Optimal Injection Volume Research Articles

New exploration on the goaf inerting with hidden fire source under CO2 injection volume of adsorption compensation

To strengthen the rationality of the design of CO2 injection volume in goaf, a framework is proposed to study goaf inerting characteristics with hidden fire sources under CO2 injection volume of adsorption compensation. The zone of hidden fire source is determined by similar simulation experiment of coal spontaneous combustion on a working face of coal mine. The range of injection volume without adsorption is calculated theoretically. A three-dimensional initial flow field model of coal spontaneous combustion is established combined with field measurement. The error of oxidation zone width is 3.64 %, which verifies the reliability of model. The influence of injection volume on the inerting effect in goaf is studied, and optimal injection volume without adsorption is 1000 m3/h. Based on the relationship between adsorption capacity and temperature, a quantization model of injection volume with adsorption compensation is established. The maximum dissipation ratio is then proposed. The optimal injection volume after adsorption compensation is calculated. The results show that intermittent injection of gaseous CO2 is recommended under simulated conditions. The maximum dissipation ratio is 1/4, and the CO2 injection volume compensated by adsorption is 1333 m3/h. The research results can provide theoretical guidance for the optimization of CO2 inerting parameters in goaf.

Optimization of injection parameters of a microemulsion-type oil displacement agent for heavy oil recovery

The conventional viscosity reduction technology through commercial oil-soluble agents for enhanced oil recovery in heavy oil reservoirs has potential safety hazards. In this work, micro-emulsification of heavy oil is proposed as a means of reducing its viscosity for ease of its recovery. The microemulsion-type oil displacement agent was developed, and its performance was characterized by its pseudoternary phase diagram and dynamic light scattering tests. The core tests were used to study the effects of injection volume, injection speed, and subsequent water flooding speed on the oil recovery factors. These results were used to determine the optimal injection parameters. Furthermore, the displacement mechanism for heavy oil was determined based on combined macroscopic and microscopic visual tests. The results showed that the optimal injection volume is 0.15 PV (pore volume), the injection rate is 0.10 ml/min, and the subsequent water flooding rate is 0.20 ml/min. Based on the optimal parameters, the oil recovery efficiency can reach up to 39.83%, which is 25.69% higher than water flooding process. The displacement mechanism of the microemulsion can be divided into three stages. First, when the microemulsion is in contact with the heavy oil, the solubilization occurs spontaneously, and the heavy oil is peeled off from the rock surface. Then, the solvent in the microemulsion interacts with the heavy oil to achieve the viscosity decrease in the heavy oil. Third, during the water flooding process, the viscosity-reduced heavy oil can be emulsified to form oil-in-water emulsion, further realizing the viscosity reduction of heavy oil.

Feasibility of Advanced CO2 Injection and Well Pattern Adjustment to Improve Oil Recovery and CO2 Storage in Tight-Oil Reservoirs

Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO2 injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO2 storage. Currently, limited research exists on advanced CO2 injection and well pattern adjustment aimed at improving the oil recovery and CO2 storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO2 sequestration via advanced CO2 injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO2 storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO2 injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO2–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO2 injection, advanced CO2 injection can more effectively facilitate EOR and achieve CO2 sequestration, with the recovery and CO2 sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO2 injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO2 storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO2 injection development in tight-oil reservoirs.

Optimization Study of Injection and Production Parameters for Shallow- and Thin-Layer Heavy Oil Reservoirs with Nitrogen Foam-Assisted Steam Flooding

Shallow- and thin-layer heavy oil reservoirs are characterized by their shallow burial, thin thickness, high viscosity, and scattered distribution. After years of steam injection development, several issues have emerged, including a highly comprehensive water cut in the reservoir and serious steam channeling. Therefore, there is an urgent need to change the development approach to enhance crude oil recovery. It has been discovered that developing heavy oil reservoirs through nitrogen foam-assisted steam flooding can effectively address the challenges encountered in pure steam development. This paper takes H Oilfield Block A as a case study, analyzes the geological characteristics and development status of the reservoir in this block, and predicts the recovery of steam injection development in this block using the injection-production characteristic curve method. Furthermore, by establishing a reservoir geological model and fitting it to the historical behavior of the target reservoir, the nitrogen foam-assisted steam flooding injection and production parameters were optimized. The optimal parameters are as follows: optimal steam injection intensity of 2.0 t/(d·ha·m), optimal production/injection ratio of 1.2:1, optimal nitrogen foam slug injection volume of 0.15 PV, optimal nitrogen/steam ratio of 2:1, and intermittent injection between 3 and 4 foam slugs. It is anticipated that this optimized scheme will result in a predicted increase in final recovery of 13.55%. The findings of this study hold significant importance in guiding the application of nitrogen foam-assisted steam flooding in shallow and thin heavy oil reservoirs.

Evaluation of Foam Gel Compound Profile Control and Flooding Technology in Low-Permeability Reservoirs

In the waterflooding development of fractured ultra-low permeability reservoirs, the heterogeneity is becoming increasingly serious. The development of large fracture channels leads to serious water channelling and low recovery, and the effect of conventional profile control is not ideal. This paper proposed gel foam composite profile control and flooding technology to solve the above problems. Herein, the new intelligent gel and foaming agent systems were optimized through laboratory experiments, and their performance was evaluated. The new intelligent gel system has the characteristics of low viscosity, easy preparation, good injection, slow cross-linking, high strength, and long-term effectiveness. The injection parameters were optimized, and the indoor injection scheme was formulated, that is, the optimal injection volumes of gel and foam slugs were 0.3 and 0.6 PV, respectively. The injection sequence of composite slugs was to inject gel slugs first, then foam slugs. The injection mode of air foam slugs was multiple rounds of small slug injection. The final recovery rate in the indoor dual tube oil displacement experiment reached 35.01%, increasing by 23.69%. Furthermore, an oil output increase of 899 t and an average water cut decrease of 5% were acquired in the oil field test. It shows that the injection scheme can effectively improve oil recovery. The gel foam compound profile control and flooding technology herein has good adaptability in similar reservoirs and has good promotion prospects.

Correlation analysis of injection parameters for low-medium pressure injection of liquid CO2 for CH4 displacement in coal seams

The injection parameters for liquid CO2 to displace CH4 in a coal seam depend on engineering analogy and construction experience. To explore the relationship between key pressure injection parameters, such as liquid injection pressure and liquid injection volume, a combination of theoretical analysis and a downhole pilot test was used. The effective displacement radii of the CO2 and CH4 extraction under different liquid injection pressures were compared. The correlations between the volume, flow, time, and pressure of the injection liquid were analyzed. The results showed that the influence radius of CO2 effective displacement and influence period of CO2 pressure injection were proportional to the injection pressure. Low-pressure tank injection effectively promoted the extraction of coal seam CH4, whereas medium-pressure pump injection greatly enhanced the extraction of CH4. Therefore, in a low-to-medium pressure injection range, the higher the injection pressure of the liquid CO2, the better the displacement effect. A correlation analysis of the liquid injection parameters reveals that the liquid injection volume shows a concave nonlinear increasing trend with an increase in the liquid injection pressure, the liquid injection flow shows a parabolic trend of the upper opening with the increase of the liquid injection pressureand the liquid injection time shows a parabolic trend of the lower opening with an increase in liquid injection pressure. A comprehensive analysis shows that the optimal injection pressure and volume for the low-medium pressure injection of liquid CO2 to displace coal seam CH4 are 7.5 MPa and 7.4 m3, respectively.

Integrated Approach Optimizes Underground Gas-Storage Process

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207941, “Underground Gas-Storage Process Optimization Using Integrated Subsurface Characterization, Dynamic Modeling, and Monitoring: A Case Study,” by Longxin Li, Yuan Zhou, and Limin Li, PetroChina Southwest Oil and Gasfield Company, et al. The paper has not been peer reviewed. _ The operator’s Xiangguosi (XGS) gasfield facility began underground gas storage (UGS) operations in a depleted gas field in southwest China in 2013. Following this initial period, the site was reassessed to increase deliverability safely during the winter months to meet future peak gas demand. The results of that analysis informed the resulting system design, in combination with fit-for-purpose reservoir-surveillance systems; caprock-seal recording pressure, rock deformation, and seismicity data in real time; and regular wellbore inspection. Introduction The XGS UGS facility currently operates in a previously depleted gas reservoir in Sichuan province. Its construction took place during the second half of 2011; cushion gas injection started in June 2013. Located in a high-tectonic-stress region, the geological setting of the XGS field is structurally complex and highly faulted and the targeted carbonate formation is heterogeneous and naturally fractured. When the studies described in the complete paper commenced in November 2019, the field hosted 22.80×108 m3 of working gas along with 19.80×108 m3 of cushion gas. As of May 2020, the reservoir had completed eight injection and six withdrawal cycles and delivered a maximum withdrawal rate of 21.96×106 m3/d. The UGS conversion plans required a revisit to analyze the possibility of increasing the withdrawal rate to 28.55×106 m3/d, thereby positioning better for future peak gas demand. The drilling of five new wells commenced in 2019. Planned Technical Approach The purpose of the study was to optimize the XGS UGS facility’s working gas capacity and improve operational performance throughout asset life. It was proposed to achieve this by 4D geomechanical and 3D dynamic flow-simulation models. The geomechanical model would hinge on an integrated subsurface characterization work flow combined with an advanced monitoring network tightly connected with the surface facility operation to ensure maximum containment and optimal injection and withdrawal rates and volumes. This holistic approach would aid in ascertaining optimal drawdown pressures to minimize rock fatigue and ensure operation of the UGS facility within safe pressure limits. Fully integrated Subsurface Characterization A detailed review of the existing petrophysical interpretation from wells calibrated with core analysis data was undertaken. Petrophysical interpretations from 29 wells were used to construct a reservoir classification and petrophysical property models. This led to the understanding that depositional facies were not the overriding control on reservoir quality in this case because the reservoir is highly affected by karstification, diagenesis, and fracturing. Prestack migrated seismic data was improved with acquisition footprint, noise, and multiple removal and then interpreted to map subsurface structure. The edited well logs were used to build synthetic seismograms. A complex structural model was created that included 22 stratigraphic zones and a detailed fault model within the main field structure, integrating stratigraphic data and log curves from all recently drilled wells.

Optimal Injection Volume in Treatment of Tendinopathy

Background: Tendinopathy, a pathology of tendons characterized by inflammation and or degeneration, is a prevalent cause of disease and disability in active and working patients. Within the past decade, orthobiologic injections such as Platelet Rich Plasma (PRP) have become increasingly popular within the musculoskeletal physician’s practice for treatment of chronic tendinopathies. However, there is a lack of standardization of PRP preparation and injection protocols, leading to gaps in our knowledge regarding the optimal administration dosages to maximize treatment efficacy. Purpose: This review aims to compile and evaluate the existing data for PRP injection volumes for various tendinopathies in hopes of contributing to standardization of PRP protocols, with a further goal of minimiz-ing waste of a costly therapeutic. Study Design: Systematic Review Methods: In June 2020, comprehensive electronic database searches were conducted by a medical librarian in Medline via PubMed, EMBASE (embase.com), CINAHL (EbscoHost), CENTRAL and Scopus according to the Preferred Reporting Items for Systematic Reviews and Meta-Analyses (PRISMA) guidelines. Data was extracted from studies meeting inclusion criteria on injection volumes and outcomes and grouped based on anatomic injection location. Results: Twenty-eight studies were identified for inclusion in which ultrasound-guided intra-tendinous PRP injections were administered to patients to treat various tendinopathies. For all tendon locations, the mini-mum volume of injectate reported achieved positive clinical outcomes in patients compared to baseline. Conclusions: Despite its many benefits—tendon healing, pain relief, increased function—PRP can pose a significant financial burden to patients, with patients often having to pay for the full cost out-of-pocket due to lack of insurance coverage. This study provides evidence that PRP can be effective at smaller volumes, minimizing waste and the out-of-pocket cost to the patient. In addition, this study further stresses the impor-tance of protocol standardization. Clinical Relevance: Though more data is needed, it is apparent that the minimum amount of injectate used clinically for various anatomic locations is enough for overall positive outcomes, and therefore can be the recommended dose given. As such, the authors have incorporated the minimum injection volume into their practice using the following volumes: Rotator Cuff-1 mL, Lateral or Medial Epicondyle-1.5 mL, Gluteal or Hamstring-3 mL, Patella-2 mL, Achilles-3 mL. Unfortunately, without more data available in the literature, the authors cannot make stronger recommendations at this time. What is known about the subject: Among intralesional injections for the treatment of tendinopathy, PRP has shown positive results in multiple trials and has made its way into many musculoskeletal physicians’ practice. However, there is a significant lack of standardization in PRP protocols. What this study adds to existing knowledge: While other reviews have highlighted the discrepancies amongst PRP protocols, our review is the first to examine injection volume and its effect on outcomes. We were able to suggest a minimum injectate amount for positive outcomes, either pain relief or improvement in the tendon appearance on imaging.

Separation and purification of antioxidant peptides from purple speckled kidney bean by macroporous adsorption resin and analysis of amino acid composition.

The protein hydrolysate of purple speckled kidney bean (PSKB) was used as the raw material in this study, and the antioxidant peptide of the PSKB protein hydrolysate was purified using macroporous resin. The XAD-7HP macroporous resin was selected as the best purification material, and the static adsorption-desorption of the purified PSKB antioxidant peptide was optimized. The optimum static adsorption and desorption conditions were as follows: the adsorption capacity reached 11.93 ± 0.11 mg/ml at pH 7 for 24 h, and the desorption capacity was 5.24 ± 0.04 mg/ml with 60% ethanol for 30 min. Under this condition, the amount of antioxidant peptide obtained by adsorption-desorption was the highest. The optimum process conditions were as follows: the appropriate flow rate was 1 ml/min, and the optimal injection volume was 40 ml. The adsorption amount at this time can reach 12.19 ± 0.15 mg/ml. The components with an elution time of 10-30 min were separated using the reversed-phase high-performance liquid chromatography (RP-HPLC) technique to obtain three main components, namely, RP1, RP2, and RP3. The DPPH free radical scavenging ability reached 56.26 ± 0.56, 66.42 ± 0.56, and 78.57 ± 0.56%, respectively, which were 36.65, 46.34 ± 0.56, and 54.39 ± 0.56% higher than those before purification. The amino acid sequences of the three components were identified as Phe-Leu-Val-Asp-Arg-Ile, Phe-Leu-Val-Ala-Pro-Asp-Asp, and Lys-Asp-Arg-Val-Ile-Ser-Glu-Leu.

Development and Performance Evaluation of a Selective Plugging System for High-Temperature and High-Salinity Water-Bearing Gas Reservoir

In the development of natural gas reservoirs, the water produced in wells will cause a decline in gas well productivity. In this study, a selective frozen gel plugging agent system suitable for water plugging in gas reservoirs under conditions of high temperature and high salinity. The plugging capacity of the gel system was evaluated. The experimental results showed that: (1) the optimal experimental scheme of the frozen gelling system was as follows: 107 °C with 1.0% AM-AMPS +0.6% p-benzenediol +0.6% hexamethylenetetramine +0.2% thiourea. (2) The optimal injection volume of the system for water phase plugging was 0.5 PV, and the system has an excellent plugging effect at a permeability of 356–3118 mD. (3) The system could also effectively improve the degree of heterogeneity, and the smaller the degree of heterogeneity, the better the improvement effect. (4) The gel system had a good effect on different plugging methods, and the gas medium did not affect the plugging performance. This study provides a sufficient theoretical basis for the exploitation of high-temperature and high-salinity water-bearing gas reservoirs through experimental research, which is of great significance for improving production capacity.

Percolation Characteristics and Injection Limit of Surfactant Huff-n-Puff in a Tight Reservoir.

For the development of tight reservoirs, large-scale volume fracturing is frequently utilized as an effective production enhancement strategy. However, there is a significant decrease in productivity after fracturing. Improvement of production through secondary surfactant huff-n-puff has become one of the methods. In this paper, the characteristics of surfactant percolation during huff-n-puff were analyzed from macroscopic and microscopic perspectives. The production variation characteristics of the huff-n-puff were calculated by experiments and numerical methods. From Stokes' equations and phase field equations, solutions were found to analyze the effect of interfacial properties on surfactant percolation from the microscopic perspective. The findings demonstrated that a surfactant with a high displacement efficiency could not considerably increase huff-n-puff production, whereas the percolation rate had a wider influence. The surfactant with ultralow interfacial tension (<1 × 10-2 mN/m) and a higher wetting angle (>12.6°) has a faster percolation rate. Significant huff-n-puff production can be obtained in the percolation rate range of 1.38 to 1.63 m/PV. Simultaneously, the concepts of limit and optimal injection volume were established and utilized to characterize the influence of injection parameters on production under nonextension fracture situations. Based on the data, in order to obtain high production in a short time, the injection strength should be near to the value at fracture extension, and the optimum injection volume is 1000-1200 m3/m. The findings of this study have the potential to guide the selection of the surfactant and injection parameters in the field.

Can a computer “learn” nonlinear chromatography?: Physics-based deep neural networks for simulation and optimization of chromatographic processes

The design and optimization of chromatographic processes is essential for enabling efficient separations. To this end, hyperbolic partial differential equations (PDEs) along with nonlinear adsorption isotherms must be solved using computationally expensive numerical solvers to understand, simulate, and design the complex behavior of solute movement in chromatographic columns. In this study, physics-based artificial neural network framework for adsorption and chromatography emulation (PANACHE) is used to simulate and optimize chromatographic processes in a computationally faster and reliable manner. The proposed approach relies on learning the underlying PDEs in the form of a physics-constrained loss function to improve the accuracy of process simulations. The effectiveness of this approach is demonstrated by considering the complex dynamics of binary solute mixtures for generic pulse injections subjected to different isotherm systems, namely, the four cases of the generalized Langmuir isotherms. Unique neural network models were developed for each isotherm and the models accurately predicted the spatiotemporal concentrations of solute mixture in chromatographic columns for an arbitrary feed concentrations and injection volumes by facilitating up to 250 times computational speed-ups. Moreover, the neural network models were incorporated with process optimization routines to precisely determine the optimal injection volumes to enable baseline separation of solute components of the feed mixture.

Murine Neural Plate Targeting by In Utero Nano-Injection (NEPTUNE) at Embryonic Day 7.5

Manipulating gene expression in the developing mouse brain in utero holds great potential for functional genetics studies. However, it has previously largely been restricted to the manipulation of embryonic stages post-neurulation. A protocol was developed to inject the amniotic cavity at embryonic day (E)7.5 and deliver lentivirus, encoding cDNA or shRNA, targeting >95% of the neural plate and neural crest cells, contributing to the future brain, spinal cord, and peripheral nervous system. This protocol describes the steps necessary to achieve successful transduction, including grinding of the glass capillary needles, pregnancy verification, developmental staging using ultrasound imaging, and optimal injection volumes matched to embryonic stages. Following this protocol, it is possible to achieve transduction of >95% of the developing brain with high-titer lentivirus and thus perform whole-brain genetic manipulation. In contrast, it is possible to achieve mosaic transduction using lower viral titers, allowing for genetic screening or lineage tracing. Injection at E7.5 also targets ectoderm and neural crest contributing to distinct compartments of the eye, tongue, and peripheral nervous system. This technique thus offers the possibility to manipulate gene expression in mouse neural-plate- and ectoderm-derived tissues from preneurulation stages, with the benefit of reducing the number of mice used in experiments.

Murine Neural Plate Targeting by In Utero Nano-Injection (NEPTUNE) at Embryonic Day 7.5.

Manipulating gene expression in the developing mouse brain in utero holds great potential for functional genetics studies. However, it has previously largely been restricted to the manipulation of embryonic stages post-neurulation. A protocol was developed to inject the amniotic cavity at embryonic day (E)7.5 and deliver lentivirus, encoding cDNA or shRNA, targeting >95% of the neural plate and neural crest cells, contributing to the future brain, spinal cord, and peripheral nervous system. This protocol describes the steps necessary to achieve successful transduction, including grinding of the glass capillary needles, pregnancy verification, developmental staging using ultrasound imaging, and optimal injection volumes matched to embryonic stages. Following this protocol, it is possible to achieve transduction of >95% of the developing brain with high-titer lentivirus and thus perform whole-brain genetic manipulation. In contrast, it is possible to achieve mosaic transduction using lower viral titers, allowing for genetic screening or lineage tracing. Injection at E7.5 also targets ectoderm and neural crest contributing to distinct compartments of the eye, tongue, and peripheral nervous system. This technique thus offers the possibility to manipulate gene expression in mouse neural-plate- and ectoderm-derived tissues from preneurulation stages, with the benefit of reducing the number of mice used in experiments.

Study of Water Huff-n-Puff in Low-Permeability Oil Reservoirs With Horizontal Fractures: A Case Study of Chang 6 Reservoir in Yanchang, China

Water huff-n-puff is an effective technology to enhance oil recovery (EOR) of low-permeability reservoirs, which are usually developed with hydraulic fracturing. Fluid exchange between fractures and the matrix is the main EOR mechanism. However, the presented water huff-n-puff simulations usually assume vertical fracture morphology, while the horizontal fractures formed in shallow reservoirs are rarely reported. In this study, we first introduced the water huff-n-puff process in a low-permeability oil reservoir with horizontal fractures and described the multiphase flow characteristics during the huff, soak, and puff stages. Then combined with a series of experiments, a comprehensive method is used to determine the key flow parameters, that is, capillary pressure and relative permeability. Finally, using the Chang 6 reservoir as an example, a series of numerical simulations were conducted to demonstrate the effect of water huff-n-puff on the well performance in this field. The simulation results showed that oil production is mainly affected by the injection volume and injection rate, while water production mainly depends on the well shut-in time. For a typical well in this field, the optimal injection volume, injection rate, and well shut-in time are 300 m3, 10 m3/d, and 30 days, respectively. In addition, our results showed that increasing the number of cycles not only benefits fluid exchange but also enhances the formation pressure. Both of them can accelerate the development of low-permeability oil reservoirs.

Method to optimize the volume of nitrogen gas injected into the trapped annulus to mitigate thermal-expanded pressure in oil and gas wells

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

Effect of rubber particles on water flow behavior in fractured-vuggy reservoirs

The presence of the large channel in fractured-vuggy reservoirs diminishes the sweep efficiency of any water, gas or polymer flooding. This paper presents a novel type of rubber particle for water shutoff agent and the flow direction of water is adjusted by plugging the large channel. Simultaneously, through the microscopic displacement experiment of the organic glass etching model, the water flow behavior and injection parameters optimization are studied. The results show that the resistance of solid media to fluid flow is almost zero when the oil-water two-phase flow occurs, and the gravity action is prominent. Therefore, there are still a lot of residual oil of karst cave, flow around oil and attic oil with poor connectivity after the fractured-vuggy reservoir is displaced by injected water. In addition, the rubber particles can form a temporary plugging zone by migration – accumulation – bridging under formation conditions, resulting in the flow direction of subsequent injection water changes from the large channel to the small channel, thereby reducing water content and increasing oil production. By optimizing the injection parameters of rubber particles, the optimal injection volume, particle size and injection speed are obtained, which are 0.02PV, 0–1 mm, 2–4 mm and 25 mL/min, respectively.

Experimental Study on Supercritical CO2 Huff and Puff in Tight Conglomerate Reservoirs.

A tight conglomerate reservoir is a kind of unconventional reservoir with strong heterogeneity, and CO2 injection is an economical and environmentally friendly method to enhance tight oil recovery. Supercritical CO2 is a very promising fluid medium for unconventional reservoir development due to its gas–liquid dual properties. In this study, the production effects of supercritical CO2 and non-supercritical CO2 in tight conglomerate reservoirs were quantitatively analyzed by huff and puff simulation experiments conducted under reservoir conditions (formation pressure 37 MPa, temperature 89 °C). Also, the influencing factors of CO2 huff and puff production, including injection volume, soaking time, and throughput cycles, were investigated. The results showed that supercritical CO2 improves the recovery by 4.02% compared with non-supercritical CO2. It could be seen that supercritical CO2 plays a positive role in improving tight conglomerate reservoirs. The optimal injection volume, soaking time, and throughput cycles were determined to be 0.50 PV, 2 h, and 3 cycles, respectively. This paper provides an important basis for the study of supercritical CO2 production in tight conglomerate reservoirs.

Research on Optimal Blocking Limits and Injection Parameter Optimization of Polymer Microsphere Conformance Control.

Polymer microsphere (PM) profile control has been attributed to improving sweep efficiency during the oil development process. The critical factors for PM conformance control are the plugging properties controlled by matching the relationship between the throat diameter and particle size and the injection parameters. A new matching relationship between the reservoir and PM based on the function of blocking rate and the ratio of throat diameter to microsphere diameter (CR) is established to choose the most appropriate PM size. The blocking rate indicates that it will get the most excellent plugging effect when CR is 0.5. The displacement experiments under different injection concentrations and other injection volumes show that the blocking rate is increased by injection concentration and finally stabilized. A similar trend is presented between the injection volume and plugging rate. The optimal injection concentration is 0.5%, and the optimal injection volume is 0.3 PV. According to the new size selection method and injection parameter optimal method, PM100 chooses to conduct field application. PM100 presents a good performance with a success rate of 37.5% and a validity period of more than 120 days, and its daily oil production rate increased 1.7 times, on average, and finally, the total oil increase is 556 t. The optimal size microsphere shows a good EOR effect, which indicates that this size selection method is reasonable.

Tumor ablation due to inhomogeneous anisotropic diffusion in generic three-dimensional topologies.

In recent decades computer-aided technologies have become prevalent in medicine, however, cancer drugs are often only tested on in vitro cell lines from biopsies. We derive a full three-dimensional model of inhomogeneous -anisotropic diffusion in a tumor region coupled to a binary population model, which simulates in vivo scenarios faster than traditional cell-line tests. The diffusion tensors are acquired using diffusion tensor magnetic resonance imaging from a patient diagnosed with glioblastoma multiform. Then we numerically simulate the full model with finite element methods and produce drug concentration heat maps, apoptosis hotspots, and dose-response curves. Finally, predictions are made about optimal injection locations and volumes, which are presented in a form that can be employed by doctors and oncologists.