scholarly journals Formation damage due to asphaltene precipitation during CO2 flooding processes with NMR technique

2019 ◽  
Vol 74 ◽  
pp. 11 ◽  
Author(s):  
Kun Qian ◽  
Shenglai Yang ◽  
Hong-en Dou ◽  
Jieqiong Pang ◽  
Yu Huang
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Dominant Role ◽  
Injection Pressure ◽  
Recovery Process ◽  
Core Sample ◽  
Formation Damage ◽  
Co2 Flooding ◽  
Asphaltene Precipitation ◽  
The Core

In order to quantitatively evaluate the pore-scale formation damage of tight sandstones caused by asphaltene precipitation during CO2 flooding, the coreflood tests and Nuclear Magnetic Resonance (NMR) relaxometry measurements have been designed and applied. Five CO2 coreflood tests at immiscible, near-miscible and miscible conditions were conducted and the characteristics of the produced oil and gas were analyzed. For each coreflood test, the T2 spectrum of the core sample was measured and compared before and after CO2 flooding to determine the asphaltene precipitation distribution in pores. It is found that, the solubility and extraction effect of the CO2 plays a more dominant role in the CO2-EOR (Enhanced Oil Recovery) process with higher injection pressure. And, more light components are extracted and recovered by the CO2 and more heavy components including asphaltene are left in the core sample. Thus, the severity of formation damage influenced by asphaltene precipitation increases as the injection pressure increases. In comparison to micro and small pores (0.1–10 ms), the asphaltene precipitation has a greater influence on the medium and large pores (10–1000 ms) due to the sufficient interaction between the CO2 and crude oil in the medium and large pores. Furthermore, the asphaltene precipitation not only causes pore clogging, but also induces rock wettability to alter towards oil-wet direction.

Finite Element Analysis of Casing Material Behavior in Steam Injection Well Operations

2015 ◽  
Vol 799-800 ◽  
pp. 196-200
Author(s):  
Abhilash M. Bharadwaj ◽  
Sonny Irawan ◽  
Saravanan Karuppanan ◽  
Mohamad Zaki bin Abdullah ◽  
Ismail bin Mohd Saaid
Keyword(s):  
Finite Element ◽  
Oil Recovery ◽  
Thermal Stresses ◽  
Oil And Gas ◽  
Extreme Temperature ◽  
Injection Pressure ◽  
Oil And Gas Industry ◽  
Steam Injection ◽  
Material Behavior ◽  
Element Analysis

Casing design is one of the most important parts of the well planning in the oil and gas industry. Various factors affecting the casing material needs to be considered by the drilling engineers. Wells partaking in thermal oil recovery processes undergo extreme temperature variation and this induces high thermal stresses in the casings. Therefore, forecasting the material behavior and checking for failure mechanisms becomes highly important. This paper uses Finite Element Methods to analyze the behavior two of the frequently used materials for casing - J55 and L80 steels. Modeling the casing and application of boundary conditions are performed through Ansys Workbench. Effect of steam injection pressure and temperature on the materials is presented in this work, indicating the possibilities of failure during heating cycle. The change in diameter of the casing body due to axial restriction is also presented. This paper aims to draw special attention towards the casing design in high temperature conditions of the well.

Asphaltene Thermodynamic Flocculation during Immiscible Nitrogen Gas Injection

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Pore Size ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Filter Paper ◽  
Mixing Time ◽  
Injection Pressure ◽  
Weight Percent ◽  
Asphaltene Precipitation ◽  
Nitrogen Injection ◽  
The Impact

Summary Gas-enhanced oil recovery is one of the most advantageous enhanced oil recovery methods. Nitrogen is one of the most investigated gases because of its beneficial properties. However, during its interaction with crude oil, nitrogen can induce asphaltene deposition, which may result in severe formation damage and pore plugging. Few works have investigated the impact of nitrogen on asphaltene instability. This research studied the immiscibility conditions for nitrogen in nanopores and the impact of nitrogen on asphaltene precipitations, which could lead to plugging pores and oil recovery reduction. A slimtube was used to determine the minimum miscibility pressure (MMP) of nitrogen to ensure that all the experiments would be carried out below the MMP. Then, filtration experiments were conducted using nanofilter membranes to highlight the impact of the asphaltene particles on the pores of the membranes. A special filtration vessel was designed and used to accommodate the filter paper membranes. Various factors were investigated, including nitrogen injection pressure, temperature, nitrogen mixing time, and pore size heterogeneity. Supercritical phase nitrogen was used during all filtration experiments. Visualization tests were implemented to observe the asphaltene precipitation and deposition mechanism over time. Increasing the nitrogen injection pressure resulted in an increase in the asphaltene weight percent in all experiments. Decreasing the pore size of the filter membranes resulted in an increase in the asphaltene weight percent. Greater asphaltene weight percents were observed with a longer nitrogen mixing time. Visualization tests revealed that asphaltene clusters started to form after 1 hour and fully deposited after 12 hours in the bottom of the test tubes. Chromatography analysis of the produced oil confirmed that there was a reduction in the heavy components and asphaltene weight percent. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes found that significant pore plugging resulted from asphaltene deposition and precipitation. This research investigated asphaltene precipitation and deposition during immiscible nitrogen injection to understand the main factors that impact the success of using such a technique in unconventional shale reservoirs.

Modeling Formation Damage by Asphaltene Deposition During Primary Oil Recovery

2005 ◽  
Vol 127 (4) ◽  
pp. 310-317 ◽  
Author(s):  
Shaojun Wang ◽  
Faruk Civan
Keyword(s):  
Experimental Data ◽  
Mathematical Model ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Formation Damage ◽  
Asphaltene Precipitation ◽  
Vertical Wells ◽  
Core Flow ◽  
Asphaltene Deposition

Asphaltene precipitation and deposition during primary oil recovery and resulting reservoir formation damage are described by a phenomenological mathematical model. This model is applied using experimental data from laboratory core flow tests. The effect of asphaltene deposition on porosity, permeability, and the productivity of vertical wells in asphaltenic-oil reservoirs are investigated by simulation.

Novel microscopic imager instrument for rock and fluid imaging

Geophysics ◽  
2009 ◽  
Vol 74 (6) ◽  
pp. E251-E262 ◽  
Author(s):  
Marc H. Schneider ◽  
Patrick Tabeling ◽  
Fadhel Rezgui ◽  
Martin G. Lüling ◽  
Aurelien Daynes
Keyword(s):  
Oil And Gas ◽  
Image Interpretation ◽  
Core Sample ◽  
Reservoir Rock ◽  
Rock Properties ◽  
Oil And Gas Exploration ◽  
The Core ◽  
Video Acquisition ◽  
Visible Light Range ◽  
Acquisition Mode

Core analysis from reservoir rock plays an important role in oil and gas exploration as it can provide a large number of rock properties. Some of these rock properties can be extracted by image analysis of microscopic rock images in the visible light range. Such properties include the size, shape, and distribution of pores and grains, or more generally the texture, mineral distribution, and so on. A novel laboratory instrument and method allows for easy and reliable core imaging. This method is applicable even when the core sample is in poor shape. The capabilities of this technique can be verified by core images, image interpretation, and dynamic measurements of rock samples during flooding. A microscopic imager instrument is operated in video acquisition mode and can measure additional properties, such as fluid mobility, by detecting the emergence of injected fluids across the core sample.

scholarly journals Asphaltene Deposition during CO2 Flooding in Ultralow Permeability Reservoirs: A Case Study from Changqing Oil Field

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Li Rong-tao ◽  
Liao Xin-wei ◽  
Zou Jian-dong ◽  
Gao Chang-wang ◽  
Zhao Dong-feng ◽  
...  
Keyword(s):  
Adverse Effects ◽  
Injection Rate ◽  
Oil Field ◽  
Formation Damage ◽  
Co2 Flooding ◽  
Asphaltene Precipitation ◽  
Asphaltene Content ◽  
Asphaltene Deposition ◽  
Ultralow Permeability

Asphaltene deposition is a common phenomenon during CO2 flooding in ultralow permeability reservoirs. The deposited asphaltene occupies the pore volume and decreases permeability, resulting in serious formation damage and pore well productivity. It is urgent to investigate the asphaltene deposition mechanisms, adverse effects, and preventive measures. However, few asphaltene deposition investigations have been systematically conducted by now. In this research, the asphaltene precipitation mechanisms and adverse effects were comprehensively investigated by using experimental and numerical methods. To study the effects of pressure, asphaltene content, and temperature on asphaltene precipitation qualitatively and quantitatively, the microscope visible detection experiment and the PVT cell static experiment were firstly conducted. The adverse effects on porosity and permeability resulted from asphaltene deposition were also studied by the core flooding experiment. Secondly, simulation models of asphaltene precipitation and deposition were developed and validated by experimental data. Finally, a case study from Changqing oil field was presented to analyze the asphaltene deposition characteristic and preventive measures. The experimental results showed that the asphaltene precipitation increases with the increased pressure before reaching the minimum miscible pressure (MMP) and gets the peak value around the MMP, while decreases slowly. The asphaltene precipitation increases with the increased temperature and asphaltene content. The variation trend of adverse effects on porosity and permeability resulted from asphaltene deposition is similar to that of asphaltene precipitation under the influence of pressure, asphaltene content, and temperature. The case study shows that the water-altering-gas (WAG) with high injection rate suffers more serious asphaltene deposition compared with the WAG with low injection rate, for the asphaltene precipitation increases as the increased pressure before reaching the MMP. The CO2 continuous injection with high injection rate is the worst choice, for low sweep efficiency and the most severe formation damage. Thus, the WAG with optimal injection rate was proposed to maintain well productivity and to reduce formation damage resulted from asphaltene deposition during developing ultralow permeability reservoirs.

The Impact of Nanoparticles Adsorption and Transport on Wettability Alteration of Intermediate Wet Berea Sandstone

2015 ◽  
Author(s):  
Shidong Li ◽  
Ole Torsæter
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Fluid Pressure ◽  
Injection Pressure ◽  
Wettability Alteration ◽  
Colloidal Nanoparticles ◽  
Berea Sandstone ◽  
Nano Structure ◽  
The Core ◽  
The Impact

AbstractNanoparticles as part of nanotechnology have drawn the attention for its great potential of increasing oil recovery. From authors' previous studies (Li et al., 2013a), wettability alteration was proposed as one of the main Enhanced Oil Recovery (EOR) mechanisms for nanoparticles fluid, as adsorption of nanoparticles on pore walls leads to wettability alteration of reservoir. We conducted a series of wettability measurement experiments for aged intermediate-wet Berea sandstone, where the core plugs were treated by different concentration and type of nanoparticles fluid. Nanoparticles transport experiments also were performed for core plugs with injection of varying concentration and type of nanoparticles fluid. Pressure drop across the core plug during injection was recorded to evaluate nanoparticles adsorption and retention inside core, as well as desorption during brine postflush. Both hydrophilic silica nano-structure particles and hydrophilic silica colloidal nanoparticles were utilized in above two experiments.The results of wettability alteration experiments indicated that hydrophilic nanoparticles have ability of making intermediate-wet Berea sandstone to be more water wet, and basically the higher concentration the more water wet will be. And different type of nanoparticles has different effect on the wettability alteration process. For nanoparticles transport experiments, the results showed that the nanoparticles undergo both adsorption and desorption as well as retention during injection. Pressure drop curves showed that absorption and retention of nano-structure particles inside core was significant while colloidal nanoparticles did not adsorb much. Permeability impairment was observed during nano-structure particles fluid injection, but on the contrary colloidal nanoparticles dispersion injection made core more permeable.

scholarly journals Influence of CO2-brine-rock Interactions on the Physical Properties of Tight Sandstone Cores via Nuclear Magnetic Resonance

2021 ◽  
Vol 898 (1) ◽  
pp. 012021
Author(s):  
Hanbin Liu ◽  
Chengzheng Li ◽  
Zhenfeng Zhao ◽  
Guangtao Wang ◽  
Changheng Li ◽  
...  
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Physical Properties ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Low Permeability ◽  
Pore Throat ◽  
Tight Sandstone ◽  
The Core ◽  
Before And After ◽  
Enhance Oil Recovery

Abstract For sandstone reservoirs with extra-low permeability, CO2 injection is regarded as a valid method to enhance oil recovery. When CO2 injection is implemented in such reservoirs, the physical properties of the formation could be altered owing to the interactions between CO2, water, and rock. In this study, the influence of CO2–brine–rock interactions on the physical properties of tight sandstone cores was analyzed by comparing the obtained T 2 spectrum before and after CO2 injection. The results revealed that the T2 spectrum after CO2 injection was significantly different from the original T2 spectrum. CO2 injection changed the pore size distribution of the core samples. When the injection pressure was low, the pore volume decreased from micropores to macropores leading to a decrease in both permeability and porosity. As the injection pressure increasing, the dissolution of CO2 in the micropores was enhanced thus improving the pore-throat connectivity; which ultimately improved the reservoir physical properties.

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