Browsing by Subject "Steam injection"
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Item A simulation study of steam and steam-propane injection using a novel smart horizontal producer to enhance oil production(Texas A&M University, 2004-11-15) Sandoval Munoz, Jorge EduardoA 3D 8-component thermal compositional simulation study has been performed to evaluate the merits of steam-propane injection and a novel vertical-smart horizontal well system for the Lombardi reservoir in the San Ardo field, California. The novel well system consists of a vertical steam injector and a horizontal producer, whose horizontal section is fully open initially, and after steam breakthrough, only one-third (heel-end) is kept open. A 16x16x20 Cartesian model was used that represented a quarter of a typical 10acre 9-spot inverted steamflood pattern in the field. The prediction cases studied assume prior natural depletion to reservoir pressure of about 415 psia. Main results of the simulation study may be summarized as follows. First, under steam injection, oil recovery is significantly higher with the novel vertical-smart horizontal well system (45.5-58.7% OOIP at 150-300 BPDCWE) compared to the vertical well system (33.6-32.2% OOIP at 150-300 BPDCWE). Second, oil recovery increases with steam injection rate in the vertical-smart horizontal well system but appears to reach a maximum at about 150 BPDCWE in the vertical well system (due to severe bypassing of oil). Third, under steam-propane injection, oil recovery for the vertical-smart horizontal well system increases to 46.1% OOIP at 150 BPDCWE but decreases to 51.6% OOIP at 300 PDCWE due to earlier steam breakthrough that resulted in reduced sweep efficiency. Fourth, for the vertical well system, steam-propane injection results in an increase of oil recovery to 35.4-32.6% OOIP at 150-300 BPDCWE. Fifth, with steam-propane injection, for both well systems, oil production acceleration increases with lower injection rates. Sixth, the second oil production peak in the vertical-smart horizontal well system is accelerated by 24-50% in time for 150-300 BPDCWE compared to that with pure steam injection.Item Experimental investigation of the effect of increasing the temperature on ASP flooding(2011-12) Walker, Dustin Luke; Pope, Gary A.; Weerasooriya, UpaliChemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent.Item Shear-enhanced permeability and poroelastic deformation in unconsolidated sands(2012-08) Hamza, Syed Muhammad Farrukh; Olson, Jon E.; Holder, Jon T.Heavy oil production depends on the understanding of mechanical and flow properties of unconsolidated or weakly consolidated sands under different loading paths and boundary conditions. Reconstituted bitumen-free Athabasca oil-sands samples were used to investigate the geomechanics of a steam injection process such as the Steam Assisted Gravity Drainage (SAGD). Four stress paths have been studied in this work: triaxial compression, radial extension, pore pressure increase and isotropic compression. Absolute permeability, end-point relative permeability to oil & water (kro and krw), initial water saturation and residual oil saturation were measured while the samples deformed. Triaxial compression is a stress path of increasing mean stress while radial extension and pore pressure increase lead to decreasing mean stress. Pore pressure increase experiments were carried out for three initial states: equal axial and confining stresses, axial stress greater than confining stress and confining stress greater than axial stress. Pore pressure was increased under four boundary conditions: 1) constant axial and confining stress; 2) constant axial stress and zero radial strain; 3) zero axial strain and constant confining stress; and 4) zero axial and radial strain. These experiments were designed to mimic geologic conditions where vertical stress was either S1 or S3, the lateral boundary conditions were either zero strain or constant stress, and the vertical boundary conditions were either zero strain or constant stress. Triaxial compression caused a decrease in permeability as the sample compacted, followed by appreciable permeability enhancement during sample dilation. Radial extension led to sample dilation, shear failure and permeability increase from the beginning. The krw and kro increased by 40% and 15% post-compaction respectively for the samples corresponding to lower depths during triaxial compression. For these samples, residual oil saturation decreased by as much as 40%. For radial extension, the permeability enhancement decreased with depth and ranged from 20% to 50% while the residual oil saturation decreased by up to 55%. For both stress paths, more shear-enhanced permeability was observed for samples tested at lower pressures, implying that permeability enhancement is higher for shallower sands. The pore pressure increase experiments showed an increase of only 0-10% in absolute permeability except when the effective stress became close to zero. This could possibly have occurred due to steady state flow not being reached during absolute permeability measurement. The krw curves generally increased as the pore pressure was increased from 0 psi. The increase ranged from 5% to 44% for the different boundary conditions and differential stresses. The kro curves also showed an increasing trend for most of the cases. The residual oil saturation decreased by 40-60% for samples corresponding to shallow depths while it increased by 0-10% for samples corresponding to greater depths. The reservoirs with high differential stress are more conducive to favorable changes in permeability and residual oil saturation. These results suggested that a decreasing mean stress path is more beneficial for production increase than an increasing mean stress path. The unconsolidated sands are over-consolidated because of previous ice loading which makes the sand matrix stiffer. In this work, it was found that over-consolidation, as expected, decreased the porosity and permeability (40-50%) and increased the Young’s and bulk moduli of the sand. The result is sand which failed at higher than expected stress during triaxial compression. Overall, results show that lab experiments support increased permeability due to steam injection operations in heavy oil, and more importantly, the observed reduction in residual oil saturation implies SAGD induced deformation should improve recovery factors.