Dynamic Simulation Establishes Water-Cut Limits for Well Kickoff

Abstract

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88543, "Impact of Dynamic Simulation on Establishing Water-Cut Limits for Well Kickoff," by Juan Carlos Mantecon, SPE, and Iris Andersen, Scandpower Petroleum Technology; David Freeman, SPE, Woodside Energy Ltd.; and Mark Adams, SPE, Helix-RDS, prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October. Dynamic well modeling can provide understanding and a process that ensures a well is going to flow naturally during initial kickoff or predict the water-cut limits for the restart/kickoff of naturally flowing wells after a shut-in. As reservoir pressure declines and water cut increases, naturally flowing wells often require gas lift (or some other method of artificial lift) to kick off and flow continuously. Generally, these wells encounter kickoff problems at a lower water cut than their natural-flow limit because of fluid-segregation effects in the wellbore under static conditions. Therefore, determining the kickoff limit is of primary importance to determine the optimum gas lift implementation schedule and its economic effect. Dynamic modeling of the wells during kickoff can determine the associated flowing tubinghead pressure (FTHP) that will enable the well to attain steady-state flow as a function of well productivity index (PI), reservoir pressure, and water cut. Introduction A well producing oil, water, and gas will exhibit segregation of the three fluids in the tubing during shut-in. When the well is first opened after the shut-in period, the column of gas is produced from the tubing, leaving a higher-density mixture of oil, water, and new reservoir fluid. The flowing bottomhole pressure (FBHP) of the well reaches a maximum at the point when the gas column has been produced from the tubing. As shown in Fig. 1, in certain circumstances, the weight of fluid in the tubing at this point in time does not allow the well to flow, and the well is deemed to have a kickoff problem. The water cut at which the kickoff problem is experienced usually is lower than the water cut at which the well will naturally stop flowing. Four undersaturated-oil fields with eight wells producing through a subsea system to the Cossack Pioneer floating production, storage, and offloading vessel were studied. Gas lift is expected to be required sometime in the future to kick off production from wells in the Wanaea, Lambert, and Hermes fields. The Cossack field already had gas lift installed in the single producing well (Cossack 4). The Wanaea, Lambert, and Hermes wells do not use artificial lift, although the wells do have gas lift valves installed. Studies to support the installation of gas lift flowlines and sufficient additional compression to meet future artificial-lift requirements are under way. The cost for installation of a gas lift system to support the kickoff of the Wanaea, Lambert, and Hermes wells is significant, and deferring this expenditure could increase asset value. However, the inability to kick off the wells has a bigger value effect in terms of deferred production, typically 10 times greater than the capital-expense-deferment savings.