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1.
Carbonated water injection (CWI) is a CO 2-augmented water injection strategy that leads to increased oil recovery with added advantage of safe storage of CO 2 in oil reservoirs. In CWI, CO 2 is used efficiently (compared to conventional CO 2 injection) and hence it is particularly attractive for reservoirs with limited access to large quantities of CO 2, e.g. offshore reservoirs or reservoirs far from large sources of CO 2. We present the results of a series of CWI coreflood experiments using water-wet and mixed-wet Clashach sandstone cores and
a reservoir core with light oil ( n-decane), refined viscous oil and a stock-tank crude oil. The experiments were carried out to assess the performance of CWI
and to quantify the level of additional oil recovery and CO 2 storage under various experimental conditions. We show that the ultimate oil recovery by CWI is higher than the conventional
water flooding in both secondary and tertiary recovery methods. Oil swelling as a result of CO 2 diffusion into the oil and the subsequent oil viscosity reduction and coalescence of the isolated oil ganglia are amongst
the main mechanisms of oil recovery by CWI that were observed through the visualisation experiments in high-pressure glass
micromodels. There was also evidence of a change in the rock wettability that could also influence the oil recovery. The coreflood
test results also reveal that the CWI performance is influenced by oil viscosity, core wettability and the brine salinity.
Higher oil recovery was obtained with the mixed-wet core than the water-wet core, with light oil than with the viscous oil
and low salinity carbonated brine than high-salinity carbonated brine. At the end of the flooding period, an encouraging amount
of the injected CO 2 was stored in the brine and the remaining oil in the form of stable dissolved CO 2. The experimental results clearly demonstrate the potential of CWI for improving oil recovery as compared with the conventional
water flooding (secondary recovery) or as a water-based EOR (enhanced oil recovery) method for watered out reservoirs. 相似文献
2.
This article deals with developing a solution approach, called the non-isothermal negative saturation (NegSat) solution approach.
The NegSat solution approach solves efficiently any non-isothermal compositional flow problem that involves phase disappearance,
phase appearance, and phase transition. The advantage of the solution approach is that it circumvents using different equations
for single-phase and two-phase regions and the ensuing unstable procedure. This paper shows that the NegSat solution approach
can also be used for non-isothermal systems. The NegSat solution approach can be implemented efficiently in numerical simulators
to tackle modeling issues for mixed CO 2–water injection in geothermal reservoirs, thermal recovery processes, and for multicontact miscible and immiscible gas injection
in oil reservoirs. We illustrate the approach by way of example to cold mixed CO 2–water injection in a 1D geothermal reservoir. The solution is compared with an analytical solution obtained with the wave-curve
method (method of characteristics) and shows excellent agreement. A complete set of simulations is carried out, which identifies
six bifurcations. The two main bifurcations are (1) when the most downstream compositional wave is replaced by a compositional
shock and (2) when an extra Buckley–Leverett rarefaction appears. The plot of the useful energy (exergy) versus the CO 2 storage capacity shows a Z-shape. The top horizontal part represents a branch of high exergy recovery/relatively lower storage capacity, whereas the
bottom part represents a branch of lower exergy recovery/higher storage capacity. 相似文献
3.
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
4.
Scaled in situ laboratory core flooding experiments with CO 2, N 2 and flue gas were carried out on coal in an experimental high P,T device. These experiments will be able to give an insight
into the design of the injection system, management, control of the operations and the efficiency of an ECBM project. Although
the experience gained by the oil industry represents a valuable starting point, several problems are still to be studied and
solved before CO 2 improved deep coalbed methane production may be operationally feasible. These are all related to the heterogeneous nature
of the pore structure of coal, and in particular to the presence of fractures. More specifically, a number of questions need
to be addressed, e.g. what are the conditions under which the fluid in the micro pores of the coal is displaced by the CO 2 in the presence of competitive adsorption; what is the role of compositional heterogeneity and fracture anisotropy of coal
for the injection design and the efficiency of the sequestration in relation to the swelling and shrinkage characteristics
of coal; how does the mobile and the immobile water in the coal affect the exchange process. These questions can be answered
by means of downscaled laboratory experiments that are capable of accurately describing the coupled process of multiphase
flow, competitive adsorption and geo-mechanics. The laboratory conditions have been simulated to match pressure and temperature
at depths of 800 to 1,000 m. Under those conditions the injected CO 2 remains supercritical. Upto now, the results show that dewatering will be an essential step for successful ECBM combined
with a CO 2 sequestration process. 相似文献
6.
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
7.
低渗透油藏注水开发效果差、采收率低,而采用气驱技术是动用此类难采储量的有效方法之一。本文利用长岩心实验模型,进行了物理模拟研究,得到了该油藏在纯气驱、纯水驱、完全水驱后气水交替驱、原始状态下气水交替驱和油藏目前注水倍数下气水交替驱等方式下的采收率和压力等变化情况,为油藏选择合理的开采方式提供了依据,并且为进一步的数值模拟工作提供了基础数据。 相似文献
8.
Surfactant/polymer (SP) floods have significant potentials to recover remaining oil after water flooding. Their efficiency can be maximized by fully utilizing synergistic effect of polymer and surfactant. Various components adsorbed on the rock matrix due to chromatographic separation can significantly weaken the synergistic effect. Due to scale and dimensional problems, it is hard to investigate chromatographic separation among various components using one-dimensional natural cores. This study compared the adsorption difference between artificial and natural cores and developed a three-dimensional artificial core model of a 1/4 5-spot configuration to simulate oil recovery in multilayered reservoirs with high, middle and low permeability for each layer. Sampling wells were established to monitor pressures, and effluent fluids were acquired to measure interfacial tension (IFT) and viscosity. Then, distances of synergy of polymer and surfactant in three layers were evaluated. Meanwhile, electrodes were set in the model to measure oil saturation variation with resistance changes at different locations. Through comparison with IFT values, the contribution of improved swept volume and oil displacement efficiency to oil recovery during SP flooding could be known. Results showed that injected 0.65 PV of SP could improve oil recovery by 21.56% when water cut reached 95% after water flooding. The retention ratio of polymer viscosity was kept 55.3% at the outlet, but IFT was only 2 mN/m within the 3/10 injector–producer spacing during SP injection. Although subsequent water flooding could result in surfactant desorption and the IFT became 10?2?mN/m within the 3/10 injector–producer spacing, the IFT turned to 2?mN/m at the half of the model. The enhanced displacement efficiency by reducing IFT only worked within three-tenth location of the model in the high permeability layer, while the enlarged swept volume contributed much in the other areas. 相似文献
9.
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
10.
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
12.
Low-tension gas (LTG) flooding is a promising chemical enhanced oil recovery technique in tight sandstone and carbonate reservoirs where polymer may not be used because of plugging and degradation issues. This process has been the subject of many experimental studies. However, theoretical investigation of the LTG process is scarce in the literature. Hence, in this study, we lay out a displacement theory for LTG flooding, with a constant mobility reduction factor, which lays the groundwork for further theoretical studies. The proposed model is based on the three-phase flow of water, oil, and gas in the presence of a water-soluble surfactant component. Under the developed model, we study the effect of MRF and oil viscosity on the flow dynamics and oil recovery. Moreover, we explain experimental observations on early gas breakthrough that occurs during LTG core floods even in the presence of a stable foam drive. 相似文献
13.
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
14.
Enhanced oil recovery (EOR) by alkaline flooding for conventional oils has been extensively studied. For heavy oils, investigations are very limited due to the unfavorable mobility ratio between the water and oil phases. In this study, the displacement mechanisms of alkaline flooding for heavy oil EOR are investigated by conducting flood tests in a micromodel. Two different displacement mechanisms are observed for enhancing heavy oil recovery. One is in situ water-in-oil (W/O) emulsion formation and partial wettability alteration. The W/O emulsion formed during the injection of alkaline solution plugs high permeability water channels, and pore walls are altered to become partially oil-wetted, leading to an improvement in sweep efficiency and high tertiary oil recovery. The other mechanism is the formation of an oil-in-water (O/W) emulsion. Heavy oil is dispersed into the water phase by injecting an alkaline solution containing a very dilute surfactant. The oil is then entrained in the water phase and flows out of the model with the water phase. 相似文献
15.
Sequestration of carbon dioxide in geological formations is an alternative way of managing extra carbon. Although there are
a number of mathematical modeling studies related to this subject, experimental studies are limited and most studies focus
on injection into sandstone reservoirs as opposed to carbonate ones. This study describes a fully coupled geochemical compositional
equation-of-state compositional simulator (STARS) for the simulation of CO 2 storage in saline aquifers. STARS models physical phenomena including (1) thermodynamics of sub- and supercritical CO 2, and PVT properties of mixtures of CO 2 with other fluids, including (saline) water; (2) fluid mechanics of single and multiphase flow when CO 2 is injected into aquifers; (3) coupled hydrochemical effects due to interactions between CO 2, reservoir fluids, and primary mineral assemblages; and (4) coupled hydromechanical effects, such as porosity and permeability
change due to the aforementioned blocking of pores by carbonate particles and increased fluid pressures from CO 2 injection. Matching computerized tomography monitored laboratory experiments showed the uses of the simulation model. In
the simulations dissolution and deposition of calcite as well as adsorption of CO 2 that showed the migration of CO 2 and the dissociation of CO 2 into HCO 3 and its subsequent conversion into carbonate minerals were considered. It was observed that solubility and hydrodynamic storage
of CO 2 is larger compared to mineral trapping. 相似文献
16.
The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control. 相似文献
17.
We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms
during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under
conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate
that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG
injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the
main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by
a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the
oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible
SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection.
Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows
that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil
recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous
and high-rate gas injection is not possible (e.g. due to supply constraint). 相似文献
18.
Exact and approximate solutions to vertical diffusion in gravity-stable, ideal gas mixtures in gas reservoirs, depleted oil reservoirs, or drained aquifers are presented, and characteristic times of diffusion are obtained. Our solutions also can be used to test numerical simulators that model diffusion after gas injection. First, we consider isothermal, countercurrent vertical diffusion of carbon dioxide and methane in a horizontally homogeneous reservoir. Initially, the bottom part of the reservoir, with no flow boundaries at the top and bottom, is filled with CO 2 and the upper part with CH 4. At time equal zero, the two gases begin to diffuse. We obtain the exact solution to the initial and boundary-value problem using Fourier series method. For the same problem, we also obtain an approximate solution using the integrated mass balance method. The latter solution has a particularly simple structure, provides a good approximation and retains the important features of the exact solution. Its simplicity allows one to perform calculations that are difficult and non-transparent with the Fourier series method. It also can be used to test numerical algorithms. Furthermore, we consider diffusion of CO 2 with partitioning into connate water. We show that at reservoir pressures the CO 2 retardation by water cannot be neglected. The diffusion-retardation problem is modelled by a non-linear diffusion equation whose self-similar solution is obtained. Finally, we obtain a self-similar solution to a nonlinear diffusion problem. This solution is a good approximation at early times, before the diffusing gases reach considerable concentrations at the top and bottom boundaries of the reservoir. 相似文献
19.
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
20.
在非均质油藏模型上进行非牛顿流体流动物理模拟实验,对比研究水驱、聚合物驱和交联聚合物对提高石油采收率的影响.通过布置高精度的压差传感器测量不同驱替过程模型中的渗流压力场的动态变化,成胶后的交联聚合物封堵了高渗条区,改变了油藏内流体流动方向,驱替出低渗区内油,提高了采收率. 相似文献
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