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Статті в журналах з теми "Well injectivity"
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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.
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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.
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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.
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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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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.
Дисертації з теми "Well injectivity"
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Beinashor, R. "Effect of halite (NaCl) on sandstone permeability and well injectivity during CO2 storage in saline aquifers." Thesis, University of Salford, 2017. http://usir.salford.ac.uk/44572/.
Повний текст джерелаАнотація:
Carbon dioxide capture and storage (CCS) is one of the widely discussed options for decreasing CO2 emissions. This method requires the techniques for capturing purification of anthropogenic CO2 from fossil-fuel power plants, subsequent compression and transport, and, ultimately, its storage in deep geological formations. Due to the high formation salinity, there is a substantial concern about the near well bore formation dry out as a result salt precipitation in the form of halite (NaCl). The focus was on one of the important physical mechanisms of CO2 injection into deep saline aquifers. The salt (mainly halite) will eventually fully saturate the brine causing the salt to start precipitating as solids. This solid precipitation could significantly decrease the porosity and permeability of the porous medium. The investigations, in this study, were carried out in three distinct parts: (i) core flooding tests for different sandstone core samples (Bentheimer, Castlegate and Idaho Gray) which were saturated with different brine concentrations to measure the CO2 flow rate for different injection pressures, (ii) utilising simulated experimental apparatus to estimate the porosity and permeability of the core samples and (iii) Qualitative analysis of porosities using CT scanner. In Part (i), it was found that the CO2 flow rates vary from 0.4 to 6.0 l/min when using brine solution concentrations of 10, 15, 20 and 26.4% for core flooding tests of the studied sandstone core samples before diluting concentrations with sea water (3.5%), and after diluting by sea water the flow rates vary from 0.6 to 7.0 l/min. The flow rate increase indicates that the injectivity will increase. In part (ii), Helium Gas Porosimeter was used to calculate the porosity of each core sample and the results showed for Bentheimer, Castlegate and Idaho Gray 20.8 %, 25.6 % and 23.4 % respectively. Liquid saturating method was also used to calculate the porosity of each core sample and the results showed 23.6% for Bentheimer, 24.4% for Castlegate and 22.4% for Idaho Gray. Regarding the permeability impairment investigations for both brine permeability and gas permeability, the permeability damage took place due to the salt precipitation (NaCl) phenomenon. For brine permeability, the damage percentage of Bentheimer, Castlegate and Idaho Gray was 40%, 42% and 47%. For gas permeability the reduction due to dry out of saturated samples with 20% brine solution were calculated as 34.5% for Bentheimer, 42% for Castlegate and 50.2% for Idaho Gray. Finally, in part (iii), CT Scan was used to determine each core sample porosity and the results showed 20.7% for Bentheimer, 24.3% for Castlegate and 24.6% for Idaho Gray.
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Dijols, Sarah. "Distinguished representations : the generalized injectivity conjecture and symplectic models for unitary groups." Thesis, Aix-Marseille, 2018. http://www.theses.fr/2018AIXM0194.
Повний текст джерелаАнотація:
Soit $G$ un groupe connexe quasi-déployé défini sur un corps non-Archimédien de caractéristique nulle. On suppose que l'on se donne un sous-groupe parabolique standard de décomposition de Levi $P=MU$ ainsi qu'une représentation irréductible tempérée $\tau$ de $M$. Soit $\nu$ un élement dans le dual de l'algèbre de Lie de la composante déployée de $M$; on le choisit dans la chambre de Weyl positive. La représentation induite $I_P^G(\tau_{\nu})$ est appelée module standard. Quand la représentation $\tau$ est générique (pour un caractère non-dégénéré de $U$), i.e a un modèle de Whittaker, le module standard $I_P^G(\tau_{\nu})$ est également générique.Casselman et Shahidi ont conjecturé que l'unique sous-quotient générique apparaissait nécessairement comme sous-représentation dans le module standard $I_P^G(\tau_{\nu})$. Ceci a été démontrée dans le cas des groupes classiques $SO(2n+1), Sp(2n)$, et $SO(2n)$ quand $P$ est un sous-groupe parabolique maximal de $G$, par Hanzer en 2010.Dans notre travail, nous formulons et étudions ce problème dans le contexte plus général d'un groupe connexe quasi-déployé tel que les composantes irréductibles de $\Sigma_{\sigma}$ sont de type $A,B,C$ ou $D$.Dans la deuxième partie de cette thèse (en commun avec D.Prasad), nous prouvons d'abord qu'il n'existe pas de representation cuspidale du groupe quasi-déployé $\U_{2n}(F)$ qui soit distinguée par son sous-groupe $\Sp_{2n}(F)$ pour $F$ un corps local non-Archimédien. Nous prouvons ensuite le théorème équivalent pour un corps global: il n'existe pas de représentation cuspidale de $\U_{2n}(\A_k)$ qui ait une période symplectique non nulle pour $k$ un corps de nombres ou corps de fonctionsLet $G$ be a quasi-split connected reductive group over a non-Archimedean local field $F$ of characteristic zero. We assume we are given a standard parabolic subgroup $P$ with Levi decomposition $P=MU$ as well as an irreducible, tempered representation $\tau$ of $M$. Let now $\nu$ be an element in the dual of the real Lie algebra of the split component of $M$; we take it in the positive Weyl chamber. The induced representation $I_P^G(\tau_{\nu})$ is called a standard module. When the representation $\tau$ is generic (for a non-degenerate character of $U$), i.e. has a Whittaker model, the standard module $I_P^G(\tau_{\nu})$ is also generic. Casselman and Shahidi have conjectured that the unique irreducible generic subquotient of a standard module $I_P^G(\tau_{\nu})$ is necessarily a subrepresentation. This conjecture known as the Generalized Injectivity Conjecture was proved for the classical groups $SO(2n+1), Sp(2n)$, and $SO(2n)$ for $P$ a maximal parabolic subgroup, by Hanzer in 2010.In our work, we formulate and study this problem for any quasi-split connected reductive group such that the irreducible components of $\Sigma_{\sigma}$ are of type $A,B,C$ or $D$. In the second part of this thesis (joint work with D.Prasad), we prove that there are no cuspidal representations of the quasi-split unitary groups $\U_{2n}(F)$ distinguished by $\Sp_{2n}(F)$ for $F$ a non-archimedean local field. We also prove the corresponding global theorem that there are no cuspidal representations of $\U_{2n}(\A_k)$ with nonzero period integral on $\Sp_{2n}(k) \backslash \Sp_{2n}(\A_k)$ for $k$ any number field or a function field
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Gomes, Vanessa Limeira Azevedo. "Modelagem e previs?o da perda de injetividade em po?os canhoneados." Universidade Federal do Rio Grande do Norte, 2010. http://repositorio.ufrn.br:8080/jspui/handle/123456789/12928.
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Waterflooding is a technique largely applied in the oil industry. The injected water displaces oil to the producer wells and avoid reservoir pressure decline. However, suspended particles in the injected water may cause plugging of pore throats causing formation damage (permeability reduction) and injectivity decline during waterflooding. When injectivity decline occurs it is necessary to increase the injection pressure in order to maintain water flow injection. Therefore, a reliable prediction of injectivity decline is essential in waterflooding projects. In this dissertation, a simulator based on the traditional porous medium filtration model (including deep bed filtration and external filter cake formation) was developed and applied to predict injectivity decline in perforated wells (this prediction was made from history data). Experimental modeling and injectivity decline in open-hole wells is also discussed. The injectivity of modeling showed good agreement with field data, which can be used to support plan stimulation injection wells
A inje??o de ?gua ? uma t?cnica amplamente utilizada para deslocar o ?leo em dire??o aos po?os produtores e manter a press?o em reservat?rios de petr?leo. Entretanto, part?culas suspensas na ?gua injetada podem ser retidas no meio poroso, causando dano ? forma??o (redu??o de permeabilidade) e perda de injetividade. Quando ocorre essa redu??o de injetividade ? necess?rio aumentar a press?o de inje??o para manter a vaz?o de ?gua injetada. Desse modo, a correta previs?o da perda de injetividade ? essencial em projetos de inje??o de ?gua. Neste trabalho, um simulador, baseado no modelo tradicional da filtra??o em meios porosos (incluindo filtra??o profunda e forma??o do reboco externo), foi desenvolvido e aplicado para prever a perda de injetividade em po?os canhoneados (tal previs?o foi feita a partir de dados de hist?rico). Al?m disso, tamb?m foi discutida a determina??o experimental dos coeficientes do modelo e a perda de injetividade em po?os abertos. A modelagem da injetividade apresentou bom ajuste aos dados de campo, podendo ser utilizada para auxiliar no planejamento de estimula??es de po?os injetores
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Kalantariasl, Azim. "Advanced analytical models for well injectivity decline." Thesis, 2015. http://hdl.handle.net/2440/98001.
Повний текст джерелаАнотація:
The major fraction of world oil is produced by waterflooding, where the injected water displaces oil and maintains the reservoir pressure. In addition, produced water reinjection (PWRI) is an economic and environmental-friendly option to convert waste to value with waterflooding. However, the major challenge is the drastic decline of well injectivity which has been widely reported in the literature. The main mechanisms of the injectivity decline are capture of particles from injected water in the porous rock and formation of low permeable external filter cake on the well wall followed by its stabilisation. The reliable predictive analytical model for well injectivity behaviour forecast up to the stabilisation stage is not available in the literature. So, the aim of this thesis is to develop full predictive analytical models for injectivity decline during sea water injection and PWRI. In order to achieve this aim, a new mathematical model for injectivity stabilisation using mechanical equilibrium of a particle on the cake surface accounting for all colloidal forces is developed in this thesis. It is found that the main empirical parameter of the model, highly affecting the stabilised cake prediction, is the lever arm ratio. The lever arm ratio is calculated from laboratory cross-flow filtration experiments and from well injectivity data. It is also determined from Hertz’s theory for the elastic particle deformation. Good agreement between the calculated results for the lever arm ratio validates the developed model. This thesis presents the derivation of a new analytical model for non-uniform cake thickness profile along injection wells. It is found out that, two regimes of the stabilised cake build-up correspond to low injection rates, where the cake starts from the reservoir top, and for high injection rates, where the cake is formed only on the lower well section. The sensitivity analysis shows that water injection rate, cake porosity, water salinity and Young’s modulus are the most influential parameters defining the cake thickness profile. The thesis presents the development of an analytical model for axi-symmetric two-phase flow with simultaneous deep bed filtration of injected particles, formation of external filter cake and its stabilisation due to particle dislodgement. It also introduces a seven-parameter adjustment method. It is shown that the initial injectivity increase, induced by varying two-phase mobility, adds three degrees of freedom to one-phase impedance growth model. This additional information is used to tune the models with the Corey relative permeability and the pseudo relative permeability under the viscous-dominant displacement. Good agreement between field data and model prediction validates the developed analytical model for injectivity decline during waterflooding and its adjustment method. The developed analytical model along with laboratory coreflood test data and probabilistic histograms of injectivity damage parameters are applied to predict the injectivity behaviour during produced water disposal into a thick low preamble sandstone reservoir as a field case study. Unusual convex form of impedance curve is observed in the coreflood test and well behaviour modelling; impedance grows slower during external cake formation if compared with deep bed filtration. Risk analysis method using probabilistic histograms of injectivity damage parameters is also developed and applied to well behaviour prediction under high uncertainty conditions. The above analytical models, results of laboratory studies and field cases allow recommending the developed models for full prediction of injectivity decline during waterflooding and disposal operations.Thesis (Ph.D.) (Research by Publication) -- University of Adelaide, Australian School of Petroleum, 2015.
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Hwang, Jongsoo. "Factors affecting injection well performance and fracture growth in waterflooded reservoirs." Thesis, 2014. http://hdl.handle.net/2152/28434.
Повний текст джерелаАнотація:
Waterflooding involves the injection of water to displace oil from oil and gas reservoirs. Well over 80% of oil reservoirs will undergo waterflooding at some point in their life. It is, therefore, important to understand some key aspects of this process that have hitherto not been well studied. This dissertation investigates the following aspects of waterflooding: (i) the filtration of solids and oil-in-water emulsions in fractured and unfractured injection wells, (ii) the generation and filtration of oil-in-water (O/W) emulsion droplets in the near-well region or in the fracture, (iii) the height-growth and containment of injection-induced fractures, and (iv) the stress reorientation induced by water injection when waterflooding reservoirs. These aspects are investigated as separate physical phenomena, but their impacts are integrated using the platform of a comprehensive waterflooding injection well model. The first phenomenon investigated is filtration in frac-packed injectors. During long-term water injection, solid particles in the injection water may deposit in the proppant pack of frac-packed injectors. Researchers have not fully understood whether particles will travel without plugging the frac-packs or deposit in the near-well area under the high-velocity flow conditions in the proppants. Filtration behavior under frac-pack flow conditions is the most important factor that determines overall injector performance. In this dissertation the filtration of injected solids under these conditions was experimentally studied, and the effect of frac-pack filtration on the injector performance was predicted. The flow of dilute oil droplets in a porous medium under near-well conditions was experimentally investigated. When the porous medium has a residual oil saturation, oil droplets can be generated by viscous forces overcoming entrapping capillary forces. The generated oil droplets will subsequently participate in filtration processes along with injected oil droplets. If this occurs in the near-injector area, the injectivity can severely decline and this may require expensive remediation processes. In this study, prediction of O/W emulsion flow was improved by experimental observations of the rates of generation and filtration of oil droplets. In a larger scale problem, a 3-dimensional model of water-injection-induced fracture was developed to predict the fracture height growth. If a fracture breaches the bounding layers, the sweep efficiency can be significantly impaired and it could have severe environmental consequences (such as contamination of shallower aquifers or the seabed). During long-term water injection, fracture growth can only be simulated properly when the filtration near fractures, thermo-elastic stress changes and reservoir fluid flow behavior are all concurrently calculated. Based on this new model, the impact of reservoir stress conditions, mechanical properties, and injection-water quality on fracture growth was studied. On a reservoir-scale, the stress reorientation caused by injection-production activities during waterflooding was investigated. A new finite-volume multi-phase reservoir simulation with poro- and thermo-elasticity was developed. This model was applied to various waterflooding well patterns, such as five-, nine-spot, line-drive and horizontal well pairs, and the critical geomechanical responses by injection-production activities during waterflooding operations were analyzed. The model can be used to predict the direction of induced fractures, design infill well locations and configurations and optimize the reservoir sweep. Through the use of both experimental observations and numerical models this work has elucidated various physical phenomena affecting fracture growth and injection-well performance. The findings in this dissertation provide critical data and models that help us to more confidently specify injection water quality, the design of pumping and water treatment facilities, and the optimization of well planning. The models developed in this work can be used to substantially improve the predictions of injection well performance and improve reservoir oil recovery by waterflooding.text
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Jackson, Gregory Thomas 1983. "CFD-based representation of non-Newtonian polymer injectivity for a horizontal well with coupled formation-wellbore hydraulics." Thesis, 2010. http://hdl.handle.net/2152/ETD-UT-2010-12-2078.
Повний текст джерелаАнотація:
During injection of a high-viscosity, non-Newtonian polymer into a long horizontal well, a significant pressure drop occurs along the well length. Computational Fluid Dynamics (CFD) modeling of the shear-thinning flow of polymer in the wellbore, coupled with the viscoelastic flow in composite gravel-pack/near-well formation zone, was carried out to develop convenient correlations for axial pressure values of both Newtonian and non-Newtonian fluids along the well length, for use in chemical EOR simulations.
The detailed CFD modeling of the non-Newtonian flow behavior of polymer within the horizontal wellbore, completion zone and the near-well formation, not only allows accurate accounting of pressure distribution along the long horizontal well, but also can be employed for screening diagnosis for possible injectivity inefficiencies resulting from non-uniform pressure values.
At both high and low injection rates, CFD modeling predicts non-uniform pressure distributions for highly viscous fluids. The inclusive pressure correlation was implemented into UTCHEM, a University of Texas at Austin research simulator, to determine the importance of including pressure drop in polymer injections. Early times (i.e., less than 100 days) yielded a significant oil recovery deviation from a uniform pressure wellbore. However, at later times the recovery loss generated by the pressure decrease was deemed negligible; therefore, the traditional assumption regarding uniform pressure in horizontal wellbores was still reasonable for highly viscous non-Newtonian flow.
This CFD study is the first mechanistic investigation of the polymer injectivity with detailed description of the wellbore, completion zone and near-well formation, and with full accounting of the shear-thinning rheology for pipe flow and the viscoelastic rheology of polymer in porous media. With increased use of very high molecular-weight polymers for chemical EOR processes for mobility control, the latter mechanism is known to be critical.text
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Lee, Kyung Haeng. "Impact of fracture creation and growth on well injectivity and reservoir sweep during waterflooding and chemical EOR processes." Thesis, 2012. http://hdl.handle.net/2152/ETD-UT-2012-05-5061.
Повний текст джерелаАнотація:
During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance.
In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery.
In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated.
The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery.text
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Boechat, Chequer Larissa. "Particle Detachment in Single-Phase and Two-Phase Flows in Porous Media." Thesis, 2019. http://hdl.handle.net/2440/124362.
Повний текст джерелаАнотація:
Hereby I present a PhD thesis by publications. This thesis includes seven journal papers, of which six have already been published in peer-reviewed journals and one has been submitted for publication and is presently under review. This thesis shows that the commonly used single particle-single surface Derjaguin-Landau-Verwey-Overbeek (DLVO) calculations do not always effectively predict particle detachment. Therefore, the mobilisation of clustered structures under particle-particle attraction is investigated. The critical detachment velocity of clusters is higher than for single colloids and provides better agreement with the laboratory results. The behaviour of particles and clusters was also investigated during drainage and imbibition in visualisation experiments. Particles remain on the air-water interfaces of residual liquid patches left behind the drainage front. Later, these particles join the imbibition front away from the substrate. In a previously dried channel, the vapour condensation ahead of the imbibition front detaches particles from the surface by a rising air-water interface. This thesis presents an extension of the traditional mathematical model for colloid transport by including equations for the particle re-attachment rate and the attached-concentration-dependency of permeability. The new model captures the effect of permeability increase due to colloid mobilisation and further re-attachment in stagnant zones of the porous space. This effect was observed during high-salinity water injection in cores with low kaolinite concentrations. This model is also extended to account for the presence of a residual phase. Compared with fines migration under single-phase flow, having a residual phase significantly reduces the permeability variation. Analytical solutions for over and undersaturated state of fines were also derived in this thesis. Oversaturation means that particles begin to detach as soon as the flow starts. In the undersaturated case, particle detachment occurs only with further increase in detaching torque or decrease in attaching torque. The derived models allow formulating the fingerprints for the flow of over and undersaturated fines in porous media. Novel analytical models for one-dimensional linear and axisymmetric suspension-colloidal transport accounting for fines detachment and capture were also derived. Laboratory experiments with low-salinity water injection were performed. The model coefficients obtained from laboratory data treatment were used for reliable laboratory-based prediction of well injectivity decline. The results show that fines migration during low-salinity water injection results in significant well injectivity impairment. The thesis also investigates low-salinity water slug injection followed by a high-salinity chase drive in a two layer-cake reservoir. The formation damage caused by fines mobilisation during low-salinity water injection diverts the injected water flux into low-permeability zones and enhances sweep efficiency. An optimal low-salinity slug size existed for all simulated cases. The optimal slug size is similar to the pore volume of the high-permeability layer. The analytical models derived in this thesis are applicable in numerous environmental and engineering processes, including the injection of low-salinity or hot water in a reservoir, ocean water invasion into aquifers, freshwater storage, and contamination of subterranean waters by viruses and bacteria. It also has many applications in hydrology and ecology, such as ground cleaning from non-aqueous phase liquids, remediation of contaminated soil and groundwater, and natural filtration of pathogenic microorganisms.Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum and Energy Resources, 2020
Частини книг з теми "Well injectivity"
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A. Sokama-Neuyam, Yen, Muhammad A.M. Yusof, and Shadrack K. Owusu. "CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation and Fines Mobilization." In Carbon Sequestration [Working Title]. IntechOpen, 2022. http://dx.doi.org/10.5772/intechopen.104854.
Повний текст джерелаАнотація:
Climate change is now considered the greatest threat to global health and security. Greenhouse effect, which results in global warming, is considered the main driver of climate change. Carbon dioxide (CO2) emission has been identified as the largest contributor to global warming. The Paris Agreement, which is the biggest international treaty on Climate Change, has an ambitious goal to reach Net Zero CO2 emission by 2050. Carbon Capture, Utilization and Storage (CCUS) is the most promising approach in the portfolio of options to reduce CO2 emission. A good geological CCUS facility must have a high storage potential and robust containment efficiency. Storage potential depends on the storage capacity and well injectivity. The major target geological facilities for CO2 storage include deep saline reservoirs, depleted oil and gas reservoirs, Enhanced Oil Recovery (EOR) wells, and unmineable coal seams. Deep saline formations have the highest storage potential but challenging well injectivity. Mineral dissolution, salt precipitation, and fines mobilization are the main mechanisms responsible for CO2 injectivity impairment in saline reservoirs. This chapter reviews literature spanning several decades of work on CO2 injectivity impairment mechanisms especially in deep saline formations and their technical and economic impact on CCUS projects.
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Civan, Faruk. "INJECTIVITY OF THE WATERFLOODING WELLS." In Reservoir Formation Damage, 775–813. Elsevier, 2007. http://dx.doi.org/10.1016/b978-075067738-7/50020-8.
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Civan, Faruk. "Injectivity of the Water-flooding Wells." In Reservoir Formation Damage, 343–77. Elsevier, 2016. http://dx.doi.org/10.1016/b978-0-12-801898-9.00013-8.
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FOKKER, P., and L. VANDERMEER. "The Injectivity of Coalbed CO2 Injection Wells." In Greenhouse Gas Control Technologies - 6th International Conference, 551–56. Elsevier, 2003. http://dx.doi.org/10.1016/b978-008044276-1/50088-x.
Повний текст джерелаТези доповідей конференцій з теми "Well injectivity"
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Nabzar, L., J. -P. Coste, and G. Chauveteau. "Water Quality and Well Injectivity." In IOR 1997 - 9th European Symposium on Improved Oil Recovery. European Association of Geoscientists & Engineers, 1997. http://dx.doi.org/10.3997/2214-4609.201406785.
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Mei, Wenrong, Ammal F. Al-Anazi, and Karam S. Yateem. "Water Disposal Wells Injectivity Enhanced by Well Treatment Optimization." In Offshore Technology Conference. OTC, 2021. http://dx.doi.org/10.4043/31185-ms.
Повний текст джерелаАнотація:
Abstract Produced water is always an unwanted by-product for any hydrocarbon producing process. Underground disposal of the produced formation water has many benefits such as minimum or no damage to the environment. However, formation damage arising from injection of water containing impurities is usually of great concerns and poses challenges for maintaining good injectivity of disposal wells. Well stimulation is probably one of the most effective treatment to restore the injection of impaired wells. Therefore, well treatment and optimization always play an important role in cost saving and injectivity improvement. Although many treatments such as acidizing and mutual solvent have been developed as a standard practice and are widely employed in the oil and gas industry, there is no universal treatment recipe which may be used to effectively stimulate a well without doing any well specific studies. To effectively tackle the injection rate decline issue in water disposal wells, understanding the process, quality of injection water and the nature of the in-situ properties of the formation is vitally important. Therefore, analysis of the formation minerals and lithology, produced water, well performance and field stimulation histories had been thoroughly reviewed and examined to understand the root causes and the mechanisms underlying the rate reduction and how to improve the injectivity. Laboratory experiments had then been organized and conducted for evaluating and optimizing the treatment. Fit-for-purpose well treatments were finally designed and executed for field evaluation. Once the field treatment was done, a thorough review and benchmarking of the treatment job had been performed to capture the lessons learned. More laboratory evaluation may be necessarily carried out for further improvement in the next well treatment. Applying the above process to the treatment of water disposal wells, a new well specific matrix stimulation treatment had been developed and applied to a few water disposal wells over the last few years. When compared with the outcomes of other types of treatment in history, the injection gain from this type of treatment was significant with a maximum 400% injection increase. Moreover, the improved injectivity had longer effective duration up to 26 months so far. Still a few wells have no signs of injection rate drop. The benefits are obviously enormous in terms of cost saving and injection gain. Effectiveness of a well specific treatment is rooted into the thorough understanding of the physical and chemical interaction between alien fluids and the in-situ formation. Laboratory evaluation is an important key to the development of a successful treatment recipe, which was showcased by the work presented in this paper. This would enrich the expertise of petroleum professionals in the limited stimulation practice of the water disposal wells.
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Ponce Da Motta, E. "New Intelligent Completion Well Design For High-Rate Stimulated Wells Producing From Carbonate Reservoirs." In Second EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2017. http://dx.doi.org/10.3997/2214-4609.201702646.
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André, L. "Well Injectivity during CO2 Storage Operations in Deep Saline Aquifers." In First EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201412023.
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Kuiper, N., C. Rowell, and B. Shomar. "Inter-well Tracer and Marker Monitoring Strategies in Carbonates." In First EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201412017.
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Hassig, Santiago, Pierre Ramondenc, Adolfo Sandoval, Cabe Vreeland, Wei Zhou, Rommy Cevallos, Cristina Villacres, et al. "Surgical Coiled Tubing Stimulations Revolutionize the Effectiveness and Efficiency of Waterflooding Interventions." In SPE/ICoTA Well Intervention Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/209028-ms.
Повний текст джерелаАнотація:
Abstract An innovative coiled tubing (CT) real-time flow measurement tool was introduced in Ecuador to reformulate the stimulation workflow in water injectors, which comprised evaluation and treatment. This new technology enabled an integrated, single-run workflow instead: initial injectivity measurements, diagnostics, treatment, post-stimulation injectivity measurements, and final diagnostics. This novel, rigless approach reduced equipment footprint, operational time, and cost, and it improved production as compared to the conventional approach, despite accrued capital discipline constraints. Conventionally, operators rely on workover rigs and multiple product lines to diagnose, stimulate, and evaluate injector wells. Several challenges and inefficiencies were addressed by deploying the CT real-time flow measurement tool. Each intervention was designed to be completed with a single CT run, and without the need for a workover rig, thus saving costs and time. Tailored diversion methods substituted the need for drillpipe to set mechanical packers. Prestimulation injection logging test (ILT) results obtained with that innovative tool, coupled with real-time control of depth and high-pressure jetting during execution, enabled effective placement of the stimulation treatment. Ultimately, post-treatment ILTs confirmed treatment effectiveness and final wellbore downhole conditions. Introduction of the CT real-time downhole flow measurement tool allowed operational objectives to be met in a single run, without additional interventions, with or without a workover rig on site. When workover rigs were present, this improved workflow saved an average of 15% operational time. In cases without a workover rig, 105 hours of rig time were saved (without considering rig mobilization time). Four case studies are presented. The first two cases demonstrate how acquisition of ILTs throughout the intervention enabled optimization of fluid placement and introduction of diverter methods. The third case covers a scenario where there was an initially low injectivity and highlights the challenges and lessons associated with recovering injectivity. The fourth case presents challenges unique to flowmeter measurements in heavy-oil environments. In each case, effectiveness of the optimized treatment was measured by two metrics: improvements in net injectivity and uniformity of injection profile, both of which drive the effectiveness of secondary recovery in connected producer wells. On average, wells intervened with this approach featured an improvement in injectivity of 301% (compare to 226% conventionally) and in their injection profile homogeneity by 13%. As a result, the productivity in connected wells improved by as much as 74%, and an average of 39% (compared to 14% conventionally). This innovative workflow is a step-change over conventional approaches to rejuvenate waterflooding. It combines the capabilities of delivering treatments via CT and the power of real-time downhole flow measurements to break the paradigm of multi-line, multi-run operations to remediate and stimulate injector wells. This yields logistically leaner operations, which are less costly, and it enables breakthroughs in secondary recovery through data-enriched interventions in times of budget pressure, not only in Ecuador, but also across the globe.
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Retnanto, A., and T. Ahmed. "Candidate Evaluation, Well Preparation, And Stimulation Strategy For Mature Carbonate Reservoir Restimulation." In Second EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2017. http://dx.doi.org/10.3997/2214-4609.201702637.
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Amhamed, A., and A. Abotaleb. "Novel AGR - EOR Combination for Treating Extra Natural Gas, Saving Energy, Maximizing Oil Production and CO2 Emissions Mitigation." In Second EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2017. http://dx.doi.org/10.3997/2214-4609.201702638.
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Seers, T. D., N. Alyafei, and T. Khan. "Investigation Of The Impact Of Voxel Image Subvolume Size Upon Computed Petrophysical Properties Of Carbonate Rocks Imaged Using X-Ray Computed Microtomography." In Second EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2017. http://dx.doi.org/10.3997/2214-4609.201702639.
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Sayed, A., M. Abdul Ghani, and N. Alyafei. "Analyzing The Effect Of Wettability On Oil Recovery From A Pore-Level Perspective Using Numerical Simulation." In Second EAGE Workshop on Well Injectivity and Productivity in Carbonates. Netherlands: EAGE Publications BV, 2017. http://dx.doi.org/10.3997/2214-4609.201702640.
Повний текст джерелаЗвіти організацій з теми "Well injectivity"
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Aziz, Khalid, Thomas A. Hewett, Sepehr Arbabi, and Marilyn Smith. Productivity and Injectivity of Horizontal Wells. Office of Scientific and Technical Information (OSTI), November 1999. http://dx.doi.org/10.2172/14721.
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Khalid Aziz, Sepehr Arababi, and Thomas A. Hewett. Productivity and Injectivity of Horizontal Wells. Office of Scientific and Technical Information (OSTI), April 1997. http://dx.doi.org/10.2172/2157.
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Arababi, Sepehr, Khalid Aziz, Yasuyuki Hayashida, and Thomas Hewett. Productivity and Injectivity of Horizontal Wells. Office of Scientific and Technical Information (OSTI), November 1999. http://dx.doi.org/10.2172/14395.
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Arbabi, Sepehr, Khalid Aziz, Thomas A. Hewett, and Marilyn Smith. Productivity and Injectivity of Horizontal Wells. Office of Scientific and Technical Information (OSTI), November 1999. http://dx.doi.org/10.2172/14396.
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Aziz, Khalid. Productivity and Injectivity of Hoeizontal Wells. Office of Scientific and Technical Information (OSTI), September 1997. http://dx.doi.org/10.2172/598866.
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Aziz, Khalid. Productivity and injectivity of horizontal wells. Office of Scientific and Technical Information (OSTI), March 2000. http://dx.doi.org/10.2172/751965.
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Aziz, K., and T. A. Hewett. Productivity and injectivity of horizontal wells. Quarterly report, July 1--September 30, 1996. Office of Scientific and Technical Information (OSTI), December 1996. http://dx.doi.org/10.2172/446296.
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Aziz, K., and T. A. Hewett. Productivity and injectivity of horizontal wells. Quarterly report, October 1--December 31, 1996. Office of Scientific and Technical Information (OSTI), January 1997. http://dx.doi.org/10.2172/446297.
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Fayers, F. J., K. Aziz, and T. A. Hewett. Productivity and injectivity of horizontal wells. Quarterly report, October 1--December 31, 1993. Office of Scientific and Technical Information (OSTI), March 1993. http://dx.doi.org/10.2172/10137952.
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Aziz, K., and T. A. Hewett. Productivity and injectivity of horizontal wells. Quarterly report, July 1--September 30, 1995. Office of Scientific and Technical Information (OSTI), November 1995. http://dx.doi.org/10.2172/124996.
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