scholarly journals Progress on Modeling of Dynamic Productivity of Fractured Gas Condensate Reservoir Based on a Fluid-Solid Coupling Method

2021 ◽  
Vol 9 ◽  
Author(s):  
Shuai Wang ◽  
Xianhong Tan ◽  
Yang Xia ◽  
Bo Tian ◽  
Bin Liang
Keyword(s):  
Pressure Gradient ◽  
Large Scale ◽  
Eastern China ◽  
Gas Condensate ◽  
Dew Point ◽  
Coupling Method ◽  
Low Permeability ◽  
Gas Field ◽  
Condensate Reservoir ◽  
Starting Pressure Gradient

Bozhong 19-6 gas field is the first discovered large-scale gas condensate field in eastern China, which is also one of the largest metamorphic rock gas condensate fields in the world. It is a buried hill type, low permeability reservoir, with ultra-high condensate content where the fluid is nearly at its dew point pressure. No similar experience with such reservoirs have previously been reported in the context of gas field development in China and step-by-step progresses is been made to characterize this reservoir. Overall, documentation concerning this type of reservoir is rarely seen worldwide. This paper includes key successful results from multiple perspectives including experiments correlations, numerical modeling and the significance of incorporating certain details. Based on a fluid-solid coupling method, the simulations consider several factors including the fracture distribution, low permeability, medium deformation, and condensate characteristics, as well as their effects on the gas productivity. In the laboratory experiments, the stress sensitivity of the rock was tested using representative core samples. Here, experiment-based correlations of the starting pressure gradient of the gas condensate reservoir are proposed. The starting pressure gradient of different fluid types, such as black oil and gas condensate are highlighted as accurately simulating the reservoir. As a result, the numerical model to predict the dynamic productivity of a single well was successfully established considering all those factors. This paper can serve as a reference for studying other studies of metamorphic, fractured gas condensate reservoirs.

Influence of Back Pressure on Testing Starting Pressure Gradient in Low Permeability Gas Field

2012 ◽  
Vol 524-527 ◽  
pp. 1460-1464
Author(s):  
Jian Yan ◽  
Xiao Juan Liu
Keyword(s):  
Pressure Gradient ◽  
Gas Flow ◽  
Water Saturation ◽  
Flow Characteristics ◽  
Low Permeability ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Outlet Pressure ◽  
Test Conditions ◽  
Starting Pressure Gradient

For the existence of formation water, the capillary force increases when the gas flow in the cores, so the flow may display starting pressure gradient. However, during the lab testing, sometimes it is found that the starting pressure gradient changes in different test conditions: when the outlet pressure is atmosphere, only the water saturation reaches critical value (Sw)c, the quasi starting pressure exists; but when the outlet pressure is not atmosphere; it is easy to find the quasi staring pressure in the same water saturation. And the quasi starting pressure under the later condition is larger than that in former condition. It is also found that the quasi starting pressures are both power function to the ratio of core coefficient and water saturation. The experimental results provide some theoretical references for recognizing the flow characteristics in low permeability gas reservoirs.

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.

A Case History of Nitrogen Injection Monitoring in Rich Recycled Gas Condensate Reservoir, Onshore Gas Field, Abu Dhabi, UAE

2015 ◽  
Author(s):  
Hamza M. Hamza ◽  
Mahmood Al Suwaidi ◽  
Omar Al Jeelani ◽  
Arafat Al Yafei ◽  
Mahmoud Basioni ◽  
...  
Keyword(s):  
Case History ◽  
Gas Condensate ◽  
Abu Dhabi ◽  
Gas Field ◽  
Nitrogen Injection ◽  
Condensate Reservoir ◽  
History Of

scholarly journals PREDICTION OF CONDENSATE BANKING WITH RELATIVE PERMEABILITY TO OIL – GAS AND SATURATION IN A GAS CONDENSATE RESERVOIR

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Relative Permeability ◽  
Comparative Method ◽  
Economic Value ◽  
Gas Condensate ◽  
Dew Point ◽  
Efficient Production ◽  
Retrograde Condensation ◽  
Condensate Reservoir ◽  
Compositional Simulator ◽  
Point Pressure

Gas condensate fields are quite lucrative fields because of the highly economic value of condensates. However, the development of these fields is often difficult due to retrograde condensation resulting to condensate banking in the immediate vicinity of the wellbore. In many cases, adequate characterization and prediction of condensate banks are often difficult leading to poor technical decisions in the management of such fields. This study will present a simulation performed with Eclipse300 compositional simulator on a gas condensate reservoir with three case study wells- a gas injector (INJ1) and two producers (PROD1 and PROD2) to predict condensate banking. Rock and fluid properties at laboratory condition were simulated to reservoir conditions and a comparative method of analysis was used to efficiently diagnose the presence of condensate banks in the affected grid-blocks. Relative Permeability to Condensate and gas and saturation curves shows condensate banks region. The result shows that PROD2 was greatly affected by condensate banking while PROD1 remained unaffected during the investigation. Other factors were analyzed and the results reveal that the nature and composition of condensates can significantly affect condensate banking in the immediate vicinity of the wellbore. Also, it was observed that efficient production from condensate reservoir requires the pressure to be kept above dew point pressure so as to minimize the effect and the tendency of retrograde condensation. Keywords: Condensate Banking, Phase Production, Relative Permeability, Relative Saturation, Retrograde Condensation

Condensate Recovery from Tight Gas-Condensate Reservoirs using a new Method Based on a Gas-Based Chemical

2021 ◽  
Author(s):  
Abdulelah Nasieef ◽  
Mahmoud Jamiolahmady ◽  
Hosein Doryanidaryuni ◽  
Alejandro Restrepo ◽  
Alonso Ocampo ◽  
...  
Keyword(s):  
Enhanced Recovery ◽  
Gas Condensate ◽  
Dew Point ◽  
New Method ◽  
Reservoir Rock ◽  
Production Data ◽  
Low Permeability ◽  
Recovery Method ◽  
Gas Condensate Reservoirs ◽  
Hydrocarbon Gas

Abstract Recovery from gas condensate reservoirs, when the pressure is below dew point pressure (Pdew), is adversely affected by the accumulation of condensate in the near wellbore region. The mitigation of the near-well bore condensate banking is the main purpose of any enhanced recovery method implemented in gas condensate reservoirs. In this work, a new method was tested to improve condensate recovery by using a chemical that was delivered using hydrocarbon gas as a carrier into a very low permeability and very low porosity reservoir rock. Chemicals are typically injected using liquid carrier solvents. The use of hydrocarbon gas as the carrier provides a remedy to mitigate condensate banking in very low permeability cores by minimizing complications associated with low injectivity and back flow clean-up process requirements of an injected liquid. The chemical potential was evaluated by recording production data from unsteady-state coreflood experiments. The injection of the chemical with equilibrated gas resulted in condensate saturation to decrease from 19.6% to 6.5%. This decrease was not instantaneous and took some time to occur indicating that the chemical needs time to interact with the resident fluid and rock. The benefit of the method, at the field scale, was also estimated by performing single-well numerical simulations that use relative permeability (kr) data which history matched the measured coreflood production data. The results of these preliminary simulations also showed improved recovery of gas and condensate compared to pure depletion, without chemical, by around 40% for the cases considered.

Energy Control in the Depletion of Gas Condensate Reservoirs with Different Permeabilities

2012 ◽  
Vol 616-618 ◽  
pp. 796-803
Author(s):  
Wen Ge Hu ◽  
Xiang Fang Li ◽  
Xin Zhou Yang ◽  
Ke Liu Wu ◽  
Jun Tai Shi
Keyword(s):  
Pressure Drop ◽  
Oil Production ◽  
Pressure Control ◽  
Gas Condensate ◽  
Dew Point ◽  
Low Permeability ◽  
Energy Control ◽  
Obvious Effect ◽  
Gas Condensate Reservoirs ◽  
Condensate Blocking

Energy control (i. e. pressure control) has an obvious effect on development effect in the depletion of gas condensate reservoir. Phase change behavior and characteristics of the relative pemeability in gas condensate reservoirs were displayed in this paper, then pressure and condensate distribution were showed through reservoir simulation. Finally, the influence of the pressure drop on condensate distribution and condensate oil production in gas condensate reservoirs with different permeabilities was studied. Results show that: First, in high / moderate permeability gas condensate reservoirs, the pressure and the condensate blocking will extend to further reservoir, while the pressure and condensate just appear in the vicinity of wellbore in low permeability gas condensate reservoirs. Second, the influence of pressure drop on condensate distribution in high permeability gas condensate reservoirs is obvious, the condensate blocking extends with the increasing of the pressure drop, and condensate extent can be controlled by optimizing a rational pressure drop, while the influence is inconspicuous in low permeability gas condensate reservoirs. Third, the influence of pressure drop on condensate oil production in high / moderate permeability gas condensate reservoirs is conspicuous, a rational pressure drop exists, while the influence is indistinct in low permeability or tight gas condensate reservoirs, before the retrograde condensation, a low pressure drop should be adopted in a long term until the bottom hole flowing pressure drops below the dew point pressure, when the condensate blocking forms, well stimulation is advised before developing by pressure control.

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