permeability anisotropy
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2021 ◽  
Author(s):  
Catherine Breislin ◽  
Laura Galluccio ◽  
Kate Al Tameemi ◽  
Riaz Khan ◽  
Atef Abdelaal

Abstract Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffles or barriers to vertical flow and create significant permeability anisotropy.


Crystals ◽  
2021 ◽  
Vol 11 (12) ◽  
pp. 1524
Author(s):  
Pengfei Zhao ◽  
Xingxing Wang ◽  
Xiangyu Fan ◽  
Xingzhi Wang ◽  
Feitao Zeng ◽  
...  

The characteristics of laminae in lamellar shale oil reservoirs have important influences on reservoir parameters, especially permeability. In order to explore the influence of lamina density and occurrence on the permeability of lamellar shale after hydration, we studied the lamellar shale in the Chang 7 member of the Yanchang Formation of Triassic in Ordos Basin. By comparing the permeability of bedding shale and lamellar shale with different densities of laminae, it was found that the permeability anisotropy of lamellar shale was stronger. In the direction parallel to the lamina, the permeability increased approximately linearly with an increase in lamina density. The effect of hydration on rock micropore structure and permeability was studied by soaking shale in different fluids. Most of the microfracture in the lamellar shale was parallel to the lamina direction, and hydration led to a widening of the microfracture, which led to the most obvious increase in permeability parallel to the lamina. Collectively, the research results proved that lamina density, occurrence, and hydration have a significant influence on the permeability anisotropy of lamellar shale.


2021 ◽  
pp. 56-62
Author(s):  
М.Б. Ригмант ◽  
Н.В. Казанцева ◽  
А.В. Кочнев ◽  
Ю.Н. Коэмец ◽  
Ю.В. Корх ◽  
...  

Investigations of texture, phase composition and magnetic anisotropy in rolled samples of austenitic steel 09Kh17N5Yu were carried out. It has been shown that the method of magnetic nondestructive testing using measuring of magnetic fields from locally magnetized areas is sensitive to anisotropy of magnetic permeability. Anisotropy of magnetic properties is related to formation of mechanical rolling texture. FCC rolling texture {110}<111> was found in all the rolled samples. Rolling texture, common for BCC structure (strain-induced martensite in low-carbon austenitic steels), developed in the samples with 30% of deformation or higher. Formation of ferromagnetic strain-induced martensite in austenitic steel 09Kh17N5Yu was confirmed by magnetic force microscopy.


Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7482
Author(s):  
Mingxian Wang ◽  
Xiangji Dou ◽  
Ruiqing Ming ◽  
Weiqiang Li ◽  
Wenqi Zhao ◽  
...  

Refracturing treatment is an economical way to improve the productivity of poorly or damaged fractured horizontal wells in tight reservoirs. Fracture reorientation and fracture face damage may occur during refracturing treatment. At present, there is still no report on the rate decline solution for refractured horizontal wells in tight reservoirs. In this work, by taking a semi-analytical method, traditional rate decline and Blasingame-type rate decline solutions were derived for a refractured horizontal well intercepted by multiple reorientation fractures with fracture face damage in an anisotropic tight reservoir. The accuracy and reliability of the traditional rate decline solution were verified and validated by comparing it with a classic case in the literature and a numerical simulation case. The effects of fracture reorientation and fracture face damage on the rate decline were investigated in depth. These investigations demonstrate that fracture face damage is not conducive to increasing well productivity during the early flow period and there is an optimal matching relationship between the principal fracture section angle and permeability anisotropy, particularly for the reservoirs with strong permeability anisotropy. The fracture length ratio and fracture spacing have a weak effect on the production rate and cumulative production while the fracture number shows a strong influence on the rate decline. Furthermore, multifactor sensitivity analysis indicates that fracture conductivity has a more sensitive effect on well productivity than fracture face damage, implying the importance of improving fracture conductivity. Finally, a series of Blasingame-type rate decline curves were presented, and type curve fitting and parameter estimations for a field case were conducted too. This work deepens our understanding of the production performance of refractured horizontal wells, which helps to identify reorientation fracture properties and evaluate post-fracturing performance.


SPE Journal ◽  
2021 ◽  
pp. 1-18
Author(s):  
Yingli Xia ◽  
Tianfu Xu ◽  
Yilong Yuan ◽  
Xin Xin ◽  
Huixing Zhu

Summary Natural gas hydrate (NGH) is regarded as an important alternative future energy resource. In recent years, a few short-term production tests have been successfully conducted with both permafrost and marine sediments. However, long-term hydrate production performance and the potential geomechanical problems are not very clear. According to the available geological data at the Mallik site, a more realistic hydrate reservoir model that considers the heterogeneity of porosity, permeability, and hydrate saturation was developed and validated by reproducing the field depressurization test. The coupled multiphase and heat flow and geomechanical response induced by depressurization were fully investigated for long-term gas production from the validated hydrate reservoir model. The results indicate that long-term gas production through depressurization from a vertically heterogeneous hydrate reservoir is technically feasible, but the production efficiency is generally modest, with the low average gas production rate of 4.93 × 103 ST m3/d (ST represents the standard conditions) over a 1-year period. The hydrate dissociation region is significantly affected by the reservoir heterogeneity and reveals a heterogeneous dissociation front in the reservoir. The depressurization production results in significant increase of shear stress and vertical compaction in the hydrate reservoir. The response of shear stress indicates that the potential region of sand migration is mainly in the sand-dominant layer during gas production from the hydraulically heterogeneous hydrate reservoir (e.g., sand layers interbedded with clay layers). The maximum subsidence is approximately 78 mm and occurred at the 72nd day, whereas the final subsidence is slowly dropped to 63 mm after 1-year of depressurization production. The vertical subsidence is greatly dependent on the elastic properties and the permeability anisotropy. In particular, the maximum subsidence increased by approximately 81% when the ratio of permeability anisotropy was set at 5:1. Furthermore, the potential shear failure in the hydrate reservoir is strongly correlated to the in-situ stress state. For the normal fault stress regime, the greater the initial horizontal stress is, the less likely the hydrate reservoir is to undergo shear failure during depressurization production.


Energies ◽  
2021 ◽  
Vol 14 (19) ◽  
pp. 6122
Author(s):  
Justin Ezekiel ◽  
Diya Kumbhat ◽  
Anozie Ebigbo ◽  
Benjamin M. Adams ◽  
Martin O. Saar

There is a potential for synergy effects in utilizing CO2 for both enhanced gas recovery (EGR) and geothermal energy extraction (CO2-plume geothermal, CPG) from natural gas reservoirs. In this study, we carried out reservoir simulations using TOUGH2 to evaluate the sensitivity of natural gas recovery, pressure buildup, and geothermal power generation performance of the combined CO2-EGR–CPG system to key reservoir and operational parameters. The reservoir parameters included horizontal permeability, permeability anisotropy, reservoir temperature, and pore-size-distribution index; while the operational parameters included wellbore diameter and ambient surface temperature. Using an example of a natural gas reservoir model, we also investigated the effects of different strategies of transitioning from the CO2-EGR stage to the CPG stage on the energy-recovery performance metrics and on the two-phase fluid-flow regime in the production well. The simulation results showed that overlapping the CO2-EGR and CPG stages, and having a relatively brief period of CO2 injection, but no production (which we called the CO2-plume establishment stage) achieved the best overall energy (natural gas and geothermal) recovery performance. Permeability anisotropy and reservoir temperature were the parameters that the natural gas recovery performance of the combined system was most sensitive to. The geothermal power generation performance was most sensitive to the reservoir temperature and the production wellbore diameter. The results of this study pave the way for future CPG-based geothermal power-generation optimization studies. For a CO2-EGR–CPG project, the results can be a guide in terms of the required accuracy of the reservoir parameters during exploration and data acquisition.


Energies ◽  
2021 ◽  
Vol 14 (17) ◽  
pp. 5585
Author(s):  
Ekhwaiter Abobaker ◽  
Abadelhalim Elsanoose ◽  
Faisal Khan ◽  
Mohammad Azizur Rahman ◽  
Amer Aborig ◽  
...  

Oil and gas well productivity can be affected by a number of different skin factors, the combined influences of which contribute to a well’s total skin factor. The skin caused by deviated wells is one such well-known factor. The present study aimed to investigate skin effects caused by deviated well slants when considering vertical-to-horizontal permeability anisotropy. The research employed computational fluid dynamics (CFD) software to simulate fluid flows in inclined wells through the injection of water with Darcy flow using 3D geometric formations. The present work investigates the effects of four main characteristics—namely, the permeability anisotropy, wellbore radius, reservoir thickness, and deviation angle—of open-hole inclined wells. Additional investigations sought to verify the effect of the direction of perforations on the skin factor or pressure drop in perforated inclined wells. In the case of an inclined open hole well, the novel correlation produced in the current study simplifies the estimation of the skin factor of inclined wells at different inclination angles. Our comparison indicates good agreement between the proposed correlation and available models. Furthermore, the results demonstrated a deviation in the skin factor estimation results for perforated inclined wells in different perforation orientation scenarios; therefore, existing models must be improved in light of this variance. This work contributes to the understanding and simulation of the effects of well inclination on skin factor in the near-wellbore region.


Author(s):  
Arman Najafi ◽  
Javad Siavashi ◽  
Mohammad Ebadi ◽  
Mohammad Sharifi ◽  
Jalal Fahimpour ◽  
...  

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