scholarly journals Productivity Influence Factors of Tight Sandstone Gas Reservoir with Water Produced

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Yongchao Xue ◽  
Qingshuang Jin ◽  
Hua Tian
Keyword(s):  
Pressure Gradient ◽  
Relative Permeability ◽  
Gas Flow ◽  
Influence Factors ◽  
Stress Sensitivity ◽  
Consumption Pattern ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Two Phase ◽  
Start Up

Finding ways to accelerate the effective development of tight sandstone gas reservoirs holds great strategic importance in regard to the improvement of consumption pattern of world energy. The pores and throats of the tight sandstone gas reservoir are small with abundant interstitial materials. Moreover, the mechanism of gas flow is highly complex. This paper is based on the research of a typical tight sandstone gas reservoir in Changqing Oilfield. A strong stress sensitivity in tight sandstone gas reservoir is indicated by the results, and it would be strengthened with the water production; at the same time, a rise to start-up pressure gradient would be given by the water producing process. With the increase in driving pressure gradient, the relative permeability of water also increases gradually, while that of gas decreases instead. Following these results, a model of gas-water two-phase flow has been built, keeping stress sensitivity, start-up pressure gradient, and the change of relative permeability in consideration. It is illustrated by the results of calculations that there is a reduction in the duration of plateau production period and the gas recovery factor during this period if the stress sensitivity and start-up pressure gradient are considered. In contrast to the start-up pressure gradient, stress sensitivity holds a greater influence on gas well productivity.

scholarly journals Calculation Model of Relative Permeability in Tight Sandstone Gas Reservoir with Stress Sensitivity

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Jin Yan ◽  
Rongchen Zheng ◽  
Peng Chen ◽  
Shuping Wang ◽  
Yunqing Shi
Keyword(s):  
Relative Permeability ◽  
Pore Radius ◽  
Water Saturation ◽  
Stress Sensitivity ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Two Phase ◽  
Permeability Model ◽  
Irreducible Water Saturation ◽  
Tight Gas Reservoir

During the development of tight gas reservoir, the irreducible water saturation, rock permeability, and relative permeability change with formation pressure, which has a significant impact on well production. Based on capillary bundle model and fractal theory, the irreducible water saturation model, permeability model, and relative permeability model are constructed considering the influence of water film and stress sensitivity at the same time. The accuracy of this model is verified by results of nuclear magnetic experiment and comparison with previous models. The effects of some factors on irreducible water saturation, permeability, and relative permeability curves are discussed. The results show that the stress sensitivity will obviously reduce the formation permeability and increase the irreducible water saturation, and the existence of water film will reduce the permeability of gas phase. The increase of elastic modulus weakens the stress sensitivity of reservoir. The irreducible water saturation increases, and the relative permeability curve changes little with the increase of effective stress. When the minimum pore radius is constant, the ratio of maximum pore radius to minimum pore radius increases, the permeability increases, the irreducible water saturation decreases obviously, and the two-phase flow interval of relative permeability curve increases. When the displacement pressure increases, the irreducible water saturation decreases, and the interval of two-phase flow increases. These models can calculate the irreducible water saturation, permeability and relative permeability curves under any pressure in the development of tight gas reservoir. The findings of this study can help for better understanding of the productivity evaluation and performance prediction of tight sandstone gas reservoirs.

Experiment on Mechanical Properties and Seepage Capability of Deep Tight Sandstone Under True-Triaxial Stresses Environment

2021 ◽  
Author(s):  
Jiaying Li ◽  
Chunyan Qi ◽  
Ye Gu ◽  
Yu Ye ◽  
Jie Zhao
Keyword(s):  
Mechanical Properties ◽  
In Situ Stress ◽  
Stress Sensitivity ◽  
Stress Conditions ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
True Triaxial ◽  
Strain Behavior ◽  
Triaxial Stresses

Abstract The characteristics of seepage capability and rock strain during reservoir depletion are important for reservoir recovery, which would significantly influence production strategy optimization. The Cretaceous deep natural gas reservoirs in Keshen Gasfield in Tarim Basin are mainly buried over 5000 m, featuring with ultra-low permeability, developed natural fractures and complex in-situ stress states. However, there is no comprehensive study on the variation of mechanical properties and seepage capability of this gas reservoir under in-situ stress conditions and most studies on stress-sensitivity are conducted under conventional triaxial or uniaxial stress conditions, which cannot truly represent in-situ stress environment. In this work, Cretaceous tight sandstone in Keshen Gasfield was tested under true-triaxial stresses conditions by an advanced geophysical imaging true-triaxial testing system to study the stress-sensitivity and anisotropy of rock stress-strain behavior, porosity and permeability. Four groups of sandstone samples are prepared as the size of 80mm×80mm×80mm, three of which are artificially fractured with different angle (0°,15°，30°) to simulate hydraulic fracturing. The test results corresponding to different samples are compared to further reveal the influence of the fracture angle on rock mechanical properties and seepage capability. The samples are in elastic strain during reservoir depletion, showing an apparent correlation with fracture angles. The porosity decreases linearly with stress loading, where the decrease rate of effective porosity of fracture samples is significantly higher than that of intact samples. The permeabilities decrease exponentially and show significant anisotropy in different principal stress directions, especially in σH direction. The mechanical properties and seepage capability of deep tight sandstone are successfully tested under true-triaxial stresses conditions in this work, which reveals the stress-sensitivity of anisotropic permeability, porosity and stress-strain behavior during gas production. The testing results proposed in this paper provides an innovative method to analyse rock mechanical and petrophysical properties and has profound significance on exploration and development of tight gas reservoir.

scholarly journals Pressure Performance of Highly Deviated Well in Low Permeability Carbonate Gas Reservoir Using a Composite Model

Energies ◽  
2020 ◽  
Vol 13 (22) ◽  
pp. 5952
Author(s):  
Qinwen Zhang ◽  
Liehui Zhang ◽  
Qiguo Liu ◽  
Youshi Jiang
Keyword(s):  
Pressure Gradient ◽  
Stress Sensitivity ◽  
Composite Model ◽  
Darcy Flow ◽  
Low Permeability ◽  
Threshold Pressure ◽  
Gas Reservoir ◽  
Threshold Pressure Gradient ◽  
Effects Of Stress ◽  
Deviated Wells

It is commonly believed that matrix and natural fractures randomly distribute in carbonate gas reservoirs. In order to increase the effective connected area to the storage space as much as possible, highly deviated wells are widely used for development. Although there have been some studies on the composite model for highly deviated wells, they have not considered the effects of stress sensitivity and threshold pressure gradient in a dual-porosity gas reservoir. In this paper, a semi-analytical composite model for low permeability carbonate gas reservoir was established to study the effect of non-Darcy flow. By employing source function, Fourier transform and the perturbation method, the pressure performance and typical well test curves were obtained. Eight flow regimes were identified, and their characteristics were discussed. As a result, it can be concluded that the effects of stress sensitivity and threshold pressure gradient would make pseudo-pressure and derivative curves rise, which is the characteristic of non-Darcy flow to determine whether there is stress sensitivity or threshold pressure gradient.

scholarly journals Numerical Simulation of Gas-Water Two-Phase Flow in Deep Shale Gas Reservoir Development Based on Mixed Fracture Modeling

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Sidong Fang ◽  
Cheng Dai ◽  
Junsheng Zeng ◽  
Heng Li
Keyword(s):  
Shale Gas ◽  
Horizontal Well ◽  
Stress Sensitivity ◽  
Gas Production ◽  
Gas Reservoir ◽  
Two Phase ◽  
Discrete Fracture Model ◽  
Shale Gas Reservoir ◽  
Discrete Fracture ◽  
The Matrix

Abstract In this paper, the development of a three-dimensional, two-phase fluid flow model (Modified Embedded Discrete Fracture Model) to study flow performances of a fractured horizontal well in deep-marine shale gas is presented. Deep-marine shale gas resources account for nearly 80% in China, which is the decisive resource basis for large-scale shale gas production. The dynamic characteristics of deep shale gas reservoirs are quite different and more complex. This paper uses the embedded discrete fracture model to simulate artificial fractures (main fractures and secondary fractures) and the dual-media model to simulate the mixed fractured media of natural fractures and considers the flow characteristics of partitions (artificial fractures, natural fractures, and matrix). Gas desorption is considered in the matrix. Different degrees of stress sensitivity are considered for natural and artificial fractures. Aiming at accurately simulating the whole production history of horizontal well fracturing, especially the dynamic changes of postfracturing flowback, a postfracturing fluid initialization method based on fracturing construction parameters (fracturing fluid volume and pump stop pressure) is established. The flow of gas and water in the early stage after fracturing is simulated, and the regional phase permeability and capillary force curves are introduced to simulate the process of flowback and production of horizontal wells after fracturing. The influence of early fracture closure on the gas-water flow is characterized by stress sensitivity. A deep shale gas reservoir of Sinopec was selected for the case study. The simulation results show it necessary to consider the effects of fractures and stress sensitivity in the matrix when considering the dynamic change of production during the flowback and production stages. The findings of this study can help for better understanding of the fracture distribution characteristics of shale gas, shale gas production principle, and well EUR prediction, which provide a theoretical basis for the effective development of shale gas horizontal well groups.

A Study of Influential Factors of Advance Water Injection in Extra-Low Permeability Reservoir

2014 ◽  
Vol 487 ◽  
pp. 255-258
Author(s):  
Jin Gang He ◽  
Kao Ping Song ◽  
Jing Yang ◽  
Bao Gang Sun ◽  
Si Chen ◽  
...  
Keyword(s):  
Pressure Gradient ◽  
Early Stage ◽  
Retention Rate ◽  
Water Injection ◽  
Stress Sensitivity ◽  
Influential Factors ◽  
Low Permeability ◽  
Formation Pressure ◽  
Low Permeability Reservoir ◽  
Start Up

This paper study on the permeability, start-up pressure gradient and stress sensitivity of advance water injection in extra-low permeability reservoir in Fuyu Oil layer of Daqing Oilfield. Experimental results show that the reasonable formation pressure level should be at about 120% in the advance water injection experiment, advanced water injection in the the early stage have higher oil production, the water breakthrough, earlier than synchronous water injection has certain inhibitory effect of water cut rise; Under the premise of advance water injection can overcome the start-up pressure, the lower the level of the reservoir permeability, the higher improve recovery efficiency of the proportion; permeability retention rate increase by about 22% with 5×10-3μm2 core and effectively overcome the stress sensitivity of low permeability reservoir damage; Advanced water injection can overcome stress sensitivity and restoring formation pressure, all that influence the start-up pressure gradient, which significantly reduce the start-up pressure gradient.

scholarly journals A productivity prediction method for condensate gas reservoir

2020 ◽  
Vol 213 ◽  
pp. 02001
Author(s):  
Quan Hua Huang ◽  
Hong Jun Ding ◽  
Xing Yu Lin
Keyword(s):  
Pressure Gradient ◽  
Stress Sensitivity ◽  
Water Production ◽  
Gas Wells ◽  
Gas Reservoir ◽  
Gas Well ◽  
Well Productivity ◽  
Inclined Angle ◽  
The Impact ◽  
Starting Pressure Gradient

At present, multiphase flow productivity calculation requires many parameters, and most of them only consider oil and gas two-phase flow, which is complicated and limited. Therefore, a reasonable productivity formula of condensate gas reservoir with producing water is needed. The three-zone model of condensate gas reservoirs is generally applied to the physical model for inferring productivity. On this basis, an improved model is established, which includes that different seepage characteristics are considered for different zones. Moreover, the effects of inclined angle and water production on gas wells are regarded as pseudo-skin factors and additional-skin factors. In addition, Zone I considers the effects of high-speed nonDarcy effect(HSND), starting pressure gradient, stress sensitivity, inclined angle and water production; Zone II is the same way excepting starting pressure gradient and stress sensitivity ; Zone III only considers the effects of inclined angle and water production. As a result, a productivity equation with multiple factors for condensate gas wells is established. Through analysing cases and influences in H gas reservoir X1 well, the HSND, starting pressure gradient, stress sensitivity and water production have a negative impact on gas well productivity, but the inclined angle is opposite. Founded that the starting pressure gradient impacts on productivity is less than the HSND because of the limited radius of Zone I; the impact of the HSND on productivity increases with the decreasing of bottom hole pressure; the impact of water production on gas well productivity is much higher. When the angle is over 60°, the effect of gas

scholarly journals Shale Gas Productivity Predicting Model and Analysis of Influence Factors

2015 ◽  
Vol 8 (1) ◽  
pp. 203-207 ◽  
Author(s):  
Yin Daiyin ◽  
Wang Dongqi ◽  
Zhang Chengli ◽  
Duan Yingjiao
Keyword(s):  
Mathematical Model ◽  
Pressure Gradient ◽  
Shale Gas ◽  
Diffusion Mechanism ◽  
Influence Factors ◽  
Mass Conservation ◽  
Isothermal Adsorption ◽  
Start Up ◽  
Gas Seepage ◽  
The Impact

In order to find the dynamic characteristics of shale gas reservoirs and improve shale gas well production, it is very important to research on shale gas seepage mechanism and production evaluation. Based on the shale gas seepage mechanism, adsorption and desorption characteristics, the diffusion mechanism and mass conservation theory in shale gas development, the dual pore medium shale gas reservoir mathematical model is set up. The mathematical model is built by the finite difference method based on start-up pressure gradient, slippage effect and the isothermal adsorption principle, and then programmed to solve it. Finally, this paper analyzed the impact of Langmuir volume, Langmuir pressure, start-up pressure gradient and slippage coefficient and other factors on shale gas wells production.

scholarly journals The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs

2018 ◽  
Vol 38 ◽  
pp. 01038
Author(s):  
Yu Bei Bei ◽  
Li Hui ◽  
Li Dong Lin
Keyword(s):  
Pressure Gradient ◽  
Low Permeability ◽  
Well Testing ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Gas Field ◽  
Well Spacing ◽  
Start Up ◽  
Starting Pressure Gradient

This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.

Flow Performance Investigation of Rich Gas Pipelines

2008 ◽  
Author(s):  
Daoming Deng ◽  
Jing Gong
Keyword(s):  
Pressure Gradient ◽  
Gas Flow ◽  
Single Phase ◽  
Temperature Drop ◽  
Gas Condensate ◽  
Gas Pipelines ◽  
Liquid Holdup ◽  
Two Phase ◽  
Operating Data ◽  
The Rich

For the rich gas transfer schemes, extraction of NGL from the natural gas is not required in the oil field or gas condensate field, so the gas treatment processes in the field is simplified and the expense from the storage and transportation of NGL is saved, and the gas processing plant could be located far from the field. Rich gas can be pipelined in single phase and/or in two-phase mode. Compared with the gas-condensate ones, the rich gas pipelines behave with lower liquid loading, and are easily controlled operationally. Therefore, the rich gas pipelining modes are increasingly preferred especially in offshore and desert petroleum developments. Prediction of the performances of rich gas flow in pipelines covers a series of calculations for fluid phase behavior, fluid properties, pressure gradient, liquid holdup and temperature drop. In the paper, a hydraulic and thermodynamic model for the analysis of rich gas flow in pipelines with single-phase or two-phase modes is outlined. On account of the low liquid holdup of rich gas two-phase flow in pipelines, the constitutive relation resulting from Ottens et al (2001) correlation is selected. The iterative method to compute the pressure gradient, liquid holdup, and temperature drop of a pipe increment is developed, which shows fast convergence and good stability through case computations. In the end, the performances of non-isothermal rich gas flow in the undulating offshore long-distance pipeline in China is investigated by analyzing the profiles of pressure, temperature, velocity and liquid holdup. The predicted results in this study agree well with the operating data. The theoretical analysis, and comparison of calculated results with operating data and OLGA indicate that the presented model for analyzing rich gas flow behavior in small diameter pipelines looks reasonable.

Sign in / Sign up

Export Citation Format

Share Document