scholarly journals The Effect of Carbonyl and Hydroxyl Compounds Addition on CO2 Injection through Hydrocarbon Extraction Processes

2020 ◽  
Vol 11 (1) ◽  
pp. 159
Author(s):  
Asep Kurnia Permadi ◽  
Egi Adrian Pratama ◽  
Andri Luthfi Lukman Hakim ◽  
Alfanda Kurnia Widi ◽  
Doddy Abdassah
Keyword(s):  
Carbon Number ◽  
Compositional Analysis ◽  
Injection Pressure ◽  
Intermolecular Forces ◽  
Extraction Process ◽  
Co2 Injection ◽  
Polar Compound ◽  
Polar Components ◽  
Fracture Pressure ◽  
Hydroxyl Compounds

CO2 miscible flooding occurs when injection pressure is higher than the minimum miscibility pressure (MMP) which can exceed the fracture pressure. Co-solvents are expected to reduce the MMP by interacting with various hydrocarbons that depend on the polarity and intermolecular forces of solvent and oil. However, there are limited studies that have investigated co-solvent performance in CO2 injection through an extraction process based on oil compositional analysis. This paper is aimed at studying the effects of carbonyl and hydroxyl compounds on oil extraction and also the mutual interactions of CO2-oil-carbonyl and -hydroxyl. The experiment is conducted by using VIPS (viscosity, interfacial tension, pressure-volume, and swelling) and gas chromatography (GC) apparatuses. The compositional results from GC are utilized to analyze the performance of co-solvents, which are further classified based on the carbon number and molecular structure of oil. Acetone is a non-associated polar compound which reacts easily with and assists CO2 to extract polar-aromatic heavy and slightly polar components such as alkenes and straight-chain alkanes, due to high polarizability and low cohesive forces. Ethanol is a self-associated polar compound which has the capability of extracting high-boiling fractions and slightly polar-aromatic components. Moreover, both co-solvents also assist CO2 to extract non-polar components because they have non-polar end in the alkyl group.

scholarly journals The Effect of Carbonyl and Hydroxyl Compounds on Swelling Factor, Interfacial Tension, and Viscosity in CO2 Injection: A Case Study on Aromatic Oils

Processes ◽  
2021 ◽  
Vol 9 (1) ◽  
pp. 94
Author(s):  
Asep Kurnia Permadi ◽  
Egi Adrian Pratama ◽  
Andri Luthfi Lukman Hakim ◽  
Doddy Abdassah
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Viscosity Reduction ◽  
Co2 Injection ◽  
Minimum Miscibility Pressure ◽  
Lower Viscosity ◽  
Hydroxyl Compounds ◽  
Swelling Factor

A factor influencing the effectiveness of CO2 injection is miscibility. Besides the miscible injection, CO2 may also contribute to oil recovery improvement by immiscible injection through modifying several properties such as oil swelling, viscosity reduction, and the lowering of interfacial tension (IFT). Moreover, CO2 immiscible injection performance is also expected to be improved by adding some solvent. However, there are a lack of studies identifying the roles of solvent in assisting CO2 injection through observing those properties simultaneously. This paper explains the effects of CO2–carbonyl and CO2–hydroxyl compounds mixture injection on those properties, and also the minimum miscibility pressure (MMP) experimentally by using VIPS (refers to viscosity, interfacial tension, pressure–volume, and swelling) apparatus, which has a capability of measuring those properties simultaneously within a closed system. Higher swelling factor, lower viscosity, IFT and MMP are observed from a CO2–propanone/acetone mixture injection. The role of propanone and ethanol is more significant in Sample A1, which has higher molecular weight (MW) of C7+ and lower composition of C1–C4, than that in the other Sample A9. The solvents accelerate the ways in which CO2 dissolves and extracts oil, especially the extraction of the heavier component left in the swelling cell.

Overcoming CO2 Injector Well Design and Completion Challenges in a Carbonate Reservoir for World's First Offshore Carbon Capture Storage CCS SE Asia Project

2021 ◽  
Author(s):  
Mahesh S. Picha ◽  
M. Azuan B. Abu Bakar ◽  
Parimal A. Patil ◽  
Faiz A. Abu Bakar ◽  
Debasis P. Das ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Injection Pressure ◽  
Co2 Concentration ◽  
Carbonate Reservoir ◽  
Seismic Survey ◽  
Co2 Injection ◽  
Injection Wells ◽  
Gas Field ◽  
Accelerated Corrosion ◽  
Well Design

Abstract Oil & Gas Operators are focusing on zero carbon emission to comply with government's changing rules and regulations, which play an important role in the encouragement of carbon capture initiatives. This paper aims to give insights on the world's first offshore CCS project in carbonate reservoir, where wells will be drilled to inject CO2, and store produced CO2 from contaminated fields. To safeguard the storage containment, the integrity of all wells needs to be scrutinized. Development wells in the identified depleted gas field are more than 40 years old and were not designed with consideration of high CO2 concentration in the reservoir. In consequence, the possibility of well leakage due to accelerated corrosion channeling and cracks, along the wellbore cannot be ignored and require careful evaluation. Rigorous process has been adopted in assessing the feasibility for converting existing gas producers into CO2 injectors. The required defined basis of designs for gas producer and CO2 injection wells differs in a great extent and this governs the re-usability of wells for CO2 injection or necessity to be abandoned. Three (3) new CO2 injectors with fat to slim design approach, corrosion resistant alloy (CRA) material and CO2 resistant cement are designed in view to achieve lifecycle integrity. Optimum angle of 53 deg and maintaining the injection pressure of 50 bar at 90 MSCFD rate is required for the injection of supercritical CO2 for 20 years. During well execution, challenges such as anti-collision risk, total loss scenarios while drilling in Carbonate reservoir need to be addressed before execution. The completion design is also focusing on having minimal number of completion jewelries to reduce pressure differential and potential leak paths from tubing hangar down to the end of lower completion. The selection of downhole safety valve (TRSV) type is of high importance to accommodate CO2 phase attributes at different pressure/temperature. Fiber Optic is included for monitoring the migration of CO2 plume by acquiring seismic survey and for well integrity by analyzing DAS/DTS data.

An Approach for Characterization and Lumping of Plus Fractions of Heavy Oil

2010 ◽  
Vol 13 (02) ◽  
pp. 283-295 ◽  
Author(s):  
I.. Rodriguez ◽  
A.A.. A. Hamouda
Keyword(s):  
Molecular Weight ◽  
Mole Fraction ◽  
Heavy Oil ◽  
Equations Of State ◽  
Carbon Number ◽  
Compositional Analysis ◽  
Volume Depletion ◽  
Molecular Weights ◽  
Pvt Data ◽  
Light Oil

Summary Heavy-oil fluids contain large concentrations of high-molecular-weight components, including a large content of the plus fractions, such as C7+. Different approaches have been developed to characterize the petroleum plus fractions to improve prediction of the pseudocomponents properties by equations of state (EOSs). A method is developed in this work to split the plus fraction into single carbon numbers (SCN), generating the mole fraction and the respective molecular weight. The developed method is based on the relationships between three-parameter gamma (TPG) distribution, experimental mole fraction, molecular weight, and SCN data obtained from the literature and industrial contacts. TPG is used to fit the trend of the compositional analysis. The characterized mole distribution as a function of SCNs is generated by integrating the TPG between the limiting molecular weights (LMw). The limiting molecular weights are determined simultaneously during the integration process by fitting the characterized and experimental mole fractions. The developed method is easy to use. In addition, the approach is not dependent on the assumption that only normal carbon numbers exist in the composition resulting on fixed molecular weights for each single carbon number. There are several correlations generated to predict physicochemical properties as a function of SCNs. Those correlations have been originally developed to work with light oil. Our approach is combined with some of the correlations and is tested for heavy-oil samples to identify the ranges in which they can be applied. Two lumping schemes are used to group the SCNs into pseudocomponents. The properties for each pseudo-component in this work are used to predict pressure/volume/temperature (PVT) data, constant volume depletion, using the Peng-Robinson EOS (PR-EOS), and the PVTP™ commercial simulator.

New Model to Analyze Nonlinear Leak-Off Test Behavior

1999 ◽  
Vol 121 (2) ◽  
pp. 102-109 ◽  
Author(s):  
G. Altun ◽  
E. Shirman ◽  
J. P. Langlinais ◽  
A. T. Bourgoyne
Keyword(s):  
Mathematical Model ◽  
Drilling Fluid ◽  
Nonlinear Behavior ◽  
Injection Pressure ◽  
Maximum Pressure ◽  
Drilling Fluids ◽  
Total System ◽  
Verification Method ◽  
Fracture Pressure ◽  
Wellbore Pressure

A leak-off test (LOT) is a verification method to estimate fracture pressure of exposed formations. After cementing each casing string, LOT is run to verify that the casing, cement and formation below the casing seat can withstand the wellbore pressure required to drill for the next casing string safely. Estimated fracture pressure from the test is used as the maximum pressure that may be imposed on that formation. Critical drilling decisions for mud weights, casing setting depths, and well control techniques are based upon the result of a LOT. Although LOT is a simple and inexpensive test, its interpretation is not always easy, particularly in formations that give nonlinear relationships between pumped volume and injection pressure. The observed shape of the LOT is primarily controlled by the local stresses. However, there are other factors that can affect and distort LOT results. Physically the LOT, indeed, reflects the total system compressibility, i.e., the compressibility of the drilling fluid, wellbore expansion, or so-called borehole ballooning, and leak (filtration) of drilling fluids into the formation. There is, however, no mathematical model explaining the nonlinear behavior. Disagreement on determining or interpreting actual leak-off pressure from the test data among the operators is common. In this paper, a mathematical model using a well-known compressibility equation is derived for total system compressibility to fully analyze nonlinear LOT behavior. This model accurately predicts the observed nonlinear behavior in a field example. The model also predicts the fracture pressure of the formation without running a test until formation fracture.

An Experimental Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs

2021 ◽  
Author(s):  
Ifeanyi Seteyeobot ◽  
Mahmoud Jamiolahmady ◽  
Philip Jaeger ◽  
Abdulelah Nasieef
Keyword(s):  
Co2 Storage ◽  
Injection Pressure ◽  
Gas Condensate ◽  
Phase Behaviour ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Experimental Phase ◽  
Co2 Gas ◽  
Gas Condensate Reservoirs ◽  
Core Flood

Abstract The application of non-hydrocarbon gas injection for enhanced gas and condensate recovery (EGCR) is still in a developmental stage as the mixing/interaction between the injected gas and resident reservoir fluid is yet to be extensively understood and the inability to optimize the recovery process has led to limited pilot trials. Carbon dioxide (CO2) injection into gas-condensate reservoirs for improved recovery and CO2 storage provides additional and favorable changes in phase and fluid flow behaviour making it economically more attractive compared to other injection gases. However, to make an informed decision, adequate phase and flow behaviour analysis are required to better forecast the reservoir performance under CO2 injection. In this research, appropriate experimental phase behaviour, EOS modeling, and unsteady-state flow tests have been conducted to determine the level of CO2/gas-condensate interaction including condensing/vaporizing mechanisms during CO2 Huff-n-Puff (HnP) injection. A CO2 HnP injection technique was followed to identify the best CO2 flooding conditions. A total of four HnP injection cycles with incremental CO2 volumes of 20, 40, 60, and 80 % of the initial resident fluid volume prior to depletion was considered. CO2 injection pressure and volume are optimized below the saturation pressure. The analysis is based on evaluating the level of interaction between CO2 and resident fluid at the maximum condensate saturation of the corresponding CO2-gas-condensate fluid mixture as determined in a phase equilibria cell. Appropriate experimental phase behaviour and core flood data were generated and analyzed to identify and quantify the level of condensing/vaporizing mechanisms which are vital for adequate optimization of the injection pressure and amount of injected CO2 for both enhanced gas and condensate recovery and CO2 storage purposes. The amount of gas, condensate, and CO2 produced at each core flood stage was recorded. These data allow bridging the gap between conflicting reports on the trend and level of CO2/gas-condensate fluid interactions at pressures below the dew point pressure (Pdew). They also provide a better knowledge of the governing mechanisms during CO2 flooding, which are required for designing appropriate CO2 HnP injection for reservoir engineering applications.

scholarly journals Reservoir Management of CO2 Injection: Pressure Control and Capacity Enhancement

2013 ◽  
Vol 37 ◽  
pp. 4533-4543 ◽  
Author(s):  
Bamshad Nazarian ◽  
Rudolf Held ◽  
Lars Høier ◽  
Philip Ringrose
Keyword(s):  
Injection Pressure ◽  
Reservoir Management ◽  
Pressure Control ◽  
Co2 Injection ◽  
Capacity Enhancement

The Influences of CO2 Injection Pressure on CO2 Dispersion and the Mechanism of CO2–CH4 Displacement in Shale

2017 ◽  
Vol 140 (1) ◽  
Author(s):  
Xidong Du ◽  
Min Gu ◽  
Shuo Duan ◽  
Xuefu Xian
Keyword(s):  
Mass Transfer ◽  
Dispersion Coefficient ◽  
Pore Space ◽  
Injection Pressure ◽  
Breakthrough Curves ◽  
Co2 Injection ◽  
Mechanical Mixing ◽  
Co2 Diffusion ◽  
Stagnant Region ◽  
Capacitance Model

The effects of CO2 injection pressure (PCO2) on CO2 dispersion and the mechanism of CO2–CH4 displacement in a shale sampled from Changning of China were studied. Results indicated that Coats–Smith dispersion–capacitance model gave a reasonable simulated result to the breakthrough curves of CO2 under different injection pressures. The shapes of CO2 breakthrough curves became more asymmetrical with the increase of CO2 injection pressure. A higher CO2 injection pressure caused early CO2 breakthrough and reduced the recovery of CH4 at CO2 breakthrough (Rpipeline-CH4), but improved the ultimate displaced CH4 amount (Rultimate-CH4). With the increase of CO2 injection pressure, dispersion coefficient (Kd) increased nearly exponentially. A larger Kd led to a lower Rpipeline-CH4 and a longer transition zone. With the increase of CO2 injection pressure, the flowing fraction (F) in pore space decreased nearly linearly and more CO2 diffused into stagnant region to replace adsorbed CH4 in a shale, which resulted in a larger Rultimate-CH4. The mass transfer coefficient (Km) between the flowing and stagnant regions increased with the increase of CO2 injection pressure, which led to a smaller F and larger Rultimate-CH4. CO2 diffusion provided major contribution to CO2 dispersion at lower injection pressure, and mechanical mixing of CO2–CH4 offered predominant contribution to CO2 dispersion at higher injection pressure. Larger mechanical mixing accelerated the mixing of CO2–CH4, which was unfavorable for Rpipeline-CH4. Lower CO2 injection pressure was conductive to gain higher Rpipeline-CH4.

Modelling Production Initiation from a Lazy Well by Direct Gas Injection at the Casing Head Using Dynamic Wellbore Simulator

2021 ◽  
Author(s):  
Nashat Jumaah Omar ◽  
Ibrahim Saeb Al-Saeedi
Keyword(s):  
Gas Injection ◽  
Injection Pressure ◽  
Cost Effective ◽  
Transient Behavior ◽  
Successful Implementation ◽  
Well Production ◽  
Coiled Tubing ◽  
Fracture Pressure ◽  
Precise Knowledge ◽  
Method Of Production

Abstract This study deals with a lazy well completed with no packer in place. The main producing formation is showing strong signs of depletion where it lost more 2000 psig of reservoir pressure since the production started. Previous experiences in this well and other offset wells show there is demand for Nitrogen Injection Through Coiled Tubing Unit in the tubing in order to lift the well and bring it online whenever the well is shut-in for any reason. Direct natural gas injection at the casing head is a cost-effective alternative to rigless well lift operations. However, this is a challenging thing to achieve since it requires precise knowledge of injection rates and casing head pressure, additional to that formation fracture pressure and other reservoir characteristics should be taken into consideration. Data were collected and dynamic wellbore is created and linked to near well reservoir model to capture the transient behavior of the reservoir during start-up process. From Dynamic Modeling and simulation of the production system, best injection pressure, production choke, injection time and quantities are estimated and optimized for more efficient lifting process. After Initiating the well, production stability is observed in the transient simulator to ensure the success of the well lifting method. This method of production initiation is cost effective, and if implemented properly should bring the well back in production fast. Successful implementation this method demands a precise wellbore model to be created and shut-in surveys should be used to match the well status when it's not producing to tune the wellbore and fluid parameters.

Value addition study on coker kero for producing alpha olefin and alkyl benzene

2021 ◽  
Vol 0 (0) ◽  
Author(s):  
Deependra Tripathi ◽  
Raj K. Singh ◽  
Kamal Kumar ◽  
Udai P. Singh
Keyword(s):  
Compositional Analysis ◽  
Value Added ◽  
Alkyl Benzene ◽  
Adsorption Study ◽  
Delayed Coking ◽  
Polar Components ◽  
Alpha Olefin ◽  
Fuller’S Earth ◽  
Ir Study ◽  
Methyl Pyrrolidone

Abstract Coker kero stream is obtained from delayed coking which contains saturates with alpha olefins and PNA compounds which was physicochemical characterised. The fractions present in coker kero may be used further for value added products such as alkyl benzene and naphthalene etc. The study described potential of coker kero via aromatics and non-aromatics separation by using liquid-liquid extraction (LLE) with N-methyl pyrrolidone (NMP), acetonitrile and methanol as solvents of different polarity. Methanol imparts best colour improvement as per ASTM D-1500. Beside this, adsorption study on coker kero was performed using fuller’s earth, chalk powder, red ochre and wood-stick’s ash as adsorbents. The adsorption study suggested that fuller’s earth not only separate aromatics and non-aromatics form coker kero, but also acts as a better adsorbent than graphitic carbon (activated charcoal) and is found suitable for colour improvement comparatively. This study inferred the separation of polar components, improvement in the colour, odour and established the stable fuel. FT-IR study suggested that N-methyl Pyrrolidone gives better results comparatively other solvents. HC22 type analysis of coker kero raffinate and extract phase confirm the sharp extraction of coker kero feed using N-Methyl pyrrolidone as it is a good solvent for extraction of aromatics. GCMS and HRMS compositional analysis successfully performed for the coker kero and it is separated aromatic and non-aromatic fractions.

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