Production Optimization of Liquid Loading Gas Condensate Wells: A Case Study

Abstract

Abstract Liquid production can be a serious problem in gas condensate wells nearing the end of their production life. As the pressure in the drainage area is depleted, the gas velocity in the production tubing falls below the critical rate resulting in inadequate energy to lift all the condensate out of the wellbore. The condensate migrates down the tubing and collects at the bottom of the completion increasing the bottom hole flowing pressure and, in many cases, killing the well. A similar liquid loading problem can be also encountered in low productivity gas condensate wells. This paper investigates the behaviour of gas condensate wells in a deep basin fractured sandstone reservoir in Alberta. Regardless of the initial well productivity, sooner or later, declining reservoir pressures and/or poor productivity cause wells to liquid load. The first and the cheapest solution is to produce these wells intermittently. Although such wells continue to flow, the liquid fallback still tends to increase the average flowing bottom hole pressure, thus reducing the production rate. The paper discusses the process of selecting the best candidates among such wells for the next level of intervention, which is the installation of plunger lift systems. As a result, 19 wells were equipped with plunger lifts and a significant production increase has been observed. The project has been a technical and economic success so far and is now being extended to the rest of the field. Introduction The presence of a liquid phase during gas production has long been recognized as detrimental to well flow. In gas condensate reservoirs, as the gas in the reservoir travels towards the wellbore, it encounters decreasing pressures and as a result, a liquid hydrocarbon phase (condensate) is formed below the dew point pressure(1). Furthermore, as the gas travels to the surface, the pressure and temperature decreases causing more liquid to drop out of the gas phase. As long as the gas flow rate is sufficiently high to maintain annular mist flow, these liquids are lifted out of the well. However, when the tubing velocity becomes too small to maintain steady flow conditions, liquid accumulation in the well becomes a problem. The problem can be attributed to a low gas production rate due to low bottom hole pressure in a mature reservoir and/or low gas relative permeability for given conditions(1). The flow regime in the wellbore switches from annular mist flow to churning or slug flow and the liquid lifting capacity of the gas decreases dramatically. The flow rate for this switch is called the critical flow rate(2, 3). Below the critical flow rate, liquids tend to migrate down the tubing and start to collect at the bottom. For a while, the well will be able to unload small slugs on its own. The well will eventually stop flowing continuously and the fluid is produced in small "heads" with spikes of gas. If no remedial measures are taken, the problem will worsen as the liquids continue to accumulate in the tubing and the production rate continually decreases(4, 5).