Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | BaTaweel, Mohammed (Saudi Aramco) | Elktatany, Salaheldin (King Fahd University of Petroleum & Minerals)
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.
In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.
The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
Copyright 2005, Society of Petroleum Engineers This paper was prepared for presentation at the 2005 SPE Production and Operations Symposium held in Oklahoma City, OK, U.S.A., 17 - 19 April 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal 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 a proposal of not more than 300 words; illustrations may not be copied.
Coreflood experiments were conducted on carbonate and sandstone cores from gas-condensate reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by condensate accumulation and water blockage. Field samples of condensate were used in these experiments to mimic twophase flow around the wellbore region when the bottom hole flowing pressure dropped below the dewpoint. The impact of several fluids used as completion fluids was also investigated at reservoir conditions. Several solvents were evaluated to remove both condensate and water blockages.
Experimental results show that reductions of 70% to 95% in gas relative permeability were seen in reservoir cores due to condensate blockage. The studied solvents were found to be effective for enhancing gas relative permeability. This study also quantified the required methanol treatment volumes to increase gas relative permeability at lab conditions, which could be extrapolated to field conditions. The reduction in gas relative permeability was more pronounced during two-phase flow in the presence of water saturation due to the dual effect of condensate and water blockage. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period.
Methanol-water mixtures were ineffective in removing condensate blockage and decreased gas productivity after their treatment. Methanol was effective in removing water from the cores. A mixture of isopropyl alcohol and methanol yielded similar favorable results as pure methanol. In summary, the evaluated solvents were all effective in removing condensate blockage from the core, delayed condensate accumulation, and enhanced gas productivity.