Browsing by Subject "Fracturing fluid"
Now showing 1 - 2 of 2
Results Per Page
Sort Options
Item Measurement of fluid properties in organic-rich shales(2015-12) Jung, Chang Min; Sharma, Mukul M.; Chenevert, Martin E.; van Oort, Eric; Balhoff, Matthew; El Mohtar , ChadiThe primary objective of this study is to develop and improve water-based drilling fluids and fracturing fluids for organic rich shale reservoirs by using nanoparticles and to gain fundamental insight into water and oil flow in shales. This dissertation presents results for several shale formations in the US, namely the Barnett shale, the Eagle Ford shale, the Utica shale, and the Bakken shale. The research discussed here presents new methods for studying the interaction between various fluids and organic-rich shale and the development of proper methods to measure apparent and relative permeability of shale. First of all, we show how the petrophysical properties of shales are changed when they are poorly preserved. Experiments were performed to measure important petrophysical properties such as porosity, density, weight change, hardness, wave velocity and permeability before and after shale samples dried-out. The large differences in shale properties between preserved and un-preserved samples as reported herein, clearly indicate that shales should be preserved at the well site and tested with a standard procedure ensuring minimum alteration of fluids from the shale. Failure to follow a standard procedure leads to measurements that do not reflect the “true” or in-situ properties of the shale. Instead, the measurements can be a factor of 2 or 3 different from the “true” value. The shale handling, preservation and measurement techniques and procedures presented here can be used as a standard protocol for studying organic rich shales. Next, we discuss how fracturing fluid can change the petrophysical properties of shale. Among the various petrophysical properties, the fluid permeability is chosen to determine the effect of the fracturing fluid on the shale. Experimental procedures are presented to suggest how to measure the shale permeability. To measure the fluid permeability, the Pressure Penetration Technique (PPT) was developed and used. The reference permeability with sea water brine was measured and then fracturing fluid was injected into the shale. The brine permeability was re-measured to see the effect of exposure to the fracturing fluid, and experimental data show the permeability change due to fracturing fluid plugging the shale. Next, we focus on the development of a Water Based Mud (WBM) system for organic-rich shale. Drilling through a shale formation can result in borehole instability problems, and this is known to add substantial costs to the operation. This is because conventional drilling fluids tend to interact with clay minerals in shales, and the mechanical properties of rock are changed by clay swelling. To reduce the interaction between water-based muds and shales, we need to reduce water invasion into the shale. The addition of nanoparticle additives to water-based drilling fluids can significantly reduce the invasion. We report results for shale permeability and pressure penetration though shales using different fluids: brine, base mud and nanoparticle based muds. To better define the effect of nanoparticles, we used different concentrations of nanoparticles in the mud. From the large reduction in permeability and the pressure response results, we clearly show that nanoparticles act as good shale inhibitors to ensure wellbore stability during drilling. Experimental studies used to measure the relative permeability of shale. Such measurements have never been done before. Due to the extremely low permeability of shale, it is very difficult to measure the relative permeability of shale directly. We propose a method of relative permeability measurement using NMR (Nuclear Magnetic Resonance) spectroscopy to measure fluid saturations and a RPC (relative permeability measurements under a confining pressure) set-up to conduct the displacement. RPC set-up is a newly developed forced injection set-up using the unsteady-state method. The in-situ fluid saturation was successfully measured with NMR, and the set-up was also useful for measuring the relative permeability of shale. It yielded continuous results from the Bakken shale tests.Item Simulation and design of energized hydraulic fractures(2009-08) Friehauf, Kyle Eugene; Sharma, Mukul M.Hydraulic fracturing is essential for producing gas and oil at an economic rate from low permeability sands. Most fracturing treatments use water and polymers with a gelling agent as a fracturing fluid. The water is held in the small pore spaces by capillary pressure and is not recovered when drawdown pressures are low. The un-recovered water leaves a water saturated zone around the fracture face that stops the flow of gas into the fracture. This is a particularly acute problem in low permeability formations where capillary pressures are high. Depletion (lower reservoir pressures) causes a limitation on the drawdown pressure that can be applied. A hydraulic fracturing process can be energized by the addition of a compressible, sometimes soluble, gas phase into the treatment fluid. When the well is produced, the energized fluid expands and gas comes out of solution. Energizing the fluid creates high gas saturation in the invaded zone, thereby facilitating gas flowback. A new compositional hydraulic fracturing model has been created (EFRAC). This is the first model to include changes in composition, temperature, and phase behavior of the fluid inside the fracture. An equation of state is used to evaluate the phase behavior of the fluid. These compositional effects are coupled with the fluid rheology, proppant transport, and mechanics of fracture growth to create a general model for fracture creation when energized fluids are used. In addition to the fracture propagation model, we have also introduced another new model for hydraulically fractured well productivity. This is the first and only model that takes into account both finite fracture conductivity and damage in the invaded zone in a simple analytical way. EFRAC was successfully used to simulate several fracture treatments in a gas field in South Texas. Based on production estimates, energized fluids may be required when drawdown pressures are smaller than the capillary forces in the formation. For this field, the minimum CO2 gas quality (volume % of gas) recommended is 30% for moderate differences between fracture and reservoir pressures (2900 psi reservoir, 5300 psi fracture). The minimum quality is reduced to 20% when the difference between pressures is larger, resulting in additional gas expansion in the invaded zone. Inlet fluid temperature, flowrate, and base viscosity did not have a large impact on fracture production. Finally, every stage of the fracturing treatment should be energized with a gas component to ensure high gas saturation in the invaded zone. A second, more general, sensitivity study was conducted. Simulations show that CO2 outperforms N2 as a fluid component because it has higher solubility in water at fracturing temperatures and pressures. In fact, all gas components with higher solubility in water will increase the fluid’s ability to reduce damage in the invaded zone. Adding methanol to the fracturing solution can increase the solubility of CO2. N2 should only be used if the gas leaks-off either during the creation of the fracture or during closure, resulting in gas going into the invaded zone. Experimental data is needed to determine if the gas phase leaks-off during the creation of the fracture. Simulations show that the bubbles in a fluid traveling across the face of a porous medium are not likely to attach to the surface of the rock, the filter cake, or penetrate far into the porous medium. In summary, this research has created the first compositional fracturing simulator, a useful tool to aid in energized fracture design. We have made several important and original conclusions about the best practices when using energized fluids in tight gas sands. The models and tools presented here may be used in the future to predict behavior of any multi-phase or multi-component fracturing fluid system.