Treatment of Condensate and Water Blocks in Hydraulic-Fractured Shale-Gas/Condensate Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 665-674 ◽  
Author(s):  
Reza Ganjdanesh ◽  
Mohsen Rezaveisi ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Vapor Pressure ◽  
Shale Gas ◽  
Gas Production ◽  
Gas Condensate ◽  
Significant Drop ◽  
Pressure Drops ◽  
Gas Condensate Reservoirs ◽  
Water Blocking ◽  
High Vapor ◽  
Bottomhole Pressure

Summary The accumulation of condensate in fractures is one of the challenges of producing gas from gas/condensate reservoirs. When the bottomhole pressure drops to less than the dewpoint, condensate forms in and around fractures and causes a significant drop in the gas relative permeability, which leads to a decline in the gas-production rate. This reduction of gas productivity is in addition to the reduction because of water blocking by the fracturing water. Solvents can be used to remove liquid blocks and increase gas- and condensate-production rates. In this paper, dimethyl ether (DME) is introduced as a novel solvent for this purpose. In addition to good partitioning into condensate/gas/aqueous phases, DME has a high vapor pressure, which improves the flowback after the treatment. We compare its behavior with both methanol (MeOH) and ethanol (EtOH) solvents.

scholarly journals Wettability Alteration of Sandstone by Chemical Treatments

2013 ◽  
Vol 2013 ◽  
pp. 1-8 ◽  
Author(s):  
Yan-ling Wang ◽  
Li Ma ◽  
Bao-jun Bai ◽  
Guan-cheng Jiang ◽  
Jia-feng Jin ◽  
...  
Keyword(s):  
Contact Angle ◽  
Contact Angle Measurement ◽  
Angle Measurement ◽  
Gas Production ◽  
Gas Condensate ◽  
Dew Point ◽  
Wettability Alteration ◽  
Pressure Drops ◽  
Gas Condensate Reservoirs ◽  
Chemical Treatments

Liquid condensation in the reservoir near a wellbore may kill gas production in gas-condensate reservoirs when pressure drops lower than the dew point. It is clear from investigations reported in the literature that gas production could be improved by altering the rock wettability from liquid-wetness to gas-wetness. In this paper, three different fluorosurfactants FG1105, FC911, and FG40 were evaluated for altering the wettability of sandstone rocks from liquid-wetting to gas-wetting using contact angle measurement. The results showed that FG40 provided the best wettability alteration effect with a concentration of 0.3% and FC911 at the concentration of 0.3%.

Case Study of Condensate Dropout Effect in Unconventional Gas/Condensate Reservoirs with Hydraulically Fractured Wells

2022 ◽  
Author(s):  
Ali H. Alsultan ◽  
Josef R. Shaoul ◽  
Jason Park ◽  
Pacelli L. J. Zitha
Keyword(s):  
Gas Production ◽  
Gas Condensate ◽  
Dew Point ◽  
Productivity Index ◽  
Large Reservoir ◽  
Unconventional Gas ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Reservoir Volume ◽  
Fracture Performance

Abstract Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.

Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs

2020 ◽  
Vol 185 ◽  
pp. 106566
Author(s):  
Sadegh Dahim ◽  
Amin Taghavinejad ◽  
Milad Razghandi ◽  
Hamed Rahimi Rigi ◽  
Kianoosh Moeini ◽  
...  
Keyword(s):  
Shale Gas ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Gas Condensate Reservoirs ◽  
Transient Modeling ◽  
Fractured Horizontal Wells

Multiscale Pressure/Volume/Temperature Simulation of Decreasing Condensate/Gas Ratio at Greater than Dewpoint Pressure in Shale Gas-Condensate Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-13
Author(s):  
Sheng Luo ◽  
Fangxuan Chen ◽  
Dengen Zhou ◽  
Hadi Nasrabadi
Keyword(s):  
Pore Size ◽  
Shale Gas ◽  
Local Equilibrium ◽  
Gas Condensate ◽  
Abnormal Behavior ◽  
Fluid Distribution ◽  
Reservoir Pressure ◽  
Heavy Hydrocarbons ◽  
Gas Condensate Reservoirs ◽  
Gas Ratio

Summary In shale gas-condensate reservoirs, when the initial reservoir pressure is greater than the dewpoint pressure, the condensate/gas ratio (CGR) has been observed to decrease continuously as the pressure drops to less than the initial reservoir pressure. This abnormal behavior cannot be explained with conventional pressure/volume/temperature (PVT) models that ignore the presence of nanopores in shale rock. Herein, for the first time, we present a study that provides a physical explanation for the observed CGR trends by including the effect of nanopores on the fluid phase behavior and depletion of shale gas-condensate reservoirs. Our model uses multiscale PVT simulation by means of a pore-size-dependent equation of state (EOS). Two lean gas-condensate cases (shallow and deep reservoirs) are investigated. The simulation results show that hydrocarbons distribute heterogeneously with respect to pore size on the nanoscale. There are more intermediate to heavy hydrocarbons (C3–11+) but fewer light ends (C1–2) distributed in the nanopores than in the bulk region. At the end of depletion, because of confinement effects, large amounts of intermediate hydrocarbons are trapped in the nanopores, causing condensate recovery loss. Multiscale depletion simulations suggest that a decreasing CGR can occur at the beginning of production when the reservoir pressure is higher than the dewpoint pressure. Such behavior is caused by the nanopore depletion in the shale matrix, which is a process of selectively releasing light hydrocarbon components. We also present a novel approach to model the nonequilibrium fluid distribution between the fracture and nanopores using a simple local-equilibrium concept. Our results indicate that the nonequilibrium fluid distribution increases the CGR drop because of the compositional selectivity of the nanopore in favor of intermediate and heavy hydrocarbons.

Gas Injection EOR in Eagle Ford Shale Gas Condensate Reservoirs

2019 ◽  
Author(s):  
Reza Ganjdanesh ◽  
Wei Yu ◽  
Mauricio Xavier Fiallos ◽  
Erich Kerr ◽  
Kamy Sepehrnoori ◽  
...  
Keyword(s):  
Shale Gas ◽  
Gas Injection ◽  
Gas Condensate ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Gas Condensate Reservoirs
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