Study on Performance Evaluation of Dispersed Particle Gel for Improved Oil Recovery

2013 ◽  
Vol 135 (4) ◽  
Author(s):  
Qing You ◽  
Caili Dai ◽  
Yongchun Tang ◽  
Ping Guan ◽  
Guang Zhao ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Water Flooding ◽  
Improved Oil Recovery ◽  
Hydrocarbon Recovery ◽  
Heterogeneous Reservoirs ◽  
Atomic Force ◽  
Segregated Flow ◽  
Oil Flow

This work investigates the performance of dispersed particle gel (DPG) by core flow tests including injectivity, selective plugging, thermal stability, and improved oil recovery (IOR). Results showed that the resistance factor is small when DPG was injected, but obviously became larger while turning into brine water flooding. Both the oil and water relative permeability were reduced and greater reduction appeared in water relative permeability. DPG could block water flow without affecting oil flow, and oil–water segregated flow mechanism was proposed to explain this selective plugging. The injection pressure increases, caused by strong plugging due to the DPG aggregation aging in high temperature, which was consistent with the observation of atomic force microscope (AFM) photos. The DPG could effectively block high permeability zone and produce oil from low permeability zone, which could provide a practical way to enhance hydrocarbon recovery while reducing water production for extremely heterogeneous reservoirs.

Key characteristics of three-phase oil relative permeability formulations for improved oil recovery predictions

1999 ◽  
Vol 5 (4) ◽  
pp. 339-346 ◽  
Author(s):  
E. F. Balbinski ◽  
T. P. Fishlock ◽  
S. G. Goodyear ◽  
P. I. R. Jones
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Improved Oil Recovery ◽  
Three Phase ◽  
Key Characteristics

scholarly journals Analysis of a model for foam improved oil recovery

2014 ◽  
Vol 751 ◽  
pp. 346-405 ◽  
Author(s):  
P. Grassia ◽  
E. Mas-Hernández ◽  
N. Shokri ◽  
S. J. Cox ◽  
G. Mishuris ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Numerical Schemes ◽  
Improved Oil Recovery ◽  
Heterogeneous Reservoirs ◽  
Long Time ◽  
Porous Reservoir ◽  
Tension Term ◽  
Sharp Corners ◽  
Pressure Driven

AbstractDuring improved oil recovery (IOR), gas may be introduced into a porous reservoir filled with surfactant solution in order to form foam. A model for the evolution of the resulting foam front known as ‘pressure-driven growth’ is analysed. An asymptotic solution of this model for long times is derived that shows that foam can propagate indefinitely into the reservoir without gravity override. Moreover, ‘pressure-driven growth’ is shown to correspond to a special case of the more general ‘viscous froth’ model. In particular, it is a singular limit of the viscous froth, corresponding to the elimination of a surface tension term, permitting sharp corners and kinks in the predicted shape of the front. Sharp corners tend to develop from concave regions of the front. The principal solution of interest has a convex front, however, so that although this solution itself has no sharp corners (except for some kinks that develop spuriously owing to errors in a numerical scheme), it is found nevertheless to exhibit milder singularities in front curvature, as the long-time asymptotic analytical solution makes clear. Numerical schemes for the evolving front shape which perform robustly (avoiding the development of spurious kinks) are also developed. Generalisations of this solution to geologically heterogeneous reservoirs should exhibit concavities and/or sharp corner singularities as an inherent part of their evolution: propagation of fronts containing such ‘inherent’ singularities can be readily incorporated into these numerical schemes.

Study on Minimum Miscible Pressure and Oil Displacement Law for CO2 Flooding

2011 ◽  
Vol 391-392 ◽  
pp. 1051-1054
Author(s):  
Shu Li Chen ◽  
Wen Xiang Wu ◽  
Jia Bin Tang
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Injection Pressure ◽  
Water Flooding ◽  
Tube Model ◽  
Gas Oil ◽  
Core Flooding ◽  
Oil Displacement ◽  
Gas Flooding ◽  
Cumulative Recovery

In laboratory, the minimum miscible pressure (MMP) of oil and CO2 was studied by using a slim tube model. The results showed that the greater the gas injection pressure, the higher the cumulative recovery. The gas breakthrough when the gas was injected with a volume of 0.7~0.8PV, the trend of cumulative recovery increase slowed down and the produced gas-oil ratio increased dramatically. Core flooding experiments were carried to compare the effects of CO2 and water flooding. As a result, the ultimate oil recovery of CO2 flooding increased with the increase of gas injection pressure. If the gas flooding was miscible, the ultimate recovery of CO2 flooding was generally higher than that of water flooding.

Improved Oil Recovery by Application of Sound Waves to Water Flooding

2007 ◽  
Author(s):  
Mohammed Amro ◽  
Mohammed Abdullah Al Mobarky ◽  
Emad Solaiman Al-Homadhi
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
Sound Waves ◽  
Improved Oil Recovery

scholarly journals Multiscale Assessment of Caprock Integrity for Geologic Carbon Storage in the Pennsylvanian Farnsworth Unit, Texas, USA

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5824
Author(s):  
Natasha Trujillo ◽  
Dylan Rose-Coss ◽  
Jason E. Heath ◽  
Thomas A. Dewers ◽  
William Ampomah ◽  
...  
Keyword(s):  
Carbon Storage ◽  
Oil Recovery ◽  
Gamma Ray ◽  
Noble Gas ◽  
Mercury Porosimetry ◽  
Injection Pressure ◽  
Horizontal Stress ◽  
Gas Analysis ◽  
Water Flooding ◽  
Minimum Horizontal Stress

Leakage pathways through caprock lithologies for underground storage of CO2 and/or enhanced oil recovery (EOR) include intrusion into nano-pore mudstones, flow within fractures and faults, and larger-scale sedimentary heterogeneity (e.g., stacked channel deposits). To assess multiscale sealing integrity of the caprock system that overlies the Morrow B sandstone reservoir, Farnsworth Unit (FWU), Texas, USA, we combine pore-to-core observations, laboratory testing, well logging results, and noble gas analysis. A cluster analysis combining gamma ray, compressional slowness, and other logs was combined with caliper responses and triaxial rock mechanics testing to define eleven lithologic classes across the upper Morrow shale and Thirteen Finger limestone caprock units, with estimations of dynamic elastic moduli and fracture breakdown pressures (minimum horizontal stress gradients) for each class. Mercury porosimetry determinations of CO2 column heights in sealing formations yield values exceeding reservoir height. Noble gas profiles provide a “geologic time-integrated” assessment of fluid flow across the reservoir-caprock system, with Morrow B reservoir measurements consistent with decades-long EOR water-flooding, and upper Morrow shale and lower Thirteen Finger limestone values being consistent with long-term geohydrologic isolation. Together, these data suggest an excellent sealing capacity for the FWU and provide limits for injection pressure increases accompanying carbon storage activities.

scholarly journals Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiang Li ◽  
Yuan Cheng ◽  
Wulong Tao ◽  
Shalake Sarulicaoketi ◽  
Xuhui Ji ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

Optimized Salinity Water Flooding as an Improved Oil Recovery IOR Scheme in the Niger Delta

2020 ◽  
Author(s):  
David Alaigba ◽  
Onaiwu Oduwa ◽  
Ikponmwosa Ohenhen ◽  
Olalekan Olafuyi
Keyword(s):  
Oil Recovery ◽  
Niger Delta ◽  
Water Flooding ◽  
Improved Oil Recovery ◽  
Salinity Water

scholarly journals Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing

Nanomaterials ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 972 ◽  
Author(s):  
Amin Rezaei ◽  
Hadi Abdollahi ◽  
Zeinab Derikvand ◽  
Abdolhossein Hemmati-Sarapardeh ◽  
Amir Mosavi ◽  
...  
Keyword(s):  
Size Distribution ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Alpha Olefin Sulfonate ◽  
Core Flooding ◽  
Recovery Method ◽  
Fluid Saturation

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

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