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Abstract Gas storage and movement in porous media can give valuable insight into the gas accumulation at the macroscopic. Until now, there are few research reports on how the injection pressure affects the gas storage in tight sandstone reservoir at microscopic scale. We choose a Bashijiqike tight sandstone core to conduct a series of pore-scale simulations of gas storage for a sequence of increasing injection pressure, and with the aid of micro-CT techniques, distributions of fluid phases, characteristics of gas clusters, and change laws of gas storage have been studied. Results show that after gas injection pressure improved, there is an obvious rise in the gas saturation, at the same time, for gas clusters, the quantity and volume are growing, the shapes deviate a significant degree from sphere, and the connectivities are getting better. Three different occupation patterns of gas clusters have been identified-new birth, augment and connection, which can occur separately or together in the process of gas displacing aqueous. In the rapid injection process (RIP) gas clusters are more likely to be discontinuous droplets trapped by snap-off, while in the slow injection process (SIP) gas clusters tend to be continuous phase. The shapes and connectivities of small and large gas clusters are controlled by the pore structure characteristics of small and large pores, respectively, which have different fractals. Even the proportion of small gas clusters is overwhelming, the acquisition of gas saturation is attributed to the large gas clusters with a small quantity. Again, because the volume of gas cluster is limited to pore volume, so the gas storage capacity of tight sandstone reservoir is depending on the large connected-pore, linked by passable throat (reflection of injection pressure), but it has nothing to do with the dispersed small pores. These results have important implications for further effective exploitation of tight sandstone reservoirs. Graphical abstract Image 1 Highlights • Increasing gas injection pressure led to raise in quantities and volumes of gas clusters. • Three different gas occupation patterns occur separately or together. • Most RIP gas clusters are dispersed spherical droplets, while the SIP gas clusters are much more continuous. • Shapes and connectivities of gas clusters are controlled by the pore structure characteristics. • Gas storage capacity of tight sandstone reservoir depends on the large connected-poreslinked by passable throat. [ABSTRACT FROM AUTHOR]

Abstract Geological storage of Carbon Dioxide (CO 2) can safely and permanently store a huge amount of anthropogenic greenhouse gases. However, the possible leakage of mobile gases through the cap rock that confines them within the reservoir is a cause of safety concerns. Residual and solubility trapping of the injected gas in the pores of the rock can reduce the amount of mobile gas lying below the cap rock. These trapping mechanisms will only begin at the end of several decades of gas injection, which implies that there is an imminent risk of discharge of large amount of gas in the event of a leak. This paper presents a method to fast-track and enhance residual and solubility trapping process while gas injection is in progress, such that only a fraction of the injected gas will migrate and be trapped beneath the cap rock after injection ceases. The method involves cyclic injection of gas and water (containing small amount of foaming agent). Foams are known to have gas trapping characteristics during flow in porous medium. A series of laboratory experiments was conducted on representative rock samples at different reservoir conditions. The results show a sequential and cumulative growth in trapped gas during cyclic injection of gas and foam based on in-situ and real time measurements of gas saturation in the samples using electrical resistivity tool. The amount of trapped (residual) gas depends on the type of gas (N 2 or CO 2), water salinity, concentration of the foaming agent, and temperature. The highest residual gas saturations (50%–70% of reservoir pore volume) occurred at a temperature and water salinity typical of a deep saline aquifer (45 °C and 58,000 ppm water). At a high water salinity of 242,000 ppm, the residual gas saturation was significantly lower (27%–30%). Similarly, at a high temperature of 90 °C, the residual gas saturation reduced to 27%. Residual gas could not be sustained when CO 2 is injected compared to N 2 because of the low interfacial tension between CO 2 and water, which reduces the foam quantity and strength. The importance of foam stabilizing agents (e.g. polymers and nanoparticles) in addressing the observed shortcomings in CO 2 foam and for foam injection in high salinity - high temperature reservoirs is discussed. A field scale application of this method is also highlighted. Highlights • Foam increased residual gas saturation up to 70% of rock pore volume. • Cyclic foam injection fast tracks residual and solubility trapping mechanism. • CO 2 foam requires foam stabilizer for effective trapping of gas. • An optimum concentration of a foaming agent required for optimum residual gas. • Salinity and temperature affect capillary gas trapping by foam. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Debrining is one of the key steps to complete the construction of a salt cavern gas storage, which determines whether the cavern can transfer to underground gas storage (UGS) and the effective volume of a salt cavern UGS. A mathematical model is proposed based on the change characteristic of the dynamic depth of the interface between gas and brine and the pressure equilibrium principle to predict the parameters of the debrining. The calculating equations of debrining parameters, such as, total debrining time, gas injection pressure, gas injection volume per day, and cumulative gas injection volume, are deduced. A calculating program is developed based on the deduced equations by using Visual Basic computer language. To verify the proposed mathematical model, MZ-1 cavern of Jintan salt district, Jiangsu province, China, is simulated as an example. Based on the calculating results, the debrining parameters of MZ-1 cavern are optimized. These parameters were used in the debrining of MZ-1 cavern. By comparing the analytical results with field monitoring data, the proposed mathematical model is shown to have a high accuracy. The error between the predicting results and the field monitoring data is less than 5%, which can satisfy the requirement of actual debrining prediction. Research results can provide the parameter optimization and prediction for the debrining of salt caverns used for gas storage in Jintan salt district and some other places with similar conditions. [ABSTRACT FROM AUTHOR]

Capillary trapping plays an important role in the geological storage of Carbon dioxide (CO 2 ) because of its ability to immobilize a significant fraction of the injected gas. Numerous papers have investigated various factors that affect capillary trapping. Recently, gas-mobility control methods are being investigated through simulation studies, for improving capillary trapping of CO 2 in saline aquifers. The results published so far are inconclusive and sometimes conflicting. In this study, a series of laboratory experiments was conducted to investigate and compare the effects of two mobility control methods namely, water alternating gas (WAG) and surfactant alternating gas (SAG), on gas sequestration efficiency. Efficiency was measured by injectivity and residual trapping capacity. The two methods were tested in both vertical and horizontal flow directions using rock samples of varying lithology and permeability. The different gas injection schemes were compared with the continuous gas injection method. WAG method consistently reduced residual gas saturations in all the experiments while SAG method significantly increased residual gas saturation for both horizontal and vertical flows. Comparison of performance of SAG method in horizontal flow with its performance in vertical flow revealed a significant increase in residual gas saturation when applied in vertical flow direction. However, SAG method resulted in decreasing injectivity as the SAG cycles increase while WAG injectivity remained unaffected throughout its cycles except in tight samples. Furthermore, higher residual gas saturations were observed in high permeability rocks compared to tight rocks when subjected to vertical-SAG sequestration method. The possible reasons for such efficiency in the vertical-SAG method are discussed in detail. [ABSTRACT FROM AUTHOR]

Multi-scale fractures and karst caves are the main reservoir bodies in fractured-vuggy carbonate reservoirs, and there are still various types of remaining oil after water flooding. Oilfield development practices demonstrate that the method of N 2 injection can enhance oil recovery effectively. However, the development effect of a single well with gas injection is highly different, and the mechanism and influencing factors of gas injection for enhanced oil recovery are not clear. To reveal the mechanism and influencing factors of enhanced oil recovery through physical experiments and numerical simulation, we have produced a series of physical models of fracture and cave combinations based on the characteristics of this type of reservoir, established a visual physical simulation experimental apparatus and process, and analyzed the main factors affecting the production efficiency of gas injection wells in combination with the actual development of oilfields. The research results demonstrate that the primary types of remaining oil after water flooding in fractured-vuggy carbonate reservoirs are oil at the top of karst caves, oil shielded from high flow channels and oil not swept by the wells. The mechanism of gas injection-enhanced oil recovery is primarily composed of three aspects. First, the injected gas forms a secondary gas cap because of the effect of gravitational differentiation, and the gas cap can displace the remaining oil on top of the karst cave that the injected water cannot drive; Then, injected gas can change the pressure field distribution and the direction of fluid flow after water injection, driving the remaining oil that is shielded by high flow diversion channels; in addition, the injected gas has a certain effect on the reservoir energy supply. The geological conditions, such as the remaining reserves of injecting gas wells, filling level, well-reservoir position relationship and bottom water energy, have great influence on the development effect. The starting time of gas injection has an optimal point, and injecting too early or late will affect the oil recovery. The cyclic gas injection quantity and gas injection velocity are the primary injection production parameters that influence the production effect of a gas injection well. Finally, the principle of selecting a well for gas injection according to the research results is discussed, which can provide reference for selecting gas injection wells and injection methods of fractured-vuggy reservoirs in Tahe Oilfield. [ABSTRACT FROM AUTHOR]

In this paper, the potential to enhance oil recovery (EOR) by CH 4 gas injection in shale reservoirs is investigated through numerical analysis based on the experiments using different-diameter shale cores and crude oil. The cores used in these experiments had the same length of 2 inches and six different diameters of 1, 1.5, 2, 3, 3.5 and 4 inches. The crude oil from Wolfcamp was used to saturate the shale core plugs. A Gas Chromatography/Mass Spectrometer (GC/MS) instrument and Xcalibur software were used to analyze the crude oil components. The experiments were history-matched using numerical simulation models. The calibrated numerical models were then employed to perform a series of sensitivity studies to investigate the effects of operation parameters on oil recovery in shale oil cores, such as the number of injection cycles, molecular diffusion, soaking time, and operation schedule. The experimental results show that oil recovery factor is smaller from a larger core than that from a smaller core due to the decline of surface area per volume and the drop of pressure gradient along the diameter. The simulation results show that incremental oil recovery in each of the subsequent cycle decreases as the number of injection cycles increases. In terms of EOR mechanisms, viscous displacement and relative permeability hysteresis may be important, while molecular diffusion does not seem to play an important role after the first five cycles. For the soaking time, a larger core needs a longer soaking time to achieve the maximized oil recovery than a smaller core within a single cycle. Within a fixed elapse time, a shorter soaking time results in higher oil recovery. This work provides a fundamental understanding of the key parameters that control cyclic CH 4 injection to enhance oil recovery in shale rocks. [ABSTRACT FROM AUTHOR]

Due to the precipitous dropping oil price, air injection becomes advantageous to other gas flooding techniques as a result of the low cost. Therefore, this work targeted a light oil reservoir and comprehensively investigated the potential of air injection in this reservoir using experimental and numerical simulation, from which some new insights into high pressure air injection were recognized. Oxidation kinetics of the crude oil were first established using Thermal Gravity Analysis (TG)/Differential Thermal Gravity (DTG), and further validated through a set of history matching. The results indicate that the intense oxidation reaction consumed a great volume of oxygen forming only CO 2 . Temperature peak occurred after reacting 23 h, revealing that the oxidation reaction is an exothermic process under reservoir conditions and spontaneous combustion might take place. Reservoir dip angle is a crucial parameter governing the oil production and updip injection is generally suggested. Earlier air injection leads to more noticeable incremental temperature effect and also higher ultimate recovery. Air injection seems notably appropriate for rhythm reservoirs. Given a mature reservoir, high-permeability zone would cause gas breakthrough and thus considerably detract the air injection performance. Temperature-resistant polymer gel or foam is suggested to plug thief zones promoting oxidation reactions and air sweep efficiency. [ABSTRACT FROM AUTHOR]

The increase in U.S crude oil over the past decade have been primarily driven by tight and shale oil. With the high production decline rates in shale reservoirs, improved oil recovery techniques must be applied to maintain the oil recovery from existing wells. Gas injection has been investigated and demonstrated as the most effective solution to face such challenge. As gas can be injected into the subsurface by two modes: continuous injection (flooding) and cyclic injection (huff-n-puff), this study aims to compare the recovery efficiencies of such two processes in shale core plugs with ultra-low matrix permeability. Eagle Ford core samples were used in this study and saturated with shale oil. Using N 2 as the gas source, gas injection tests were operated on the same plug orderly by both modes under the same operating conditions. The sensitivity of soaking time on the huff-n-puff performance was evaluated. Lab-scale numerical models were built to simulate flooding and huff-n-puff processes and to history match the experimental data. It was found that optimization design of huff-n-puff is important to achieve the maximum oil recovery. The results show that the huff-n-puff possess can achieve a higher oil recovery than the flooding process. [ABSTRACT FROM AUTHOR]

Carbon dioxide is a greenhouse gas that has the most effect on the phenomenon of global warming. Saline aquifers have higher potential compared to other storage options to store carbon dioxide. Sandstone and carbonate aquifers have good reservoir characteristics and can be appropriate choices for CO 2 storage. The modeling of the process has been performed combining salt precipitation, solubility, region specification and pressure drop models to study the effect of CO 2 injection on gas saturation and pressure distribution profile, skin factor over time, the amount of salt precipitation, porosity and permeability. Sensitivity analysis has been done for temperature, pressure, permeability, porosity, salinity, critical gas saturation and CO 2 injection rate. In order to study chemical reactions, long time simulation of rock-fluid interaction in carbonate and sandstone aquifer is also performed. The permeability reduction is in the range of 0.69–0.86 in all cases of salt precipitation simulation which is consistent with experimental results. The proposed salt precipitation model with an average relative deviation of about 5% for rock-fluid interaction parameters is able to predict the aquifer properties accurately during CO 2 gas injection. The advantage of the model presented in this study compared to Zeidouni's model (2009) is that the proposed model predicts the pressure distribution after injection and estimates mole fraction of components in equilibrium with higher accuracy. The results of this study are shown that CO 2 storage needs an aquifer with lower temperature, higher pressure and lower salinity compared to other options as the solubility trapping of carbon dioxide increases in this case. Permeability change does not influence on determining equilibrium regions and the only effect of the permeability is on the injectivity. Simulation of mineral reactions shows that chemical equilibrium is established after long time (more than 100 years) in sandstone aquifer and it is established in less than one day in carbonate aquifer. It should be noted that mineral trapping capacity of carbonate aquifer is less than sandstone aquifer in the CO 2 storage process. [ABSTRACT FROM AUTHOR]

Abandonment pressure of shale gas reservoirs has been in the center of attention to evaluate the CO 2 storage in such reservoirs. However, the evaluation of abandonment pressure in shale gas reservoirs is not clearly defined. To quantitatively determine the abandonment pressure for CO 2 storage in depleted shale gas reservoirs, we introduced two effective and reasonable semi-analytical models, named pressure transient analysis (PTA) and rate transient analysis (RTA), based on a free-simulator approach. Firstly, by line source function, CO 2 seepage models for an injection well with constant injection rate or constant injection pressure were simultaneously proposed in consideration of gas adsorption, diffusion flow, stress sensitivity and non-Darcy flow effects. Then, we solved seepage models using Laplace transformation, perturbation method, superposition principle and numerical discretization method, thus obtained transient-pressure and transient-rate solutions of the injection well. Further, we compared the proposed mathematical models with existing models. Furthermore, we systematically examined the sensitivity of the parameters, thereby constraining the intrinsic uncertainty to evaluate the abandonment pressure. Finally, we applied the proposed method to study a real case from Sichuan Basin in China, thus demonstrating the promising prosperity of this new quantitative determination of abandonment pressure for CO 2 storage in depleted shale gas reservoirs. Our results showed that the maximum difference between our proposed method and numerical method was lower than 5%, suggesting a good agreement between the two methods. Moreover, our results also showed that free-simulator approach gave much faster calculation speed compared to numerical method. As a result, we provided a framework for the quantitative determination of abandonment pressure, by coupling pressure transient analysis (PTA) and rate transient analysis (RTA) during CO 2 injection at constant injection pressure and injection rate. Moreover, our results also showed that the abandonment pressure has power law relationship with the injection pressure using PTA method, and the abandonment pressure has logarithm relationship with CO 2 injection volume using RTA method. [ABSTRACT FROM AUTHOR]

One of the key aspects of underground carbon dioxide disposal is the injection rate. This defines the amount of CO 2 to be injected into a reservoir, and is limited by reservoir fracture pressure. Therefore, it is very important to determine all parameters which contribute to pressure build up to identify optimal injection design. When injection volumes are high, the rate is split between multiple injectors, making the optimization process time consuming for numerical simulations. As such analytical or semi analytical approaches can be very useful. In this paper, a fast semi-analytical approach to evaluate pressure distribution in saline aquifers during multiple well CO 2 injection is presented. It is based on general 1-D solutions of the diffusivity equation for three regions (CO 2 , two-phase and brine) established in aquifers when injection is done using a single well. The boundaries of a two-phase region, where both CO 2 and brine coexist in pores, depend on reservoir and fluid properties and assessed using a single numerical simulation, run to match the analytical solution for pressure distribution, and these values are kept constant when extending to multiple well scenarios. Extension to multiple well injection has been conducted using the superposition principle. The results of modeling were compared with the numerical simulations including single well injection and a variety of cases of multiple well injection, with differing numbers of injectors and their placement. Different reservoir properties, such as permeability, formation compressibility as well as vertical size have been considered. Good agreement between modeling and reservoir simulations was observed for all cases. The approach presented here can be used as a pre-screening tool for fast initial evaluation of potential injection sites as well as to suggest injection design ideas and optimization of well placement. [ABSTRACT FROM AUTHOR]

Gas production from hydrate-bearing sediments requires methane dissociation, which induces two-phase gas flow, mobilizing fine clay particles from within saturated pores. Fines migration within sandy sediments results in subsequent pore clogging, reducing reservoir connectivity. Sediments complex pore morphology, require direct 3D microscopic pore-scale imaging to investigate fines' influence on the porous media. The work uses synchrotron microcomputed tomography, to understand how fines migration due to gas injection, affects pore morphology and gas connectivity within sandy sediments. The goal is to study the impact of fines type and content at different gas injection stages, on gas flow regime and sediments rearrangement. Six saturated samples of sand and fines mixtures (Kaolinite and Montmorillonite at different contents) underwent four stages of gas injection during in-situ 3D scanning. X-ray images were segmented for direct visualization, as well to quantify gas ganglia distribution, also to extract pore networks to statistically measure changes in pore and throats distributions, and to simulate single-phase and relative permeability. Findings reveal that the extent of deformation to pore morphology increases with fines content and gas injection regardless of fines type. High kaolinite content (equal to or larger than 6%) results in fractured porous media, while high montmorillonite content (equal to or larger than 5%) results in disconnected vuggy media. Lower contents cause a gradual reduction in pore and throat sizes during gas injection. As fines content increases, clogging intensifies, thus gas connectivity and flow regime changes from connected capillary to disconnected vugs and microfractures. Both hydrophobic and hydrophilic fines reduced throat sizes, due to dislocations in sand grains. A unique pattern is discovered using pore networks, which describe pore-size fluctuations during fractures and vugs formation, due to fines migration. [Display omitted] • Sand and fines mixtures of different types and contents undergo CO 2 injection. • Microtomography 3D scans study changes in pore morphology and gas connectivity. • Pore networks correlate changes in pore morphology with fines content. • Fines migration clog throats and disconnect gas flow pathways during CO 2 injection. [ABSTRACT FROM AUTHOR]

The complex flow behavior of a gas condensate reservoir is caused by the compositional changes and the creation of condensate blockage around the wellbore. Once the pressure is lower than the dew point pressure, liquid dropout is formed in the reservoir. This liquid dropout reduces gas relative permeability. As a consequence, gas production is decreased and liquid dropout-condensate, a valuable resource, remains in the reservoir. In this paper, the re-vaporization mechanism of huff-n-puff gas injection is investigated from both experimental and numerical work. In huff-n-puff gas injection, when pressure is increased to be higher than the dew point pressure, part of the condensate can be re-vaporized and flows to the production well with gas during the puff process. Since there is only one well in the huff-n-puff process, the condensate region is near the well. When gas is injected into the reservoir, the pressure of the condensate region will be increased rapidly. Very limited research has been conducted on the re-vaporization of condensate, especially for shale gas condensate reservoir. Both experimental work and simulation study have confirmed the mechanism of condensate re-vaporization by huff-n-puff gas injection. The work from this paper indicates that huff-n-puff is an effective way to re-vaporize the condensate and enhance the condensate recovery. [ABSTRACT FROM AUTHOR]

Surfactant-alternating-gas injection, where foam generation can be expected, is a feasible approach for improving the sweep efficiency of solvent flooding by increasing the apparent viscosity of gas solvent. The foam stability plays an important role in this process. In this study, the foam stability and mobility of solvent/surfactant/pseudo-heavy-oil system under reservoir condition has been examined experimentally. The following factors are considered in the static foam stability experiments: surfactant concentration, salinity, temperature, the presence of pure n -C 16 H 34 as pseudo-heavy oil, and two types of gases (CO 2 and C 3 H 8 ). During the static experiments, foam is generated by sparging C 3 H 8 or CO 2 at a constant flow rate through the surfactant Triton X-100 solution, and then stirring the mixture with a magnetic stirrer. The foam stability is subsequently evaluated in terms of its height change as a function of time. It is found that the increasing surfactant concentration contributes to an increase in foam stability; foam stability is insensitive to surfactant concentration when the surfactant concentration is above the threshold CMC. As for the C 3 H 8 foam, an elevated temperature is detrimental to foam stability. At a higher temperature, the effective critical micelle concentration (CMC) of surfactant also increases. In general, the stability of C 3 H 8 foam is negatively affected by an increasing salinity. As n -C 16 H 34 is added to the solution, foam stability deteriorates. In order to study the effect of solvent type on foam stability, CO 2 is used to replace C 3 H 8 for generating foam, with the consideration of different salinity and temperature conditions. In comparison, CO 2 foam only exhibits several minutes of half-life at any conditions, which is much shorter than the C 3 H 8 foam. Additional flow experiments are also conducted by alternately injecting C 3 H 8 and Triton X-100 solution into a glass beadpack. The pressure difference during the experiments is recorded so as to obtain the mobility of the dynamic flow in the porous media. It is found that alternating C 3 H 8 and Triton X-100 solution results in a larger pressure difference, hence leading to more mobility reduction than alternating C 3 H 8 and water through the porous media. [ABSTRACT FROM AUTHOR]

Gas-injection enhanced oil recovery (EOR) has good displacement efficiency but poor sweep efficiency. Foam can improve sweep efficiency in these processes, but its direct injection would not be practical due to its poor injectivity. Field results suggest that the well injectivity can be improved if gas and surfactant solution are injected in alternating slugs, leading to foam creation inside porous medium as gas and surfactant intermingle in situ. This process, referred to as Surfactant Alternating Gas (SAG), aims at reducing gas mobility at the displacement front. Behind the front, because of low water saturation, foam collapses (partially or completely); thus, gas mobility gradually increases to its original mobility at the injection well. This can potentially lead to fingering of the highly-mobile gas into the region with low-mobility gas in the form of foam. To the best of our knowledge this phenomenon has not been investigated in the literature, apparently due to poor grid resolutions employed in the numerical simulations and/or focus on other parameters, from which it is difficult to infer instabilities. In this paper we use an implicit-texture foam model to simulate a SAG process with fine grid resolution. The magnitude of the instabilities decreases with weaker foam, coarser grid resolution, increasing diffusion, and inclusion of capillary pressure, suggesting that fingering reflects the intrinsic physics of the process: it is not a numerical artifact. In a successful SAG process, as long as there is enough surfactant ahead of the gas bank to form a region with low mobility, the fluid ahead of it is efficiently displaced (i.e., stable front exists). In numerical simulations, however, there are extremely low discrete mobility values in grid blocks located at the front. In such a process, there can be fingering within the foam bank (unstable displacement), while the foam front itself appears relatively stable. Further studies are required to verify the extent to which simulations of fingering reflect numerical artifacts at the front. These results have practical implications, especially in calculation of the well injectivity and design of optimum slug size and foam strength in a SAG process. [ABSTRACT FROM AUTHOR]

The heterogeneity of tight carbonate rocks is directly related to the morphology of micropores and the connectivity of the pore network, which have a great influence on the intrinsic microporosity and fluid flow properties of porous media. However, neither can be quantitatively evaluated by conventional techniques. Based on core observation and thin section analysis, combined with high-resolution field emission-scanning electron microscopy (FE-SEM) and mercury injection capillary pressure (MICP) measurements, we can identify carbonate rock types, determine the microporosity and microstructure and calculate the pore structure parameters. Digital image analysis (DIA) and the fractal dimension (FD) method are used to study the relationship between the quantified pore structure parameters, heterogeneity and fluid flow properties. The results indicate that rock types in 12 carbonate samples are dominated by grainstone and packstone, followed by wackestone and dolomitic packstone. The microporosity of rock types has various microstructure characteristics. Crystalline types of microporosity (the small and large intercrystalline pores) increase pore network connectivity whereas micromoldic pores show variations in connectivity of different lithofacies. However, the small intercrystalline pores contribute little to the permeability because of narrow and complex pore networks for fluid flow. MICP data of samples reveal that these samples are relatively tight with low porosity (avg. 3.7%) and permeability (avg. 0.452mD). The pore-throat radius mainly ranges from 0.1 μm to 1.0 μm, which contributes the highest proportion of permeability to the samples. Fractal dimensions calculated from the “J-curve” models vary between 2.0746 and 2.8551 (avg. 2.331), indicating high heterogeneity. Moreover, the fractal dimension is strongly negatively related to the permeability, average pore throat radius and separation coefficient. Additionally, quantified pore geometric parameters from DIA, including dominant pore size (DOMsize), perimeter over area (PoA), pore body-to-throat ratio (BTR) and average roundness (γ a ), greatly influence the pore structure and fluid flow behavior. The samples with large DOMsize, high γ a , low PoA and low BTR show a low fractal dimension and simple pore network but high permeability. Diagenesis can also affect the fractal pore space and self-similarity pore geometries of carbonates across all length scales. This information about the micropore geometry and microstructure of the carbonate rock will further improve the assessment of its reservoir properties. [ABSTRACT FROM AUTHOR]

This study presents a framework for hydrate formation risk management. Hydrate formation accidents and the consequences of hydrate formation risk are defined by the initiation of hydrate formation and pipeline blockage due to hydrate formation, respectively. The hazards, preventive measures and mitigating measures for hydrate formation are presented in accordance with defined accidents and consequences. A life-cycle cost (LCC)-based hydrate formation risk management methodology is proposed that consists of four steps: construction of an exceedance curve for the durations of operational interruptions, construction of an exceedance curve for the frequency versus the monoethylene glycol (MEG) injection rate, selection of the MEG injection rate, and LCC estimation. Operational interruptions are quantified in terms of the frequency of hazard occurrence and their extent via exceedance curves for the durations of the operational interruptions. The next step of constructing the exceedance curve for the frequency of hydrate formation with respect to the MEG injection rate quantifies the frequency of the accidents for a given MEG injection rate. Because the failure rate and the repair time of equipment are discrete, only a set of representative MEG injection rates deserve further consideration in the LCC estimation. Two case studies are performed with topsides that have different process complexities, which lead to different frequencies of operational interruption. [ABSTRACT FROM AUTHOR]

Gas huff-n-puff injection, which avoids the viscous fingering phenomenon or gas channeling between connected wells, is a potential method to efficiently enhance oil recovery (EOR) in liquid-rich shale oil cores. In this paper, an experimental study of core size effect on the gas huff-n-puff EOR was implemented by using two groups of cores from the Wolfcamp field in West Texas. The first group contained core plugs with a length of 2″, but different diameters varying from 1″ to 4″. The second group of core plugs had a diameter of 1.5″, but differed in length from 1″ to 3.5″. CH 4 huff-n-puff EOR experiments with an injection pressure of 2000 psi were conducted to analyze the size effects. CT scan was also implemented to check the oil saturation and cumulative oil recovery for each cycle. The results show that after eight huff-n-puff cycles, the oil recovery of cores with 1″, 1.5″, 2″, 3″, 3.5″ and 4″ in diameter are 49.65%, 48.57%, 47.76%, 46.15%, 43.55%, and 42.64%, respectively. The core plug with a larger diameter yields a relatively smaller oil recovery due to its lower apparent surface-to-volume ratio (AS/V) and smaller pressure gradient (ΔP/Δr). The core plugs with 1″, 2″, 2.75″, and 3.5″ achieve almost the same oil recovery during the huff-n-puff process. It is demonstrated that core length has no effect on final cumulative oil recovery. The result also shows that the oil recovered in one cycle decreases as the huff-n-puff cycle number increases. The first cycle gives the peak incremental oil recovery. The obtained CT scan images together with the analysis of CT number reveal the density and oil saturation change inside the core and reflect the cumulative oil recovery during the gas huff-n-puff process. [ABSTRACT FROM AUTHOR]

In order to enhance effectively permeability of coal seams and increase the efficiency of gas extraction, the pulse gas fracturing is proposed as a new stimulation method. In this study, the pulse gas fracturing experiment of low permeability coal on the laboratory scale was executed and sequential 267 pulse times were preformed. The mercury intrusion porosimetry, scanning electron microscope and permeability measurements were conducted to investigate the changes in the pore structure and permeability caused by the pulse gas injection. The results show as follows. (1) The volume of the coal specimen repeats the swelling-shrinkage process during the pulse gas fracturing which contributes to improve the size and shape of pores and generate micro-cracks in the coal. The deformation of the coal sample has a fatigue threshold in the pulse gas fracturing and its value is near 100 pulse times. (2) The pulse gas fracturing promotes the transfer of smaller pores to larger pores and improves the pore size distribution. After the pulse gas fracturing, the average incremental pore volume of transition pores, mesopores and macropores increases 25.85%, 117.86% and 105.07%, respectively. The total pore volume of the coal sample has an increase of 80.65%. The macropores, mesopores and transition pores volumes increase by 165.22%, 438.33% and 27.27%, respectively. The results indicate that pulse gas fracturing can improve the pore space and the pore distribution, and ultimately increase the permeability of the coal. The change that micropores transfer into larger pores also results that the cumulative pore specific surface of transition pores, mesopores and macropores has an increase of 10.18%, contributing to coalbed methane (CBM) sorption/desorption and diffusion. (3) The crossover network cracks are formed in the coal during the pulse gas fracturing. The porosity and permeability of the coal are obviously improved by the pulse gas fracturing, indicating that the pulse gas fracturing can be used to effectively enhance the permeability of CBM reservoirs. It is worth noting that there is a critical pulse time for the increase of the coal permeability and its value is about 100 pulse times under the stress condition and pulse gas injection method of this research. [ABSTRACT FROM AUTHOR]

The investigations aimed at proving the influence of selected parameters on the flow properties of LPG vapor phase injectors. The author mainly assessed the feed pressure, the injector piston lift, the diameter of the outlet nozzle and the realization of the current-modulating signal. Functional relations have been determined and qualitative assessment of the compatibility has been performed. Additionally, an evaluation of the influence of the analyzed parameters has been performed on the injector full opening and closing times that confirms the response to the impulse and may be decisive in the case of short injection times. It has been confirmed that the injector piston lift significantly influences the response times (for full opening - 1.00 ms and full closing – 1.08 ms) and the PWM duty cycle below 50% may lead to a closure of the injector due to insufficient counter force (difference for full closing by 7.53 ms at the 10 ms opening times). In order to measure the response times, an outflow meter has been proposed. A new parameter has been introduced to the analysis – opening timing that may be used in simplified flow analysis. The investigations are a response to the market demands for this type of analyses and to an increasing demand for multipoint LPG vapor phase injection systems. The investigations may turn out useful in calculations or validations of simulation models. [ABSTRACT FROM AUTHOR]

Devonian-Mississippian Chattanooga shale plays in North America are categorized as unconventional reserves with potential hydrocarbon resource accumulations. Unlike Chattanooga shale in the Appalachian region, less effort has been dedicated to its correspondent in the Ozark region. The ultra-tight nature of the formation causes fast decline of the production and small recovery factors. However, application of CO 2 huff-n-puff can potentially improve the recovery of oil when the complex shale oil resource is fully understood. This would eventually lead to the development of a map which delineates sweet-spots. Therefore, the characterization of these reservoirs is an essential step to fully understand the associated complexities of the reservoir as well as to evaluate the economic viability of their exploitation. Thus this paper presents a fully integrated characterization at multiple scales (petrophysical, geophysical and geological evaluation, geomechanical and geochemical analysis) of the black shale sequence in Sumner County, Kansas. Multi-scale dataset for this regional characterization is obtained from laboratory measured petrophysical parameters, well-log measurements as well as seismic data. Therefore, this paper presents a comprehensive approach to reservoir characterization which would eventually lead to fully understanding the resource play as well as accurately identifying sweet spots for well placement and improved hydrocarbon recovery. Chattanooga shale in Sumner County has an average TOC of ∼2.26 wt. % in the middle shale member with additional organic porosity of 5% and a vitrinite reflectance (Ro %) of 0.62. It is classified as a shale oil resource with OOIP of 4 MMbbl. Petrophysical correlations developed at wellbore vicinity were trained with artificial neural networks (ANNs) and correlated with seismic to provide lateral distribution of such properties farther from the wellbore. Moreover, due to the heavy reliance of unconventional shale plays on fracture network for improved flow conditions, fracture models were developed based on the mineral-brittleness as well as the fracture toughness. Consequently, a complete study based on compositional numerical simulation was conducted to analyze the potential of CO 2 as an EOR technique, together with an evaluation of the impact of reservoir and fracture parameters in the well productivity potential. Subsequently, an economic optimization process was also formulated to obtain the best gas injection design for the highest Net Present Value (NPV). The cumulative oil was notably observed to increase by the use of the optimum injection design. Moreover, the huff-n-puff injection of CO 2 proved to be a viable option by increasing the final oil recovery from 10% to 53% of the OOIP in the SRV region using optimal parameters. [ABSTRACT FROM AUTHOR]

Gas injection in coalbed Methane reservoirs is an environmentally friendly and economically viable enhanced recovery technique. Promising results can be obtained by injecting a mixture of CO2 and N2. The optimum composition is a function of geomechanical and sorption characteristics of the coal. In the current study, it is sought to optimise the composition of the injected gas, based on an economic objective function. The decision variables are the composition of the injected gas and the injection rate that can be both subjected to change over a continuous injection. In the formulated objective function, the OPEX costs (e.g., separation, compression for injection and injectant supply) and the income, resulting from, CH4 production and CO2 sequestration are considered. This optimisation problem is nonlinear, and the corresponding search space is high-dimensional. Therefore, a sophisticated optimisation algorithm is required. For this study, a parallel real-value genetic algorithm is coded in MatLab and coupled to a commercial coalbed simulator (ECLIPSE-E300). This interface allows us to measure the goodness of each solution-candidate and also to perform optimisation automatically. The algorithm is used to optimise rates and compositions of a semi-synthetic ECBM case study, and the optimum scenario is compared with the optimum scenario of a constant composition injection. The comparison confirms that a varying-composition strategy results in more revenue from an ECBM project. In this study, also, the optimum solution for different economic conditions are approximated and then the optimum solutions are compared with each other to investigate the effect of carbon credit and Methane price on the injection schedule. In those economic conditions that carbon credit is higher than CO2 supply costs, the optimum scenarios tend to yield a higher amount of sequestrated CO2, and in all of them, the optimum schedules are the ones that start with a very low fraction of CO2 in the injected gas and continue by a gradual increase of CO2 fraction. In other economic conditions, the optimum scenarios move towards the ones that less CO2 is injected. [ABSTRACT FROM AUTHOR]

Black-oil fluid properties are determined by lab measurements or can be calculated through flash calculations of the reservoir fluid. Allowing for variable bubble-point pressures in black- or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. Reservoir simulation accuracy, however, may be affected by discontinuities in the input data and poor predictions of extrapolated fluid properties. Common practice is to add surface gas to the original oil in the lab and increase the pressure to reach a new bubble-point. Another approach is to use linear extrapolation of oil and gas K -values with pressure on a log-log plot, where K -values are equal to 1.0 at a pseudo-critical or convergence pressure. The latter approach results in discontinuities in the phase behavior. We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached at the top of the pseudocomponent pressure-composition diagram. Unlike other methods commonly used or recently proposed, the approach provides a smooth and continuous pressure-composition curve to the critical point. The model further allows for reinjection of produced gas, methane, or CO 2 to increase oil recovery for both volatile and black oils. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure alters the saturation pressures by decreasing the bubble-point pressure or increasing the dew-point pressure. Bubble-point pressure in the new model is a function of both capillary pressure (effective pore radius) and gas content. The phase behavior is illustrated using ternary diagrams for up to four components (water, oil, gas, and CO 2 or CH 4 ) and three phases (aqueous, oleic, gaseous) to allow for miscible and immiscible injection of various gases. The new phase behavior could be easily incorporated in a compositionally-extended black- or volatile-oil simulator. The approach could also be used to model gas condensate reservoirs with or without gas injection and capillary pressure. Finally, 1-D slim-tube simulations are made with the extrapolated black oil fluid properties to estimate minimum miscibility pressure (MMP) to demonstrate the applicability of the approach. Shocks occur in the 1-D displacement consistent with a compositional simulator. [ABSTRACT FROM AUTHOR]

Naturally Fractured Reservoirs (NFRs) contain a large portion of oil reserves. Most of NFRs are subjected to secondary and tertiary recovery schemes due to their low primary recovery. Gas injection into NFRs has received much attention in recent years. The main mechanisms contributing to oil recovery during gas injection into NFRs are viscous flow, gravity drainage and diffusion. The viscous flow rarely happens in NFRs due to low pressure drop and early breakthrough of injected gas in high conductive fractures. Gravity drainage is also important in fractured reservoirs with tall matrix blocks where gravity force overcomes capillary force. Diffusion is another recovery mechanism that is found to have a significant role in recovery of oil from NFRs. This has been affirmed by numerous experimental and simulation investigations in the literature. However, sole effect of this mechanism is not well recognized especially in NFRs with very low matrix permeability. In the current work, we have experimentally studied the effect of diffusion and viscous flow on oil recovery from NFRs with tight matrix blocks. The relative importance of each mechanism which reflects the impact of convection versus diffusion is investigated. We have also studied the sole effect of diffusion on final oil recovery using two types of gas (helium and nitrogen) with different diffusion coefficients. Results show that effect of diffusion in tight reservoirs is significant and comparable to effect of viscous flow. Numerical simulation also was conducted to verify results obtained in four experiments involving nitrogen injection. Simulation results reveal that current models for diffusion do not take into account the role of diffusion in ultimate oil recovery properly. [ABSTRACT FROM AUTHOR]

As one of the primary techniques for enhanced oil recovery, the gas injection method has been investigated widely. However, introducing “dry gas” into a gas-condensate reservoir is more than miscible flooding that maintains reservoir pressure and improves oil displacement. This method is associated with complex thermodynamic processes or phase transitions, such as the re-vaporization of heavy hydrocarbon ends and connate water, the reduction of the condensate/gas ratio and retrograde dew point (RDP) pressure, etc. In this paper, a laboratory study was conducted to estimate the effectiveness of the gas injection process during gas-condensate reservoir development. Specific laboratory equipment was constructed to conduct an experimental investigation by modelling the gas injection and reservoir depletion process. Detailed analysis of experimental investigations suggests the gas injection process might be more effective when the “reservoir” pressure is below the initial RDP pressure of the fluid. Thermodynamically, this pressure stage could be conducive for gas injection, by decreasing the condensate/gas ratio, re-vaporizing the liquid phase that dropped out and maintaining the system in a single gas phase. To further examine the process of the liquid or fog formation phase in the gas-condensate mixture, the fluid was investigated as a colloidal structure. Theoretical findings confirm that the fog condition is a well-matched feature of gas-condensate fluids with the properties of aerosol-colloidal systems. The correlation between fog up (FU), RDP pressures and temperature was investigated experimentally. The rationale for increasing the difference between the FU and RDP pressures with the increase of temperature and other physical and thermodynamic properties of gas-condensate systems is explained according to the fundamentals of colloidal systems. Based on these obtained results, conclusions were reached about the physical nature of the condensation under reservoir conditions. The results show that condensation in the reservoir condition can occur when the pressure in the interval creates the formation of liquid phase micro-embryos or aerosols. Thus, the fluid condenses due to surface forces between the sub-micron-sized condensate particles and the rock granules. This phenomenon can cause condensate blockage or condensate banking in the early stage of reservoir development when even the reservoir pressure is greater than the RDP pressure identified in the PVT cell. These results were used to explain the dynamic processes occurring within and influencing the operating characteristics of the gas-condensate wells. Because these colloidal features of fluid can play a significant role in reservoir development, we recommended considering these aspects when planning gas injection methods. [ABSTRACT FROM AUTHOR]

Injection of CO 2 , as a redundant gas, is considered as one of the most viable options to enhance oil recovery. The performance of this process may though be compromised in the event of severe precipitation and deposition of asphaltene. In this study, the effect of Co 3 O 4 nanoparticles with various concentrations of 0.01, 0.1 and 1.0 wt% on precipitation of asphaltene during CO 2 injection was investigated by means of interfacial tension (IFT) measurements. The addition of Co 3 O 4 nanoparticles to synthetic solutions comprising of n-heptane, toluene and 5 wt% asphaltene and crude oil caused the IFT to decrease linearly as a function of pressure with two different slopes. In the first region, CO 2 dissolved in the oil phase while in the second region, asphaltene was prone to precipitation. The IFT reduced at lower slope in the second region. It was found that the addition of nanoparticles to the synthetic and crude oils resulted in more asphaltene particles adsorption on the surface of nanoparticles. In addition, more stable dispersion of asphaltene nano-aggregates could be attained. Consequently, the ultimate recovery of asphaltenic oil would take place in reservoir conditions during CO 2 injection due to less aggregation and precipitation of asphaltene particles. Finally, the optimum concentration of dispersed Co 3 O 4 nanoparticles was found to be 0.1 wt%. [ABSTRACT FROM AUTHOR]

Given the increasing exploitation depth, outburst under the condition of uncovering coal in crosscut is increasingly dangerous. To prevent the occurrence of outburst, a novel forecast indicator, which is the initial volume of gas emission from the borehole (IVGEB) was proposed to validate the outburst-prevention effect. A self-developed experimental device for measuring the initial rate of gas emission from the borehole (IRGEB) was developed correspondingly. The IVGEB value is the sum of the unit length of IRGEB. Experiments have been conducted under different gas injection rates and gas pressures. CO 2 and N 2 gases have been used as injection media. After 50 test runs, 48 sets of valid data have been collected. The results suggested that the IVGEB value is approximately proportional to the gas pressure: the higher the gas pressure, the larger the IVGEB value. Furthermore, based on the relationship of the initial expansion energy of released gas (IEERG), which is another forecast indicator and gas pressure, the weak outburst pressure P 1 and intense outburst pressure P 2 of each coal sample could be calculated because the critical values of IEERG were 42.98 and 103.8 mJ/g, respectively. Thus, the IVGEB critical value of weak outburst and intense outburst could be obtained by applying a relation formula between IVGEB and gas pressure. The obtained IVGEB critical value of weak outburst and intense outburst were 39.69 L and 93.32 L, respectively. This approach might provide a possible method to validate the outburst-prevention effect quickly in the process of uncovering coal in crosscuts within deep mines. [ABSTRACT FROM AUTHOR]

Asphaltene precipitation and deposition within the reservoir formation is one of the main concerns during enhanced oil recovery (EOR) processes especially during the gas injection. In the current study, different aspects of carbon dioxide (CO 2 ) and nitrogen (N 2 ) injection in the reservoir, was thoroughly examined. The feasibility of using these gases as the injection gas was explored using Bayesian network-based screening method. After recombination and preparation of the live crude oil, precipitation of asphaltene using vanishing interfacial tension (VIT) method and core flooding experimentation was examined. Besides, swelling test was utilized to investigate the effect of CO 2 and N 2 injection on the expansion of live crude oil. The obtained results showed that recovery factor (RF) of CO 2 injected method in core flood test is higher than N 2 injection due to higher swelling and better miscibility conditions. Although, VIT measurements showed asphaltene precipitation during CO 2 injection, no sign of asphaltene deposition during core flood test at near bubble point pressure was observed. [ABSTRACT FROM AUTHOR]

This paper presents a huff-n-puff gas injection method to increase condensate production in an Eagle Ford gas condensate reservoir using a simulation approach. The simulation study suggests that the huff time and puff time should be the same. Because of higher compressibility of a gas condensate fluid, either huff or puff time required will be longer than that for a shale oil reservoir. For the studied reservoir, an optimum huff or puff time is about 600 days. However, a shorter time of 300 days is preferable for recouping the cost for facilities. To improve the overall liquid condensate recovery performance, during the last half of the development period, the huff-n-puff may be changed to pressure depletion so that the energy injected earlier can be fully utilized. Other effects such as those of initial water saturation, injection pressure, and gas composition, are also investigated in this paper. The methodology presented in this paper is applicable to other gas condensate reservoirs, and some of results or conclusions may be typical of gas condensate reservoirs. [ABSTRACT FROM AUTHOR]

Gas-injection in coalbed methane resources is a well-studied enhanced recovery technique. Through several experimental, simulation and pilot studies, it has been shown that the composition and type of injectant have a significant impact on the ultimate Methane recovery and the production rate. The commonly used gases are Carbon Dioxide (CO 2 ), Nitrogen (N 2 ) and a mixture of N 2 and CO 2 . Pure CO 2 (CO 2 -enriched gas) injection may cause irretrievable well injectivity reduction, because of high adsorption affinity of coal to CO 2 , which result in matrix swelling. By injecting pure N 2 (N 2 -enriched gas), an early breakthrough of the injected gas may occur, which degrades the quality of the produced gas. Studies have shown that a better performance is obtained, when a mixture of CO 2 and N 2 is injected, and there is an optimum composition for the mixture, which depends on the geomechanical and sorption characteristics of the coal. In all of these studies, the composition of the injected gas is kept constant within the period of injection. In this study, a varying-composition injection is proposed, as an alternative technique to the constant-composition injection. In a varying-composition injection, the composition of the injected gas is altered during the injection period through several steps. Such a scenario can postpone the breakthrough time, and meanwhile avoid the deterioration of well injectivity. To assess the proposed method and find an optimal and practical injection schedule, a semi-synthetic simulation model is constructed. Different injection scenarios are compared with each other, using a compositional simulator (ECLIPSE-300), which uses the extended Langmuir isotherm and the modified Palmer-Mansoori model. By carrying out a series of sensitivity analyses, an optimum scenario is found. The best obtained scenario is the one that begins by injecting a mixture with less CO 2 , and continues by a sequential rise in the CO 2 fraction. The outcomes confirm that the proposed technique has the following benefits, in comparison with the optimum scenario of constant-composition injection: 1- greater Methane recovery, 2- higher Methane production rate 3- deferment in permeability reduction, 4- later N 2 breakthrough. [ABSTRACT FROM AUTHOR]

Water-alternating gas injection (WAG) is a common EOR method used at different reservoirs around the world. In this paper we present a novel method called a nanofluid alternating gas (NWAG) injection to improve the ability of the conventional WAG process for the oil-wet carbonate reservoirs. Different experimental tests of water-alternating gas (WAG), as well as nanofluid alternating gas (NWAG) injection were performed on carbonate core samples saturated with crude oil. SiO 2 nanoparticles, with spherical morphology and two different sizes of 11–14 and 30–40 nm, were used to improve the performance of the WAG injection method. The WAG process in the core-flooding experiments was carried out by the injection of gas and SiO 2 water-based nanofluids. Also, different characterization investigations, such as interfacial tension and contact angle measurements, were completed to study the nanoparticles effect on the recovery mechanisms. Our experiments showed that nano-silica adsorption on the rock surface changed the wettability of reservoir rock from oil-wet to strongly water-wet. Moreover, nanoparticles were located at the oil/water interface, which leads to a reduction in interfacial tension (IFT) between oil and water. Also, by adding SiO 2 nanoparticles to the aqueous phase, the viscosity of the injected fluid was increased. Increasing viscosity and changing wettability affect the viscous and capillary forces and increase the capillary numbers; hence, the recovery is improved. Our tests showed that the dominant mechanism is the wettability alteration. These mechanisms enhanced the oil production from the porous media compared to the conventional WAG process. The results indicated a better recovery factor and efficiency for smaller nanoparticle size. Moreover, the experiments showed higher recovery factor for the core sample with lower permeability in comparison with the other. [ABSTRACT FROM AUTHOR]

In enhanced oil recovery, a successful process of injecting gases such as methane ties profoundly to the presence of detrimental heavy components of crude oil such as asphaltene. This experimental study aimed at investigating parameters that would influence the interfacial tension (IFT) of methane and synthetic oil solutions of toluene and n-paraffins such as n-heptane and n-decane with or without asphaltene. The percentage of asphaltene content was adjusted to 5 wt%. The experimental results showed that the presence of asphaltene, at elevated pressures, caused IFT to decrease non-linearly. At a certain point as pressure increased further then based on surface coverage theory, IFT turned the course indicating the precipitation of asphaltene. This coincided with the increased solubility of methane in the solution while IFT was decreasing. The lower IFT at high pressures also tended to follow a second order decay equation. The slope of the IFT versus pressure also decreased with increased concentration of n-paraffins in the solution. Accordingly, at high pressures the IFT of solutions containing more n-paraffins was larger. Finally, a correlation was developed to estimate the equilibrium IFT of the methane and n-paraffins based on the explicit functionality of the pressure and n-paraffin concentration. [ABSTRACT FROM AUTHOR]

Induced flow after completion is one of the challenges that hinder the development efficiency for depleted offshore gas reservoirs. Coiled tubing (CT) gas injection has many advantages in inducing the wells to self-flow. The critical conditions of induced self-flow are analyzed. And the pressure distribution in the annulus between the oil tubing and CT is calculated by numerical modeling based on gas–liquid two-phase flow theories. The effects of gas injection depth, injection rate, CT size, wellhead back pressure, and well deviation angle on the results of induced self-flow are investigated. Numerical modeling results indicate that the pressure drop caused by gas injection decreases significantly as the injection depth decreases, and as the wellhead back pressure and the well deviation angle (especially for high angles, >60°) increases. Within the range of injection rates commonly used for CT gas injection, CT size and injection rate show little influence on the pressure drop. Therefore, injection depth and wellhead back pressure are key factors controlling the results of the induced flow treatment. For horizontal wells and high deviated wells, it is better to use a deeper injection depth and/or lower wellhead back pressure, which benefits the successful induced flow. [ABSTRACT FROM AUTHOR]

The current available technique to produce shale oil and gas condensate is through primary depletion using horizontal wells with multiple transverse fractures. The oil recovery factor is only a few percent. There is a big prize to be claimed in terms of enhanced oil recovery (EOR). Because gas price is low and oil price is high, maximizing liquid oil production from gas condensate reservoirs becomes shale producers' top interest. This paper provides the status of enhanced oil recovery (EOR) in shale oil and gas condensate reservoirs by gas injection. It starts with the discussion of possible EOR options in shale reservoirs. For the gas injection option, the huff and puff mode is compared with the gas flooding mode. Different modes of water injection in shale oil reservoirs are also compared. The discussion and comparison show that gas injection is more feasible in shale reservoirs than waterflooding and any other EOR methods. The rest of the paper focuses on review of gas injection in shale reservoirs, which covers the following. • Mechanisms of gas injection. • Experimental results on huff and puff gas injection. • Simulation results on huff and puff gas injection. • Gas injection in gas condensate reservoirs. This paper summarizes the EOR efforts which has been made in the industry and provides the direction for the industry future efforts to maximize liquid oil production. [ABSTRACT FROM AUTHOR]

This paper investigates the macroscopic and microscopic characteristics of DME(dimethyl ether)/isobutene blended fuel using a spray visualization and droplet particle analyzing system. In this study, the spray characteristics of DME/isobutene blends were investigated with regard to spray injection rate, spray tip penetration, spray cone angle, and the development of spray images at various blending ratios of isobutene fuel. In addition, the size distribution of DME/isobutene blended fuels and the velocity distribution of blended fuels were conducted and compared to those of conventional diesel fuel. The results showed that DME fuel has a higher injection rate peak than those of the DME/isobutene blends. The spray tip penetration increased with an increase in the injection pressure; however, the increasing rate of the spray penetration decreased with an increase in injection pressure. The spray cone angle at a 60 MPa injection pressure was larger than that at 30 MPa of injection pressure. The effect of ambient pressure on the spray cone angle according to the variation in ambient pressure showed that the spray cone angle is wider at the beginning of the fuel injection, and it converges to a similar and constant distribution. The droplet size of DME fuel showed the smallest Sauter mean diameter among the DME/isobutene blending fuels due to the excellent evaporation characteristics compared to those of blended fuels. The droplet size distributions of the test fuels were divided into two patterns: DME and the other three DME/isobutene blended fuels. [ABSTRACT FROM AUTHOR]

Transient gas–liquid two-phase flow usually occurs in wells because of gas inflow. The objective of this paper is to investigate the pressure variation in wellbore caused by gas kick/injection. A general and simple drift flux model based on Shi slip relation is presented for dynamic two-phase flow in wells. The model is numerically solved by the finite volume method and AUSMV scheme. Moreover, a laboratory experiment is implemented to simulate the process of gas kick/injection for a high gas volume fraction. The pressures at different depths of the test section of the annular tube are measured, and the change of the flow behavior is observed during the experiment. The laboratory experiment results and the data of a full-scale experiment provided by Lage et al. (2003) indicate that the annular pressures increase at first and subsequently decrease during the process of gas injection in the experiments, and the pressure increases slightly in the real well. Comparisons between the simulation results and the data of the two experiments show fair agreement in terms of the pressure. The simulation results indicate that the gas and liquid mass flow rates and well depth have a strong influence on the variation of the bottom pressure caused by gas kick/injection. The liquid viscosity slightly affects the variation of the bottom pressure. [ABSTRACT FROM AUTHOR]

Ten phases of south pars in five independent gas processing plants (GPP) are located on the Iranian coast of the Persian Gulf. In each phase, raw gas is taken from the on-veil platform and transferred in a multi-phase form through 32-inch submarine pipeline at a distance of 110 km from shore. In GPP No 1 or Phase 1, gas is daily extracted from two on-veil platforms and the gas-water separation as dehydration policy is performed on the platform. In order to preserve the pipes and avoid hydrate and corrosion, Mono Ethylene Glycol (MEG) accompanied by corrosion inhibitor as corrosion inhibition policy (in GPP No. 3, 5) or MDEA as pH stabilization policy (in GPP No. 2, 4) is transferred to the platforms via two 4.5-inch pipelines and injected into the submarine pipeline. Sludge and scale deposits formed within the pipeline as byproducts of the corrosion inhibition and PH stabilization techniques, respectively. The derivation of the field partitioning of MEG, ferrous ion, calcium, chloride, pH and weight loss coupons provide useful information concerning the sealine corrosion and scale accumulation. Heat transfer analyses of submarine pipeline show that the water condensation rate and top of the line corrosion can occur with the loose concrete and any pipe coating defects. The results show that the pH stabilization with the separation of brine water which is located in offshore has better performance than corrosion inhibition policy. [ABSTRACT FROM AUTHOR]

Water-soluble gas reservoir refers to those unconventional reservoirs composed of methane mostly, which dissolved in over-pressure and high-temperature groundwater. The Paleogene Wenchang and Enping Formations of the Huizhou Sag are major source rocks that generate significant quantities of gas and the sandstone reservoirs are varying from weakly overpressured to overpressured on the whole. According to the 3D geologic model using geostatistics method, the volume of water-soluble gas in the resource is about 1791.5 × 10 8 m 3 and 2688.5 × 10 8 m 3 , 1.19 and 3.46 times of the conventional gas, respectively. The water-soluble gas is an unconventional resource with great potential, and can provide substantial gas source for conventional pools through degasification. In this paper, a new feasible technology is proposed for the development of water-soluble gas reservoirs. Produced water reinjection, when combined with water-soluble gas recovery, not only enhances the relatively gas production by maintaining reservoir pressure, but also contributes to the output of water treatment, especially under marine production conditions that faces the tough situation of the high cost and large number of water output. It has a significant meaning to alleviate the bottleneck problem of the resource shortage in Pearl River delta industrial base of China. A 3D injection–production model is developed using the TOUGH2/EOS7C program. Numerical results show that under the condition of constant bottom hole pressure 30 MPa, water injection can increase the plateau of the production period from 36.68 years to 70.53 years, and enhance the cumulative gas production effectively. Relative parameters are also analyzed, and the following conclusions can be drawn: producer–injector spacing and perforation intervals of producing well have considerable influences on the gas recovery, comparing with the rate of water-injection and perforation interval of injection well. In addition, it is necessary to find the optimal value of these parameters. In general, produced water reinjection is a potential choice for water-soluble gas recovery. [ABSTRACT FROM AUTHOR]

Miscible gas injection is one of the most efficient enhanced oil recovery (EOR) methods in petroleum industry. Minimum miscibility pressure (MMP) is a key parameter in any gas injection design project. Experimental Measurement of MMP is a costly and time-consuming method; so searching for a quick, not expensive and reliable method to determine gas-oil MMP is inevitable. This paper Present a fast and vigorous method using a new approach based on multi-gene genetic programming (MGGP) to determine carbon dioxide minimum miscibility pressure (CO 2 MMP) for carbon dioxide injection processes. Then, new correlations for MMP calculation of both pure and impure CO 2 streams using the MGGP, have been developed. Consequently, the MGGP models have been validated and compared with the other conventional model results, to evaluate different techniques. It was founded that the new developed correlations predict accurate values of CO 2 MMP compare with the experimental slim-tube CO 2 MMP test results, with the lowest average relative and absolute error and also higher correlation coefficient among all evaluated CO 2 MMP correlation results. [ABSTRACT FROM AUTHOR]

The focus of this paper is to determine the hydrate saturation of the natural gas hydrate (NGH) deposits in the Muri Basin of Qilian Mountain permafrost on the Qinghai–Tibet Plateau and to analyse the performance of different production methods using TOUGH + HYDRATE (T + H) simulator for simulation of the NGH production process trial. Both depressurisation and thermal stimulation methods, using a high-pressure submersible pump to keep the water level in the borehole below the hydrate layer and injecting either hot air or steam, were applied in the hydrate production trial. The simulation of depressurisation-induced gas production under different initial hydrate saturations showed that the gas production was 104.8 m 3 for 84 h when the saturation of the hydrate layer was 1.0% and the hydrate abnormal layer was 0.5%. The simulated production was close to the actual value of 102 m 3 . The result for the NGH deposits indicated a production of 12.8 m 3 for the hot air injection-induced gas for 11 h, which is slightly higher than the actual production 10.1 m 3 . The hot steam injection produced 7.1 m 3 of gas for 6 h versus the actual production 3.3 m 3 . The difference was associated with the simplification of the simulated pressure. The simulation also revealed that larger pressure differences caused the dissociation front of the lower hydrate formation to advance faster than that of the upper formation. Further results also showed that the two heating methods had weak impacts on hydrate dissociation in this production trail since they were used mainly for accelerating the gas migration around the wall of the well, resulting in a slight growth of gas production rate. Depressurisation-induced production was relatively more effective for low saturation hydrate deposits in the Qilian Mountain permafrost. [ABSTRACT FROM AUTHOR]

Many experimental measurements have been conducted to evaluate the effect of moisture on gas sorption and diffusion kinetics in coal but these works normally focus on the adsorption process that takes place during carbon dioxide injection. While for coalbed methane recovery, methane desorption dominates. Therefore, the conclusions on adsorption kinetics may be not always valid for the desorption-dominated coalbed methane recovery. In this paper, a series of methane desorption measurements were conducted on pulverized Chinese coal samples. Then the diffusion kinetics were modeled using the unipore model and the bidisperse model. The results show that the bidisperse model is more suitable than the unipore model for modeling the diffusion kinetics in coals used in this study. The diffusivity value of the anthracite is lower compared with the bituminous coal. The moisture effects on diffusion kinetics are different between the two rank coals used in this work. For the anthracite, diffusivity decreases with increasing moisture content, while for the bituminous coal, it varies with the moisture content according to a U-shape function. The U-shape relationship between diffusivity and moisture content for bituminous coal during methane desorption process has not been observed in experimental measurements on adsorption kinetics, which normally show that the diffusivity varies monotonically with moisture content. This difference may be due to the different moisture effects on adsorption and desorption. This indicates that the diffusion kinetics are different between adsorption and desorption, and the conclusions based on adsorption kinetics may be invalid for coalbed methane recovery because it is the desorption that takes place during methane production. [ABSTRACT FROM AUTHOR]

Horizontal gas drilling has been considered as an innovative technique for tight gas reservoir development. Given currently there are few effective models to determine the exact minimum required gas injection rate in a wide range of ROP of horizontal gas drilling, in this work a new method for determining the minimum required gas injection rate for hole cleaning in horizontal gas drilling is developed, meanwhile a new terminal velocity model and a new required minimum gas velocity model are developed in the “build” section of horizontal well based on the widely used Gray's model to extend the minimum velocity criteria to be applied in horizontal gas drilling. Analysis using field data in the published article demonstrates that the new method can accurately determine the minimum required gas injection rate of horizontal gas drilling in a wide range of ROP (or cuttings size) and provides drilling engineers a practical tool for designing the appropriate gas injection rate in horizontal gas drilling. [ABSTRACT FROM AUTHOR]

To determine the mechanism of component mass transfer among the phases in EOR and fluid phase change principles, this study chose an oil field in western China as the research object for forward or backward contact experimentation on the mechanisms by which injected gas fronts displace oil and enriched input gas displaces residual oil. Slim tube displacement experiments were also conducted to examine the regulation of phase state alteration and the characteristics of dynamic displacement efficiency during gas injection. Results show that the mechanism through which hydrocarbon gas drive occurs is the dual action of evaporation and condensation, with the former as the primary mechanism. The intermediate component of produced gas exhibits a decreasing and then increasing trend. Both miscible flooding and immiscible flooding exist in the inter-phase mass transfer zone of oil and gas. The size of the mass transfer zone determines the oil displacement efficiency of gas injection. [ABSTRACT FROM AUTHOR]

Because of the unique advantages such as easy miscibility, high temperature resistance and so on, hydrocarbon gas flooding has proved to be a promising technology for enhanced oil recovery in deep reservoirs. In order to reveal the potential mechanism of miscibility and displacement of crude oil and hydrocarbon gas, an innovative two-dimensional physical field model is constructed by coupling Navier-Stokes equations and mass transfer equation. Accordingly, the effect of gas injection velocity and pore morphology on fluid transport and miscibility properties is investigated based on computational fluid dynamics approach. The simulation results demonstrated that the residual oil (RO) content is lower at low gas injection velocity than that at high gas injection velocity due to the better miscibility of fluids. For pore morphology, the RO content increases with increasing pore throat ratio and pore throat angle, which are not related to the gas injection velocity. The blocked pore structure has a negative effect on hydrocarbon gas flooding, resulting in the higher RO content. In addition, the influence of the pore throat length on the RO content is related to the gas injection velocity, which means the RO content increases at low gas injection velocity and decreases at high gas injection velocity with increasing pore throat length. [Display omitted] • A novel CFD model is constructed to describe the miscible displacement process. • The optimum injection velocity of hydrocarbon gas is selected to be 1 × 10−4 m/s. • The effect of different pore morphology on gas flooding is investigated. [ABSTRACT FROM AUTHOR]

The sealing capacity of the caprock of a gas-reservoir-type underground gas storage (UGS) directly affects the safe storage and efficient utilization of natural gas, especially during a high rate of multicycle injection-withdrawal under different pressure ranges. In order to determine the safety threshold, we propose an in-situ stress-fluid coupling simulation and evaluation method to analyze the dynamic breakthrough pressure of caprock, and use the caprock samples from three UGSs to explore the evolution of the sealing capacity at alternating stress and the critical sealing capacity. We find that the fatigue effect caused by multicycle injection-withdrawal can change the pore-throat structure and enhance the in-situ sealing capacity of the caprock. Increasing gas injection pressure leads to the decline of breakthrough pressure, and the failure of capillary sealing occurs before mechanical failure. Our results show that the sealing capacity of caprock changes dynamically under in-situ effective stress during injection-withdrawal periods, and the dynamic sealing mechanism reveals the risk timing of the caprock, and guides to release the full potential of an UGS. • A novel method to evaluate dynamic sealing capacity of UGS caprock is proposed. • Safe threshold of caprock is found under in-situ stress-fluid coupling condition. • Sealing capacity of caprock changes dynamically during injection-withdrawal. • Capillary sealing failure is more likely to cause leakage than mechanical failure. [ABSTRACT FROM AUTHOR]

Miscible gas injection is one of the most popular and applicable enhanced oil recovery method in oil fields. Minimum miscibility pressure (MMP) is an important parameter for an enhanced oil recovery process involving carbon dioxide or hydrocarbon miscible gas injection. There are many methods for measuring MMP but the most standard method for measuring MMP value in oil field gas injection process is slim tube method, which is very time consuming (4-6 weeks). Measurements of the interfacial tension of mixtures of a reservoir fluid and injection gas at various pressures have been proposed recently as an experimental method for predicting the minimum miscibility pressure (MMP) in an experiment called the vanishing interfacial tension (VIT) technique. This method is quantitative in nature and fast (2-3 days) with respect to slim tube method. VIT technique is based on the concept that the interfacial tension between the gas and crude oil phases at reservoir temperature must reduce to zero as these two phases approach the point of miscibility. The concept of zero interfacial tension at miscibility is, in turn, based on the well-accepted fact that the interface between the phases must vanish, as they become miscible with one another. Our results show the MMP value obtained from VIT method exceeds the slim tube MMP and miscibility pressure does not necessarily occur at zero IFT. Using zero IFT criteria cause MMP overestimation. In this study, by using the VIT and slim tube test, we measured the IFT in which slim tube MMP occur in VIT test for CO2-oil system for various types of reservoir oil. These IFT values are correlated by oil properties and test condition to help us measure the accurate value of MMP by using VIT method. This study shows VIT MMP is completely far from slim tube MMP. [ABSTRACT FROM AUTHOR]

Abstract: In coal permeability models, it is normally assumed that coal matrix pressure is equalized with the fracture pressure (local equilibrium). In this assumption, coal swells uniformly under constant confining (total) stress conditions commonly used in laboratory measurements. Under these conditions, a uniform swelling will not change the fracture aperture for a matchstick model where only two sets of vertical fractures cut through the whole matrix blocks. However, a uniform swelling changes both the fracture aperture and the spacing (the coal bridge swelling increases the fracture aperture while the matrix swelling changes the spacing only) for a fractured coal model, where fractures do not create a full separation between adjacent matrix blocks but where solid coal bridges are present, is used. Therefore, coal permeability remains unchanged for a matchstick model or increases slightly due to the coal bridge swelling under common laboratory conditions. These conclusions are directly contradictory with most laboratory observations in the literature. This direct contradiction suggests that the local equilibrium condition has not been achieved under common laboratory conditions. If this was the case, the current local equilibrium assumption based approach would be inappropriate for the analysis of laboratory measurements. In our previous studies, we introduced a concept of matrix swelling transition from local to global under stress conditions. In this concept, we recognized the fact that coal permeability evolves as a function of time from the initial equilibrium state (both matrix pressure and fracture pressure are equal to the initial reservoir pressure) to the final equilibrium state (both matrix pressure and fracture pressure are equal to the injection pressure). In this study, we extended this concept to the most complex situations where multiple processes (thermal transport, gas transport and coal deformation) are involved. Based on the concept of matrix swelling transition, we introduced a new concept of Critical Swelling Area that defines the relationship between swelling transition and coal permeability evolution. The combination of swelling transition and Critical Swelling Area concepts can explain why adsorptive types of gas injection reduces coal permeability in the early stage of the injection and may rebound later. [Copyright &y& Elsevier]

Abstract: Gas injection process is one of the most dependable techniques in enhanced oil recovery (EOR) methods. Multiple contact miscible injection is the method that has been well-established during last decades. Due to high sensitivity of local sweep efficiency to minimum miscibility pressure (MMP), this parameter has a key role in the gas injection process designing. Conventional tests to determine gas-oil MMP such as rising bubble apparatus and slim tube displacement are either costly or time consuming. Thus, it is necessary to utilize a quick, not expensive, and reliable method to determine MMP. In spite of several studies and various attempts to develop a model to predict MMP satisfactorily, there is no reliable and comprehensive MMP prediction model for CO2. Inductive machine learning algorithms have already been applied in various branches of science and engineering in an attempt to model several macroscopic properties through pattern recognition and generalization of results using a set of experimentally measured data. The objective of this study is to develop a comprehensive and intelligent model based on the radial basis neural network to predict of MMP for pure and impure CO2. To construct and evaluate the proposed model, about 147 data sets from literature and corresponding gas/oil compositional information were used. The results show the superiority of the proposed model in comparison with existing methods and predicted values are in good agreement with the experimental data. The other feature of the proposed model is its generalization capability. The proposed model provides accurate values for data sets that have not been introduced to the network previously. At the end, the outlier diagnosis is performed to determine the data sets that might be different from the bulk of the data present in the dataset. [Copyright &y& Elsevier]

Trapped annular pressure caused by thermal-expand liquid greatly threatens well integrity, so its mitigation is very necessary and essential. Nitrogen gas has been proved as an effective and low-cost mitigation measure for thermal-expanded annular pressure, but few methods are available to design the injection volume while this is vital for its mitigation reliability. Hence, this paper aims to develop a design method of the optimal injection volume of nitrogen gas to mitigate trapped annular pressure. The design method is based on volume consistency law and volume compensation effect. The proposed design method takes annular pressure increment and optimal injection volume as mitigation aim. A solving process is proposed according to volume increment and error iteration. An index is defined to evaluate mitigation efficiency. The results indicate the mitigation would fail once the injection volume is lower than the optimal injection volume, but over-surplus injection volume reduces mitigation efficiency. Optimal injection volume increases as production time and rate increase. The mitigation efficiency decreases and optimal injection volume increases as water depth increases. The optimal volume increases as the geothermal gradient increases. More nitrogen gas is needed as the mitigation aim of annular pressure increment decreases. The optimal injection volume increases as the expand-compress ratio increase while mitigation efficiency changes little. This design method can be applied in deep-water and HPHT wells. Detailed production data should be obtained and the geothermal temperature should be measured accurately. The extra injection volume is recommended to overcome the unexpected change of production plan and error of geothermal temperature measurement. The mitigation aim should consider the change of well barriers' strengths. The expand-compress ratio of annular liquid should be adjusted to prevent too large optimal injection volume. Compared with field experience or qualitative analysis, this method can provide an optimal injection volume as reference for the mitigation of thermal-expanded annular pressure, which can enhance the long-term reliability of mitigation by injecting nitrogen gas, thus promoting the popularization. • Design method to optimize the nitrogen gas injection volume. • New index to evaluate the mitigation efficiency. • Sensitivities analysis to provide reliable mitigation. [ABSTRACT FROM AUTHOR]