Publisher: Geological Society of America   (Total: 4 journals)   [Sort by number of followers]

Showing 1 - 4 of 4 Journals sorted alphabetically
Bulletin of the Geological Society of America     Hybrid Journal   (Followers: 34, SJR: 2.329, CiteScore: 4)
Geology     Full-text available via subscription   (Followers: 56, SJR: 3.114, CiteScore: 4)
Geosphere     Open Access   (Followers: 2, SJR: 1.752, CiteScore: 3)
Lithosphere     Open Access   (Followers: 2, SJR: 1.892, CiteScore: 3)
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Lithosphere
Journal Prestige (SJR): 1.892
Citation Impact (citeScore): 3
Number of Followers: 2  

  This is an Open Access Journal Open Access journal
ISSN (Print) 1941-8264 - ISSN (Online) 1947-4253
Published by Geological Society of America Homepage  [4 journals]
  • Research on the Application of Double-Tube Gas Lift Drainage Recovery in
           Coalbed Methane Wells: A Case Study of the Hancheng Block, China

    • Authors: Li C; An Y, Yang Y, et al.
      Abstract: AbstractThe key point in coalbed methane (CBM) wells is to pump out the confined water to produce gas. Traditional drainage coalbed methane recovery methods have different limitations and characteristics. A new drainage gas recovery method called double-tube gas lift is applied in the Hancheng block for CBM production. The working mechanism of double-tube gas lift technology is to insert a hollow sucker rod into the original production pipe string to assist CBM production. What is more, the gas production channel and the drainage channel can be distinguished by this method. An improved measure is designed to overcome the double-tube gas lift’s shortcomings by adjusting the entry depth of the smaller tubing to expose the coal seam. In this way, the two-phase liquid of injected gas and produced liquid can be discharged from the annulus between the tubing and the smaller tubing. The produced gas is directly discharged from the annulus between the external tubing and the casing. The analysis of influence factors shows that the gas injection volume, water production, smaller-diameter tubing size, and the well entry depth have a significant influence on the production of the double-tube gas lift technology. The improved double-tube gas lift method has been applied in the Hancheng CBM wells to prove that this method has great production results and has the potential to get more applications in other CBM fields.
      PubDate: Sat, 14 May 2022 00:00:00 GMT
       
  • Comprehensive Investigation of the Petrophysical and Two-Phase Flow
           Properties of the Tight Sandstone in Yanchang Formation, Ordos Basin,
           

    • Authors: Wang Y; Song R, Liu J, et al.
      Abstract: AbstractAccurate determination of petrophysical and fluid transporting properties of rocks is essential for many engineering applications. In this paper, microcomputed tomography (CT) imaging technique is adopted to image the microstructure of tight sandstones drilled from Chang-7 member in Yanchang Formation. The pore geometry, pore-throat size distribution, pore connectivity, and tortuosity of the pore-throat structure are quantitatively characterized by extracting the pore network model (PNM). Direct numerical simulation (DNS) approach is applied on the segmented CT images to investigate the anisotropic permeability of tight sandstones. In addition, the unstructured mesh model of the pore space is reconstructed, and the pore scale immiscible two-phase flow is simulated by computational fluid dynamics (CFD) using the volume of fluid (VOF) model. The results indicate that the pore-throat system of tight sandstone reservoirs is mainly composed of discontinuous intergranular pores and grain margin microfractures with poor connectivity and diverse pore morphology. The two-phase flow simulations indicate that the strong heterogeneity of pore-throat structure can lead to obvious fingering phenomenon of the injected fluid, which reduces the sweep efficiency and the oil recovery as well. The residual fluids are mainly trapped in tiny throats and dead-end pores. It is found that the digital rock analysis based on CT imaging can be a cost-effective and time-saving alternative to routine core analysis of tight sandstone reservoirs.
      PubDate: Sat, 14 May 2022 00:00:00 GMT
       
  • Understanding Hydrothermal Activity and Organic Matter Enrichment with the
           Geochemical Characteristics of Black Shales in Lower Cambrian,
           Northwestern Hunan, South China

    • Authors: Dong L; Huang Y, Li W, et al.
      Abstract: AbstractThere are many hydrothermal activities in the early Cambrian in northwestern Hunan, and Zhangjiajie and Xinhuang-Tianzhu are the concentration region which brings much influence during this time. Based on the total organic carbon, mineral composition, element analysis, and so on, the wells have no or little hydrothermal activity in HY1, XJD1, and XAD1 and may also have limited effects by the hydrothermal activity. However, the hydrothermal sediments can come to the wells during the sedimentary period of Niutitang formation. XJD1 has a clear diminishing trend on the intensity of hydrothermal activity. It also shows the high element enrichment by the hydrothermal activity. XAD1 show little influence in contrast, and HY1 is between them. The enrichment of the element is a result of the combination of effects of hydrothermal activity, anoxic/euxinic conditions, biological forces, etc. The hydrothermal activity can improve the paleoproductivity and especially enhance the reducibility in the sedimentary environment. Reducibility is one of the major factors affecting organic matter enrichment. Finally, the sedimentary model with hydrothermal activity can be established in the Ediacaran-Cambrian transition. That will help to understand the distribution laws of high-quality source rocks and provide evidences on shale gas exploration.
      PubDate: Sat, 14 May 2022 00:00:00 GMT
       
  • Source Analysis and Countermeasure Research of Sand Production after
           Hydraulic Fracturing in Tight Sandstone Gas Reservoir

    • Authors: Peng H; Yang J, Peng J, et al.
      Abstract: AbstractSand production is the most common problem after hydraulic fracturing treatment. This problem is particular prominent in sandstone reservoirs. For Jinqiu gas reservoir of Sichuan Basin in China, the average sand production after fracturing is 103 tons, and the sand production rate is 2.36% through statistics of 12 wells. The sand production will seriously damage the downhole equipment as well as ground facilities. In this study, based on the analysis of sand production source, it is clear that the sand production mainly is 70/140 mesh sand flowback after hydraulic fracturing treatment. In order to control this proppant flowback, average fibers length of about 3 mm, 6 mm, 9 mm, and 12 mm are selected for proppant flowback control experimental study. A series of laboratory evaluations are designed to quantify the effectiveness of fibers on proppant flowback control, so as to explore the mechanisms behind for optimizing their properties for a chosen reservoir. The key fiber properties include dispersion performance, microstructure, the influence on proppant transport in fracture, fracture conductivity, and critical flowrate. The dispersion of fibers with different lengths and concentrations in slickwater is good, and the fibers can form a net-like structure that reinforces the pack, and for 70/140 mesh sand and 40/70 mesh resin-coated sand, with the increase of fiber length and concentration, the sand transport distance and critical flowrate increase, but fracture conductivity decreases. The field test is carried out through the fiber type and dosage optimized by indoor experiment. A systematic indoor evaluation and field test shows that fiber plays a significant role in proppant flowback control. The findings of this study can help for a better understanding of the source analysis and countermeasure research of sand production after hydraulic fracturing in tight sandstone gas reservoir.
      PubDate: Tue, 10 May 2022 00:00:00 GMT
       
  • Theoretical Research in Laboratory and Field Trial of Micro-Nano-Oil
           Displacement System Conformance Control Technology

    • Authors: Sun Z; Wang X, Xie K.
      Abstract: AbstractIn recent years, a series of field tests of a new micro-nano-oil displacement system (MNS) conformance control technology have been carried out in different oilfields, which can increase oil production and reduce water cut obviously. However, compared with its field application, the research on its performance evaluation and oil displacement mechanism is still in the initial stage. And it is urgent to carry out relevant research work. Therefore, this paper made a profound study on its physicochemical properties, reservoir adaptability, transport and deep fluid diversion ability, and oil displacement mechanism. Results show that MNS with a series of particle sizes in different sizes (from nanometer to micrometer) can be obtained. And it has good expansion ability. Through reservoir adaptability evaluation, the matching relationship between the size distributions of MNS particles and pore throat is given, which has important guiding significance for MNS particle size selection for target reservoir before field trial. Furthermore, MNS has strong transport ability. When migrating in the porous media, it shows the motion feature of “trapping, deformation, migration, retrapping, redeformation, and remigration,” which can obtain better oil incremental effect than traditional polymer flooding. Under the condition of the same agent type, composition, and slug size, the oil recovery rate can be further enhanced by 6.96%. In addition, MNS conformance control technology has obtained good technical and economic effect in the 8 oilfields, with the lowest input-output ratio of 1.67 and the highest of 14.37. The reason why MNS have the above-mentioned good performances depends on its advanced mechanism: the unique particle phase separation phenomenon. When transporting in porous media, MNS particles gather in the larger pore to form bridge blocking, and its carrier fluid displaces oil in the small pore. Working in cooperation, MNS can realize deep fluid diversion and expand macroscopic and microscopic swept volume.
      PubDate: Mon, 09 May 2022 00:00:00 GMT
       
  • Evaluation of Different Machine Learning Frameworks to Estimate CO 2
           Solubility in NaCl Brines: Implications for CO 2 Injection into
           Low-Salinity Formations

    • Authors: Mohammadian E; Liu B, Riazi A, et al.
      Abstract: AbstractAn accurate estimation of carbon dioxide (CO2) solubility in brine is of great significance for industrial applications such as quantifying CO2 sequestration in subsurface formations, CO2 surface mixing, and different CO2-based enhanced recovery methods (EOR). In this research, four different data-driven/machine learning techniques, extreme gradient boosting (XGB), multilayer perceptron (MLP), K-nearest neighbor (KNN), and in-house genetic algorithm (GA), were used to estimate solubility in terms of pressure, temperature, and salinity. Pressure, temperature, and salinity were used as model inputs, while CO2 solubility was the output. The experimental database used in this study was collected by dissolving CO2 into NaCl brines at salinity ranging from 0 to 15000 ppm, temperature ranging from 298 to 373 K, and pressures up to 200 atm. All data-driven models accurately estimated solubility through a coefficient of correlation (R2) ranging from 0.95 to 0.99, and a precise simple-to-use empirical solubility equation was developed using GA. The performance of the models was analyzed using proper model metrics (such as mean absolute error and relative error). A detailed feature importance analysis was conducted using feature importance, permutation, and Shapley values to clarify the correlation between the input and output parameters. The pressure was found to be the most impactful feature, followed by temperature and salinity. The model’s accuracy was compared to a well-established solubility model from the literature, and a good agreement between the two models’ results was observed. Lastly, conducting sensitivity analysis on the model revealed that the model’s estimations were still accurate when pressure and salinity were beyond the scopes of the original dataset.
      PubDate: Wed, 04 May 2022 00:00:00 GMT
       
  • Experimental Study on Influences of Self-Preservation Effects and Memory
           Effects on the Hydrate Decomposition Process

    • Authors: Li Z; Tian X, Li Z, et al.
      Abstract: AbstractIn order to explore the characteristics of the hydrate decomposition behavior at the pore scale, this study carries out a pore-scale experimental study of methane hydrate decomposition based on the high-pressure visual model under the etched glass. A mathematical model is also constructed to analyze the behavioral characteristic of the self-preservation effect and memory effect during the hydrate decomposition period. This study draws the following conclusions: (1) The self-preservation effect and memory effect exist during the methane hydrate decomposition lead by depressurization, which generally inhibits the hydrate decomposition process. (2) The hydrate self-preservation effect is a transition of the surface water film’s phase state to inhibit the methane hydrate decomposition, in which the liquid phase transforms into a metastable “quasiliquid film”. (3) The multiple syntheses induced by the hydrate memory effect are a periodic attenuation process. The times of synthesis are a critical factor affecting the hydrate gas production and decomposition rate. (4) The self-preservation and memory effects during the hydrate decomposition period are associated with each other. The two are correlated at some degree with playing a dominant role alternately at different stages. The self-preservation effect is an abnormal behavior of the hydrate, which refers to the hydrate’s transition from the solid phase to the gas-liquid mixed phase. The memory effect is another abnormal behavior, which refers to the transition from the gas-liquid mixed phase to the solid phase. The sustaining pressure drop is the key reason of the disappearance of the two effects. This research was aimed at providing a theoretical basis for the exploitation and optimization of marine natural gas hydrates.
      PubDate: Thu, 14 Apr 2022 00:00:00 GMT
       
  • Risk Assessment Method for Bullheading Killing Based on the Uncertainty of
           Formation Parameters

    • Authors: Chi P; Qingfeng L, Jianhong F, et al.
      Abstract: AbstractTo analyze the risks caused by the uncertainty of formation parameters to bullheading killing, a method for quantitatively evaluating the bullheading killing risks is established. Firstly, considering the influence of gas invasion volume, formation fracture, and killing parameters, a bullheading killing model is established based on a gas-liquid two-phase flow. Then, the uncertainties of formation parameters (formation pressure and permeability) are quantified. Based on the shut-in wellhead information, the range of formation pressure is predicted with the gas column model and multiphase flow model. Considering the influence of formation fracture on the permeability, Monte Carlo random sampling is applied to predict the range of formation permeability. Based on industry standards, a safety pressure value is set up, and the wellbore pressure corresponding to all value combinations of formation parameters under the given killing parameters is obtained by killing model. Moreover, according to the probability and degree that wellbore pressure exceeds the safety value, the risks are rated to quantify the risk of bullheading killing. Under this circumstance, the feasibility and accuracy of this method are validated by practical cases, and it is found by simulation that flow rate can affect the risk of wellhead damage to the greatest extent, and there exists a critical rate. When the flow rate is greater than the critical rate, the increase in flow rate will greatly improve the risk probability. In such case, improving the density of kill fluid can reduce the risk of wellhead damage in a limited way, but it will greatly increase the risks of formation fracture and casing damage. Therefore, for bullheading killing, it is not advisable to employ high-density kill fluid. By this method, the bullheading killing risks can be fully assessed before actual construction, thus providing reference for determining reasonable construction parameters of bullheading killing.
      PubDate: Sat, 19 Mar 2022 00:00:00 GMT
       
 
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