Digital Solution Reduces Liquid Loading in a China Unconventional Gas Development
Authors: Carpenter Chris 
Published: September 2022

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205586, “Remote-Controlled Automated Foam Injection: A Digital Solution to Liquid Loading in a China Unconventional Gas Development,” by Jiang Wei Bo, Beryl Audrey, SPE, and Uzezi Orivri, Schlumberger, et al. The paper has not been peer reviewed.
Gas field C is an unconventional tight gas reservoir in central China. Horizontal-well multistage hydraulic fracturing has proved effective in this field. However, with continuous production over time, reservoir pressure declines, which results in a decrease in gas production rate below the critical gas velocity, leading to accumulation of liquid in the wellbore (liquid loading), which in turn results in backpressure and formation damage. To mitigate these challenges, a versatile intelligent dosing technology has been piloted to reduce liquid loading.

Field Issues
The field produces from four main reservoirs: Benxi, S2, S1, and H8, as shown from bottom to top in Fig. 1, at depths of between 7,850 and 10,816 ft, with an average thickness of 7.5 m. The porosity of S1 is between 2–6% and permeability is less than 0.03 md, similar to that of H8. S23 (a subreservoir) features similar porosity as S1, but a higher permeability of approximately 0.3 md. Horizontal wells with multistage fracturing completions are used to develop the main reservoir, S2, whereas slanted wells are used to develop the other reservoirs in a commingled manner.
This field’s first gas production was in July 2018. The current average daily gas production at the time of writing is approximately 132 MMscf/D. By the middle of 2021, the total number of
gas production wells had reached 211, with approximately 10% of the wells shut in and waiting on well interventions.
Two well completion types are used in the field, deviated and horizontal. The deviated wells are completed with 5½-in. casing and 2⅞-in. tubing, or 3½-in. TAP lite and fractured. The horizontal wells feature an openhole completion with 3½-in. upper casing and 4½-in. down casing with fracturing. According to a recent analysis, 43% of production wells in the field experience liquid loading. Some are either shut in because of lack of gas production, while others produce intermittently because of depleted reservoir pressure. Wellhead-gas-sample analysis indicates that most of the produced gas is dry gas (i.e., no condensate liquid production). However, average field-flowback percentage after fracturing operations is only 40%, which means that 60% of the fracturing fluid is still in the formation when the well is brought online. Production-liquid-sample analysis suggests that the cause of liquid loading is low post-fracturing flowback ratio.
Several deliquefication methods have been applied, such as velocity-string installation that reduces the critical unloading gas flow rate, soap or foam lift (either solid soap stick or liquid soap injection) that reduces the liquid density, and multirate well-testing equipment that increases the gas flow rate above the critical unloading gas rate. At the initial implementation of soap sticks, it was observed that incremental gas production was below expectations. This poor response was judged to be the result of the dosing quantity, and frequency trial-and-error judgments of the operators.