Temperature And Pressure Gradients In Gas Wells

Abstract

Abstract A stepwise procedure has been developed for successive calculation of pressure and temperature gradients in gas wells during production or injection. The method, based on a thermodynamic energy balance in the well bore and the usual equations for the flow of natural gas in vertical pipe, is shown to give reasonably accurate predictions when evaluated on the basis of actual field measurements. Assumptions of succession of steady states in the well bore and approximate independence from local unsteady heating or cooling of geothermal gradient appear to be justifiable for reasonably short flow times encountered in storage service. Considerations related to design of deep storage fields where use of down hole chokes may permit elimination of heating and pressure regulation at the field gathering system are discussed in light of results obtained. Introduction Gas storage technology involves much of the knowledge used in natural gas production. Differences however, consist of annually renewed reservoir pressures, high rates of gas injection and withdrawal and use of pressures above discovery. The coupling of well temperature changes with pressure changes and the use of bottom hole chokes pressure changes and the use of bottom hole chokes to avoid consumption of fuel for heating in controlling pressures and temperatures at the surface gas gathering system are topics of current interest. Recent developments affecting natural gas production and storage industry prompted production and storage industry prompted reassessment of design procedures related to flow of gas through tubing, casing or casing-tubing annulus. Control and regulation of pressure at the surface, prevention of cooling the gas beyond hydrate prevention of cooling the gas beyond hydrate thresholds require that temperature and pressure effects to be well understood and properly attended for optimum design. Under certain conditions flow through casing or casing-tubing annulus and use of properly sized down hole chokes permit more optimal properly sized down hole chokes permit more optimal temperature and pressure conditions at the well head by taking advantage of heat exchange with prevailing geothermal gradients near the well bore. prevailing geothermal gradients near the well bore. Also, recent interest in and prospects for geothermal energy as well as storage of compressed air or hydrogen require that our understanding of pressure-flow relations in the well bore be pressure-flow relations in the well bore be augmented to include more realistic concepts of nonisothermal flow. The literature presently available on temperature distributions in the well bore include such studies in unsteady-state well bore heat transmission, understanding and interpretation of temperature profiles in water injection wells. While the reference (1) above gives an approximate analytical solution to calculate temperature in the well bore it is basically directed to geothermal wells involving the flow of hot water and steam. The paper includes two examples; one on air and one on hot natural gas injection. The work presented in this paper is also based on assumption of steady state heat transfer in the well bore involving thermodynamic energy balance and the established relations for vertical flow of natural gas through pipe. The unsteady distortion around the well bore pipe. The unsteady distortion around the well bore of geothermal gradient due to long time flow is found not to affect appreciably the temperature distribution in the well bore for the time frame related to Storage operations. In all cases computed by the stepwise method described in this paper the maximum deviation between the predicted paper the maximum deviation between the predicted and measured temperatures remained under 10 percent. PROBLEMS IN GAS STORAGE INVOLVING TEMPERATURE AND PROBLEMS IN GAS STORAGE INVOLVING TEMPERATURE AND PRESSURE GRADIENTS IN WELLS PRESSURE GRADIENTS IN WELLS Figure 1 shows schematically the temperature and pressure gradients in wells during storage operations. Curve A shows the static hydraulic gradient prevailing underground. Many storage reservoirs employ a delta pressure, where the gas pressure at pay level exceeds the discovery pressure at pay level exceeds the discovery pressure. pressure.