Practical Imaging Applications of Wettability Contact Angles on Kuwaiti Tight Carbonate Reservoir with Different Rock Types DOI

Saleh Al-Sayegh,

Ralph E. Flori,

Waleed Al-Bazzaz

et al.

Published: March 13, 2023

Abstract This study focuses on a tight carbonate reservoir which is located in Northern Kuwait and classified as an unconventional reservoir. A practical imaging technique of wettability contact angle (θ°) presents "big data" well relative-permeability (Krw Kro) measurements. Also, modeling, through rock image technology, the vast well-documented grain/pore boundary morphology available inside fresh fragments have achieved good results. Conventional laboratory experiments are expensive time-consuming. introduces novel method to measure/calculate relative permeability fast, less expensive, non-destructive, environmentally friendly techniques technology. One selected, imaged, processed, analyzed, then modeled using several pore diameter morphological models. The images captured backscattered electron microscopy BSE-SEM technology analyses. In this study, two-dimensional used characterize selected samples grains pores, two-step technique. first step, detector (BSE), digital imaging, pore-counting processing All sample features reported micrometer units. second area such scanned analysis software that can accurately measure parameters grain spaces. robust visual estimate used, has advantage speeding process. tool counts different pores also measures their shapes sizes crucial for calculations. Several models been considered optimum accuracy comparisons, including pore/grain relationships (area/perimeter), (θ), count. Relative calculated based measured from images. objectives huge geometries 2D understand nature network candidate To internal influences needed enhanced oil recovery/improved recovery (EOR/ IOR) future programs. And, finally, faster more accurately.

Language: Английский

Fluid–rock interactions and its implications on EOR: Critical analysis, experimental techniques and knowledge gaps DOI Creative Commons
Abubakar Isah, Muhammad Arif, Amjed Hassan

et al.

Energy Reports, Journal Year: 2022, Volume and Issue: 8, P. 6355 - 6395

Published: May 16, 2022

Characterization of fluid–rock interactions is essential for a broad range subsurface applications such as understanding fluid flow in porous medium and enhanced oil recovery predictions. Enhanced (EOR) crucial gas production operations, it entails injecting fluids into the reservoir to enhance productivity. When are injected, occur between injected rock/fluids; outcomes critically impact associated recovery. Furthermore, changes properties (porosity, permeability etc.) behavior (i.e. wettability alteration relative changes) demonstrate variability at scales. Thus, great importance understand these multiple scales their ensuing implications on EOR. This study therefore provides comprehensive review types both carbonate sandstone reservoirs. Fluid–rock quantification methods, applicability principle measurements were summarized. The fluid–rock​ extensively discussed. Finally, we identified highlighted some research gaps provided recommendations future directions. findings this show that despite numerous studies adsorption, dissolution/precipitation, clay swelling/fines migration wetting characteristics media involving EOR fluids, exact mechanism action during rock/oil/brine system, still not fully understood. extent depends several factors/parameters. Such factors include type chemical composition, rock mineralogical brine pH, salinity composition. Moreover, shows all techniques have limitations either applicability, measurement range, or uncertainty level. Therefore, incorporation various imaging characterization tools would be required improved interactions. review, therefore, critical insights area its expected our knowledge provide better thereby reduce uncertainties with laboratory-scale predictions, management oil.

Language: Английский

Citations

53
Corrosion challenges in supercritical CO2 transportation, storage, and utilization—a review DOI
Haofei Sun, Haoxiang Wang, Yimin Zeng

et al.

Renewable and Sustainable Energy Reviews, Journal Year: 2023, Volume and Issue: 179, P. 113292 - 113292

Published: April 14, 2023

Language: Английский

Citations

39
Microfluidics experimental investigation of the mechanisms of enhanced oil recovery by low salinity water flooding in fractured porous media DOI
Atena Mahmoudzadeh, Mobeen Fatemi, Mohsen Masihi

et al.

Fuel, Journal Year: 2022, Volume and Issue: 314, P. 123067 - 123067

Published: Jan. 6, 2022

Language: Английский

Citations

32
Wettability Alteration during Low-Salinity Water Flooding DOI
Ammar M. Al-bayati, Chamini Ishaka Karunarathne,

Abdulrahman S. Al Jehani

et al.

Energy & Fuels, Journal Year: 2022, Volume and Issue: 36(2), P. 871 - 879

Published: Jan. 11, 2022

Low-salinity water flooding (LSWF) for hydrocarbon recovery has attracted industrial attention, owing to its simplicity and economic feasibility. Although this topic received numerous studies, mechanisms driving the low-salinity effect remain poorly understood. This study is aimed at investigating direct effects of injecting brine (0.6 0.2 M NaCl) as non-wetting fluid Soltrol 130 a synthetic wetting on outcrop "Austin Chalk" rock samples. The petrophysical properties samples were estimated by saturating core with high- laboratory conditions. Experiments conducted unsteady-state steady-state flow both imbibition drainage processes. A shift right been observed relative permeability curve NaCl along drop in irreducible saturation (Swi) residual oil (Sor). Furthermore, results have shown reduction from 22.2 18.7% when using compared 0.6 NaCl. current research demonstrates that ionic interactions among rock, oil, compositions would alter situ wettability carbonate oil-wet/mixed-wet more water-wet correlation found double-layer expansion, ζ potential, alteration during LSWF. Moreover, improved takes place LSWF only repulsive electrostatic force between oil–brine mineral–brine interfaces induced change composition. potential become negative dilution brine. After sample aged changed, indicating an wettability.

Language: Английский

Citations

31
Pore-scale imaging of asphaltene deposition with permeability reduction and wettability alteration DOI Creative Commons
Yihuai Zhang, Qingyang Lin, Ali Q. Raeini

et al.

Fuel, Journal Year: 2022, Volume and Issue: 316, P. 123202 - 123202

Published: Jan. 23, 2022

To better understand asphaltene deposition mechanisms and their influence on rock permeability wettability, we have developed an in situ micro-CT imaging capability to observe precipitation during multiphase flow at high resolution three dimensions. Pure heptane crude oil were simultaneously injected induce the pore space of a sandstone sample. The across sample was nine times lower after first precipitation, while it reduced by factor ninety due migration growth subsequent brine injection. Furthermore, through quantifying curvatures contact angles images before observed that wettability porous medium changed from water-wet mixed-wet. Overall, demonstrate analysis workflow quantify deposition, reduction change which can be used for reservoir characterisation remediation.

Language: Английский

Citations

30
Impact of rock morphology on the dominating enhanced oil recovery mechanisms by low salinity water flooding in carbonate rocks DOI
Hamed Farhadi, Shahab Ayatollahi, Mobeen Fatemi

et al.

Fuel, Journal Year: 2022, Volume and Issue: 324, P. 124769 - 124769

Published: June 10, 2022

Language: Английский

Citations

24
The impact of bimodal pore size distribution and wettability on relative permeability and capillary pressure in a microporous limestone with uncertainty quantification DOI Creative Commons
Guanglei Zhang, Sajjad Foroughi, Ali Q. Raeini

et al.

Advances in Water Resources, Journal Year: 2022, Volume and Issue: 171, P. 104352 - 104352

Published: Nov. 16, 2022

Pore-scale X-ray imaging combined with a steady-state flow experiment was used to study the displacement processes during waterflooding in an altered-wettability carbonate, Ketton limestone, more than two orders of magnitude difference pore size between macropores and microporosity. We simultaneously characterized macroscopic local multiphase parameters, including relative permeability, capillary pressure, wettability, fluid occupancy pores throats. An accurate method applied for porosity saturation measurements using greyscale based differential without image segmentation. The permeability values were corrected by considering measured profile along sample length account so-called end effect. behaviour pressure compared other literature demonstrate effects wettability structure. Typical oil-wet resolvable from contact angle, curvature. negative while oil dropped quickly as drained low flowed through connected layers. Brine initially largely water-wet microporosity, then filled centre large bodies. Thus, brine remained exceptionally until formed path leading substantial increase permeability. Overall, this work demonstrates that not only but also distribution microporosity have significant impact on processes.

Language: Английский

Citations

24
Pore network-scale visualization of the effect of brine composition on sweep efficiency and speed of oil recovery from carbonates using a photolithography-based calcite microfluidic model DOI
Mehdi Mohammadi,

Hadi Nikbin‐Fashkacheh,

Hassan Mahani

et al.

Journal of Petroleum Science and Engineering, Journal Year: 2021, Volume and Issue: 208, P. 109641 - 109641

Published: Oct. 12, 2021

Language: Английский

Citations

25
Investigation on microscopic invasion characteristics and retention mechanism of fracturing fluid in fractured porous media DOI Creative Commons
Qian Da, Chuanjin Yao, Xue Zhang

et al.

Petroleum Science, Journal Year: 2022, Volume and Issue: 19(4), P. 1745 - 1756

Published: March 5, 2022

Reservoir damage caused by guar gum fracturing fluid and slick water seriously affects the subsequent oil gas production. However, invasion characteristics retention mechanisms of fluids in fracture-matrix zone are still unclear. In this work, a microscopic model reflecting was designed. Based on microfluidic experimental method, process invasion, flowback investigated visually characterized quantitatively. The factors affecting were analyzed clarified. results indicated that process, frontal swept range larger than fluid, displacement efficiency rate lower those under same pressure. With increase pressure, increased from 61.09% to 82.77%, decreased 93.45% 83.36%. Before production, invaded mainly concentrated medium-high permeability area zone. main resistance capillary force, while viscous resistance. most serious low region near end fracture. numerical simulation showed increasing production pressure difference could improve velocity field distribution zone, finally reduce fracture fluid. include emulsion flow retention, retention. Emulsion is force interception effect. Viscous polymer, flow-field uneven velocity.

Language: Английский

Citations

19
Pore-scale imaging and analysis of secondary surfactant flooding in a heterogeneous carbonate rock DOI
Hussain M. Alzahrani, Branko Bijeljic, Sajjad Foroughi

et al.

Geoenergy Science and Engineering, Journal Year: 2025, Volume and Issue: unknown, P. 213728 - 213728

Published: Jan. 1, 2025

Language: Английский

Citations

0