Co2 relative permeability is a critical parameter affecting many aspects of Co2 injection for Enhanced Oil recovery and Co2 storage including; injectivity and trapped phase saturation.
In this study, we use measured Co2 - brine relative permeability data available in the literature to study the behaviour of the data obtained for various rocks. These measured Co2 relative permeabilities show large variations in the values of relative permeability and also in the trend of the relative permeability curves.
We identify the rock internal structure or quality as a controlling factor with considerable impact on Co2 relative permeability and we offer an explanation for the observed variation in Co2 relative permeability behaviour. We use a pore network model with different pore and throat distributions to verify the effect of rock pore and throat distributions on Co2 relative permeability. Based on our definition, a normal pore-throat distributions with similar connection produces a regular Co2 relative permeability curve shape which gives a high Co2 injection rate whereas in an abnormal pore-throat distribution with dissimilar connection, it is observed that the Co2 relative permeability curve shape is almost vertical .
We extended the work to the investigation of the impact of the rock internal structure on the Co2 injection characteristics particularly on Co2 injection rate. We found that normal pore-throat distributions with similar connection result in much higher Co2 injection rate than do the abnormal pore-throat distributions with dissimilar connection.
The results of this study will allow us to identify rocks that would be more suitable for Co2 injection (e.g., higher injectivity requiring lower number of injection wells) on the basis of the structure and distribution of the pores inside the rock.
Introduction and Objective.
In most petroleum engineering literatures, the relative permeability of Co2 has been studied for each formation separately and the main factors considered to affect the Co2 relative permeability are; fluid saturation, hysteresis and interfacial tension. As for a group of formations with different rock types, the difference in Co2 relative permeability curves is mainly attributed to rock type parameters. However, it has been found that even in a set of samples extracted from different formations in the same rock type or from a single formation, there is diversity in Co2 relative permeability curves. Rock pore structure or quality has been assumed to be responsible of the observed disparity, but no detailed explanation has been offered as to how it could results in different Co2 relative permeability curves for a set of formations in the same rock type. In this work, we are introducing an improved concept of pore and throat distribution, which will be used to interpret the observed differences in Co2 relative permeabilities.
Slick water hydraulic fracturing treatments are the preferred method for stimulation of tight hydrocarbon plays as these treatments enhance the complexity of fracture networks, increase fracture lengths, reduce formation damage and decrease treatment costs. These characteristics of a slick water treatment are critical to produce economic wells in unconventional formations. Even though these treatments are effective, they also have disadvantages that can limit production and increase treatment costs. With slight modifications to the treatment design of traditional slick waters - the addition of a novel chemical and 5% nitrogen - the limitations can be reduced.
The performance of the slick water treatment is improved by modifying the proppant's surface properties. A novel surfactant preferentially adsorbs onto the surface of the proppant (for both quartz and ceramic), hydrophobically modifying the surface of the solids. The enhanced surface properties create an attraction between the proppant surface and nitrogen gas, in effect, surrounding the particle with a thin layer of gas and thus increasing the buoyancy of the proppant in water. These enhanced properties allow for improved proppant distribution, deeper proppant penetration within the complex fracture network, increased proppant pack volume, and increased maximum proppant concentration that can be placed. Improving proppant placement and increasing the volume that the proppant occupies within the fracture enhances the conductivity of the fracture network, therefore improving the productivity of the well.
Laboratory studies of polymer adsorption, sand pack column flow analysis, crush resistance and brine compatibility testing will be presented to complement laboratory analyses previously published. Case studies of field treatments will also be provided. The first case study uses pad wells and compares the new system to traditional fracturing fluids. It will show that, without changing any other variables in the treatment design, production is enhanced significantly. The other two case studies will illustrate how production has been increased in two formations in the Western Canadian Sedimentary Basin.
The Hussar experiment was carried out in September 2011 with the purpose of acquiring broadband seismic data, including low frequencies, to be used in inversion methods. Three wells located close to the seismic line and a dynamite-source dataset, acquired with three-component 10 Hz geophones, were used for a post-stack inversion test using commercial software. Several low-frequency cut-off filters applied to the data were tested with the 3-5 Hz model being selected as the optimum. The resultant impedance reflects lateral changes that were not present in the initial model and therefore are derived from the seismic reflections. Impedance changes in the target zone shows the general trend and relative variations, which would allow changes in the reservoir as variations in the rock properties occur. A final inversion was performed to simulate traditional approaches when the low-frequency component is absent in the seismic data. Filtered seismic-data (10-15-60-85 Hz) and an initial model with a 10-15 Hz cut-off were used for this test. The results at the well locations show a good match but the lateral variation and character of the events resemble more the initial model character.
Akinnikawe, Oyewande (Texas A&M University) | Chaudhary, Anish (Texas A&M University) | Vasquez, Oscar (Texas A&M University) | Enih, Chijioke (Texas A&M University) | Ehlig-Economides, Christine A. (Texas A&M University)
Previous studies have shown that bulk carbon dioxide (CO2) injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk because of aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO2 in a CO2/brine displacement. Two approaches to CO2/brine displacement are considered--an external brine-disposal strategy in which brine is disposed of into another formation such as oilfield brine and an internal saturated brine-injection strategy with which the produced brine is desalinated and reinjected into the same formation. The displacement strategies increase the storage efficiency from 0.48% for the bulk-injection case to more than 7%. A conceptual case study with documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is sufficient to store all the CO2 being generated by power plants in the vicinity for approximately 20 years only. However, the CO2/brine displacement increases storage efficiency enough to store the CO2 produced for at least 240 years at the current rate of coal-fired electric-power generation. Sensitivity analyses on relative permeability, permeability, and temperature were conducted to see the effects of these reservoir parameters on storage efficiency.
For bulk injection, increased permeability resulted in increased storage efficiency, but for the CO2/brine-displacement strategies, decreased permeability increased storage efficiency because this resulted in higher average pressure that increased CO2 storage per unit of pore volume (PV) and increased CO2 viscosity. Also, storage efficiencies for the displacement strategies were highly sensitive to relative permeability. There is an optimal CO2-injection temperature below which the formation-fracturing pressure is lowered and above which CO2 breakthrough occurs for a smaller injection mass. The CO2/brine-displacement approach increased capital expenditures for additional wells and an operating expense for produced-brine disposal, but these additional costs are offset by increased CO2-storage efficiency at least 12 times that achieved by the bulk-injection strategy.