scholarly journals Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3663
Author(s):  
Lindsey Rasmussen ◽  
Tianguang Fan ◽  
Alex Rinehart ◽  
Andrew Luhmann ◽  
William Ampomah ◽  
...  

The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO2 flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO2, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO2 and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO2 co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO2-enhanced oil recovery in heterogeneous reservoirs.

Author(s):  
Trine S. Mykkeltvedt ◽  
Sarah E. Gasda ◽  
Tor Harald Sandve

AbstractCarbon-neutral oil production is one way to improve the sustainability of petroleum resources. The emissions from produced hydrocarbons can be offset by injecting capture CO$$_{2}$$ 2 from a nearby point source into a saline aquifer for storage or a producing oil reservoir. The latter is referred to as enhanced oil recovery (EOR) and would enhance the economic viability of CO$$_{2}$$ 2 sequestration. The injected CO$$_{2}$$ 2 will interact with the oil and cause it to flow more freely within the reservoir. Consequently, the overall recovery of oil from the reservoir will increase. This enhanced oil recovery (EOR) technique is perceived as the most cost-effective method for disposing captured CO$$_{2}$$ 2 emissions and has been performed for many decades with the focus on oil recovery. The interaction between existing oil and injected CO$$_{2}$$ 2 needs to be fully understood to effectively manage CO$$_{2}$$ 2 migration and storage efficiency. When CO$$_{2}$$ 2 and oil mix in a fully miscible setting, the density can change non-linearly and cause density instabilities. These instabilities involve complex convective-diffusive processes, which are hard to model and simulate. The interactions occur at the sub-centimeter scale, and it is important to understand its implications for the field scale migration of CO$$_{2}$$ 2 and oil. In this work, we simulate gravity effects, namely gravity override and convective mixing, during miscible displacement of CO$$_{2}$$ 2 and oil. The flow behavior due to the competition between viscous and gravity effects is complex, and can only be accurately simulated with a very fine grid. We demonstrate that convection occurs rapidly, and has a strong effect on breakthrough of CO$$_{2}$$ 2 at the outlet. This work for the first time quantifies these effects for a simple system under realistic conditions.


2018 ◽  
Vol 7 (3.11) ◽  
pp. 232
Author(s):  
Aqilah Dollah ◽  
Zakirah Zainol Rashid ◽  
Nur Hidayati Othman ◽  
Siti Nurliyana Che Mohamed Hussein ◽  
Suriatie Mat Yusuf ◽  
...  

Ultrasonic waves is an unconventional enhanced oil recovery (EOR) technology and has been a point of interest as it is more economical and environmentally friendly. Numerous research works on ultrasonic waves application in EOR have been reported, nevertheless the studies on the effect of ultrasonic waves towards oil mobilization in porous media are still debatable. Therefore, this study aims to investigate the effect of ultrasonic waves on enhanced oil recovery of three types of oil (kerosene, engine oil and crude oil) and a brine sample at different temperatures (27°C, 35°C, 45°C, 55°C). A series of ultrasonic waterflooding experiments were conducted under controlled temperature conditions. Results demonstrated that oil recovery increases as the temperature increases during ultrasonic exposure compared to conventional waterflooding. The ultrasonic waves creates energy that increase the mobility of a displacing fluid thus reduce the viscosity of displaced fluids whereas the vibration energy produced from ultrasonic waves induced the mobility of the entrapped oil within the pores. The IR Spectra test indicates that the oil produced from ultrasonic simulated waterflooding for oils with different viscosity and density from the IR Spectra result without ultrasonic exposure due to the influence of flow behavior and sweep efficiencies of fluids. As conclusion, the ultrasonic cavitation is one of mechanism that could improve oil mobilization and enhanced oil recovery.  


1961 ◽  
Vol 1 (02) ◽  
pp. 61-70 ◽  
Author(s):  
J. Naar ◽  
J.H. Henderson

Introduction The displacement of a wetting fluid from a porous medium by a non-wetting fluid (drainage) is now reasonably well understood. A complete explanation has yet to be found for the analogous case of a wetting fluid being spontaneously imbibed and the non-wetting phase displaced (imbibition). During the displacement of oil or gas by water in a water-wet sand, the porous medium ordinarily imbibes water. The amount of oil recovered, the cost of recovery and the production history seem then to be controlled mainly by pore geometry. The influence of pore geometry is reflected in drainage and imbibition capillary-pressure curves and relative permeability curves. Relative permeability curves for a particular consolidated sand show that at any given saturation the permeability to oil during imbibition is smaller than during drainage. Low imbibition permeabilities suggest that the non-wetting phase, oil or gas, is gradually trapped by the advancing water. This paper describes a mathematical image (model) of consolidated porous rock based on the concept of the trapping of the non-wetting phase during the imbibition process. The following items have been derived from the model.A direct relation between the relative permeability characteristics during imbibition and those observed during drainage.A theoretical limit for the fractional amount of oil or gas recoverable by imbibition.An expression for the resistivity index which can be used in connection with the formula for wetting-phase relative permeability to check the consistency of the model.The limits of flow performance for a given rock dictated by complete wetting by either oil or water.The factors controlling oil recovery by imbibition in the presence of free gas. The complexity of a porous medium is such that drastic simplifications must be introduced to obtain a model amenable to mathematical treatment. Many parameters have been introduced by others in "progressing" from the parallel-capillary model to the randomly interconnected capillary models independently proposed by Wyllie and Gardner and Marshall. To these a further complication must be added since an imbibition model must trap part of the non-wetting phase during imbibition of the wetting phase. Like so many of the previously introduced complications, this fluid-block was introduced to make the model performance fit the observed imbibition flow behavior.


2014 ◽  
Author(s):  
Robert Heins ◽  
Mohammad Simjoo ◽  
Pacelli L.J. Zitha ◽  
William Richard Rossen

Nanomaterials ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 972 ◽  
Author(s):  
Amin Rezaei ◽  
Hadi Abdollahi ◽  
Zeinab Derikvand ◽  
Abdolhossein Hemmati-Sarapardeh ◽  
Amir Mosavi ◽  
...  

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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