scholarly journals Quantitative evaluation of geological fluid evolution and accumulated mechanism: in case of tight sandstone gas field in central Sichuan Basin

2021 ◽  
Author(s):  
Ya-Hao Huang ◽  
You-Jun Tang ◽  
Mei-Jun Li ◽  
Hai-Tao Hong ◽  
Chang-Jiang Wu ◽  
...  
Keyword(s):  
Sichuan Basin ◽  
Raman Shift ◽  
Burial Depth ◽  
Tight Gas ◽  
Fluid Accumulation ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
Tight Gas Reservoir ◽  
Homogenization Temperatures ◽  
Central Sichuan Basin

AbstractTight gas exploration plays an important part in China’s unconventional energy strategy. The tight gas reservoirs in the Jurassic Shaximiao Formation in the Qiulin and Jinhua Gas Fields of central Sichuan Basin are characterized by shallow burial depths and large reserves. The evolution of the fluid phases is a key element in understanding the accumulation of hydrocarbons in tight gas reservoirs. This study investigates the fluid accumulation mechanisms and the indicators of reservoir properties preservation and degradation in a tight gas reservoir. Based on petrographic observations and micro-Raman spectroscopy, pure CH4 inclusions, pure CO2 inclusions, hybrid CH4–CO2 gas inclusions, and N2-rich gas inclusions were studied in quartz grains. The pressure–volume–temperature–composition properties (PVT-x) of the CH4 and CO2 bearing inclusions were determined using quantitative Raman analysis and thermodynamic models, while the density of pure CO2 inclusions was calculated based on the separation of Fermi diad. Two stages of CO2 fluid accumulation were observed: primary CO2 inclusions, characterized by higher densities (0.874–1.020 g/cm3) and higher homogenization temperatures (> 210 °C) and secondary CO2 inclusions, characterized by lower densities (0.514–0.715 g/cm3) and lower homogenization temperatures: ~ 180–200 °C). CO2 inclusions with abnormally high homogenization temperatures are thought to be the result of deep hydrothermal fluid activity. The pore fluid pressure (44.0–58.5 MPa) calculated from the Raman shift of C–H symmetric stretching (v1) band of methane inclusions is key to understanding the development of overpressure. PT entrapment conditions and simulation of burial history can be used to constrain the timing of paleo-fluid emplacement. Methane accumulated in the late Cretaceous (~ 75–65 Ma), close to the maximum burial depth during the early stages of the Himalayan tectonic event while maximum overpressure occurred at ~ 70 Ma, just before uplift. Later, hydrocarbon gas migrated through the faults and gradually displaced the early emplaced CO2 in the reservoirs accompanied by a continuous decrease in overpressure during and after the Himalayan event, which has led to a decrease in the reservoir sealing capabilities. The continuous release of overpressure to present-day conditions indicates that the tectonic movement after the Himalayan period has led to a decline in reservoir conditions and sealing properties.

Liquid loading in wellbores and its effect on cleanup period and well productivity in tight gas sand reservoirs

2010 ◽  
Vol 50 (1) ◽  
pp. 559
Author(s):  
Hassan Bahrami ◽  
M Reza Rezaee ◽  
Vamegh Rasouli ◽  
Armin Hosseinian
Keyword(s):  
Numerical Simulation ◽  
Gas Production ◽  
Production Performance ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Liquid Loading ◽  
Performance Modelling ◽  
Well Productivity ◽  
Tight Gas Reservoirs ◽  
Tight Gas Reservoir

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore they might not flow gas to surface at optimum rates without advanced production improvement techniques. After well stimulation and fracturing operations, invaded liquids such as filtrate will flow from the reservoir into the wellbore, as gas is produced during well cleanup. In addition, there might be production of condensate with gas. The produced liquids when loaded and re-circulated downhole in wellbores, can significantly reduce the gas production rate and well productivity in tight gas formations. This paper presents assessments of tight gas reservoir productivity issues related to liquid loading in wellbores using numerical simulation of multiphase flow in deviated and horizontal wells. A field example of production logging in a horizontal well is used to verify reliability of the numerical simulation model outputs. Well production performance modelling is also performed to quantitatively evaluate water loading in a typical tight gas well, and test the water unloading techniques that can improve the well productivity. The results indicate the effect of downhole liquid loading on well productivity in tight gas reservoirs. It also shows how well cleanup is sped up with the improved well productivity when downhole circulating liquids are lifted using the proposed methods.

Induced and natural fracture interaction in tight-gas reservoirs

2012 ◽  
Vol 52 (1) ◽  
pp. 611
Author(s):  
Mohammad Rahman ◽  
Sheik Rahman
Keyword(s):  
Hydraulic Fracture ◽  
Development Planning ◽  
Natural Fracture ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Differential Stress ◽  
Tight Gas Reservoirs ◽  
Reservoir Development ◽  
Well Spacing ◽  
Tight Gas Reservoir

This paper investigates the interaction of an induced hydraulic fracture in the presence of a natural fracture and the subsequent propagation of this induced fracture. The developed, fully coupled finite element model integrates a wellbore, an induced hydraulic fracture, a natural fracture, and a reservoir that simulates interaction between the induced and natural fracture. The results of this study have shown that natural fractures can have a profound effect on induced fracture propagation. In most cases, the induced fracture crosses the natural fracture at high angles of approach and high differential stress. At low angles of approach and low differential stress, the induced fracture is more likely to be arrested and/or break out from the far-end side of the natural fracture. It has also been observed that the propagation of the induced fracture is stopped by a large natural fracture at a high angle of approach, when the injection rate remains low. At a low angle of approach, the induced fracture deviates and propagates along the natural fracture. Crossing of the natural fracture and/or arrest by the natural fracture is controlled by the shear strength of the natural fracture, natural fracture orientation, and the in situ stress state of the reservoir. In tight-gas reservoir development, the optimum well spacing and induced hydraulic fracture length are correlated. Therefore, fracturing design should be performed during the initial reservoir development planning phase along with the well spacing design to obtain an optimal depletion strategy. This model has a potential application in the design and optimisation of fracturing design in unconventional reservoirs including tight-gas reservoirs and enhanced geothermal systems.

Thermally Controlled Fluid to Reduce Formation Breakdown Pressures in Tight Gas Reservoirs

2021 ◽  
Author(s):  
Misfer J Almarri ◽  
Murtadha J AlTammar ◽  
Khalid M Alruwaili ◽  
Shuang Zheng
Keyword(s):  
Cost Effective ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Effective Solution ◽  
Gas Reservoirs ◽  
Breakdown Pressure ◽  
Tight Gas Reservoirs ◽  
Tight Gas Reservoir ◽  
Oil Flow ◽  
Reservoir Simulator

Abstract High breakdown pressure is one of the major challenges in deep tight gas reservoirs. In certain wells, achieving breakdown pressures within the completion tubular yield limit is not possible, and those zones may have to be abandoned without fracturing. Using thermally controlled fluid can lower the formation temperature and ultimately reduce the stresses of the tight gas reservoir formation near the wellbore. The objective of this study is to prove numerically that having a cooled near-wellbore region is a feasible and effective solution to reduce the breakdown pressure. An integrated hydraulic fracturing and reservoir simulator that has been developed at the University of Texas at Austin is utilized for this study. The simulator is a non-isothermal, multi-phase black-oil flow in reservoir, fracture, and wellbore domains. It was found that using thermally controlled fluid is effective in reducing breakdown pressure. Bottomhole Pressure (BHP) decreased by up to around 60% when the temperature of the near-wellbore region is reduced by 60 °F under the simulated conditions in this study. Injecting thermally controlled fluid did not only reduce the high breakdown pressure but also improve the hydraulic fractures efficiency and complexity. This technique is novel and has not been studied in depth in the literature. Utilizing thermally controlled fluid can be a cost effective solution to reduce high breakdown pressure in tight gas reservoirs.

Study and Apply of Seepage Law on Multi-Stage Fractured Horizontal Wells in Tight Gas Reservoirs

2014 ◽  
Vol 1030-1032 ◽  
pp. 1394-1398
Author(s):  
Ping Wang ◽  
Zhao Hui Xia ◽  
Wei Ding ◽  
Chao Bin Zhao ◽  
Yun Peng Hu ◽  
...  
Keyword(s):  
Scientific Evidence ◽  
Horizontal Wells ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Tight Gas Reservoirs ◽  
Multi Stage ◽  
Tight Gas Reservoir ◽  
Commercial Value ◽  
Fractured Horizontal Wells

Because the extremely low permeability for tight gas reservoirs, lead to the way to seepage and the shape of production curves different with the convention reservoirs; this will increase the difficulty to develop the tight gas reservoirs; on the other hand, the convention exploit cannot recover the tight gas with commercial value, with this problem, the main solution is the technology of multi-stage fractured horizontal wells, the fractured can provide the channel for gas to transport, the horizontal wells can increase the seepage area of tight gas, it’s the guarantee to get the commercial value. But, at present, the study on the tight was dependent on the method of convention gas reservoirs, the production curve get from this method also the same with the convention gas reservoirs, in order to close with the really exploitation of tight gas reservoirs and provide the more accurate scientific evidence, we must study based on the feature of tight gas reservoir, in this situation, we can get the suitable production curves for tight gas reservoirs. This paper based on the feature of tight gas reservoir, combine with the model of multi-stage fractured horizontal wells, and get the production equation of tight gas, combine with the yield of discard time, we can get the type curve, and then get the C level reserves of region.

scholarly journals Analysis on the effect of different fracture geometries on the productivity of tight gas reservoirs

2020 ◽  
Vol 16 (2) ◽  
pp. 201-211
Author(s):  
Temoor Muther ◽  
Adnan Aftab Nizamani ◽  
Abdul Razak Ismail
Keyword(s):  
Hydraulic Fracture ◽  
Constant Width ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Fracture Geometry ◽  
Tight Gas Reservoirs ◽  
Constant Height ◽  
Tight Gas Reservoir ◽  
Half Length

Tight gas reservoirs are unconventional reservoir assets which have been the focus of major research in the petroleum industry owing to the global decline in conventional reservoirs. They are widely unlocked by creating hydraulic fractures in the formation to increase the flow capacity and productivity. The objective of this paper is to analyze different fracture geometries and their effect on tight gas production. The reservoir simulation model of the tight gas reservoir has been built with single porosity approach. A single vertical well with a single stage fracture has been used in the model to predict the behavior of fracture geometry. The major parameters of fracture geometry studied are fracture half-length, fracture width, and fracture height. Four sensitivities are run over different fracture geometry that is constant height and constant width, constant height and changing width, changing height and constant width, and changing height and changing width, while increasing the fracture half-length from 100 ft to 500 ft in each case. Sensitivity analysis exhibited that keeping the hydraulic fracture at constant height and constant width while increasing the fracture half-length resulted in enhanced tight gas productivity i.e. 11.63%, 14.14%, 16.06%, 17.48%, and 18.89% at hydraulic fracture half-lengths of 100 ft, 200 ft, 300 ft, 400 ft, and 500 ft, respectively, compared to other types of fracture geometry.

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