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1
Bedrikovetsky, Pavel, Mohammad Afiq ab Wahab, Gladys Chang, Antonio Luiz Serra de Souza, and Claudio Alves Furtado. "Improved oil recovery by raw water injection using horizontal wells." APPEA Journal 49, no. 1 (2009): 453. http://dx.doi.org/10.1071/aj08029.
Повний текст джерелаАнотація:
Injectivity formation damage with water-flooding using sea/produced water has been widely reported in the North Sea, the Gulf of Mexico and the Campos Basin in Brazil. The damage is due to the capture of solid/liquid particles by the rock with consequent permeability decline; it is also due to the formation of a low permeable external filter cake. Yet, moderate injectivity decline is not too damaging with long horizontal injectors where the initial injectivity is high. In this case, injection of raw or poorly treated water would save money on water treatment, which is not only cumbersome but also an expensive procedure in offshore projects. In this paper we investigate the effects of injected water quality on waterflooding using horizontal wells. It was found that induced injectivity damage results in increased sweep efficiency. The explanation of the phenomenon is as follows: injectivity rate is distributed along a horizontal well non-uniformly; water advances faster from higher rate intervals resulting in early breakthrough; the retained particles plug mostly the high permeability channels and homogenise the injectivity profile along the well. An analytical model for injectivity decline accounting for particle capture and a low permeable external filter cake formation has been implemented into the Eclipse 100 reservoir simulator. It is shown that sweep efficiency in a heterogeneous formation can increase by up to 5% after one pore volume injected, compared to clean water injection.
2
Frash, Luke P., Marte Gutierrez, and Jesse Hampton. "Laboratory-Scale-Model Testing of Well Stimulation by Use of Mechanical-Impulse Hydraulic Fracturing." SPE Journal 20, no. 03 (June 15, 2015): 536–49. http://dx.doi.org/10.2118/173186-pa.
Повний текст джерелаАнотація:
Summary Reservoir stimulation is commonly used to increase well-production rates and enable economic oil and gas recovery from conventional and unconventional reservoirs. One potential stimulation method that has been laboratory tested as a means to increase well injectivity after conventional hydraulic fracturing is mechanical-impulse hydraulic fracturing (MIHF). MIHF is a high-strain-rate stimulation method that uses a mechanical-energy source as an alternative to rapid gas expansion. Field-scale viability of MIHF was evaluated by use of elastic mechanics and thermodynamics. Results from laboratory tests are presented in which associated flow data indicated significant increases to well injectivity after MIHF stimulation. Tests were performed in two granite specimens with dimensions of 300×300×240 mm3 and 300×300×300 mm3, respectively. The first specimen was unconfined at room-temperature conditions, whereas the second was subjected to heating and true-triaxial confinement. Stimulated well injectivity was evaluated with a series of step-constant-pressure and step-constant-flow injection tests.
3
Demirci, Yilmaz Mehmet. "Modules and abelian groups with a bounded domain of injectivity." Journal of Algebra and Its Applications 17, no. 06 (May 23, 2018): 1850108. http://dx.doi.org/10.1142/s0219498818501086.
Повний текст джерелаАнотація:
In this work, impecunious modules are introduced as modules whose injectivity domains are contained in the class of all pure-split modules. This notion gives a generalization of both poor modules and pure-injectively poor modules. Properties involving impecunious modules as well as examples that show the relations between impecunious modules, poor modules and pure-injectively poor modules are given. Rings over which every module is impecunious are right pure-semisimple. A commutative ring over which there is a projective semisimple impecunious module is proved to be semisimple artinian. Moreover, the characterization of impecunious abelian groups is given. It states that an abelian group [Formula: see text] is impecunious if and only if for every prime integer [Formula: see text], [Formula: see text] has a direct summand isomorphic to [Formula: see text] for some positive integer [Formula: see text]. Consequently, an example of an impecunious abelian group which is neither poor nor pure-injectively poor is given so that the generalization defined is proper.
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Katsov, Y. "Axiomatizability of homological classes of semimodules over semirings." Journal of Algebra and Its Applications 19, no. 10 (September 19, 2019): 2050182. http://dx.doi.org/10.1142/s0219498820501820.
Повний текст джерелаАнотація:
In this paper, we characterize semirings over which classes of projective, strongly projective, free, and injective semimodules are axiomatizable. Together with injectivity, we consider the concepts of Baer-injectivity and e-injectivity for semimodules over semirings and illustrate possible relationships between axiomatizabilities of the corresponding injective classes of semimodules, as well as characterize semirings over which the class of e-injective semimodules is axiomatizable.
5
Carpenter, Chris. "Seismic and Seismochemical Stimulation Increases Well Injectivity and Productivity." Journal of Petroleum Technology 71, no. 06 (June 1, 2019): 61–63. http://dx.doi.org/10.2118/0619-0061-jpt.
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Yuan, Bin, and Rouzbeh Ghanbarnezhad Moghanloo. "Analytical model of well injectivity improvement using nanofluid preflush." Fuel 202 (August 2017): 380–94. http://dx.doi.org/10.1016/j.fuel.2017.04.004.
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7
Alkhamis, Mohammed, and Abdulmohsin Imqam. "Sealant injectivity through void space conduits to assess remediation of well cement failure." Journal of Petroleum Exploration and Production Technology 11, no. 6 (June 2021): 2791–804. http://dx.doi.org/10.1007/s13202-021-01218-x.
Повний текст джерелаАнотація:
AbstractThe primary cement of oil and gas wells is prone to fail under downhole conditions. Thus, a remedial operation must be conducted to restore the wellbore integrity and provides zonal isolation. Many types of materials are currently used and/or have the potential to be employed in wellbore integrity applications, including, but not limited to, conventional Portland cement, microfine and ultrafine cement, thermoset materials, and thermoplastic materials. In this study, several types of materials were selected for evaluation: (1) conventional Portland cement, which is the most widely used in remedial operations in the petroleum industry, (2) polymer resin, which is one of the most recent technologies being applied successfully in the field, (3) polymer solutions, and (4) polymer gel, which is a semisolid material that has shown potential in conformance control applications. This work addresses injectivity and the parameters that affect the injectivity of these materials, which to the authors' best knowledge have not been addressed comprehensively in the literature. The results of this study demonstrate the effects of several factors on the injectivity of the sealants: void size, viscosity of the sealant, injection flow rate, and heterogeneity of the void. The results also promote the use of solids-free sealants, such as epoxy resin, in wellbore remedial operations because epoxy resin behaved like Newtonian fluid and can therefore be injected into very small voids with a minimum pressure requirement.
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Li, Zhitao, and Mojdeh Delshad. "Development of an Analytical Injectivity Model for Non-Newtonian Polymer Solutions." SPE Journal 19, no. 03 (January 30, 2014): 381–89. http://dx.doi.org/10.2118/163672-pa.
Повний текст джерелаАнотація:
Summary In applications of polymer flood for enhanced oil recovery (EOR), polymer injectivity is of great concern because project economics is sensitive to injection rates. In-situ non-Newtonian polymer rheology is the most crucial factor that affects polymer injectivity. There are several ongoing polymer-injection field tests in which the field injectivities differ significantly from the simulation forecasts. We have developed an analytical model to more accurately calculate and predict polymer injectivity during the field projects to help with optimum injection strategies. Significant viscosity variations during polymer flood occur in the vicinities of wellbores where velocities are high. As the size of a wellblock increases, velocity smears, and thus polymer injectivity is erroneously calculated. In the University of Texas Chemical Flooding Simulator (UTCHEM), the solution was to use an effective radius to capture the “grid effect,” which is empirical and impractical for large-scale field simulations with several hundred wells. Another approach is to use local grid refinement near wells, but this adds to the computational cost and limits the size of the problem. An attractive alternative to previous approaches is to extend the Peaceman well model (Peaceman 1983) to non-Newtonian polymer solutions. The polymer rheological model and its implementation in UTCHEM were validated by simulating single-phase polymer injectivity in coreflood experiments. On the basis of the Peaceman well model and UTCHEM polymer rheological models covering both shear-thinning and shear-thickening polymers, an analytical polymer-injectivity model was developed. The analytical model was validated by comparing results of different gridblock sizes and radial numerical simulation. We also tested a field case by comparing results of a fine-grid simulation and its upscaled coarse-grid model. A pilot-scale polymer flood was simulated to demonstrate the capability of the proposed analytical model. The model successfully captured polymer injectivity in all these cases with no need to introduce empirical parameters.
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Gong, J., S. Vincent-Bonnieu, R. Z. Kamarul Bahrim, C. A. Che Mamat, R. D. Tewari, J. Groenenboom, R. Farajzadeh, and W. R. Rossen. "Modeling of Liquid Injectivity in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery." SPE Journal 24, no. 03 (February 6, 2019): 1123–38. http://dx.doi.org/10.2118/190435-pa.
Повний текст джерелаАнотація:
Summary Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity. In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator's results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor. The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.
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Tranter, Morgan, Marco De Lucia, and Michael Kühn. "Barite Scaling Potential Modelled for Fractured-Porous Geothermal Reservoirs." Minerals 11, no. 11 (October 28, 2021): 1198. http://dx.doi.org/10.3390/min11111198.
Повний текст джерелаАнотація:
Barite scalings are a common cause of permanent formation damage to deep geothermal reservoirs. Well injectivity can be impaired because the ooling of saline fluids reduces the solubility of barite, and the continuous re-injection of supersaturated fluids forces barite to precipitate in the host rock. Stimulated reservoirs in the Upper Rhine Graben often have multiple relevant flow paths in the porous matrix and fracture zones, sometimes spanning multiple stratigraphical units to achieve the economically necessary injectivity. While the influence of barite scaling on injectivity has been investigated for purely porous media, the role of fractures within reservoirs consisting of both fractured and porous sections is still not well understood. Here, we present hydro-chemical simulations of a dual-layer geothermal reservoir to study the long-term impact of barite scale formation on well injectivity. Our results show that, compared to purely porous reservoirs, fractured porous reservoirs have a significantly reduced scaling risk by up to 50%, depending on the flow rate ratio of fractures. Injectivity loss is doubled, however, if the amount of active fractures is increased by one order of magnitude, while the mean fracture aperture is decreased, provided the fractured aquifer dictates the injection rate. We conclude that fractured, and especially hydraulically stimulated, reservoirs are generally less affected by barite scaling and that large, but few, fractures are favourable. We present a scaling score for fractured-porous reservoirs, which is composed of easily derivable quantities such as the radial equilibrium length and precipitation potential. This score is suggested for use approximating the scaling potential and its impact on injectivity of a fractured-porous reservoir for geothermal exploitation.
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Salazar Castillo, Rodrigo O., Sterre F. Ter Haar, Christopher G. Ponners, Martijn Bos, and William Rossen. "Fractional-Flow Theory for Non-Newtonian Surfactant-Alternating-Gas Foam Processes." Transport in Porous Media 131, no. 2 (October 31, 2019): 399–426. http://dx.doi.org/10.1007/s11242-019-01351-6.
Повний текст джерелаАнотація:
Abstract Foam can improve sweep efficiency in gas-injection-enhanced oil recovery. Surfactant-alternating-gas (SAG) is a favored method of foam injection. Laboratory data indicate that foam can be non-Newtonian at low water fractional flow fw, and therefore during gas injection in a SAG process. We investigate the implications of this finding for mobility control and injectivity, by extending fractional-flow theory to gas injection in a non-Newtonian SAG process in radial flow. We make most of the standard assumptions of fractional-flow theory (incompressible phases, one-dimensional displacement through a homogeneous reservoir, instantaneous attainment of local equilibrium), excluding Newtonian mobilities. For this initial study, we ignore the effect of changing or non-uniform oil saturation on foam. Non-Newtonian behavior at low fw implies that the limiting water saturation for foam stability varies as superficial velocity decreases with radial distance from the well. We discretize the domain radially and perform Buckley–Leverett analysis on each narrow increment in radius. Solution characteristics move outward with fixed fw. We base the foam model parameters and non-Newtonian behavior on laboratory data in the absence of oil. We compare results to mobility and injectivity determined by conventional simulation, where grid resolution is usually limited. For shear-thinning foam, mobility control improves as the foam front propagates from the well, but injectivity declines somewhat with time. This change in mobility ratio is not that at steady state at fixed water fractional flow in the laboratory, however, because the shock front in a non-Newtonian SAG process does not propagate at fixed fractional flow (though individual characteristics do). Moreover, the shock front is not governed by the conventional condition of tangency to the fractional-flow curve, though it continually approaches this condition. Injectivity benefits from the increased mobility of shear-thinning foam near the well. The foam front, which maintains a constant dimensionless velocity for Newtonian foam, decelerates somewhat with time for shear-thinning foam. For shear-thickening foam, mobility control deteriorates as the foam front advances, though injectivity improves somewhat with time. Overall, however, injectivity suffers from reduced foam mobility at high superficial velocity near the well. The foam front accelerates somewhat with time. Conventional simulators cannot adequately represent these effects, or estimate injectivity accurately, in the absence of extraordinarily fine grid resolution near the injection well.
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Bedrikovetsky, P., A. S. L. S. L. Vaz, C. Furtado, and A. L. S. L. S. de Souza. "Formation-Damage Evaluation From Nonlinear Skin Growth During Coreflooding." SPE Reservoir Evaluation & Engineering 14, no. 02 (March 24, 2011): 193–203. http://dx.doi.org/10.2118/112509-pa.
Повний текст джерелаАнотація:
Summary Injectivity decline of oilfield injection wells is a widespread phenomenon during seawater/produced-water injection. The decline may result in significant cost increase of the waterflooding project. Reliable modeling-based prediction of injectivity-index decrease is important for waterflood design as well as for the planning of preventive injected-water treatment. One of the reasons for well injectivity decline is permeability decrease caused by rock plugging by solid/liquid particles suspended in the injected water. The mathematical model for deep-bed filtration contains two empirical functions: the filtration coefficient and the formation-damage coefficient. These empirical coefficients must be determined from laboratory coreflood tests by forcing water with particles to flow through the core samples. A routine laboratory method determines the filtration coefficient from expensive and difficult particle-concentration measurements at the core effluent; then, the formation-damage coefficient is determined from inexpensive and simple pressure-drop measurements. An alternative three-point-pressure method uses pressure data at an intermediate point of the core, supplementing pressure measurements at the core inlet and outlet. The method provides unique and stable values for constant-filtration and formation-damage coefficients. In the current work, we consider a more complex case in which both coefficients are linear functions of retained-particle concentration. In this case, the model is fully determined by four constants. The three-point-pressure method furnishes unique values for the four model parameters. A new semianalytical model for axisymmetric suspension filtration was developed to predict well-injectivity decline from the linear coreflood data with pressure measurements in three core points.
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Lück, Wolfgang, Holger Reich, John Rognes, and Marco Varisco. "Assembly maps for topological cyclic homology of group algebras." Journal für die reine und angewandte Mathematik (Crelles Journal) 2019, no. 755 (October 1, 2019): 247–77. http://dx.doi.org/10.1515/crelle-2017-0023.
Повний текст джерелаАнотація:
AbstractWe use assembly maps to study \mathbf{TC}(\mathbb{A}[G];p), the topological cyclic homology at a prime p of the group algebra of a discrete group G with coefficients in a connective ring spectrum \mathbb{A}. For any finite group, we prove that the assembly map for the family of cyclic subgroups is an isomorphism on homotopy groups. For infinite groups, we establish pro-isomorphism, (split) injectivity, and rational injectivity results, as well as counterexamples to injectivity and surjectivity. In particular, for hyperbolic groups and for virtually finitely generated abelian groups, we show that the assembly map for the family of virtually cyclic subgroups is injective but in general not surjective.
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Alekseenko, O. P., and A. M. Vaisman. "Calculation of Steady-State Injectivity of Input Well after Hydraulic Fracturing." Journal of Mining Science 39, no. 3 (May 2003): 225–32. http://dx.doi.org/10.1023/b:jomi.0000013781.70624.14.
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Chequer, Larissa, Mohammad Bagheri, Abbas Zeinijahromi, and Pavel Bedrikovetsky. "Injectivity formation damage due to fines migration." APPEA Journal 58, no. 2 (2018): 700. http://dx.doi.org/10.1071/aj17191.
Повний текст джерелаАнотація:
Formation damage by fines migration during low-salinity water injection can greatly affect field-scale waterflooding projects. In this paper, we present the basic governing equations for single-phase flow with detachment, migration and straining of natural reservoir fines. We perform laboratory corefloods with low-salinity water injections and monitor the breakthrough particle concentration and pressure drop across the core. The analytical model for linear flow matches the laboratory data with high accuracy. The analytical model for radial flow predicts well behaviour from laboratory-tuned coefficients. The calculations show that fines migration during low-salinity water injection causes significant injectivity decline. For typical values of fines-migration model coefficients, injectivity index declines 2–8 times during 10−3 pore volumes injected and the radius of the damaged zone does not exceed a few metres. We present two field cases on waterflooding and low-salinity water injection. The radial model presents good agreement with well injectivity field data.
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Koroncz, Péter, Zsanett Vizhányó, Márton Pál Farkas, Máté Kuncz, Péter Ács, Gábor Kocsis, Péter Mucsi, Anita Fedorné Szász, Ferenc Fedor, and János Kovács. "Experimental Rock Characterisation of Upper Pannonian Sandstones from Szentes Geothermal Field, Hungary." Energies 15, no. 23 (December 2, 2022): 9136. http://dx.doi.org/10.3390/en15239136.
Повний текст джерелаАнотація:
The Upper Pannonian (UP) sandstone formation has been utilised for thermal water production in Hungary for several decades. Although sustainable utilisation requires the reinjection of cooled geothermal brine into the host rock, only a fraction of the used water is reinjected in the country. UP sandstone formation is reported to exhibit low injectivity, making reinjection challenging, and its petrophysical properties are poorly known, which increases uncertainty in designing operational parameters. The goal of the study is to provide experimental data and to gain a better understanding of formation characteristics that control injectivity and productivity issues in Upper Pannonian sandstone layers. Petrographical characterisation and petrophysical laboratory experiments are conducted on cores retrieved from two wells drilled in the framework of an R&D project at the depth of between 1750 m and 2000 m. The experiments, such as grain density, porosity, permeability, and ultrasonic velocity, as well as thin section, grain size distribution, XRD, and SEM analyses, are used to determine Petrophysical Rock Types (PRT) that share distinct hydraulic (flow zone indicator, FZI) and petrophysical characteristics. These are used to identify well intervals with lower potential for injectivity issues. The results imply that fines migration due to formation erosion is one of the key processes that must be better understood and controlled in order to mitigate injectivity issues at the study area. Future investigation should include numerical and experimental characterisation of formation damage, including water–rock interaction tests, critical flow velocity measurements, and fines migration analysis under reservoir conditions.
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Gong, Jiakun, Sebastien Vincent-Bonnieu, Ridhwan Z. Kamarul Bahrim, Che A. N. B. Che Mamat, Raj D. Tewari, Mohammad I. Mahamad Amir, Jeroen Groenenboom, Rouhollah Farajzadeh, and William R. Rossen. "Injectivity of Multiple Slugs in Surfactant Alternating Gas Foam EOR: A CT Scan Study." SPE Journal 25, no. 02 (February 4, 2020): 895–906. http://dx.doi.org/10.2118/199888-pa.
Повний текст джерелаАнотація:
Summary A surfactant alternating gas (SAG) process is often the injection method for foam, on the basis of its improved injectivity over direct foam injection. In a previous study, we reported coreflood experiments on liquid injectivity after foam flooding and liquid injectivity after injection of a gas slug following steady-state foam. Results showed that a period of gas injection is important for the subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored. In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in an SAG process in a field core. Nitrogen and surfactant solution are either coinjected or injected separately into the sandstone core sample. The experiments are conducted at an elevated temperature of 90°C with a backpressure of 40 bar. Differential pressures are measured to quantify gas and liquid injectivities. Computed tomography (CT) scanning is applied to relate water saturation to mobility. During the injection of a large gas slug following foam, a bank in which foam completely collapses or greatly weakens forms near the inlet and propagates slowly downstream. During the subsequent period of liquid injection, liquid flows through the collapsed-foam bank much more easily than further downstream. Beyond the collapsed-foam region, liquid first imbibes into the whole cross section. In this region, liquid flows mainly through a finger of high liquid saturation. Our CT results suggest a revision of our earlier interpretation; the process of gas dissolution does not merely follow fingering but is evidently directly involved in the fingering process. Our results suggest that, in radial flow, the small region of foam collapse very near the well greatly improves injectivity. The subsequent gas and liquid slugs behave near the wellbore, affecting injectivity, in a way similar to the first slugs. Thus, the behavior and modeling of the first gas slug and first subsequent liquid slug is representative of near-well behavior in an SAG process. The trends observed in our previous work are reproduced in a low-permeability field core.
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Tranter, Morgan, Marco De Lucia, Markus Wolfgramm, and Michael Kühn. "Barite Scale Formation and Injectivity Loss Models for Geothermal Systems." Water 12, no. 11 (November 3, 2020): 3078. http://dx.doi.org/10.3390/w12113078.
Повний текст джерелаАнотація:
Barite scales in geothermal installations are a highly unwanted effect of circulating deep saline fluids. They build up in the reservoir if supersaturated fluids are re-injected, leading to irreversible loss of injectivity. A model is presented for calculating the total expected barite precipitation. To determine the related injectivity decline over time, the spatial precipitation distribution in the subsurface near the injection well is assessed by modelling barite growth kinetics in a radially diverging Darcy flow domain. Flow and reservoir properties as well as fluid chemistry are chosen to represent reservoirs subject to geothermal exploration located in the North German Basin (NGB) and the Upper Rhine Graben (URG) in Germany. Fluids encountered at similar depths are hotter in the URG, while they are more saline in the NGB. The associated scaling amount normalised to flow rate is similar for both regions. The predicted injectivity decline after 10 years, on the other hand, is far greater for the NGB (64%) compared to the URG (24%), due to the temperature- and salinity-dependent precipitation rate. The systems in the NGB are at higher risk. Finally, a lightweight score is developed for approximating the injectivity loss using the Damköhler number, flow rate and total barite scaling potential. This formula can be easily applied to geothermal installations without running complex reactive transport simulations.
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Barzegar, Hasan. "Strongly s-dense injective hull and Banaschewski’s theorems for acts." Mathematica Slovaca 70, no. 2 (April 28, 2020): 251–58. http://dx.doi.org/10.1515/ms-2017-0348.
Повний текст джерелаАнотація:
Abstract For a class 𝓜 of monomorphisms of a category, mathematicians usually use different types of essentiality. Essentiality is an important notion closely related to injectivity. Banaschewski defines and gives sufficient conditions on a category 𝓐 and a subclass 𝓜 of its monomorphisms under which 𝓜-injectivity well-behaves with respect to the notions such as 𝓜-absolute retract and 𝓜-essentialness. In this paper, 𝓐 is taken to be the category of acts over a semigroup S and 𝓜sd to be the class of strongly s-dense monomorphisms. We study essentiality with respect to strongly s-dense monomorphisms of acts. Depending on a class 𝓜 of morphisms of a category 𝓐, In some literatures, three different types of essentialness are considered. Each has its own benefits in regards with the behavior of 𝓜-injectivity. We will show that these three different definitions of essentiality with respect to the class of strongly s-dense monomorphisms are equivalent. Also, the existence and the explicit description of a strongly s-dense injective hull for any given act which is equivalent to the maximal such essential extension and minimal strongly s-dense injective extension with respect to strongly s-dense monomorphism is investigated. At last we conclude that strongly s-dense injectivity well behaves in the category Act-S.
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Dung, Nguyen V. "Generalized injectivity and chain conditions." Glasgow Mathematical Journal 34, no. 3 (September 1992): 319–26. http://dx.doi.org/10.1017/s0017089500008880.
Повний текст джерелаАнотація:
Relationships between injectivity or generalized injectivity and chain conditions on a module category have been studied by several authors. A well-known theorem of Osofsky [14, 15] asserts that a ring all of whose cyclic right modules are injective is semisimple Artinian. Osofsky's proofs in [14, 15] essentially used homological properties of injective modules, and, later, her arguments were applied by other authors in their studies of rings for which cyclic right modules are quasi-injective, continuous or quasi-continuous (see e. g. [1, 10, 12]). Following [5] (cf. [4]), a module M is called a CS-module if every submodule of M is essential in a direct summand of M. In the recent paper [17], B. L. Osofsky and P. F. Smith have proved a very general theorem on cyclic completely CS-modules from which many known results in this area follow rather easily. In another direction, it was proved in [8] that a finitely generated quasi-injective module with ACC (respectively DCC) on essential submodules is Noetherian (respectively Artinian). This result was also extended to CS-modules in [3, 16], and weak CS-modules in [19].
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Brehme, Maren, Simona Regenspurg, Peter Leary, Fatih Bulut, Harald Milsch, Sigitas Petrauskas, Robertas Valickas, and Guido Blöcher. "Injection-Triggered Occlusion of Flow Pathways in Geothermal Operations." Geofluids 2018 (July 5, 2018): 1–14. http://dx.doi.org/10.1155/2018/4694829.
Повний текст джерелаАнотація:
Reasons for injectivity decline were investigated in a low-enthalpy geothermal aquifer in Klaipeda (Lithuania). It is one of the study sites within the DESTRESS project, which demonstrates different stimulation techniques in geothermal reservoirs. Due to low injectivity, production rates from the Lithuanian field are currently reduced, which lead to negative commercial implications for the site. Productivity from the same wells is measured to be 40 times higher. Injectivity decline in aquifers is often related to clogging processes in spatially correlated highly permeable structures, which control the main flow volume. We subdivided clogging processes into (1) physical, (2) chemical, and (3) biological processes and studied them by analyzing fluid and solid samples as well as operational data. The methods we used are fluid and solid analyses in situ, in the laboratory and in experimental setups, statistical interpretation, and numerical modeling. Our results show that the spatially correlating nature of permeable structures is responsible for exponentially decreasing injectivity because few highly permeable zones clog rapidly by intruded particles. In particular, field operations cause changes of the physical, chemical, and biological processes in the aquifer. Mineral precipitation and corrosion are the main chemical processes observed at our site. Microbial activity causes biofilm while fines migration is caused by changes in physical boundary conditions. Moreover, these processes can affect each other and generate further reactions, for example, microbial activity triggers corrosion in surface pipelines.
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Buret, S., L. Nabzar, and A. Jada. "Water Quality and Well Injectivity: Do Residual Oil-in-Water Emulsions Matter?" SPE Journal 15, no. 02 (March 3, 2010): 557–68. http://dx.doi.org/10.2118/122060-pa.
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Summary The present work is a part of a thorough and systematic laboratory study of oil-in-water emulsion flow in porous media that we have undertaken recently to investigate the mechanisms of oil-droplet retention and its consecutive effect on permeability. One of our main objectives was to see how the in-depth propagation of produced- water (PW) residual dilute emulsion could impair the permeability during PW reinjection (PWRI). During this casework, we used granular packs of sharp-edged silicon carbide grains and stable and dilute dodecane-in-water emulsions. The flow experiments were performed under well-controlled conditions, and we studied the effect of most of the relevant parameters, including flow rate, salinity, droplet size, and permeability of the porous medium. A careful monitoring of the salinity and the jamming ratio (JR) allowed us to consider and work separately on the two main mechanisms of droplet capture (i.e., surface capture and straining capture). In a previous paper (Buret et al. 2008), we reported on the effect of salinity and flow rate on emulsion flow through porous media where the pore-size/droplet-size ratio (JR) was very high, ensuring that only droplet capture on pore surface is operative. This paper reports on the effect of salinity and JR on both mechanisms, with the main focus being on the induced permeability impairment. We demonstrated that surface capture could induce significant in-depth permeability losses even at a high JR. The maximum reached permeability loss is very sensitive to salinity and flow rate (shear-thinning effect). This maximum is always lower than a limiting value dictated by the surface-coverage jamming limit of random sequential adsorption (RSA) theory. This limiting value increases while decreasing the JR, according to a simple formula extracted from Poiseuille's law with a mean hydrodynamic thickness of the deposited layer close to the droplet diameter (monolayer deposition). Regarding the straining capture, we determined a critical JR of 7 for this mechanism to occur. Preliminary results using only two JR values and one flow rate are presented. Compared to surface capture, the results show that straining capture induces more severe plugging with a lower rate of propagation. The lower the JR is, the more severe the plugging is and the lower the propagation rate is. However, more investigations are still required, notably using various JRs and flow rates to characterize this important mechanism better.
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Alzaabi, Mohamed Adel, Juan Manuel Leon, Arne Skauge, and Shehadeh Masalmeh. "Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir." Polymers 13, no. 11 (May 27, 2021): 1765. http://dx.doi.org/10.3390/polym13111765.
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Polymer flooding has gained much interest within the oil industry in the past few decades as one of the most successful chemical enhanced oil recovery (CEOR) methods. The injectivity of polymer solutions in porous media is a key factor in polymer flooding projects. The main challenge that faces prediction of polymer injectivity in field applications is the inherent non-Newtonian behavior of polymer solutions. Polymer in situ rheology in porous media may exhibit complex behavior that encompasses shear thickening at high flow rates in addition to the typical shear thinning at low rates. This shear-dependent behavior is usually measured in lab core flood experiments. However, data from field applications are usually limited to the well bottom-hole pressure (BHP) as the sole source of information. In this paper, we analyze BHP data from field polymer injectivity test conducted in a Middle Eastern heterogeneous carbonate reservoir characterized by high-temperature and high-salinity (HTHS) conditions. The analysis involved incorporating available data to build a single-well model to simulate the injectivity test. Several generic sensitivities were tested to investigate the impact of stepwise variation in injection flow rate and polymer concentration. Polymer injection was reflected in a non-linear increase in pressure with injection, and longer transient behavior toward steady state. The results differ from water injection which have linear pressure response to rate variation, and quick stabilization of pressure after rate change. The best match of the polymer injection was obtained with complex rheology, that means the combined shear thickening at high rate near the well and moving through apparent Newtonian and shear thinning at low rate.
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Clark, J., and P. F. Smith. "On semi-artinian modules and injectivity conditions." Proceedings of the Edinburgh Mathematical Society 39, no. 2 (June 1996): 263–70. http://dx.doi.org/10.1017/s0013091500022999.
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It is well known that a module M has finite length if and only if it is semi-artinian and Noetherian or, equivalently, semi-noetherian and artinian. Our main result shows that finite length is often achieved by just assuming that M is semi-artinian, semi-noetherian and has finitely generated socle.
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Zanganeh, M. Namdar, and W. R. R. Rossen. "Optimization of Foam Enhanced Oil Recovery: Balancing Sweep and Injectivity." SPE Reservoir Evaluation & Engineering 16, no. 01 (January 30, 2013): 51–59. http://dx.doi.org/10.2118/163109-pa.
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Summary Foam is a means of improving sweep efficiency that reduces the gas mobility by capturing gas in foam bubbles and hindering its movement. Foam enhanced-oil-recovery (EOR) techniques are relatively expensive; hence, it is important to optimize their performance. We present a case study on the conflict between mobility control and injectivity in optimizing oil recovery in a foam EOR process in a simple 3D reservoir with constrained injection and production pressures. Specifically, we examine a surfactant-alternating-gas (SAG) process in which the surfactant-slug size is optimized. The maximum oil recovery is obtained with a surfactant slug just sufficient to advance the foam front just short of the production well. In other words, the reservoir is partially unswept by foam at the optimum surfactant-slug size. If a larger surfactant slug is used and the foam front breaks through to the production well, productivity index (PI) is seriously reduced and oil recovery is less than optimal: The benefit of sweeping the far corners of the pattern does not compensate for the harm to PI. A similar effect occurs near the injection well: Small surfactant slugs harm injectivity with little or no benefit to sweep. Larger slugs give better sweep with only a modest decrease in injectivity until the foam front approaches the production well. In some cases, SAG is inferior to gasflood (Namdar Zanganeh 2011).
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Qiao, C., L. Li, R. T. Johns, and J. Xu. "Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO2 Flooding in Carbonate Reservoirs." SPE Journal 21, no. 03 (June 15, 2016): 0809–26. http://dx.doi.org/10.2118/170930-pa.
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Summary Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO2 flooding. In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicit-composition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions. The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO2 and water injected. For continuous CO2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO2-saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.
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Du, Xingyi, Danny M. Kaufman, Qingnan Zhou, Shahar Z. Kovalsky, Yajie Yan, Noam Aigerman, and Tao Ju. "Optimizing global injectivity for constrained parameterization." ACM Transactions on Graphics 40, no. 6 (December 2021): 1–18. http://dx.doi.org/10.1145/3478513.3480556.
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Injective parameterizations of triangulated meshes are critical across applications but remain challenging to compute. Existing algorithms to find injectivity either require initialization from an injective starting state, which is currently only possible without positional constraints, or else can only prevent triangle inversion, which is insufficient to ensure injectivity. Here we present, to our knowledge, the first algorithm for recovering a globally injective parameterization from an arbitrary non-injective initial mesh subject to stationary constraints. These initial meshes can be inverted, wound about interior vertices and/or overlapping. Our algorithm in turn enables globally injective mapping for meshes with arbitrary positional constraints. Our key contribution is a new energy, called smooth excess area (SEA), that measures non-injectivity in a map. This energy is well-defined across both injective and non-injective maps and is smooth almost everywhere, making it readily minimizable using standard gradient-based solvers starting from a non-injective initial state. Importantly, we show that maps minimizing SEA are guaranteed to be locally injective and almost globally injective, in the sense that the overlapping area can be made arbitrarily small. Analyzing SEA's behavior over a new benchmark set designed to test injective mapping, we find that optimizing SEA successfully recovers globally injective maps for 85% of the benchmark and obtains locally injective maps for 90%. In contrast, state-of-the-art methods for removing triangle inversion obtain locally injective maps for less than 6% of the benchmark, and achieve global injectivity (largely by chance as prior methods are not designed to recover it) on less than 4%.
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Aitkulov, Almas, Reid Edwards, Eric Delamaide, and Kishore K. Mohanty. "An analytical tool to forecast horizontal well injectivity in viscous oil polymer floods." Journal of Petroleum Science and Engineering 204 (September 2021): 108748. http://dx.doi.org/10.1016/j.petrol.2021.108748.
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Ahmed, Quosay A., Hassan B. Nimir, Mohammed A. Ayoub, and Mysara Eissa Mohyaldinn. "Application of variance-based sensitivity analysis in modeling oil well productivity and injectivity." Journal of Petroleum Exploration and Production Technology 10, no. 2 (September 4, 2019): 729–38. http://dx.doi.org/10.1007/s13202-019-00771-w.
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López, Daniel, Richard D. Zabala, Cristian Matute, Sergio H. Lopera, Farid B. Cortés, and Camilo A. Franco. "Well injectivity loss during chemical gas stimulation process in gas-condensate tight reservoirs." Fuel 283 (January 2021): 118931. http://dx.doi.org/10.1016/j.fuel.2020.118931.
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Zhao, Xuanyi, Jinggai Li, Ying Wang, and Chungang Zhu. "Improved algorithms for determining the injectivity of 2D and 3D rational Bézier curves." Electronic Research Archive 30, no. 5 (2022): 1799–812. http://dx.doi.org/10.3934/era.2022091.
Повний текст джерелаАнотація:
<abstract><p>Bézier curves and surfaces are important to computer-aided design applications. This paper presents algorithms for checking the injectivity of 2D and 3D Bézier curves. An injective Bézier curve or surface is one that has no self-intersections. The proposed algorithms use recently proposed sufficient and necessary conditions under which Bézier curves are guaranteed to be non-self-intersecting. As well as a rigorous derivation of the proposed algorithms, we present a series of examples and derive the complexity and computation times of the proposed algorithms. We find that the complexity our algorithms is approximately $ O(m) $, representing an improvement over previous injectivity-checking algorithms.</p></abstract>
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Indrupskiy, I. M., and A. D. Bukatkina. "Semi-Analytical Method for Accurate Calculation of Well Injectivity During Hot Water Injection for Heavy Oil Recovery." Journal of Physics: Conference Series 2090, no. 1 (November 1, 2021): 012141. http://dx.doi.org/10.1088/1742-6596/2090/1/012141.
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Abstract Representation of wells in numerical simulation of petroleum reservoirs is a challenging task due to large difference in typical scales of grid blocks (tens to hundreds meters) and wells (~0.1 m), with high pressure and saturation gradients around wells. Although a variety of grid refinement techniques can be used for local simulations, they have limited application in field-scale problems due to huge model dimensions. Thus, auxiliary quasi-stationary local solutions (so-called inflow performance relations) are used to relate well flow rate with well and grid block pressures. These auxiliary solutions are strictly derived for linear cases and generalized to non-linear problems by using grid-block averaged values of fluid and reservoir properties. In the case of hot water injection for heavy oil recovery, this results in significant errors in well injectivity calculations due to large temperature and saturation gradients dynamically influencing viscosity and relative permeability distributions around the well. In this paper we propose a method which combines a semi-analytical solution of the hyperbolic Entov-Zazovsky problem for non-isothermal oil displacement with integration for pressure distribution taking into account nonlinear dependencies of fluid viscosities and relative permeabilities on temperature and saturations. Both constant injection rate and constant well pressure cases are considered. Example calculations demonstrate that the method helps to avoid underestimation of well injectivity in non-isothermal problems caused by grid-block averaging of fluid and reservoir properties in conventional inflow performance relations.
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Khabibullin, M. Ya. "INCREASING THE EFFICIENCY OF BOTTOMHOLE INJECTION WELL ZONE." Oil and Gas Studies, no. 5 (October 30, 2018): 103–7. http://dx.doi.org/10.31660/0445-0108-2018-5-103-107.
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It is necessary to know the mechanism of contamination of bottomhole injection well zone in order to choose the right exposure method and predict the interprophylactic period of operation of this well. The article provides the essence of the proposed method. The well is being closed, and the wellhead pressure is restoring. An angular coefficient is being found by wellhead pressure build up curve, and then the graphical dependences will be plotted in the ΔP-lgt coordinates. Periodically determining the degree of contamination of bottomhole injection wells zones, we can restore their purity by timely flushing and drainage. If these works don’t contribute to cleaning, hydroimpulse treatment should be carried out. The suggested technique for determining the contamination of the bottomhole injection wells zone will allow to determine the true reason for the decrease in injectivity and to correctly outline measures to increase or stabilize the absorptive capacity of the injection well.
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Lotfollahi, Mohammad, Rouhi Farajzadeh, Mojdeh Delshad, Al-Khalil Al-Abri, Bart M. Wassing, Rifaat Al-Mjeni, Kamran Awan, and Pavel Bedrikovetsky. "Mechanistic Simulation of Polymer Injectivity in Field Tests." SPE Journal 21, no. 04 (August 15, 2016): 1178–91. http://dx.doi.org/10.2118/174665-pa.
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Summary Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates. The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times. One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.
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Mashnich, V. V., A. A. Berdnikova, A. A. Pavlova, M. V. Majlin, A. A. Grinko, and E. V. Frantsina. "Research of Low-Temperature Properties of Diesel Fuel and Their Interrelation with Its Hydrocarbon Composition and Physico-Chemical Properties." Oil and Gas Technologies 142, no. 5 (2022): 22–27. http://dx.doi.org/10.32935/1815-2600-2022-142-5-22-27.
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In the article, the main physical and chemical properties of various samples of diesel fuel are investigated and their influence on low-temperature characteristics is evaluated. The regularities of changes in the low-temperature properties of the fuel depending on the hydrocarbon composition, as well as its effect on the injectivity of the fuelto depressant additives, have been studied. Based on the results obtained, it was concluded that the low-temperature properties of diesel fractions are best correlated with such physicochemical properties as: the latitude of the fractional composition, the boiling point of 90% and the molecular weight of the fraction. Of the presented hydrocarbonsin the composition of diesel fractions, the content of paraffins, their normality factor and the ratio of naphthenes to n-paraffins have the greatest influence. At the same time, the determining factors affecting the injectivityof diesel fractions to a pour point depressant are: the content of paraffins and aromatics, the molecular weight distribution of n-paraffins, and the width of the fractional composition.
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Hajiabadi, Seyed Hasan, Pavel Bedrikovetsky, Sara Borazjani, and Hassan Mahani. "Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects." Energy & Fuels 35, no. 11 (May 17, 2021): 9240–67. http://dx.doi.org/10.1021/acs.energyfuels.1c00931.
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Durucan, Sevket, and Ji-Quan Shi. "Improving the CO2 well injectivity and enhanced coalbed methane production performance in coal seams." International Journal of Coal Geology 77, no. 1-2 (January 2009): 214–21. http://dx.doi.org/10.1016/j.coal.2008.09.012.
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Detienne, J.-L., Max Creusot, Nicolas Kessler, Bernard Sahuquet, and J.-L. Bergerot. "Thermally Induced Fractures: A Field-Proven Analytical Model." SPE Reservoir Evaluation & Engineering 1, no. 01 (February 1, 1998): 30–35. http://dx.doi.org/10.2118/30777-pa.
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Summary Thermally induced fracturing (TIF) during water injection is a well-established phenomenon. TIF modeling implies solving equations simultaneously that conventional petroleum engineering applications deal with separately. Combining these equations leads to very complex computer programs. This has led to the need for a simple model, which we present in this paper. Coupling analytical expressions representing each of these phenomena, rather than the basic physical equations, has led to a computer program that can be run on a modern desk-top computer. This program has successfully matched the daily wellhead pressure and injection rate during a period of 3 to 5 years for injection wells in complex sandstone/dolomite reservoirs. The model can be used for injection-well monitoring as well as in a predictive mode when planning new water-injection projects. The algorithm is sufficiently simple to be implemented in a conventional reservoir simulator. Introduction The concept of a constant productivity index, extrapolated below bubble point by use of Vogel's curve, is one of the fundamental tools of petroleum engineering. One of its most interesting features is that it depends on reservoir and reservoir properties alone. It is independent of downstream wellbore equipment and surface facilities. One would like to be able to use a similar concept for water injection wells, but, unfortunately, calculating an injectivity index, turns out to be much more complex. Water available for injection is often much colder than the reservoir, and numerous temperature-induced phenomena often having opposite effects occur within the first few days or weeks of injection. From the beginning of injection, the bottomhole flowing temperature decreases and finally reaches a stabilized value depending on surface and reservoir temperature, injection rate, depth, and well completion. During that time, matrix flows will have a reducing effect on injectivity. This is because, in such conditions, the bottom-hole viscosity can often increase two- to four-fold. Also, when water displaces oil, there is a relative-permeability effect tied to the growth of the zone from which oil has been displaced. At the same time, mechanical effects will tend to decrease injectivity inversely. The reservoir stress near the well is reduced when the reservoir is cooled, and fracturing will occur if the reservoir stress falls below bottomhole flowing pressure. This phenomena is called TIF.1–6 It leads to a continuous increase in injectivity when fracture develops. In fact, the final reduced stress is the result of a thermal reducing effect (thermoelasticity) and a fluid-pressure increasing effect (poroelasticity) at the injector. In general, however, the latter is much smaller. As we have shown, the injectivity index cannot be calculated without taking into account the wellbore pressure and temperature performance. Injectivity therefore depends on the situation both upstream (wellbore equipment and surface facilities) and downstream (reservoir properties). Modeling water injectivity therefore leads to very large computer programs in which the complexities of both reservoir models and fracturing simulators are intermingled. The pioneering work of Hagoort7 and Perkins and Gonzalez8 on thermo-poroelasticity were followed by more refined models, such as that published by Dikken and Niko.9 More recently, Settari10,11 and Clifford12 presented three-dimensional (3D) fracturing calculations. This paper presents a model that uses simple analytical formulas representing all these intermingled physical processes that influence the injectivity index. The model has been programmed on a PC and used to match the performance of wells injecting into a complex sandstone/dolomite reservoir in the Gulf of Guinea. Well behavior is modeled as a sequence of timesteps. The basic assumption is that steady-state equilibrium is reached at the end of each timestep. This is a good approximation for long-term well behavior. We do not aim to simulate short-term phenomena such as those encountered during well tests; in our model, reservoir pressure transients are ignored, as are the mechanics of fracture propagation. Our model starts at the wellhead, with a given injection rate and wellhead temperature. The model calculates a wellhead pressure, which can be compared to measurements. The least known parameters are adjusted within their plausible range of values until a satisfactory match is obtained. The algorithm also has been programmed so that when wellhead pressure and temperature are given as data, the model calculates the injection rate. This calculation mode is of particular interest when planning waterfloods. Part 1: The Model Wellbore Temperature Profile. The first task is to calculate bottomhole flowing temperature, ?wf, from surface temperature, injection rate, and wellbore equipment. A linear geothermal gradient is assumed. Bottomhole flowing temperature is calculated from wellhead temperature by dividing the tubing into 25 segments. We use the transient heat-exchange solution13 between each segment and the surrounding earth to calculate the quantity of heat that reaches the water in the tubing. This solution assumes that the well rate is constant. To cope with rate-varying behavior, an effective injection time has been defined with the cumulative injection Wi and the current injection rate i : As long as injection rate does not decrease too abruptly, this simple algorithm gives satisfactory results. The reason that such a simple algorithm works is that most of the heat exchange between an injection well and the surrounding earth takes place at depth, where the well geometry is simplest: a tubing and one casing. On the contrary, such a simple calculation is impossible on a production well because, in this case, the biggest temperature contrast and therefore most of the heat exchange are close to the surface where well geometry and its surroundings are most variable. This algorithm does not give realistic results when the injection rate is reduced abruptly (for instance, when the well is shut in). A smoothing function has therefore been introduced to limit the change in ?wf during any one timestep. Calculation Assuming Radial Injection. We use the term radial injection when flow is radially outwards from the well; the alternative, when the reservoir is fractured by the water injection process, is called fractured injection.
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Habibullin, M. Ya, R. I. Suleymanov, M. L. Galimullin, and D. I. Sidorkin. "DOWNHOLE UNIVERSAL DEVICE FOR PULSEDSTATIONARY PUMPING OF FLUIDS INTO THE WELL." Oil and Gas Studies, no. 2 (May 1, 2018): 60–65. http://dx.doi.org/10.31660/0445-0108-2018-2-60-65.
Повний текст джерелаАнотація:
The article deals with a downhole universal device for pulsed stationary pumping of fluids into the well. The versatility of this device is concluded in the ability to create a high-frequency vibra-tions in case of an injection well injectivity decline due to use of an additional element. On the basis of mathematical expressions and taking into account the simulation the authors determine the main parameters of the device. In developed laboratory bench tests experimental design was carried out taking into account the modeling of downhole conditions. When comparing the theoretical and laboratory results, the error was no more than ± 11,7 %. According to the results of bench tests the optimal size of the device for effective action at a pulsed stationary pumping of fluids into the well was determined.
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Azizi, Ehsan, and Yildiray Cinar. "Approximate Analytical Solutions for CO2 Injectivity Into Saline Formations." SPE Reservoir Evaluation & Engineering 16, no. 02 (May 8, 2013): 123–33. http://dx.doi.org/10.2118/165575-pa.
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Summary This paper presents new analytical models to estimate the bottomhole pressure (BHP) of a vertical carbon dioxide (CO2) injection well in a radial, homogeneous, horizontal saline formation. The new models include the effects of multiphase flow, CO2 dissolution in formation brine, and near-well drying out on the BHP. CO2 is injected into the formation at a constant rate. The analytical solutions are presented for three types of formation outer boundary conditions: closed boundary, constant-pressure boundary, and infinite-acting formation. The sensitivity of BHP computations to gas relative permeability, retardation factors, and CO2 compressibility is examined. The predictive capability of the analytical models is tested by use of numerical reservoir simulations. The results show a good agreement between the analytical and numerical computations for all three boundary conditions. Variations in gas compressibility, retardation factors, and gas relative permeability in the drying-out zone are found to have moderate effects on BHP computations. It is demonstrated for several hypothetical but realistic cases that the new models can estimate CO2 injectivity reliably.
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Kostadinov, Marko. "Injectivity of linear combinations in $\mathcal{B}(\mathcal{H})$." Electronic Journal of Linear Algebra 37 (May 17, 2021): 359–69. http://dx.doi.org/10.13001/ela.2021.5049.
Повний текст джерелаАнотація:
The aim of this paper is to provide sufficient and necessary conditions under which the linear combination $\alpha A + \beta B$, for given operators $A,B \in {\cal B}({\cal H})$ and $\alpha, \beta \in \mathbb{C}\setminus \lbrace 0 \rbrace$, is injective. Using these results, necessary and sufficient conditions for left (right) invertibility are given. Some special cases will be studied as well.
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Nguyen, Q. P. P., Peter K. Currie, and P. S. R. S. R. Bouzanga. "The Effect of Gas on the Injectivity of Particles in Sandstone." SPE Journal 16, no. 01 (November 11, 2010): 95–103. http://dx.doi.org/10.2118/121637-pa.
Повний текст джерелаАнотація:
Summary Many operations involve the injection of fluids into the formation around a well. In many cases, the fluids contain colloidal particles, either initially present or introduced during the operation through dirt or naturally occurring particles. Therefore, all injection schemes potentially suffer from injectivity decline. This injectivity decline is caused by clogging of the formation by particles, forming an external filter cake on the surface of the formation and blocking the pores inside the formation. This paper reports on the effects of gas on the injectivity of particles in sandstone. Experiments were performed in which water containing micron-sized particles (hematite) was injected into sandstone cores with or without small gas bubbles (nitrogen) present in the water. The position and amount of particle deposition could be determined both visually and by chemical analysis. It was found that the presence of gas reduces the external filter cake formed on the inlet surface of the core. Also, with gas, the particles penetrate deeper inside the core and more particles pass through the core and are detected in the effluent stream. The same effects are enhanced when the mixture of gas bubbles and water is replaced by foam. This suggests that the presence of gas/water interfaces has a major influence on the retention of particles in the sandstone. Possible mechanisms are discussed. The pressure drop across the core when gas or foam is present is initially higher than in an identical test without gas because of relative permeability effects or foam-flow resistance. However, because fewer particles are retained, ultimately the pressure drop is significantly less when gas is present. This effect may be significant in injection operations involving foam and offers ways to mitigate injectivity loss.
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Suri, Ajay, Mukul M. Sharma, and Ekwere J. Peters. "Estimates of Fracture Lengths in an Injection Well by History Matching Bottomhole Pressures and Injection Profile." SPE Reservoir Evaluation & Engineering 14, no. 04 (August 12, 2011): 385–97. http://dx.doi.org/10.2118/132524-pa.
Повний текст джерелаАнотація:
Summary An injection-well model is presented and used to history match a field injector's bottomhole pressures (BHPs) and injection profile (injection rate into each layer), taking into account plugging of formation caused by suspended solids in the injection water, poro- and thermoelastic stresses, injector shut-ins/restarts, and changes in both the injection rates and the average reservoir pressure. Fracture lengths and injection profile are estimated for a field injector as a case study. The injection-well fracture model is very similar to the Perkins and Gonzalez (1985) model except that it has integrated a more comprehensive and experimentally tested internal filtration model (Rajagopalan and Tien 1976; Pang and Sharma 1997; Gadde and Sharma 2001; Suri 2000; Wennberg and Sharma 1997) for calculating permeability reduction. It has also added a pressure-transient model that makes the earlier reservoir flow models more accurate. The solids deposition is modeled using a filtration model (Rajagopalan and Tien 1976). The fluid flow in the reservoir is modeled using three approximated composite zones with uniform saturations and average mobilities, and the pressure for the fractured wellbore is calculated with the help of Gringarten's (1974) infinite-conductivity solution. The induced-fracture lengths are calculated on the basis of the Perkins and Gonzalez fracture-propagation model (1985) that accounts for the thermal and poroelastic stresses. The model is developed into a semianalytical numerical simulator that can predict and history match an injector's daily BHP, fracture lengths, and injection profile. Future estimates of pump pressures, BHP, injectivity, skin, front locations, fracture lengths, and injection profile can be obtained from this model. Both short-term pressure transients and long-term pseudosteady pressures observed over several years of injection can be history matched to capture effects that are important at both short and long time scales. Finally a field-case injection-well study is presented in which BHP and injectivity are history matched over a period of 3 years. We show that the model can be used to estimate the minimum horizontal stresses in the layers if they are not known. Estimates of fracture lengths, fraction of flow, permeability reduction, and skin and front locations are also obtained. There is significant uncertainty in the results because of uncertainty in the model inputs and in the completeness of the physics of the model of fracturing itself. Both the solids deposition and the opening/closing of the injection-induced fractures had to be accounted for to obtain the history match. The layer/sand stresses and the water quality are the most important parameters that determine the well's injectivity, fracture growth, and injection profile. Microseismic surveys and PLTs are needed to confirm fracture lengths in injection wells.
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Rogers, John D., and Reid B. Grigg. "A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process." SPE Reservoir Evaluation & Engineering 4, no. 05 (October 1, 2001): 375–86. http://dx.doi.org/10.2118/73830-pa.
Повний текст джерелаАнотація:
Summary This paper summarizes the hypotheses and theories relating to the causes and expectations of injectivity behavior in various CO2 and gasflooded reservoirs. The intent of the paper is to:Provide a concise compendium to the current understanding of the water-alternating-gas (WAG) mechanism and predictability.Provide a comprehensive single-source review of the causes and conditions of injectivity abnormalities in CO2/gasflood EOR projects.Aid in formulating the direction of research.Help operators develop operational and design strategies for current and future projects, as well as to input parameters for simulating current and future projects. Background Moritis1 identified 94 gas improved oil recovery (IOR) projects in the U.S. Of these, 74 are still active and 64 are CO2 miscible projects. New CO2 projects start each year. Five new U.S. miscible CO2 projects were being planned as of January 2000. Brock and Bryan2 presented a summary of CO2 IOR projects and reviewed the performance of 30 full-scale field projects and field pilots up to 1987. In 1992, there were 45 active CO2 projects in the U.S.3 Because of the low oil prices following the 1985-86 price collapse, the initial industry outlook was pessimistic; however, by 1992, most projects had been shown to be technically and economically successful. In a number of projects, the production performance has been better than anticipated.3 At the beginning of 2000, and based on 1999 production figures, the U.S. production from gas-injected IOR was estimated at 328,759 B/D, or approximately 5% of the total oil production in the U.S. Oil production from CO2 activity alone contributed 189,493 B/D, which is an increase of 5.8% over 1998 production attributable to CO2 production and represents 3% of the 1999 U.S. oil production.1 This increase occurred despite the 1998-99 price collapse, which was deeper than the mid-1980s collapse. The Permian Basin of west Texas and southeastern New Mexico remains a very active area for CO2 projects. However, CO2 IOR field or pilot projects also exist in seven other states: California, Colorado, Kansas, Michigan, Mississippi, Oklahoma, and Utah. Analysis of individual projects4 and reported problems are not presented here. A review of 23 projects regarding injectivity is included in a U.S. Dept. of Energy annual report.5 A number of reviews have appeared in the literature.1-3,4,6 During the spring of even years, the Oil & Gas Journal usually publishes a survey of active IOR projects. Industry's Initial Concerns. There are two basic IOR techniques in gasflooding a reservoir-continuous gas injection and the WAG injection scheme. Industry initially had a number of concerns about CO2 injection, especially during the WAG process, in terms of controlling the higher-mobility gas: water blocking, corrosion, production concerns, oil recovery, and loss of injectivity. Careful planning and design along with good management practices have allayed most concerns, except for loss of injectivity. Lower injection rates of CO2 slugs and water slugs have been a concern because CO2 field tests were conducted in the early 1970s.7 Currently, the problem is still a concern in the management of a WAG process.4 This concern is the primary focus of this paper. Injectivity Losses. There are two separate but related questions regarding this perplexing issue.What causes the unexpectedly low injectivity during gas injection?What is the reason for the apparent reduction in water injectivity during brine injection after gas injection? Injectivity is a key variable for determining the viability of a CO2 project. Potential loss of injectivity and corresponding loss of reservoir pressure (and possibly loss of miscibility resulting in lower oil recovery) have potentially major impacts on the economics of a gas-injection process. Many of the projects evaluated by Hadlow3 showed higher CO2 (gas) injectivity than that obtained in prewaterflood water injection. However, substantial loss in water injectivity after CO2 or gas injection also has been seen. On the average, an approximately 20% loss of water injectivity can be expected in the WAG process3; attempts to mitigate this include decreasing the WAG ratio to decrease the mobility control, increasing the injection pressure, and adding additional injection wells. Optimization of operations can improve the economics of existing CO28 and other enhanced oil recovery (EOR) projects significantly. Three major management parameters that effect the economics of a CO2 or gasflood are:8The CO2 and water half-cycle slug sizes.The gas/water ratio profile.The ultimate injected CO2 slug size. Overview of WAG Injection Process WAG Process Description. The WAG scheme is a combination of two traditional techniques of improved hydrocarbon recovery: waterflooding and gas injection.9 The first field application of WAG is attributed to the North Pembina field in Alberta, Canada, by Mobil in 1957,6 where no injectivity abnormalities were reported. Conventional gas or waterfloods usually leave at least 50% of the oil as residual.10 Laboratory models conducted early in the history of flooding showed that simultaneous water/gas injection had sweep efficiency as high as 90%, compared to 60%10 for gas alone. However, completion costs, complexity in operations, and gravity segregation from simultaneous water/gas injection indicated that it was an impractical method for minimizing mobility. Therefore, a CO2 slug followed by WAG has been adopted. The planned WAG ratios of 0.5:4 in frequencies of 0.1 to 2% PV slugs of each fluid11 will cause water-saturation increases during the water cycles and decreasing water saturations during the gas half of the WAG cycle. The displacement mechanism caused by the WAG process occurs in a three-phase regime; the cyclic nature of the process creates a combination of imbibition and drainage.9 Optimum conditions of oil displacement by WAG processes are achieved if the gas and water have equal velocity in the reservoir. The optimum WAG design is different for each reservoir and needs to be determined for a specific reservoir and possibly fine-tuned for patterns within the reservoir.12 There are a number of different WAG schemes to optimize recovery. Unocal patented a process called Hybrid-WAG, in which a large fraction of the pore volume of CO2 to be injected is injected followed by the remaining fraction divided into 1:1 WAG ratios.11 Shell empirically evolved a similar process called DUWAG (Denver Unit WAG) by comparing continuous injection and WAG processes.
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NASR-ISFAHANI, RASOUL, and SIMA SOLTANI RENANI. "ON HOMOLOGICAL PROPERTIES FOR SOME MODULES OF UNIFORMLY CONTINUOUS FUNCTIONS OVER CONVOLUTION ALGEBRAS." Bulletin of the Australian Mathematical Society 84, no. 2 (July 13, 2011): 177–85. http://dx.doi.org/10.1017/s0004972711002024.
Повний текст джерелаАнотація:
AbstractFor a locally compact group G, let LUC(G) denote the space of all left uniformly continuous functions on G. Here, we investigate projectivity, injectivity and flatness of LUC(G) and its dual space LUC(G)* as Banach left modules over the group algebra as well as the measure algebra of G.
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Fedorov, Konstantin, Alexander Shevelev, Alexander Gilmanov, Andrey Arzhylovskiy, Denis Anuriev, Ivan Vydysh, and Nikita Morozovskiy. "Injection of Gelling Systems to a Layered Reservoir for Conformance Improvement." Gels 8, no. 10 (September 29, 2022): 621. http://dx.doi.org/10.3390/gels8100621.
Повний текст джерелаАнотація:
The paper describes the introduction and estimation of performance criteria for the gelling agent injection technology based on a general approach to modeling physical and chemical enhanced oil recovery (EOR) methods. The current mathematical models do not include performance criteria for the process of gelling agent injection and do not allow for assessing the level of success of a treatment job in production wells. The paper introduces such criteria for the first time. To simulate the effect on injection wells, the mass conservation laws and the generalized flow law are used, and closing relations for the gelling rate are taken into account. A conformance control coefficient is introduced which characterizes the positive effect of well treatments and injectivity drop which characterizes the negative effect. The performance criteria allow for identifying the wells where the treatment jobs were the most successful. The model verification, based on the comparison of post-treatment injectivity estimated in the developed model, with Rosneft’s field data showed a satisfactory match. The developed correlations can be used as the basis for a surrogate model that allows for avoiding building sector geological and flow simulation models of the treated zone.
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Wang, Yuan, Jie Ren, Shaobin Hu, and Di Feng. "Global Sensitivity Analysis to Assess Salt Precipitation for CO2 Geological Storage in Deep Saline Aquifers." Geofluids 2017 (2017): 1–16. http://dx.doi.org/10.1155/2017/5603923.
Повний текст джерелаАнотація:
Salt precipitation is generated near the injection well when dry supercritical carbon dioxide (scCO2) is injected into saline aquifers, and it can seriously impair the CO2 injectivity of the well. We used solid saturation (Ss) to map CO2 injectivity. Ss was used as the response variable for the sensitivity analysis, and the input variables included the CO2 injection rate (QCO2), salinity of the aquifer (XNaCl), empirical parameter m, air entry pressure (P0), maximum capillary pressure (Pmax), and liquid residual saturation (Splr and Sclr). Global sensitivity analysis methods, namely, the Morris method and Sobol method, were used. A significant increase in Ss was observed near the injection well, and the results of the two methods were similar: XNaCl had the greatest effect on Ss; the effect of P0 and Pmax on Ss was negligible. On the other hand, with these two methods, QCO2 had various effects on Ss: QCO2 had a large effect on Ss in the Morris method, but it had little effect on Ss in the Sobol method. We also found that a low QCO2 had a profound effect on Ss but that a high QCO2 had almost no effect on the Ss value.
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Tomkinson, M. J. "Infinite quasi-injective groups." Proceedings of the Edinburgh Mathematical Society 31, no. 2 (June 1988): 249–59. http://dx.doi.org/10.1017/s0013091500003370.
Повний текст джерелаАнотація:
A group G is said to be quasi-injective if, for each subgroup H of G and homomorphism θ:H→G, there is an endomorphism such that . It is of course well known that the category of groups does not possess non-trivial injective objects and so we consider groups satisfying the weaker condition of quasi-injectivity.
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Saikia, Bikash D., and Dandina N. Rao. "A Single-Well Gas-Assisted Gravity Drainage Enhanced Oil Recovery Process for U.S. Deepwater Gulf of Mexico Operations." Energies 14, no. 6 (March 21, 2021): 1743. http://dx.doi.org/10.3390/en14061743.
Повний текст джерелаАнотація:
The U.S. Deepwater Gulf of Mexico (DGOM) area that has some of the most prolific oil reservoirs is still awaiting the development of a viable enhanced oil recovery (EOR) process. Without it, DGOM will remain severely untapped. Exorbitant well costs, in excess of $200 million, preclude having extensive injection patterns, commonly used in EOR design frameworks. Aside from injection patterns, even operationally waterflooding has met with significant challenges because of injectivity issues in these over pressurized turbidities. The gas-assisted gravity drainage (GAGD) EOR process, that holds promise for deepwater environments because of lesser injectivity issues, among others, has been adapted in this work to overcome these limitations. A novel design in the form of a single well—gas assisted gravity drainage (SW-GAGD) process, has been demonstrated to emulate the benefits of a GAGD process in a cost-effective manner. Unlike conventional GAGD processes, which need multiple injectors and separate horizontal production wells, the SW-GAGD process just uses a single well for injection and well production. The performance of the process has been established using partially scaled visual glass models based on dimensional analyses for scale up of the process. The recovery factor has been shown to be in the range of 65–80% in the immiscible mode alone, and the process is orders of magnitude faster than natural gravity drainage. A toe-to-heel configuration of the SW-GAGD process has also been tested and for the configuration to be immune from reservoir layering, the toe of the well should ideally end at the top of the payzone. Better sweep of the payzone and consequent high recovery factor of 80% OOIP was observed, if the heel part of the bottom lateral is located in a lower permeability zone.
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Al-Mohammad, A. M. M., M. H. H. Alkhaldi, S. H. H. Al-Mutairi, and A. A. A. Al-Zahrani. "Acidizing-Induced Damage in Sandstone Injector Wells: Laboratory Testing and a Case History." SPE Journal 17, no. 03 (April 25, 2012): 885–902. http://dx.doi.org/10.2118/144007-pa.
Повний текст джерелаАнотація:
Summary Throughout a well's lifetime, formation damage can occur during the activities of drilling, completion, injection, or well-stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more-severe form of formation damage. This report discusses the improper use of mud acid [at 9 wt% hydrochloric acid (HCl)/1 wt% hydrofluoric acid (HF)] in restoring the injectivity of Well N-510. The subject well was stimulated with two acid-stimulation treatments in an attempt to improve the poor results of a previous cleanout job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage that resulted in the severe decline of well injectivity. Integration of chemical-analysis techniques performed on return fluids and coreflood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation-damage mechanism that occurred during each treatment. On the basis of these studies, it was found that the poor results of the cleanout job were caused by precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-sulfate-content water. Most of this precipitation occurred in the wellbore vicinity during the preceding stages of the well flowback. Calcium sulfate precipitation had a negative impact on the performance of the conducted acid-stimulation treatments. In the presence of this precipitation, the two successive mud-acid-stimulation treatments created another form of damage (i.e., in-situ fluoride-based scale). Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale, and as a result, it contained a high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value. The interactions between different acid systems and the constituents of the downhole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications for future stimulation treatments, conducted under similar conditions, so as to prevent the formation of these scales.