Minimum Injection Rate Research Articles

Study on Microscopic Water Flooding in Porous Carbonate Reservoirs by Numerical Simulation

The study on the flow behaviors of oil and water two phases in porous media and their influencing factor is very important to adjust the porous carbonate reservoir development strategy and enhance the oil recovery. Based on the CT (computed tomography) scanning of real carbonate reservoir core sample, the micropore structure was reconstructed, and the effects of different factors (injection rate, oil-to-water viscosity ratio, and contact angle) and secondary development methods (higher injection rate and water displacement direction optimization) on the flow behavior of oil and water two phases were explored by numerical simulation in this paper. It is found from the study that the pores in the porous carbonate reservoirs have good structural connectivity. During the displacement process, the oil-water interface mainly resides at the pore throat junction with a large change of pore size, and the Haines jumps exist in the oil-water movement; the areal sweep efficiency of the water phase is jointly affected by the viscosity effect, interfacial tension, pore structure, and injection rate. Under the minimum injection rate and oil-to-water viscosity ratio, the maximum oil recovery can be obtained, and the oil recovery is 52.62% and 57.01%, respectively. The recovery efficiency and swept area are better in a water-wet system than oil-wet system. During the secondary development, the remaining oil is hardly displaced even with the injection rate increased by a factor of 50, and it shows improvement after 250 times of initial injection rate. Changing the position of water inlet and the produced fluid outlet results in better recovery since the remaining oil near the new inlet and outlet can be effectively produced.

Design of Micropipette System with High Precision for Small Enzyme Immunoassay Analyzer

A small auto micropipette system is developed to improve the reliability and accuracy of the automatic enzyme immunoassay analyzer’s microscale pipetting system. A sophisticated injection mechanism is designed by the means of dislocation parallel distribution of the screw and injector piston rod. It possesses the function of pipetting, taking and removing the pipette tips. In the control system, STM32 controller is used, controlling the single-axis S-type acceleration/deceleration algorithm and multi-threaded coordinated motion. The acceleration/deceleration curves are analyzed and optimized by using the method of segmentation; a minimum injection rate of 1 μL and a step rate of 0.05 μL are realized. The method of digital image processing is used to detect the amount of pipetting in micro-pipetting quantitatively. The liquid area is extracted by background contrast method, and the liquid volume in the tip is obtained by combining the geometric characteristics of the disposable tip, when the pipetting capacity is not qualified to carry out specific guidance on the pipetting system, and avoid the blocking needle, bubble and other abnormal pipetting phenomenon on the impact of pipetting accuracy. The experimental results show that the combination of the automatic sampling system and the image flow detection system can effectively improve the precision and reliability of the micropipetting system. Finally, the injection accuracy of the system at the test points with 10, 50 and 100 μL liquid volumes reaches 1.8%, 1.28% and 1.15% respectively.

SYSTEMATIZATION OF METHODS OF WATER INJECTION IN WELLS

Setting the required injection water rates for injection wells is a key factor for oil field successful operation using waterflooding. The success of such activities could reduce the water cyclical nature at field level, crosssection and structure; improve the ratio of water and oil and the wells cleaning efficiency; improve production and recovery of oil by channeling water to specific zones and areas and reduce material costs by improving water use. As a rule, on-site engineers adjust the fluid injection rate using heuristics. While this improves performance, we believe that a more systematic approach can be developed. In accordance with the limitations, including the available water total amount, the maximum and minimum injection rate, the maximum total production liquid for the manufacturer and the sensor installation, to determine the optimal water injection rate, based on the established distribution factor, the linear optimizer was applied programming. This approach has been experimentally tested at the Rosneft Samaraneftegaz field. The decline curve of oil production is calculated within 6 months. The results of a three-month experimental test showed that optimized oil production fits well with the historical six-month decline curve, about 22 % less than the total daily water supply, we also observed a 2 % increase over the historical two-month decline curve (also by 22 % less total daily water injection). These results show that a systematic method can ensure the optimization of target water injection rates.

The Analysis of Effectiveness of BWR/6 URG Strategies

After the Fukushima Daichii accidents, Taiwan Power Company developed a strategy to cope with such extended SBO (Station Blackout) cases at nuclear power plants, which called URG. The MAAP and PCTRAN were used to perform the study for Kuosheng BWR/6 nuclear power plant (NPP) ultimate response guideline (URG). The main actions of URG are the depressurization and low pressure water injection of the reactor and the venting of the containment. This study focuses to confirm the URG efficiency. The analysis results depict that following the URG, the fuel can be covered by the coolant, no exposure. It can also prevent the radiation release and the large evacuation. It indicated that Kuosheng NPP was at the safe situation. It shows that the two-step depressurizations can extend the time of the preparation of alternate water source. The minimum injection rate to prevent the fuel to expose is 192 gpm in MAAP.

Reactive transport in the underground leaching of uranium: Asymptotic analytical solution for multi-reaction model

The production of uranium and several other metals found at depths of several metres or more is performed by the method of in-situ leaching, which consists of injecting acid (or alkali) into geological strata in order to dissolve uranium oxides. The effectiveness of this method can be significantly reduced by certain damaging reactions between acid and carbonates which lead to the formation of solid gypsum, flakes of which cover pore walls and reduce the surface of contact between acid and uranium minerals. The present paper provides a development of the general asymptotic method of solving the system of differential equations describing reactive transport with several useful and detrimental chemical reactions. The method is based on the specific composition of the leaching solutions, in which the concentrations of water and acid dominate, while all other concentrations are small. The technique of asymptotic expansions can be used to obtain a significantly reduced system of transport equations without compositional effects in zero approximation and with a linearized compositional system in the first approximation. In the one-dimensional case, this kind of method enabled us to obtain analytical solutions.These solutions can be used to test the validity of numerical solvers and to solve the inverse problem. The analytical solutions were found to fit well the numerical results obtained using the finite element method. The example of using these solutions to fit experimental data and to solve the inverse problem is also illustrated: the method enables the determination of the reaction kinetics and the initial concentration of uranium in the mineral phases.The qualitative analysis reveals several effects such as the quantitative dependence of the ultimate recovery on the gypsum precipitation and the minimum injection rate which determines complete ultimate recovery of uranium.

Reactivation mechanism of natural fractures by hydraulic fracturing in naturally fractured shale reservoirs

Hydraulic fracturing technique has been commonly used in the development of shale reservoir aiming to produce from complex network of fractures. One of the key parameters that affects the hydraulic fracture complexity is the natural fracture in the shale reservoir. Hydraulic fractures being trapped by natural fractures propagate non-planar fracture in three dimensions. Therefore, conventional hydraulic fracture model cannot include the non-planar characteristics of these fractures. In case a hydraulic fracture crosses a natural fracture, the dependence of the natural fracture reactivation on injection rate remains poorly understood. A non-planar propagation model for hydraulic fracturing in naturally fractured shale reservoirs was developed based on PKN model. A dynamic model was derived to calculate the stress intensity factor for a natural fracture being crossed by a hydraulic fracture based on the theory of rock fracture mechanics. Based on the experimental data from Longmaxi shale reservoir, the fluid pressure threshold to activate the natural fractures was obtained for different approaching angles. The effects of fluid pressure on the propagation angle of natural fracture were discussed. According to different initial injection rates and approaching angles, the time and minimum injection rate were determined to adjust the pump, which can improve the complexity of hydraulic fracture. True tri-axial hydraulic fracturing test with rapidly variable injection rate was conducted on the shale outcrop from Longmaxi formation. Experimental results proved that increasing the injection rate at the right time can reactivate the natural fractures, which can induce a network of fractures in shale reservoirs.

Reactivation mechanism of natural fractures by hydraulic fracturing in naturally fractured shale reservoirs

Hydraulic fracturing technique has been commonly used in the development of shale reservoir aiming to produce from complex network of fractures. One of the key parameters that affects the hydraulic fracture complexity is the natural fracture in the shale reservoir. Hydraulic fractures being trapped by natural fractures propagate non-planar fracture in three dimensions. Therefore, conventional hydraulic fracture model cannot include the non-planar characteristics of these fractures. In case a hydraulic fracture crosses a natural fracture, the dependence of the natural fracture reactivation on injection rate remains poorly understood. A non-planar propagation model for hydraulic fracturing in naturally fractured shale reservoirs was developed based on PKN model. A dynamic model was derived to calculate the stress intensity factor for a natural fracture being crossed by a hydraulic fracture based on the theory of rock fracture mechanics. Based on the experimental data from Longmaxi shale reservoir, the fluid pressure threshold to activate the natural fractures was obtained for different approaching angles. The effects of fluid pressure on the propagation angle of natural fracture were discussed. According to different initial injection rates and approaching angles, the time and minimum injection rate were determined to adjust the pump, which can improve the complexity of hydraulic fracture. True tri-axial hydraulic fracturing test with rapidly variable injection rate was conducted on the shale outcrop from Longmaxi formation. Experimental results proved that increasing the injection rate at the right time can reactivate the natural fractures, which can induce a network of fractures in shale reservoirs.

Effect of System Pressure and Solute Concentration on Fertilizer Injection Rate of a Venturi for Fertigation

Venturi injector is a commonly used device for fertilizer application through drip irrigation. The injection rate of a venturi injector mainly depends upon the suction created due to the difference between its upstream and downstream pressures. A commercially available venturi was evaluated for injection rate under the range of operating pressures from 1.0 to 2.0 kg.cm-2 using normal irrigation water and fertilizer solution. Maximum injection rate of the venturi with irrigation water was 106.4 l.h-1 at operating pressure of 2.0 kg.cm-2. Maximum injection rate (105.8 l.h-1), when urea fertilizer dissolved in irrigation water in the ratio of 0.25:1 (urea: water) was at the upstream and downstream pressure of 2.0 kg.cm-2 and 0.1 kg.cm-2, respectively. However, for muriate of potash (MOP) dissolved in irrigation water in the ratio of 1:1 (MOP: water), minimum injection rate of venturi was 1.44 l.h-1 at upstream pressure of

A futuristic least-cost optimisation model of CO 2 transportation and storage in the UK/UK Continental Shelf

The owners of 8 power plants in the UK have announced interest in capturing and sequestering CO 2. Using various criteria from the literature twenty fields in the UK Continental Shelf were selected as possible sinks for the captured CO 2. Using a linear programming model, the study determined the least-cost transportation network under various constraints on the volumes of CO 2 captured from the sources and the injection rates at the sinks. Four scenarios were developed to gauge the sensitivity of the results to these and to the availability of fields for EOR and Permanent Storage. Depending on the scenario, the optimal transportation CAPEX was found to range between £3.5 and £5.2 billion in real terms. With higher minimum injection rates at the fields, accelerating CO 2–EOR investments was found to reduce unit transportation CAPEX compared to waiting for their cessation of production dates. On the other hand a combination of the later availability of the CO 2–EOR fields plus a lower minimum injection rate yielded the minimum transportation network CAPEX. The modelling also unveiled the problem of CO 2 supply overflows in the longer term. The modelling approach has wide applicability beyond the UK.

Prediction model of bottom hole temperature and pressure at deep injector for CO2 sequestration to recover injection rate

Abstract The field test of CO 2 -ECBM was carried during 2003 to 2007 in order to evaluate technical feasibility of injecting CO 2 into the coal seam while producing CH 4 at Yubari City, Hokkaido, Japan. It aims to resolve global warming and to develop a system for injection and sequestration of CO 2 into coal seams. The targeted coal seam is located about 900 m below the surface. The absolute pressure at the bottom hole is approximately 15.5 MPa and the CO 2 temperature is about 28 ∘ C before the injecting into the coal seam. Thus, CO 2 is injected in liquid phase to the coal seam and supercritical condition of CO 2 has not been satisfied due to heat loss along the deep injection well. Replacements of usual tubing pipes with thermal insulated tubings were applied, however the temperature at the bottom hole was still lower than the CO 2 critical temperature. The project had a problem about decreasing injection rate after starting injection CO 2 . It was evaluated by analysing the field test data that the maximu m decreasing ratio of the coal seam permeability was 0.065 and permeability around injection well was became 6 times larger than the original one. We assumed that its reason is caused with swelling of the coal seam around the injection well by liquid CO 2 injection. Present study has focused on the keeping supercritical CO 2 in the tubing because viscosity of supercritical CO 2 that is 40% smaller than that of liquid CO 2 . The CO 2 temperature has been successfully predicted in order to keep CO 2 in supercritical condition from the surface to the bottom for various CO 2 injection rates and electric heater power. The minimum injection rate has been presented in order to keep CO 2 in the supercritical condition at the bottom hole of the injection tubing. Injected CO 2 is expected to be super critical over 12 ton/day of injection rate without any heating in the tubing.

Conditions for the growth of a long‐lived shallow crustal magma chamber below Mount Pelee volcano (Martinique, Lesser Antilles Arc)

The compositional homogeneity of silicic andesites emitted during the 13,500‐year‐long last eruptive cycle of Mount Pelee suggests that the physical state of the magma chamber was largely unmodified during this period. Experimental phase equilibria on Mount Pelee recent products indicate that pre‐eruptive magma temperatures and pressures were in the range of 875–900°C and 2 ± 0.5 kbar, respectively. The estimated average eruption rate was 7.5 × 10−4 km3/a with an average volume of about 0.3 km3 per eruption. An analytical model for a spherical magma chamber indicates that a magma flux of 4–5 × 10−4 km3/a can maintain a magma chamber of 0.3 km3 above 875°C below Mount Pelee. However, observations of plutons suggest that magma chambers may grow by addition of sheet‐like intrusions. With numerical simulation we show that a minimum sheet accretion rate of a few centimeters per year is required to grow a persistently active magma chamber independently of the intruded volumetric flux. This minimum injection rate is higher if the heat transfer is enhanced by convection processes. The limited ability of an arc crust to extend and accommodate dikes suggests that magma injections are sills or, if they are dikes, that most of the volume injected in the magma chamber is eventually erupted. In a conductively cooling igneous body formed by sills injected at a rate of a few centimeters per year, most of the injected magma completely solidifies and only a small part of the body (about 10–20%) is above 875°C and able to feed eruptions.

Investigation of jet breakup and droplet size distribution of liquid CO2and water systems—implications for CO2hydrate formation for ocean carbon sequestration

An experimental investigation has been conducted into the effect of fluid velocity and orifice size on the breakup patterns of liquid CO2 in water, as well as those for water in CO2. Under high-pressure and low-temperature conditions, the jet breakup patterns follow distinct Rayleigh, transitional, and spray modes. Droplet size distribution was determined in the different modes, with the spray mode producing the smallest droplets and the most uniform size distribution. The system appears to progress from transitional to spray mode when the Ohnesorge number is approximately 18 Re−1. Using this relationship, it is possible to predict the minimum injection rate necessary for spray mode at any injector diameter. Under hydrate-forming conditions, the jet breakup did not appear to be affected because breakup occurred faster than hydrate formation. However, injection into a confined space could promote droplet coalescence, resulting in a larger average drop size. These results can be used to control hydrate conversion in an ocean CO2 injection system and to ensure a large dispersion of injected CO2 during its sequestration in the ocean.

Matrix Acidizing in Saudi Arabia Using Buoyant Ball Sealers

Abstract Acid jobs utilizing buoyant ball sealers have been performed on several wells with varied downhole conditions and different productivities. The test objectives were to determine buoyant productivities. The test objectives were to determine buoyant ball sealer's diverting efficiency when pumping at matrix acidizing rate and to determine whether or not the buoyant ball sealers are more effective than the particulate diverting materials presently being used. Complete pre and post-acidization testing provided accurate data for valid test analysis. The buoyant ball sealers were effective in every test. Matrix acidizing of long intervals and multiple sets of perforations was successfully accomplished. Marked production perforations was successfully accomplished. Marked production improvement resulted from a well previously acidized utilizing particulate diverting materials. Production of an old well particulate diverting materials. Production of an old well previously acidized six times was increased to the highest rate in previously acidized six times was increased to the highest rate in its sixteen year producing history. Buoyant ball sealers are the most effective means of diverting acid when matrix acidizing perforated completions. Introduction Stimulation in Saudi Arabia is performed primarily to remove the perforation damage and to establish a flow path through formation damage near the wellbore. Completion intervals in our carbonate reservoirs may be either open hole or perforations. Intervals will vary from 10 to 90 m (30 to 300 ft) or more in thickness with diverse porosities and permeabilities. Various particulate diverting materials, wax beads, benzoic acid flakes, particulate diverting materials, wax beads, benzoic acid flakes, and graded rock salt have been used with varying degrees of success. High density ball sealers, 1.3 gm/cm have been used. There has been problems with each diverting system. Determination of the proper quantity of particulate diverting material to use is difficult. Insufficient diverting material will perform little or no diverting. Too much diverting material will cause excessive plugging which may not clean up and will leave the formation damaged. An example of excessive plugging occurred in an exploration well and illustrates the problem. Eleven meters (35 ft) of a reservoir were perforated, acidized, and were production tested for 160 m/d (1000 BOPD). Fourteen meters (45 ft) more of the reservoir above this were perforated. Rather than setting a bridge plug or squeezing the interval with cement, particulate diverting material was added to the first portion of the acid used for stimulating the new perforations. portion of the acid used for stimulating the new perforations. With both sets of perforations on production test together, the well produced only a small quantity of oil. The original production was not recovered. Diversion of treating fluids generally result from the use of high density ball sealers whenever high injection rates are maintained and the perforation density has been limited to 2 shots per foot. The minimum injection rate required for good per foot. The minimum injection rate required for good perforation sealing efficiency using high density ball sealers is perforation sealing efficiency using high density ball sealers is greater than calculated matrix acidizing rates for most wells. When not limited to matrix acidizing, the injection rate required for effective diverting with high density ball sealers is not possible because of the large friction losses in our small tubing possible because of the large friction losses in our small tubing kill strings and the pressure limitations of our well heads. In most acidizing jobs we have performed utilizing the 1.3 gm/cm ball sealers, diverting efficiency has been low because of low injection rate and the perforation density of 4 shots per foot. Exxon Production Research Company recognized the problems associated with particulate matter diverters and the high density ball sealers several years ago and undertook a study to improve ball sealer diverting efficiency. Their study revealed that buoyant ball sealers exhibited a very high seating efficiency resulting in greatly improved diversion. p. 485

Predicting Performance of Waterfloods at Highest Constant Injection Rate

Using the principles of dimensionless ratios, the data from a Higgins-Leighton method at constant pressure may be easily and quickly usedto predict the pressure may be easily and quickly usedto predict the highest constant rate of injection of water that is possible without fracturing the reservoir rock at the possible without fracturing the reservoir rock at the wellbore,to predict quickly the performance to the ultimate life of a waterflood with a constant rate of injection,to predict the life of a waterflood using a high constant rate early in the flood when the pressure at the wellhead may be low and then, later, a pressure at the wellhead may be low and then, later, a reduced rate to avoid fracture, andto estimate, after the flooding is started, the time at which the kick (first increase in oil rate) will occur and the relative size of the kick. These are all useful in making an economic analysis of a potential waterflood. With the method presented we can quickly process the predictions using relative permeabilities that appreciably influence recovery of oil. The method includes the use of layers to determine the effect of vertical permeability variations. All of this information is useful in designing the constant-rate pumps used to inject water into reservoirs. With these features, we can use the predicted performance at a constant pressure to obtain the predicted performance history at a constant injection rate during the entire life of the flood. Also, we can quickly predict the performance of a flood at different constant rates performance of a flood at different constant rates during the life of the flood; that is, at a very high rate for the short initial period when the well may be operating under nearly vacuum conditions at the wellhead, then at decreasing sets of constant rates or even at continuously changing rates. The economics of a flood is affected by the size and cost of constant-rate pumps and the rate of return of the investment during the life of a flood. With the performance data vs the rate of injection, the performance data vs the rate of injection, the economic feasibility can be easily determined. The relationships among time, rates and volumes have been checked by computer runs. They were tested on the individual layers and on combinations of layers of different absolute permeability. The ratio relationship was found to reproduce exactly the produced volumes and other data. At the time of this produced volumes and other data. At the time of this writing, it has not been tested on combinations of layers of different relative permeability-saturation curves. But, in principle, it should hold for these combinations also. The highest constant injection rate that will require a pressure just less than would be expected to fracture the formation can be determined with a model computer run at constant pressure. When the mobility ratio is greater than one, the injection rate for the model will decrease, pass through a minimum, and then increase. This minimum injection rate is the maximum permissible constant injection rate. Any constant rate in excess of this would require a pressure that would probably fracture the formation at pressure that would probably fracture the formation at some time during the flood. This highest permissible pressure is used in the Higgins-Leighton prediction method. The printout of the results of the calculations using the Higgins-Leighton method at constant pressure or a plot of the results will show lowest injection rate. P. 1246