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Journal articles on the topic 'Oil wells'

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Author: Grafiati

Published: 4 June 2021

Last updated: 1 August 2024

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1

ON, Shemelina. "Constructing a Heavy Oil Well." Petroleum & Petrochemical Engineering Journal 6, no. 1 (2022): 1–6. http://dx.doi.org/10.23880/ppej-16000300.

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The article presents a description of the designs of wells intended for the production of high-viscosity oil. The main problems associated with the planning and deployments of architecture, construction of high-viscosity oil wells are described. World experience in well construction is presented. Vertical wells are usually used for primary cold production and cyclic steam or steam flooding processes. On the other hand, increased reservoir contact may require deviated, horizontal, or multilateral wells. In the case of steam-assisted gravity drainage (SAGD) and some solvent injection processes, the recovery process may require a well-placed pair of horizontal wells. Advanced drilling and real-time measurement technologies reviewed. Geo mechanical factors are studied when considering the implementation of any steam or thermal processes in the field. Examples of construction of multilateral wells in various combinations are shown depending on the field development strategy and for maximum reservoir drainage. The main recommendations for the placement of wells are proposed.

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2

S, Gomaa. "Electrical Submersible Pump Design in Vertical Oil Wells." Petroleum & Petrochemical Engineering Journal 4, no. 4 (2020): 1–7. http://dx.doi.org/10.23880/ppej-16000237.

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Artificial Lift is a very essential tool to increase the oil production rate or lift the oil column in the wellbore up to the surface. Artificial lift is the key in case of bottom hole pressure is not sufficient to produce oil from the reservoir to the surface. So, a complete study is carried to select the suitable type of artificial lift according to the reservoir and wellbore conditions like water production, sand production, solution gas-oil ratio, and surface area available at the surface. Besides, the maintenance cost and volume of produced oil have an essential part in the selection of the type of artificial lift tool. Artificial lift tools have several types such as Sucker Rod Pump, Gas Lift, Hydraulic Pump, Progressive Cavity Pump, Jet Pump, and Electrical Submersible Pump. All these types require specific conditions for subsurface and surface parameters to apply in oil wells. This paper will study the Electrical Submersible Pump “ESP” which is considered one of the most familiar types of artificial lifts in the whole world. Electrical Submersible Pump “ESP” is the most widely used for huge oil volumes. In contrast, ESP has high maintenance and workover cost. Finally, this paper will discuss a case study for the Electrical Submersible pump “ESP” design in an oil well. This case study includes the entire well and reservoir properties involving fluid properties to be applied using Prosper software. The results of the design model will impact oil productivity and future performance of oil well.

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3

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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4

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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5

Liashenko, Anna, Valeriy Makarenko, Yuriy Vynnykov, and Oleksandr Petrash. "Oil wells hydrate formation regularities." Eastern-European Journal of Enterprise Technologies 3, no. 6 (111) (June 18, 2021): 19–24. http://dx.doi.org/10.15587/1729-4061.2021.233511.

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The paper considers the process of hydrate-paraffin deposits formation in oil wells. Due to the research with the author's specially designed laboratory equipment – an experimental installation containing a technological unit and an information-measuring system, the most favorable pressure-temperature conditions of hydrate formation in a wide range of pressure (0.1–120 MPa) and temperature (from –20 to +80 °C) were determined. The experimental results made it possible to determine the conditions required for hydrate deposits and iron (Fe) oxides in the range of temperature from –15 to +60 °C and pressure from 0 to 60 MPa. These results are confirmed by thermodynamic calculations of the oil-gas-hydrate phase equilibria in the annulus of the well. Data processing was performed using the methods of correlation, dispersion and regression analysis, which allowed comparing the processes of hydrates and iron (Fe) oxides formation in the annulus of oil wells. The results of the study can be used to prevent and eliminate hydrate-paraffin plugs in the downhole equipment of oil wells, and also to determine the operation mode of the well for long-term operation of the downhole equipment without complications, accidents and stops for repair works, which reduces downtime.

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6

Rassoul, G. A. R., and Omar M. Waheeb. "Producing Oil from Dead Oil Wells Using injected LPG." Iraqi Journal of Chemical and Petroleum Engineering 11, no. 2 (June 30, 2010): 29–33. http://dx.doi.org/10.31699/ijcpe.2010.2.3.

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In order to reduce hydrostatic pressure in oil wells and produce oil from dead oil wells, laboratory rig was constructed, by injecting LPG through pipe containing mixture of two to one part of East Baghdad crude oil and water. The used pressure of injection was 2.0 bar, which results the hydrostatic pressure reduction around 246 to 222 mbar and flow rate of 34.5 liter/hr fluid (oil-water), at 220 cm injection depth. Effects of other operating parameters were also studied on the behavior of two phase flow and on the production of oil from dead oil wells.

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7

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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8

Li, Guang Fu. "Low-Yielding Wells Automatic Metering System." Advanced Materials Research 953-954 (June 2014): 1467–70. http://dx.doi.org/10.4028/www.scientific.net/amr.953-954.1467.

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When oil field entered into the high water content period, liquid production capacity of oil wells had large fluctuation and poor regularity, which leaded to the error of human reading and bottom water density in the measurement process, the difficulty of measuring oil wells is gradually increasing. Therefore, the measurement of low producing well has aroused extensive attention. How to research and establish a suitable measuring device for low producing well, improve measurement accuracy and management level of intermittent oil wells has become a serious problem in oil production. Using automatic oil measuring system can improve the accuracy of measurement, which achieved the automatic measurement for the fluid and gas production and moisture content of oil wells.

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9

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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10

Shtoff, A. V. "Prediction of Oil Production Rate of Jet Pumping Oil Wells From Sample Well Data." SPE Production & Facilities 14, no. 01 (February 1, 1999): 77–80. http://dx.doi.org/10.2118/54537-pa.

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11

Bybee, Karen. "Orinoco Oil Belt Well Construction Using Wells-in-Series Technology." Journal of Petroleum Technology 53, no. 09 (September 1, 2001): 69. http://dx.doi.org/10.2118/0901-0069-jpt.

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12

Adzhar, Anis Zuriati, and Sulaimon Aliyu Adebayor. "EVALUATING THE EFFECT WELL INCLINATION AND FORMATION ANISOTROPY ON CONING RATE IN DEVIATED WELLS." Platform : A Journal of Engineering 3, no. 1 (May 6, 2019): 43. http://dx.doi.org/10.61762/pajevol3iss1art4985.

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In oil reservoirs with bottom water drive, coning is a fundamental problem during oil production. Horizontal and deviated wells are often used to reduce the effect of water coning on total oil production. To avoid the premature breakthrough of water, the production of oil should be maximised through effective monitoring of the critical coning rate, and many researchers have developed models to determine the critical coning rate. However, very few studies have been conducted to evaluate the effect of good inclination and formation anisotropy on the critical coning rate. Therefore, we have incorporated well deviation and formation anisotropy into a water coning model to investigate their effects on the critical coning rate. Previous researches have been limited mainly to the calculation of water critical coning rate in the vertical well. In this study, a combination of radial and spherical flows in deviated wells has been adopted to develop a new model for analysing coning in non-vertical wells. The well inclination considered ranged from 20o to 80o, horizontal permeability (kh ) from 100 mD to 200 mD and the vertical permeability (kv ) was varied from 2 mD to 10 mD. Results showed that highly-deviated wells and formations with a high degree of reservoir heterogeneity (kv/kh) result in high critical coning rate and therefore less susceptible to early water breakthrough. This shows that more allowance to increase the production rate is possible for horizontal wells and anisotropic formations than in vertical and homogeneous reservoirs. Keywords: Water coning, deviated wells, reservoir heterogeneity, anisotropy permeability, critical coning rate, critical parameters.

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13

Zhang, Hai Yong, Shun Li He, Dai Hong Gu, Guo Hua Luan, Shao Yuan Mo, and Guang Ming Li. "Investigation of Well Patterns of Horizontal-Vertical Wells for the Exploitation of Tight Reservoir." Advanced Materials Research 848 (November 2013): 88–91. http://dx.doi.org/10.4028/www.scientific.net/amr.848.88.

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In general, the scale of production, exploitation period and the economic benefits of oil and gas field are, to a large extent, depended on the selection, deployment and adjustment of well patterns, especially for tight reservoir. So far, some problems exist in Changqing low permeability oil field, such as the effective displacement system is not easy to be established, a low utilization efficiency of injection water, low oil production and so on. Therefore, five kinds of different well pattern schemes are designed. Then, the well pattern schemes are optimized through numerical simulation method based on the exploitation index including the daily oil output per well, moisture content and oil recovery. Results show that the well patterns of horizontal-vertical wells have better development efficiency than the well patterns of vertical wells. For the optimized well pattern, when the horizontal segment length of horizontal well is 300m, the optimalizing well spacing is 400m and the optimalizing row spacing is 100~150m.

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14

Kozhageldin, H. K., P. A. Tanzharikov, and A. T. Erzhanova. "Improving the rod well pumpfor production of watered oil from deep wells." Neft i Gaz 140, no. 2 (February 15, 2024): 107–19. http://dx.doi.org/10.37878/2708-0080/2024-2.10.

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At the moment, the bulk of the total reserves of well oil fields in Kazakhstan are developed using sucker rod pumping units at a late stage of development. Experience in operating sucker rod pumping units has shown that the problem of rod chain failure in the form of breakage and rupture is still relevant today, given that the production of medium-high water oil during well operation significantly increases corrosion processes and applied loads. This article discusses methods for analyzing and optimizing the method of oil production using sucker rod pumping units. Methods used to prevent corrosion of metal structures under the influence of mineralized water are shown.

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15

Sadikov, I. F., and D. V. Schelokov. "Hydrate blockage elimination in oil wells." Neftyanoe khozyaystvo - Oil Industry, no. 9 (2020): 124–26. http://dx.doi.org/10.24887/0028-2448-2020-9-124-126.

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16

Pavlova, P. L., and D. V. Guzei. "Thermal Control Devices for Oil Wells." Russian Engineering Research 42, no. 7 (July 2022): 650–55. http://dx.doi.org/10.3103/s1068798x22070231.

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17

Thomas, D. C., H. L. Becker, and R. A. Del Real Soria. "Controlling Asphaltene Deposition in Oil Wells." SPE Production & Facilities 10, no. 02 (May 1, 1995): 119–23. http://dx.doi.org/10.2118/25483-pa.

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18

Raloff, J. "Prospecting for Seeping, Buried Oil Wells." Science News 143, no. 15 (April 10, 1993): 230. http://dx.doi.org/10.2307/3976945.

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19

Dhia, Hamed Ben. "Tunisian geothermal data from oil wells." GEOPHYSICS 53, no. 11 (November 1988): 1479–87. http://dx.doi.org/10.1190/1.1442428.

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Since direct measurements of steady‐state temperatures are not readily available in Tunisia, a geothermal investigation has been made using 1319 values of bottom‐hole temperatures (BHTs) obtained from 217 petroleum exploration wells. An empirical relation based on the differences between BHT and DST (drill stem tests) was used to correct BHTs and estimate geothermal gradients. The estimated geothermal gradient of the country varies between 21 and 52 °C/km. A few regions with similar gradients have been identified, and similarities between gradient contours and the main structural directions are noted. Furthermore, for 25 points from 12 wells, it was possible to apply the Horner‐plot method to determine the equilibrium formation temperature (Tf). Comparison of Tf values with those calculated by the estimated gradients reveals a good correlation (r = 97 percent) between the two estimates. This agreement permits greater confidence in the statistical method used and consequently in the estimated gradients for the whole country.

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20

Badertdinova, E. R., M. Kh Khairullin, and M. N. Shamsiev. "Thermohydrodynamic investigations of vertical oil wells." High Temperature 49, no. 5 (October 2011): 769–72. http://dx.doi.org/10.1134/s0018151x11050014.

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21

Khairullin, M. Kh, M. N. Shamsiev, E. R. Badretdinova, and A. I. Abdullin. "Thermohydrodynamic investigations of horizontal oil wells." High Temperature 50, no. 6 (November 2012): 774–78. http://dx.doi.org/10.1134/s0018151x12050070.

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22

Mullakaev, M. S., V. O. Abramov, and A. A. Pechkov. "Ultrasonic unit for restoring oil wells." Chemical and Petroleum Engineering 45, no. 3-4 (March 2009): 133–37. http://dx.doi.org/10.1007/s10556-009-9160-9.

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23

Torre, A. J., Z. Schmidt, R. N. Blais, D. R. Doty, and J. P. Brill. "Casing Heading in Flowing Oil Wells." SPE Production Engineering 2, no. 04 (November 1, 1987): 297–304. http://dx.doi.org/10.2118/13801-pa.

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24

Abd Alhaleem, Ayad, Safaa Husain Sahi, and Amel Habeeb Assi. "Bit Performance in Directional Oil Wells." Journal of Engineering 21, no. 11 (November 1, 2015): 80–93. http://dx.doi.org/10.31026/j.eng.2015.11.05.

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This work aims to analyze and study the bit performance in directional oil wells which leads to get experience about the drilled area by monitoring bit performance and analyzing its work. This study is concerned with Rumaila Oil Field by studying directional hole of one oil well with different angles of inclination. Drilling program was used in order to compare with used parameters (WOB, RPM and FR).in those holes. The effect of the drilling hydraulic system on the bit performance was studied as well as the hydraulic calculation can be done by using Excel program. This study suggests method which is used to predict the value of penetration rate by studying different formation type to choose the best drilling parameters to drill each formation. Finally, the main aim of this research is to have the benefit from the past well drilling data to drill new wells without needing new drilling program for each well, also knowing the problems of each formation to avoid them as soon as possible through drilling the new wells, which will improve the bit performance.

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25

McQueen, Greg, David Parman, and Heath Williams. "Electrothermal Heating of California Oil Wells: A Case Study of Enhanced Oil Recovery of Shallow Wells." IEEE Industry Applications Magazine 18, no. 5 (September 2012): 18–25. http://dx.doi.org/10.1109/mias.2012.2202197.

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26

Parfiryev, V. A., S. A. Paleyev, and Yu V. Vaganov. "THE ANALYSIS OF OIL WELLS CONSTRUCTION IN ABNORMAL CONDITIONS IN EASTERN SIBERIA OIL-FIELDS." Oil and Gas Studies, no. 6 (December 1, 2016): 97–100. http://dx.doi.org/10.31660/0445-0108-2016-6-97-100.

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The paper presents an analysis of oil wells construction at oil fields of Eastern Siberia. The petrophysical formation cross-section affecting the quality of oil wells construction is characterized. In addition, drilling and casing experience under those mining and geological conditions demonstrates that, as of today, there are no readily available technologies that would afford safe and efficient construction of oil wells in that region. The analysis of the oil wells construction gives grounds to demonstrate indispensability of a comprehensive approach to solving the problems of construction and operation of oil wells at oil fields of the Talakangroup of deposits.

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27

Ma, Yingying, Hongwei Song, Changqi Zhao, Ran Wei, and Lihuizi Sun. "Numerical Simulation of Oil-Water Flow Velocity Field and Flow Pattern in Horizontal Wells and Near Horizontal Wells." Journal of Physics: Conference Series 2068, no. 1 (October 1, 2021): 012008. http://dx.doi.org/10.1088/1742-6596/2068/1/012008.

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Abstract Oil-water flow widely exists in oilfield development. Due to the gravity differentiation, the oil-water flow in low-flow horizontal wells has a clear characteristics of stratified flow. With the increase of flow rate, the stratified characteristics are not obvious, which leads to the difficulty of multiphase flow phase separation flow interpretation in oilfield. In this paper, the oil-water flow in horizontal wells is taken as the research object. The VOF model of Fluent software is used to study the relationship between velocity field and flow pattern distribution characteristics with water cut, well deviation angle and total flow. The results show that with the increase of water cut, the oil-water separation level gradually moves up, and the velocity of water phase is greater than that of oil phase. When the well deviation angle changes slightly, the flow stratification of oil-water changes sharply, and the flow velocity in the pipeline also changes. When the total flow rate is lower than 200 m3/d, the oil-water phases have obvious stratified flow characteristics. With the increase of flow rate, the oil-water interface fluctuates. The average velocity of oil and water is not much different.

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28

Kharisov, Mansur N., Eleonora A. Yunusova, Elvira A. Kharisova, and Ravil A. Maiski. "ANALYSIS OF DISPLACEMENT CHARACTERISTICS OF OIL WELLS AND OIL FIELDS." Problems of Gathering, Treatment and Transportation of Oil and Oil Products, no. 4 (December 2017): 73. http://dx.doi.org/10.17122/ntj-oil-2017-4-73-83.

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29

Dantas de Araujo Junior, Aldayr, Marcos Allyson Felipe Rodrigues, Antonio Robson Gurgel, Anthony Andrey Ramalho Diniz, and Wilson da Mata. "Oil Recovery By Electromagnetic Heating Method In Fractured Oil Wells." IEEE Latin America Transactions 13, no. 4 (April 2015): 1016–21. http://dx.doi.org/10.1109/tla.2015.7106351.

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30

M Elfaghi, Abdulhafid, Wisam B. Ajaj, and Lukmon Owolabi Afolabi. "Effect of Oil Mass Flow Rate on Temperature Profile in Oil Wells." Journal of Advanced Research in Fluid Mechanics and Thermal Sciences 77, no. 2 (November 14, 2020): 23–32. http://dx.doi.org/10.37934/arfmts.77.2.2332.

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In several design calculations including the development of programs to optimize production, engineers and scientists require accurate prediction of temperature drop due to flow in oil wells. The purpose of this research is to create mathematical models to predict the effect of oil mass flow rate on temperature distribution in oil wells. A numerical mathematical model is developed to study the parameters affecting the dynamic and static temperature profiles in oil wells in production and shutting operation. The temperature distribution of the oil from the reservoir to the surface and the temperature distribution in the wall tubing of the oil well and casing, cement sheaths, and surrounding formation is studied. The natural flow of oil wells in Alwahat area located 70 Kilometres south of Marada area east of Libya in the Zaggut field called (6Q1-59) is taken as a study case. In production case, different mass flow rates in winter and summer seasons are studied. The temperature profile in the horizontal direction is estimated at different depths. The Results show that the surface temperature of crude oil increases with the rise in mass flow rate.

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31

Yuan, Zhang, Hong Fu Fan, Hong Xia Liu, and Shuo Liang Wang. "Study of the Initial Well Production Line of Adjusted Wells in X Oilfield." Applied Mechanics and Materials 268-270 (December 2012): 2071–74. http://dx.doi.org/10.4028/www.scientific.net/amm.268-270.2071.

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Different overseas oil field development and production projects, have different tax provisions. The contract requires different models for different development strategies. In this paper, the X oilfield abroad, for example, studied the oilfield development to adjust the initial well production line, and the adjustment of the oil field development well later provided the basis for the deployment.

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32

Guoynes, John, Mehdi Azari, Robert Gillstrom, Bret Friend, and Mike Fairbanks. "New Well-Testing Methods for Rod-Pumping Oil Wells - Case Studies." SPE Production & Facilities 17, no. 04 (November 1, 2002): 204–11. http://dx.doi.org/10.2118/80291-pa.

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33

Mahidov, A. G., R. S. Safarov, N. S. Seidahmadov, and R. G. Ragimov. "Issues of abandonment of oil wells and soil recultivation." Azerbaijan Oil Industry, no. 4 (April 15, 2020): 55–60. http://dx.doi.org/10.37474/0365-8554/2020-4-55-60.

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Eventually, the wells are abandoned as depleted their resources, in some cases during construction process due to the technical and geological factors as well. The abandonment itself was carried out according to the existing safety rules in the oil-gas producing industry, obliged for the further control on the abandoned wells and did not assume further civil accommodation construction on this territory. The areas with abandoned oil wells were not used for economic needs and building construction and were under the control of oil-gas producing enterprises managing these wells. It emerged that existing methods of oil and gas wells abandonment do not guarantee their safety and may lead to the emergencies in the future. The transfer of such territories to the citywide balance leads to the loss of control on the abandoned wells. It is necessary to keep record of such wells and set up their register as well.

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34

Al-Mudhafar, Watheq J., David A. Wood, Dahlia A. Al-Obaidi, and Andrew K. Wojtanowicz. "Well Placement Optimization through the Triple-Completion Gas and Downhole Water Sink-Assisted Gravity Drainage (TC-GDWS-AGD) EOR Process." Energies 16, no. 4 (February 10, 2023): 1790. http://dx.doi.org/10.3390/en16041790.

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Gas and downhole water sink-assisted gravity drainage (GDWS-AGD) is a new process of enhanced oil recovery (EOR) in oil reservoirs underlain by large bottom aquifers. The process is capital intensive as it requires the construction of dual-completed wells for oil production and water drainage and additional multiple vertical gas-injection wells. The costs could be substantially reduced by eliminating the gas-injection wells and using triple-completed multi-functional wells. These wells are dubbed triple-completion-GDWS-AGD (TC-GDWS-AGD). In this work, we design and optimize the TC-GDWS-AGD oil recovery process in a fictitious oil reservoir (Punq-S3) that emulates a real North Sea oil field. The design aims at maximum oil recovery using a minimum number of triple-completed wells with a gas-injection completion in the vertical section of the well, and two horizontal well sections—the upper section for producing oil (from above the oil/water contact) and the lower section for draining water below the oil/water contact. The three well completions are isolated with hydraulic packers and water is drained from below the oil–water contact using the electric submersible pump. Well placement is optimized using the particle swarm optimization (PSO) technique by considering only 1 or 2 TC-GDWS-AGD wells to maximize a 12-year oil recovery with a minimum volume of produced water. The best well placement was found by considering hundreds of possible well locations throughout the reservoir for the single-well and two-well scenarios. The results show 58% oil recovery and 0.28 water cut for the single-well scenario and 63.5% oil recovery and 0.45 water cut for the two-well scenario. Interestingly, the base-case scenario using two wells without the TC-GDWS-AGD process would give the smallest oil recovery of 55.5% and the largest 70% water cut. The study indicates that the TC-GDWS-AGD process could be more productive by reducing the number of wells and increasing recovery with less water production.

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35

Maratovna, Sadikova Adalat, and Artikova Gulnoza Arislan Qizi. "EXPANSION OIL WELL CEMENT BASED ON SUBSTANDARD RAW MATERIALS." American Journal of Applied Science and Technology 03, no. 06 (June 1, 2023): 26–29. http://dx.doi.org/10.37547/ajast/volume03issue06-06.

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Grouting cement is a type of Portland cement designed to insulate pipes of oil and gas wells and protect them from groundwater pressure, shifts of ground layers, and the negative effects of aggressive media. When solidified, the cement mortar forms a monolithic jacket, impermeable to liquids and gases. The material adheres firmly to the metal pipe and to the walls of the trunk drilled in the rock. The use of grouting cement creates conditions for safe operation of wells and prolongs their working period. In traditional construction, this type of Portland cement is not used. The exception is the foundation of drilling piles in difficult geological conditions. That's whay, the article presents the investigation of grouting cement with the basis of substandard raw materials.

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Karanikas, John, Guillermo Pastor, and Scott Penny. "Downhole electric heating of heavy-oil wells." CT&F - Ciencia, Tecnología y Futuro 10, no. 2 (December 17, 2020): 61–72. http://dx.doi.org/10.29047/01225383.273.

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Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data. The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.

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Wu, Zhiqiang, Guangai Wu, Xuesong Xing, Jin Yang, Shujie Liu, Hao Xu, and Xiaowei Cheng. "Effect of Hole on Oil Well Cement and Failure Mechanism: Application for Oil and Gas Wells." ACS Omega 7, no. 7 (February 7, 2022): 5972–81. http://dx.doi.org/10.1021/acsomega.1c06275.

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38

Alemi, Dr Mehrdad, and Hossein Jalalifar. "Optimal Horizontal Well Placement Technology to Improve Heavy Oil Production." Indian Journal of Petroleum Engineering 2, no. 1 (May 30, 2022): 6–9. http://dx.doi.org/10.54105/ijpe.b1913.052122.

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Optimal horizontal well placement and production optimization have been highly scrutinized. Development adjustments, such as drilling new infill wells and changing the injection/production rates of wells, can improve the performance of mature fields and leading to incremental oil recovery. Infill wells are new wells added to an existing field within original well patterns. Infill drilling can hasten oil production in heterogeneous reservoirs. If well patterns alter, fluid flow paths and sweep to areas with high oil saturations would be increased. Of course, this plan is difficult to be examined because reservoir performance is affected by many different parameters. Compared to vertical or low inclination wells, horizontal wells can deliver higher production rates, higher recovery factors and more efficient use of steam in thermally enhanced recovery projects for heavy oil. Maximum oil production is achieved when horizontal wells are placed near the bottom of the reservoir. In addition, cumulative steam to oil ratio is lowest when wells are near the bottom of the reservoir, meaning that the least volume of steam will need to be generated to produce a particular volume of oil. In this paper, the optimal horizontal well placement technology to improve heavy oil production has been studied.

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39

Uteev, R. N., A. S. Mardanov, R. A. Yussubaliev, Assylkhan A. Yergaliyev, K. B. Ashimov, and B. K. Zhienbayev. "The evaluation of the efficiency of horizontal wells." Kazakhstan journal for oil & gas industry 4, no. 1 (May 16, 2022): 28–38. http://dx.doi.org/10.54859/kjogi105526.

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The number of fields that have reached stage IV of development is increasing every year. Due to the high level of water cut, it becomes difficult to develop residual recoverable reserves. Also, due to the increase in the share of high-viscosity oils in Kazakhstan, the task of their effective development becomes more complicated. The development of terrigenous reservoirs, which have a complex structure and contain high-viscosity oil, is usually characterized by low production rates and oil recovery factors. Currently, technologies that ensure high efficiency in the development of such deposits are very expensive. In this regard, the development of oil fields through the commissioning of horizontal wells is becoming more in demand, capable of increasing the efficiency of developing oil reserves. Drilling of horizontal wells is considered for: floating reservoirs with low reservoir production coverage due to high water cut. High levels of water cut are due to breakthroughs of bottom water and degraded technical condition of wells (annular flows, wear and leakage of the string, depressurization of previously isolated intervals and poor quality of cement adhesion); thin layers, not involved in the production. Basically, thin layers are not involved in the production due to the low performance of vertical wells; on horizons with high-viscosity oil. In highly viscous horizons, the injected water breaks through to the bottom of production wells along the base of the reservoir when the horizon is not developed. Also in the Atyrau region, fields with hard-to-recover reserves (fields with high oil viscosity and low permeability of the productive horizon) are being developed. It is in such fields that horizontal wells have already been drilled and will be drilled in the future. The presented article discusses the results of the analysis of the drilled horizontal wells in the North Volga and Aknur oil fields.

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Villa, Marco, Giambattista De Ghetto, Francesco Paone, Giancarlo Giacchetta, and Maurizio Bevilacqua. "Ejectors for Boosting Low-Pressure Oil Wells." SPE Production & Facilities 14, no. 04 (November 1, 1999): 229–34. http://dx.doi.org/10.2118/59091-pa.

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Jacobs, Trent. "Changing the Equation: Refracturing Shale Oil Wells." Journal of Petroleum Technology 67, no. 04 (April 1, 2015): 44–49. http://dx.doi.org/10.2118/0415-0044-jpt.

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42

Janakiraman, S. "DIGITAL OIL FIELDS - INTELLIGENT WELLS AND PLATFORMS." Petroleum Engineering 16, no. 5 (December 2018): 24. http://dx.doi.org/10.17122/ngdelo-2018-5-24-29.

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43

Soares, Lennedy C., André L. Maitelli, and Adelardo A. D. Medeiros. "Sisal: a supervisory system for oil wells." Sba: Controle & Automação Sociedade Brasileira de Automatica 22, no. 6 (December 2011): 631–37. http://dx.doi.org/10.1590/s0103-17592011000600008.

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Artificial lifting in oil industry uses a variety of methods and specific automation equipments for each method. Supervisory systems to these processes are usually specific for a unique method and/or for a unique manufacturer. To avoid this problem, it has been developed a supervisory system named SISAL, conceived for supervising wells with different lift methods and different automation equipments. SISAL is now in operation in several Brazilian states. This work shows how this system has been developed and presents some details of the SISAL's modules dealing with the artificial lift method called Plunger Lift.

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Behie, A., D. Collins, P. A. Forsyth, and P. H. Sammon. "Fully Coupled Multiblock Wells in Oil Simulation." Society of Petroleum Engineers Journal 25, no. 04 (August 1, 1985): 535–42. http://dx.doi.org/10.2118/11877-pa.

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Abstract A fully coupled treatment of oil wells that are completed in more than one zone results in a bordered matrix. This paper develops solution algorithms that incorporate paper develops solution algorithms that incorporate existing direct and iterative (incomplete LU) solutions in a straightforward manner. Timings in scalar and vector modes on the Cray for a typical reservoir simulation problem are presented. problem are presented. Introduction Numerical simulation of oil reservoirs requires the solution of coupled sets of highly nonlinear partial differential equations. These equations represent the conservation of oil, gas, water, and energy. It usually is necessary to solve from 3 to 10 coupled equations per finite-difference cell. The equations usually are discretized by use of a nearest-neighbor coupling in space and a fully implicit timestep scheme. The resulting set of nonlinear algebraic equations then is solved by Newtonian iteration., Clearly, simulation of large systems requires effective solution of the Jacobian matrix. Many practical reservoir simulation problems involve multiblock wells or fractures. These situations arise when a well is completed in several layers, and consequently the wellbore penetrates several finite-difference cells. Each conservation equation in a cell penetrated by a well will have a source term of the form .....................................(1) where qjt is the mass influx of component k (resulting from the well), Xk is the mobility of component k, 1 pi is the pressure in cell i, and pi, is the unknown wellbore pressure in well j. pressure in well j. To specify the wellbore pressure, pi, an additional equation is required. This extra equation as generally a constraint op the total flow into the well - This constraint is of the form .....................................(2) where qJt. is the total specified fluid flow into well j, Nc, is the total number of components, and is the set of cell numbers penetrated by well j. Because several cells are connected to the same well, there is now an extra degree of coupling between these cells through the well-bore pressure. This coupling generally will not be consistent with the coupling produced by the usual finite-difference molecule. If the well pressures, pjw, are treated explicitly, or are lagged one iteration, convergence difficulties or stability limitations often result. 7 Fully coupled treatment of multiblock wells gives rise to a bordered matrix. We develop various methods to solve these systems. These methods are specifically designed for the block-banded systems arising from fully implicit thermal problems, although similar methods can be used for single-component systems The iterative methods are extensions of the incomplete factorization techniques (ILU), and a direct method is presented for comparison. Existing solution routines can be modified easily to solve the bordered system. Solution of the Bordered Matrix The standard approach to solving fully implicit, fully coupled multiblock wells (or fractures) is to order the unknowns so that those connected with flow in the reservoir (cell pressures, saturations, etc.) appear first in the solution vector. The unknowns connected with the well (well pressures) are placed last in the solution vector. This produces a bordered Jacobian matrix (see Fig. 1). The upper left portion of the matrix has the usual incidence matrix for the Jacobian of nearest-neighbor finite-difference discretization. The incidence matrix for the Jacobian is a matrix with entries zero if the Jacobian elements are zero, and with entries one if the Jacobian elements are nonzero. The border of columns on the upper right of Fig. 1 contains derivatives of the source terms (Eq. 1) with respect to the wellbore pressure The border of rows on the lower left contains derivatives of the constraint equations (Eq. 2) with respect to reservoir variables (i.e., cell pressures). The block on the lower right contains derivatives of the constraint equations with respect to the wellbore pressures and is diagonal. The number of extra columns and rows is proportional to the number of fully coupled wells (or fractures). Although the incidence matrix of the reservoir flow portion of the matrix is symmetric, the incidence matrix of portion of the matrix is symmetric, the incidence matrix of the borders is not necessarily symmetric. George discusses three possible block factorizations of sparse, linear systems. The algorithm used here is based on his second factorization. SPEJ P. 535

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Safarov, R. S., N. S. Seidakhmedov, and R. G. Ragimov. "Problems of Oil and Gas Wells Abandonment." Occupational Safety in Industry, no. 4 (April 2019): 25–30. http://dx.doi.org/10.24000/0409-2961-2019-4-25-30.

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46

McCourt, I., T. Truslove, and J. Kubie. "Penetration of tubulars into horizontal oil wells." Proceedings of the Institution of Mechanical Engineers, Part C: Journal of Mechanical Engineering Science 216, no. 12 (December 1, 2002): 1237–45. http://dx.doi.org/10.1243/095440602321029472.

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Penetration of tubulars into horizontal oil wells is investigated in this work. Locking of the tubulars by frictional forces alone is modelled by inserting small diameter rubber rods into horizontal acrylic tubes. Three different regions of the penetrating rod are described: the initial straight section, followed by sinusoidal deformations with gradually decreasing lengths and increasing amplitudes, which finally develop into helical deformations with subsequent lock-up. The effect of the insertion velocity is also investigated. A simplified model is developed, which is in reasonable agreement with experimental data.

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47

Jackson, R. B. "The integrity of oil and gas wells." Proceedings of the National Academy of Sciences 111, no. 30 (July 9, 2014): 10902–3. http://dx.doi.org/10.1073/pnas.1410786111.

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48

Davis, Adelina P., and Efstathios E. Michaelides. "Geothermal power production from abandoned oil wells." Energy 34, no. 7 (July 2009): 866–72. http://dx.doi.org/10.1016/j.energy.2009.03.017.

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Kabir, Shah, Faisal Rasdi, and B. Igboalisi. "Analyzing Production Data From Tight Oil Wells." Journal of Canadian Petroleum Technology 50, no. 05 (May 1, 2011): 48–58. http://dx.doi.org/10.2118/137414-pa.

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50

Barry, Tim. "PLUNGER LIFT APPLICATION IN DEEP OIL WELLS." APPEA Journal 28, no. 1 (1988): 47. http://dx.doi.org/10.1071/aj87005.

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The Patchawarra Central Oilfields 40 km to the north of Moomba are operated by Santos Ltd. Wells produce 52 API oil with a high gas/oil ratio from depths of about 2 956 m (9 700'). A number of wells, not influenced by pressure maintenance, require some form of vertical lift assistance in order to deplete the reservoir effectively.Following a successful trial on a gas well, plunger lift was installed on the Moorari 6 oil well in early 1987 to assess the suitability of this artificial lift method. This installation was the first use of plunger lift in Australia to assist production in a well at this depth.Plunger lift uses a free piston as an interface to prevent fallback of liquids. The plunger is propelled by pressure build-up in the annulus. Crucial to the operation of plunger lift is the gas/liquid ratio. Sufficient gas must be available to produce the liquid load. In suitable wells, no external energy source is required and it provides a very economical method of maintaining production.The Moorari 6 installation was tested at 11.5 m3/d (72 BOPD) on a well previously producing approximately 7 m3/d (44 BOPD) and requiring significant operator involvement for frequent blowdown of the well to atmosphere.As the reservoir depletes, the expected rise in producing GOR will serve to increase the efficiency of plunger lift operation. Currently under consideration is the introduction of extra gas to the casing, which will give a significant production increase in the early life of the installation.

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