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.

Asphaltene Thermodynamic Precipitation during Miscible Nitrogen Gas Injection

SPE Journal ◽  
2021 ◽  
pp. 1-18
Author(s):  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Pore Size ◽  
Oil Recovery ◽  
Mixing Time ◽  
Gas Injection ◽  
Injection Pressure ◽  
Weight Percent ◽  
Asphaltene Precipitation ◽  
Nitrogen Gas ◽  
Recovery Method ◽  
Asphaltene Deposition

Summary For many years, miscible gas injection has been the most beneficial enhanced oil recovery method in the oil and gas industry. However, injecting a miscible gas to displace oil often causes the flocculation and deposition of asphaltenes, which subsequently leads to a number of production problems. Nitrogen gas (N2) injection has been used to enhance oil recovery in some oil fields, seeking to improve oil recovery. However, few works have implemented N2 injection and investigated its effect on asphaltene precipitation and deposition. This research investigated the N2 miscible flow mechanism in nanopores and its impact on asphaltene precipitations, which can plug pores and reduce oil recovery. First, a slimtube was used to determine the minimum miscibility pressure (MMP) of N2 to ensure that all of the experiments would be conducted at levels above the MMP. Second, filtration experiments were conducted using nanocomposite filter membranes to study asphaltene deposition on the membranes. A filtration apparatus was designed specifically and built to accommodate the filter membranes. The factors studied include N2 injection pressure, temperature, N2 mixing time, and pore size heterogeneity. Visualization tests were conducted to highlight the asphaltene precipitation process over time. Increasing the N2 injection pressure resulted in an increase in the asphaltene weight percent in all experiments. Decreasing the pore size of the filter membranes increased the asphaltene weight percent. More N2 mixing time also resulted in an increase in asphaltene weight percent, especially early in the process. Visualization tests revealed that after 1 hour, the asphaltene particles were conspicuous, and more asphaltene clusters were found in the test tubes of the oil samples from the filter with the smallest pore size. Chromatography analysis of the produced oil confirmed the reduction in the asphaltene weight percent. Microscopy and scanning electron microscopy (SEM) imaging of the filter membranes indicated significant pore plugging from the asphaltenes, especially for the smaller pore sizes. This research highlights the severity of asphaltene deposition during miscible N2 injection in nanopore structures so as to understand the main factors that may affect the success of miscible N2 injection in unconventional reservoirs.

Modeling to support physicochemical enhancement techniques

2021 ◽  
pp. 79-90
Author(s):  
Т. A. Pospelova
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Chemical Modeling ◽  
Comparative Structure ◽  
Water Cut ◽  
Physical And Chemical ◽  
Oil And Gas Companies ◽  
The Impact ◽  
Selection Of

The article discusses ways to increase the oil recovery factor in already developed fields, special attention is paid to the methods of enhanced oil recovery. The comparative structure of oil production in Russia in the medium term is given. The experience of oil and gas companies in the application of enhanced oil recovery in the fields is analyzed and the dynamics of the growth in the use of various enhanced oil recovery in Russia is estimated. With an increase in the number of operations in the fields, the requirements for the selection of candidates inevitably increase, therefore, the work focuses on hydrodynamic modeling of physical and chemical modeling, highlights the features and disadvantages of existing simulators. The main dependences for adequate modeling during polymer flooding are given. The calculation with different concentration of polymer solution is presented, which significantly affects the water cut and further reduction of operating costs for the preparation of the produced fluid. The possibility of creating a specialized hydrodynamic simulator for low-volume chemical enhanced oil recovery is considered, since mainly simulators are applicable for chemical waterflooding and the impact is on the formation as a whole.

The Impact of Ionic Liquid and Nanoparticles on Stabilizing Foam for Enhanced Oil Recovery

2018 ◽  
Vol 3 (44) ◽  
pp. 12461-12468
Author(s):  
Lei Jiang ◽  
Jingtao Sun ◽  
Jiqian Wang ◽  
Qi Xue ◽  
Songyan Li ◽  
...  
Keyword(s):  
Ionic Liquid ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
The Impact

scholarly journals An experimental investigation of asphaltene stability in heavy crude oil during carbon dioxide injection

2019 ◽  
Vol 10 (3) ◽  
pp. 919-931 ◽  
Author(s):  
Sherif Fakher ◽  
Mohamed Ahdaya ◽  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Crude Oil ◽  
Pore Size ◽  
Oil Recovery ◽  
Asphaltene Precipitation ◽  
Carbon Dioxide Injection ◽  
Oil Viscosity ◽  
Membrane Pore ◽  
Pore Sizes ◽  
Filter Membrane

Abstract Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs.

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.

The impact of alkyl polyglycoside surfactant on oil yields and its potential effect on the biogenic souring during enhanced oil recovery (EOR)

Fuel ◽  
2020 ◽  
Vol 280 ◽  
pp. 118512 ◽  
Author(s):  
Tatiana Oliveira do Vale ◽  
Roberta Santoro de Magalhães ◽  
Paulo Fernando de Almeida ◽  
Josilene Borges Torres Lima Matos ◽  
Fábio Alexandre Chinalia
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Potential Effect ◽  
Alkyl Polyglycoside ◽  
The Impact

Integrated EOR Screening in a Marginal Oil Field Environment

2021 ◽  
Author(s):  
Chukwunonso Uche ◽  
Samuel Esieboma ◽  
Jennifer Uche ◽  
Ibrahim Bukar
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Data ◽  
Oil Field ◽  
Chemical Flooding ◽  
Implementation Challenges ◽  
Recovery Potential ◽  
Field Environment ◽  
Screening Study ◽  
The Impact

Abstract An evaluation of potential EOR processes applicable in the marginal oil field operation of the Niger Delta region is presented. Technical feasibility, process availability, oil recovery potential, and other uncertainties and risks associated with exploitation of enhanced oil recovery technique in a marginal oil field environment are being assessed. Few Enhanced oil recovery processes, namely polymer flooding, chemical flooding and microbial EOR (MEOR), are considered for possible application in this marginal oil field. The objective of the screening study is to evaluate and rank the EOR options and also select the most attractive method that will have to be further chased to a pilot test stage. Emphasis is strictly on a technical assessment of the incremental oil potential of each of the EOR methods and also identification of critical operational and logistical components of the entire process for their implementation in the offshore operating environment. Recoverable volumes associated with EOR may be significant, but key project development and implementation challenges and extra cost elements must be considered in any EOR forecast for an effective EOR process ranking. Some of these concerns (e.g. Polymer/chemical supply, facilities requirements, and the impact of EOR on reservoir performance and wellbore integrity) may be significant enough to eliminate a method from being considered further and at that point the best EOR option that requires minimal cost exposure for achieving the best recoverable shall be considered. Moreso, there is consideration of the quantity and quality of laboratory data that should support the viability of each EOR process being considered. This paper narrates the state of technical readiness for field implementation of each EOR method and identifies remaining work required to progress EOR process in this marginal oil field.

Horizontal Versus Vertical Wells: Assessment of Sweep Efficiency in a Multi-Layered Reservoir Based on Consecutive Inter-Well Tracer Tests - A Comparison Between Water Injection and Polymer EOR

2021 ◽  
Author(s):  
Bogdan-George Davidescu ◽  
Mathias Bayerl ◽  
Christoph Puls ◽  
Torsten Clemens
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Tracer Tests ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Sweep Efficiency ◽  
Flow Paths ◽  
Full Field ◽  
Polymer Injection ◽  
The Impact

Abstract Enhanced Oil Recovery pilot testing aims at reducing uncertainty ranges for parameters and determining operating conditions which improve the economics of full-field deployment. In the 8.TH and 9.TH reservoirs of the Matzen field, different well configurations were tested, vertical versus horizontal injection and production wells. The use of vertical or horizontal wells depends on costs and reservoir performance which is challenging to assess. Water cut, polymer back-production and pressures are used to understand reservoir behaviour and incremental oil production, however, these data do not reveal insights about changes in reservoir connectivity owing to polymer injection. Here, we used consecutive tracer tests prior and during polymer injection as well as water composition to elucidate the impact of various well configurations on sweep efficiency improvements. The results show that vertical well configuration for polymer injection and production leads to substantial acceleration along flow paths but less swept volume. Polymer injection does not only change the flow paths as can be seen from the different allocation factors before and after polymer injection but also the connected flow paths as indicated by a change in the skewness of the breakthrough tracer curves. For horizontal wells, the data shows that in addition to acceleration, the connected pore volume after polymer injection is substantially increased. This indicates that the sweep efficiency is improved for horizontal well configurations after polymer injection. The methodology leads to a quantitative assessment of the reservoir effects using different well configurations. These effects depend on the reservoir architecture impacting the changes in sweep efficiency by polymer injection. Consecutive tracer tests are an important source of information to determine which well configuration to be used in full-field implementation of polymer Enhanced Oil Recovery.

Theoretical and Numerical Investigation of Supersonic Multiphase Gas Injection

2021 ◽  
Author(s):  
Da Zhu ◽  
Mohan Sivagnanam ◽  
Ian Gates
Keyword(s):  
Shock Wave ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Single Phase ◽  
Gas Injection ◽  
Continuous Phase ◽  
Solid Particles ◽  
Gas Flows ◽  
Theoretical Derivation ◽  
The Impact

Abstract Supersonic gas injection can help deliver gas uniformly to a reservoir, regardless of reservoir conditions. This technology has played a key role in enhanced oil recovery (EOR) and in particular, thermal enhanced oil recovery operations. Most previous studies have focused on single phase gas injection whereas in most field applications, multiphase and multicomponent situations occur. In the research documented in this paper, we report on results of evaluations of compressible multiphase supersonic gas flows in which gas is the continuous phase is seeded with dispersed liquid droplets or solid particles. Theoretical derivation and numerical simulations with and without relative motions between continuous and disperse phases are examined first. The results illustrate that the shock wave structures and flow properties associated with the multiphase gas flows are different than that of single-phase isentropic flows. The existence and importance of relaxation zones after the normal shock wave in multiphase flow is described. Numerical computational fluid dynamics (CFD) simulations are conducted to show how the multiphase multicomponent flow affects gas phase injection under different conditions. The impact of solid/liquid mass loading on flow performance is discussed. Finally, the practical application of the findings is discussed.

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