Gas-water Ratio Research Articles

Enhanced technique for analyzing waterflooding characteristic curve in water-bearing gas reservoirs considering the influence of water-sealed gas

ABSTRACT Considering the water-sealed gas effect in water-bearing gas reservoirs, this study integrates the heterogeneity coefficient (A) and the water influx coefficient (B) to quantify the water-sealed reserves precisely. Building upon this, a novel waterflooding characteristic curve equation is proposed by merging the material balance equation with the relative permeability model. Sensitivity analyses of the theoretical curve reveal that an increase in both the heterogeneity coefficient (A) and the water influx coefficient (B) exacerbates the water-sealed effect, prematurely and steeply elevating the waterflooding characteristic curve; this leads to a higher water-gas ratio. The results demonstrate that the proposed curve, which accounts for the water-sealed phenomenon, aligns well with production data throughout the entire development phase, enabling an effective assessment of gas reservoir exploitation efficiency and forecasting of water-gas ratios. This research enhances the versatility of waterflooding characteristic curve, improving the precision of water production forecasts and providing a robust foundation for water management strategies. Therefore, it has significant practical implications.

Molecular Insights into Hybrid CH4 Physisorption-Hydrate Formation in Spiral Halloysite Nanotubes: Implications for Energy Storage.

A microscopic insight into hybrid CH4 physisorption-hydrate formation in halloysite nanotubes (HNTs) is vital for understanding the solidification storage of natural gas in the HNTs and developing energy storage technology. Herein, large-scale microsecond classical molecular dynamics simulations are conducted to investigate CH4 storage in the HNTs via the adsorption-hydration hybrid (AHH) method to reveal the effect of gas-water ratio. The simulation results indicate that the HNTs are excellent nanomaterials for CH4 storage via the adsorption-hydration hybrid method. The CH4 physisorption and hydrate formation inside and outside of the HNTs are profoundly influenced by the surface properties of the HNTs and the kinetic characteristics of CH4/H2O molecules. The outer surfaces of the HNTs exhibit relative hydrophobicity and adsorb CH4 molecules to form nanobubbles. Moreover, CH4 molecules adsorbed on the outer surface are tightly trapped between the hydrate solids and the outer surface, inhibiting their kinetic behavior and favoring CH4 storage via physisorption. The inner surface of the HNTs exhibits extreme hydrophilicity and strongly adsorbs H2O molecules; thus, CH4 hydrate can form inside of the HNTs. It is more difficult for CH4 and H2O molecules inside of the HNTs to convert into hydrates than for those outside of the HNTs. A moderate gas-water ratio is advantageous for CH4 physisorption and hydrate formation, whereas excessively high or low gas-water ratios are unfavorable for efficient CH4 storage. These insights can help to develop an efficient CH4 solidification storage technology.

Gas–Water–Sand Inflow Patterns and Completion Optimization in Hydrate Wells with Different Sand Control Completions

Sand production poses a significant problem for marine natural gas hydrate efficient production. However, the bottom hole gas–water–sand inflow pattern remains unclear, hindering the design of standalone screen and gravel packing sand control completions. Therefore, gas–water–sand inflow patterns were studied in horizontal and vertical wells with the two completions. The experimental results showed that gas–water stratification occurred in horizontal and vertical standalone screen wells. The gas–water interface changed dynamically, leading to an uneven screen plugging, with severe plugging at the bottom and high permeability at the top. The high sand production rate and low well deviation angle exacerbated screen plugging, resulting in a faster rising rate of the gas–water interface. The screen plugging degree initially decreased and then increased as the gas–water ratio increased, resulting in the corresponding variation in the gas–water interface rising rate. Conversely, gas–water stratification did not occur in the gravel packing well because of the pore throat formed between the packing gravels. However, the impact of gas and water led to gravel rearrangement and the formation of erosion holes, causing sand control failure. A higher gas–water ratio and lower packing degree could result in more severe destabilization. Therefore, for the standalone screen completion, sand control accuracy should be designed at different levels according to the uneven plugging degree of the screen. For the gravel packing completion, increase the gravel density without destabilizing the hydrate reservoir, and use the coated gravel with a cementing effect to improve the gravel layer stability. In addition, the screen sand control accuracy inside the gravel packing layer should be designed according to the sand size to keep long-term stable hydrate production.

A Sensitive Frequency Band Study for Distributed Acoustical Sensing Monitoring Based on the Coupled Simulation of Gas–Liquid Two-Phase Flow and Acoustic Processes

The sensitivity of gas and water phases to DAS acoustic frequency bands can be used to interpret the production profile of horizontal wells. DAS typically collects acoustic signals in the kilohertz range, presenting a key challenge in identifying the sensitive frequency bands of the gas and water phases in the production well for accurate interpretation. In this study, a gas–water two-phase flow–acoustic coupling model for a horizontal well is developed by integrating a gas–water separation flow model with a pipeline acoustic model. The model simulates the sound pressure level (SPL) and amplitude variations of acoustic waves under different flow patterns, spatial locations, and gas–water ratio schemes. The results demonstrate that within the same flow pattern, an increase in the gas–water ratio significantly elevates acoustic amplitude and SPL peaks within the 5–50 Hz frequency band. Analysis of oil field DAS data reveals that the amplitude response range for stages with a lower gas–water ratio falls within 5–10 Hz, whereas stages with a higher gas–water ratio exhibit an amplitude response range of 10–50 Hz.

How shallow CO2 hydrate cap affects depressurization production in deeper natural gas hydrate reservoirs: An example at Site W17, South China Sea

The logging results from the Shenhu Sea show that the P-T conditions of NGH deposits are below the CO2 hydrate phase equilibrium curve. The burial depth difference between the CO2 hydrate stable zone and NGH deposits is usually above 100 m, which differs from the laboratory scale. Thus, whether CO2 hydrate caps can provide pore sealing and reinforcement of natural gas hydrate (NGH) overburden at the engineering scale is unknown. Based on this, we aimed to perfect research on the CO2 hydrate cap, including its formation process, effects on NGH exploitation, geomechanical response, and comprehensive benefit evaluation, by establishing a THMC model based on Site W17. Results indicate that (i) CO2 can form hydrates in the overburden layer with a conversion rate of about 28%, preventing the upward escape of residual liquid CO2 due to density difference. (ii) CO2 injection and CO2 hydrate cap formation can increase the decomposition driving force during depressurization to enhance production, but it fails to inhibit water invasion from the upper part of the NGH deposit due to the excessive depth difference. (iii) The CO2 hydrate cap causes strata uplift, thereby mitigating strata subsidence during depressurization production, especially for the cases of horizontal wells, where the subsidence is reduced by about 103.4%. (iv) Injecting too much CO2 may not benefit gas production, where part of the free gas will convert into NGH due to pressure rise. The optimal injection rate in this study is 40,000 m3/d. (v) Indicators like CO2 hydrate conversion rate, gas-water ratio, and maximum strata displacement show that horizontal well systems with CO2 hydrate caps are more beneficial than vertical well systems, and multi-branched well systems are more beneficial than single-direction well systems. These key findings may differ from the laboratory scale, which can provide a reference for applying CO2 hydrate caps in actual NGH exploitation.

Analysis of Water Production Factors of Gas Wells in Sulige Gas Field

Abstract The Sulige gas field, characterized by its low porosity and poor permeability, faces challenges in managing the complex gas-water distribution, which has become a growing concern as the field develops. This complexity, coupled with the varied and intricate nature of water production, has impacted the field’s efficiency. To tackle this issue, a study was carried out on water-producing gas wells within the field, examining the production mechanisms, main factors, and distribution patterns. The study found that in the field’s central region, the gas-water ratio in water-producing wells is relatively stable, with some wells yielding over 0.8m3 of water per day. The water sources include formation water, pore water, and water from the wellbore edges and bottom, as well as industrial water usage. Understanding these factors helps mitigate the negative impact of water production on field development and provides guidance for managing similar gas fields effectively.

Livestock and poultry waste compost as an amendment in medium for pumpkin seedlings

This research evaluated cow dung compost (CDC), goose dung compost (GDC), and duck dung compost (DDC) as peat addition in growing media used for the production of pumpkin seedlings. Commercial substrate (peat: vermiculite: perlite=3:1:1, v/v) was used as the control (CK). The partial addition in peat of each waste compost in the mixtures were 10%, 20%, and 30% (v/v). The results showed that all compost in mixtures increased bulk density, total porosity, electrical conductivity, and mineral content, but negatively affected the pH and organic matter of the growing media compared to CK. CDC in mixture increased ventilation porosity and gas-water ratio and decreased water-holding porosity compared to CK, which was the opposite of the effect of GDC and DDC. The mixtures elaborated with GDC showed better growth, biomass, gas exchange parameters, and physiological indicators of seedling plants than other treatments in varying degrees, which depended on the additional amount of GDC. DDC inhibited plant growth and gas exchange parameters, especially in high addition rate; however, it had a slight promotion effect on chlorophyll content and quality because DDC was rich in minerals. GDC was better than CDC and DDC as a partial addition for peat in the cultivation of pumpkin seedlings.

A Coupling Model of Gas–Water Two-Phase Productivity for Multilateral Horizontal Wells in a Multilayer Gas Reservoir

A series of complex horizontal wells have been implemented in challenging gas reservoirs. Multilateral horizontal well technology can be used in multilayer gas reservoirs, facilitating the expansion of the gas drainage area and enhancing productivity. Accurate productivity calculations for multilateral wells in multilayer reservoirs are essential for effective reservoir development. However, there have been few studies in this area. This paper introduces a coupling model for calculating the gas–water two-phase productivity of multilateral wells in multilayer reservoirs, based on the principles of conformal transformation and superposition of potential functions. The accuracy of the model is validated by obtaining the distribution of flow along the horizontal wellbore through numerical simulation cases. The results from the field case and sensitivity analysis indicate that the pressure difference increases nonlinearly from the toe to the heel, and the productivity of multilateral wells decreases as the gas–water ratio increases. The method proposed in this paper is applicable for calculating the productivity of multilateral wells in multilayer reservoirs.

The injection pattern investigation of hydrocarbon gas enhanced oil recovery in heterogeneous reservoirs

Considering the large difference in physical properties and low water flooding efficiency of heterogeneous reservoirs, the hydrocarbon gas flooding to enhance oil recovery was investigated. Through the rising bubble apparatus experiment, it was determined that the injected gas and crude oil are immiscible under formation conditions. On the other hand, the displacement experiment carried out on a long core was used to perform the effect of hydrocarbon gas flooding. According to displacement experiment, alternative injection of gas as slugs with water slugs can mobilize the residual oil in place in the reservoirs. When the gas injection rate is 0.5 cm3/min, the recovery efficiency of hydrocarbon gas flooding is highest. At the same time, the lower of water content, the better the timing of waterflooding to gas flooding. In experiments with slugs of different gas–water ratios, when the gas–water ratio is 1:1, the oil recovery efficiency is the highest. The water alternate gas in use within limit adaptation could significantly enhance the residual oil recovery and bring more economic benefits.

Iron-carbon microelectrolysis coordinated advanced N and P removal from municipal tailwater: Unexpected N conversion and microbial characteristic

The biochemical mechanisms that iron-carbon microelectrolysis (IC-ME) advanced and coordinated treating nitrogen (N) and phosphorus (P) from tailwater are not intensive. Depending on the optimal operating conditions of the iron carbon biofilter (ICBF), the interface P reaction, functional microbial community and characteristics were analyzed. Results demonstrated that iron (Fe) engaged in reaction with nitrate nitrogen (NO3−-N), facilitating the release of both nitrite nitrogen (NO2−-N) and ammonia nitrogen (NH4+-N) to 0.75 and 2.46 mg/L. Total nitrogen (TN) and total phosphorus (TP) were simultaneously removed lower than 10 and 0.3 mg/L under the optimum conditions i.e., gas water ratio of 15, empty bed contact time (EBCT) of 105 min, and backwashing cycle of 12 h. Microelectrolysis (ME) exhibited a robust capacity to degrade macromolecular pollutants, and P was predominantly eliminated via Fe3(PO4)2 and Fe4(PO4)3(OH)2 precipitation. Intriguingly, IC-ME did alter the microbial community composition, especially the Fe-containing microflora (Desulfuromonas, Azospira, Denitratisoma, Rhodobacter and Paludibaculum). The relatively high abundance of Gammaproteobacteria (29.67–38.3 %) promoted N transformation and the N cycle was mainly dominated by nitrogen respiration (1.95–3.39 %), nitrate reduction (2.06–3.45 %) and nitrate respiration (1.95–3.39 %). ME invigorated functional metabolism, thereby promoting organic carbon metabolism.

Study on the influence of coal on coal-to-ethylene glycol process considering the integration of reactor, distillation column, and heat exchanger network

The ethylene glycol (EG) process has low energy efficiency and high emissions. The raw coals purchased from different mines have different compositions and affect the reactor/column parameters and the integration of the heat exchanger network (HEN). An integrated reactor-distillation column-HEN model is built for optimizing the coal-to-ethylene glycol (CTEG) process considering the variation of raw coal. The particle swarm optimization (PSO) algorithm is used to solve this model and target the optimal raw coal for the CTEG process based on the interaction of MATLAB and Aspen Plus software. The influence of raw coal is obtained based on the sensitivity analysis performed for key reactor parameters and energy consumption. For the identified optimal raw coal, the mass fraction of carbon, hydrogen, oxygen, and ash are 84.02%, 6.80%, 1.00%, and 5.00%, respectively; the water added in the coal-water slurry is 62.15 t·h−1, and the water-gas ratio is 0.32, the corresponding energy consumption and the CO2 emission per unit product are 0.093 kgce⋅kmol−1 and 0.247 kgCO2⋅kmol−1, both decreased by 32.61%. The proposed method can be used to optimize the design and operation of the CTEG process and extended to optimize the other coal-based processes to achieve cleaner production.

Cushion gas effects on hydrogen storage in porous rocks: Insights from reservoir simulation and deep learning

Underground hydrogen (H2) storage (UHS) is crucial for the H2 economy, offering scalable and long-term solutions vital for reliable and sustainable H2-based energy systems. Cushion gas is a common component in UHS designs, but its impact on H2 storage performance is not yet fully understood. This study bridges this research gap by systematically investigating the effects of various cushion gas scenarios on UHS performance in porous rocks, specifically saline aquifers and depleted gas reservoirs, using reservoir simulations and deep learning. Firstly, we conducted 8,000 multiphase compositional reservoir simulations for UHS operations in two types of storage formations, considering four cushion gas scenarios: no cushion gas, methane (CH4), nitrogen (N2), and carbon dioxide (CO2). These simulations cover a wide range of geological and operational parameters relevant to practical UHS projects. From these simulations, we derived key insights into the physical mechanisms governing UHS processes and proposed critical storage performance metrics, including H2 withdrawal efficiency, produced H2 purity, produced gas–water ratio, and well injectivity. Then, we developed a unified reduced-order model (ROM) using a deep neural network (DNN) based on the comprehensive simulation results. The DNN architecture, with an input layer, five hidden layers, and an output layer, takes 12 geological and operational parameters as inputs, and forecasts the four performance metrics. The ROM accurately predicts the cyclic evolution of performance metrics and is over 5,000,000 times faster than traditional physics-based simulations, allowing for thorough uncertainty quantification of UHS performance prediction under various geological and operational conditions. Key findings of this study include: (a) UHS in porous rocks is technically promising, with improving storage performance over cycles; (b) UHS in saline aquifers has higher withdrawal efficiency and purity but lower gas–water ratio and injectivity compared to depleted gas reservoirs; (c) In saline aquifers, cushion gas reduces withdrawal efficiency and purity but significantly enhances gas–water ratio and injectivity, making it particularly beneficial in scenarios with high water production risks; (d) In depleted gas reservoirs, cushion gas is less important under the current operational conditions, as it barely affects withdrawal efficiency and purity, and these reservoirs inherently exhibit high gas–water ratio and injectivity due to initial/leftover native gas (mostly CH4); (e) The cushion gas type slightly affects storage performance, with N2 slightly outperforming CH4 and CO2 in withdrawal efficiency and purity, CO2 being better for gas–water ratio, and CH4 for injectivity. The findings of this study support cushion gas designs in future UHS projects in both saline aquifers and depleted gas reservoirs. Moreover, the developed ROM offers a highly efficient tool for conducting extensive sensitivity analysis and uncertainty quantification, optimizing operational conditions, and facilitating the screening of potential field sites for future UHS projects.

A new workflow for warning and controlling the water invasion

Warning and controlling the water invasion in water-driving reservoirs is significant because water invasion will seriously hamper well productivity and gas recovery. Unfortunately, there are few comprehensive methods to control water invasion. First, we establish and verify a water invasion model of reservoir scale. Then, a new workflow for warning and controlling the water invasion is proposed using the numerical simulation method. The workflow first judges the water invasion characteristics, determines the water invasion index based on the production data, and then controls the water invasion by finding and closing the perforation layer of serious water production. Finally, the optimal water control scheme is obtained by comparing water and gas production. The results show that the accuracy of the geological reserves of the established water invasion model is 99% and has a good pressure fitting result. The early warning chart for the gas reservoir in the west of Amu Darya B area is drawn, including the early warning pressure and the level 1, level 2, and level 3 early warning water–gas ratio, which is convenient for field application. For the water-driving wells west of area B, the early warning value of the water–gas ratio increases with the increase of gas production rate during fixed production and decreases with the increase of bottom hole pressure during constant pressure production. Closing the harmful perforation from the water-finding study will significantly reduce the water while retaining the gas production. After water control technology, water production decreased by 90.9%, while gas production decreased by only 9.7%.

Decarbonization of simulated biogas with microchannel mixer by pressurized water scrubbing

Pressurized water scrubbing is an environmentally friendly technology for the decarbonization of biogas. However, the key bottlenecks such as low efficiency, high cost of water consumption and secondary CO2 emission by water absorption and desorption in the process of decarbonization are still necessary to be solved. This study focused on improve the mass transfer effect by introduce finger-crossed microchannel in the process of simulated biogas decarbonization using pressurized water scrubbing. The simulated biogas was mixed with pressurized water in the finger-crossed microchannel, and the gas-water mixture was continuously separated in the gas-water separation tank. The effects of pressure (26–30 bar), temperature (5–30 °C), gas-water ratio (5:1–12:1), liquid volumetric flowrate (5–10 mL/min), and other factors on the decarbonization were investigated. The overall mass transfer coefficient based on the liquid phase and the CO2 flux were also calculated and analyzed. The decarbonization parameters were optimized using the response surface methodology as follows: temperature 20 °C, pressure 29/27 bar, gas-water ratio 10:1, liquid volumetric flowrate 5 mL/min. The process remained stable, achieving 98 % removal of CO2 under optimal conditions. Furthermore, the CO2 concentration in the purified gas was maintained below 3 %. Additionally, a significant number of micro-nano bubbles were observed in the absorption water obtained through this mixer, and the releasing of CO2 from the water lasted 5 days. These results indicated the excellent decarbonization performance of the finger-crossed microchannel in pressurized water scrubbing and potential application value of new ways of CO2 absorption water without desorption.

Failure analysis of local effusion corrosion in small diameter gas pipeline: Experiment and numerical

In the later stage of gas well production, water–gas ratio increases, liquid carrying capacity decreases, gas field water accumulates in pipes for a long time, and the corrosion environment of pipelines becomes more and more severe. On the basis of carbon dioxide corrosion, microbial corrosion in gas field water accelerates catalytic pitting and finally leads to serious internal corrosion of pipelines. Therefore, accurate prediction of fluid distribution and flow characteristics in pipes is of great significance for engineering applications. In this work, the location and morphology of the corrosion pit were determined by physicochemical analysis. A computational fluid dynamics (CFD) model was established by using VOF and RNG k-ε models to predict fluid distribution characteristics and fluid accumulation locations in pipelines. The results showed that: 1) Corrosion and perforation occurred in the position of pipeline fluid accumulation. 2) The main elements of the corrosion pit on the inner surface of the pipe sample are O, Fe, C, S and Cl. The main corrosive substances in the pipeline corrosion pit are FeCO3 and Fe2O3. 3) The low-lying areas and uphill sections are prone to corrosion. A decrease in the fluid velocity in the pipe and a corresponding increase in the gas–liquid ratio will result in a greater accumulation of liquid in the pipe. 4) Magnetic flux leakage (MFL) detection method can be used to detect the characteristics and distribution of pipeline corrosion defects and determine the corrosion area. The research results are of great significance to the safety evaluation of small diameter pipelines for gathering and transporting in oil fields.

Experimental Study of the Dynamic Water–Gas Ratio of Water and Gas Flooding in Low-Permeability Reservoirs

WAG flooding is a dynamic process of continuous reservoir flow field reconstruction. The unique advantages of WAG flooding cannot be utilized, due to the fixed water–gas ratio. Therefore, we must investigate the dynamic adjustment of the water–gas ratio for WAG flooding. Using nine cases of long-core displacement experiments in low-permeability reservoirs, the development effects of three different displacement methods, namely, continuous gas flooding, WAG flooding with a fixed water–gas ratio, and WAG flooding with a dynamic water–gas ratio, were investigated after elastic development, water flooding, and gas flooding. This study shows that for early elastic development in low-permeability reservoirs, WAG flooding can significantly improve oil recovery, but WAG flooding with a dynamic water–gas ratio is not conducive to the control of the water cut rise and gas channeling. As a result, it is more suitable to adopt WAG flooding with a fixed water–gas ratio. For early water flooding in low-permeability reservoirs, WAG flooding more clearly improves oil recovery and suppresses gas channeling, but WAG flooding with a dynamic water–gas ratio exhibits a higher oil recovery and thus is recommended. For early gas flooding in low-permeability reservoirs, whether the development effect of WAG flooding can improve oil recovery and inhibit gas channeling strongly depends on whether the water–gas ratio is adjusted. The development effect of WAG flooding with a dynamic water–gas ratio is significantly better than that with a fixed water–gas ratio. Therefore, WAG flooding with a dynamic water–gas ratio is recommended to achieve the best displacement effect. This research has important practical significance for further improving the development effect of WAG flooding in low-permeability reservoirs.

Efficient prediction of hydrogen storage performance in depleted gas reservoirs using machine learning

Underground hydrogen (H2) storage (UHS) has emerged as a promising technology to facilitate the widespread adoption of fluctuating renewable energy sources. However, the current UHS experience primarily focuses on salt caverns, with no working examples of storing pure H2 in porous reservoirs. A key challenge in UHS within porous rocks is the uncertainty in evaluating storage performance due to complicated geological and operational conditions. While physics-based reservoir simulations are commonly used to quantify H2 injection and withdrawal processes during storage cycles, they are computationally demanding and unsuitable for providing rapid support to UHS operations. In this study, we develop efficient reduced-order models (ROMs) for UHS in depleted natural gas reservoirs using deep neural networks (DNNs) based on comprehensive reservoir simulation data sets. The ROMs can accurately forecast UHS performance metrics (H2 withdrawal efficiency, produced H2 purity, produced gas-water ratio) across various geological and operational conditions and are over 22000 times faster than physics-based simulations. Then, we employ the ROMs for sensitivity analysis to assess the impact of geological and operational parameters on UHS performance and conduct uncertainty quantification to characterize potential performance and associated probabilities. Lastly, we present a field case study from the Dakota formation of the Basin field in the Intermountain-West (I-WEST) region, USA. Based on the ROMs’ predictions, Dakota formation is favorable for UHS due to its high H2 withdrawal efficiency and purity, and low water production risk. By optimizing operational parameters, we can further improve the storage performance in Dakota formation and reduce the uncertainty in UHS performance prediction. This study introduces an efficient ROM-based approach to assess and optimize UHS performance, supporting the development of effective UHS projects in depleted gas reservoirs.

Establishment and application of temperature–pressure coupling model for opening and closing wells in HTHP gas wells

Switching wells in high-temperature and high-pressure gas wells will affect parameters such as the temperature and pressure of the fluid in the wellbore. Dynamic monitoring of temperature and pressure is difficult, and wellbore temperature, pressure, and fluid physical parameters are coupled to each other. Obtaining them separately will lead to large calculation errors. In order to improve the prediction accuracy of temperature and pressure in high-temperature and high-pressure gas wells, Based on the temperature–pressure coupling algorithm, this study compares the advantages and disadvantages of nine classic algorithms based on the temperature–pressure coupling algorithm, considers the impact of high temperature and high pressure on the temperature and pressure of the gas wellbore fluid, and establishes an unsteady temperature–pressure coupling model for high-temperature and high-pressure gas wells under on–off well conditions. Comparing with the measured data, it is proved that the prediction accuracy of the unsteady temperature–pressure coupling model of high-temperature and high-pressure gas wells meets the construction requirements of switch wells. The established model is used to simulate the temperature and pressure distribution of two high-temperature and high-pressure gas wells under switching conditions. The analysis shows that the distribution of wellbore temperature and pressure under the switch on and off conditions is affected by the gas–water ratio, heat transfer coefficient, tube size, and gas well production. Among them, the gas–water ratio increased by 1.5 times, the wellhead temperature increased by 25%, and the wellhead pressure decreased is 7.68%; When the heat transfer coefficient is increased by 1.5 times, the wellhead temperature drops to 34.38% and the wellhead pressure drops to 2.29%. When the tube size is increased by 1.125 times, the wellhead temperature is reduced by 44.20% and the pressure is increased by 6.09%. When the production of gas well is doubled, the wellhead temperature increases by 40.79% and the wellhead pressure decreases by 2.29%. The results can be used as a basis for the construction of high-temperature and high-pressure gas wells.

Numerical Simulation and Parameter Optimization for Water-to-CO2 Flooding in a Strongly Water-Sensitive Reservoir.

Carbon dioxide flooding can accelerate the development of low-permeability reservoirs of the Kexia group in the K region of the T oil field, thus resolving the issue of inadequate water drive effects. This study was focused on the well group 80513 in the K region, and based on the reservoir and fluid parameters, a simulation model of water-sensitive post-CO2 flooding was constructed to refine the gas injection strategy gradually. The injection rate of the continuous gas injection stage was preferred based on the degree of recovery. Multiindicator and multifactor injection and extraction schemes were established to optimize and analyze the key controlling factors, including the gas injection rate, gas injection period, gas-to-water ratio, and bottom-hole flow pressure, in the carbon dioxide gas-to-water alternation process. Recovery efficiency, oil exchange rate, formation pressure, and carbon dioxide storage rate were used as indicators. After 5 years of continuous CO2 flooding, the results indicated that switching to CO2 gas-water alternating flooding was more appropriate for the target block's environment. The best development plan was achieved when the gas injection rates were 1.0 and 1.25 × 104 m3·d-1 for continuous gas injection and CO2 gas-water alternating flooding, respectively, with a gas-water ratio of 1:1, a gas injection cycle of 90 days, and a bottom-hole flow pressure of 25 MPa in the production wells. A comparison between the results revealed that the formation pressure and oil recovery efficiency of this well group significantly increased upon CO2 flooding, and the parameter optimization results were well suited for controlling the gas flurry, offering a versatile model for future development of the block.

Material balance evaluation method for water-bearing gas reservoirs considering the influence of relative permeability

In this paper, we developed a material balance method based on a two-phase flow equation for evaluating the development efficiency in gas reservoirs. The calculating results show that the theoretical curves of development performance simulated by material balance fit well with early production data and can be used to evaluate the development efficiency of the field. The influence parameters of the theoretical curves were analyzed by simulating a constant production gas reservoir. The results show that the numerical differences between the initial water saturation and the water saturation at the isotonic point of the relative permeability curve greatly influence the theoretical curves. The higher the ratio of water phase relative permeability to gas phase relative permeability, the higher the water-gas ratio in the early and middle periods of well production. It is beneficial to exploit the underground fluid with a large average rock compressibility coefficient which means a strong formation elastic energy. Besides, the value of initial water saturation will also influence the loss of formation elastic energy. This study extends the applicability of material balance and avoids the cost risk of field well testing. Therefore, it has a good practical significance.