The Impact of Condensate Blockage and Completion Fluids on Gas Productivity in Gas-Condensate Reservoirs

Abstract

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. Introduction Gas production from reservoirs flowing at bottom hole pressure lower than the dewpoint pressure, precipitates the accumulation of a liquid condensate in the near wellbore region. This condensate accumulation, also referred to as condensate banking, reduces the gas relative permeability and thus the well's productivity. Condensate saturations in the near wellbore region can reach as high as 50–60% under pseudo steady-state flow conditions.[1] Even when the gas is very lean, such as in the Arun field, with a maximum liquid drop out of 1.1%, condensate banking can cause a drastic 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 banking 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] Hydraulic fracturing is a commonly used technique to restore the gas productivity of wells in which the flowing bottom hole pressure has dropped below the dewpoint.[12] High water saturation in the formation after a stimulation or workover treatment reduces the gas relative permeability. The adverse effect of condensate banking increases in the presence of high water saturation. A water block may occur when capillary forces exceed formation gas pressure. Under this scenario, water remains in the reservoir and it is flowed back at a very low rate. There are numerous examples of wells that required long periods of time to restore the initial gas productivity following liquid injection into the formation. The negative impact of water blockage increases in low permeability formations where the capillary forces are high or in low pressure reservoirs.[6,11,13]

Wettability Alteration of Reservoir Rocks from Liquid Wetting to Gas Wetting Using Nanofluid

“…• re-perforating the wellbore, and solvent injection (Al-Anazi et al 2005;Liangui et al 2000;Alzate et al 2006) • dry gas injection (condensate re-vaporization) (Smith and Yarborough 1968;Shi et al 2001) • water injection, nitrogen injection to drive condensate back (Siregar et al 1992) • increasing reservoir contact using horizontal well (Muladi and Pinczewski 1999) • hydraulic fracturing, and near wellbore wettability alteration are additional examples to mention Apart from the wettability alteration method, other methods are not permanent solutions and the condensate bank will re-form (Li and Firoozabadi 2000a). The latter authors (2000b) studied the gas condensate system using a phenomenological network model and investigated the effects of interfacial tension, gravity, flow rate, contact angle hysteresis and network size on the critical condensate saturation.…”

Permanent Alteration of Porous Media Wettability from Liquid-Wetting to Intermediate Gas-Wetting

“…As the pressure drops below the dew-point pressure, condensate accumulates at the wellbore in high saturations and reduces gas relative permeability (Barnum et al 1995;El-Banbi et al 2000). The injection of a volatile solvent such as an alcohol has been implemented to remove the accumulated liquid (Ahmed et al 1998;Du et al 2000;Walker et al 2000;Al-Anazi et al 2005b) at the wellbore to increase gas well deliverability. In a methanol stimulation treatment in Hatter's Pond field in Alabama (Al-Anazi 2005a) where there was an initial decline in well deliverability by a factor of three to five due to condensate blocking, gas deliverability increased by a factor of two after dissolving water and condensate liquids in methanol in the wellbore region.…”

“…Fahes and Firoozabadi (2007) and Al-Anazi et al (2007) used ethanol solvent; Kumar et al (2006) used methanol-water solvent. The treatment with pure alcohol is not permanent (Al-Anazi et al 2005b;Du et al 2000) and the treatment is less effective than the chemical surfactants (Noh and Firooaabadi 2008a).…”

Effect of disjoining pressure on the onset of condensate blockage in gas condensate reservoirs

“…This problem is recognized as condensate blockage. It may reduce the gas production down to 5% of the initial rate (Al-Anazi et al, 2005). Therefore, due to its importance, the flow behavior of gas and condensate near the wellbore region, and the associated problem of condensate blockage has been the subject of intensive research (Al-Anazi et al, 2005;Henderson et al, 1995Henderson et al, , 1996Jamiolahmady et al, 2000).…”

“…It may reduce the gas production down to 5% of the initial rate (Al-Anazi et al, 2005). Therefore, due to its importance, the flow behavior of gas and condensate near the wellbore region, and the associated problem of condensate blockage has been the subject of intensive research (Al-Anazi et al, 2005;Henderson et al, 1995Henderson et al, , 1996Jamiolahmady et al, 2000). The main result of these studies is that flow behavior in gas condensate reservoirs is essentially different from the two-phase gas/oil flow within under-saturated oil reservoirs (Henderson et al, 1995(Henderson et al, , 1996.…”