14 Oilfield Review Understanding Gas-Condensate Reservoirs Li Fan College Station, Texas, USA Billy W. Harris Wagner & Brown, Ltd. Midland, Texas A. (Jamal) Jamaluddin Rosharon, Texas Jairam Kamath Chevron Energy Technology Company San Ramon, California, USA Robert Mott Independent Consultant Dorchester, UK Gary A. Pope University of Texas Austin, Texas Alexander Shandrygin Moscow, Russia Curtis Hays Whitson Norwegian University of Science and Technology and PERA, A/S Trondheim, Norway For help in preparation of this article, thanks to Syed Ali, Chevron, Houston; and Jerome Maniere, Moscow. ECLIPSE 300, LFA (Live Fluid Analyzer for MDT tool), MDT (Modular Formation Dynamics Tester) and PVT Express are marks of Schlumberger. CHEARS is a mark of Chevron. Teflon is a mark of E.I. du Pont de Nemours and Company. How does a company optimize development of a gas-condensate field, when depletion leaves valuable condensate fluids in a reservoir and condensate blockage can cause a loss of well productivity? Gas-condensate fields present this puzzle. The first step must be to understand the fluids and how they flow in the reservoir. A gas-condensate reservoir can choke on it s most valuable components. Condensate liquid saturation can build up near a well because of d rawdown below the dewpo i nt pressure, ultimately restricting the flow of gas. The near- well choking can reduce the productivity of a well by a factor of two or more. Th i s phenomenon, called condensat e blockage or condensate banking, results from a combination of factors, including fluid phase properties, formation flow characteristics and pressures in the formation and in the wellbore. I f t h ese f acto r s a r e n ot u n de r stood at t h e beginning of field development, sooner or later production performance can suffer. For example, well productivity in the Arun f ield, in North Sumatra, Indonesia, declined signi f icantly about 10 years af ter production began. This was a serious problem, since well deliverability was critical to meet contractual o bligations f or gas delivery. Well studies , including pressure transient testing, indicated t he loss was caused b y accumulation o f condensate near the wellbore. 1 Arun is one of several huge gas-condensate reservoirs that together contain a significant global resource. Other lar ge gas-condensate resources include Shtokmanovskoye field in the Russian Barents Sea, Karachaganak field i n K azakhstan , the North field in Qatar that becomes the South Pars field in Iran, and the Cupiagua field in Colombia. 2 This article reviews the combination of fluid thermodynamics and rock physics that results in condensate dropout and condensate blockage. We examine implications for production and methods for managing the effects of condensate dropout, including reservoir modeling to predict field performance. Case studies from Russia, the USA and the North Sea describe field practices and results. Forming Dewdrops A gas condensate is a single-phase f luid a t o ri g inal reservoir conditions. It consist s predominantly of methane [C 1 ] and other short- chain hydrocarbons, but it also contains long- chain hydrocarbons, termed heavy ends. Under 1. Afidick D, Kaczorowski NJ and Bette S: “Production Performance of a Retrograde Gas Reservoir: A Case Study of the Arun Field,” paper SPE 28749, presented at the SPE Asia Pacific Oil & Gas Conference, Melbourne, Australia, November 7–10, 1984. 2. For a case study of the Karachaganak field: Elliott S, Hsu HH, O’Hearn T, Sylvester IF and Vercesi R: “The Giant Karachaganak Field, Unlocking Its Potential,” Oilfield Review 10, no. 3 (Autumn 1998): 16–25. 3. Gas-condensate fluids are termed retrograde because their behavior can be the reverse of fluids comprising pure components. As reservoir pressure declines and passes through the dewpoint, liquid forms and the amount of the liquid phase increases with pressure drop. The system reaches a point in a retrograde condensate where, as pressure continues to decline, the liquid revaporizes. 4. Injection of cold or hot fluids can change reservoir temperature, but this rarely occurs near production wells. The dominant factor for fluid behavior in the reservoir is the pressure change. As will be discussed later, this is no longer the case once the fluid is produced into the wellbore.