Sonolog

Key Takeaways

• Fluid level measurement by sonolog is complicated by the presence of casing collars (the thickened sections of the casing where two joints of casing are connected by a collar) and tubing collars that produce characteristic acoustic echoes (collar echoes) at regular intervals in the sonolog trace, which are used as depth calibration markers: as the acoustic pulse travels down the annulus, each casing collar it passes produces a small reflection (because the collar represents a slight change in the acoustic cross-section of the annulus), creating a series of evenly spaced echo peaks on the sonolog trace at intervals equal to the joint length of the casing (typically 40 feet for standard API casing or 30 feet for short-form casing); the number of collar echoes between the surface and the fluid level echo provides an independent depth check on the travel-time-based fluid level calculation — the total depth to the collar at which the trace becomes obscured by the fluid level echo should match the fluid level depth computed from the travel time; the collar echo method is valuable when the acoustic velocity in the gas column is uncertain (due to unknown gas composition or pressure variations along the annulus), because the collar spacing provides a physical depth reference that does not depend on the assumed acoustic velocity; in practice, both the collar count and the travel time calculation are used together to get the most accurate fluid level depth, with the acoustic velocity calibrated by comparison with the known collar depth to eliminate systematic error from incorrect gas velocity assumptions.
• Bottomhole flowing pressure estimation from fluid level measurements is the primary engineering use of sonolog data, allowing the production engineer to infer the reservoir pressure and productivity index without running a pressure gauge downhole: the bottomhole flowing pressure (BHFP) at the pump intake is calculated as BHFP = Pcasing + rho_gas * g * fluid_level_depth + rho_liquid * g * (pump_depth - fluid_level_depth), where Pcasing is the wellhead casing pressure measured at the surface, rho_gas is the density of the gas column in the annulus, rho_liquid is the density of the liquid column from the fluid level to the pump intake, and the depths are the fluid level depth and the pump setting depth; this calculation converts the surface measurement (casing pressure plus fluid level depth) into an estimate of the downhole flowing pressure, which combined with the surface production rate allows the productivity index (PI = q / (Pstatic - BHFP)) to be calculated and the static reservoir pressure to be estimated from extrapolation of the PI relationship; the accuracy of the BHFP estimate depends on the accuracy of the gas column density (which requires knowledge of the gas composition and temperature profile in the annulus) and the liquid column density (which depends on the gas-liquid ratio of the fluid between the fluid level and the pump intake); in gassy wells where significant free gas enters the annulus above the pump, the liquid column contains a mixture of oil, water, and dissolved gas that has a lower effective density than pure liquid, and the BHFP will be overestimated if a pure liquid density is assumed for the fluid column.
• Pump diagnostic analysis using sonolog data identifies specific pump problems including gas lock, fluid pound, and pump leakage that affect pump efficiency and well productivity: gas lock occurs when the pump barrel fills primarily with gas rather than liquid, preventing the pump from displacing liquid and causing the pump to cycle without moving fluid; gas lock is diagnosed by a fluid level that does not fall during pumping (indicating that liquid is not being lifted from the annulus) combined with erratic or high pump card shapes on the dynamometer card; fluid pound occurs when the pump barrel partially fills with gas during the upstroke (because the fluid level is too low and the pump does not have adequate submergence), causing the pump valves to slam shut as the liquid slug at the bottom of the partly gas-filled barrel is suddenly compressed on the downstroke; fluid pound is diagnosed by the characteristic "pound" appearance of the downhole pump card (a flat section on the downstroke followed by an abrupt load change) and is corrected by reducing the pump speed to allow more time for fluid to accumulate in the annulus and by adjusting the tubing pump load to match the actual formation productivity; pump leakage (fluid bypassing through worn or damaged plunger-barrel clearances or leaking valves) is diagnosed by comparing the theoretical pump displacement (from the stroke length and pump barrel area) to the actual surface production rate, with significant discrepancy indicating that a fraction of the fluid is being bypassed back into the tubing rather than being produced to surface.
• Real-time automated fluid level monitoring using permanent acoustic fluid level systems (continuous sonologs or regularly triggered automated acoustic fluid level instruments) allows production engineers at a remote operations center to monitor hundreds of rod-pump wells simultaneously and detect pump problems without dispatching field technicians: permanent acoustic fluid level systems mount a microphone and pulse generator on the casing head valve and fire an acoustic pulse at programmed intervals (typically every 15-60 minutes), transmitting the recorded acoustic trace by SCADA telemetry to the central monitoring system where automated analysis software identifies the fluid level echo, calculates the fluid level depth, and computes the BHFP; alarm conditions (fluid level falling below a preset minimum that indicates the well is being over-pumped or the reservoir is depleting) trigger automated actions including speed reduction on variable-speed drive (VSD) pump controllers or notifications to the field supervisor; continuous fluid level monitoring has demonstrated significant production improvements in fields with many rod-pump wells by enabling rapid detection of pump inefficiency (when the fluid level rises above the pump because the pump is undersized or damaged) and pump-off conditions (when the fluid level falls to the pump intake and the pump cycles without adequate liquid fillage), allowing pump speeds and stroke rates to be optimized to match the actual formation inflow performance rather than fixed at values set during initial well startup.
• Sonolog interpretation in the presence of multiple perforated zones requires distinguishing the fluid level in the primary producing zone from gas migration from shallower zones that may create a false acoustic reflector above the true fluid level: in a well completed in multiple zones with different pressures and permeabilities, gas from a shallower zone may migrate up the annulus and accumulate above the liquid from the deeper zone, creating a gas-liquid interface at a shallower depth than the actual pump submergence level; the sonolog echo from this gas-liquid interface may be mistaken for the fluid level, causing the pump submergence to be overestimated and the pump speed to be set inappropriately low; the presence of multiple reflecting surfaces in the sonolog trace (more than one echo at different depths below the collar sequence) is the diagnostic indicator of a complex annular fluid distribution; in some cases, the fluid level measurement can distinguish between a single fluid level (smooth, well-defined echo peak at one depth) and a fluid distribution with gas cap above liquid (series of echo peaks at different depths corresponding to foam, bubbly flow, or alternating gas and liquid slugs in the annulus above the main liquid level); selective zone isolation (packer completions that confine each zone's production to a specific tubing annulus) eliminates the multiple-zone fluid level interpretation problem but adds completion complexity and reduces production flexibility.