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Abstract Results of Pashninsky oilfield wells operation monitoring after complex intensification of oil production (IOP) technology treatment are presented in article. The analysis of monitoring results of IOP technology's disadvantage was determined and ways of improvement of the technology were proposed. Based on results of laboratory research the most effective gelling agents for hydrochloric acid composition were proposed. Based on invert-emulsion (IES) new water-blocking solution with SiO2 nanoparticles content was developed. On results of interaction seven different gelling agents with hydrochloric acid composition by chemical laboratory tests have found that the most effective gelling agents are based on cocamide DEA (diethanolamide) agent that enable to reach viscosity by a factor of 3-8 to basic acid composition viscosity. Results of experiments on interactions of invert-emulsion solution with SiO2 nanoparticles content identified that nanoparticles presence into IES assist to structure stability and dynamic viscosity growth up to 800-1500 mPa·s.
Mechanism of Oil Displacement During Polymer Flooding in Porous Media with Micro-Inhomogeneities
Shandrygin, A.. (DeGolyer and MacNaughton) | Shelepov, V.. (Moscow State University) | Ramazanov, R.. (Moscow State University) | Andrianov, N.. (Schlumberger) | Klemin, D.. (Schlumberger) | Nadeev, A.. (Schlumberger) | Safonov, S.. (Schlumberger) | Yakimchuk, I.. (Schlumberger)
Abstract Enhanced oil recovery (EOR) process selection is an important part of field development strategy. One of the most important categories of EOR methods utilize certain chemical components that enhance the fluid properties. Polymer-enhanced waterfloods are one of the examples. During conventional waterfloods, the flow characteristics and displacement efficiency usually depends on a certain rock type in study. In a chemical EOR flood, there are a large number of parameters needed to be defined and optimized that impact process efficiency. The attempt to execute corefloods for various combinations of these parameters for each rock type would lead to a large number of tests not executable in a time frame compatible with timely decision making. And the destructive nature of the experimental chemical EOR floods prohibits repeated testing on the same core sample. The natural difference between the samples selected for the study can prevail over the process efficiency difference related to the certain design parameter in the study. Digital core analysis can help to optimize design of EOR floods and reduce the associated uncertainty. In this work we apply digital core analysis to investigate the dynamics of oil displacement, using water and water-based polymer solutions in porous media. The described technology application includes scanning of core samples using X-ray microtomography, creating digital models for the samples in study, and running pore-scale hydrodynamic modeling using the density functional hydrodynamics (DFH) method, which combines density functional theory with compositional multiphase hydrodynamics. The results include visual snapshots of phase distributions at pore scale for various times during the waterflooding and polymer solution flooding at various concentrations. Polymer-enhanced waterflooding increased the displacement coefficient by almost 2% and 20% for low- and high-concentrated polymer solutions, respectively. This effect was further explained by analyzing the dynamics of oil displacement on a pore scale. The results show an exemplary sensitivity study that investigates the dependency of the displacement coefficient on the polymer solution type and concentration. Additional sensitity studies with varying design parameters (slug size, injection sequence, polymer type, etc.) can be also performed.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
Abstract Heavy oil reservoirs are expected to have viscous anisotropy, both vertical and lateral, with viscosity value varying in the range of several orders of magnitude. Today, there is no any reliable technique to define viscosity anisotropy and to estimate oil viscosity in-situ. The existing methods cannot evaluate the viscosity of crude oil without its lifting to the surface. The solution is the Nuclear Magnetic Resonance (NMR) process which is capable of both reservoir characterization and formation fluid properties analysis. Oil samples in such a case should be collected from reservoir zones that have not been exposed to heat or chemicals. Such samples can be derived, particularly, from oil-saturated core material recovered while drilling wells in newly discovered fields or in untreated reservoir areas. Centrifuge method (HSC) turned out to be the most successful and less laborious. The obtained by HSC samples most accurately reflect the intrinsic properties of potentially recoverable fluid. Methods whisch can determine mobile oil viscosity from relaxation time is existing. However, all the earlier empirical equations fail to determine oil viscosity higher than 1000 MPa•s. It has been shown that the logarithmic mean spin-spin relaxation time demonstrates the best correlation with oil viscosity, which in combination with a calculated time cutoff, yields over 80% accuracy in viscosity estimation. The developed technique determines oil viscosity distribution from high-field NMR-logging data after calibrating correlation factors. Considering oil viscosity anisotropy yields a significant economic benefit including the reduced costs of steam injection and increased cumulative oil production.
- Europe > Russia (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Experimental and Computational Complex for Determination of the Effectiveness of Cyclic Carbon Dioxide Injection for Tight Oil Reservoirs
Popov, Evgeny (Skolkovo Institute of Science and Technology) | Myasnkov, Artem (Skolkovo Institute of Science and Technology) | Cheremisin, Alexey (Skolkovo Institute of Science and Technology) | Miftakov, Ruslan (Skolkovo Institute of Science and Technology) | Stukachev, Vladimir (Skolkovo Institute of Science and Technology) | Mukhametdinova, Aliya (Skolkovo Institute of Science and Technology)
Abstract The problems of numerical and experimental modeling of cyclic carbon dioxide injection in a supercritical state for low-permeability reservoirs were considered in this study. Sensitivity analysis of the cumulative oil production from a number of physical - chemical parameters of the reservoir was performed. The experimental and numerical simulation of cyclic injection of carbon dioxide (huff-n-puff) on core samples of low permeability reservoirs was carried out. Calculations of phase equilibrium pumping supercritical fluid were conducted. Two-dimensional model was proposed for huff-n-puff technology of cyclic injection of CO2, which is a periodic pumping in and pumping out of the solvent into the formation.
- Europe (0.93)
- North America > United States > Montana (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.40)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- Asia > Russia > West Siberian Basin > Bazhenov Formation (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Systematic Study of Viscoelastic Properties During Polymer-Surfactant Flooding in Porous Media
Elhajjaji, R. R. (Wintershall Libya) | Hincapie, R. E. (Clausthal University of Technology) | Tahir, M.. (Clausthal University of Technology) | Rock, A.. (Clausthal University of Technology) | Wegner, J.. (Clausthal University of Technology) | Ganzer, L.. (Clausthal University of Technology)
Abstract Based on the currently discussed ability of HPAM-polymer to increase displacement efficiency due to viscoelastic properties, a comprehensive evaluation of the possible impact on the design of polymer-surfactant mixtures is presented in this investigation. This assessment includes a comprehensive analysis of laboratory experiments. Experimental data was obtained from different sources and furthermore crosschecked, such as: rheological characterization, flooding through microfluidics devices, and core flooding experiments. First, solutions were characterized by the analysis of different rheological techniques. Second, flooding experiments were performed in a microfluidic device which has a hyperbolical contraction-expansion geometry, capable to provide apparent extensional viscosity. Third, single phase core flooding experiment was conducted using Bentheimer core plugs to evaluate the flow behavior of polymer and surfactant in porous media. Finally, flow paths of polymer-surfactant mixtures were described using streamline visualization techniques. The latter was performed injecting the solutions at different flow rates in a Glass-Silicon-Glass (GSG) micromodel generated from a micro CT scan images of a real porous media. Polymer-surfactant mixtures depicted a pseudoplastic behavior with an increasing in polymer's apparent viscosity due to the presence of a surfactant. Polymer extensional viscosity has been slightly improved due to the addition of Polyethylene oxide (PEO) at 0.5wt% and 1.5wt% using a solvent of 4.0 g/l TDS. Increasing in the measured extensional pressure drops suggested that the viscoelastic properties are improved by using polymer-surfactant combination at apparent rates below 720s. Shear rate coefficients resulted in an acceptable match between the rheometer and the core flooding measurements. At a critical value of adjusted shear rates (40-50 S), viscosity of three solutions was almost the same value of 30 mPa.S (Critical apparent viscosity). After this critical value, HPAM with no PEO and with 0.5wt% PEO showed shear thickening behavior, while with 1.5wt% PEO showed shear thinning behavior till shear rate value of 95 S, after this rate, it was dominated by shear thickening behavior. Moreover, different flow regimes were observed through the streamline visualization in GSG micromodels; a zone mainly considered by laminar flow in case of HPAM with 0.5wt% PEO, remarkable vortex was observed in an open pore geometry and crossing streamlines especially in the wall areas in case of HPAM with no PEO. This evaluation leads to understanding the viscoelastic behavior in porous media when polymer and surfactant flooding are applied in combination and provide a proper understanding to complement the few literature resources available about this topic.
- North America > United States (0.28)
- North America > Canada > Alberta (0.28)
- Africa > Middle East (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract A submersible system is provided for viscous fluids recovery making use of a newly designed rotary displacement sliding-vane pump. As opposed to sucker rod and surface-driven PCP pumps also used for viscous oil extraction, the system in question does not include elastomers (requiring selectin to match the fluid being extracted) and forgoes the line of rods, hence there are no limitations for lift it generates and it could be deployed even in horizontal wells. The first sample has been in operation for almost a year with average flow about 10 m/day and reservoir conditions of 70 CP.
Fracturing in Challenging Low-Temperature Reservoirs: Combining Laboratory and Field Approach Produces Promising Results
Parkhonyuk, Sergey (Schlumberger) | Klyubin, Artem (Schlumberger) | Vernigora, Denis (Schlumberger) | Olennikova, Olesya (Schlumberger) | Lisitsyn, Andrey (Schlumberger) | Konchenko, Andrey (Schlumberger) | Sitdikov, Dmitry (Bashneft) | Bildanov, Vladislav (Bashneft) | Gaponov, Mikhail (Bashneft)
Abstract Development of traditional oil reservoirs is becoming increasingly challenging with time as more reservoirs move to brown state. The Bashkiria field complex is typical example of such reservoir: development started in 1932 and as of today, more than 80% of initial oil reserves have been produced. Thus, the only method to make wells produce economically is hydraulic fracturing. Particularities of the region are viscous crude oils, small net height of the reservoir, and low bottomhole static temperatures coupled with depleted reservoir pressure. This imposes additional constraints on the hydraulic fracturing design. The typical practice in region is to employ an aggressive pumping strategy to maximize fracture conductivity and minimize the amount of fluid pumped into the reservoir. Robust fluid is required to avoid premature screenout due to proppant settling. Another essential component of the fracture conductivity is fracturing fluid breakers. The goal in using breakers is to reduce fluid viscosity and break polymer residues in the proppant pack after treatment to facilitate fracture cleanup. Traditionally, breakers based on ammonium persulfate (APS) (both live and encapsulated) are used in Russian oil fields. They have proved successful in the typical conditions of Western Siberia (80 to 120°C). Enzyme-based breakers have limitations on temperature range and fluid viscosity range. In this paper, we focus on development of novel fracturing fluid tailored for Bashkiria oilfield conditions. An enzyme breaker was compared with traditional oxidative breakers. Production analyses were performed using actual treatment data and post-fracturing production data and comparing them with conventional treatment results. Laboratory testing proved that in terms of fracture-pack conductivity, the new enzyme breaker produced approximately twice the conductivity, as did oxidative breakers over the temperature range of the Bashkiria region. Implementation of novel fluid with pressure-independent viscosity behavior led to a reduction of more than twice the screenout rate with zero fluid-related screen outs. Up to 9 times production increase resulted based on a dimensionless productivity index.
- North America > United States (1.00)
- Europe > Russia > Volga Federal District > Bashkortostan (0.68)
- Phanerozoic > Paleozoic > Devonian (1.00)
- Phanerozoic > Paleozoic > Carboniferous (0.70)
- Geology > Geological Subdiscipline (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)