An Efficient Reservoir - Coupled Gas Gathering System Simulator (1979)

Abstract Stringent requirements to maintain high deliverability capacity, large lead time on delivery of equipment, and widely fluctuating seasonal gas demands present a special predictive well management problem for the southern North Sea gas fields. It problem for the southern North Sea gas fields. It was thus essential to develop the ability to generate accurate and realistic production and deliverability forecasts. An existing gas simulator was modified to take into account not only the effects of the gathering system but also the salient features of the gas sales contract. By using a sparse matrix solution technique with optimal ordering of gathering system nodes, the gathering system simulation time was reduced to a small fraction of the reservoir simulation time. The details of the algorithms developed form the subject of this paper. Introduction In order to generate realistic and accurate production and deliverability forecasts, an existing production and deliverability forecasts, an existing single phase dry gas reservoir simulator was modified to take into account:the surface gathering network effects;salient features of a gas salescontract; andspecial modeling requirements forefficient inclusion of the above twoitems in the computation of production and deliverability forecasts under various operating conditions. A noniterative algorithm has been devised for determining production rates such that the contractually imposed deliverability capacity requirements for fulfilled. The gas sales contracts for the southern North Sea gas fields have provisions for seasonal gas demand fluctuations. They also stipulate high deliverability capacity requirements to be maintained, particularly over the winter months when demand for particularly over the winter months when demand for gas is the highest. A single-phase dry gas reservoir model has been extensively used to study performance of the southern North Sea gas fields. This model assumed that all wells would be produced against a fixed wellhead pressure; the effect of compression was simulated by lowering this constant wellhead pressure for all wells. The fixed wellhead pressure pressure for all wells. The fixed wellhead pressure was chosen on the basis of pressure drop experienced in getting the maximum contractually required volume of gas on shore to the delivery point (a fixed deliver pressure being assumed). pressure being assumed).This concept was sufficiently valid for predicting the initial compression timing requirement. However, once a field goes on decline, the assumption of fixed wellhead pressure would choke back wells unnecessarily, thereby reducing computed economic life and ultimate recovery of the field. Also, the incremental value of compression would be overestimated for the following reason. In the run with higher fixed wellhead pressure (i.e., no compression case), the wells would be choked back immediately after the field went on decline, thereby unduly restricting production. The incremental production rate versus time due to compression would production rate versus time due to compression would thus be overestimated, making the calculated present worth of the compression too favorable. An attempt was made to account for the reduced wellhead pressure as the field went on decline. This was in the form of a wellhead pressure versus throughout curve and was solely based on the main pipeline characteristics. However, this could not pipeline characteristics. However, this could not take in to accountthe effect of a compression unitinstalled on a single platform as opposed to a compression unit for the entire field;interference effects in the surface gathering system from other producing platforms having different producing wellhead pressures; andcomplex and simple pipeline loopings in the gathering system.