Increasing the Production from Marginal Gas Wells

Abstract

Abstract A large number of gas production wells in Europe are mature and are virtually incapable of lifting liquid, which has built up over time, out of the well. A well in a gas field was suffering from these liquid loading problems. The gas pressure was insufficient to unload the well for an extended period of time. A proprietary computer model, developed by Baker Petrolite and specifically designed to identify wells which will respond to chemical treatment, was used to determine whether a foamer product could help unload the gas well. Removal of the water would also help to reduce downhole corrosion. The application of the foamer also had to take into account the different gas well operating standards in Europe compared to those of some other parts of the world. Subsequent selection of the foamer was achieved by the use of the computer model and by laboratory test work using actual well fluids. Consequently the chemical was applied downhole by continuous injection via capillary tubing. The maximum production rate achieved during the trial was 0.1 MMSCMD. The volume of gas production was increased five-fold. No problems were encountered with downstream processing. The use of this foamer technology was of considerable value to the gas producer in this marginal field. It was shown that the rapid and methodical use of these unique services can help alleviate the loss in gas production shown by wells suffering from liquid loading. Introduction Gas production systems are normally designed to enable the extraction of oil and gas as soon as possible. The designer therefore may use large well and pipeline diameters to allow high flow rates in the early stages of extraction from the reservoir. Later on in the life of the well or the pipeline gas flow rates decrease to a point where water can accumulate due to depletion in the reservoir. The gas is unable to transport liquid out of the well bore.[1] The accumulation of water in the well tubing can cause a back pressure that decreases production and reservoir recovery. In some cases the liquid hydrostatic head caused by accumulation in the well bore can kill the well. The accumulated water can also cause substantial corrosion.[2] Corrosion problems occur due to the constant water wetting in the tubing, the water containing dissolved acid gases such as carbon dioxide. The build up of fluids (largely water) in a pipeline can also decrease gas production and contribute to increased corrosion. Therefore the removal of water from the well tubing and pipeline should increase production and also improve the system asset integrity. Certain chemical additives can change the physical properties of the liquids being produced. The right choice of additives can change the well or pipeline characteristics to enable the removal of liquids from the well tubing and mixed production pipelines. In such cases the benefit to the operator can be very significant. The use of these types of chemical surfactants, called foamers, to revive gas wells is now an established procedure. In addition, the environmental profile of the chemicals involved is frequently positive. For example, chemicals are in use which have a Hazard Quotient (HQ) less than one for CHARM (i.e. are in the Gold band for the UK) and which also pass the pre-screening process. The chemical surfactant helps the removal of water by changing its properties: decreasing the density of the liquid droplets and also allowing the formation of smaller droplets. The surface active nature of the chemical changes the liquid surface tension. This use of a chemical solution is a relatively simple and cost effective way of maintaining or increasing gas production. The existing gas flow coupled with the use of the surfactant removes the liquid from the well.