Alaskar, Mohammed N. (Stanford University) | Ames, Morgan F. (Stanford University) | Connor, Steve T. (Stanford University) | Liu, Chong (Stanford University) | Cui, Yi (Stanford University) | Li, Kewen (Stanford University) | Horne, Roland N. (Stanford University)
The goal of this research was to develop methods for acquiring reservoir pressure and temperature data near the wellbore and farther out into the formation and to correlate such information to fracture connectivity and geometry. Existing reservoir-characterization tools allow pressure and temperature to be measured only at the wellbore. The development of temperature- and pressure-sensitive nanosensors will enable in-situ measurements within the reservoir. This paper provides the details of the experimental work performed in the process of developing temperature nanosensors. The study investigated the parameters involved in the mobility of nanoparticles through porous and fractured media. These parameters include particle size or size distribution, shape, and surface charge or affinity to rock materials.
The principal findings of this study were that spherically shaped nanoparticles of a certain size and surface charge compatible with that expected in formation rock are most likely to be transported successfully, without being trapped because of physical straining, chemical, or electrostatic effects. We found that tin-bismuth (Sn-Bi) nanoparticles of 200 nm and smaller were transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle size range. We also found that the entrapment of silver (Ag) nanowires was primarily because of their shape. This conclusion was supported by the recovery of the spherical Ag nanoparticles with the same surface characteristics through the same porous media used during the Ag nanowires injection. The entrapment of hematite nanorice was attributed to its affinity to the porous matrix caused by surface charge. The hematite coated with surfactant (which modified its surface charge to one compatible with flow media) flowed through the glass beads, emphasizing the importance of particle surface charge.
Preliminary investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. We found that silica microspheres of different sizes (smaller than the fracture opening) could be transported through the fracture. We demonstrated the possibility of using microspheres to estimate fracture aperture by injecting a polydisperse microsphere sample. It was observed that only spheres of 20 µm and smaller were transported. This result agreed reasonably well with the measurement of hydraulic fracture aperture (27 µm), as determined by the cubic law.
Capillary pressure might be ignored in high-permeability rocks, but it cannot be neglected in low-permeability rocks. To study the effect of capillary pressure on production performance in low-permeability oil wells or reservoirs, the formulas for calculating water cut and dimensionless total and oil productivity indices (PIs) were derived by considering capillary pressure. PI and water-cut data were computed using the new models with capillary pressure included. The results proved that PI increases with water cut in high-permeability rocks but decreases with the increase in water cut within a specific range in low-permeability rocks. Waterflooding experiments were then conducted in core samples with low and high permeabilities. The experimental waterflooding data demonstrated the same relationship between PI and water cut that was proved in the new PI model. Finally, the PI data were calculated using production data from oil wells, and the results were compared with the experimental data of the PI determined from coreflooding tests. The curves of PI vs. water cut, obtained from the production data of oil producers, were consistent with those inferred from waterflooding data in core samples. Note that the core plugs were sampled from the same oil wells. The new PI model was used to explain the difference in production performance between high- and low-permeability oil wells..
Most of the "easy?? oil in high permeability reservoirs has been explored and developed to a great extent. More and more "difficult?? oil has been discovered. There are many problems in developing the "difficult?? oil in low or extremely low permeability reservoirs. One of the problems is the pressure sensitivity of permeability which declines significantly as pore pressure decreases or net overburden pressure increases. There have been a few mathematical models to calculate oil or gas production by considering the pressure sensitivity of permeability. However most of the models have not been verified using field production data. In this study, a new production model has been derived theoretically with the pressure sensitivity of permeability considered. Using the production data from a low permeability (less than 1.0×10-3µm2) oil field (Yushulin, Daqing), the model has been tested and verified. The pressure sensitivity coefficient of permeability has been calculated by using the new model with the field data. The results calculated using the new model also showed that the permeability near the well bottom decreased significantly because of the drop in pressure in low permeability reservoirs. An obvious permeability decline funnel could be formed even the formation was homogeneous before development. It was found that the productivity index is no longer a constant in low permeability reservoirs with serious pressure sensitivity of permeability. According to this study, it is necessary to consider the pressure sensitivity of permeability when low permeability reservoirs are being developed. Otherwise, the production will be greatly overestimated.
Proppant embedment plays a significant role in decreasing fracture aperture and conductivity, especially for weakly consolidated sandstones, shale (oil and gas) rock, and coal beds. Empirical and semi-empirical models were usually used to calculate the embedment of proppants. However the accuracy of matching or predicting the proppant embedment using these existing models may not be satisfactory in some cases. On the other hand, it is difficult to determine the coefficients of these models In this study, analytical models were derived to compute the proppant embedment and fracture conductivity.
These new models can be used to calculate the proppant embedment, proppant deformation, the change in fracture aperture and fracture conductivity in the ideal or experimental situations of either single-layer or multi-layer patterns in the fractures under closure pressures. The new models showed that the proppant embedment and fracture conductivity are affected by the factors of closure pressure, fracture aperture, the elastic modulus of proppant and coal bed, the size of proppant, the concentration of proppant-paving, etc.
Experimental data of proppant embedment in fractures and fracture conductivity of different proppants at different closure pressures were used to test the models derived in this study. The results from matching the experimental data using the new and the existing models were compared. The results showed that the new models especially the revised new models could match the experimental data in all of the cases studied.
The new models for calculating the proppant embedment and fracture conductivity with a better accuracy are of great significance in selecting proppants, which is helpful to achieve high fracture conductivity and then high oil or gas productions of conventional, especially unconventional resources such as shale oil, shale gas, and coal bed methane.
The purpose of hydraulic fracturing is to create high conductivity fractures in the formations targeted for the recovery of energy resources (hydrocarbons, steam, and water for geothermal energy). Due to the interaction between proppants and fracture surface in the condition of closure pressure, the proppants embed into the formations, which results in the decreasing in fracture aperture and conductivity. Comparing with sandstone, the elastic modulus of the weakly consolidated sandstones, shale rocks and coal beds are small, so the proppant embedment may be more serious. Proppant embedment would reduce fracture aperture from 10 to 60 % with subsequent reduction of productivity from oil and gas wells in weakly consolidated sandstone, and about a 20 % reduction in fracture aperture might restrict fluid flow and recovery by 50 to 60 % (Lacy et al., 1998). It is clear that the proppant embedment plays a significant role for the stimulation effect of hydraulic fracturing. Therefore, it is of importance to study the theoretical computation and the influencing factors of proppant embedment.
Polymer flooding has been used to enhance oil production and reduce water cut for a long time. However there are still many fundamental challenges in characterizing the multi-phase fluid flow, even the single-phase fluid flow, associated with polymer flooding. For example, it is difficult to measure and calculate two-phase polymer solution/oil relative permeability. One of the difficulties comes from the non-Newtonian and time-dependent properties of polymer solutions; another comes from the change in absolute permeability caused by the adsorption of polymer on rock surfaces. Almost all of the methods for computing relative permeability are based on the assumption that the absolute permeability is constant. It will be helpful to further understand the mechanisms and develop more reliable methods for calculating two-phase polymer solution/oil relative permeability by investigating the single-phase polymer flooding more profoundly. In this study, a new method has been developed to calculate the pseudo permeability during single-phase polymer flooding. The non-Newtonian property of the polymer solutions was considered in the proposed method. A series of polymer flooding experiments using different concentrations of polymers were designed and conducted to study the single-phase flow of polymer solution in rocks with different permeabilities. The values of the pseudo permeability of single-phase polymer flooding were then calculated using the new method. It has been found that the relationships between the pseudo permeability and the reciprocal of shear rate were linear. The pseudo polymer flooding permeability extrapolated at the infinite shear rate was close to the brine flush permeability after polymer injections in most of the cases.
Keywords: permeability measurements, dilatant behavior, non-Newtonian fluids, polymer flooding, single-phase flow.