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Collaborating Authors
Results
Abstract Transient N2-foam flow experiments were conducted in a heterogeneous sandstone core to improve our understanding of how foam flows in these complex systems. An apparatus with an aluminum core holder and a medical x-ray CT scanner was built to measure the aqueous-phase saturation nondestructively. Pressure readings along the length of the core, were recorded using six pressure taps drilled into the core. We coinjected the foamer solution and the gas at the core's inlet and allowed foam generation to occur inside the core. Measurements of the aqueous-phase saturation and of the pressure at various times enabled us to track and analyze the transient foam behavior in the core. Three foam qualities were tested ranging from low quality (gas fractional flow) of 33% to high quality of 90%. Results show that gas initially drains the core and forms weak foam before crossing a permeability discontinuity present in the core. The travel distance from the inlet until the point of entrance into the permeability discontinuity was inversely proportional to the water content of the foam. Wetter foams required a shorter distance before the gas entered the low-permeability layer. Crossing the permeability discontinuity, the weak foam became stronger as evidenced by the drop in aqueous-phase saturation and the increase in the pressure gradient. Once strong foam was generated, it traveled to the outlet in a piston-like fashion. After it breaks through the outlet, a second front appears to be traveling backward toward the inlet against the direction of flow. Diversion to lower-permeability layers occurs during this second front movement. This observation was validated qualitatively by a simple pore network model that is equipped with the invasion percolation with memory algorithm. The results of the network show the diversion occurring once strong foam generates in the high-permeability zone and explain the discontinuous aqueous-phase saturation observed during the first foam front movement.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Microscale Dynamics of Oil Connectivity and Mobilization by Controlled-Ionic-Composition Waterflooding at Evaluated Temperature Using Synchrotron 3D X-Ray Microscopy
Qin, Tianzhu (Chemical Sciences and Engineering Division, Argonne National Laboratory) | Fenter, Paul (Chemical Sciences and Engineering Division, Argonne National Laboratory) | AlOtaibi, Mohammed (EXPEC Advanced Research Center, Saudi Aramco) | Ayirala, Subhash (EXPEC Advanced Research Center, Saudi Aramco)
Abstract Controlled-ionic-composition waterflooding improves oil displacement efficiency in heterogeneous carbonate rocks. Recent microscale experimental studies confirm that the injection of brines containing high sulfate ion concentrations alters the wettability of the pore surfaces and improves oil mobilization at elevated temperature. However, the dynamics of associated with changes in the microscale brine/oil/rock interactions at typical field flow rates is unclear due to the limited temporal resolutions of leading micro-CT scanners, which often require hours for data acquisition. The goal of this study is to investigate microscale dynamics of oil connectivity and mobilization by controlled-ionic-composition waterflooding at evaluated temperature using synchrotron-based 3D X-ray microscopy. Heterogeneous carbonate rocks were saturated and aged with formation brine and oil at 90 °C, then flooded with brine containing different ion types and concentrations at 90 °C. Each flooding cycle was visualized using 3D X-ray microscopy at Advanced Photon Source. This source is the brightest hard X-ray source in the U.S. and therefore enables us to visualize the oil displacement at high temporal resolutions (45s). The experimental results show that injection brine containing high sulfate concentration rapidly increases the oil connectivity across the porous medium within the first few minutes and consequently improves oil recovery from pores regardless of pore sizes.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.89)
- Geology > Mineral (0.59)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.57)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
Simulation of Water and Condensate Blockage and Solvent Treatments in Tight Formations Using Coupled Three-Phase Flash and Capillary Pressure Models
Neshat, Sajjad S. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Water and condensate blockage near production wells in unconventional reservoirs can significantly reduce oil and gas production rates. This paper presents a new approach for more accurate modelling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. A cubic equation of state is used to model the phase behavior of three-phase mixtures of solvent, hydrocarbons and water. The three-phase flash model is coupled with a rigorous three-phase capillary pressure model to account for the effect of capillary pressure. The capillary pressure function includes the impact of several important petrophysical properties such as pore size distribution and wettability. A compositional simulator is used to simulate the effectiveness of using methanol, dimethyl ether or CO2 to remove liquid blockage and increase production rate.
- Overview > Innovation (0.48)
- Research Report > New Finding (0.47)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract This paper discusses a review and adaptation of some classic waterflood performance analytical methods, such as X-plot, comprehensive Y-plot (cY-plot), and WOR vs cumulative oil (Np) for the case of unstable immiscible displacement (viscous-oil fingering effect). These methods were reviewed based on fractional flow analysis (FFA) for unstable immiscible waterflood. These classic techniques account for the solution of the one-dimension frontal advance Buckley-Leverett theory (1942), assuming stable flow. In addition, the traditional semilog linear relationship between oil-water relative permeability ratio and water saturationis assumed (constant parameters A and B). Those assumptions tend toover predict ultimate oil recovery for the case of viscous-oil waterfloods because flow functions do not capture the viscous fingering effect. This work proposes to redefine aforementioned classic waterflood performance analytical methods with novel oil and water relative permeability expressions derived from the effective-fingering model(EFM) presented by Luo et al. (2016), which accounts for viscous fingering effects. In addition, an accurate exponential expression of kro/krw ratio as function of water saturation and an exact solution for a water saturation-dependent parameter B (named Bj) are proposed. New approaches of classic analytical methods were derived, and both laboratory and field cases were tested at the light of new equations. Adaptation of classic equations (stable) to solutions that account for unstable flow results in more reliable diagnostic-plot techniques for the case of viscous-oil, allowing to correct predictions of oil and water production in the case of heavy-oil waterflooding Additionally, new equations resulted in unified solutions that can be applied for both stable and unstable waterflood and help to improve reliability when estimating ultimate oil recovery, volumetric sweep efficiency, and various reservoir parameters. In the presence of viscous fingering, the water breakthrough and oil recovery from new X, cY, and WOR functions are viscous-finger number dependent (Nvf). The bigger the Nvf the lower the oil recovery, the earlier the water breakthrough, and the narrower the water saturation ranges. In its entirety, these novel waterflood performance analytical methods incorporate viscous fingering features in the traditional flow functions, encouraging the ability to predict ultimate oil recovery for both unstable and stable waterflooding cases and for chemical flooding (i.e., polymer with future adaptation) in heavy-oil reservoirs and facilitating the optimization of heavy-oil enhanced oil recovery (EOR) projects. These results might provide a basis to adapt other classic waterflood performance analytical methods.
Experimental Study on Calculating Capillary Pressure from Resistivity
Hou, Binchi (Research Institute of Shaanxi Yanchang Petroleum (Group) CO., LTD.) | Liu, Hongliang (China Petroleum Logging TuHa Business Division) | Bian, Huiyuan (Xi'an University of Science and Technology) | Wang, Chengrong (China Petroleum Logging TuHa Business Division) | Xie, Ronghua (Daqing Oilfield CO.LTD., PetroChina) | Li, Kewen (China University of Geosciences(Beijing)/Stanford University)
Abstract Capillary pressure and resistivity in porous rocks are both functions of wetting phase saturation. Theoretically, there should be a relationship between the two parameters. However, few studies have been made regarding this issue. Capillary pressure may be neglected in high permeability reservoirs but not in low permeability reservoirs. It is more difficult to measure capillary pressure than resistivity. It would be useful to infer capillary pressure from resistivity well logging data if a reliable relationship between capillary pressure and resistivity can be found. To confirm the previous study of a power law correlation between capillary pressure and resistivity index and develop a mathematical model with a better accuracy, a series of experiments for simultaneously measuring gas-water capillary pressure and resistivity data at a room temperature in 16 core samples from 2 wells in an oil reservoir were conducted. The permeability of the core samples ranged from 9 to 974 md. The gas-water capillary pressure data were measured with confining pressures using a semi-porous plate technique. We developed the specific experimental apparatus to measure gas-water capillary pressure and resistivity simultaneously. The results demonstrated that the previous power law model correlating capillary pressure and resistivity works well in many cases studied. A more general relationship between the exponent of the power law model and the rock permeability was developed and verified using the experimental data.
- Asia > China (1.00)
- North America > United States > Texas (0.29)
- Research Report > New Finding (0.65)
- Research Report > Experimental Study (0.41)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Enhanced oil displacement in a reservoir is highly affected by wettability alterations in conjunction with the lowering of viscosities during steam assisted gravity drainage (SAGD) for bitumen extraction. The impartation of energy in the form of heat to the fluid by injecting steam triggers an alteration to a more water-wet state during SAGD. However, the presence of three distinct phases in the reservoir has implications for the effective modeling of the complex fluid dynamics. Dependency of the relative permeability endpoints on the temperature realized as a function of the introduction of steam is difficult to model. Optimization of any steam process requires simulation in order to adequately characterize years of flow and so a model that is capable of representing three phase flow is necessary. To obtain this a pseudo-two phase relative permeability is proposed that assumes fractional flow theory is valid and treats the experiments as a waterflood. In this study, experimental recovery data for two SAGD experiments and one hot water flood are empirically matched by manipulating relative permeabilities. The analytical approach implemented allows for the representation of fluid flow in the reservoir by achieving a pseudo-two phase relative permeability that results in comparable performance to the experiments. Waterflooding techniques were utilized which allowed for the negation of the steam phase in the model and so two-phase flow was established. The sensitivity of the relative permeability curves to temperature change results in the inability to formulate a generic three-phase curve and so the pseudo-two phase curve is valuable for the purpose of simulation. The methodology presented enables the formulation of a simplified relative permeability that is unique to each process used and in that specific location. The model that was established was validated and proven credible by the good match with the experimentally obtained values.
- North America > United States (1.00)
- North America > Canada > Alberta (0.29)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.91)
- Geology > Rock Type > Sedimentary Rock (0.68)