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Journal articles on the topic 'Gas wells'

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Author: Grafiati

Published: 4 June 2021

Last updated: 1 August 2024

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1

Pinchuk, Sofiya, Galina Galchenko, Aleksey Simonov, Ludmila Masakovskaya, and Irina Roslyk. "Complex Corrosion Protection of Tubing in Gas Wells." Chemistry & Chemical Technology 12, no. 4 (December 10, 2018): 529–32. http://dx.doi.org/10.23939/chcht12.04.529.

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2

Sarsenbaevna, Batirova Uldaykhan, Tajetdinova Gulnora Abatbay qizi, and Karjaubayev Marat Ospanovich. "THE PROCESS OF DRILLING OIL AND GAS WELLS." American Journal of Applied Sciences 6, no. 6 (June 1, 2024): 49–52. http://dx.doi.org/10.37547/tajas/volume06issue06-08.

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The process of drilling oil and gas wells is a critical component of the energy industry, playing an important role in the extraction of vital natural resources. This article provides an in-depth exploration of the intricate procedures and technologies involved in drilling operations. From initial site preparation to the complexities of directional drilling, this article aims to shed light on the multifaceted process of extracting oil and gas from beneath the Earth's surface. Throughout this exploration, we will delve into the fundamental principles, safety considerations, environmental impacts, and innovative advancements that shape the modern landscape of drilling operations.

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3

Chu, Hongyang, Tianbi Ma, Zhen Chen, Wenchao Liu, and Yubao Gao. "Well Testing Methodology for Multiple Vertical Wells with Well Interference and Radially Composite Structure during Underground Gas Storage." Energies 15, no. 22 (November 10, 2022): 8403. http://dx.doi.org/10.3390/en15228403.

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To achieve the goal of decarbonized energy and greenhouse gas reduction, underground gas storage (UGS) has proven to be an important source for energy storage and regulation of natural gas supply. The special working conditions in UGS cause offset vertical wells to easily interfere with target vertical wells. The current well testing methodology assumes that there is only one well, and the interference from offset wells is ignored. This paper proposes a solution and analysis method for the interference from adjacent vertical wells to target vertical wells by analytical theory. The model solution is obtained by the solution with a constant rate and the Laplace transform method. The pressure superposition is used to deal with the interference from adjacent vertical wells. The model reliability in the gas injection and production stages is verified by commercial software. Pressure analysis shows that the heterogeneity and interference in the gas storage are caused by long-term gas injection and production. As both the adjacent well and the target well are in the gas production stage, the pressure derivative value in radial flow is related to production rate, mobility ratio, and 0.5. Gas injection from offset wells will cause the pressure derivative to drop later. Multiple vertical wells from the Hutubi UGS are used to illustrate the properties of vertical wells and the formation.

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4

Lin, Jiajing, and Ding Zhu. "Modeling well performance for fractured horizontal gas wells." Journal of Natural Gas Science and Engineering 18 (May 2014): 180–93. http://dx.doi.org/10.1016/j.jngse.2014.02.011.

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5

McCain, W. D., and R. A. Alexander. "Sampling Gas-Condensate Wells." SPE Reservoir Engineering 7, no. 03 (August 1, 1992): 358–62. http://dx.doi.org/10.2118/19729-pa.

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6

Marusin, A., and I. E. Marusin. "AUTOMATION OF GAS WELLS." Международный студенческий научный вестник (International Student Scientific Herald), no. 3 2023 (2023): 19. http://dx.doi.org/10.17513/msnv.21302.

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7

Karnaukhov, M. L., and O. N. Pavelyeva. "WELL TESTING HORIZONTALGAS-CONDENSATE WELLS." Oil and Gas Studies, no. 3 (July 1, 2017): 56–61. http://dx.doi.org/10.31660/0445-0108-2017-3-56-61.

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The well testing of gas-condensate horizontal wells are discussed in the article and the comparative analysis of borehole flow capacity, depending on the mode of it’s operation is presented. Extra attention is focused on the issue of timely identification of the reasons for the reduction of fluid withdrawal from the reservoir. The presence of high skin effect is proved, which confirms the existence of low-permeability of bottomhole formation zone related to condensation in the immediate area of the horizontal wellbore.

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8

Carpenter, Chris. "Expertise in Complex-Well Construction Leveraged for Geothermal Wells." Journal of Petroleum Technology 75, no. 05 (May 1, 2023): 87–89. http://dx.doi.org/10.2118/0523-0087-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204097, “Constructing Deep Closed-Loop Geothermal Wells for Globally Scalable Energy Production by Leveraging Oil and Gas Extended-Reach Drilling and High-Pressure/High-Temperature Well-Construction Expertise,” by Eric van Oort, SPE, Dongmei Chen, SPE, and Pradeepkumar Ashok, SPE, The University of Texas at Austin, et al. The paper has not been peer reviewed. _ In the complete paper, deep closed-loop geothermal systems (DCLGS) are introduced as an alternative to traditional enhanced geothermal systems (EGS) for green energy production that is globally scalable and dispatchable. The authors demonstrate that DCLGS wells can generate power on a scale comparable to that of EGS. They also highlight technology gaps and needs that still exist for economically drilling DCLGS wells, writing that it is possible to extend oil and gas technology, expertise, and experience in extended-reach drilling (ERD) and high-pressure/high-temperature (HP/HT) drilling to construct complex DCLGS wells. Introduction CLGS is considered a subset of EGS, but the authors write that it is a distinct entity. EGS mostly involves well designs that rely on fractures for heat extraction. Such systems are different from CLGS wells in that the latter use closed conduits for thermal fluid circulation and heating. CLGS relies on fluids pumped through a closed loop. The authors treat CLGS systems as being different from EGS systems, with the understanding that drilling technologies discussed in the paper as enablers for CLGS wells apply equally to EGS wells. In the geothermal (GT) domain, the majority of attention and funding currently is assigned to EGS projects. A case is made in the complete paper to continue to develop DCLGS technology because of its favorable risk profile compared with EGS. Part I of the complete paper introduces a hydraulic model coupled with a thermal model suitable for calculating the power generation of DCLGS wells. This synopsis concentrates instead on Part II of the complete paper, in which technology gaps and needs of DCLGS drilling and well construction are highlighted and opportunities identified where oil and gas experience and technology can be directly applied and leveraged. Similarities and Differences of Deep GT and Oil and Gas HP/HT Wells - GT wells generally use larger production hole sizes than typical land wells. - Casing-cement annuli typically are cemented back to surface. - GT wells can be drilled in more-forgiving pore-pressure fracture gradient (PPFG) environments with wider drilling margins than geopressured HP/HT wells in hydrocarbon systems. - Severe lost circulation appears to be a universal problem in deep GT wells. - Drilling costs can account for 50% or more of the total capital costs for a GT energy project. - Data sets on GT wells are much smaller than those for oil and gas wells.

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9

Khudjaev, M., and A. Rakhimov. "Gas flow modeling in wells." Journal of Physics: Conference Series 2131, no. 5 (December 1, 2021): 052075. http://dx.doi.org/10.1088/1742-6596/2131/5/052075.

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Abstract The topic of research is gas flow modeling in wells. The subject of the study is to determine the dynamic parameters of gas in a gas well, taking into account changes in the ambient temperature and gravity. Mathematical and numerical modeling of gas flow in a gas well is performed; a numerical algorithm to determine gas pressure in a gas well is built. This algorithm allows studying the state of production and injection wells with varying conditions at the wellhead and at the lower end of the well. Research methods are based on the energy equations of the transported gas; the mass conservation equation, which are the basic equations of gas flow; the methods of numerical and mathematical modeling. In the article, numerical and mathematical models of gas flow in a gas well are obtained, taking into account changes in the ambient temperature and gravity. A numerical algorithm and a program were built to determine the gas-dynamic characteristics of wells. The computational process was based on the “cycle in cycle” principle. Provisions were made to study the state of production and injection wells with varying conditions at the wellhead and at the bottom end of the well.

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10

Mahadevan, Jagannathan, Mukul Mani Sharma, and Yannis C. Yortsos. "Capillary Wicking in Gas Wells." SPE Journal 12, no. 04 (December 1, 2007): 429–37. http://dx.doi.org/10.2118/103229-pa.

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Summary Gas expansion near the wellbore during production causes the evaporation of connate water. When the reservoir permeability is low, capillarity is controlling, causing liquid movement to the near-wellbore region, where drying rates are higher. In tight-gas sands or in shale gas formations, where capillarity is high, the gas production itself can cause depletion of the water saturation below residual values because of such evaporation. In this work, we present a study of the fundamental processes involved during the flow of a gas in a liquid-saturated porous medium. We have modeled evaporation by accounting for the capillary driven film flow, or "wicking," of saline liquid to the wellbore or the near-fracture region and the effect of gas expansion. It is shown that, for gas reservoirs with connate water saturation, large pressure drawdowns lead to a drying front that develops at the formation face and propagates into the reservoir. When pressure drops are lower, water rapidly redistributes because of capillarity-induced movement of liquid from high- to low-saturation regions. This phase redistribution causes higher drying rates near the wellbore. The results show, for the first time, the effect of both capillarity- induced film flow and gas compressibility on the rate of drying in gas wells. The model can be used to help maximize gas production under conditions such as water blocking by optimizing the operating conditions. Additionally, it can be used to obtain a better understanding of the impact of capillarity on evaporation and consequent processes, such as salt precipitation. Introduction Problems involving gas flow past trapped liquids in porous media are encountered in a variety of contexts, such as water block removal in gas wells, evaporation of volatile oils, and recovery of residual oil. In the case of a binary system, such as gas and water, the thermodynamic phase equilibrium can be represented by a simple linear law and gas injection that reduces to a drying problem in which the remaining liquid is evaporated by the flowing gas. Drying of wetting liquids in porous media has been studied by several authors. These studies mainly focused on pass-over drying, in which gas is passed over a porous medium saturated with the wetting liquid. This form of drying is controlled by the gas flow rate. However, when the liquid recedes into the porous medium, drying is controlled by the rate of diffusion of the components in the liquid phase in the pore spaces. Early in 1949, Allerton et al. studied through-drying of packed beds of crushed quartz and other porous materials by convection of dry gas. The study, however, did not consider the effect of gas compressibility or capillarity. Whitaker developed a diffusion theory of drying using volume averaging methods with constant pressure in the gas phase. This eliminated the effect of compressibility of gas on the drying rates and therefore is useful only in a pass-over drying context. Experimental and simulation studies of gas injection (Dullien et al. 1989; Holditch 1979; Kamath and Laroche 2003) showed that trapped water is first removed by a viscous displacement followed by a long period of evaporation. These studies showed that higher pressure drop, permeability, and temperatures caused greater rates of evaporation and faster progression of saturation drying fronts in both fractured and unfractured wells.

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11

A, Chemmakh. "Evaluation of Liquid Loading in Gas Wells Using Machine Learning." Petroleum & Petrochemical Engineering Journal 7, no. 1 (January 11, 2023): 1–11. http://dx.doi.org/10.23880/ppej-16000333.

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The inevitable result that gas wells witness during their life production is the liquid loading problem. The liquids that come with gas block the production tubing if the gas velocity supplied by the reservoir pressure is not enough to carry them to surface. Researchers used different theories to solve the problem naming, droplet fallback theory, liquid film reversal theory, characteristic velocity, transient simulations, and others. While there is no definitive answer on what theory is the most valid or the one that performs the best in all cases. This paper comes to involve a different approach, a combination between physics-based modeling and statistical analysis of what is known as Machine Learning (ML). The authors used a refined ML algorithm named XGBoost (extreme gradient boosting) to develop a novel full procedure on how to diagnose the well with liquid loading issues and predict the critical gas velocity at which it starts to load if not loaded already. The novel procedure includes a combination of a classification problem where a well will be evaluated based on some completion and fluid properties (diameter, liquid density, gas density, liquid viscosity, gas viscosity, angle of inclination from horizontal (alpha), superficial liquid velocity, and the interfacial tension) as a “Liquid Loaded” or “Unloaded”. The second practice is to determine the critical gas velocity, and this is done by a regression method using the same inputs. Since the procedure is a data-driven approach, a considerable amount of data (247 well and lab measurements) collected from literatures has been used. Convenient ML technics have been applied from dividing the data to scaling, modeling and assessment. The results showed that a wellconstructed XGBoost model with an optimized hyperparameters is efficient in diagnosing the wells with the correct status and in predicting the onset of liquid loading by estimating the critical gas velocity. The assessment of the model was done relatively to existing correlations in literature. In the classification problem, the model showed a better performance with an F-1 score of 0.947 (correctly classified 46 cases from 50 used for testing). In contrast, the next best model was the one by Barnea with an F-1 score of 0.81 (correctly classified 37 from 50 cases). In the regression problem, the model showed an R2 of 0.959. In contrast, the second best model was the one by Shekhar with an R2 of 0.84. The results shown here prove that the model and the procedure developed give better results in diagnosing the well correctly if properly used by engineers.

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12

Young, Alan, and Nigel J. Gay. "Interactions Between Gas Extraction Wells." Waste Management & Research 13, no. 1 (January 1995): 3–12. http://dx.doi.org/10.1177/0734242x9501300102.

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13

Eikrem, Gisle Otto, Bjarne Foss, Lars Imsland, Bin Hu, and Michael Golan. "STABILIZATION OF GAS LIFTED WELLS." IFAC Proceedings Volumes 35, no. 1 (2002): 139–44. http://dx.doi.org/10.3182/20020721-6-es-1901.01491.

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14

Şuţoiu, Florinel, Argentina Tătaru, and Bogdan Simescu. "Rigless jobs in gas wells." AGH Drilling, Oil, Gas 30, no. 1 (2013): 221. http://dx.doi.org/10.7494/drill.2013.30.1.221.

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15

Silin, M. A., L. A. Magadova, M. A. Cherygova, Z. A. Shidginov, and G. R. Kutusheva. "Foamers for gas and gas condensate wells deliquification." Proceedings of Gubkin Russian State University of Oil and Gas, no. 2 (2020): 111–19. http://dx.doi.org/10.33285/2073-9028-2020-2(299)-111-119.

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16

Alsheikhly, M. J., and Sh J. Mirboboev. "FEATURES OF WELL TEST INTERPRETATION RESULTS IN HORIZONTAL WELLS." Oil and Gas Studies, no. 2 (May 1, 2018): 32–34. http://dx.doi.org/10.31660/0445-0108-2018-2-32-34.

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The article explores the features of well test interpretation results of oil and gas horizontal wells in the southern Iraqi fields. The author pays attention to the deconvolution method during processing the results of studying horizontal wells. The conclusion is made to determine the boun-daries of the drainage area of the wells on the need for a long-term study of horizontal wells.

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17

Morgan, Richard G., and Brian T. O'Reilly. "EPA at it again concerning coastal gas wells." Natural Gas 6, no. 7 (August 20, 2008): 7–8. http://dx.doi.org/10.1002/gas.3410060703.

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18

Vusal Zarbaliyev, Shahin Ismayilov, Vusal Zarbaliyev, Shahin Ismayilov. "DETERMINATION OF THE MINIMUM GAS FLOW RATE REQUIRED FOR COMPLETE REMOVAL OF CONDENSATE FROM THE WELL IN GAS-CONDENSATE WELLS." PAHTEI-Procedings of Azerbaijan High Technical Educational Institutions 17, no. 06 (May 18, 2022): 215–19. http://dx.doi.org/10.36962/pahtei17062022-215.

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The article provides a brief analysis of the determination of the minimum gas flow rate required for complete removal of condensate from the wellbore in gas condensate wells. In gas wells, water collects in the wellbore as a result of condensation of produced water and steamed water entering the wellbore together with the well product. In gas condensate wells, gas condensate from the formation is added to it. Thus, part of the filters of gas and gas condensate wells is filled with liquid, which ultimately reduces the flow rate of these wells. At the beginning of the development and operation of gas and gas condensate fields, the amount of liquid (water) and condensate in the gas is low, and due to high formation pressure in the first period of this field, raised to the surface. Over time, the velocity of the well product in the gas condensate wells gradually decreases, and as the amount of water and condensate entering the reservoir increases, the fluid accumulates in the well as the reservoir cannot be fully lifted by its own energy. This creates a counter-pressure on the bottom of the well and affects the formation, which closes with a liquid column in the filter section of the well, which significantly reduces the flow rate of the well, and in some cases leads to a complete shutdown of the well. Various methods have been developed and are still being used to prevent this and to ensure the efficient operation of gas and gas condensate. Keywords: layer waters, condensation, gas condensate, filter, layer pressure, well bottom.

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19

Huang, Zhimin, Wenbin Cai, Huiren Zhang, and Xiangyang Mo. "Liquid Loading of Horizontal Gas Wells in Changbei Gas Field." Processes 11, no. 1 (January 2, 2023): 134. http://dx.doi.org/10.3390/pr11010134.

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The Changbei gas field, which initially exhibited high gas-production performance, is dominated by large-displacement horizontal wells. With the decrease in reservoir pressure, the liquid loading in the gas well is currently severe, and production has been rapidly decreasing. Thus, recognizing the gas-well liquid loading to maintain stable gas-well production is necessary. A method was established to identify the water source of the liquid loading in the Changbei gas field. First, formation water and condensate water were identified based on the mineralization of the recovered water and the mass concentration of Cl− and K+ + Na+, and then the condensate content of the water produced in the gas well was qualitatively evaluated. The water–gas ratio curve for the gas well was plotted to determine whether the produced water was edge-bottom water, pore water, or condensate. Then a method was established to distinguish the start time of liquid loading in the gas well using a curve depicting a decrease in production; the method was also used to estimate the depth of the gas well where liquid loading occurs, according to the bottomhole pressure. First, based on the available production data, the Arps decline model was applied to fit the production curve for the entire production phase; the resulting curve was compared with the actual production curve of the gas well, and the two curves diverged when fluid accumulation began in the gas well. Finally, the liquid-loading depth of the gas well was estimated based on the bottomhole pressure. This method can be used to determine the fluid accumulation and calculate the liquid-loading depth of gas wells with unconnected oil jackets. The analysis revealed that in the Changbei gas field, condensate was the type of water primarily produced in 35 gas wells, accounting for 62.5% of the total number of gas wells. Edge-bottom water was the type of water primarily produced in 16 gas wells, accounting for 28.6% of the total number of gas wells. In the remainder of the gas wells, pore water was the water primarily produced; the calculations of accumulation time and accumulation volume of typical gas wells in the block revealed that some gas wells started to accumulate liquid after 45–50 months, and the amount of accumulation could reach several tens of meters, while others were in good production condition. The method established in this paper could enhance our understanding of liquid loading in gas wells in the Changbei gas field and lay a foundation for the development of gas-well deliquification techniques.

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20

Sung, Wonmo. "Prediction of Production Performance Using RTA for Gas Wells in Horn River Shale Gas Field, Canada." Journal of the Korean Society of Mineral and Energy Resources Engineers 49, no. 6 (2012): 807. http://dx.doi.org/10.12972/ksmer.2012.49.6.807.

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21

Zhang, Qing. "Well Interference Analysis of Shale Gas Wells Based on Embedded Discrete Fracture Model." Geofluids 2022 (April 19, 2022): 1–13. http://dx.doi.org/10.1155/2022/1795369.

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Well interference is commonly observed in shale gas reservoirs due to the small well spacing, and it significantly affects the shale gas production. Effective evaluation of well interference is important to increase the gas production of shale gas wells. Previous researches mainly focus on the well interference phenomenon and production optimization using numerical simulation so that the quantitative analysis of shale gas well interference is rare. Therefore, this paper is aimed at analyzing the well interference of shale gas wells through production type curves. First, the complex fracture networks are described by using the embedded discrete fracture model (EDFM). Second, different cases are designed to characterize different types and degrees of well interference in shale gas reservoirs. Third, numerical modelling is conducted to simulate the well interference and its effect on gas production. Fourth, the type curves are obtained to quantitatively analyze and compare the impact of well interference on shale gas production. Results show that well interference caused by hydraulic fractures mainly reduce the gas production of the parent well while the gas production of child well can be increased owing to the larger equivalent stimulated area. The pressure depletion is obvious when the well communication degree becomes higher. Differences can be found from early to late periods by the combination of log-log and Blasingame type curves. This work provides a method for well interference evaluation, and it can be used to obtain well spacing and adjust fracturing parameter in shale gas reservoirs.

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22

Blick, E. F., P. N. Enga, and P. C. Lin. "Stability Analysis of Flowing Oil Wells and Gas Lift Wells." SPE Production Engineering 3, no. 04 (November 1, 1988): 508–14. http://dx.doi.org/10.2118/15022-pa.

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23

Panikarovskii, V. V., and E. V. Panikarovskii. "EXPLOITATION OF GAS WELLS IN LATE STAGE OF DEVELOPMENT OF GAS FIELDS." Oil and Gas Studies, no. 5 (November 1, 2017): 85–89. http://dx.doi.org/10.31660/0445-0108-2017-5-85-89.

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At late stage of development of gas fields they need to solve the specific issues of increasing the production rate of wells and decreasing water cut. The available experience of development of gas and gas condensate fields proves, that the most effective method of removing of water, accumulating in wells, is an injection into the bottom hole zone of foam-forming compositions, based on surfactants. The most technological in the application was the use of solid and liquid surfactants. Installation in wells of lift columns of smaller diameter ensured the removal of liquid from the bottom hole of wells, but after few month of exploitation the conditions of removal of liquid from the bottom hole of wells deteriorate. The technologies of concentric lift systems and plunger-lift systems are used in small number of wells. The basic technology for removal of liquid from bottom hole of gas wells at present time is the technology of treatment of bottom hole of wells with solid surfactants.

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24

Hashemi, Abdolnabi, Laurent Nicolas, and Alain C. Gringarten. "Well Test Analysis of Horizontal Wells in Gas-Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 9, no. 01 (February 1, 2006): 86–99. http://dx.doi.org/10.2118/89905-pa.

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25

Yang, Shuren, Di Xu, Lili Liu, Chao Duan, and Liqun Xiu. "Research of Drainage Gas Recovery Technology in Gas Wells." Open Journal of Fluid Dynamics 04, no. 02 (2014): 154–62. http://dx.doi.org/10.4236/ojfd.2014.42014.

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26

Montague, James A., George F. Pinder, and Theresa L. Watson. "Predicting gas migration through existing oil and gas wells." Environmental Geosciences 25, no. 4 (December 2018): 121–32. http://dx.doi.org/10.1306/eg.01241817008.

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27

Chen, Jianda, Dajiang Wang, Zhiquan Zhang, and Jie Liu. "Reasonable Pumping Depth for Drainage and Gas Recovery of Shale Gas Wells." International Journal of Heat and Technology 38, no. 3 (October 15, 2020): 701–7. http://dx.doi.org/10.18280/ijht.380314.

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For shale gas wells, in the initial production stage, the liquid production is large, and the lifting process is needed to assist the drainage. However, for gas wells, especially shale gas wells, the ultimate purpose is different from that of oil wells, and the current design method of pumping depth cannot meet the field requirements. Starting from the production characteristics of liquid-producing gas wells, this paper analyzed the gas well productivity, wellbore pressure distribution and critical liquid-carrying flow, and adopted the node analysis method to propose a design method for the pumping depth of shale gas wells during drainage and gas recovery. Then, the proposed method was applied to optimize the design of the jet pump of well A in Block JY, according to the design results, the pump was started for production; after the wellbore liquid level was raised to the designed depth, the gas well can conduct annulus space liquid-carrying production, and the production effect of well A showed that, the proposed method can be applied as a method for optimizing the technological parameters of shale gas wells.

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28

Fan, Zhiqiang, Guangjun Xu, Liying Xi, Dangni Zhao, Sihong Liu, Long Sun, and Runhua Zhu. "Optimization of management measures for water-producing gas wells in SM gas field." E3S Web of Conferences 352 (2022): 01006. http://dx.doi.org/10.1051/e3sconf/202235201006.

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SM gas field is a typical tight sandstone gas reservoir, which adopts the production mode of downhole throttling and inter-well series connection. Gas wells will have different production characteristics at different stages of production, which will cause the management measures implemented by gas wells in different stages to have different effects on efficiency[1-2]. Based on the complex production law of water-producing gas wells in SM Gas Field, this paper is based on the quantitative evaluation of the impact of water production on gas well development indicators for the latter. Clarify the reasons for the production of water and water from gas wells, understand the production rules of water-producing gas wells, optimize the management measures of water-producing gas wells in SM Gas Field, and clarify the rational production allocation methods and work under various complex water-producing conditions during the development of water-producing gas wells system[3]. It can also lay a foundation for the subsequent development of low-yield and low-efficiency wells to tap potential measures, to propose technical countermeasures to enhance oil recovery in the SM gas field, and to carry out gas field-related stable production potential evaluation.

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29

Matyakubov, M. Y., Sh Kh Umedov, Sh Kh Mirsaatova, B. P. Pazilov, and A. B. Matyakubov. "Annular Gas Manifestation Occurring in Wells." Oil and Gas Technologies 136, no. 5 (2021): 30–33. http://dx.doi.org/10.32935/1815-2600-2021-136-5-30-33.

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The article presents the results of annular manifestation of gas as well as the influence of the type and manufactures of cement on annular pressure, recommendations are for cementing. In order to identify the reasons for the appearance of gas in the annular space, data on the nature of gas manifestation, field materials and the presentation of specialists are also provided.

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30

Soliman, M. Y., J. L. Hunt, and Mehdi Azari. "Fracturing Horizontal Wells in Gas Reservoirs." SPE Production & Facilities 14, no. 04 (November 1, 1999): 277–83. http://dx.doi.org/10.2118/59096-pa.

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31

Bloemen, Hayco, Stefan Belfroid, Wilco Sturm, and Frederic Verhelst. "Soft Sensing for Gas-Lift Wells." SPE Journal 11, no. 04 (December 1, 2006): 454–63. http://dx.doi.org/10.2118/90370-pa.

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Summary This paper considers the use of extended Kalman filtering as a soft-sensing technique for gas lift wells. This technique is deployed for the estimation of dynamic variables that are not directly measured. Possible applications are the estimation of flow rates from surface and downhole pressure measurements or the estimation of parameters of a drift-flux model. By means of simulation examples, different configurations of sensor systems are analyzed. Finally, the estimation of drift-flux model parameters is demonstrated on real data from a laboratory setup. Introduction During the last 10 years, the industry has seen different downhole actuation technologies (commonly known as intelligent completions or under different trademarks) coming into existence. The goal of these technologies is ultimately to maximize the value of an asset by applying "right-time" optimization concepts borrowed from control engineering. Depending on the specific economics of the asset, this can be translated into more specific objectives such as speeding up of production, stabilization of unstable production, deferment of production of unwanted fluids, maximizing ultimate recovery, or a combination of some of the aforementioned short- and long-term objectives. Control theory concepts of optimization by means of a feedback loop require means for determining the deviation between the actual response and the desired response of the system. In wells, this often boils down to some sort of multiphase flow measurement. Different accurate multiphase-measurement technologies have been matured during the last decade, and the industry seems to be crossing the chasm between the early-adopter and the early-follower stages. Often for control purposes, direct measurements with high absolute accuracy are not required, as long as the measurements give a good indication of the relative change in the property that needs to be optimized. In different process industries, soft-sensing techniques were developed to determine variables where it is either impossible to directly measure the variables of interest or where it is economically not justifiable. In this paper, the concept of soft sensing is used; unmeasured dynamic variables (such as flow rates) are estimated from measured ones (i.e., pressures) by fitting a sufficiently accurate numerical model to the available measurements. We have looked at the gas lifted well application, where the lift gas rate may be controlled. Ideally this control would be based on directly measured multiphase flow rates, but in reality one often finds that this information is not available. Other measurements, such as surface and downhole pressure and temperature measurements, are more readily available and may be used for soft sensing. The paper is organized in the following manner: first, the model of the gas lifted well is described; then, the soft-sensing concepts are explained; and, finally, different examples and configurations are shown in which this technology is applied for estimating multiphase flows.

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32

Prakhova, M. Yu. "Method of Diagnosing Watering Gas Wells." SOCAR Proceedings, no. 3 (September 30, 2016): 19–26. http://dx.doi.org/10.5510/ogp20160300284.

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Stolyarov, V. E., N. A. Eremin, Al N. Eremin, and I. K. Basnieva. "Digital gas wells: state and prospects." Oilfield Engineering, no. 7 (2018): 48–55. http://dx.doi.org/10.30713/0207-2351-2018-7-48-55.

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34

Yang, Cheng, Li Zihan, Zhang Binghai, Huang Jing, and Liao Ruiquan. "Liquid Accumulation in Horizontal Gas Wells." Chemistry and Technology of Fuels and Oils 57, no. 6 (January 2022): 955–62. http://dx.doi.org/10.1007/s10553-022-01333-3.

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35

Fan, Yong, and F. M. Llave. "Tip Screenout Fracturing of Gas Wells." SPE Journal 1, no. 04 (December 1, 1996): 463–72. http://dx.doi.org/10.2118/35636-pa.

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36

Marlow, Roy S. "Cement Bonding Characteristics in Gas Wells." Journal of Petroleum Technology 41, no. 11 (November 1, 1989): 1146–53. http://dx.doi.org/10.2118/17121-pa.

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Myslyuk, M. A. "New Technologies in Gas Wells Construction." Nauka ta innovacii 1, no. 5 (September 30, 2005): 61–76. http://dx.doi.org/10.15407/scin1.05.061.

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Prundurel, Alina Petronela, Ioana Gabriela Stan, Ion Pană, Cristian Nicolae Eparu, Doru Bogdan Stoica, and Iuliana Veronica Ghețiu. "Production Forecasting at Natural Gas Wells." Processes 12, no. 5 (May 15, 2024): 1009. http://dx.doi.org/10.3390/pr12051009.

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In Romania, natural gas production is concentrated in two large producers, OMV Petrom and Romgaz. However, there are also smaller companies in the natural gas production area. In these companies, the deposits are mostly mature, or new deposits have low production capacity. Thus, the production forecast is very important for the continued existence of these companies. The model is based on the pressure variation in the gas reservoir, and the exponential model with production decline is currently used by gas and oil producers. Following the variation in the production of the gas wells, we found that in many cases, the Gaussian and Hubbert forecast models are more suitable for simulating the production pattern of gas wells. The models used to belong to the category of poorly conditioned models, with little data, usually called gray models. Papers published in this category are based on data collected over a period of time and provide a forecast of the model for the next period. The mathematical method can lead to a very good approximation of the known data, as well as short-term forecasting in the continuation of the time interval, for which we have these data. The neural network method requires more data for the network learning stage. Increasing the number of known variables is conducive to a successful model. Often, we do not have this data, or obtaining it is expensive and uneconomical for short periods of possible exploitation. The network model sometimes captures a fairly local pattern and changing conditions require the model to be remade. The model is not valid for a large category of gas wells. The Hubbert and Gauss models used in the article have a more comprehensive character, including a wide category of gas wells whose behavior as evolutionary stages is similar. The model is adapted according to practical observations by reducing the production growth period; the layout is asymmetric around the production peak; and the production range is reduced. Thus, an attempt is made to replace the exponential model with the Hubbert and Gauss models, which were found to be in good agreement with the production values. These models were completed using the Monte Carlo method and matrix of risk evaluation. A better appreciation of monthly production, which is an important aspect of supply contracts, and cumulative production, which is important for evaluating the utility of the investment, is ensured. In addition, we can determine the risk associated with the realization of production at a certain moment of exploitation, generating a complete picture of the forecast over the entire operating interval. A comparison with production results on a case study confirms the benefits of the forecasting procedure used.

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Sadiq Gadirov, Zahid, and Anar Yahya Jomardov. "Characteristics of research in gas wells." Seismoprognosis Observations in the Territory of Azerbaijan, no. 01 (2024): 44. http://dx.doi.org/10.59849/2219-6641.2024.1.44.

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40

Hansen, Christine. "Preliminary study indicates large environmental costs for stripper wells." Natural Gas 16, no. 4 (January 9, 2007): 13–18. http://dx.doi.org/10.1002/gas.3410160404.

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41

Shchekin, Alexander I., Vyacheslav V. Verzhbitsky, Tatiana A. Gunkina, and Alexander V. Handzel. "Factor analysis of gas wells’ operating parameters." Georesursy 24, no. 2 (September 30, 2022): 139–48. http://dx.doi.org/10.18599/grs.2022.3.12.

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The paper discusses methodological approaches to the use of deterministic factor analysis for identifying the sources of changes in gas wells’ parameters under steady-state gas inflow obeying linear and non-linear filtration laws. Factor analysis methods make it possible to quantify the degree of influence of individual factors on the deviation of the indicator under study. In accordance with the methodology of factor analysis, mathematical models of the factor system were substantiated for linear and non-linear gas filtration, a set of factors of influence was determined, and ready-made solutions for factor analysis of gas wells’ operating parameters were obtained. In the paper, the method of weighted finite differences was substantiated and investigated with the aim of factor analyzing gas wells’ mode of operation and obtaining formulas to calculate the increment in gas production caused by changes in factors. Approbation of working formulas for assessing the degree of influence of factors on either positive or negative deviations in the gas flow rate was carried out with respect to the parameters of the wells of underground gas storages in the cycles of withdrawal and injection. The obtained formulas for factor analysis of gas wells make it possible to quantify the influence of such factors as reservoir and bottomhole pressures, filtration resistance coefficients, on the deviation of gas flow rate. Further ranking of wells by factors constitutes the basis for managing gas withdrawal (injection) processes and for well interventions planning.

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Dvoynikov, Mikhail V., Yakov D. Minaev, Vildan V. Minibaev, Evgenii Yu Kambulov, and Mikhail E. Lamosov. "Technology for killing gas wells at managed pressure." Bulletin of the Tomsk Polytechnic University Geo Assets Engineering 335, no. 1 (January 31, 2024): 7–18. http://dx.doi.org/10.18799/24131830/2024/1/4315.

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Relevance. The need to solve the problem of developing gas wells after multistage hydraulic fracturing. This problem consists in losses of process fluids during killing gas wells with high permeability by traditional methods, and reducing the achieved productivity of gas deposits. Aim. To develop and justify a method for gentle killing of gas and gas condensate wells after working out in operation mode. Objects. Gas and gas condensate wells after multistage hydraulic fracturing. Methods. Filtration experiment to determine the effect of killing fluid on reservoir permeability; mathematical modeling of gentle killing of a gas well using flexible tubing and equipment for work at controlled pressure; laboratory studies of the mechanical properties of the blocking pack – liquid packer. Results. According to the results of the filtration experiment, the negative effect of the silencing fluid on low-permeable gas layers is justified. The authors developed the technology of gentle killing of gas and gas condensate wells using flexible tubing and equipment for operations at controlled pressure. Laboratory studies were carried out and technological parameters were selected for the second blocking pack – a liquid packer for additional isolation of a gas reservoir. The authors constructed a mathematical model of killing gas wells using the presented technology; a calculation was carried out for the conditions of a gas condensate field in Eastern Siberia. The paper introduces the results of modeling technological operations reflecting the change in the main technological parameters during well killing.

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B, Takyi. "Gas Profiles Unravel Fractured and Compartmentalized Reservoirs." Petroleum & Petrochemical Engineering Journal 6, no. 4 (October 20, 2022): 1–9. http://dx.doi.org/10.23880/ppej-16000311.

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The profiles of gas in reservoirs of the Nene Oil Field in the Lower Congo Basin was modelled and evaluated for the objective of delineating the reservoir structure. The wells are NNM Well 6, NNM Well 301 and NNM Well 302. The C1 profiles show significant difference between wells 6 and 301 relative to well 302. The C1 profile for Well 302 unravels gas migrations from different compartments at the reservoir depth and mixes at a depth of 1.5KM. The observation also indicates the presence of a fracture that allow homogenization of the gases at that depth. The iC4/nC4 ratio for NNM Well 302 showed a profile for which the ratio is greater than 1.0 throughout the well section downdip. The observation portrays biodegradation throughout the well section generation from an immature source. The study shows that the NNM Well 6 reservoir is laterally compartmentalized from others, while all the well shoe some potential for vertical continuity of the wells

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Zhang, Ding Yong, Xiao Jie Liu, Tao Ma, Guo Shun Qin, and Wei Li. "Experiment Study on the Scaling of Gas Wells in Songnan Gas Field." Advanced Materials Research 781-784 (September 2013): 2881–85. http://dx.doi.org/10.4028/www.scientific.net/amr.781-784.2881.

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Gas field scaling is an important factor affecting the normal production of the gas wells. Scaling problems have been come into being in many production wells of Songnan gas field. The paper carried on experimental study and reason analysis on the scaling problem of Songnan gas field. The result shows that the fouling is mainly composed of calcium carbonate. The mainly reasons for the scaling are the incompatibility between Cacl2 killing fluid and formation water as well as the pressure reduction around the wells.

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Bei, Yu Bei, Li Hui, and Li Dong Lin. "The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs." E3S Web of Conferences 38 (2018): 01038. http://dx.doi.org/10.1051/e3sconf/20183801038.

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This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.

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46

Vaganov, Yu V. "NECESSITY OF IMPROVEMENT OF COMPLEX GAS WELL REPAIR WORKS CLASSIFICATION IN CURRENT CONDITIONS OF WELLS OPERATION." Oil and Gas Studies, no. 2 (May 1, 2016): 40–44. http://dx.doi.org/10.31660/0445-0108-2016-2-40-44.

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It is shown that the changed conditions of gas and gas-condensate fields operation entailed an increase in complexity of well repairs using coiltubing technologies. However, the methods developed for wells recovery in terms of emergency-refurbishment and water-influx restriction works are not provided for by the existing classification of complex well repairs which makes difficult to justify the length of repair works and, accordingly, their cost. The suggested amendments to the current structure of wells repair types promote further development of technologies of well workover in the conditions of oil and gas production decline .

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Danilović, Dušan, Marija Ilić, Miroslav Crnogorac, and Lola Tomić. "Gas-lift wells optimization at the oil field "K"." Podzemni radovi, no. 41 (2022): 31–42. http://dx.doi.org/10.5937/podrad2241031d.

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Optimization the operating parameters of a group of gas-lift wells in an oil field is a complex procedure. It is important to match parameters such as gas compression pressure, gas injection pressure, separation pressure at the gathering station, diameters of distribution pipelines, injection gas quantities as well as all individual operating parameters of the gas-lift wells. In this paper, a model for determining the optimum gas injection rate was created. Also, it is described the procedure for gas-lift well optimization at the oil filed "K" and its results. For all five wells, the optimum amount of injected gas and required number of gas-lift valves were determined.

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Liangbin, D., G. Li, S. Tiantai, M. Zhang, and H. Shi. "Study on hydraulic pulse cavitating jet drilling in unconventional natural gas wells." "Proceedings" of "OilGasScientificResearchProjects" Institute, SOCAR, no. 4 (December 30, 2014): 19–26. http://dx.doi.org/10.5510/ogp20140400217.

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Bybee, Karen. "Evaluating Well Performance and Completion Effectiveness in Low-Permeability Gas Wells." Journal of Petroleum Technology 56, no. 03 (March 1, 2004): 39–40. http://dx.doi.org/10.2118/0304-0039-jpt.

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JPT staff, _. "Techbits: Well Performance in Hydraulically Fractured Gas Wells Subject of Lecture." Journal of Petroleum Technology 55, no. 12 (December 1, 2003): 22. http://dx.doi.org/10.2118/1203-0022-jpt.

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