Simulation Experimental Study on Aeolotropism Affects the Recovery of Low Permeable Sub Layer Reservoir

2015 ◽  
Vol 733 ◽  
pp. 174-177
Author(s):  
Xin Yuan Zhao ◽  
Yi Kun Liu ◽  
Feng Jiao Wang ◽  
Ru Ya Chen ◽  
Jin Ming Wang
Keyword(s):  
Recovery Rate ◽  
Water Flooding ◽  
Displacement Rate ◽  
Low Permeability ◽  
High Permeability ◽  
Water Displacement ◽  
Sand Body ◽  
Rock Cores ◽  
Layer Analysis ◽  
The Impact

In order to reveal the impact of reservoir heterogeneity on its recovery and by taking the interlayer heterogeneous and inner layer sand superimposition model (two forms of complexity situation) into account, water flooding experiments have been conducted on parallel connected rock cores, which are selected and artificially casted cores with different permeability, at different injection rates. Experimental results suggested that water displacement recovery is kept decreasing with the increasing of interlayer heterogeneity. when the interlayer permeability ratio (ratio of high permeability versus low permeability) is at about 6.5 and water displacement rate is set at 0.5ml/min, 1ml/min, 1.5ml/min, 2ml/min, respectively, the water flooding experiments indicated that the low permeability recovery increased significantly and low permeability layer became main producer with the increasing of water displacement rate, on the opposite, the high permeability recovery showed no little big change. Laboratory experiments on the model of layer sand body superimposition revealed that the recovery rate of FTRLPTPL model is about 5%~10% higher than that of FTPLPTRL model.(FTRLPTPL is briefed from that flooding from the thick and rich in oil layer and produced from the thin and poor in oil layer. FTPLPTRL is briefed from that flooding from the thin and poor in oil layer and produced from the thick and rich in oil layer.) Analysis on the experiments in different reservoir inner situation told us that recovery enhancement of low permeability layer can play a significant role in increasing the overall recovery rate.

Evaporative Cleanup of Water Blocks in Gas Wells

SPE Journal ◽  
2007 ◽  
Vol 12 (02) ◽  
pp. 209-216 ◽  
Author(s):  
Jagannathan Mahadevan ◽  
Mukul Mani Sharma ◽  
Yannis C. Yortsos
Keyword(s):  
Capillary Pressure ◽  
Damage Zone ◽  
Low Permeability ◽  
Tight Gas ◽  
High Permeability ◽  
Water Displacement ◽  
Gas Wells ◽  
Well Productivity ◽  
Gas Expansion ◽  
The Impact

Summary The flow of a gas toward the wellbore of a production well will result in the evaporative cleanup of water blocks, if the latter exist. This occurs primarily due to gas expansion. This paper presents for the first time a model to calculate the rate at which such water blocks are removed, for either fractured or unfractured gas wells. The model allows us to compute the impact of evaporative cleaning on well productivity. The removal of water first occurs by gas displacement. Evaporative cleanup is caused by gas expansion. The resulting saturation profile is qualitatively different for low- or high-permeability rocks. As a consequence, the increase in gas relative permeability, or the well productivity, with time can vary depending on the rock permeability and the well drawdown. High-permeability (e.g. fractured) rocks clean up significantly faster. By contrast, low-permeability unfractured wells may require a very long time to clean up. Large pressure drawdowns, as well as the use of more volatile fluids, such as alcohols, also result in faster cleanup. A distinctive feature of the work presented is that the model equations are formulated and solved completely without the assumption of skin factors for the damage zone. Thus, the prediction of cleanup rates can be made more accurately. Introduction Water blocks in low-permeability rocks clean up much more slowly than those of higher permeability because of the smaller pore sizes and the consequent higher capillary entry pressures (Mahadevan et al. 2003). In particular, water blocks in tight gas sands are not easily cleaned up, especially in cases where the reservoir pressures are too low to initiate flow. Past studies (Tannich 1975; Holditch 1979, Parekh and Sharma 2004) have reported the effect of water displacement by gas in the cleanup of water blocks in gas wells. They showed that when the drawdown in the gas well is significantly larger than the capillary pressure, cleanup is faster. However, in cases where the drawdown becomes comparable to the capillary pressure, as is the case in depleted tight gas reservoirs, displacement alone is not sufficient to remove water from the near-wellbore region. Subsequent water removal occurs by evaporation. The flow of a fully saturated compressible gas through a water-saturated porous rock induces evaporation. Roughly, this is because the volume of the gas, and hence its capacity for water content, increases as pressure declines. In past studies, the impact of evaporation caused by the flow of gas has been neglected. The focus of this paper is precisely on this regime in gas wells, in which the drawdown is comparable in magnitude to the capillary entry pressure, and cleanup of water blocks is by evaporation.

scholarly journals Strategy of water-flooding enhancement for low-permeable polymictic reservoirs

2020 ◽  
pp. 1-11
Author(s):  
Aleksandra Palyanitsina ◽  
Dmitry Tananykhin ◽  
Riazi Masoud
Keyword(s):  
Western Siberia ◽  
Oil Fields ◽  
Water Flooding ◽  
Optimal Time ◽  
Low Permeability ◽  
Low Salinity ◽  
Stage Of Development ◽  
Low Salinity Waterflooding ◽  
The Impact ◽  
Artificial Water

This article pays attention to the issues of increasing the efficiency of the development of oil fields with low-permeable polymictic reservoirs. It is possible to increase the efficiency of this process by improving the technology of their artificial water-flooding. This goal is being realized by identifying the features of the development of low-permeable polymictic reservoirs of fields in Western Siberia and creating a strategy to improve the technology of artificial waterflooding, taking into account the impact on the surface molecular properties of the reservoir system by the stages of their development. The developed strategy was substantiated in stages using hydrodynamic modeling. Also, an assessment was made of the effectiveness of the implementation of low-salinity waterflooding at the late stage of development of low-permeability polymictic reservoirs, the optimal time for changing the waterflooding agent from formation water to fresh water was determined.  

scholarly journals Enhanced oil recovery ability of branched preformed particle gel in heterogeneous reservoirs

2018 ◽  
Vol 73 ◽  
pp. 65 ◽  
Author(s):  
Long Yu ◽  
Qian Sang ◽  
Mingzhe Dong
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Low Permeability ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Reservoir Heterogeneity ◽  
Heterogeneous Reservoirs ◽  
Preformed Particle Gel ◽  
Profile Control

Reservoir heterogeneity is the main cause of high water production and low oil recovery in oilfields. Extreme heterogeneity results in a serious fingering phenomenon of the displacing fluid in high permeability channels. To enhance total oil recovery, the selective plugging of high permeability zones and the resulting improvement of sweep efficiency of the displacing fluids in low permeability areas are important. Recently, a Branched Preformed Particle Gel (B-PPG) was developed to improve reservoir heterogeneity and enhance oil recovery. In this work, conformance control performance and Enhanced Oil Recovery (EOR) ability of B-PPG in heterogeneous reservoirs were systematically investigated, using heterogeneous dual sandpack flooding experiments. The results show that B-PPG can effectively plug the high permeability sandpacks and cause displacing fluid to divert to the low permeability sandpacks. The water injection profile could be significantly improved by B-PPG treatment. B-PPG exhibits good performance in profile control when the high/low permeability ratio of the heterogeneous dual sandpacks is less than 7 and the injected B-PPG slug size is between 0.25 and 1.0 PV. The oil recovery increment enhanced by B-PPG after initial water flooding increases with the increase in temperature, sandpack heterogeneity and injected B-PPG slug size, and it decreases slightly with the increase of simulated formation brine salinity. Choosing an appropriate B-PPG concentration is important for B-PPG treatments in oilfield applications. B-PPG is an efficient flow diversion agent, it can significantly increase sweep efficiency of displacing fluid in low permeability areas, which is beneficial to enhanced oil recovery in heterogeneous reservoirs.

scholarly journals Key geological factors controlling oil displacement efficiency of CO2 injection in low-permeability reservoirs

2021 ◽  
pp. 014459872199560
Author(s):  
Zhaosheng Wang ◽  
Lianbo Zeng ◽  
Jiangtao Yu ◽  
Zhenguo Zhang ◽  
Siyu Yang ◽  
...  
Keyword(s):  
Low Permeability ◽  
Natural Fractures ◽  
Displacement Efficiency ◽  
High Permeability ◽  
Oil Displacement ◽  
Sand Body ◽  
Oil Displacement Efficiency ◽  
Geological Factors ◽  
Low Permeability Reservoirs ◽  
Sand Bodies

Carbon dioxide (CO2) flooding is an effective method to enhance oil recovery in low-permeability reservoirs. Studying key geological factors controlling oil displacement efficiency is of great significance to the CO2 injection scheme design in low-permeability reservoirs. Focusing on low-permeable H reservoir in Songliao Basin, China, this paper describes the contact and connection of sand bodies, natural fractures and high-permeability zones with core samples, log data and experiment firstly. After that, the impact of interaction of sand body connection, natural fracture and high-permeability zone on oil displacement efficiency is determined by using geological and dynamic data in CO2 injection area. Results indicate that the connection of single sand bodies between injectors and producters wells primarily controls CO2 flooding in low-permeability reservoirs. Furthermore, coupling of sand body connection, natural fractures and high-permeability zones is the key geological factor governing oil displacement efficiency of CO2 injection in low-permeability reservoirs, where well or generally-connected sand bodies can improve the efficiency significantly. Meanwhile, the dominant seepage channels in other directions have no influence on producers, which is beneficial to improve CO2 flooding efficiency.

High Temperature Ageing of Fe-based Nanocrystalline Ribbons

2012 ◽  
Vol 2012 (HITEC) ◽  
pp. 000260-000265 ◽  
Author(s):  
Christian Martin ◽  
Rémi Robutel ◽  
Cyril Buttay ◽  
Fabien Sixdenier ◽  
Pascal Bevilacqua ◽  
...  
Keyword(s):  
High Temperature ◽  
High Temperature Stress ◽  
Complex Permeability ◽  
Magnetic Flux Density ◽  
Low Permeability ◽  
High Permeability ◽  
Design Considerations ◽  
Temperature Ageing ◽  
The Impact

The impact of long-term high-temperature stress on nanocrystalline Finemet materials is measured by keeping samples at 200 °C for 1300 hours. The standard industrialized, high permeability Finemet materials as well as the recently available low permeability Finemet materials are investigated. Characterizations are performed at different frequencies, temperatures and magnetic field excitations on both aged and non-aged samples. Their complex permeability is also measured during the ageing test. Irreversible changes are pointed out on permeability, coercive field and magnetic flux density at saturation. Regarding the design considerations for high temperature power electronics, the suitability of these materials is demonstrated but an ageing effect has to be considered nonetheless. The presented data can be extrapolated to several thousand hours at 200 °C using the presented empiric ageing law.

Study the Displacement Characteristics of Foam Flooding after Polymer Flooding on NMR

2011 ◽  
Vol 361-363 ◽  
pp. 493-498
Author(s):  
Jin Sheng Zhao ◽  
Tian Tai Li ◽  
Ming Zhang ◽  
Zhao Min Li
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Fluid Distribution ◽  
Distribution Area ◽  
Low Permeability ◽  
High Permeability ◽  
Polymer Foam ◽  
Foam Flooding

Through parallel cores with different permeability contrast, the displacement process of foam flooding after polymer flooding is experimental studied. Using the experiment technology of nuclear magnetic resonance, the fluid distribution in cores with different diameter was studied. The distribution area of bore diameter in which oil is sweepouted of water flooding, polymer flooding and foam flooding under different processes and various heterogeneity conditions. The results show, against water flooding and polymer flooding, the distribution area of bore diameter in which oil is sweepouted is broadened. Foam can plugging the wide aperture in which water and polyer channeling，and foam can sweep the bore diameter which can’t be swept by water and polymer. Foam can not only advance the recovery of low permeability core but also sweep the oil in microbore of high permeability core.

scholarly journals Impact of Low- or High-Permeability Inclusion on Free Convection in a Porous Medium

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-11
Author(s):  
Min Yan ◽  
Chunhui Lu ◽  
Jie Yang ◽  
Yifan Xie ◽  
Jian Luo
Keyword(s):  
Porous Media ◽  
Free Convection ◽  
Solute Transport ◽  
Large Scale ◽  
Effective Area ◽  
Source Zone ◽  
Sensitivity Analyses ◽  
Low Permeability ◽  
High Permeability ◽  
The Impact

Density-driven free convection in porous media is highly affected by large-scale heterogeneity, typical of which are low- or high-permeability inclusions imbedded in homogeneous porous media. In this research, we applied the modified Elder problem to investigate the impact of low- or high-permeability inclusions on the migration of a dense, unstable salt plume. Sensitivity analyses were conducted in terms of the permeability contrast, the effective area (the area of the inclusion beneath the source zone), and the distance of the inclusion from the source zone, all of which were found to play a significant role in controlling the total mass flux released from the source into the media. Results show that (1) a high-permeability inclusion has stronger effects than low-permeability inclusion, due to significantly unbalanced solute distributions caused by accelerated solute transport, (2) the inclusion with a larger effective area has more potential to influence free convection, (3) free convection is more sensitive to the low-/high-permeability inclusion vertically closer to the source zone, and (4) free convection is more susceptible to the low-permeability inclusion horizontally closer to the source zone. For high-permeability inclusions, the inclusion horizontally closer to the source zone influences the transport process more significantly at the early stage, and conversely, the inclusion far from the source zone has a later impact. The results obtained could offer significant implications for understanding unstable density-driven flow and solute transport in porous media with structured heterogeneity.

Low Permeability Reservoir Water Displacing Oil and Water Flooding Characteristic Curve Theory

2014 ◽  
Vol 556-562 ◽  
pp. 4701-4704
Author(s):  
Chun Sen Zhao ◽  
Qing Lin Ren ◽  
Pei Jing Li
Keyword(s):  
Characteristic Curve ◽  
Water Injection ◽  
Oil Field ◽  
Water Flooding ◽  
Practical Significance ◽  
Low Permeability ◽  
Reservoir Water ◽  
Field Development ◽  
Recoverable Reserves ◽  
The Impact

The so-called water flooding characteristic curve refers to the oilfield water injection (or natural water drive) development process, a relationship between curve cumulative oil production, cumulative water production and accumulation of fluid production. These curves have been widely used for water injection development of dynamic and recoverable reserves forecast. After many years of practical application, summed up the four kinds of water drive characteristic curve, they have a good practical significance. Recoverable reserves are important indicators of field development is the main basis for planning and design, the application of waterflooding characteristic curve can be predicted oil recoverable reserves. Four water flooding characteristics discussed above curve is mainly applied in high-permeability oil field, which did not consider starting pressure, but should consider the impact of low permeability oilfield actuating pressure gradient on the moisture content.

scholarly journals Optimization Technique and Practice of Stratified Injection in Low and Medium Permeability Thin Interlayer Reservoirs

2021 ◽  
Vol 8 (5) ◽  
pp. 8-11
Author(s):  
Fen He ◽  
Tao Li ◽  
Yang Li
Keyword(s):  
Recovery Rate ◽  
Optimization Technique ◽  
Water Injection ◽  
Low Permeability ◽  
Longitudinal Splitting ◽  
Research Technology ◽  
Medium Permeability ◽  
Thin Interlayer ◽  
Injection Effect ◽  
The Impact

Reservoir S is a typical medium and low permeability thin interlayer reservoir. It is developed by co-production of directional Wells and separate injection of directional Wells. The comprehensive water content of the oilfield is 54%. Therefore, it is urgent to optimize the injection method of stratified injection distribution in this reservoir, so as to improve the degree of water driving and recovery. In this paper, the reservoir engineering and numerical simulation methods are adopted to introduce the impact factor of injection-production correspondence rate, modify the previously used fine injection matching model, and use the model to quantitatively analyze the sensitivity of key parameters such as longitudinal splitting coefficient, pressure recovery rate and injection-production correspondence rate. The results show that it is very important to select the influencing factors for the injection and production response ratio of medium and low permeability thin interlayer reservoirs, which directly affects the effect of stratified water injection. At present, this research technology has been widely applied in S oilfield, and the water injection effect is very significant, effectively improving the recovery rate of the implementation area by 2%, which provides experience for the water injection development of similar reservoirs.

scholarly journals Effect of Viscosity Action and Capillarity on Pore-Scale Oil–Water Flowing Behaviors in a Low-Permeability Sandstone Waterflood

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8200
Author(s):  
Tao Ning ◽  
Meng Xi ◽  
Bingtao Hu ◽  
Le Wang ◽  
Chuanqing Huang ◽  
...  
Keyword(s):  
Water Flow ◽  
Oil Recovery ◽  
Recovery Rate ◽  
Viscosity Ratio ◽  
Rapid Change ◽  
Water Flooding ◽  
Pore Channel ◽  
Low Permeability ◽  
Pore Scale ◽  
Oil Water

Water flooding technology is an important measure to enhance oil recovery in oilfields. Understanding the pore-scale flow mechanism in the water flooding process is of great significance for the optimization of water flooding development schemes. Viscous action and capillarity are crucial factors in the determination of the oil recovery rate of water flooding. In this paper, a direct numerical simulation (DNS) method based on a Navier–Stokes equation and a volume of fluid (VOF) method is employed to investigate the dynamic behavior of the oil–water flow in the pore structure of a low-permeability sandstone reservoir in depth, and the influencing mechanism of viscous action and capillarity on the oil–water flow is explored. The results show that the inhomogeneity variation of viscous action resulted from the viscosity difference of oil and water, and the complex pore-scale oil–water two-phase flow dynamic behaviors exhibited by capillarity play a decisive role in determining the spatial sweep region and the final oil recovery rate. The larger the viscosity ratio is, the stronger the dynamic inhomogeneity will be as the displacement process proceeds, and the greater the difference in distribution of the volumetric flow rate in different channels, which will lead to the formation of a growing viscous fingering phenomenon, thus lowering the oil recovery rate. Under the same viscosity ratio, the absolute viscosity of the oil and water will also have an essential impact on the oil recovery rate by adjusting the relative importance between viscous action and capillarity. Capillarity is the direct cause of the rapid change of the flow velocity, the flow path diversion, and the formation of residual oil in the pore space. Furthermore, influenced by the wettability of the channel and the pore structure’s characteristics, the pore-scale behaviors of capillary force—including the capillary barrier induced by the abrupt change of pore channel positions, the inhibiting effect of capillary imbibition on the flow of parallel channels, and the blockage effect induced by the newly formed oil–water interface—play a vital role in determining the pore-scale oil–water flow dynamics, and influence the final oil recovery rate of the water flooding.

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