Injected Pore Volume Research Articles

Effects of Pore Geometry on Flowing Foam Dynamics in 3D-Printed Porous Media

Foam flow in porous media is important in several environmental and industrial applications including soil remediation and enhanced oil recovery. The behaviour of foam is greatly influenced by transport properties of porous media, properties of foam and the fluid residing in porous media. We conducted a series of experiments to investigate the effects of pore geometry on foam flow in porous media and its implications for hydrocarbon displacement. We fabricated four porous media with well-defined pore throat size distributions, permeability and angularity by means of 3D printing technology. The models were initially saturated with oil. Gas and surfactant solution were subsequently injected into the model simultaneously for in situ generation of foam to displace the oil. Displacement dynamics were recorded using an automated imaging setup. Analysis of the pore-scale images revealed that the injected pore volumes required for the initiation of foam generation decreased as the pore size of porous media increased, presumably due to the lower entry capillary pressure. For the same pore throat size range, changes in the permeability due to increased number of pore throats did not appear to have a significant influence on the overall recovery of oil. Our results illustrate the impact of grain angularity on foam generation owing to its influence on the pore-to-throat aspect ratio and capillary pressure gradient.

Co2 geological storage coupled with water alternating gas for enhanced oil recovery

Due to the climate change and global warming, the concern about CO2 emission into the atmosphere has been raised in many industries such as oil and gas business. The sources of CO2 include natural gas processing and other processes. The current technology to mitigate CO2 is carbon capture, storage and utilisation. At the same time, oil production is expected to increase due to the higher consumption. CO2 geological storage in depleting oilfield coupled with enhanced oil recovery can be a better technology to meet both requirements. The excellent example of this technology is the Weyburn Project in Canada that can store CO2 and produce more oil as well as prolong the reservoir life. From this successful project, the technology is studied by applying it with the depleting oilfield for both oil production and CO2 storage in the North of Thailand by using simulation model. It becomes the objective of this research, which is to evaluate CO2 geological storage coupled with water alternating gas (WAG) for enhanced oil recovery as well as to study the effects the parameters, such as total hydrocarbon pore volume (HCPV) injection and WAG ratio, on oil production and CO2 consumption and sequestration for enhanced oil recovery, with the added benefit of carbon sequestration. CMG software from Computer Modeling Group Ltd. is used to create the 3D simulation model to predict the CO2 storage in the geological formation. From the simulation, the results reported that oil can be produced up to 125,976 m3 of oil or 57 % recovery, CO2 consumption is 66,261 m3 of gas and CO2 utilisation is approximately 0.53 m3 of gas per m3 of oil. The main parameters for WAG process is WAG ratio in that oil production increases as WAG ratio increases. CO2 consumption increases with total HCPV injection. The results of this study can be applied to develop the CO2 enhanced oil recovery (EOR) in the depleting oilfield in the North of Thailand for both oil production and CO2 storage.

Application of modified Dykstra-Parsons method to natural bottom-water drive in non-communicating fractured-vuggy reservoir

Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically.

Prognosis for Safe Water-Disposal-Well Operations and Practices That Are Based on Reservoir Flow Modeling and Real-Time Performance Analysis

Summary Oklahoma has been at center stage of induced seismicity. Water-disposal activities have been associated with triggering the increasing number of seismic events. The objective of the study is to provide a simple diagnostics method and procedure for safe water-disposal operations. A comprehensive suite of scenarios and parameters has been analyzed that affect water disposal. On the basis of this study, prognosis will lead to safe water-disposal operation without the adverse effect. A suite of reservoir models involving water injection helped understand disposal-well performance. The well operational limits correspond to disposal-zone fracture gradient. The modified Hall analysis is used to ascertain the point of departure from normal injection behavior. Limiting cumulative injected volumes are determined and investigated for various scenarios from simple to increasingly complex subsurface conditions. This investigation includes studying the effects of disposal-zone porosity, compartment size, conductivity, formation compressibility, heterogeneity, and natural fractures. In addition, we explored the effects of communication with overlying producing zone, communication through completion anomaly, seal integrity, and fluid complexities. This study illuminates an overall understanding of disposal-well performance through various scenario analyses. A relationship between disposal-zone fracture gradient and limiting cumulative injection volume is established. For a fracture gradient of 0.7 psi/ft, this limiting pore-volume (PV) injection is less than 2%, which corresponds well with the conventional wisdom learned from carbon dioxide (CO2) injection-well performance. The relationship of disposal-zone compartment size, established with rate-transient analysis (RTA), with limiting cumulative injection volume is formulated. Analyses from the various statistical design of experiments (DoEs) reveal the important variables that may affect disposal-well performance. The disposal-well operation can be devised in real time with the modified Hall analysis that can reveal the departure from normal injection-well behavior. Factors accentuating the departure from normal behavior include disposal-zone porosity, formation compressibility, and seal integrity. Situations in which pressure release through leaks or communication with an adjacent formation takes place will naturally accommodate a larger volume of disposal water. Also, we learned that limiting cumulative injection volume and not injection rate (assuming injection pressure gradient is less than the fracture gradient) triggers a departure from normal injection behavior. Using a suite of numerical reservoir models and the reservoir-monitoring tools involving modified. Hall analysis and RTA led to a comprehensive understanding of disposal-well performance. This study found a relationship of fracture gradient with limiting cumulative injection volume, and identified key variables affecting the disposal-well behavior. These findings led to a smart and safe disposal-well monitoring scheme, which will help disposal-well management become more economical and environmentally friendly.

Dependence of wettability on brine composition in high temperature carbonate rocks

Laboratory experiments and small-scale field tests have shown that injection of low salinity brine can improve oil recovery from carbonate rocks. Contact angle studies, spontaneous imbibition and core flood experiments indicate that wettability alteration is responsible for this process. In this study, the core-scale manifestation of wettability mechanisms is evaluated, and a geochemical model is developed for further insight into reaction pathways. Brines of different compositions were injected into carbonate cores with no oil and the effluent was analyzed for ionic composition. Seawater, sulfate-rich seawater, and dilutions of seawater were tested. A mechanistic model was developed using our in-house reservoir simulator UTCHEM-IPHREEQC for the wettability alteration process. The model changes core wettability according to the adsorbed naphthenic acid concentration on the rock surface, which is controlled by the brine composition. The model was used to match previously published two-phase flow experiments. The single-phase core floods with test brines indicate retention of SO42− within the core. Calcite dissolution is prominent in ultra-dilute seawater injection. The relative permeability parameters for oil-wet and water-wet conditions were different, but the same for all the core floods. Model results were in good agreement with single-phase core floods and oil recovery experiments. Sulfate adsorption and calcium dissolution led to naphthenic acid desorption which in turn altered core wettability. Single-phase core floods reached equilibrium within 2 pore volumes (PV) of injection. Two-phase core floods with seawater and sulfate enriched seawater took longer to reach equilibrium, only after 3–4 PV. Oil-displacing ultra-dilute brine injection experiments did not reach equilibrium in 5 PV, particularly the Ca2+ ions, due to slow calcite dissolution.

Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 °C in high salinity brine

Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)15N+(CH3)2CH2COO−), stabilizes viscous C/W foam (>15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 °C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 °C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from ∼37 mN/m to <5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (∼134 Å2/molecule), resulting in generation of viscous foam (∼6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s−1) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m2, and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (>20 cP) within 6 pore volumes of injection at 120 °C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.

Porous media acidizing simulation: New two-phase two-scale continuum modeling approach

In Recent years some experimental studies have been conducted to investigate the effects of presence of a non-aqueous phase during carbonate acidizing process. Narrower and longer wormholes were observed to be formed when acid is injected into an oil-saturated porous medium, instead of a water-saturated one; which can provide breakthrough earlier with less injected pore volume. However, the mechanisms responsible for these observations had not been comprehensively studied. In this research, a two-phase two-scale continuum (TPTSC) model for simulation of dissolution process during acid injection into carbonate rocks is presented. This model couples two-phase fluid flow equations in porous media and the previously developed two-scale continuum (TSC) model equations for carbonate acidizing. A synthetic case is simulated and the effect of the restricted flow due to various relative permeability values, viscous fingering effects on injected pore volumes to breakthrough; and dissolution patterns are investigated. Our simulation results demonstrate positive effects of two-phase flow and viscous fingering on formation of narrower and longer wormholes. It is observed that pore volumes to breakthrough for an initially high viscosity oil-saturated core is significantly less than pore volumes to breakthrough for an initially water-saturated core. Flow restriction around wormhole due to less relative permeability values and viscous fingering phenomenon can be responsible for gaining lower injected acid volumes to breakthrough. Thus, especially for high viscosity oil reservoir conditions, direct injection of acid to an oil-saturated medium, instead of injecting a pre-flush to push back the saturating oil, can be beneficial.

Comparison of huff-n-puff gas injection and solvent injection in large-scale shale gas condensate reservoirs

A compositional simulation approach is utilized to compare huff-n-puff gas and solvent injection in a shale gas condensate reservoir. Each injection process is analyzed in terms of the least cost, shortest payback period, smallest injected pore volume and maximized recovery of the condensate components.Two gases (methane and ethane) and two solvents (methanol and isopropanol) are chosen for the comparison. The reservoir model is calibrated based on available published rock and fluid properties, and history matching is carried out with production data. The model consists of heterogeneities representative of a shale reservoir such as a stimulated rock volume (SRV) and a non-stimulated rock volume (NSRV) that is intersected by a network of natural fractures.The reference model is used to understand and establish the basic recovery mechanisms of the four injection fluids while highlighting the principal differences between them. The effects of injection pressure, initial reservoir pressure, injection and production time, the gas-condensate composition and nanopore confinement are evaluated. Analysis of the performances of the four injection fluids are based on the total hydrocarbon recovery factors, combining the liquid and gas phases, calculated within the same operation time.Results demonstrate ethane to be a superior injection fluid with a high recovery factor for most scenarios, accompanied by a relatively higher profit to investment ratio and shorter payback period. Ethane injection recovers the heavy condensate components more efficiently compared to methane and solvent injection for a given gas condensate composition. This advantage is complemented by ethane's capability to equally recover all of other hydrocarbon components from the reservoir. The recovery performance of solvent huff-n-puff for a leaner gas condensate fluid is significantly greater than that for the richer gas-condensate reservoir fluid. The main difference in the optimization of gas and solvent performance is highlighted. Gases require longer injection and production time, whereas solvents perform better with shorter injection time and longer production time.

Pore-scale remaining oil distribution under different pore volume water injection based on CT technology

A water-injection experiment was performed on a water-wet reservoir core plug that was filled with brine first and then displaced by synthetic oil. A X-ray Computed Tomography was used to take snapshots of the process of oil-water displacement at predefined time intervals to characterize the distribution of remaining oil. The quasi-real time images were used to understand the pore-scale phase displacement mechanisms and the distributional pattern of the remaining oil. Four forms of the distributional patterns, i.e. network, porous, isolated and film shape, were observed and analyzed with respect to the injected pore volumes (PV). The results show that with the increased level of water injection, the volume of the oil phase continuously decreases, and the morphology of the oil phase changes from initial continuous network-like to film shape forms. At 15 PV, the network- like remaining oil disappears and transforms into isolated and film-like forms. The statistics of the volume for each form of the remaining oil show that the isolated blobs increase with increasing water injection, by contrast, the average volume of the remaining oil decreases with increasing water injection. The rate of volumetric changes is fast before 5 PV but slow in the later period. Cited as : Liu, Z., Yang, Y., Yao, J., et al. Pore-scale remaining oil distribution under different pore volume water injection based on CT technology. Advances in Geo-Energy Research, 2017, 1(3): 171-181, doi: 10.26804/ager.2017.03.04

A Study on the Matching Relationship of Polymer Molecular Weight and Reservoir Permeability in ASP Flooding for Duanxi Reservoirs in Daqing Oil Field

In order to determine the matching relationship of polymer molecular weight and reservoir permeability in ASP (alkaline/surfactant/polymer) flooding, a number of core flooding experiments with different polymer molecular weights are performed. Two types of curves for the relationship between the pressure difference and the injection pore volume multiples are obtained. One describes the characteristics of the core plugging; the other describes the characteristics of the injection well. The relationship between the polymer molecular cyclotron radius and the pore throat radius used to describe the relationship between the polymer molecular weight and the core permeability. The results indicate that when the ratio of the pore throat radius (rh) to the polymer molecular cyclotron radius (rp) is greater than 7, the injection of ASP system with a variety of molecular weights will not be blocked; on contrary, when the ratio is less than 7, the core will be blocked. The range of water permeability of the core is determined by the value of the polymer molecular weight. The ratio between the pore throat radius (rh) to the polymer molecular cyclotron radius (rp) for the ASP system is greater than that of polymer system (rh/rp = 5). A scanning electron microscope (SEM) is used to compare the morphology of polymer molecules in polymer solution and ASP solution, and shows that the dimension of polymer molecular coils in ASP solution is smaller than that in polymer solution, which is caused by the double effect of alkali and surfactant.

The Effect of Water Flushing on CO2 Concentration Around Injection Well as Identified through Laboratory Study

A clear understanding of dynamic water flushing on laboratory scale is useful for the effectiveness and safety of CO2 geological storage. The objective of this study was to investigate the effect of water flushing on CO2 concentration including displacement and the dissolution. The high-resolution Magnetic Resonance Imaging (MRI) technique was used to visualize the process. The core sample was packed with glass beads under the temperature and pressure of 40 and 8 MPa, corroding to the depth of 800 m. The CO2 unsaturated brine was injected upward into the supercritical CO2 saturated sample with flow rate of 0.03 mL /min, to imitate the water flushing. The transient intensity in MRI image during the water flushing was observed, reflecting the transition from displacement to dissolution in the porous media. The concentration distribution along the porous media was inhomogeneous. The CO2 concentration declined along the porous media with injected pore volume.

Improving Oil Recovery Using Miscible Selective Simultaneous Water Alternating Gas (MSSWAG) Injection in One of the Iranian Reservoirs

In the current investigation, feasibility study has been done for miscible selective simultaneous water alternating gas (MSSWAG) injection compared with immiscible and miscible water alternating gas (IWAG and MWAG) injection in one of the Iranian reservoirs which has been subject to water flooding for several years and the recovery factor (RF) for water flooding is about 23% of the original oil in place. Through IWAG injection, the effect of gas types comprising lean and rich has been investigated which led to increase the recovery factor to 29% for rich and 28% for lean gas. Moreover, miscible injection results show that the recovery factor for rich MWAG with optimized injection pore volume led to 41.74% which shows 12% greater values than the value for immiscible one. Also, sensitivity analysis represents that under rich MWAG injection with 1:2 WAG ratio and 100-day injection period, recovery factor has improved by 7% and reached 48.55%. In continuation to the study with emphasis on the advantages of miscibility, rich MSSWAG with RF: 54.73% has led to increase the recovery factor by 6% compared to rich MWAG with RF: 48.55% (being the best scenario in this study based on simulation results). Finally, considering the economic aspects, the net present value for rich MWAG and rich MSSWAG is significantly increased by approximately average 31% relative to water flooding.

Investigation of Low-Density CO2 Injection for Enhanced Oil Recovery

The density of the CO2-rich phase in a reservoir would play a crucial role in the performance of an enahcned oil recovery (EOR) scheme. Many oil reservoirs are located in deep formations; hence, they have high temperatures. Moreover, the pressure of reservoirs decreases because of natural depletion. Under the conditions of those reservoirs, CO2 would be a low-density gas. A series of coreflood experiments were performed to evaluate the potential of low-density CO2 EOR. The experiments are intermittent CO2 injection, continuous tertiary and secondary CO2 injection, and water alternating CO2 injection followed by the coinjection of a surfactant and CO2. The same oil and gas were mixed to prepare live oil for all the experiments. The initial rate of oil recovery during secondary waterflood was high, but the efficiency of the process decreased after the breakthrough. Three pore volumes (PVs) of secondary CO2 injection resulted in the recovery of around 50% of the initial oil in place, which was 27% higher tha...

Fracture-Cross-Flow Equilibrium in Compositional Two-Phase Reservoir Simulation

Summary Compositional two-phase flow in fractured media has wide applications, including carbon dioxide (CO2) injection in the subsurface for improved oil recovery and for CO2 sequestration. In a recent work, we used the fracture-crossflow-equilibrium (FCFE) approach in single-phase compressible flow to simulate fractured reservoirs. In this work, we apply the same concept in compositional two-phase flow and show that we can compute all details of two-phase flow in fractured media with a central-processing-unit (CPU) time comparable with that of homogeneous media. Such a high computational efficiency is dependent on the concept of FCFE, and the implicit solution of the transport equations in the fractures to avoid the Courant-Freidricks-Levy (CFL) condition in the small fracture elements. The implicit solution of two-phase compositional flow in fractures has some challenges that do not appear in single-phase flow. The complexities arise from the upstreaming of the derivatives of the molar concentration of component i in phase α(cα,i) with respect to the total molar concentration (ci) when several fractures intersect at one interface. In addition, because of gravity, countercurrent flow may develop, which adds complexity when using the FCFE concept. We overcome these complexities by providing an upstreaming technique at the fracture/fracture interface and the matrix/fracture interface. We calculate various derivatives at constant volume V and temperature T by performing flash calculations in the fracture elements and the matrix domain to capture the discontinuity at the matrix/fracture interface. We demonstrate in various examples the efficiency and accuracy of the proposed algorithm in problems of various degrees of complexity in eight-component mixtures. In one example with 4,300 elements (1,100 fracture elements), the CPU time to 1 pore volume injection (PVI) is approximately 3 hours. Without the fractures, the CPU time is 2 hours and 28 minutes. In another example with 7,200 elements (1,200 fracture elements), the CPU time is 4 hours and 8 minutes; without fractures in homogeneous media, the CPU time is 2 hours and 53 minutes.

Evaluation and Optimization Study on a Hybrid EOR Technique Named as Chemical-Alternating-Foam Floods

This work presents a novel Enhanced Oil Recovery (EOR) method called Chemical-Alternating-Foam (CAF) floods in order to overcome the drawbacks of the conventional foam flooding such as insufficient amount of in-situ foams, severe foam collapse and surfactant retention. The first part of this research focused on the comparison of conventional foam floods and CAF floods both of which had the same amount of gas and chemicals. It showed that: (1) CAF floods possessed the much greater Residual Resistance Factor (RRF) at elevated temperature; (2) the accumulative oil recovery of the CAF floods was 10%-15% higher than that of the conventional foam flooding. After 1.8 Pore Volume (PV) injection, the oil recovery reached the plateau for both methods; (3) CAF floods yielded the most amount of incremental oil at the 98% water cut (water content in the effluent), while the continuous foam floods achieved the best performance at 60% water cut. The second part of this work determined the optimal foam quality (gas/liquid ratio or the volume percent gas within foam), chemical/foam slug size ratio, cycle number and injection sequence for the CAF floods. It was found that the CAF was endowed with the peak performance if the foam quality, chemical/foam slug size ratio, cycle number was fixed at 80%, 1:1 and 3 respectively with the chemical slug being introduced ahead of the foam slug. Through systematic and thorough research, the proposed hybrid process has been approved to be a viable and effective method significantly strengthening the conventional foam flooding.

Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields.

Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work ( Al-Menhali and Krevor Environ. Sci. Technol. 2016 , 50 , 2727 - 2734 ) , it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.

Experimental investigation of tertiary CO2 injection for enhanced heavy oil recovery

The recovery efficiency of primary production for heavy oil reservoirs is generally poor meaning that significant quantities of oil still remain in place. Waterflood has been, and continues to be, the first intervention method for oil recovery in many oil reservoirs. However, heavy oil is considerably more viscous than water and hence, a significant fraction of the oil is bypassed by waterflood. In this study, we present the results of two coreflood experiments which have been performed under reservoir conditions to investigate the potential of tertiary CO2 injection for heavy oil recovery. In addition, the mechanisms involved in this process and their impacts on the efficiency of oil recovery are identified and discussed. The same crude oil and gas were used to prepare live oil for both experiments. Despite the difference in the viscosity of oil samples, secondary waterflood showed relatively similar behavior in both experiments and 22% and 24% of the initial oil were recovered after 2 and 1.1 pore volumes (PVs) of water injection in the first and second experiments, respectively. The oil production results show that tertiary CO2 injection recovered 23% of the remaining oil after 6 PVs of injection in the first experiment and after 3 PVs of injection in the second experiment. Another waterflood followed the tertiary CO2 injection which recovered 14% of the remaining oil in both experiments.The main mechanisms contributing to oil recovery by CO2 injection are the oil viscosity reduction by CO2 dissolution, the liberation of methane from oil, oil swelling, and the extraction of hydrocarbons by CO2. The results imply that viscous fingering dominates the flow of water or CO2 for heavy oil recovery. The compositional analysis of the core effluent shows that tertiary injection of CO2 alters the physical properties of heavy oil in the core and a higher quality oil (e.g. lower density and viscosity) than the original oil in place is recovered by CO2 injection. It is also discussed that CO2 can diffuse into the oil surrounded by water. The transport of CO2 into the oil results in the oil being saturated and this leads to the nucleation of a CO2−rich phase among the trapped oil ganglia. By continuing CO2 injection, the nucleated CO2−rich phase grows further and causes oil swelling by the extraction of light and intermediate components of the oil.

Slow migration of detached fine particles over rock surface in porous media

Fines migration involving particle detachment in natural reservoirs usually exhibits significant permeability damage. This occurs due to mobilization and migration of detached colloidal or suspended fines that were strained in thin pore throats. Numerous laboratory coreflood tests show that the time for permeability stabilization accounts for hundreds of injected pore volumes. However, classical filtration theory assumes that the released fines are transported by the bulk of the carrier fluid, thus stabilizing the permeability after the injection of one pore volume. The current paper attributes the stabilization delay to the slow drift of the mobilized fines near the pore walls. We propose basic flow equations for single-phase particle transport in porous media with velocity lower than the carrier fluid velocity. We derive an analytical model for one dimensional flow with particle release and straining under piecewise-constant increasing velocity. The laboratory data are in high agreement with the results of mathematical modelling. The effective particle speed is 500–1000 times lower than the water velocity.

Analysis and simulation of rheological behavior and diverting mechanism of In Situ Self-Diverting acid

SDVA acid is one kind of In Situ Self-Diverting acid fluids that are widely used for diverting acid into a low-permeability zone in carbonate reservoir treatment, thus stimulating the production of the heterogeneous reservoir effectively. However, the rheological behavior and diverting mechanism of In Situ Self-Diverting acid (SDVA acid) is so complicated that no models reported can perfectly simulate the acidizing process of SDVA acid, especially in radial flow. In this paper, we study the factors influencing rheological behavior such as pH value, calcium ion concentration and SDVA concentration. An empirical rheological model is developed to describe the relationship between the apparent viscosity of SDVA acid and the coefficient of pH, calcium ion and SDVA. Based on the two-scale continuum models, a numerical model is developed to describe reaction, transportation and diversion of SDVA acid in carbonate rocks for linear flow and radial flow. From the simulation results, the gel region is observed around the wormholes and branches, and this high-resistance region limits the propagation of wormholes more seriously in the radial direction compared to the length direction of linear core. When the acidizing is performed in a single linear core or in a single radial core, the injection pressure drop decreases monotonically versus the injected pore volume of HCl acid. But when SDVA acid is injected, the pressure drop increases initially and decreases afterward. The pressure drop curves from simulations are consistent with experimental results. Finally, we analyze the diversion results in parallel core set-up with different permeability, where the wormhole propagates much longer in the low-permeability core when SDVA acid is injected compared to HCl acid systems and wormhole breaks in high-permeability core firstly no matter which acid systems are used. The curves of diversion flow rate in the parallel core simulation further confirms that the diverting mechanism is simulated successfully for SDVA acid by models developed in this paper.

Characterization of pore volume of cumulative water injection distribution

Abstract Pore volume of Cumulative water injection is one of the factors for evaluating water flood effect in a water flood oil field. In previous study, there were limited lab studies for evaluating oil displacement efficiency. A method to characterize the distribution of pore volume of cumulative water injection is proposed in this paper, and it is verified by a five-spot water flooding streamline simulation model. The logarithmic relation between pore volume of cumulative water injection and water saturation is established by regression. An inflection point and limit point of cumulative water injection pore volume are identified. Current simulation model indicates inflection point appears after 2–5 pore volume (PV) injection, and limit point appears after 15–25 PV injection. Both inflection and limit point vary in different regions of reservoir.