Water Injection Method Research Articles

Effect of Methane Solubility on Hydrate Formation and Dissociation: Review and Perspectives

Methane solubility in water is the foundation to make full sense of the mechanism of hydrate formation and dissociation. It is significant for realizing the safe and efficient exploitation of natural gas hydrate (NGH). This review discusses the calculation of methane solubility in gas–water and hydrate–water equilibrium systems, based on the hydrate phase equilibrium model theory, and the parameters used in the calculation process are described in detail. In addition, the influences of bubbles, capillary pressure, and salt on methane solubility are revealed. The difference in fugacity between the water phase and hydrate phase caused by the undersaturation of methane induces hydrate dissolution. Water injecting is a promising auxiliary method for hydrate exploitation, which will flush out the sand and gravel accumulated during the depressurization process. A novel hydrate exploitation method, which combines depressurization and a water injection method using double-split wells, is proposed. This novel method provides a new idea for efficient and sustainable exploitation of hydrate.

Influence of Water Injection Pressure and Method on Oil Recovery of Water Injection Huff and Puff in Tight Volcanic Oil Reservoirs

The water injection huff and puff (WIHP) technology is regarded as one of the important means to improve the recovery factor (RF) of tight volcanic oil reservoirs (TVORs), but the influence of water injection pressure (WIP) and water injection method (WIM) on the oil recovery effect of WIHP has been rarely reported. In this paper, we first collected the real full-diameter cores from a TVOR and then simulated the distribution characteristics of fractures and matrix pores after hydraulic fracturing of the reservoir through the combination and cutting of the cores. Finally, we used the large-sized physical simulation device for tight oil WIHP that can bear high temperature and high pressure and a nuclear magnetic resonance instrument to conduct experiments of five cycles of constant pressure WIHP (CWIHP) with WIPs of 25, 32.5, and 40 MPa and step-by-step pressure rising WIHP (SWIHP) (the WIP was 25, 30, 33, 37, and 40 MPa in order) and obtained the liquid production law and mechanism of tight volcanic rock (TVR) under CWIHP and SWIHP. The result shows that under the CWIHP mode, the RF of TVR has a good power-law-positive correlation with the WIP. However, with the increase of WIHP cycles, the RF of CWIHP always decreases rapidly. In the WIHP of TVR, the injected water mainly collects oil in large pores (the pore radius is greater than 0.1 μm), and the closer the area to the outlet end of oil production and the higher the fracture density, the higher the RF. SWIHP can also effectively improve the RF of TVR, but compared with CWIHP with a WIP of 40 MPa, the amount of recovered oil decreases relatively slowly with the increase of WIHP cycles. In the first two cycles of the five cycles of WIHP, the RF of CWIHP was higher, but from the third cycle, the RF of SWIHP begins to be greater, and the more the number of cycles of WIHP, the more obvious the advantage of SWIHP. When the number of WIHP cycles exceeds 5, the oil recovery effect and the economy of SWIHP are better. This study can provide a solid theoretical basis for the efficient development of WIHP in TVORs.

New insights into the beneficial use of coalbed-associated water: A feasibility study of co-produced water reinjection to coalbeds

Coalbed methane development is accompanied by the emission of a large amount of associated water that is rich in chemical substances. If the water is improperly treated, it poses a great threat to the ecological environment and human health. Therefore, it is of great importance to manage the produced water. In this paper, the feasibility of reinjecting coalbed production water into primary coalbed is studied. We applied the reservoir numerical simulation to study the effects of water injection method, water injection volume, water injection position and water injection timing on gas production. The results of a case study show that while injecting 16,869 m3 of water, it can also increase gas production by 15,032 m3. This study prove that the reinjection of produced water into original coalbed to achieve water storage can also increase gas production.

Height identification of water-permeable fractured zone based on synchronous movement in overlying strata

Height identification of water-permeable fractured zone (WPFZ) is one of the decisive influence factors for mining safety, especially in some specific conditions, such as mining under aquifer. In order to demonstrate the formation process of the WPFZ, the scaling model experiment is carried out. Through the analysis of movement and breaking in overlying strata, the WPFZ height is significantly affected by mining range, movement characteristics of key strata and its follow-up strata. Based on the research findings, a new theoretical method, " overlying strata synchronous movement method " (OSSM) is established to predict the WPFZ height. Taking 3301 mining face of Zhujiamao Coal Mine in China as the engineering background, the WPFZ height is estimated by OSSM. Additionally, the field detection is carried out by the downhole segmented water injection method combined with borehole camera method. By comparing the results of different methods, the accuracy of OSSM is verified and the WPFZ height is determined finally. What´s more, various methods for determining WPFZ height are evaluated.

Increasing Reservoir Recovery Efficiency through Laboratory-Proven Hybrid Smart Water-Assisted Foam (SWAF) Flooding in Carbonate Reservoirs

This contribution introduces a new hybrid enhanced oil recovery (EOR) method which combines smart water-assisted foam (SWAF) flooding, known as the SWAF process. The concept of applying SWAF flooding in carbonate reservoirs is a novel approach previously unexplored in the literature. The synergy effect of the SWAF technique has the potential to mitigate a number of limitations related to individual (i.e., conventional water injection and foam flooding) methods encountered in carbonates. In general, carbonate rocks are characterized by a mixed-wet to oil-wet wettability state, which contributes to poor oil recovery. Hence, the smart water solution has been designed to produce a dual-improvement effect of altering carbonate rock wettability towards more water-wet, which preconditions the reservoir and augments the stability of the foam lamellae, which has for some conditions more favorable relative permeability behavior. Then the smart water solution is combined with surfactant (surfactant aqueous solution or SAS) and gas injection produces a synergy effect, which leads to more wettability alteration, and interfacial tension (IFT) reduction, and thus improves the oil recovery. Accordingly, to determine the optimal conditions of smart water solution with an optimal SAS, we conducted a series of experimental laboratory studies. The experimental design is divided into three main steps. At first, the screening process is required so that the candidates can be narrowed down for our designed smart water using the contact angle tests that employ calcite plate (i.e., Indiana limestone or ILS) as the first filter. Following this, the optimum smart water solutions candidates are blended with different types of cationic and anionic surfactants to create optimum SAS formulations. Subsequently, a second screening process is performed with the aim to narrow down the SAS candidates with varying types of gases (i.e., carbon dioxide, CO2 and nitrogen, N2) via the aqueous stability test (AST), foamability test (FT), and foam stability test (FST). We employed the state-of-the-art R5 parameter tests for rapid and accurate results in place of the conventional foam half-life method. The most effective combination of SAS and gas candidates are endorsed for the core-flooding experiments. In this work, two types of crude oils (Type A and B) with different total acid and base numbers (TAN and TBN). Results showed that the greatest wettability changes occurred for SW (MgCl2) solution at 3500 (ppm) for both crude oil types. This demonstrates the efficacy of our designed SW in the wettability alteration of carbonates, which is also supported by the zeta-potential measurements. The concentrations of both SW (MgCl2) and CTAB-based surfactants considerably affect the stability of the SAS (i.e., up to 90% foam stability). However when in the presence of crude oil, for the same SAS solution, the foam stability is reduced from 90% to 80%, which indicates the negative effect of crude oil on foam stability. Moreover, the core floods results showed that the MgCl2-foam injection mixture (MgCl2 + CTAB + AOS + N2) provided the highest residual oil recovery factor of SWAF process of 92% cumulative recovery of original oil in core (OIIC). This showcases the effectiveness of our proposed SWAF technique in oil recovery from carbonate reservoirs. Additionally, changing the large slug of 5 PVs to a small slug of 2 PVs of smart water solution was more effective in producing higher OIIC recovery and in reducing the fluid circulation costs (i.e., thereby, lowering CO2 footprint), making the SWAF process environmentally benign. Thus, it is expected that under optimum conditions (SW solution and SAS), the novel SWAF process can be a potentially successful hybrid EOR method for carbonate reservoirs, having both economic and environmental benefits.

Mini Review on Stability and Formation of Emulsion During Injection of Smart Water in Fractured Carbonate Reservoirs

One of the most commonly used methods of enhanced oil recovery for use in carbonate reservoirs is the smart water injection method. Asphalt nitic compounds in the oil serve as natural surfactants and form water emulations in the oil when they are placed at the water and oil contact points. Besides, the salt contained in saltwater also contributes to the emulsion stability. Given that low-salty water and seawater are used for enhanced oil recovery, this process also increases the likelihood of the formation of W/O emulsions, so the assessment of the formation of W/O emulsions with low-salty water and seawater compounds and the stability of these emulsions due to the presence of different ions, can bring the conditions of formation of natural emulsions closer to actual events. Distinctive properties of injected water in order to form microemulsions of W/O and, the effect of concentration of ions in the injected smart water on the oil extraction efficiency have been investigated. Also, the formation of water emulsion in oil and its stability in oil sweeping in the formation in the case of smart water injection and its effect on the oil extraction efficiency have been discussed in full detail by presenting experimental results.

Determination of the stability of the water-fuel emulsions obtained by the method of water injection into diesel fuel for agricultural enterprises

When studying the possibility of using water-fuel emulsions (WFE) as fuels for diesel engines, researchers face the difficult task of obtaining an emulsion of a given quality. The most important requirement when using WFE as a fuel is their stability, which determines the safety of the emulsion, combustion efficiency and depends on many factors, such as: the difference in the densities of water and diesel fuel: the size of water droplets formed in the fuel; viscosity of water and fuel; surface tension of water and diesel fuel; the presence of surfactants that contribute to the stabilization of WFE. The purpose of this work is to study the stability of WFE obtained by the method of water injection into diesel fuel for efficient use in agriculture.

Research on well selection method for high-pressure water injection in fractured-vuggy carbonate reservoirs in Tahe oilfield

Carbonate fractured vuggy reservoir in Tahe oilfield belongs to fractured vuggy reservoir with strong heterogeneity. After a period of production, the elastic energy of the cave formation weakens caused insufficient liquid supply, It is faced with a series of problems in some single wells, such as low water injection efficiency, high water cut, short production period, and so on. The introduction of high-pressure water injection technology can greatly restore the productivity of single wells and improve reservoir recovery. It is one of the effective new technology to develop fractured vuggy carbonate reservoirs. At present, this technology is still in the initial stage, with no clear guide method that selecting wells for high-pressure water injection. Among them, the determination of the high-pressure water injection well selection method is particularly important for the development effect of a single well. Based on the analysis of the mechanism of high-pressure water injection and combined with the field data, this paper formulates the well selection method of high-pressure water injection from three aspects: Karst Characteristics, reservoir structure and reservoir parameters:①Karst geological data show the characteristics of oil-increasing substances such as many abnormal bodies around the well and wide lateral distribution; ②The reservoir structure has multiple sets of connected karst caves with connectivity potential; ③After the failure of conventional water injection, the fracture passage effect is poor and the energy of the remote well is insufficient. The independent high-pressure water injection development method can reduce the channel seepage resistance, expand the scope of the injected water, and realize increased production. Up to now, Tahe oilfield has used the method to implement high-pressure water injection 41 well, achieving an average single well cumulative incremental oil production of 3211 tons, with an effective rate of 85.4%, which has a satisfactory application value.

DATA PREPARATION FOR WATER INJECTION LABORATORY TEST

Oil production limit that is usually followed by decrease of oil productivity in old fields is a major problem and can't be avoided. This case happened when cumulative oil production has approached primary recovery method. Decrease of the action of native reservoir energy is followed by drastically increase of production of water (saturation almost 100 %). In relation to this, a method is needed to obtain the additional oil recovery. Water injection method is one of the solutions to solve oil production problem that happened in old fields. It is expected that by using water injection method, productivity and oil recovery in old fields can be improved. Water that is used as the fluid injected into reservoir to improve oil recovery is sea water. How far oil recovery can be improved by using water injection method, is determined by a laboratory research. Before carrying out water injection laboratory test; one has to know what are the main points that play important role in determining the optimal oil recovery by water injection method. These are: firstly, basic parameters, secondly, laboratory test for water flooding, thirdly, the displacement of water injection process, then, standard operational procedure, next, water injection to obtain the additional oil recovey, lastly, the results are plotted a figure and or tabulated as the result of water injection laboratory test is obtained. In relation to the mentioned above, it will be better to write a scientific paper of water injection laboratory test. This paper is written based on our experience in enhanced oil recovery research (EOR), supported by textbook, such ás American Petroleum Institute, Petroleum Production Handbook and Standard Corrosion and water Technology For Petroleum Producers. Therefore, the main focus of this paper is "Data Preparation for Water Injection Laboratory Test". Hopefully, the contents of this paper give precious and useful informations, that is extremely valuable not only for LEMIGAS as Research and Development Centre for Oil and Gas technology, but also for the oil industry of the Departement of Petroleum Engineering of the universities in Indonesia

DETERMINATION OF OIL RECOVERY FACTOR BY USING WATER INJECTION-LABORATORY TEST METHOD

Oil production limit that is usually followed by decrease of oil productivity in old fields is a major problem and can't be avoided. This case happened when cumulative oil production has approached primary recovery method. Decrease of the action of native reservoir energy is followed by drastically increase of production of water (saturation almost 100 %). In relation to this, a method is needed to obtain the additional oil recovery. Water injection method is one of the solutions to solve oil production problem that happened in old fields. It is expected that by using water injection method, productivity and oil recovery in old fields can be improved. Water that is used as the fluid injected into reservoir to improve oil recovery is sea water. How far oil recovery can be improved by using water injection method, is determined by a laboratory research. Before carrying out water injection laboratory test; one has to know what the main points that play important role in determining the optimal oil recovery by water injection method. These are: firstly, reservoir data, secondly, formation water and sea water analysis, thirdly, determination of physical fluid and rock properties, next, the displacement of water injection process to obtain the additional oil recovery and standard operational procedure. The main focus of this paper is "Determination of Oil Recovery Factor By Using Water Injection-Laboratory Test Method ". Hopefully, the contents of this paper give extremely valuable and useful information not only for LEMIGAS as Research and Development Centre for Oil and Gas Technology, but also for the oil industry or the Department of Petroleum Engineering of the universities in Indonesia.

Experimental measurement and clustered equal diameter particle model of permeability with methane hydrate in glass beads

Permeability is a key parameter for gas recovery from marine hydrate reservoirs. In this study, two kinds of BZ02 and BZ04 glass beads provided skeleton structure for methane hydrate synthesis in pressure vessel. Based on the observation of Scanning Electron Microscopy (SEM), the glass beads in the pressure vessel were considered to be equal diameter spheres and stacked in the form of orthorhombic. The water effective permeability KW of glass beads with different hydrate saturations (SH) were carried out by steady-state water injection method. Experimental results indicated that the presence of methane hydrate could cause significant decrease of KW, and the gas produced by hydrate dissociation would reduce the resistance of fluid flow in pores. The permeability ratio in the presence and absence of hydrate KrW was exponentially decreasing with the SH. A clustered equal diameter particle (CEDP) model was proposed that methane hydrate was clustered as equal diameter spheres and occupied in the center of pore space. The internal surface area of pore space with and without hydrate was simplified and the KrW-SH relationship was deduced in detail. When the saturation exponent n of BZ02 and BZ04 were recommended to be 10 and 18, respectively, the KrW in the CEDP model was fitted well with the experimental results. This model also revealed that the radius of glass beads and hydrate particles had a stronger effect on the KrW.

Experimental investigation of synergistic effect of non-ionic surfactant and smart water injection methods for enhanced oil recovery from carbonate reservoirs

In the water-based EOR methods, surfactants and smart water injection methods usually are employed to reduce the water-oil interfacial tension and altered the rock wettability, respectively. The main objective of this study is to employ the combination effects of non-ionic Surfactants (including KEPS 80 and Behamid D) and Smart water Flooding to alter the wettability and interfacial tension (IFT) towards the most favorable conditions. Contact angle, spontaneous imbibition, capillary pressure (P c ), and relative permeability (k r ) experiments were performed at various concentrations of the surfactants and ions using carbonate rock to identify the various mechanisms occurring in the Surfactant and Smart water (SSW) flooding process and also to determine the additional oil recovery. The optimum concentrations of surfactant and positive ions (Mg 2+ , Ca 2+ ) were also obtained. In this regard, concentrations of the employed ions were optimized for altering the carbonate rock surface wettability toward the water-wet. The optimum surfactant concentrations obtained by Mohammadshahi et al. (2019) were also used, in this study. After obtaining the optimum concentrations, some promising aqueous solutions were designed for Amott cell, relative permeability, and capillary pressure experiments using the combination of surfactant and ions. Amott cell tests were implemented for comparing the ability of different aqueous solutions such as base water (Brine with 30,000 ppm NaCl), surfactant solution, smart water, and SSW solution in the oil recovery from the cores. Subsequently, relative permeability and capillary pressure experiments were performed. The results of contact angle experiments depicted that brine containing 24,000 ppm NaCl +6000 ppm Mg 2+ yielded the lowest contact angle among the studied samples. In the spontaneous imbibition tests, the oil recovery was obtained to be 7.6% for the base water, 9.5% for the smart water (24,000 ppm NaCl + 6000 ppm Mg), 15.09% for the surfactant solution (1500 ppm KEPE in 30,000 NaCl), and 20.8% for the SSF water. The relative permeability and capillary pressure tests have demonstrated the change of residual oil saturation and wettability of rock while using the SSW method compared to other techniques (i.e. base water, surfactant injection, smart water flooding). Finally, the results indicated that the combination of smart water and surfactant injection could lead to a much higher recovery factor than each method alone. • The brine with concentrations of 6000 and 2000 ppm of Mg ++ achieved the highest improvement in wettability alteration towards the water wetness. • The kr measurement highlighted that smart water can slightly improve oil relative permeability and the surfactant, was not very successful in improvingkr. • The brine designed with optimum ion and surfactant incredibly improved the kroand highly reduced the krw compared to the cases where each of surfactant and smart water are used separately. • The Pc tests demonstrated that the smart-surfactant water has the most favorable Pc with the least residual oil saturation.

Simulation and Modelling of Water Injection for Reservoir Pressure Maintenance

Water injection has shown to be one of the most successful, efficient, and cost-effective reservoir management strategies. By re-injecting treated and filtered water into reservoirs, this approach can help maintain reservoir pressure, increase hydrocarbon output, and reduce the environmental effect. The goal of this project is to create a water injection model utilizing Eclipse reservoir simulation software to better understand water injection methods for reservoir pressure maintenance. A basic reservoir model is utilized in this investigation. For simulation designs, the reservoir length, breadth, and thickness may be changed to different levels. The water-oil contact was discovered at 7000 feet, and the reservoir pressure was recorded at 3000 pounds per square inch at a depth of 6900 feet. The aquifer chosen was of the Fetkovich type and was linked to the reservoir in the j+ direction. The porosity was estimated to be varied, ranging from 9% to 16%. The residual oil saturation was set to 25% and the irreducible water saturation was set at 20%. The vertical permeability was set at 50 md as a constant. Pressure Volume Temperature (PVT) data was used to estimate the gas and water characteristics.

Control of Water Inrush from Longwall Floor Aquifers Using a Division Paste Backfilling Method

Aiming at the problem of the safety mining problems of longwall paste filling working face under buildings on high confined water in the Daizhuang Coal Mine, the paste filling mining method was used. A series of theoretical analyses, numerical simulations, and field measurements were applied. The results showed that when the filling interval of the working face increases from 1.2 m to 3.6 m, no significant change is found in the depth of the perforated plastic zone of the floor strata. According to the types of water-conducting cracks in the floor strata of the working face 11607, the floor strata are divided into the floor intact area, the structure developed area, and the floor weak area. Based on that, the measures for preventing and controlling the floor failure in the paste filling working face are proposed. Furthermore, the failure depth of the floor of the test working face was detected by the on-site water injection method, and the results showed that the maximum failure depth of the floor of the test working face was about 3 m.

Research and practice on optimal design method of the oilfield water injection system pipeline network

The efficiency of oilfield water injection system is generally low and energy consumption is high. With the deepening of oilfield exploitation, the water cut of the oilfield is increasing, the power consumption of the water injection system is increasing year by year, the oilfield exploitation cost is increasing, and energy conservation and consumption reduction are very important. In order to improve oilfield water injection efficiency and reduce water injection energy loss, this paper puts forward the pipe network optimization design method of partial pressure water injection, establishes the mathematical model of partial pressure water injection pipe network and throttling loss calculation model, compiles the calculation software of partial pressure water injection mathematical model, optimizes the partial pressure interval, calculates the partial pressure points, effectively reduces the energy loss of water injection system and improves the efficiency of water injection system.

Evaluation and extension of the load and fuel flexibility limits of a stratified downdraft gasifier

The small-scale biomass gasifiers' application for CHP in conventional households is still inhibited by their inflexible operating conditions, which do often not meet the user's desires of yielding varying loads and switching between any available fuels. Thus, the present work aims to identify the gasifier's flexibility limits by investigating sudden steps in load and fuel water content in a woodchips-driven, stratified downdraft gasifier with a 90-kW nominal fuel load. In contrast to former work, the focus was set on the transient processes, during which the product gas composition and the gasifier bed temperatures were continuously monitored. The evaluations revealed that the gasifier produces a continuously high and almost load independent product gas quality in the range of ±20% of the nominal load, even throughout sudden load changes. Steps of 8 m% fuel water content from dry to wet fuel turned out to be the maximum manageable step size without additional measures. Switches from wet to dry fuel required the previously introduced methods of exhaust gas recirculation and water injection. These methods successfully enlarged the allowable step to over 8 m% fuel water content. These promising results will allow a future more versatile and user-optimized operation of stratified downdraft gasifiers.

Investigation of Water Injection Influence on Cloud Cavitating Vortical Flow for a NACA66 (MOD) Hydrofoil

Re-entrant jet causes cloud cavitation shedding, and cavitating vortical flow results in flow field instability. In the present work, a method of water injection is proposed to hinder re-entrant jet and suppress vortex in cloud cavitating flow of a NACA66 (MOD) hydrofoil (Re = 5.1 × 105, σ = 0.83). A combination of filter-based density corrected turbulence model (FBDCM) with the Zwart–Gerber–Belamri cavitation model (ZGB) is adopted to obtain the transient flow characteristics while vortex structures are identified by Q criterion & λ2 criterion. Results demonstrate that the injected water flow reduces the range of the low-pressure zone below 1940 Pa on the suction surface by 54.76%. Vortex structures are observed both inside the attached and shedding cavitation, and the water injection shrinks the vortex region. The water injection successfully blocks the re-entrant jet by generating a favorable pressure gradient (FPG) and effectively weakens the re-entrant jet intensity by 46.98%. The water injection shrinks the vortex distribution area near the hydrofoil suction surface, which makes the flow in the boundary layer more stable. From an energy transfer perspective, the water injection supplies energy to the near-wall flow, and hence keeps the steadiness of the flow field.

A relative assessment of emulsification and water injection methods to mitigate higher oxides of nitrogen emissions from biodiesel fueled light-duty diesel engine

In-cylinder emission control strategies based on fuel modifications have gained considerable interest in diesel engine applications because of the potential to simultaneously reduce the oxides of nitrogen (NOx) and soot emissions. There is a renewed interest to replace diesel with carbon-neutral biodiesel to mitigate global warming potential from the transport sector. Further, the bi-directional NOx-soot trade-off problem in conventional diesel combustion has been reduced to a unidirectional higher NOx problem with biodiesel. The efficacy of utilizing emulsification and water injection methods to mitigate the higher NOx emissions with biodiesel is investigated in the present work. The water to biodiesel ratio for the emulsion and injection methods was kept similar at 3%, 6%, and 9% by mass of fuel. Experiments were conducted in a light-duty diesel engine at rated speed, varying load conditions with neat biodiesel, biodiesel-water emulsion, and biodiesel water injection. Biodiesel-water emulsions prepared using a combination of non-ionic surfactants, Span 80 and Tween 80, were stable for over four months. The average droplet size measured using the Dynamic Light Scattering (DLS) technique was 305 nm, 334 nm and 443 nm with 3%, 6% and 9% emulsion, respectively. The intake manifold was modified to include a low-pressure port fuel injector (PFI) to enable water injection. The pulse width of the PFI injector was controlled using a National Instruments PFI module to vary the injected water mass per cycle. The results obtained with biodiesel-water emulsion and biodiesel water injection were compared with neat biodiesel as a reference fuel. The ignition delay time increased, and the peak pressure was reduced with biodiesel-water emulsion. The combustion duration was reduced with emulsion indicating faster burning characteristics. The engine brake thermal efficiency increased with emulsion with a maximum increase of 6%, and there was a 10% reduction in the brake-specific fuel consumption. Both emulsion and water injection result in a simultaneous decrease in NOx and smoke emissions. The drop is significant with emulsion, with a maximum reduction of 40% and 34% in the NOx and smoke emissions, respectively. Overall, the present study shows that biodiesel-water emulsion has a higher potential to achieve a simultaneous reduction in NOx and smoke emissions with better engine performance.

Influence of water injection on broadband noise and hydrodynamic performance for a NACA66 (MOD) hydrofoil under cloud cavitation condition

Cavitation and its induced noise have negative effects on the hydrodynamic performance of underwater devices such as marine propellers. In this paper, a new flow control method of water injection is proposed to investigate its influence on the flow field around NACA66 (MOD) hydrofoil under the condition of cloud cavitation (Cavitation number σ = 0.83, Reynolds number Re = 5.1 × 105). The density corrected turbulence model (DCM) combined with Zwart-Gerber-Belamri cavitation model (ZGB) is used to simulate the hydrodynamic performance and the pressure fluctuation, while the dipole noise and quadrupole noise are calculated by Broadband noise source models. The numerical results are in good agreement with our previous experimental observations. The results are all compared with those for the original hydrofoil without water injection and show that the injected water noticeably weakens the severe pressure fluctuation on the hydrofoil suction surface and reduce the volume of cavitation by 72.89%. The water injection also performs well on drag reduction, which reduces the drag coefficient by 17.9%. The dipole noise on the hydrofoil surface is effectively suppressed, and the Curle Acoustic Power (AP) for over 50 dB is decreased by 28.99%. It is also found that the water injection significantly reduces the region of over 45 dB for Proudman AP by 46.21%. The water injection improves the stability of the flow field by means of providing extra energy, blocking the re-entrant jet, hindering the evolution process of turbulence and weakening the impact of the fluid on the hydrofoil wall.

A Tracer Streamline Practice for Re-Evaluation Waterflood Pattern to Introduce a Cyclic Water Injection Scheme

Waterflood introduces in the oil field a couple of years ago. Several waterflood schemes have been implemented in the fields to get the best incremental oil, such as peripheral injection, pattern waterflood, and etcetera. Many waterflood schemes are not working properly to boost the oil recovery due to unpredicted and unexpected water tide array. Then, the tracer practice started to be used for getting a better picture of the transmissibility reservoir as well as the direction of water pathway. This practice honors the parameters, such pressure, water cut, GOR, and rates. The streamline modeling is used to map the tracer, and it concludes that the selection of location of the injector should be based on the highest oil recovery achieved. Subsequently, the cyclic water injection method is one alternative. Apparently, this approach yields a quantify incremental recovery. This research utilizes the pressure different approach to figure out the route of water in the formation. The inter-well tracer technique in this modeling study is a tool to review communication between injectors and producers in the existing pattern. Many scenario should be tried to find the best options for the new pattern opportunities. In parallel, a innovative scheme of waterflood technique should be implemented too for escalating oil recovery. The stream pathway observes a new potential of the waterflood scheme. It is called "cyclic injection" scheme. The novelty of this approach is the ability to solve the poor sweep efficiency due to improper pathway of water influx in the oil bearing".