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Abstract The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower the effective conductivity even for the portions of the fracture above the wellbore. Laboratory and field studies are presented comparing various sizes and types of proppants and the influence of surfactants used in oil bearing formations including commonly used demulsifiers and a multi-phase complex nano fluid system. Ammot cell and centrifuge tests were used to evaluate imbibition of oil and water. Columns packed with proppant and formation cuttings are used to compare the effectiveness of various additives in allowing the displacement of water and establishing oil flow. Results are correlated with interfacial tension, contact angle, capillary pressures and surface energies of actual formation materials, oils and treating fluids from the Niobrara, Bakken, Granite Wash and Eagleford formations. Simulations are presented that show the impact of capillary pressure and oil viscosity on the displacement of fluids. Field results from various fields including the Niobrara, Bakken, and Marcellus formations are presented. The normalized field data shows that wells with higher conductivity proppants and properly selected surfactant packages result in longer effective frac lengths and greater normalized oil and gas production. Correlations are made between the observed relative perms in the lab vs. the observed field results.
- North America > United States > West Virginia (1.00)
- North America > United States > Texas (1.00)
- Geology > Rock Type > Sedimentary Rock (0.99)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (23 more...)
Wettability in CO2/Brine/Quartz Systems: An Experimental Study at Reservoir Conditions
Saraji, Soheil (Department of Chemical and Petroleum Engineering, University of Wyoming) | Goual, Lamia (Department of Chemical and Petroleum Engineering, University of Wyoming) | Piri, Mohammad (Department of Chemical and Petroleum Engineering, University of Wyoming)
Abstract A new experimental setup is developed that is capable of performing accurate IFT and contact angle measurements under extreme conditions, i.e., high pressure (up to 15,000 psi), high temperature (up to 200°C), and with highly corrosive fluids. The apparatus is equipped with an advanced and accurate temperature control system and a pulse-free Quizix pump to provide precise and stable experimental pressures and temperatures. Pre-equilibration of phases is achieved before each test, outside the measurement cell, to avoid non-equilibrium effects. Using an advanced drop shape analysis technique (ADSA-NA) and an automated polynomial fit, advancing and reseeding contact angles were measured with a protruded needle. The results cover a range of temperatures and pressures including subcritical and supercritical CO2 phases allowing characterization of wettability under both conditions. This preliminary study shows that wettability of quartz surface alters towards less water-wet condition when CO2 phase changes from subcritical to supercritical conditions. In addition, changes in wettability of quartz may not be monotonous function of temperature.
- Research Report > New Finding (0.64)
- Research Report > Experimental Study (0.40)
Abstract Wettability is a key property, which controls multiphase fluid flow in oil recovery processes. It is well known that the asphaltene deposition on rock surface changes the wettability of the rock. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration in crude oil/brine/rock (COBR) system because of asphaltene deposition; a sophisticated mathematical model describing this phenomenon is absent. In this paper, based on available experimental data in the literature and known physical mechanisms of asphaltene deposition on the rock in the COBR system, a model for wettability alteration due to asphaltene instability in crude oil is presented. Contact angle is introduced as a function of asphaltene stability index (ASI), which is determined thermodynamically based on the difference between the fugacity of asphaltene and the heaviest component in the oil. The shape of this function depends on pH, salinity and cation valency of brine, and asphaltene content of crude oil. We implemented our proposed model along with asphaltene precipitation, flocculation, and deposition models into an in-house compositional simulator, UTCOMP, developed at The University of Texas at Austin. Permeability and porosity reduction due to asphaltene deposition are also considered. Furthermore, relative permeabilities and capillary pressure are modified because of contact angle alteration during simulation. Although the amount of asphaltene deposition in the reservoir may not be comparable to the wellbore, a significant change in wettability occurs after the deposition of first layer of asphaltene on the rock surface. The result of our simulation shows that wettability alteration affects oil recovery, specifically when the brine produces unstable water film on the rock surface. In this case, rock wettability can change from 30° (water-wet) to 150° (oil-wet) and yield change in recovery depending on absolute permeability reduction magnitude and change in trapped oil saturation as well as end-point relative permeability.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.36)