Successful Application of Integrated Digital Automation System for Production Optimization in the North San Juan Basin

Abstract

An integrated digital automation system has been used successfully to efficiently optimize tubing flow control and plunger lift installations in North San Juan basin. This paper presents description, application, and significant results achieved by using an intelligent closed looped digital integrated automation system. Results included increased gas production, equipment reliability, also, efficient and inexpensive deliquification method through almost exclusively remote-controlled operations. The smart digitally enhanced system consists of two parts; the Remote Terminal Unit (RTU) and the SCADA-host. The common RTU application is deployed across all well sites and utilizes a common application load. Where and when needed, new feature selections have been added however complete backwards compatibility has been maintained. This is made possible mainly by abstracted I/O and a modular programming technique. The SCADA-host which is also a common unifying system provides interface to all wells for surveillance, monitoring and control capability. The system displays the current system layout graphically. Historical trends are also easily retrievable. Gas production increment of over 4MMcfd has been achieved and sustained in less than 40 plunger lift installations mainly due to availability of high quality digital automatic control system coupled with effective utilization of plunger lift data. By itself, the system adjusts plunger arrival time, after flow and shut-in time based on pre-set operating range to maximize gas production. Thirty tubing flow control installations have resulted in an average gas production uplift of 130Mcfd per well. In tubing flow control application, the casing valve is automatically controlled based on well conditions. This allows a well to flow gas through tubing above critical gas rate while releasing friction and backpressure on the formation by producing additional gas through the tubing-casing annulus. It is a simple process that includes a combination of surface equipment and control logic that could not perform faultlessly without intelligent automation system. This is a significant departure from the traditional means of operating gas wells where highly expensive full rig intervention is required to continuously optimize tubing size and artificial lift installation. As expected, improved business performance has been achieved through an intelligent integrated digital automation system. Introduction Gas wells tend to show a decrease in production over time as a result of depleting reservoir pressure. The liquids that are associated with the produced gas accumulate in the gas well. The liquid column that is built up in the well creates hydrostatic backpressure on the well which further reduces the gas flow rate. Turner et al1 and Coleman et al2 models, give the minimum gas flow rates required to lift the entrained liquid droplets to the surface at a specific wellhead pressure. There are several artificial lift and de-watering methods available to lift liquid from the bottom of the well to the surface, one such method being plunger lift. In some of the marginal gas wells, neither gas production nor anticipated production uplift from wells could justify installing more costly artificial lift systems such as a sucker-rod pump to de-water wells. In some other application, given the consideration of low rates, economic feasibility, well characteristics and mechanical integrity - plunger lift became the obvious choice. Plunger lift is an intermittent form of artificial lift, which utilizes the natural energy of the reservoir to lift the liquids out of the well bore. Plunger lift like other forms of artificial lift has benefited from improved digital technology. The entire system is completely monitored and optimized. Unlike conventional natural gas reservoirs in which gas production rates tend to be greatest at the onset, then steadily decline over the life of the well, coal bed methane produced in North San Juan progressively increases in gas production rate to a maximum flow rate years or several days after the first production. It has always been a great challenge to match and optimize tubing and well bore conduit with the ever changing production rate. Application of optimized Tubing-Flow Control is helping to mitigate these challenges.