SPE 80901 A Successful Methanol Treatment in a Gas-Condensate Reservoir: Field Application Hamoud A. Al-Anazi, SPE, Saudi Aramco, Jacob G. Walker, SPE, Miller and Lents, Ltd., Gary A. Pope, SPE, Mukul M. Sharma, SPE, The University of Texas at Austin, and David F. Hackney, SPE, ChevronTexaco Copyright 2003, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, U.S.A., 22–25 March 2003. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435. Abstract A field test was conducted to investigate the effectiveness of methanol as a solvent for removing condensate banks that form when pressure in the near wellbore region falls below the dewpoint. Core flood experiments on Texas Cream Limestone and Berea cores show that condensate accumulation can cause a severe decline in gas relative permeability, especially in the presence of high water saturation. This can result in well productivity declining by a factor of 3 to 5 as bottom hole pressure declines below the dewpoint. PVT analysis performed on field samples taken from the Hatter’s Pond field in Alabama indicate retrograde condensate behavior. These high-temperature deep gas wells show low gas productivity and large skin. A preliminary analysis of the data indicated the possibility of condensate and water blocking due to the loss of water-based drilling fluids. Core samples were used to measure gas relative permeability. Compatibility tests were conducted to ensure that the injection of filtrate and methanol did not cause any damage to the core. Since the formation brine is very saline, tests were conducted to check for salt precipitation during methanol injection. Based on these laboratory results and a single-well numerical simulation, a field test was conducted. The well chosen for treatment was producing 250 MSCFPD with 87 BPD of condensate. A thousand barrels of methanol was pumped down the tubing at a rate of 5 to 8 B/min. Gas production increased by a factor of 3 initially and stabilized at about 500 MSCFPD. Condensate production doubled to 157 BPD. The well shows a skin of –1.9 after methanol treatment. The increase in gas and condensate production was observed to persist more than 10 months after the treatment. Several possible explanations are provided for the positive results obtained in this test. Some general conclusions are made for the design for future treatments. Introduction Gas production from reservoirs having a bottom hole flowing pressure below the dewpoint pressure results in an accumulation of a liquid hydrocarbon near the wells. This condensate accumulation, sometimes called condensate blocking, reduces the gas relative permeability and thus the well's productivity. Condensate saturations near the well can reach as high as 50-60% under pseudo steady-state flow of gas and condensate. 1 Even when the gas is very lean, such as in the Arun field with a maximum liquid drop out of 1.1%, condensate blocking can cause a large decline in well productivity. 2-4 The Cal Canal field in California showed a very poor recovery of 10% of the original gas-in-place because of the dual effect of condensate blocking and high water saturation. 5 Several methods have been proposed to restore gas production rates after a decline due to condensate and/or water blocking. 6-9 Gas cycling has been used to maintain reservoir pressure above the dewpoint. Injection of dry gas into a retrograde gas-condensate reservoir vaporizes condensate and increases its dewpoint pressure. 8 Injection of propane was experimentally found to decrease the dewpoint and vaporize condensate more efficiently than carbon dioxide. 10 Hydraulic fracturing has been used to enhance gas productivity, but is not always feasible or cost-effective. 5,11 Inducing hydraulic fractures into the formation can increase the bottom hole pressure. Hydraulic fracturing successfully restored the gas productivity of a well that died after the flowing bottom hole pressure dropped below the dewpoint. 12 Recently, a new strategy of using solvents was developed to increase gas relative permeability reduced by condensate and water blocking. 7,9 Al-Anazi et al. 9 found that methanol was effective in removing both condensate and water and restored gas productivity in both low-permeability limestone cores and high-permeability sandstone cores. Gas productivity decreased about the same extent in both low and high permeability cores due to condensate blocking. After methanol treatment, an enhanced flow period is observed in both low and high permeability cores. Condensate accumulation is delayed for a certain time. During this time, the productivity index is increased an order of magnitude in both low and high permeability cores. The duration of the enhanced flow period is controlled by the volume of methanol injected and its rate of mass transfer into the flowing gas phase after treatment. Methanol treatments remove both water and