Transient Behavior of Water-Oil Interface in an Upward Flow in Porous Media

Ould-Amer, Yacine; Chikh, Salah

doi:10.1615/jpormedia.v6.i2.20

Cited by 11 publications

(5 citation statements)

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“…Unlike other gas reservoirs, fractured gas reservoir is characterized by extremely low permeability in matrix, well-developed fractures, strong heterogeneity, and active edge and bottom water (Jiang et al., 2017; Li et al., 2017). During the development of gas reservoirs, water will flow to gas well along the fracture channel owing to the complex fractures existing in reservoir media, and gas production will greatly reduce and even stop with the part gas separated by water, which will give rise to great difficulties in the development of gas reservoirs (Hu et al., 2014; Ould-Amer and Chikh, 2003; Ould-Amer et al., 2004).…”

Section: Introductionmentioning

confidence: 99%

Study on the effects of fracture on permeability with pore-fracture network model

Jiao

et al. 2018

Energy Exploration & Exploitation

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Reservoir quality and productivity of fractured gas reservoirs depend heavily on the degree of fracture development. The fracture evaluation of such reservoir media is the key to quantify reservoir characterization for the purposes such as well drilling and completion as well as development and simulation of fractured gas reservoirs. In this study, a pore-fracture network model was constructed to understand the effects of fracture on permeability in the reservoir media. The microstructure parameters of fractures including fracture length, fracture density, fracture number, and fracture radius were analyzed. Then two modes and effects of matrix and fracture network control were discussed. The results indicate that the network permeability in the fractured reservoir media will increase linearly with fracture length, fracture density, fracture number, and fracture radius. When the fracture radius exceeds 80 mm, the fracture radius has a little effect on network permeability. Within the fracture density less than 0.55, it belongs to the matrix control mode, while the fracture network control mode is dominant in the fracture density exceeding 0.55. The network permeability in the matrix and fracture network control modes is affected by fracture density and the ratio of fracture radius to pore radius. There is a great change in the critical density for the matrix network control compared with the fracture network control. This work can provide a better understanding of the relationship between matrix and fractures, and the effects of fracture on permeability so as to evaluate the fluid flow in the fractured reservoir media.

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Section: Introductionmentioning

confidence: 99%

Study on the effects of fracture on permeability with pore-fracture network model

Jiao

et al. 2018

Energy Exploration & Exploitation

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“…Oil fields are typically operated at flow rates greater than the critical flow rates that are determined using common correlations; otherwise, the field would be uneconomic. If a well produces above its critical rate, the water cone will breakthrough after a certain time period known as “breakthrough time.” There are some correlations in the literature such as Yang and Wattenbarger and Rhecam et al to determine this specific time . Two of the most common methods used are the Sobocinski‐Cornelius and Bournazel‐Jeanson techniques.…”

Section: Introductionmentioning

confidence: 99%

Estimation of breakthrough time for water coning in fractured systems: Experimental study and connectionist modeling

et al. 2014

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in Wiley Online Library (wileyonlinelibrary.com) Water coning in petroleum reservoirs leads to lower well productivity and higher operational costs. Adequate knowledge of coning phenomena and breakthrough time is essential to overcome this issue. A series of experiments using fractured porous media models were conducted to investigate the effects of production process and pore structure characteristics on water coning. In addition, a hybrid artificial neural network (ANN) with particle swarm optimization (PSO) algorithm was applied to predict breakthrough time of water coning as a function of production rate and physical model properties. Data from the literature combined with experimental data generated in this study were used to develop and verify the ANN-PSO model. A good correlation was found between the predicted and real data sets having an absolute maximum error percentage less than 9%. The developed ANN-PSO model is able to estimate breakthrough time and critical production rate with higher accuracy compared to the conventional or back propagation (BP) ANN (ANN-BP) and common correlations. The presence of vertical fractures was found to accelerate considerably the water coning phenomena during oil production. Results of this study using combined data suggest the potential application of ANN-PSO in predicting the water breakthrough time and critical production rate that are critical in designing and evaluating production strategies for naturally fractured reservoirs.

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“…Many investigators have reported both experimental and theoretical results for the effects of gravity and viscosity on the stability of miscible displacements (Hill, 1952;Perrine, 1961 and1963;Dumore, 1964;Tan andHomsy, 1987 and1988;Homsy, 1987;Hickernell and Yortsos, 1986;Manickam and Homsy, 1995) and immiscible displacements (Engelberts and Klinkenberg, 1951;Chuoke et al, 1959;Terwilliger et al, 1951;Sheldon et al, 1959;Fayers and Sheldon, 1959;Raghavan and Marsden, 1971;Nayfeh, 1972;Peters and Flock, 1981;Glass and Yarrington, 1996;Stephen et al, 2001;Meheust et al, 2002;Ould-Amer and Chikh, 2003;Riaz and Tchelepi, 2004). Many investigators have reported both experimental and theoretical results for the effects of gravity and viscosity on the stability of miscible displacements (Hill, 1952;Perrine, 1961 and1963;Dumore, 1964;Tan andHomsy, 1987 and1988;Homsy, 1987;Hickernell and Yortsos, 1986;Manickam and Homsy, 1995) and immiscible displacements (Engelberts and Klinkenberg, 1951;Chuoke et al, 1959;Terwilliger et al, 1951;Sheldon et al, 1959;Fayers and Sheldon, 1959;Raghavan and Marsden, 1971;…”

Section: Introductionmentioning

confidence: 99%

Stability Investigation of Low-Tension Surfactant Floods

Pope

Weerasooriya

2013

SPE International Symposium on Oilfield Chemistry

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Classical stability theory can be used to estimate the critical velocity of a miscible flood stabilized by gravity forces. However, stability theory for an ultra-low interfacial tension (IFT) surfactant displacement is not well developed or validated. In this paper, a method for predicting the critical velocity for a surfactant flood is proposed taking into account the microemulsion phase. Vertical upward surfactant displacement experiments were performed and compared with stability theory. The proposed theory and experimental results offer new insight into the behavior of surfactant floods stabilized by gravity forces.

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Transient Behavior of Water-Oil Interface in an Upward Flow in Porous Media

Cited by 11 publications

References 0 publications

Study on the effects of fracture on permeability with pore-fracture network model

Study on the effects of fracture on permeability with pore-fracture network model

Estimation of breakthrough time for water coning in fractured systems: Experimental study and connectionist modeling

Stability Investigation of Low-Tension Surfactant Floods

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