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1.
Carbon dioxide (CO 2) injection is a well-established method for increasing recovery from oil reservoirs. However, poor sweep efficiency has been
reported in many CO 2 injection projects due to the high mobility contrast between CO 2 and oil and water. Various injection strategies including gravity stable, WAG and SWAG have been suggested and, to some extent,
applied in the field to alleviate this problem. An alternative injection strategy is carbonated water injection (CWI). In
CWI, CO 2 is delivered to a much larger part of the reservoir compared to direct CO 2 injection due to a much improved sweep efficiency. In CWI, CO 2 is used efficiently and much less CO 2 is required compared to conventional CO 2 flooding, and hence the process is particularly attractive for reservoirs with limited access to large quantities of CO 2 (offshore reservoirs or reservoirs far away from inexpensive natural CO 2 resources). This article describes the results of a pore-scale study of the process of CWI by performing high-pressure visualisation
flow experiments. The experimental results show that CWI, compared to unadulterated (conventional) water injection, improves
oil recovery as both a secondary (before water flooding) and a tertiary (after water flooding) recovery method. The mechanisms
of oil recovery by CWI include oil swelling, coalescence of the isolated oil ganglia and flow diversion due to flow restriction
in some of the pores as a result of oil swelling and the resultant fluid redistribution. In this article the potential benefit
of a subsequent depressurisation period on oil recovery after the CWI period is also investigated. 相似文献
2.
Low salinity water injections for oil recovery have shown seemingly promising results in the case of clay-bearing sandstones
saturated with asphaltic crude oil. Reported data showed that low salinity water injection could provide up to 20% pore volume
(PV) of additional oil recovery for core samples and up to 25% PV for reservoirs in near wellbore regions, compared with brine
injection at the same Darcy velocity. The question remains as to whether this additional recovery is also attainable in reservoirs.
The answer requires a thorough understanding of oil recovery mechanism of low salinity water injections. Numerous hypotheses
have been proposed to explain the increased oil recovery using low salinity water, including migration of detached mixed-wet
clay particles with absorbed residual oil drops, wettability alteration toward increased water-wetness, and emulsion formation.
However, many later reports showed that a higher oil recovery associated with low salinity water injection at the common laboratory
flow velocity was neither necessarily accompanied by migration of clay particles, nor necessarily accompanied by emulsion.
Moreover, increased water-wetness has been shown to cause the reduction of oil recovery. The present study is based on both
experimental and theoretical analyses. Our study reveals that the increased oil recovery is only related to the reduction
of water permeability due to physical plugging of the porous network by swelling clay aggregates or migrating clay particles
and crystals. At a fixed apparent flow velocity, the value of negative pressure gradient along the flow path increases as
the water permeability decreases. Some oil drops and blobs can be mobilized under the increased negative pressure gradient
and contribute to the additional oil recovery. Based on the revealed mechanism, we conclude that low salinity water injection
cannot be superior to brine injection in any clay-bearing sandstone reservoir at the maximum permitted injection pressure.
Through our study of low salinity water injection, the theory of tertiary oil recovery has been notably improved. 相似文献
3.
In this study, we systematically investigate the effect of core-scale heterogeneity on the performance of miscible CO 2 flooding under various injection modes (secondary and tertiary). Manufactured heterogeneous core plugs are used to simulate vertical and horizontal heterogeneity that may be present in a reservoir. A sample with vertical heterogeneity (i.e. a layered sample) is constructed using two axially cut half plugs each with a distinctly different permeability value. In these samples, the permeability ratio (PR) defines the ratio between the permeabilities of adjacent half plugs. Horizontal heterogeneity (i.e. a composite sample) is introduced by stacking two or three short cylindrical core segments each with a different permeability value. Our special sample construction techniques have also enabled us to investigate the effect of permeability ratio and crossflow in layered samples and axial arrangement of core segments in composite samples on the ultimate recovery of the floods. Core flooding experiments are conducted with an n-Decane–brine–CO 2 system at a pore pressure of 17.2 MPa and a temperature of 343 K. At this temperature, the minimum miscibility pressure of CO 2 with n-Decane is 12.6–12.7 MPa so it is expected that at 17.2 MPa CO 2 is fully miscible with n-Decane. The results obtained for both the composite and layered samples indicate that CO 2 injection would achieve the highest recovery factor (RF) when performed under the secondary mode (e.g. layered: 79.00%, composite: 89.83%) compared with the tertiary mode (e.g. layered: 73.2%, composite: 86.2%). This may be attributed to the effect of water shielding which impedes the access of the injected CO 2 to the residual oil under the tertiary injection mode. It is also found that the oil recovery from a layered sample decreases noticeably with an increase in the PR as higher PR makes the displacement more uneven due to CO 2 channelling. The RFs of 93.4, 87.89, 77.9 and 69.8% correspond to PRs of 1, 2.5, 5, and 12.5, respectively. In addition, for the layered samples, crossflow was found to have an important role during the recovery process; however, due to excessive channelling, this effect tends to diminish as PR increases. Compared with the layered heterogeneity, the effect of composite heterogeneity on the RF seems to be very subtle as the RF is found to be almost independent from the permeability sequence along the length of a composite sample. This outcome may have been caused by the small diameter of the plugs resulting in invariable 1-D floods. 相似文献
4.
In this work, coreflood studies were carried out to determine the recovery benefits of low salinity waterflood compared to
high salinity waterflood and the role of wettability in any observed recovery benefit. Two sets of coreflood experiments were
conducted; the first set examined the EOR potential of low salinity floods in tertiary oil recovery processes, while the second
set of experiments examined the secondary oil recovery potential of low salinity floods. Changes in residual oil saturation
with variation in wettability, brine salinity and temperature were monitored. All the coreflood tests gave consistent increase
in produced oil, corresponding to reduction in residual oil saturation and increase in water-wetness (for the second set of
experiments) with decrease in brine salinity and increase in brine temperature. 相似文献
5.
Dissolution of CO 2 into brine is an important and favorable trapping mechanism for geologic storage of CO 2. There are scenarios, however, where dissolved CO 2 may migrate out of the storage reservoir. Under these conditions, CO 2 will exsolve from solution during depressurization of the brine, leading to the formation of separate phase CO 2. For example, a CO 2 sequestration system with a brine-permeable caprock may be favored to allow for pressure relief in the sequestration reservoir.
In this case, CO 2-rich brine may be transported upwards along a pressure gradient caused by CO 2 injection. Here we conduct an experimental study of CO 2 exsolution to observe the behavior of exsolved gas under a wide range of depressurization. Exsolution experiments in highly
permeable Berea sandstones and low permeability Mount Simon sandstones are presented. Using X-ray CT scanning, the evolution
of gas phase CO 2 and its spatial distribution is observed. In addition, we measure relative permeability for exsolved CO 2 and water in sandstone rocks based on mass balances and continuous observation of the pressure drop across the core from
12.41 to 2.76 MPa. The results show that the minimum CO 2 saturation at which the exsolved CO 2 phase mobilization occurs is from 11.7 to 15.5%. Exsolved CO 2 is distributed uniformly in homogeneous rock samples with no statistical correlation between porosity and CO 2 saturation observed. No gravitational redistribution of exsolved CO 2 was observed after depressurization, even in the high permeability core. Significant differences exist between the exsolved
CO 2 and water relative permeabilities, compared to relative permeabilities derived from steady-state drainage relative permeability
measurements in the same cores. Specifically, very low CO 2 and water relative permeabilities are measured in the exsolution experiments, even when the CO 2 saturation is as high as 40%. The large relative permeability reduction in both the water and CO 2 phases is hypothesized to result from the presence of disconnected gas bubbles in this two-phase flow system. This feature
is also thought to be favorable for storage security after CO 2 injection. 相似文献
6.
We use a three-dimensional mixed-wet random network model representing Berea sandstone to compute displacement paths and relative
permeabilities for water alternating gas (WAG) flooding. First we reproduce cycles of water and gas injection observed in
previously published experimental studies. We predict the measured oil, water and gas relative permeabilities accurately.
We discuss the hysteresis trends in the water and gas relative permeabilities and compare the behavior of water-wet and oil-wet
media. We interpret the results in terms of pore-scale displacements. In water-wet media the water relative permeability is
lower during water injection in the presence of gas due to an increase in oil/water capillary pressure that causes a decrease
in wetting layer conductance. The gas relative permeability is higher for displacement cycles after first gas injection at
high gas saturation due to cooperative pore filling, but lower at low saturation due to trapping. In oil-wet media, the water
relative permeability remains low until water-filled elements span the system at which point the relative permeability increases
rapidly. The gas relative permeability is lower in the presence of water than oil because it is no longer the most non-wetting
phase. 相似文献
7.
On the basis of observations at four enhanced coalbed methane (ECBM)/CO 2 sequestration pilots, a laboratory-scale study was conducted to understand the flow behavior of coal in a methane/CO 2 environment. Sorption-induced volumetric strain was first measured by flooding fresh coal samples with adsorptive gases (methane
and CO 2). In order to replicate the CO 2–ECBM process, CO 2 was then injected into a methane-saturated core to measure the incremental “swelling.” As a separate effort, the permeability
of a coal core, held under triaxial stress, was measured using methane. This was followed by CO 2 flooding to replace the methane. In order to best replicate the conditions in situ, the core was held under uniaxial strain,
that is, no horizontal strain was permitted during CO 2 flooding. Instead, the horizontal stress was adjusted to ensure zero strain. The results showed that the relative strain
ratio for CO 2/methane was between 2 and 3.5. The measured volumetric strains were also fitted using a Langmuir-type model, thus enabling
calculation of the strain at any gas pressure and using the analytical permeability models. For permeability work, effort
was made to increase the horizontal stress to achieve the desired zero horizontal strain condition expected under in situ
condition, but this became impossible because the “excess” stress required to maintain this condition was very large, resulting
in sample failure. Finally, when CO 2 was introduced and horizontal strain was permitted, permeability reduction was an order of magnitude greater, suggesting
that the “excess” stress would have reduced it significantly further. The positive finding of the work was that the “excess”
stresses associated with injection of CO 2 are large. The excess stresses generated might be sufficient to cause microfracturing and increased permeability, and improved
injectivity. Also, there might be a weakening effect resulting from repeated CO 2 injection, as has been found to be the case with thermal cycling of rocks. 相似文献
8.
Although there are a number of mathematical modeling studies for carbon dioxide (CO 2) injection into aquifer formations, experimental studies are limited and most studies focus on injection into sandstone reservoirs
as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments
to analyze permeability and porosity changes as well as to characterize relevant chemical reactions associated with injection
and storage of CO 2 in carbonate formations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows.
Highly heterogeneous cores drilled from a carbonate aquifer formation located in South East Turkey were used during the experiments.
Porosity changes along the core plugs and the corresponding permeability changes are reported for different CO 2 injection rates and different salt concentrations of formation water. It was observed that either a permeability increase
or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related
to distribution of pores, brine composition and thermodynamic conditions. As the salt concentration decreases, porosity and
the permeability decreases are less pronounced. Calcite deposition is mainly influenced by orientation, with horizontal flow
resulting in larger calcite deposition compared to vertical flow. 相似文献
9.
It is well known that the oil recovery is affected by wettability of porous medium; however, the role of nanoparticles on
wettability alteration of medium surfaces has remained a topic of debate in the literature. Furthermore, there is a little
information of the way dispersed silica nanoparticles affect the oil recovery efficiency during polymer flooding, especially,
when heavy oil is used. In this study, a series of injection experiments were performed in a five-spot glass micromodel after
saturation with the heavy oil. Polyacrylamide solution and dispersed silica nanoparticles in polyacrylamide (DSNP) solution
were used as injected fluids. The oil recovery as well as fluid distribution in the pores and throats was measured with analysis
of continuously provided pictures during the experiments. Sessile drop method was used for measuring the contact angles of
the glass surface at different states of wettability after coating by heavy oil, distilled water, dispersed silica nanoparticles
in water (DSNW), polyacrylamide solution, and DSNP solution. The results showed that the silica nanoparticles caused enhanced
oil recovery during polymer flooding by a factor of 10%. The distribution of DSNP solution during flooding tests in pores
and throats showed strong water-wetting of the medium after flooding with this solution. The results of sessile drop experiments
showed that coating with heavy oil, could make an oil-wet surface. Coating with distilled water and polymer solution could
partially alter the wettability of surface to water-wet and coating with DSNW and DSNP could make a strongly water-wet surface. 相似文献
10.
The injection of supercritical CO 2 through wells into deep brine reservoirs is a topic of interest for geologic carbon sequestration. The injected CO 2 is predominantly immiscible with the brine and its low density relative to brine leads to strong buoyancy effects. The displacement
of brine by CO 2 in general is a multidimensional, complex nonlinear problem that requires numerical methods to solve. The approximations
of vertical equilibrium and complete gravity segregation (sharp interface) have been introduced to reduce the complexity and
dimensionality of the problem. Furthermore, for the radial displacement process considered here, the problem can be formulated
in terms of a similarity variable that reduces spatial and temporal dependencies to a single variable. However, the resulting
ordinary differential equation is still nonlinear and exact solutions are not available. The existing analytical solutions
are approximations limited to certain parameter ranges that become inaccurate over a large portion of the parameter space.
Here, I use a matched boundary extrapolation method to provide much greater accuracy for analytical/semi-analytical approximations
over the full parameter range. 相似文献
11.
The injection of supercritical CO 2 in deep saline aquifers leads to the formation of a CO 2 plume that tends to float above the formation brine. As pressure builds up, CO 2 properties, i.e. density and viscosity, can vary significantly. Current analytical solutions do not account for CO 2 compressibility. In this article, we investigate numerically and analytically the effect of this variability on the position
of the interface between the CO 2-rich phase and the formation brine. We introduce a correction to account for CO 2 compressibility (density variations) and viscosity variations in current analytical solutions. We find that the error in
the interface position caused by neglecting CO 2 compressibility is relatively small when viscous forces dominate. However, it can become significant when gravity forces
dominate, which is likely to occur at late times of injection. 相似文献
12.
According to the research theory of improved black oil simulator, a practical mathematical model for C02 miscible flooding was presented. In the model, the miscible process simulation was realized by adjusting oil/gas relative permeability and effective viscosity under the condition of miscible flow. In order to predict the production performance fast, streamline method is employed to solve this model as an alternative to traditional finite difference methods. Based on streamline distribution of steady-state flow through porous media with complex boundary confirmed with the boundary element method (BEM), an explicit total variation diminishing (TVD) method is used to solve the one-dimensional flow problem. At the same time, influences of development scheme, solvent slug size, and injection periods on CO2 drive recovery are discussed. The model has the advantages of less information need, fast calculation, and adaptation to calculate CO2 drive performance of all kinds of patterns in a random shaped porous media with assembly boundary. It can be an effective tool for early stage screening andmiscible oil field.reservoir dynamic management of the CO2 miscible oil field. 相似文献
13.
This paper presents a quantitative investigation of the interfacial tension dependent relative permeability (IFT-DRP) and
displacement efficiency of supercritical CO 2 injection into gas-condensate reservoirs. A high-pressure high-temperature experimental laboratory was established to simulate
reservoir conditions and to perform relative permeability measurements on sandstone cores at a constant reservoir temperature
of 95°C and displacement velocity of 10 cm/h. This investigation covers immiscible displacements (1100 and 2100 psi), near-miscible
displacement (3000 psi) and miscible displacements (4500 and 5900 psi). The coreflooding results demonstrated that displacement
pressure is a key factor governing the attainment of optimum sweep efficiency. The ultimate condensate recovery increased
by almost threefold when CO 2 was injected at near-miscible conditions (i.e., 23.40% ultimate recovery at 1100 psi compared to 69.70% at 3000 psi). Miscible
flooding was found to give the optimum condensate recovery (9% extra ultimate recovery compared to near-miscible injection).
Besides improving the ultimate recovery, miscible floods provided better mobility ratios and delayed gas breakthrough (0.62
PV BT at 5900 psi compared to 0.21 PV BT at 1100 psi). In addition to the elimination of IFT forces in miscible displacements,
favourable ratios of fluid properties and phase behaviour relationships between the SCCO 2 and condensate were believed to be the driving force for the improved recovery as they provided a stabilising effect on the
displacement front and stimulated swelling of the condensate volume. This paper incorporates the theoretical aspects of phase
behaviour and fluid properties that largely affect the microscopic displacement efficiency and serves as a practical guideline
for operators to aid their project designs and enhance their recovery capabilities. 相似文献
14.
Injection of fluids into deep saline aquifers is practiced in several industrial activities, and is being considered as part of a possible mitigation strategy to reduce anthropogenic emissions of carbon dioxide into the atmosphere. Injection of CO 2 into deep saline aquifers involves CO 2 as a supercritical fluid that is less dense and less viscous than the resident formation water. These fluid properties lead to gravity override and possible viscous fingering. With relatively mild assumptions regarding fluid properties and displacement patterns, an analytical solution may be derived to describe the space–time evolution of the CO 2 plume. The solution uses arguments of energy minimization, and reduces to a simple radial form of the Buckley–Leverett solution for conditions of viscous domination. In order to test the applicability of the analytical solution to the CO 2 injection problem, we consider a wide range of subsurface conditions, characteristic of sedimentary basins around the world, that are expected to apply to possible CO 2 injection scenarios. For comparison, we run numerical simulations with an industry standard simulator, and show that the new analytical solution matches a full numerical solution for the entire range of CO 2 injection scenarios considered. The analytical solution provides a tool to estimate practical quantities associated with CO 2 injection, including maximum spatial extent of a plume and the shape of the overriding less-dense CO 2 front. 相似文献
15.
CO 2 injected into porous formations is accommodated by reduction in the volume of the formation fluid and enlargement of the
pore space, through compression of the formation fluids and rock material, respectively. A critical issue is how the resulting
pressure buildup will affect the mechanical integrity of the host formation and caprock. Building on an existing approximate
solution for formations of infinite radial extent, this article presents an explicit approximate solution for estimating pressure
buildup due to injection of CO 2 into closed brine aquifers of finite radial extent. The analysis is also applicable for injection into a formation containing
multiple wells, in which each well acts as if it were in a quasi-circular closed region. The approximate solution is validated
by comparison with vertically averaged results obtained using TOUGH2 with ECO2N (where many of the simplifying assumptions
are relaxed), and is shown to be very accurate over wide ranges of the relevant parameter space. The resulting equations for
the pressure distribution are explicit, and can be easily implemented within spreadsheet software for estimating CO 2 injection capacity. 相似文献
16.
Geological sequestration of CO 2 offers a promising solution for reducing net emissions of greenhouse gases into the atmosphere. This emerging technology
must make it possible to inject CO 2 into deep saline aquifers or oil- and gas-depleted reservoirs in the supercritical state ( P > 7.4MPa and T > 31.1°C) to achieve a higher density and therefore occupy less volume underground. Previous experimental and numerical simulations
have demonstrated that massive CO 2 injection in saline reservoirs causes a major disequilibrium of the physical and geochemical characteristics of the host
aquifer. The near-well injection zone seems to constitute an underground hydrogeological system particularly impacted by supercritical
CO 2 injection and the most sensitive area, where chemical phenomena (e.g. mineral dissolution/precipitation) can have a major
impact on the porosity and permeability. Furthermore, these phenomena are highly sensitive to temperature. This study, based
on numerical multi-phase simulations, investigates thermal effects during CO 2 injection into a deep carbonate formation. Different thermal processes and their influence on the chemical and mineral reactivity
of the saline reservoir are discussed. This study underlines both the minor effects of intrinsic thermal and thermodynamic
processes on mineral reactivity in carbonate aquifers, and the influence of anthropic thermal processes (e.g. injection temperature)
on the carbonates’ behaviour. 相似文献
17.
The reinjection of sour or acid gas mixtures is often required for the exploitation of hydrocarbon reservoirs containing remarkable
amounts of acid gases (H 2S and CO 2) to reduce the environmental impact of field exploitation and provide pressure support for enhanced oil recovery (EOR) purposes.
Sour and acid gas injection in geological structures can be modelled with TMGAS, a new Equation of State (EOS) module for
the TOUGH2 reservoir simulator. TMGAS can simulate the two-phase behaviour of NaCl-dominated brines in equilibrium with a
non-aqueous (NA) phase, made up of inorganic gases such as CO 2 and H 2S and hydrocarbons (pure as well as pseudo-components), up to the high pressures (~100 MPa) and temperatures (~200°C) found
in deep sedimentary basins. This study is focused on the near-wellbore processes driven by the injection of an acid gas mixture
in a hypothetical high-pressure, under-saturated sour oil reservoir at a well-sector scale and at conditions for which the
injected gas is fully miscible with the oil. Relevant-coupled processes are simulated, including the displacement of oil originally
in place, the evaporation of connate brine, the salt concentration and consequent halite precipitation, as well as non-isothermal
effects generated by the injection of the acid gas mixture at temperatures lower than initial reservoir temperature. Non-isothermal
effects are studied by modelling in a coupled way wellbore and reservoir flow with a modified version of the TOUGH2 reservoir
simulator. The described approach is limited to single-phase wellbore flow conditions occurring when injecting sour, acid
or greenhouse gas mixtures in high-pressure geological structures. 相似文献
18.
Simulations of CO 2 injection into confined saline aquifers were conducted for both vertical and horizontal injection wells. The metrics used
in quantifying the performances of different injection scenarios included changes in pressure near the injection well, mass
of CO 2 dissolved into brine (solubility trapping), and storage efficiency, all evaluated with an assumed injection period of 50 years.
Metrics were quantified as functions of well length, well orientation, CO 2 injection rate, and formation anisotropy (ratio of vertical to horizontal conductivity). When equal well lengths are compared,
there is not a significant difference between the predicted performances of horizontal and vertical wells. However, the length
of a horizontal well may exceed the length of a vertical well because the length of the horizontal well is not constrained
to the vertical thickness of the geologic formation. Simulations show that, as the length of the horizontal well is allowed
to increase, the geologic formation can receive a significantly higher CO 2 injection rate without exceeding a maximum allowable pressure. This result is observed in both isotropic and anisotropic
formations, and suggests that horizontal wells may be advantageous under pressure-limited conditions. However, the use of
horizontal wells does not significantly improve the storage efficiency, and under strongly anisotropic conditions, a vertical
well provides higher storage efficiency than a horizontal well. We conclude that horizontal wells may be preferable if the
goal is to sequester a large amount of CO 2 in a short period of time, but do not offer a significant advantage in terms of long-term capacity of a potential repository. 相似文献
19.
Higher oil recovery after waterflood in carbonate reservoirs is attributed to increasing water wettability of the rock that in turn relies on complicated surface chemistry. In addition, calcite mineral reacts with aqueous solutions and can alter substantially the composition of injected water by mineral dissolution. Carefully designed chemical and/or brine flood compositions in the laboratory may not remain intact while the injected solutions pass through the reactive reservoir rock. This is especially true for a low-salinity waterflood process, where some finely tuned brine compositions can improve flood performances, whereas others cannot. We present a 1D reactive transport numerical model that captures the changes in injected compositions during water flow through porous carbonate rock. We include highly coupled bulk aqueous and surface carbonate-reaction chemistry, detailed reaction and mass transfer kinetics, 2:1 calcium ion exchange, and axial dispersion. At typical calcite reaction rates, local equilibrium is established immediately upon injection. In SI, we validate the reactive transport model against analytic solutions for rock dissolution, ion exchange, and longitudinal dispersion, each considered separately. Accordingly, using an open-source algorithm (Charlton and Parkhurst in Comput Geosci 37(10):1653–1663, 2011. https://doi.org/10.1016/j.cageo.2011.02.005), we outline a design tool to specify chemical/brine flooding formulations that correct for composition alteration by the carbonate rock. Subsequent works compare proposed theory against experiments on core plugs of Indiana limestone and give examples of how injected salinity compositions deviate from those designed in the laboratory for water-wettability improvement. 相似文献
20.
Mitigation and control of borehole pressure at the bottom of an injection well is directly related to the effective management
of well injectivity during geologic carbon sequestration activity. Researchers have generally accepted the idea that high
rates of CO 2 injection into low permeability strata results in increased bottom-hole pressure in a well. However, the results of this
study suggested that this is not always the case, due to the occurrence of localized salt precipitation adjacent to the injection
well. A series of numerical simulations indicated that in some cases, a low rate of CO 2 injection into high permeability formation induced greater pressure build-up. This occurred because of the different types
of salt precipitation pattern controlled by buoyancy-driven CO 2 plume migration. The first type is non-localized salt precipitation, which is characterized by uniform salt precipitation
within the dry-out zone. The second type, localized salt precipitation, is characterized by an abnormally high level of salt
precipitation at the dry-out front. This localized salt precipitation acts as a barrier that hampers the propagation of both
CO 2 and pressure to the far field as well as counter-flowing brine migration toward the injection well. These dynamic processes
caused a drastic pressure build-up in the well, which decreased injectivity. By modeling a series of test cases, it was found
that low-rate CO 2 injection into high permeability formation was likely to cause localized salt precipitation. Sensitivity studies revealed
that brine salinity linearly affected the level of salt precipitation, and that vertical permeability enhanced the buoyancy
effect which increased the growth of the salt barrier. The porosity also affected both the level of localized salt precipitation
and dry-out zone extension depending on injection rates. High temperature injected CO 2 promoted the vertical movement of the CO 2 plume, which accelerated localized salt precipitation, but at the same time caused a decrease in the density of the injected
CO 2. The combination of these two effects eventually decreased bottomhole pressure. Considering the injectivity degradation,
a method is proposed for decreasing the pressure build-up and increasing injectivity by assigning a ‘skin zone’ that represents
a local region with a transmissivity different from that of the surrounding aquifer. 相似文献
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