Multi-Well Gas Lift

summary netx's multi well gas lift scenarios enable rapid screening of injection gas allocation across multiple wells connected to a single compressor to enable a rapid solution, pressure drops across surface pipelines are not considered solution fundamentals and methodology netx wells are connected to wells modeled in prodx, and when a scenario is ran, the latest gas lift performance curve will be used for optimization wells can be configured to be fixed (i e leave the well at it's current operating point) or optimize (i e allow the operating point of the well to change during optimization) wells can be configured to handle liquid loading critical rates (or critical injection rates) in different ways hard an optimized well cannot operate below critical injection rate soft an optimized well can operate below critical injection rate shut in below an optimized well will be shut in if the optimal solution for the compressor requires a well to go below the critical injection rate well level constraints are considered explicitly and the solver cannot propose potential solutions that are in violation of well level constraints the optimization's objective function is maximizing cash flow, which is based on the wells' gas lift optimization settings in prodx wells which are shut in or cannot compute a gas lift performance curve for the latest day will be held constant with the values reported in docid\ jnogjwoaowkpzzaho3pkp compressors have a max gas lift injection constraint which sets the maximum gas available for allocation other compressor level constraints are, in reality, system level constraints (max oil rate, water rate, liquid rate, and gas rate) they are configured under the compressor for simplicity these other constraints are handled using a penalty function in the solver, which can lead to some edge cases where they are violated slightly or aggressively (such as starting a scenario run with impossible system level constraints) each compressor > well(s) system in the network is solved independently the compressor gas allocation optimization problem is solved using differential evolution ( https //en wikipedia org/wiki/differential evolution this is used to adequately sample the solution space while minimizing the possibility of local maxima (cash flow maxima) at a sub optimal solution potential drawbacks for any given well, assuming a constant injection pressure at varying gas lift injection rates (especially major changes in injection rate) is fundamentally incorrect and can lead to inaccurate vlps caution should be exercised on compressor > well configurations which have extreme changes in injection rates conversely, solving a full pressure problem for large compression networks may take prohibitively long to converge, making the simplified, multi well gas lift scenario an adequate screening tool differential evolution (or any optimization methodology) is not guaranteed to yield a global maximum cash flow when aggressively constrained or solving compressors with large well counts, results should be scrutinized to ensure the engineer is satisfied with the result before implementing any changes in general, a typical gas lift performance curve has a point every 50 mscf from 0 2000 mscf, there would be 40 points if the compressor feeds 20 wells, there are at least 20^40 = 1 1 10^52 possible solutions (assuming a solution can only exist at the points of the original gas lift performance curves) exploring every possible solution would be physically impossible