In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Yu, Hongyan (State Key Laboratory of Continental Dynamics) | Li, Xiaolong (Department of Geology, Northwest University) | Wang, Zhenliang (State Key Laboratory of Continental Dynamics) | Rezaee, Reza (Department of Geology, Northwest University) | Gan, Litao (Northwest University)
Abundant shale oil and gas resources have been discovered in the Zhangjiatan shale of the Yanchang formation in ordos basin in recent years. Zhangjiatan shale is a typical lacustrine shale, which is different from Marine shale in physical properties. Most previous research has focused on Marine shale. In order to understand the rock mechanical properties of Zhangjiatan shale, we conducted dynamic and static elastic properties experiments. We selected argillaceous shale and silty laminae shale in Zhangjiatan shale as samples. In order to obtain the static Young's modulus and Poisson's ratio, we use the triaxial pressure test. We use the dipole log to measure the acoustic velocity down the hole, and then we calculate the dynamic Young's modulus and Poisson's ratio of the sample based on acoustic velocity. Young's modulus of argillaceous shale is slightly smaller than that of silty laminae shale and the Poisson's ratio of argillaceous shale is also smaller than that of silty laminae shale. The brittleness of argillaceous shale are greater than that of silty laminae shale, as a result, argillaceous shale is much easier fracturing under pressure. We plotted the cross-plot of RCS, elastic properties and TOC and reached a conclusion that the mass ratio of clay to quartz and feldspar determined the brittleness and deformability of rock, while organic matters also affected the elastic properties of rock. Therefore, the elastic properties of shale are not controlled by a single factor, instead of multiple factors.
Yu, Hongyan (Northwest University) | Zhang, Yihuai (Curtin University) | Lebedev, Maxim (Curtin University) | Wang, Zhenliang (Northwest University) | Verrall, Michael (CSIRO) | Iglauer, Stefan (Edith Cowan University)
Carbon dioxide (CO2) inject to the saline aquifers are general considered as the best candidates for large-scale storage and CO2 enhance oil recovery. The pore structure and permeability are changed by the fines release, migration in the initial stage of CO2 injection, which is of great importance for reservoir screening and injection design requires adequate understanding. We thus imaged an unconsolidated sandstone at reservoir condition before and after live brine injection in situ with micro-CT core flooding apparatus. We conclude that the pore structure of the unsolid high pores media rock can be significantly changed after live brine injection, although the porosity just have a small increased. Meanwhile, many fractures are generated in the quartz after live brine flush away. Specific surface area are quantified from micro CT scan image analysis to calculate the absolute permeability. The permeability is significantly improved due to the pore structure change which can improve CO2 infectivity, especially low-permeability reservoirs. The results of this study present a broad characterization of the mechanical properties in lacustrine shale and can therefore help optimize hydraulic fractured fundamental and enhanced gas recovery.
Yu, Hongyan (Northwest University) | Wei, Xiaolong (University of Houston) | Wang, Zhenliang (Northwest University) | Rezaee, Reza (Curtin University) | Zhang, Yihuai (Curtin University) | Lebedev, Maxim (Curtin University) | Iglauer, Stefan (Edith Cowan University)
The gas content in shale reservoir is of great importance in reservoir evaluation. Shale reservoir has various gas including free gas, adsorpted gas and soluted gas. Free gas take an important part for the total gas content. Hence, we investigated three equations for water saturation calculating and compared and improved them based on theoretical analysis in order to find a siutable one for the shale reservoir characterization. The results indicate that the Archie formula has several limitations applied to complex pore structure, which leads to high water saturation. Since the Archie formula was proposed by experimental data in pure sandstone without enough consideration about the clay of shale reservoir. The Waxman-Smits is suitable to shale gas reservoirs through theoretical analysis, but there are several uncertain parameters. The conductivity of formation water is necessary parameter in calculation of formation water saturation, but calculating the conductivity of formation water is difficult in shale gas reservoir because of its intricate characterization of pore structure and conductivity. Waxman-Smits model take account for the clay conductivity, but there are several uncertain parameters which are hard to obtained, resuting high error. For instance, the equivalent conductivity of exchange cations (B) and the capacitance of exchange anions (Qv) can not be defined accurately relied on experimental calculation, which causes indefinite influence on results. Thus, we concluded that selecting the improved Indonesia equation is a better method to calculate water saturation. This study provided a comprehensive analysis and an accurate way for water satruartion evaluation in shale reservoir.
Zhang, Weizhong (China University of Petroleum–East China) | Zha, Ming (China University of Petroleum–East China) | Tan, Mingyou (Geophysical Research Institute of Sinopec Shengli Oilfield) | Zhang, Yunyin (Geophysical Research Institute of Sinopec Shengli Oilfield) | Qu, Zhipeng (Geophysical Research Institute of Sinopec Shengli Oilfield) | Ma, Jinfeng (Northwest University)
Accurate assessment of CO2 flooding range and geological storage efficiency is one of the important parts of the CO2 flooding technology. Based on AVO theory, the method of CO2 flooding range monitoring has been studied by selecting the middle and deep formations in G89 field as the research object. The theoretical forward modeling results demonstrate that the reservoirs with injected CO2 show the class ⅠAVO phenomenon, and the gradient of AVO attributes is more sensitive to the changes of pore pressure and CO2 saturation. In the G89 area, the oil reservoirs with injected CO2 show the obvious classⅠ AVO characteristics, while the oil reservoirs without injected CO2 and the cap rocks don’t show the AVO phenomenon. There is certain quantitative relationship between the CO2 injection and the AVO phenomenon, which shows that using gradient attribute can better describe the CO2 flooding range in the middle and deep reservoirs. The quantitative relationship of the P G attributes and CO2 injection quantity is analyzed, which shows that CO2 flooding range can be divided into primary CO2 flooding areas, secondary CO2 flooding areas and areas without CO2 flooding. Based on the identification template, 3 concentric circular flooding bands are predicted which are well relevant to the history of the CO2 injection.
Presentation Date: Tuesday, September 26, 2017
Start Time: 1:50 PM
Presentation Type: ORAL
Yu, Hongyan (Northwest University) | Wang, Zhenliang (Northwest University) | Rezaee, Reza (Curtin University) | Su, Yang (China University of Petroleum) | Tan, Wei (Zhanjiang Branch of CNOOC Ltd.) | Yuan, Yujie (Curtin University) | Zhang, Yihuai (Curtin University) | Xiao, Liang (China University of Geosciences, Beijing) | Liu, Xi (Northwest University, China)
Pore size distribution is of extreme important in the shale gas reservoir evaluation and exploration. However, shale is kind of quit complicated material, and traditional well logs (i.e. acoustic, density and neutron) only measure total porosity, while it cannot quantity the different pore size. Also, the laboratory NMR test is not suitable for filed scale well evaluation. Thus, we used NMR well logs to analyze different pore size distribution, we found that relaxation time <4.5ms is the bound fluid volume, which occupied the most part of the total NMR porosity. Furthermore, we also found that another new cutoff (except T2 cutoff) presence in the T2 distribution figure. We conclude that such new cutoff is for routine free fluid volume and micro fractures volume. Finally, we found that bound fluid volume is the main part for shale gas storage, and the micro fractures did not contribute a lot.
Fully understanding of the shale’s pore size distribution and bound water T2 cutoff are key important for shale gas reservoir (Cao Minh et al. 2012, Odusina and Sigal 2011), especially for the reservoir capacity estimation and hydraulic fracturing (Yu et al. 2016a, Yu et al. 2016b). Shale gas reservoirs are of complex pore types which presented the multi pore system: nano-pores in the organic matter, micro pores between the hard minerals and clay and micro-fractures along the bedding (Sondergeld et al. 2010). However, such pore characteristic especially bound fluid volume and micro-fractures, which directly influence the gas storage and hydraulic fracturing method. Loucks (2012) reported that nanometer- to micrometer-size pores and the natural fractures along with them which is the flow path during gas production (Loucks et al. 2012). Saltt also claimed that microscale and nanoscale pores within organic matter in shales come from SEM is importance to storage (Slatt and O'Brien 2011). The former studies have fully investigated the pore types in the shale, but limited literature to demonstrate the method to quantity them. These different types of pore will show bound fluid volume and free fluid volume from the NMR data Nadia (2016) has reported that the T2 cutoff for shale is 0.24ms-0.26ms, this study data is from NMR experiment (Testamanti and Rezaee 2017), however, it is not suitable for NMR logs (Georgi et al. 1999). Therefore, no significant attention has been to given to evaluate the NMR well logs for pore size distribution in the shale gas reservoir. Thus in this paper, we used NMR log data to get different pore size distribution, and find the T2 cutoff for bound fluid volume.
Liang, X. (PetroChina Zhejiang Oilfield Company) | Jiao, Y. J. (PetroChina Zhejiang Oilfield Company) | Wang, G. C. (PetroChina Zhejiang Oilfield Company) | Zhang, L. (PetroChina Zhejiang Oilfield Company) | Zhang, Y. Q. (PetroChina Zhejiang Oilfield Company) | Liu, C. (PetroChina Zhejiang Oilfield Company) | Wang, Y. (Schlumberger) | Luo, Y. (Schlumberger) | Zhao, X. R. (Schlumberger) | Li, K. X. (Schlumberger) | Zhang, R. (Schlumberger) | Liu, Q. M. (Research Institute of Petroleum Exploration & Development) | Chen, Z. P. (Northwest University)
The performance of shale gas wells varies, and the heterogeneity of shale gas reservoirs requires a good understanding of both reservoir quality (RQ) and completion quality (CQ) of the formation. There are many choices for data acquisition in shale gas horizontal wells, such as wireline conveyance and logging while drilling (LWD). The operator needs to balance between costs, risks, availability of certain measurements and quality of data acquisition.
This paper shows a new logging method using a slim tool string that is designed to be conveyed though the drill string and a hollow bit, and the memory data can be obtained when the tool is tripping out. It shows great advantage in lowering the costs, reducing the risks and saving the rig time, when compared to other logging methods. The quad-combo logging suite incorporates spectral gamma ray, density, compensated neutron, array induction resistivity, and array sonic measurements. An integrated formation evaluation derived from the quad-combo data provides answers to RQ and CQ of the shale gas reservoir, which can be the guide for the hydraulic stimulation.
Case studies are presented from shale gas reservoirs of Huangjinba Block in Zhejiang Oilfield of PetroChina, which is located at the Zhaotong area of Northern Yunnan and Guizhou provinces. The environmental corrected quad-combo data from the new slim logging tool proves to be consistent when compared with the wireline data in the pilot hole and LWD data in the offset horizontal wells, using a heterogeneous analysis method. A robust and comprehensive petrophysical description of lithology, porosity, permeability, total organic carbon content (TOC), gas content, fluid saturation, and tri-axial stress magnitudes is presented. A new understanding of shale gas reservoir heterogeneity is established. Engineered completion design based on the RQ and CQ has demonstrable value in improving perforation efficiency and production performance.
This paper discusses a novel application of a new slim logging tool in formation evaluation of shale gas horizontal wells, and it proves to be efficient and economical. It makes the engineered design for the hydraulic stimulation possible and a success. The workflow can also be applied to other shale gas plays in China.
Chang 3 reservoir in Hua 152 block is located in the Ordos basin, China. The average permeability and porosity is 3.17mD and 14.9%. There exists serious scaling at the oil layer near to bottom hole because of high salinity formation water and incompatible injection water. The scaling process and mechanisms in the layers has been researched by means of a visual real-sand micro-model. The results have shown that: 1) The permeability of the oil layer will reduce by 40% when formation water contacts with injection water twice times at the same place; 2) It is very easy for scaling molecules to crystallize from water phase and scale particles are very small because the pores and throats of the formation rock contain a lot of fine clay and impurity; 3) The scale accumulates in pores and looks like "chicken roost??; 4) The scale inhibitors can reduce scaling, but the higher concentration of scale inhibitors is needed. Scaling in low permeability reservoirs may significantly reduce rock permeability thus affecting the production of oil well. The visual real- sand micro-model is a good method to use in research of scaling mechanisms because of its visualization, using actual rock and ease of construction.