A Gas-Lift Optimization and Allocation Model for Manifolded Subsea Wells

Abstract

Abstract The increasing need to develop marginal accumulations using subsea equipment and common facilities has highlighted the challenge of the allocation and optimum distribution of fluids within these systems. The commingling of produced fluids requires that an auditible procedure is employed to accurately back-allocate fluids produced from different fiscal regimes. Similarly, there is a requirement to optimise lift gas allocation to ensure that the available gas provides the maximum incremental oil production. A method of optimising lift gas allocation and allocating production within a manifolded subsea development has been developed for use on a portable computer. The basic requirements for the model were that it should be usable by offshore personnel and allow a quick comparison of different operating scenarios. INTRODUCTION Prior to start up of the Ivanhoe and Rob Roy fields, one of the development scenarios considered early water breakthrough with an immediate need for gas lift as an artificial lift mechanism. The variable nature of the two reservoir units within each field dictates that some method of optimising the distribution of lift gas between wells will be necessary to ensure that the available gas-lift gas is used to best effect. Software has been developed to allocate the lift gas in order to maximise productivity by balancing incremental oil production per unit of injected gas for each well. The gas lift optimisation model can then be operated as a decision support system whereby the current and optimum production rates can be compared to recommend operator action according to a set of decision criteria. The production asllocation model can be used to monitor production by utilising the wellhead pressure performance curves created by the system performance module of the optimisation model. This feature enables the correct allocation of total production to individual wells between well tests. The model will be fully employed in the day-to-day management of the field when gas-lift is required to maintain production rates. In its predictive mode the model can be used in combination with reservoir simulation data to identify the incremental improvements that may be achieved through gas lift later in the field life and the impact of gas deficiency. PROJECT BACKGROUND Reservoirs The Ivanhoe and Rob Roy fields are located in the UK Sector Block 15121a, approximately 110 miles north east of Aberdeen. As development of the Ivanhoe and Rob Roy fields progressed, exploration in the 15/21 area continued, resulting in the discovery of the Hamish field with well 15/21b-21. Hamish was appraised, developed and on production two years after its discovery, using the existing Ivanhoe/Rob Roy infrastructure (Figures 1 and 2). The Ivanhoe and Rob Roy and fields produce from two Jurassic intervals, the Main and Supra Piper. The Hamish field produces only from the Main Piper. The Main Piper sands are thicker and generally more productive than the Supra Piper. There are three distinct crude types within the fields (Table 1). Reservoirs The Ivanhoe and Rob Roy fields are located in the UK Sector Block 15121a, approximately 110 miles north east of Aberdeen. As development of the Ivanhoe and Rob Roy fields progressed, exploration in the 15/21 area continued, resulting in the discovery of the Hamish field with well 15/21b-21. Hamish was appraised, developed and on production two years after its discovery, using the existing Ivanhoe/Rob Roy infrastructure (Figures 1 and 2). The Ivanhoe and Rob Roy and fields produce from two Jurassic intervals, the Main and Supra Piper. The Hamish field produces only from the Main Piper. The Main Piper sands are thicker and generally more productive than the Supra Piper. There are three distinct crude types within the fields (Table 1).