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Collaborating Authors
Results
Deviation from Darcy's Flow in Fractured Tight Gas Sand Reservoirs
Khlaifat, Abdelaziz (Weatherford Oil Tool Middle East, Dubai, UAE) | Qutob, Hani (Weatherford Oil Tool Middle East, Dubai, UAE) | Arastoopour, Hamid (Department of Chemical and Biological Engineering, Illinois Institute of Technology, Chicago, USA)
Abstract Unconventional gas resources will significantly affect the future of the energy sector worldwide in the coming years. The importance of non-Darcy flow has been highlighted in the literature in the context of highly productive fractured gas wells. The low gas flow rates from typical tight gas wells contradict this assumption. Neglecting the non-Darcy flow effect in tight reservoirs will lead to an overestimation of production and other misleading facts about tight gas reservoirs behavior. The interpretation of deviation from Darcy's flow through tight sand porous medium is addressed, in this work, by conducting a series of single phase gas flow experiments. The considered porous medium sample was slot-and-solution pore type tight sand collected from the Travis Peak Formation at a depth of 2654 m with permeability in microdarcy range and porosity of 7%. Two gases, nitrogen and helium, were used. Single-phase gas experiments were carried out at different pressure drops and overburden pressures. The experimental results showed that the examined slot-and-solution tight sand porous media is very sensitive to overburden pressure. Pore size distribution measurements, by mercury intrusion porosimetry and sorption isotherm, showed the existence of a wide range of pore size distribution (from 0.4 to 400 nm). The analysis shows that single phase gas flow through tight gas sand particularly at low pressure is of Knudsen diffusion type. Thus, the gas molecules may slip at the wall of the capillary and the Klinkenberg formulation may be the approach to describe the deviation from Darcy's law when the pore size and particle size are almost the same.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- North America > United States > Louisiana > Travis Peak Formation (0.99)
- North America > United States > Arkansas > Travis Peak Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Imbibition runs at different overburden pressures have been performed on a SFE2-8707 sample from the Travis Peak formation (slot and solution pore type), with an approximate porosity of 7% and gas permeability of 22 to 37 d, using our physical model. The experiment continued for several days until the water flow rate reached the steady state values. The single phase water flow experiments were performed at several inlet and overburden pressures, following the imbibition runs. The results from imbibition and single phase water flow experiments showed that under different overburden pressures, due to the porous structure changes, considerable amounts of pore closing and opening occurred which resulted in an overall increase in permeability of the sample. However, from single phase gas flow experiments an overall decrease in permeability of the sample was observed. Furthermore the single phase transient experiments compared well with steady state runs. This proves the reliability of transient runs which results in significant saving in time and expense for core analysis of tight core samples. Introduction A large portion of gas reservoirs lies in unconventional fields. Among these unconventional resources of gas, Sharer and O'Shea estimated that over 500 trillion cubic feet of natural gas may be recoverable from low permeability sandstones located in the Eastern and Western United States. There are several experimental studies for the measurements of flow properties in tight sand media as well as the petrographic, petrophysical and insitu analyses of tight, sandstones; such as Jones and Owens, Walls et al., Spencer, Chowdiah, Soeder, Soeder and Chowdiah, Narahara and Holditch, Holditch, Robinson and Whitehead. The tight sand porous media may be grouped in the following three distinct categories based on pore geometry:The classic tight sand is basically a conventional sandmade tight by precipitation of minerals in the pore throats. This type usually has the highest permeability as well a slow stress-dependence of permeability among the tight sandstones. Slot and solution pore types are the most common tight sandstones. The narrow and flat slot pores were generated from the reduction of the primary porosity, which occurred along the boundaries of adjoining quartz overgrowths. The flat, poorly-supported structure of the slots gives the high stress-dependence of permeability in this kind of tight sand. Matrix supported grain types are the least common of the tight sandstones. The sand grains are supported in an ultra-fine microporous matrix. This type of pore geometry tends to occur in the lowest permeability tight sand and has a high drop in permeability under increasing stress. Our experiments have been performed on a sample of the second category, slot and solution pore type, which is sensitive to net stress. In this study we particularly focused on the effect of the variation of the net stress on this kind of sample. P. 307^
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- North America > United States > Louisiana > Travis Peak Formation (0.99)
- North America > United States > Arkansas > Travis Peak Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)