scholarly journals Optimal Inflow Performance Relationship Equation for Horizontal and Deviated Wells in Low-Permeability Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Liqiang Wang ◽  
Zhengke Li ◽  
Mingji Shao ◽  
Yinghuai Cui ◽  
Wenbo Jing ◽  
...  
Keyword(s):  
Pressure Gradient ◽  
Superposition Principle ◽  
Horizontal Wells ◽  
Low Permeability ◽  
Flow Function ◽  
Low Permeability Reservoir ◽  
Inflow Performance ◽  
Low Permeability Reservoirs ◽  
Performance Equation ◽  
Deviated Wells

After Vogel proposed a dimensionless inflow performance equation, with the rise of the horizontal well production mode, a large number of inflow performance relationship (IPR) equations have emerged. In the productivity analysis of deviated and horizontal wells, the IPR equation proposed by Cheng is mainly used. However, it is still unclear whether these inflow performance models (such as the Cheng, Klins-Majcher, Bendakhlia-Aziz, and Wiggins-Russell-Jennings types) are suitable for productivity evaluations of horizontal and deviated wells in low-permeability reservoirs. In-depth comparisons and analyses have not been carried out, which hinders improvements in the accuracy of the productivity evaluations of horizontal wells in low-permeability reservoirs. In this study, exploratory work was conducted in two areas. First, the linear flow function relationship used in previous studies was improved. Based on the experimental pressure-volume-temperature results, a power exponential flow function model was established according to different intervals greater or less than the bubble point pressure, which was introduced into the subsequent derivation of the inflow performance equation. Second, given the particularity of low-permeability reservoir percolation, considering that the reservoir is a deformation medium, and because of the existence of a threshold pressure gradient in fluid flow, the relationship between permeability and pressure was changed. The starting pressure gradient was introduced into the subsequent establishment of the inflow performance equation. Based on the above two aspects of this work, the dimensionless IPR of single-phase and oil-gas two-phase horizontal wells in a deformed medium reservoir was established by using the equivalent seepage resistance method and complex potential superposition principle. Furthermore, through regression and error analyses of the standard inflow performance data, the correlation coefficients and error distributions of six types of IPR equations applicable to deviated and horizontal wells at different inclination angles were compared. The results show that the IPR equation established in this study features good stability and accuracy and that it can fully reflect the particularity of low-permeability reservoir seepage. It provides the best choice of the IPR between inclined wells and horizontal wells in low-permeability reservoirs. The other types of IPR equations are the Wiggins-Russell-Jennings, Klins-Majcher, Vogel, Fetkovich, Bendakhlia-Aziz, and Harrison equations, listed here in order from good to poor in accuracy.

A New Methodology for Calculating Wellbore Shut-in Pressure in Numerical Reservoir Simulations.

2021 ◽  
Author(s):  
Babatope Kayode ◽  
Mahmoud Jamiolahmady
Keyword(s):  
Superposition Principle ◽  
Mathematical Formulation ◽  
Grid Size ◽  
Spatial Distance ◽  
Time Shift ◽  
Low Permeability ◽  
Pressure Data ◽  
Equivalent Radius ◽  
Wellbore Pressure ◽  
Low Permeability Reservoirs

Abstract In low permeability reservoirs, the pressure transient response of the build-up takes a long time to stabilize. During the history matching process, the observed non-stabilized build-up pressure cannot be compared to simulated well block pressure (WBP). This challenge arises because most reservoir simulators convert the WBP of flowing wells to wellbore pressure using Peaceman’s equation, but do not perform this conversion for build-up pressure data. Such conversion is particularly important for low permeability reservoirs. This paper discusses a new method to calculate the wellbore pressure of shut-in wells and highlights its benefits. A full superposition equation for analytical wellbore-pressure, without the usual logarithmic approximation of Ei function, is the basis of the mathematical formulation proposed here. A modified equivalent radius concept together with the superposition principle are used to arrive at an expression to calculate numerical wellbore pressure from simulated WBP. To verify the validity of the approach, the calculated numerical wellbore pressure data is compared with analytical wellbore pressure build-up data described by the Horner function. The results show that numerical wellbore pressure is in better agreement with the non-stabilized observed pressure data than WBP. This is because WBP is an average pressure over a spatial distance in which theoretical pressure varies as a logarithmic function of distance. Therefore, when the grid size is large and spatial pressure gradient is significant (as the case in low permeability reservoirs), simulated shut-in WBP may be very different from observed shut-in wellbore pressure measured by a downhole gauge. Our results demonstrate that this difference increases with increasing grid size. If, during numerical well testing, numerical wellbore pressure is used for the log-log pressure derivative plot instead of WBP, the early distortions of infinite acting radial flow (IARF) stabilization, which has been observed by some investigators is eliminated. In summary, the presented methodology to calculate shut-in wellbore pressure is practically attractive to complement existing simulator capabilities for relating wellbore pressure to well block pressure. The use of numerical wellbore pressure instead of WBP, which is currently used, eliminates the need to apply the time-shift proposed by some investigators to correct IARF signature deviation, and observe the true flow regime.

Threshold Pressure Gradient in Ultra-low Permeability Reservoirs

2008 ◽  
Vol 26 (9) ◽  
pp. 1024-1035 ◽  
Author(s):  
F. Hao ◽  
L. S. Cheng ◽  
O. Hassan ◽  
J. Hou ◽  
C. Z. Liu ◽  
...  
Keyword(s):  
Pressure Gradient ◽  
Low Permeability ◽  
Threshold Pressure ◽  
Threshold Pressure Gradient ◽  
Low Permeability Reservoirs

scholarly journals The experimental investigation of the HPAM/phenolic resin deep profile system in fractured low-permeability reservoirs

2021 ◽  
Vol 252 ◽  
pp. 02078
Author(s):  
Wei Zhou ◽  
Daiyin Yin ◽  
Yazhou Zhou
Keyword(s):  
Control System ◽  
Control Systems ◽  
Phenolic Resin ◽  
Good Effect ◽  
Low Permeability ◽  
Low Permeability Reservoir ◽  
Shearing Rate ◽  
Profile Control ◽  
Deep Profile ◽  
Low Permeability Reservoirs

The problem of injected water channeling along fractures exists in the process of water injection in fractured low permeability reservoir, aimed at this problem, deep profile control technology applies to plug fractures to improve the recovery of low permeability reservoir. In this paper, partially hydrolyzed polyacrylamide (HPAM) is used as water-plugging/profile-modifying agent and phenolic resin as crosslinker agent. Several profile control systems are tested to find the one which is suitable for fractured low permeability reservoirs. The performances of profile control systems are evaluated, and effects of formation water salinity, that of shearing rate and that of temperature on the performance are studied. Finally, in order to study effects of this profile control system on displacing oil, flowability experiment and core displacement experiment are applied. It shows that with the increase of salinty of prepared water and the increase of the shearing rate, the viscosity of this system decreases. With the increase of temperature, the gelling time shortens, the viscosity increases, but the stability weekens. This kind of profile control system has a good effect on plugging fractures of low permeability cores. After water flooding, this kind of profile control system is injected into cores, the recovery ratio can increase 3.5%. So the profile control system composed of HPAM/ phenolic resin can apply to deep profile control in fractured low permeability reservoir to enhance oil recovery.

scholarly journals Study on the Influential Factors of CO2 Storage in Low Permeability Reservoir

Energies ◽  
2022 ◽  
Vol 15 (1) ◽  
pp. 344
Author(s):  
Ping Yue ◽  
Rujie Zhang ◽  
James J. Sheng ◽  
Gaoming Yu ◽  
Feng Liu
Keyword(s):  
Carbon Dioxide ◽  
Co2 Storage ◽  
Ordos Basin ◽  
Influential Factors ◽  
Low Permeability ◽  
Geological Storage ◽  
Co2 Geological Storage ◽  
Low Permeability Reservoir ◽  
Low Permeability Reservoirs ◽  
Breakthrough Pressure

As the demands of tight-oil Enhanced Oil Recovery (EOR) and the controlling of anthropogenic carbon emission have become global challenges, Carbon Capture Utilization and Sequestration (CCUS) has been recognized as an effective solution to resolve both needs. However, the influential factors of carbon dioxide (CO2) geological storage in low permeability reservoirs have not been fully studied. Based on core samples from the Huang-3 area of the Ordos Basin, the feasibility and influential factors of geological CO2 sequestration in the Huang-3 area are analyzed through caprock breakthrough tests and a CO2 storage factor experiment. The results indicate that capillary trapping is the key mechanism of the sealing effect by the caprock. With the increase of caprock permeability, the breakthrough pressure and pressure difference decreased rapidly. A good exponential relationship between caprock breakthrough pressure and permeability can be summarized. The minimum breakthrough pressure of CO2 in the caprock of the Huang-3 area is 22 MPa, and the breakthrough pressure gradient is greater than 100 MPa/m. Huang-3 area is suitable for the geological sequestration of CO2, and the risk of CO2 breakthrough in the caprock is small. At the same storage percentage, the recovery factor of crude oil in larger permeability core is higher, and the storage percentage decreases with the increase of recovery factor. It turned out that a low permeability reservoir is easier to store CO2, and the storage percentage of carbon dioxide in the miscible phase is greater than that in the immiscible phase. This study can provide empirical reference for caprock selection and safety evaluation of CO2 geological storage in low permeability reservoirs within Ordos Basin.

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