Better Results Using Integrated Production Models for Gas Wells

Abstract

Abstract While each engineering discipline may have a piece of the puzzle to find the best solution for achieving optimized production rates and economics, we can only hope to achieve the best results if we use a total system (reservoir to sales point) approach. Relatively simple to use software tools are available to help and can be easily applied, especially on gas wells. However, effective use of these tools will require the engineering disciplines to break down silos, possibly compromise on using their "favorite" tools and work together. Examples and case histories on gas wells are shown to demonstrate how each discipline looks at solving problems and how better solutions are found using an integrated production model (IPM). Introduction There are usually at least two and more typically three engineering disciplines charged with optimizing production in a gas field. Reservoir, production and facilities/process engineers ideally work together to get optimum results, however each discipline has a different area of responsibility and expertise. Typically the reservoir engineer works from the reservoir to the well's perforations, the production engineer handles the perforations to the surface choke and the facilities/process engineers cover the facilities from the choke to the sales point. Multi-discipline teams were created in many companies in the 1990's to try to insure good communication and synergistic solutions. However, in most cases the tools to optimize solutions were not integrated and each discipline continued using tools designed to optimize its piece of the puzzle. In many cases the discipline specific tools use a level of sophistication (such as numerical simulators running compositional models) that makes integration very difficult or overly simplistic tools (for example single phase pressure drop calculations) that are insufficient to provide an optimized solution. A particular weakness is that typical facilities and production engineering tools provide solutions at a single point in time but do not provide flow streams over time needed to make economic evaluations. There are now several easy to use software packages that can be applied to provide integrated solutions that are fit for purpose and include flow streams over time. These tools can be applied relatively quickly to answer many of the problems encountered in typical gas fields including the optimum tubing size and amount and timing of compression required. Examples are presented to show how IPM can be used for gas wells to provide better solutions than those arrived at by discipline specific or serial "discipline to discipline" solutions. Discipline Specific Approaches ReservoirEngineering. The typical reservoir engineering approach to gas wells has been to use decline curve analysis and/or material balance calculations to determine remaining reserves and analyze options for optimal depletion. These methods provide adequate results for typical wells when the correct "economic limit" and/or minimum flow rate are applied to decline curves and the appropriate recovery assumption and/or abandonment pressure are applied to material balances. However, the economic limit for gas wells is heavily dependent on the surface pressure and associated compression costs. The minimum rate of flow achievable, expected percent recovery of original gas in place, and the abandonment pressure also depend on surface pressure as well as the size of tubing, location of end of tubing in relation to the producing zones, and the productivity of the well. Even in the case of detailed reservoir simulators, appropriate vertical lift performance (VLP) tables must be used and typically surface facilities are ignored and replaced with a set surface or system pressure. In some case simplified rules of thumb are used to predict rate changes in different scenarios. Production Engineering. Typically production engineers have used nodal systems analysis and/or liquid load up rate calculations1 and rules of thumb to analyze well performance and options for optimal depletion. These tools typically provide a better VLP match and may model a surface flow line but usually do not model compression and use a fixed surface and reservoir pressure.