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Geofluids ◽  
2022 ◽  
Vol 2022 ◽  
pp. 1-9
Author(s):  
Jingkui Mi ◽  
Kun He ◽  
Yanhuan Shuai ◽  
Jinhao Guo

In this study, a methane (CH4) cracking experiment in the temperature range of 425–800°C is presented. The experimental result shows that there are some alkane and alkene generation during CH4 cracking, in addition to hydrogen (H2). Moreover, the hydrocarbon gas displays carbon isotopic reversal ( δ 13 C 1 > δ 13 C 2 ) below 700°C, while solid carbon appears on the inner wall of the gold tube above 700°C. The variation in experimental products (including gas and solid carbon) with increasing temperature suggests that CH4 does not crack into carbon and H2 directly during its cracking, but first cracks into methyl (CH3⋅) and proton (H+) groups. CH3⋅ shares depleted 13C for preferential bond cleavage in 12C–H rather than 13C–H. CH3⋅ combination leads to depletion of 13C in heavy gas and further causes the carbon isotopic reversal ( δ 13 C 1 > δ 13 C 2 ) of hydrocarbon gas. Geological analysis of the experimental data indicates that the amount of heavy gas formed by the combination of CH3⋅ from CH4 early cracking and with depleted 13C is so little that can be masked by the bulk heavy gas from organic matter (OM) and with enriched 13C at R o < 2.5 % . Thus, natural gas shows normal isotope distribution ( δ 13 C 1 < δ 13 C 2 ) in this maturity stage. CH3⋅ combination (or CH4 polymerization) intensifies on exhaustion gas generation from OM in the maturity range of R o > 2.5 % . Therefore, the carbon isotopic reversal of natural gas appears at the overmature stage. CH4 polymerization is a possible mechanism for carbon isotopic reversal of overmature natural gas. The experimental results indicate that although CH4 might have start cracking at R o > 2.5 % , but it cracks substantially above 6.0% R o in actual geological settings.


Processes ◽  
2022 ◽  
Vol 10 (1) ◽  
pp. 130
Author(s):  
Kenta Kikuchi ◽  
Tsukasa Hori ◽  
Fumiteru Akamatsu

Hydrogen is expected to be a next-generation energy source that does not emit carbon dioxide, but when used as a fuel, the issue is the increase in the amount of NOx that is caused by the increase in flame temperature. In this study, we experimentally investigated NOx emissions rate when hydrogen was burned in a hydrocarbon gas burner, which is used in a wide temperature range. As a result of the experiments, the amount of NOx when burning hydrogen in a nozzle mixed burner was twice as high as when burning city gas. However, by increasing the flow velocity of the combustion air, the amount of NOx could be reduced. In addition, by reducing the number of combustion air nozzles rather than decreasing the diameter of the air nozzles, a larger recirculation flow could be formed into the furnace, and the amount of NOx could be reduced by up to 51%. Furthermore, the amount of exhaust gas recirculation was estimated from the reduction rate of NOx, and the validity was confirmed by the relationship between adiabatic flame temperature and NOx calculated from the equilibrium calculation by chemical kinetics simulator software.


Author(s):  
O. M. Dyakonov ◽  
V. Yu. Sereda

The process of inorganic and organic components temperature transformation of metal waste into solid and gaseous products in a continuous hot briquetting muffle furnace has been studied. The composition of the hydrocarbon atmosphere formed in the muffle under conditions of limited access to the oxidizer has been determined. It is shown that the thermal destruction of the coolant oil phase proceeds according to a complex mechanism of consecutive reactions, including polycondensation, polymerization, and deep compaction with a constant decrease in the hydrogen content and ends with the formation of a coke‑like carbon residue on the surface of metal particles and an air suspension of finely dispersed carbon particles (smoke). When it is heated to hot briquetting temperatures of 750–850 °C, chemically active dispersions of ferrous metals are protected from oxidation first by a hydrocarbon gas with a density of 9.0–13.5 kg/m3, then by a pyrocarbon coating with a thickness of 0.1–0.3 mm up to the completion of the processes of pressing and cooling the briquette.


2021 ◽  
Author(s):  
Siqing Xu ◽  
Ahmed A BinAmro ◽  
Aaesha K. Al Keebali ◽  
Mohamed Baslaib ◽  
Shehadeh Masalmeh

Abstract Miscible CO2 flood is a well-established proven EOR recovery mechanism. There have been a large number of CO2 EOR developments worldwide, in both carbonate and clastic reservoirs. Potential control or influence factors on incremental production and incremental recovery over water flood are well documented in the published literature. Some of the published CO2 EOR developments have reported relatively high incremental recoveries. ADNOC is a leader in miscible gas injection EOR in carbonate reservoirs. There are a number of ongoing miscible gas injection EOR developments within its portfolio contributing a significant amount of production. Miscible CO2 flood is a key EOR development for ADNOC. Following intensive screening studies and laboratory experiments, the first CO2 EOR pilot in the MENA region was conducted as early as 2009 in one of ADNOC Onshore fields. This paved the way for further large-scale deployment and CO2 WAG pilots starting in 2016, both onshore. Appreciable progresses have been made since 2009. This bodes well with the significant initiatives undertaken by the UAE towards carbon emissions and greenhouse gas reduction, climate control and sustainable development. There are broad consensus that climate changes are now and will continue to affect all countries on all continents. Potential global warming can disrupt national economies and adversely impact on lives, costing people, communities and countries already today and perhaps more in the future. Carbon Capture, Utilization, and Storage (CCUS) technologies have been making headlines and attracting increasing amount of renewed attention, because they are in line with meeting global greenhouse gas reduction goals, and contributing towards climate control and sustainable development. The giant Abu Dhabi onshore field consists of 6 carbonate reservoirs. Several pilots, immiscible hydrocarbon gas injection and CO2 WAG, and a pattern immiscible gas injection WAG flood have been executed. Miscible gas injection EOR is therefore field proven. However, due to large field size, surface congestion constraints, geological and fluid variations, miscible gas injection EOR development by reservoir individually becomes complex and economically challenging. This paper presents a comprehensive study and recommends an integrated CCUS Hub development approach - enabling field-wide EOR development with several hundred million-barrels of incremental recovery. The study follows a step-by-step systematic method. Existing water flood performances were assessed first. History matched full field simulation then leads to identification of CO2 EOR targets by area/flank for each reservoir. These are referred to as sweet development areas. Available advanced PVT data were analysed and a multi-reservoir single equation of state developed. It has been found that only CO2 is miscible across all six reservoirs, while hydrocarbon gas is also miscible for the deepest two reservoirs. Dedicated fine scale sector models (EOR history matched where applicable) were developed to generate multiple CO2 EOR development scenarios, for example, depending on water flood maturity at the time of CO2 EOR start-up, and potential impact on incremental oil production, incremental oil recovery due to reservoir heterogeneity. First results from sector modelling show that quite a few areas/flanks would be sub-economical if CO2 EOR development on a stand-alone basis. Hence the concept of a CCUS Hub is proposed, which would allow sweet development areas in any or all of the six reservoirs to be developed from a single common surface Cluster. There is potential space for development phasing, allowing additional CO2 EOR developments within the same cluster area once ullage and CO2 supply becomes available. The CCUS Hub development approach facilitates optimization and sharing of injection/production flow-lines; surface space, gathering and processing facilities, CO2 supply, CO2 recovery unit deployment coupled with produced gas re-injection into the 2 deepest reservoirs. Compared to a more conventional development approach of reservoir by reservoir, considerable scope for CAPEX and OPEX savings was found. Assuming a constant future oil price, a reduction in development costs would allow more sweet development areas to pass the threshold of economical development, leading to an increase in overall incremental production and recovery from CO2 EOR.


2021 ◽  
Author(s):  
Jyun-Syung Tsau ◽  
Qinwen Fu ◽  
Reza Ghahfarokhi Barati ◽  
J. Zaghloul ◽  
A. Baldwin ◽  
...  

Abstract The hydrocarbon gas huff and puff (HnP) technique has been used to improve oil production in unconventional oil reservoirs where excess capacity of produced gas is available and hydrocarbon prices are in a range to result in an economically viable case. Eagle Ford (EF) is one of the largest unconventional oil plays in the United State where HnP has been applied for enhanced oil recovery (EOR) at reservoirs within various oil windows. Our previously published Huff-n-puff results on dead oil with produced gas from Eagle Ford (EF) showed the recovery factor of hydrocarbon varying from 40 to 58%. The objective of this paper is to extend the experiments to live oil with EF core plugs to investigate the mechanisms of HnP which are affected by the composition of injected gas and resident oil, injection and soaking time as well as injection/depletion pressure gradient. Eagle Ford live oil and natural gas produced from the target area were used for HnP tests. Four representative core plugs were used with the tests conducted at reservoir conditions (125 °C and 3,500 psi). The live oil experiments with four reservoir core plugs showed an improvement in oil recovery with recovery factor (RF) varying from 19.5 to 33 % in six cycles of HnP, whereas the primary depletion on the same core plug showed RF below 11 %. A lower recovery factor of HnP from live oil saturated core in this study was observed as compared to dead oil saturated core reported in a previous publication. It is attributed to a lesser diffusion effect on mass transfer between injected gas and resident oil when the core is saturated with live oil. This behavior is displayed by the pressure decline curve during the first soaking period. A sharper diffusion pressure decline occurred in the dead oil saturated core plug where a higher concentration gradient between injected gas and resident oil drives a faster gas transport into the oil due to the molecular diffusion during the soaking period.


2021 ◽  
Author(s):  
Omar Nazih Jadallah ◽  
Mujahed Saleh ◽  
Mohamed Rebbou Benberber ◽  
Upadhyay Arvind ◽  
Zhanibek Diltaiyev ◽  
...  

Abstract Drilling through fractured gas bearing formations to access the oil reserves underneath has been one of the most challenging tasks for the drilling Team due to the embedded risks such as; total circulation losses, Gas migration, well control issues, hole instability, cutting beds accumulation and stuck pipe. This paper explains an approach in drilling fractured gas bearing formations that was performed for the first time in offshore Abu Dhabi field-A, Pressurized Mud Cap Drilling (PMCD). Drilling through fractured Gas bearing formation causes the loss of the mud column and the consequent intrusion of hydrocarbon gas to the wellbore, thus initiating well control response, which adds to the flat time and might cause cutting slippage, stuck pipe and eventually loss of well objective. PMCD is best suited to deal with such situation, as it allows drilling to continue under the mentioned circumstances by filling the well with sacrificial fluid while the well is closed, fractures take seawater, cuttings and the formations pressure lefts the underbalanced annular fluid to reduce losses volume. Two wells were drilled successfully using the PMCD technique in Field A where the anticipated fracture gas bearing formations system was encountered shortly below the 9-5/8″ casing shoe. The performance increased substantially in the second well as lessons learnt were implemented to avoid any time loss. Drilling the 8-1/2″ Hole section started in well #2 conventionally with required 200 psi overbalance mud weight, the drilling fluid system is directly changed to sacrificial fluid (Sea water) once the fracture system is hit and total losses observed. A light Annular mud (Seawater) is pumped in the well's annulus. After having stable PMCD parameters, drilling continued at an ROP of 100-150 FPH. TQ & Drag real-time monitoring & intermittent pumping of 3 × 50 bbls weighted HVP to clean bit & BHA from cuttings were essential to avoid getting the pipe mechanically stuck. The 6,710 ft section was drilled successfully, Striped BHA Out of hole, Ran 7,160 ft of 7″ Liner, perform cement Job & achieved isolation. Comparing with offset wells drilling conventionally in field-A through the gas bearing fractured zone, PMCD saved +/− 44 days of the well time, cost and achieved the target. and greatly improved the operational safety by providing closed-loop drilling. The PMCD application on the two wells is the first of its type in offshore Abu Dhabi, it allowed accessing parts of the reservoir that have been inaccessible due to the fracture system. Additionally, it increased safety of operation & saved rig days that would have been spent in treating losses and well control operation. Pressurized Mud Cap Drilling application in field-A provides a solution for a wider implementation in developing fractured gas cap resources in future.


2021 ◽  
Vol 6 ◽  
pp. 11-19
Author(s):  
Igor Dolotovsky ◽  
Evgeni Larin

A novel polygeneration technology and equipment concept has been suggested for energy and water supply systems of oil and gas enterprises. It was created in order to enhance opportunities of mutual integration of power and manufacturing systems using recuperation and recycling. As an example, we have described a system which incorporates modules for combined energy resource and water generation as well as wastewater and low pressure hydrocarbon gas recycling. Feasibility of polygeneration and mutual integration was assessed with use of a multi-criterion concidering efficiency and effectiveness.


2021 ◽  
Vol 84 (1) ◽  
pp. 193-210
Author(s):  
Muhammad Roslan Rahim ◽  
Annisa Palupi Trisasongko ◽  
Mohammad Nazri Mohd Jaafar ◽  
Norazila Othman ◽  
Yahaya Ramli ◽  
...  

Gasification technologies have the potential to produce clean and efficient energy sources. This technology is capable of producing synthesis gas from low or negative carbon -based raw materials such as coal, petroleum coke, high sulfur fuel oil, waste or waste materials and biomass. The gas produced from the process is used to replace natural gas to generate electrical power, or acts as basic raw material for producing chemicals and liquid fuels. Gasification is a process which utilizes heat, pressure, and steam to convert materials directly into gases, such as carbon monoxide and hydrogen gases. Despite differing in various aspects, gasification technologies have four common engineering factors such as atmospheric gasification reactors (oxygen or air content level), internal and external heating, reactor design and operating temperature. Raw materials, either in dry form or small granules, are fed into the reactor chamber called gasifier. Raw materials subjected to heat, pressure as well as an environment with rich or low oxygen content. Hydrocarbon gas (also known as Syngas), liquid hydrocarbon (oil) and coal (carbon black and ash) are the three main products of gasification. Syngas can be used as a fuel to produce electricity or steam, or acts as a basic block for various types of chemicals. When mixed with air, Syngas can be used in petrol or diesel engines with slight modifications to the engine.


2021 ◽  
Vol 9 ◽  
Author(s):  
Hongwei Yu ◽  
Lu Wang ◽  
Daiyu Zhou ◽  
Fuyong Wang ◽  
Shi Li ◽  
...  

Stable gas gravity drainage is considered an effective method to enhance oil recovery, especially suitable for deep buried, large dip angle, and thick oil reservoirs. The influence of reservoir heterogeneity on controlling the gas–oil interface and sweep characteristics of injected gas is particularly important to design reservoir development schemes. In this study, according to the interlayer characteristics of Donghe carboniferous oil reservoirs in the Tarim Basin, NW China, 2D visual physical models are established, in which the matrix permeability is 68.1 mD and average pore throat radius is 60 nm. Then, hydrocarbon gas gravity drainage simulation experiments are carried out systematically, and a high-speed camera is used to record the process of gas–oil flow and interface movement. In this experiment, the miscible zone of crude oil and hydrocarbon gas is observed for the first time. The interlayer has an obvious shielding influence, which can destroy the stability of the gas–oil interface and miscible zone, change the movement direction of the gas–oil interface, and reduce the final oil recovery after gravity drainage. The remaining oil mainly is distributed near the interlayers. The higher displacement pressure leads to increased stability of the gas–oil displacement front and later gas breakthrough, which leads to higher oil recovery. The lower gas injection rate contributes to a slower front velocity and wider miscible zone, which could delay gas breakthrough. For the immiscible gas gravity drainage, there is a critical gas injection rate, with which the oil recovery factor is the highest.


Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Yong Qin ◽  
Haochuan Zhang ◽  
Chang Liu ◽  
Haifeng Ding ◽  
Tianyu Liu ◽  
...  

Abstract Field data indicates that oil production decline quickly and the oil recovery factor is low due to low permeability and insufficient energy in the tight oil reservoirs. Enhanced oil recovery (EOR) is required to improve the oil production rates of tight oil reservoirs. Gas flooding is a good means to supplement formation energy and improve oil recovery factor, especially for hydrocarbon gas flooding when CO2 is insufficient. Due to the permeability in some areas is too low, the injected gas cannot spread farther, and the EOR performance is poor. So multifractured horizontal well (MFHW) are usually used to assist gas injection in oilfields. At present, there are few studies on the optimization of hydrocarbon gas flooding parameters especially under the complex fracture network. This article uses unstructured grids to characterize the complex fracture networks, which more realistically shows the flow of formation fluids. Based on actual reservoir data, this paper establishes the numerical model of hydrocarbon gas flooding under complex fracture networks. The article conducts numerical simulation to analyze the effect of different parameters on well performance and provides the optimal injection and production parameters for hydrocarbon gas flooding in the M tight oil reservoir. The optimal injection-production well spacing of the M tight oil reservoir is about 800 to 900 m. The EOR performance is better when the total gas injection rates are about 0.45 HCPV, and gas injection rates of each well are about 3000 to 3500 m3/d (0.021 to 0.025 HCPV/a). The recommended injection-production ratio is about 1.1 to 1.2. This work can offer engineers guidance for hydrocarbon gas flooding of the MFHW with complex fracture networks. Hydrocarbon gas flooding in tight oil reservoirs can enhance oil recovery. The findings of this study can help for a better understanding of the influence of different parameters on hydrocarbon gas flooding in the M tight oil reservoir. This work can also offer engineers guidance for hydrocarbon gas flooding of the MFHW with complex fracture networks.


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