Water Injection Method Research Articles

Impact of the Microporous Layer on Gas Diffusion Layers with Patterned Wettability I: Material Design and Characterization

Gas diffusion media is one of the main components affecting the water management in polymer electrolyte fuel cells, which is key for a high and stable performance. Building up on our previously designed gas diffusion layers (GDLs) with patterned wettability, we included in this study customized microporous layers (MPLs) with the target to enhance the effect of hydrophilic water pathways and reduce mass transport losses. The MPLs were modified by introducing “weak points” using electron induced radiation grafting or local mechanical perforation, in order to canalize the water injection to the hydrophilic pattern of the GDL. We describe the techniques used for gas diffusion media modification, their limitations and their influence on water distribution. We also study in detail the impact of different water injection methods on water distribution, in particular comparing capillary pressure water injection to electrochemical water production. The important differences observed between these two methods, were attributed to the absence of hydraulic connection between the water injection points in the latter case. Although the ex situ characterization shows that the local MPL modifications were successful, the targeted canalization of water injection was not observed, calling for future MPL modifications with an improved lateral transport.

ТЕНДЕНЦИИ РАЗВИТИЯ НЕФТЯНОЙ ОТРАСЛИ В РОССИЙСКОЙ ФЕДЕРАЦИИ

In the structure of the gross domestic product of the Russian Federation, industry accounts for about 36 %, including: manufacturing – 18 %, mining - 14.8 %, production and distribution of electricity, gas and water - 3.1%, etc. In fact, about 70 % of oil production in the country belongs to two federal districts: Ural (50 %) and Volga (19 %). Oil production in the Russian Federation for the period from 2010 to 2018 increased by 11%, exports increased by 5.5 %. About 47-49 % of the total volume of oil produced in the country is exported. The level of labor productivity in mining during the studied dynamics turned out to be three times higher than in manufacturing, and 3.5-5 times higher than in the distribution of electricity, gas and water. Currently, various methods of oil production are used, including: using methods of artificial stimulation of the reservoir (42.2 %), using water injection (34 %), using physicochemical methods, including gas (7.5 %) ), using hydrodynamic (7.3 %), thermal (0.7 %) and new methods (8.3 %). At the same time, oil production using the water injection method in the country decreased by 9.8 %, using artificial stimulation methods decreased by 3.8 %, and using hydrodynamic methods, oil production decreased by 1.2 %. In recent years, there has been a growing trend in the use of thermal (2.2 times), physicochemical (+ 27.8 %) and other new oil production methods (+ 32.3 %). The depth of oil refining in the Russian Federation increased from 71.2 % in 2010 to 82.2% in 2018. The novelty of the work lies in the fact that we included both economic and socially significant factors in our correlation and regression analysis. In addition, we found that the key factors influencing the formation of gross domestic product are the level of oil prices, export volumes and industrial production volumes.

Heterogeneity properties of methane hydrate formation in a pilot-scale hydrate simulator

The accumulation and distribution features of gas hydrates are the significant issues affecting the hydrate resource assessment, the hydrate dissociation behaviors, and the risk evaluation of hydrate exploitation. This work aims to investigate the methane hydrate formation process by numerical simulation based on the experimental data in a pilot-scale hydrate simulator. Methane hydrate is formed by multi-step water injection method. Simulation results of the evolutions of the temperature, the system pressure, the mass of formed hydrate, and the remaining mass of methane gas are in good agreement with those of the experiment. The spatial distributions of the gas, water, and hydrate are all found to be very heterogeneous in the vessel during the whole simulation period. The free methane gas tends to accumulate in the pores near the upper boundary because of buoyancy and diffusion effects, while the liquid water shows an opposite trend under the gravity and capillary effects. Finally, the formed hydrates are found to be mainly accumulated in the upper area of the reactor due to the more favorable gas-water contact conditions, and the hydrate saturation decreases from the roof to the bottom layer by layer. In addition, the inhomogeneity of methane hydrate is more pronounced along the vertical direction than the horizontal one during the formation process. Generally, the heterogeneous formation of gas hydrate is dominated by the migration processes of gas and water in porous media. Moreover, the selected kinetic model is also important for the description of the heterogeneous hydrate formation behavior.

Dynamic and static pressure combined water injection and dust reduction technology in fully mechanized top coal caving face

In order to solve the problem of high dust concentration in fully mechanized top-coal caving face with difficult wetting and high dust production, a combined water injection test of “long period static pressure, alternating dynamic static pressure and static pressure in stress-affected zone” was carried out in Wangjialing Coal Mine with the engineering background of fully mechanized top-coal caving face in 20107 and combined with the previous water injection test and field actual situation. By comparing and studying the wetting and dust-reducing effects of different water injection methods and borehole spacing, the water injection process parameters suitable for this kind of coal seam are obtained. The field practice shows that the wetting radius can be increased to 3 m by the combined water injection process. In the water injection area with 5 m drilling spacing, the total dust removal efficiency can reach 57% and the respirator dust removal efficiency can reach 70%. It can effectively solve the dust hazard problem of the working face, and the effect is re-markable.

Analysis of coiled tube waste heat storage tank under water injection

Abstract In this paper, attempts are made to increase the heat transfer in the hot water storage tank via water injection into the storage water. With new water injection system, increasing mixing effect especially around the coiled tube was aimed. The experimental study was conducted to obtain the effect of different velocity (0.03 ≤ V ≤ 1.3), different flow pressures and different outlet hole diameters on dimensionless temperature distribution, Nusselt number and second law efficiency. The results showed, depending on the velocity, water injection into the tank provided an increase in the range of 15–60% for the Nusselt number. The highest enhancement in average Nusselt number occurred when the V = 1.3 m/s. The highest decrease in the second law efficiency was observed around 5% for the 1 mm hole diameter. In addition, the water injection method compared with air bubble injection method in the literature. The comparison indicated, average Nusselt number of the air bubble method 0.6% higher than the water injection method but second law efficiency and average dimensionless temperature 1.7% and 25.7% respectively less than the water injection method.

Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

Assessment of hydrogen-based dual fuel engine on extending knock limiting combustion

The key intention of this study is to effectively utilize the Madhuca longifolia oil (ML) in a diesel engine. Dual fuel mode is one of the most promising research concepts in diesel engine arena that intends to improve the performance and reduce the smoke emission. In this work, hydrogen was injected into intake manifold as primary fuel whereas the ML was injected directly into the cylinder as pilot fuel in the setup that had a single cylinder constant speed diesel engine. The performance of the engine was increased from 25% with neat ML operation to 28.5% with hydrogen-based dual fuel mode. However, the hydrogen combustion resulted in knocking, thus it had a direct impact on BTE as well. Water Injection (WI) method was used to extend the knock limit and to increase the hydrogen energy share. The researcher observed 18% and 76% improvements in BTE and smoke emission from 5% of water using mass fraction along with hydrogen. The hydrogen energy share was increased from 6% to 8.5% with 5% WI. A distinctive attempt i.e., addition of ALPG was attempted on behalf of offsetting the knock and increasing the hydrogen energy share. ALPG was inducted along with hydrogen in the range of 1, 1.5 and 2 l/m. Interestingly, 24% improvement in BTE was noted when 1.5 l/m of ALPG was inducted. In addition to this, 83% smoke emission was reduced remarkably. Overall performance of the engine was improved by extending the knock limit, WI and ALPG induction along with hydrogen.

Prediction of scale formation according to water injection operations in Nosrat Oil Field

An oil field formation contains minerals such as sulfate, carbonate and calcium. The water injection method is widely used to imbibe oil in the oil reservoir. In this method, the incompatibility between injection water and reservoir water creates serious problems. As the water moves inside the oil reservoir and the oil well, the solubility value of soluble mineral changes according to the environmental conditions. Change in solubility of solutes in reservoir water can precipitate mineral solids and decrease production. In this study, the formation of sulfate and carbonate sediments in water injection operation is predicted using Stimcade2 software in Nosrat Oil Field. Based on the results of this study, barium sulfate, calcium carbonate and magnesium carbonate may form in the Nosrat Oil Field.

The influence of the water injection method on two-well-horizontal salt cavern construction

With high construction efficiency and large usable volumes, underground TWH caverns in rock salt formations provide optimal storage for large-scale compressed natural gas. Previous studies of SWV cavern construction indicate that different water injection methods will result in different leaching rates and will therefore form different cavern geometries. Therefore the influence of the water injection method on the TWH cavern construction process and geometries were thoroughly evaluated in this study. Based on the leaching numerical simulation code TWHSMC V2.0, we conducted a series of simulation experiments. The results illustrate that under the same water injection rate, the cavern construction speed of the alternate injection method is faster than the unidirectional injection method. Using the unidirectional method will form asymmetrical triangular pyramidal caverns. In contrast, using the alternate method will form symmetrical elliptical cone caverns. Under repeated alternating “Injection” and “Withdrawal” operations, the larger the flow rate, the shorter the cavern construction time, and the smaller the H/L ratio coefficient, as well as the closer the cavern geometry is to the horizontal cavern. Thus, during construction of a TWH-cavern in thinly-bedded rock salt (halite) deposits, repeated and alternating injections and withdrawals with high flow rates are necessary.

Numerical study of the impact of water injection holes arrangement on cavitation flow control.

A method of water injection to flow field using distributed holes on the suction surface of hydrofoil is presented in this article to control cavitation flow. Modified renormalization group k-ε turbulence model is coupled with full-cavitation model to calculate periodical cavitation patterns and the dynamic characteristics of the NACA66(MOD) hydrofoil. Water injection is found to be highly effective for cavitation suppression. The cavitation suppression effect of distributed regulation of jet holes and porosities along three-dimensional spanwise hydrofoil is also investigated. The appropriate porosities of single row spanwise jet holes and optimal jet position of double row jet holes are revealed for both cavitation suppression and good hydrodynamic performance. Double row jet holes setting in forward trapezoidal arrangement shows great potential for cavitation suppression and hydrodynamic performance. This research provides a method of water injection to flow field to actively control cavitation, which will facilitate development of engineering designs.

Effects of TiO2, MgO and γ-Al2O3 nano-particles on wettability alteration and oil production under carbonated nano-fluid imbibition in carbonate oil reservoirs

Wettability is an important factor in the reduction of oil saturation, especially when the imbibition process is the main mechanism of production from the reservoir. This process is activated towards oil production, which tends the wettability of the rock to hydrophilicity, and the rock’s hydrophilic intensity on this parameter is very effective. Both carbonated water and nanofluids injection methods are effective methods for altering the carbonate rock wettability to hydrophilicity, but stronger hydrophilicity can be achieved by combining these two methods with respect to obtain the greater dissolution of carbon dioxide in nanofluids in comparison to saline water and increase the oil production under imbibition considerably. In this study, wettability alteration based on contact angle experiments using TiO2, MgO and γ-Al2O3 nanoparticles in carbonated water were investigated and the oil production was estimated using imbibition experiments and the optimum carbonated nanofluids for the minimum contact angle was evaluated. In fact, the main goal in this study was to correct the carbon dioxide injection and increase its solubility in saline water by dispersed nanoparticles in order to alter the carbonate rock's wettability towards a highly hydrophilic and subsequently increasing the oil production under the imbibition. Finally, the lowest contact angle values for carbonated TiO2, γ-Al2O3 and MgO nanofluids at 13.79 MPa and 80 °C and salinity levels of 10 times water dilution were obtained as the base fluid, which decreased, respectively, by 55, 26 and 17% compared to carbonated water in the absence of nanoparticles, the amounts obtained, especially for nanofluids containing TiO2 nanoparticles, are placed in a highly hydrophilic zone. In addition, carbonated nanofluids containing TiO2, γ-Al2O3 and MgO nanoparticles recovered by 75.93, 71.25 and 64.98 percent of primary oil under the imbibition mechanism at 13.79 MPa and 80 °C and salinity of 10 times of dilution of base fluid, which shows an increase of about 30, 25 and 18%, respectively, relative to the oil production under imbibition with nanoparticle free carbonated water, respectively.

Surface Probing with Streaming Potential: The Polymer Flooding Scenario

The first experimental evidence of polymer adsorption in natural carbonates obtained from streaming potential measurements is presented. The surface probing of the Estaillades core was realized in a highly saline environment with I ~ 3 M similar to formation water naturally found in some oil reservoirs, which are typical target for enhanced oil recovery (EOR) by Smart Water Injection Methods (SWIM) and Hybrid SWIM. A highly sensitive setup with an exceptional signal-to-noise ratio even at high salinity, allowing to discriminate voltage fluctuations below 0.1 mV, was used to probe the streaming potential coupling coefficient. The injection of partially hydrolyzed polyacrylamide Flopaam 3130S was followed by chase flooding with formation water for several pore volumes, to assure that any changes measured after the polymer flooding are due to the retained polymer. We show that the streaming potential coupling coefficient changes sign after polymer adsorption. This result not only is an unambiguous evidence for polymer adsorption but has implications on chemical EOR scenarios that need to consider wettability changes due to inversion of surface charge.

Simulation of low and high salinity water injection method to determine the optimum salinity

Investigating the enhanced oil recovery leads to optimal production, protection and reduction of lateral impacts. Low salinity water injection (LSWI) is one of the significantly improved oil recovery (IOR) techniques for changing the amount of wettability in the carbonate fractured reservoirs. The utilization of this methodology in terms of high efficiency in displacing light crude oils to the medium-gravity crude oils, water sources availability and its sustainability for pushing the oil which leads to appropriate economic occasions, are being compared with other IOR/EOR techniques. In this study, the best injection modelling pattern is based on the highest rate of recovery factor. Comparison of “high and low salinity water injection method” with “pure water injection method” is performed in an oil reservoir. Overall, analyzing the sensitivity on the high and low salinity according to the moderately low recovery factor of high and low salinity among the injection scenarios illustrates the low sensitivity of this parameter on a fractured carbonate reservoir. By reviewing different scenarios, it could be demonstrated that if the water injection could be applied to the reservoir from the preliminary times of production, the recovery factor rate would be increased. Thereby, higher appropriate efficiency and better supplement have resulted. Pure water injection has a high recovery factor than salty water injection. By the way, these two methods have little differences in calculating recovery methods. Besides, this parameter is significantly depended on wellhead equipment properties, safety factor and economic issues (water production).

Oil recovery by low-salinity polymer flooding in carbonate oil reservoirs

Low-salinity polymer flooding (LSPF) is a promising enhanced oil recovery (EOR) method with a synergetic effect of combining the polymer injection and low-salinity water injection methods. To maximize EOR efficiency, it is essential to design the compositions of low-salinity water appropriately while considering polymer properties. The goal of this study was to investigate the effects of pH and potential determining ions (PDI; SO42− and Ca2+) in low-salinity polymer solution used as injection water on oil production when applying LSPF to a carbonate oil reservoir. From the experimental results, the SO42− ions interfered with polymer adsorption in the neutral SO42--containing polymer solution, while the adsorption was greatly promoted in the acidic conditions, reducing the permeability. In the Ca2+-containing polymer solution, the adsorption trend was different from the SO42− case. In examining the wettability alteration, the change in residual oil saturation between after-LSWF and after-LSPF (ΔSor) was greater with higher SO42− concentration under the neutral state. This means that the end-point of the relative permeability-saturation curves shifted to the right, indicating that wettability was altered to a more water-wet state. Under acidic conditions, ΔSor was smaller compared to the neutral state due to greater polymer adsorption. A small ΔSor was observed when Ca2+ ions were contained in the neutral polymer solution, causing less wettability alteration. This is because Ca2+ ions are involved in precipitation as well as adsorption, thus reducing the permeability more than SO42--containing case. We confirmed these changes also in the contact angle analysis. In conclusion, since SO42− ions interfered with adsorption of polymer molecules and adsorption occurred less in the neutral state, a neutral polymer solution with high SO42− ion concentration as an injection water provided the highest enhancement in the EOR efficiency.

Study on Failure Law and Failure Depth of Floor in Deep Mining

Aiming at the problem of floor failure in deep mining nowadays, taking a certain working face of a deep mine in Shandong, China as the engineering background, the method of numerical simulation and similar simulation are used to study the failure law of floor in the mining process. The numerical simulation results show that the vertical stress increasing area of deep mining is “bubble-shaped”; shearing stress is generally “butterfly-shaped”; plastic zone distribution is “rectangular-shaped”, shearing failure is dominant in the surrounding and middle parts, the range of plastic zone decreases with the increase of the depth from the coal seam; when the working face is advanced to 100 m, the floor failure depth reaches 30 m and tends to be stable state no longer increase. The similar simulation results show that that with the increase of floor rock depth, the stress value decreases, and the stress propagation of floor rock mass to deep depth has a lag effect, and the lag time is longer with the increase of depth. Finally, the depth of floor failure in working face is measured by the method of subsection water injection in the downhole. The measured result shows that the maximum floor failure depth is 31.6 m, which is similar to the result of numerical simulation. The two results were verified each other. The numerical simulation can provide a reference for the study of floor failure law in similar mines, and it can also provide some guidance for the prevention and control of water inrush in deep mines.

Injection of in-situ generated CO2 microbubbles into deep saline aquifers for enhanced carbon sequestration

Carbon sequestration into deep saline aquifers has been considered a promising technology for mitigating heavy atmospheric carbon dioxide (CO2) concentration. When gaseous CO2 is continuously injected into these aquifers, resident brine near a wellbore area is rapidly evaporated while precipitating significant amounts of salt at pores, thereby damaging the aquifer media unfavorable for subsequent CO2 injection. In addition, the continuous injection of CO2 at a large volume significantly hinders dissolution of CO2 into brine. In this study, we propose a new method of sequential water injection with gaseous CO2 for in-situ generation of micro-sized CO2 bubbles that minimizes the brine drying-out and simultaneously accelerates CO2 dissolution. We observed that, with this method, a partial volume of CO2 dissolves effectively into the co-injected water during pumping, thereby decreasing the rate of brine drying-out at pores. Another benefit of sequential injection is the significantly increased rate of CO2 hydration induced by the large surface-to-volume ratio of tiny bubbles at micro to nanoscale. To further accelerate CO2 hydration, we investigated reactive dynamics of bubble-driven CO2 hydration at different frequencies of sequential injection and pH levels of the solution. Operation at a higher frequency with higher basicity proved to be the most effective in decreasing the bubble size and therefore accelerating CO2 hydration into brine, which is a more feasible CO2 storage plan.

Influence of Eccentric Water Injection on Shaft Wall Stability

The approach of water injection is an effective way to prevent shaft failure. However, due to the building existence or the need for adding a single water injection hole, the symmetric arrangement of the water injection borehole becomes more and more difficult. Therefore, eccentric water injection becomes a water injection method that has to be used. In this paper, the numerical simulation method was used to study the influence of eccentric water injection on the shaft stability by setting the water pressure and injection position distance from the shaft. The results showed that the larger the water injection pressure was, the smaller the vertical compressive stress on the shaft wall was and the larger the strata uplift was. The farther the injection position from the shaft was, the larger the vertical compressive stress on the shaft wall was. It also showed that the farther injection position distance from the shaft was, the weaker the lateral transfer of water pressure was, and the larger the vertical pressure difference between the water injection side and the opposite side was. Combined with the simulation results and the pre-industrial tests, the optimal water injection engineering parameters were determined as injection pressure of 0.3 MPa with injection position 50 m away from the shaft.

Application of horizontal wells to the oceanic methane hydrate production in the Nankai Trough, Japan

Due to the complicated reservoir conditions in the oceanic methane hydrate (MH) reservoir in the Nankai Trough, Japan, the gas production rate for the economical extraction had not been achieved during the current field production tests in 2013 and 2017 using vertical wells. Therefore, this study aimed at the application of the horizontal wells to the oceanic MH production in the Nankai Trough. Since there existed three sub-hydrate-bearing layers with different physical properties (i.e., initial hydrate saturation, porosity, and intrinsic permeability) in the reservoir, some possible well configurations including single horizontal well patterns and dual horizontal well patterns were designed based on a multilayered geological model simulating the real oceanic MH reservoir in the Nankai Trough. Then, the effectiveness of these two kinds of well designs was verified via long-term simulations of the oceanic MH production by simple depressurization, and the optimal well configuration for each design was recommended. Furthermore, a combined method of depressurization and hot water injection was also tested based on the dual horizontal well pattern, and the sensitivity analyses indicated that a favorable gas production rate of 8.64 × 105 m3/day could be obtained within the first year, even under a relatively low injection temperature of 40 °C and a relatively small injection rate of 2 kg/s/m of well.

Method of moderate water injection and its application in ultra-low permeability oil reservoirs of Yanchang Oilfield, NW China

Abstract To explore the method of improving development effect and solving the problem of water breakthrough and water out for ultralow permeability fractured reservoirs, an indoor evaluation method of dynamic imbibition for fracture-matrix system was established taking the Chang 8 reservoir in southern Yanchang Oilfield as a research target. Key factors for the imbibition effect were obtained, an imbibition's rate expression was obtained, a model considering the double effects of imbibition-displacement was built and optimal injection and production parameters for the research area were obtained as well. The results show that an optimum displacement rate that maximizes the oil displacement efficiency exists in the water displacing oil process, and the optimal displacing rate becomes smaller as the permeability decreases. The imbibition displacement efficiency increases as the reservoir quality index and water wettability index of rock become bigger. But the larger the initial water saturation or oil-water viscosity ratio is, the smaller the imbibition displacement efficiency is. The optimal injection-production ratio for the Chang 8 reservoir of southern Yanchang Oilfield is 0.95, and the predicted recovery is 17.2% when the water cut is 95%, it is 2.9% higher than the recovery of conventional injection-production ratio 1.2. By using the moderate water injection technique based on the double effects of imbibition-displacement mechanism, the water injection development effect for the ultra-low permeability fractured reservoirs can be improved significantly.

Heat-assisted production strategy for oceanic methane hydrate development in the Nankai Trough, Japan

The heat-assisted production strategy was considered to be an effective approach for the oceanic methane hydrate (MH) development. In this study, the combined method of depressurization and hot water injection was applied to the multilayered MH reservoir in the Nankai Trough, Japan, by using dual horizontal wells. Some possible well placements by placing the two wells in the same sublayer and different sublayers were designed in this study, and their effectiveness on the gas recovery enhancement was verified via long-term simulations of the oceanic MH production. It was found that when the two wells were placed in different sublayers, with some horizontal distance and the injection well locating above the production well, a favorable average gas production rate of 2.0 × 106 m3/day could be obtained, and was up to 100 times of that confirmed during the 2013 offshore MH production test in the Nankai Trough (2.0 × 104 m3/day), which indicated the high efficiency of the method proposed in this study. Furthermore, sensitivity analyses on the well locations suggested that the production well should be placed near the bottom of the hydrate reservoir, and a mild well spacing should be carefully determined, both to promote the heat transfer in the reservoir by making the maximum use of the injected hot water, and obtain a higher gas production rate.