Reservoir characteristics and genesis of high-porosity and high-permeability reservoirs in Tarim Basin

2002 ◽  
Vol 47 (S1) ◽  
pp. 12-19 ◽  
Author(s):  
Jiayu Gu ◽  
Jinhua Jia ◽  
Hui Fang
Keyword(s):  
Tarim Basin ◽  
High Porosity ◽  
High Permeability ◽  
Reservoir Characteristics

scholarly journals Novel glucose-responsive of the transparent nanofiber hydrogel patches as a wearable biosensor via electrospinning

2020 ◽  
Vol 10 (1) ◽  
Author(s):  
Gun Jin Kim ◽  
Kyu Oh Kim
Keyword(s):  
Continuous Monitoring ◽  
Interstitial Fluid ◽  
High Sensitivity ◽  
Poly Vinyl Alcohol ◽  
High Porosity ◽  
High Permeability ◽  
Reverse Iontophoresis ◽  
Glucose Levels ◽  
Non Invasive ◽  
High Enzyme

Abstract Micro- and nanofiber (NF) hydrogels fabricated by electrospinning to typically exhibit outstanding high porosity and specific surface area under hydrated conditions. However, the high crystallinity of NFs limits the achievement of transparency via electrospinning. Transparent poly(vinyl alcohol)/β-cyclodextrin polymer NF hydrogels contacted with reverse iontophoresis electrodes were prepared for the development of a non-invasive continuous monitoring biosensor platform of interstitial fluid glucose levels reaching ~ 1 mM. We designed the PVA/BTCA/β-CD/GOx/AuNPs NF hydrogels, which exhibit flexibility, biocompatibility, excellent absorptivity (DI water: 21.9 ± 1.9, PBS: 41.91 ± 3.4), good mechanical properties (dried: 12.1 MPa, wetted: 5.33 MPa), and high enzyme activity of 76.3%. Owing to the unique features of PVA/β-CD/GOx containing AuNPs NF hydrogels, such as high permeability to bio-substrates and rapid electron transfer, our biosensors demonstrate excellent sensing performance with a wide linear range, high sensitivity(47.2 μA mM−1), low sensing limit (0.01 mM), and rapid response time (< 15 s). The results indicate that the PVA/BTCA/β-CD/GOx/AuNPs NF hydrogel patch sensor can measure the glucose concentration in human serum and holds massive potential for future clinical applications.

scholarly journals Reservoir Characteristics of the Lower Jurassic Lacustrine Shale in the Eastern Sichuan Basin and Its Effect on Gas Properties: An Integrated Approach

Energies ◽  
2020 ◽  
Vol 13 (17) ◽  
pp. 4495
Author(s):  
Jianhua He ◽  
Hucheng Deng ◽  
Ruolong Ma ◽  
Ruyue Wang ◽  
Yuanyuan Wang ◽  
...  
Keyword(s):  
Adsorption Capacity ◽  
Shale Gas ◽  
Lower Jurassic ◽  
Gas Content ◽  
Carbonate Content ◽  
Great Success ◽  
High Porosity ◽  
Reservoir Characteristics ◽  
Laminated Structures ◽  
Gas Properties

The exploration of shale gas in Fuling area achieved great success, but the reservoir characteristics and gas content of the lower Jurassic lacustrine in the northern Fuling areas remain unknown. We conducted organic geochemical analyses, Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction (XRD) analysis, high-pressure mercury intrusion (MIP) and CH4adsorption experimental methods, as well as NMR logging, to study mineral composition, geochemical, pore structure characteristics of organic-rich shales and their effects on the methane adsorption capacity. The Da’anzhai shale member is generally a set of relatively thick (avg. 75 m) and high carbonate-content (avg. 56.89%) lacustrine sediments with moderate total organic carbon (TOC) (avg. 1.12%) and thermal maturation (Vitrinite reflectance (VR): avg. 1.19%). Five types of lithofacies can be classified: marl (ML), calcareous shale (CS), argillaceous shale (AS), muddy siltstone (MS), and silty shale (SS). CS has good reservoir quality with a high porosity (avg. 4.72%). The small pores with the transverse relaxation time of 0.6–1 ms and 1–3 ms comprised the major part of the porosity in the most lithofacies from Nuclear magnetic resonance (NMR) data, while the large pore (>300 ms) accounts for a small porosity proportion in the CS. The pores mainly constitute of mesopores (avg. 23.2 nm). The clay minerals with a large number of interparticle pores in the SEM contributes most to surface area in the shale lithofacies with a moderate TOC. The adsorption potential of shale samples is huge with an average adsorption capacity of 4.38 mL/g and also has high gas content (avg. 1.04 m3/t). The adsorption capacity of shale samples increases when TOC increases and temperature decreases. Considered reservoir properties and gas properties, CS with the laminated structures in the medium-upper section of the Da’anzhai member is the most advantage lithofacies for shale gas exploitation.

Seismic monitoring of a CO2 flood in a carbonate reservoir: A rock physics study

Geophysics ◽  
1998 ◽  
Vol 63 (5) ◽  
pp. 1604-1617 ◽  
Author(s):  
Zhijing Wang ◽  
Michael E. Cates ◽  
Robert T. Langan
Keyword(s):  
High Resolution ◽  
Pore Pressure ◽  
Rock Physics ◽  
Fluid Substitution ◽  
High Porosity ◽  
High Permeability ◽  
Pressure Buildup ◽  
Reservoir Rocks ◽  
Velocity Changes

A carbon dioxide (CO2) injection pilot project is underway in Section 205 of the McElroy field, West Texas. High‐resolution crosswell seismic imaging surveys were conducted before and after CO2 flooding to monitor the CO2 flood process and map the flooded zones. The velocity changes observed by these time‐lapse surveys are typically on the order of −6%, with maximum values on the order of −10% in the vicinity of the injection well. These values generally agree with laboratory measurements if the effects of changing pore pressure are included. The observed dramatic compressional ([Formula: see text]) and shear ([Formula: see text]) velocity changes are considerably greater than we had initially predicted using the Gassmann (1951) fluid substitution analysis (Nolen‐Hoeksema et al., 1995) because we had assumed reservoir pressure would not change from survey to survey. However, the post‐CO2 reservoir pore fluid pressure was substantially higher than the original pore pressure. In addition, our original petrophysical data for dry and brine‐saturated reservoir rocks did not cover the range of pressures actually seen in the field. Therefore, we undertook a rock physics study of CO2 flooding in the laboratory, under the simulated McElroy pressures and temperature. Our results show that the combined effects of pore pressure buildup and fluid substitution caused by CO2 flooding make it petrophysically feasible to monitor the CO2 flood process and to map the flooded zones seismically. The measured data show that [Formula: see text] decreases from a minimum 3.0% to as high as 10.9%, while [Formula: see text] decreases from 3.3% to 9.5% as the reservoir rocks are flooded with CO2 under in‐situ conditions. Such [Formula: see text] and [Formula: see text] decreases, even if averaged over all the samples measured, are probably detectable by either crosswell or high‐resolution surface seismic imaging technologies. Our results show [Formula: see text] is sensitive to both the CO2 saturation and the pore pressure increase, but [Formula: see text] is particularly sensitive to the pore pressure increase. As a result, the combined [Formula: see text] and [Formula: see text] changes caused by the CO2 injection may be used, at least semiquantitatively, to separate CO2‐flooded zones with pore pressure buildup from those regions without pore pressure buildup or to separate CO2 zones from pressured‐up, non‐CO2 zones. Our laboratory results show that the largest [Formula: see text] and [Formula: see text] changes caused by CO2 injection are associated with high‐porosity, high‐permeability rocks. In other words, CO2 flooding and pore pressure buildup decrease [Formula: see text] and [Formula: see text] more in high‐porosity, high‐permeability samples. Therefore, it may be possible to delineate such high‐porosity, high‐permeability streaks seismically in situ. If the streaks are thick enough compared to seismic resolution, they can be identified by the larger [Formula: see text] or [Formula: see text] changes.

Experimental Study on Sensitivity Damage of Offshore High-Porosity and High-Permeability Reservoir

2014 ◽  
Vol 926-930 ◽  
pp. 111-114
Author(s):  
Jun Yi Liu ◽  
Zheng Song Qiu ◽  
Wei An Huang ◽  
Yang Luo
Keyword(s):  
Experimental Studies ◽  
Wide Distribution ◽  
Development Stage ◽  
Stress Sensitivity ◽  
Laboratory Evaluation ◽  
Drilling Fluids ◽  
High Porosity ◽  
High Permeability ◽  
Intrusion Prevention ◽  
Water Sensitivity

Offshore high-porosity and high-permeability reservoirs, characterized by large pore throat, wide distribution of pore size and enriched sensitive minerals, are easily damaged due to improper use of drilling fluids and completion fluids during the development stage. A series of experimental studies were carried out on the sensitivity damage analysis including X-ray diffraction, scanning electron microscopy, mercury injection porosimetry and core flow experiment. According to the laboratory evaluation results, the reservoir SZLF of high-porosity and high-permeability existed strong water sensitivity and mid to strong stress sensitivity. Furthermore, shielding and temporary plugging technique applied for reservoir protection was put forward, and laboratory tests showed that it had a better effect on solid intrusion prevention.

scholarly journals A numerical sensitivity study of how permeability, geological structure, and hydraulic gradient control the lifetime of a geothermal reservoir

2019 ◽  
Author(s):  
Johanna F. Bauer ◽  
Michael Krumbholz ◽  
Elco Luijendijk ◽  
David C. Tanner
Keyword(s):  
Damage Zone ◽  
Complex Function ◽  
Sensitivity Study ◽  
Geological Structure ◽  
Hydraulic Gradient ◽  
High Porosity ◽  
High Permeability ◽  
Reservoir Volume ◽  
Thermal Breakthrough ◽  
High Yields

Abstract. Geothermal energy is an important and sustainable resource that has more potential than is currently utilized. Whether or not a deep geothermal resource can be exploited, depends on, besides temperature, mostly the utilizable reservoir volume over time, which in turn largely depends on petrophysical parameters. We show, using a large series (n = 1027) of 4-dimensional finite element models of a simple geothermal doublet, that the lifetime of a reservoir is a complex function of its geological parameters, their heterogeneity, and the background hydraulic gradient (BHG). In our models, we test the effects of porosity, permeability, and BHG in an isotropic medium. Further, we simulate the effect of permeability contrast and anisotropy induced by layering, fractures, and a fault. We quantify the lifetime of the reservoir by measuring the time to thermal breakthrough, i.e., how many years pass before the 100 °C isotherm (HDI) reaches the production well. Our results attest to the positive effect of high porosity; however, high permeability and BHG can combine to outperform the former. Certain configurations of all the parameters can cause either early thermal breakthrough or extreme longevity of the reservoir. For example, the presence of high permeability fractures, e.g., in a fault damage zone, can provide initially high yields, but channels fluid flow and therefore dramatically restricts the exploitable reservoir volume. We demonstrate that the magnitude and orientation of the BHG, provided permeability is sufficiently high, are prime parameters that affect the lifetime of a reservoir. Our numerical experiments show also that BHGs (low and high) can be outperformed by comparatively small variations in permeability contrast (103) and fracture-induced permeability anisotropy (101) that thus strongly affect the performance of geothermal reservoirs.

scholarly journals A numerical sensitivity study of how permeability, porosity, geological structure, and hydraulic gradient control the lifetime of a geothermal reservoir

Solid Earth ◽  
2019 ◽  
Vol 10 (6) ◽  
pp. 2115-2135 ◽  
Author(s):  
Johanna F. Bauer ◽  
Michael Krumbholz ◽  
Elco Luijendijk ◽  
David C. Tanner
Keyword(s):  
Damage Zone ◽  
Complex Function ◽  
Sensitivity Study ◽  
Geological Structure ◽  
Hydraulic Gradient ◽  
High Porosity ◽  
High Permeability ◽  
Reservoir Volume ◽  
Thermal Breakthrough ◽  
High Yields

Abstract. Geothermal energy is an important and sustainable resource that has more potential than is currently utilized. Whether or not a deep geothermal resource can be exploited, mostly depends on, besides temperature, the utilizable reservoir volume over time, which in turn largely depends on petrophysical parameters. We show, using over 1000 (n=1027) 4-D finite-element models of a simple geothermal doublet, that the lifetime of a reservoir is a complex function of its geological parameters, their heterogeneity, and the background hydraulic gradient (BHG). In our models, we test the effects of porosity, permeability, and BHG in an isotropic medium. Furthermore, we simulate the effect of permeability contrast and anisotropy induced by layering, fractures, and a fault. We quantify the lifetime of the reservoir by measuring the time to thermal breakthrough, i.e. how many years pass before the temperature of the produced fluid falls below the 100 ∘C threshold. The results of our sensitivity study attest to the positive effect of high porosity; however, high permeability and BHG can combine to outperform the former. Particular configurations of all the parameters can cause either early thermal breakthrough or extreme longevity of the reservoir. For example, the presence of high-permeability fractures, e.g. in a fault damage zone, can provide initially high yields, but it channels fluid flow and therefore dramatically restricts the exploitable reservoir volume. We demonstrate that the magnitude and orientation of the BHG, provided permeability is sufficiently high, are the prime parameters that affect the lifetime of a reservoir. Our numerical experiments show also that BHGs (low and high) can be outperformed by comparatively small variations in permeability contrast (103) and fracture-induced permeability anisotropy (101) that thus strongly affect the performance of geothermal reservoirs.

Reservoir characteristics and controlling factors of Silurian Lower Kepingtage Formation in Tahe area, Tarim Basin, NW China

2017 ◽  
Vol 28 (6) ◽  
pp. 1135-1144 ◽  
Author(s):  
Ruohan Liu ◽  
Zaixing Jiang ◽  
Ming Wang ◽  
Weili Yang ◽  
Jingxiang Guo ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Controlling Factors ◽  
Nw China ◽  
Reservoir Characteristics

Pay Zone Protection During Drilling In Offshore Oilfield Producing With High Porosity, High Permeability And Low Pore Pressure

2010 ◽  
Author(s):  
Wei Jiang ◽  
Jianming Deng ◽  
Xiaocheng Zhang ◽  
Wenbo Tang ◽  
Zili Li ◽  
...  
Keyword(s):  
Pore Pressure ◽  
High Porosity ◽  
High Permeability

The Petroleum System of Northern Kashi Sag in Tarim Basin and Exploration Direction

2012 ◽  
Vol 524-527 ◽  
pp. 89-95 ◽  
Author(s):  
Yu Zhao Hu ◽  
Pei Rong Zhao ◽  
Yu Hui Lv
Keyword(s):  
Source Rock ◽  
Tarim Basin ◽  
First Grade ◽  
Petroleum System ◽  
Reservoir Rock ◽  
Lower Permian ◽  
High Porosity ◽  
Oil Sand ◽  
Gas Reservoir ◽  
Petroleum Systems

Northern Kashi Sag is located on the northwestern periphery of Tarim Basin, China. This block has been explored for a half century, and Akmomu gas reservoir was discovered in 2001. In Northern Kashi Sag, organic-rich intervals mainly occur in Carboniferous, Lower Permian and Jurassic. Lower Cretaceous Kezilesu Formation(K1kz) is dominated by braid river succession and is best in big thickness of 385-862m，high porosity of 14.90% and high permeability of 207.00 ×10-3μm2. The first grade cap rocks are gypsolyte and mud-gypsolyte in upper Cretaceous and Paleogene with thickness of 100-200m. Two Petroleum Systems are identified, and one is J2y-N1p, Yangye Formation (J2y) serves as source rock, and Neogene Pakabulake(N1p) as reservoir rock. Another is C1+P1by-K1kz petroleum system, Lower Carboniferous and Lower Permian Biyoulieti Formation( P1by) serve as source rock, and Kezilesu Formation (K1kz) as reservoir rock. J2y-N1p petroleum system contains abundant oil sand resource. In 2001,Akmomu gas reservoir was discovered by AK＃1 in C1+P1by-K1kz petroleum system.

Sweep Improvement Options for Highly Heterogeneous Reservoirs with High Temperature and Ultra-High Salinity: A Case Study in Tarim Basin, China

2021 ◽  
Author(s):  
Chengdong Yuan ◽  
Wanfen Pu ◽  
Mikhail Alekseevich Varfolomeev ◽  
Aidar Zamilevich Mustafin ◽  
Tao Tan ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Tarim Basin ◽  
High Salinity ◽  
Mobility Control ◽  
Surfactant Flooding ◽  
High Permeability ◽  
Permeability Heterogeneity ◽  
Foam Flooding

Abstract How to control excessive water production in high-temperature and high-salinity reservoirs has always been a challenge, which has been facing many oil reservoirs in Tarim Basin (China), such as Y2 reservoir with an average temperature of 107 ℃, salinity of 213900 mg/L (Ca2++Mg2+&gt;11300mg/L), and permeability from 2 to 2048 mD. In this work, we present experimental studies to determine the potential EOR process for Y2 reservoir from foam flooding, polymer gel/foam flooding, and microgel/surfactant flooding. To simulate the permeability heterogeneity of Y2 reservoir, a 2-D sand-pack model was used for flooding experiments. Vertically, three layers (first 0.6cm, second 0.8cm and third 1.6cm from top to bottom, respectively) were packed with different size sand to simulate permeability heterogeneity (permeability increases from first to third layer). A 0.3 cm higher permeability zone was also filled inside third layer. Horizontally, permeability gradually decreases from middle to two sides. In this model, injection well was vertical, and production well was horizontal. The effect of impermeable interlayer was also studied by isolating the second and third layer. The results show that conformance treatments using in-situ crosslinked gel or micro-gel are necessary before foam or surfactant injection under a high permeability heterogeneity. When an impermeable interlayer existed between the second and third layer, the additional oil recovery of N2 foam flooding, in-situ crosslinked gel/N2 foam flooding, and microgel/surfactant flooding was 16.34%, 20.37%, 17.50%, respectively, which was much higher than that without impermeable interlayer (9.84%, 13.62%, 12.07%). This implies that when multiple layers exist, crossflow between layers is unfavorable for improving oil recovery, which should be paid extra attention in EOR process. Foam flooding has not only a good mobility control capacity but also a good oil displacement ability (verified by visual observations of washed sand after experiments), which, together with the strong conformance control ability of crosslinked gel, makes in-situ crosslinked gel/N2 foam flooding yield the highest displacement efficiency. Generally, for high-temperature and ultra-high-salinity reservoirs with strong heterogeneity like Y2 reservoir, in-situ crosslinked gel/foam flooding can be a good candidate for EOR. This work provides a potential EOR method with high efficiency, i.e. in-situ crosslinked gel assisted N2 foam flooding, for the development of similar reservoirs like Y2 with high temperature, ultra-high salinity, high heterogeneity and multiple layers. Moreover, this work also highlights that, despite that foam has the ability of mobility and profile control, a conformance treatment is necessary to block high permeability zone before foam injection when the reservoirs has a strong heterogeneity.

Sign in / Sign up

Export Citation Format

Share Document