Application of Horizontal Wells To Reduce Condensate Blockage in Gas/Condensate Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 130996, ’Application of Horizontal Wells To Reduce Condensate Blockage in Gas/ Condensate Reservoirs,’ by Nathan Miller, SPE, Hadi Nasrabadi, SPE, Texas A&M University-Qatar, and Ding Zhu, SPE, Texas A&M University, prepared for the 2010 SPE International Oil & Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed.
Much of the world’s gas reserves can be found in gas/condensate reservoirs. These reservoirs, from a recovery and deliverability standpoint, can have significant differences from oil reservoirs. When the pressure, either in the wellbore or in the reservoir, drops below the dewpoint pressure, a condensate phase appears that reduces gas production significantly. In this study, horizontal wells were used in a giant gas/condensate reservoir (North field, Qatar) to reduce the condensate blockage. Critical questions are: What fraction of a horizontal well’s increased gas production results from the increased formation contact and what fraction results from reducing condensate blockage?
Introduction
The largest gas/condensate reservoirs include the Arun field in Indonesia; the Cupiagua field in Colombia; the Karachaganak field in Kazakhstan; the North field in Qatar, which borders with the South Pars field in Iran; and the Shtokmanovskoye field in the Russian Barents Sea. All of these fields have one thing in common—condensate blockage. Condensate blockage occurs when a liquid phase forms around the wellbore because the pressure falls below the dewpoint pressure. Production performance can decrease significantly if these condensate-banking effects are not understood at the beginning of field development.
Retrograde gases exhibit a lower gas/oil ratio (GOR) limit of 3,300 scf/STB and an upper GOR limit of 150,000 scf/STB. Retrograde gases have stock-tank liquid gravities between 40 and 60°API and can be lightly colored orange, brown, or greenish or can be clear.
The North field is a massive offshore gas/condensate reservoir with more than 900 Tcf of proven natural-gas reserves. The abnormally pressured field covers more than 6000 km2. As Fig. 1 shows, the North field adjoins Iran’s South Pars field, which has 280 Tcf of recoverable natural-gas reserves. The initial reservoir pressure was 5,300 psi, and the initial reservoir temperature was 220°F. The field produces from a carbonate reservoir called the Khuff formation (late Permian to early Triassic). The Khuff formation consists of four noncommunicating, highly stratified layers. Discovered in 1971, North field appraisal drilling occurred over the next 14 years to quantify the reservoir-gas accumulations and to determine the reservoir-fluid and geological characteristics. The Alpha Project began in 1991 to develop the field’s reserves by producing natural gas and condensate from the Lower Khuff. The first concession was awarded in 1993, the first delivery of condensate occurred in 1996, and the first delivery of liquefied natural gas took place in 1997.