Modeling, simulation and optimization of continuous gas lift systems for deepwater offshore petroleum production J.N.M. de Souza a, ⁎, J.L. de Medeiros a,1 , A.L.H. Costa b,2 , G.C. Nunes c,3 a School of Chemistry, Federal University of Rio de Janeiro, UFRJ, Centro de Tecnologia, Bloco E, sala 209, Cidade Universitária, Ilha do Fundão, CEP 21949-900, Rio de Janeiro, RJ, Brazil b Institute of Chemistry, Rio de Janeiro State University, UERJ, Rua São Francisco Xavier, 524, Pavilhão Haroldo Lisboa da Cunha, Maracanã, CEP 20550-900, Rio de Janeiro, RJ, Brazil c Petróleo Brasileiro S.A.- PETROBRAS, Av. República do Chile, 65, Centro, CEP 20031-912, Rio de Janeiro, RJ, Brazil abstract article info Article history: Received 22 May 2009 Accepted 29 March 2010 Keywords: Gas lift Optimization Two-phase Pipeline network Gas allocation Simulation This paper proposed a framework for the analysis of continuous gas lift systems using an optimization algorithm coupled to a stationary two-phase flow network model. The objective function can consider the annualized capital costs on compressor, turbine and gas pipelines, the operating costs related to fuel and the revenue from produced oil. The interaction among wells, production lines and riser is properly evaluated by a stationary two-phase flow simulator for pipe networks composed by mass balances at network elements and momentum balances at pipes using the Beggs and Brill empirical correlation. The solution of the optimization problem can estimate important information for the conceptual design phase of a petroleum production system: (i) the injected gas flow rates that guarantees maximum oil production, (ii) the injected gas flow rates for maximum profit and (iii) optimal design of gas lift system considering capital costs of compressor, turbine and gas pipelines. Case studies of single and multiple wells with different complexities describe some applications of the proposed framework. At the first case study, an offshore petroleum well with gas lift artificial elevation is simulated – to determine the behavior of petroleum production as a function of the injected gas flow rate for different reservoir pressures and different wellbore diameters – and optimized—to determine the maximum production considering different productivity indexes. At the second case study, a complex petroleum production system with multiple wells is simulated and optimized to obtain the optimal design considering annualized costs of compressor, turbine driver, gas pipelines and fuel gas consumption. © 2010 Elsevier B.V. All rights reserved. 1. Introduction The high oil prices increase efforts in exploration and production, development of marginal fields and enhanced oil recovery projects. “Worldwide average oil recovery factor is expected to increase substantially from the current figure of around 35% due to technology development, adding significant resources to the reserve base” (Kjärstad and Johnsson, 2009). In many cases of deepwater production, when the reservoir pressure is not sufficient to guarantee the oil elevation up to surface with a viable economical return, the necessity of artificial lift technologies to enhance the recovery factor is mandatory. A very common and efficient technique is the gas lift, where the injection of lean gas in a certain position of the well reduces the mean density of the liquid column and thus decreases the hydrostatic pressure. Two methodologies are commonly applied: Continuous Gas Lift (CGL) and Intermittent Gas Lift (IGL). As this work is restricted to stationary two- phase flow, only the CGL is considered. The quantity of injected gas is a critical variable whereas a lower value can reduce significantly the production and a higher value can increase the operational costs with compression and gas usage. In most cases, it is possible to verify the oil production that reaches a maximum value for a certain injected gas flow rate. Many authors explored this optimization problem determining the optimal operational conditions to extract the maximum quantity of oil for single well models (Fang and Lo, 1996) and multiple wells model (Alarcon et al., 2002; Ray and Sarker, 2007) and considering or not the constraints on gas availability and using different formulations: linear programming (Fang and Lo, 1996), mixed integer linear programming (Kosmidis et al., 2005), non-linear programming (Alarcon et al., 2002), dynamic programming (Camponogara and Nakashima, 2006) and genetic algorithms (Ray and Sarker, 2007). As described by Dutta-Roy and Kattapuram (1997), the gas lift optimization problem shall consider the effect of flow interactions Journal of Petroleum Science and Engineering 72 (2010) 277–289 ⁎ Corresponding author. Tel.: +5521 25627637, +5521 82125066. fax: +5521 25627535. E-mail addresses: jaimenms@yahoo.com.br (J.N.M. de Souza), jlm@eq.ufrj.br (J.L. de Medeiros), andrehc@uerj.br (A.L.H. Costa), giovanicn@petrobras.com.br (G.C. Nunes). 1 Tel.: +5521 25627637; fax.: +5521 25627535. 2 Tel.: +5521 25877322. 3 Tel.: +5521 32245875. 0920-4105/$ – see front matter © 2010 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2010.03.028 Contents lists available at ScienceDirect Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol