates oil-associated gas with likely liquid hydrocarbons in the reservoir; the balance ratio and the character ratio together are the primary mud log gas indicators used by wellsite geologists to classify a gas show as oil, condensate, wet gas, dry gas, or recycled gas (previously circulated gas from a shallower show), with the classification guiding the decision of whether to conduct a wireline formation test or core the interval before drilling ahead.
• Trip gas, connection gas, and background gas must be distinguished from formation gas shows in the lag gas curve to avoid false show identification or missed shows obscured by non-formation gas: trip gas arrives at the surface after a pipe trip (pulling the drill string and then running it back in the hole) as a slug of gas that accumulated in the open hole during the period when the bit was off bottom and circulation was stopped — the gas that seeped from the formation into the mud column during the trip time; trip gas is identified by its arrival at the surface shortly after circulation resumes after a trip, with a concentration that depends on the formation gas saturation, the trip time, and the effectiveness of the mud column in controlling formation fluid influx; connection gas is a smaller version of trip gas that arrives after each connection (the addition of a new joint of drill pipe, requiring a brief pump-off period while the connection is made) and is visible as a small periodic gas spike every 30-60 feet of drilling at the connection interval; background gas is the continuous baseline level of gas from the continuous liberation of gas from cuttings, from the drilled formation matrix, and from gas dissolved in the drilling fluid from previous exposure to gas-bearing formations; all three non-show gas types are subtracted from the total gas curve (conceptually, by identifying them from their timing and shape) to isolate the stratigraphically significant formation gas shows that indicate the presence of reservoir hydrocarbons at specific depths.
• Quantitative gas show analysis (QGSA) uses the measured gas volumes at surface, the annular volume, the pump rate, and the formation characteristics to estimate the formation gas concentration (gas saturation and porosity) from the surface gas measurements: the principle is that the gas detected at surface represents a specific volume of formation gas that was liberated from a specific volume of formation and carried to surface in the drilling fluid; the formation gas volume per unit volume of rock (proportional to porosity times gas saturation) can be calculated from the peak gas concentration at surface (in gas units or ppm) multiplied by the drilling fluid volume in the lagged interval divided by the formation volume exposed to the bit in that interval; QGSA is sensitive to the efficiency of gas liberation from cuttings (which depends on the cuttings size, the bit type, and the drill string vibration that liberates gas from the cut surface), the gas solubility in the drilling fluid (oil-based mud dissolves gas more readily than water-based mud, requiring a correction for the solubility effect), and the stripping efficiency of the gas trap at surface (the fraction of the gas dissolved in the mud that is extracted by the gas trap before the mud returns to the pit); despite these corrections, QGSA provides quantitative estimates of formation gas content that are useful for ranking shows and for setting priorities for wireline formation testing or coring, even if the absolute gas saturation values are not reliable enough to substitute for core or log-derived porosity and saturation data.
• H2S and CO2 in lag gas represent a safety risk and a well control challenge that must be monitored continuously during drilling in formations with known or suspected sour gas or CO2-containing fluids: H2S detected at the mud logging unit (by electrochemical sensors or colorimetric tubes) triggers well site safety procedures (mandatory H2S monitor activation, personnel evacuation from the hazard zone, breathing apparatus staging) in addition to informing the formation evaluation program; CO2 in the gas stream is important for well control because CO2 dissolves readily in water-based mud (forming carbonic acid that reduces mud pH and affects drilling fluid properties) and can reduce the mud weight equivalent of the annular fluid if dissolved CO2 comes out of solution in the upper part of the well (where the annular pressure is lower), potentially causing the apparent density of the mud column to decrease and reducing the hydrostatic head against the formation; mud loggers monitoring CO2 in the lag gas stream provide early warning of sour or CO2-contaminated formations that require adjustment of the mud system chemistry and density before the contamination affects the borehole stability or the well control margin; the mud logging unit's gas monitoring system (the total gas sensor, the individual hydrocarbon chromatograph, the H2S sensor, and the CO2 sensor) together constitute the first line of early warning for unexpected formation fluid influx, complementing the surface pit volume monitors and return flow sensors that detect kick conditions directly.