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Results
Compositional Changes in Athabasca Bitumen During Air Injection into Mature SAGD Chambers - Observations from 3-D Large Scale Experiments
Sequera-Dalton, Belenitza M. (University of Calgary) | Aminfar, Ehsan (University of Calgary) | Moore, Robert G. (University of Calgary) | Mehta, Sudarshan A. (University of Calgary) | Ursenbach, Matthew G. (University of Calgary)
Abstract Air injection into mature SAGD chambers is a promising method to sustain steam chamber pressures while reducing steam-to-oil-ratios (SOR) and increasing oil production in SAGD late life. The feasibility of attaining and sustaining a high temperature combustion front when injecting air into a steam chamber has been recently demonstrated with a three-dimensional (3-D) large scale experiment. In order to effectively mobilize bitumen, bond scission reactions are required to occur between the injected oxygen and the bitumen. The highly effective combustion process is accompanied by thermal cracking reactions which often produce lighter oil fractions and coke. However, low temperature oxidation reactions or oxygen addition to the bitumen may occur if oxygen rates are not sufficient to sustain the combustion front which in turn could degrade the bitumen properties. This paper focuses on the compositional changes observed on Athabasca bitumen during air injection after SAGD in a 3-D large scale experiment. Changes in bitumen properties, as measured from produced and residual oil samples, such as density, viscosity, asphaltenes content and hydrocarbon cut point distribution are presented. The well configuration in the 3-D experiment consisted of two well-pairs located near the bottom corners of the rectangular model. At the end of the SAGD period, air was injected into one of the injection wells while fluids were produced from both wells in the well-pair located on the other end of the model. Oil properties from produced liquid samples, captured from the upper and lower production wells during the test, as well as extracted oil from selected post-test core samples were analysed and correlated with time and their location in the 3-D model, respectively. Fluid segregation and distinctive fluid properties were observed in the samples produced from the upper and lower producer wells. A significant portion of produced oil samples exhibited lower density, viscosity and asphaltenes content than the original bitumen indicating that oil upgrading took place during the test. Post-test core samples were analysed during the excavation or unpacking of the 3-D model and their weights, visual appearance and 3-D location were recorded. Properties of oil extracted from selected post-test core samples also indicated the presence of upgraded oil in the residual hydrocarbons. The asphaltenes content in selected residual oil samples remained similar to that of the original oil. Significant amounts of upgraded oil produced during the 3-D experiments highlights the potential added benefits of air injection into mature SAGD chambers.
- South America > Argentina > Mendoza > Neuquen Basin > Llancanelo Field > Nuequen Group Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract The objective of this study was to develop and apply a non-chemical based environmentally preferable hydrogen sulfide scavenger that addresses secondary issues caused by current chemical scavengers like triazine and glyoxal and to confirm its ability to mitigate sulfide in different applications. Recombinant DNA and protein expression technologies were exploited to develop this novel H2S scavenger. This non-chemical scavenger (NCS) is generated by cloning the cDNA sequence from a thermophilic organism and expression of the encoded protein in suitable vector. Non-chemical based formulation was developed and blended in a pilot plant. The efficacy of the scavenger was evaluated in sour brine, crude oil and mixed production fluids from different sources. Sulfide concentrations before and after reactions in headspace were measured by using Dräger gas detection tubes (ASTM D5705). Corrosion testing was performed using kettle tests. Field assessment of the scavenger was carried out by treating sour oil at the Bakken oil field as per the field testing plan. In this study, H2S mitigation was addressed using a novel non-chemical scavenger generated from thermophilic bacteria from lab scale to pilot scale. Functional studies conducted by treatment of soured brine and oil revealed 72% and 90% reduction in H2S concentration respectively. The scavenger showed a 75% reduction of sulfide in simulated mixed production samples containing 30:70 ratio of brine and oil. Limited testing of this scavenger in field showed reduction of headspace sulfide from 400 ppm to 2 ppm. In addition, the field data showed less than 0.5% BS&W. The scavenger also showed no significant increase in corrosion during the scavenging reaction. These studies confirm that this novel non-chemical scavenger can be successfully used to mitigate H2S in various systems without causing adverse effects that were seen with chemical scavengers. A non-chemical scavenger has several advantages such as meeting environmental regulations, reducing, or eliminating secondary effects like solids formation, corrosion, scaling, and health hazards that are associated with current chemical scavengers.
- North America > United States > South Dakota (0.25)
- North America > United States > North Dakota (0.25)
- North America > United States > Montana (0.25)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Abstract This paper presents a new workflow for the simulation of in-situ combustion (ISC) dynamics. In the proposed method, data from kinetic cell experiments, depicting the combustion chemistry, are tabulated and graphed based on the isoconversional principle. The tables hold the reaction rates used to predict the production and consumption of chemical species during in-situ combustion. This new method of representing kinetics without the Arrhenius method is applied on one synthetic and two real kinetic cell experiments. In each case, the new method reasonably captures the reaction pathways taken by the reacting species as the combustive process occurs. A data-density sensitivity study on the tabulated rates for the real case shows that only four experiments are required to capture adequately the kinetics of the combustion process. The results are, however, found to be sensitive to the size of the time step taken. The method predicts critical changes in the reaction rates as the experiment is exposed to different temperature conditions, thereby capturing the speed of the combustion front, temperature profile, and fluid compositions of a simulated combustion tube experiment. The direct use of the data ensures flexibility of the reaction rates with time and temperature. In addition, the non-Arrhenius kinetics technique eliminates the need for a descriptive reaction scheme that is typically computationally demanding, and instead focuses on the overall changes in the carbon oxides, oil, water and heat occurring at any time. Significantly, less tuning of parameters is required to match laboratory experiments because laboratory observations are easier to enforce.
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
Abstract Increased surface area of reservoir rock due to the presence of clays and the catalytic impact of clays are known to enhance the in-situ combustion (ISC) performance. But the basics behind these mechanisms are still not known. In this study, we investigated the role of clays on ISC in microscopic scale. Six one-dimensional combustion tube experiments were conducted on three different crude oil samples. The combustion performance of each crude oil was evaluated with two combustion runs; reservoir rock prepared with sand-oil and with sand-clay-oil mixtures. Each combustion tube test was evaluated in terms of cumulative oil production, combustion front propagation, and characterization of the produced oil samples. Activation energy and heat of combustion were calculated empirically. Quality of the produced oil samples was determined through viscosity measurements. Saturates, aromatics, resins, and asphaltenes (SARA) fractions of initial and produced oil samples were compared. To better understand the fuel formation mechanism, asphaltenes surfaces were visualized by a Scanning Electron Microscope (SEM) and SARA fractions with Fourier Transform Infrared (FTIR). Combustion tube experimental results highlight that crude oil type affects the process performance the most. Clay presence in the rock expedited the combustion front velocity by increasing the oxygen utilization rate. Activation energy was reduced drastically with the presence of clays, however, the heat of combustion has not changed. Thus, the generated heat has been consumed more effectively with the presence of clays. Produced oil quality has been increased significantly in terms of viscosity, more viscosity reduction was observed with the presence of clays. Since saturates acts like an ignitor during ISC, the amount of saturates fraction was decreased in produced oil when compared to initial oil. While the amount of aromatics fraction was increased significantly, the asphaltenes fraction is decreased with the presence of clays when compared to the aromatics and asphaltenes fractions of the initial oil. The reduction in viscosity is mainly due to increased aromatics content of produced oil with high solvent power. With the SEM images taken on asphaltenes surface, the role of clays has been observed clearly on fuel formation. With the presence of clays, the asphaltenes surface have created cribriform structures. Without clays, asphaltenes surfaces were observed as smooth surface. Those holes should increase the surface area on asphaltenes surfaces and increase the effective transformation of asphaltenes into fuel.
- South America (0.68)
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Oil recovery following in-situ combustion (ISC) is highly dependent on initial oil saturation. The mechanisms leading to this dependence are not well understood due to the complexity of the reaction pathways leading to oil upgrading. We hypothesize that this dependence can be explained through a reductionist chemical model based on Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractionation. We then substantiate this model with five combustion tube experiments, and by performing SARA fractionation on produced oils. The combustion tube experiments are conducted at identical experimental conditions but varying initial oil saturations of 13%, 26%, 34%, 42%, and 53%. The produced oil samples are examined with viscosity and API gravity measurements and weight of SARA fractions. Analysis of SARA fractions is performed with Fourier Transform InfraRed Spectroscopy (FTIR). The oil recovery and the produced gas and temperature profiles are used to define the dominant reaction type that occurred throughout the experiments, namely High Temperature Oxidation (HTO) or Low Temperature Oxidation (LTO) reactions. Metal content of the produced water samples are determined with Inductive Coupled Plasma-Mass Spectroscopy (ICP-MS). The highest temperature, with greatest oil recovery and the highest carbon dioxide concentration are observed in the experiment conducted with 42% initial oil saturation in which the HTO reactions dominate the reaction path. However, the higher oxygen and lower carbon dioxide yields observed during the experiments with 13% and 26% initial oil saturations indicate that those experiments are controlled mainly by the LTO reactions. The experiments which show dominance in HTO reactions produce low density but higher viscosity oil. On the other hand, a reverse relationship is observed for cases with LTO reaction dominance. The analysis of SARA fractions with FTIR displays significant variations in molecular structure of aromatic fractions only. A quantitative analysis of resins to aromatics ratio strongly correlates with the viscosity of the samples. Hence, we conclude that resins to aromatics ratio governs the viscosity reduction and the molecular structure of the aromatic fraction seems to be the leading factor of density improvement. ICP- MS analysis on produced water show that the dominance of the HTO reactions reduces the water-oil interaction, which leads to the production of more neutral pH water. ISC is one of the most efficient thermal enhanced oil recovery methods in which maximum oil recovery can be attained. However, the complexity of the chemical reactions taking place during the process make this process difficult to understand and control. In this study, we provide a reductionist chemical model based on SARA fractionation to explain the reaction pathways describing the in-situ oil upgrading mechanisms and the dependence of oil recovery on initial oil saturation.
- North America > United States (1.00)
- North America > Canada > Alberta (0.70)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
The Influence of Pressure on the Low Temperature Oxidation (LTO) of Heavy Oil During the High Pressure Air Injection(HPAI)Process in Tahe Oilfield
Li, Yi-Bo (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Cheng-Yuan, Dong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Pu, Wan-Fen (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Jin, Fa-Yang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Chen, Ya-Fei (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Li, Dong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Zhao, Jiang-yu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China) | Zhao, Jin-Zhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People's Republic of China)
Abstract With the decline of conventional oil production, developing and producing heavy oil resources efficiently are becoming more important. High pressure air injection (HPAI) is generally considered as an efficient method to drive the crude oil in light oil reservoir. But there is a debate about whether the released heat from oxidation reaction is able to activate the heavy oil effectively. Comparing to the in-situ combustion (ISC) technique, air injection without ignition will reduce the operation difficulty and eliminate the security risk. Thus studying the changing of the oil property in presence of injected air is the prerequisite to apply the HPAI technique in heavy oil reservoir. For this purpose, the constant temperature oxidation experiments have been carried to study the influence of pressure on heavy oil in the air injection process at reservoir condition of Tahe oilfield. The results showed that the pressure has obvious influence on the crude oil property. By the increment of pressure, the oxygen in the air presented a decreasing trend while the amount of carbon dioxide did not exhibit an increasing trend. The oxidation addition reaction dominated the reaction type. For the oil phase, the viscosity of the oxidized oil presented a slight decrease under relative low pressure condition. When the pressure reached 50MPa, the crude oil has transferred into coke completely. During the oxidation process, the property and amount of the coke directly related to the released heat amount in the high temperature oxidation (HTO) stage. According to the thermogravimetry (TG) and differential scanning calorimetry (DSC) results, the oxidized oil achieved lower HTO trigger temperature. So it is believed that the higher pressure has a positive influence on the coke deposit process. The formation of sufficient coke will bring the possibility for the application of HPAI technique in heavy oil reservoirs.
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- Oceania > Australia > Queensland > Eromanga Basin (0.99)
- Oceania > Australia > Northern Territory > Eromanga Basin (0.99)
- (3 more...)
Summary The effect of nickel nanoparticles on in-situ upgrading of heavy oil (HO) during aquathermolysis and the effect of this process on the recovery through cyclic steam injection were studied. High-temperature experiments were conducted with a benchtop reactor to study the kinetics of the reactions among oil, water, and sandstones in the presence and absence of the nickel nanoparticles. Eighteen experiments were conducted at three different temperatures and at three different lengths of time, and the evolved hydrogen sulfide during the reaction was analyzed. The kinetic analysis showed that nickel nanoparticles reduce the activation energy of the reactions corresponding to the generation of hydrogen sulfide by approximately 50%. This reaction was the breakage of C-S bonds in the organosulfur compounds of the HO. The maximal catalysis effect was observed to be at a temperature of approximately 270°C. Also, the simulated-distillation gas-chromatography (GC) analysis of the oil sample, after the aquathermolysis reactions, confirmed the catalysis effect of nickel nanoparticles. According to this analysis, by catalytic process, the concentration of the components lighter than C30 increased whereas the concentration of heavier components decreased. Next, the effect of the catalytic aquathermolysis on the recovery factor of the steam-stimulation technique was studied. The stimulation experiments consisted of three injection/soaking/production phases. The results showed that the nickel nanoparticles increased the recovery factor by approximately 22% when the nanoparticles were injected with a cationic surfactant and xanthan-gum polymer. This increase of recovery was approximately 7% more than that of the experiment conducted with the surfactant and polymer only.
- Asia > Middle East (0.46)
- North America > Canada > Alberta (0.29)
Abstract Heterogeneity and depth rule out steam injection and in-situ combustion processes for heavy-oil recovery in deep naturally fractured reservoirs (NFR). Once it is controlled by a proper injection scheme and the consumption of air injected through efficient diffusion into the matrix, low temperature air injection (LTAI) can be an alternative technique for heavy-oil recovery from deep NFRs. Limited studies on light oils showed that this process was strongly dependent on an oxygen diffusion coefficient and matrix permeability, both of which are typically low. A new approach, i.e., the addition of hydrocarbon solvent gases into air is expected to improve the diffusivity of the gas mixture and to accelerate the oxidation reaction to breakdown asphaltenic molecules effectively. This improves the gravity drainage recovery from the matrix. To study this new idea called low temperature air-solvent injection (LTASI), laboratory tests were performed by immersing heavy-oil saturated cores into air¬ solvent filled reactors to determine the critical parameters on recovery, diffusion coefficient, oxidation kinetics, viscosity reduction, and gravity drainage rate. It is imperative that enough time is given for the diffusion process before injected air filling to fracture network breakthrough. This implies that huff and puff injection is an option as opposed to the continuous injection of air. A high recovery factor was obtained by soaking a single matrix in an air-solvent chamber at static conditions rather than with air only. The period of pressure stabilization was faster for the air-solvent mixture atmosphere than in 100% solvent. The asphaltene content was lowered more in the air-solvent chamber than in a 100% air case.
- Asia (0.68)
- North America > Mexico (0.46)
- North America > Canada > Alberta (0.29)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Mexico > Tabasco > Bellota-Jujo > Sureste Basin > Comalcalco Basin > Cardenas Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Feasibility Study of Air Injection for IOR in Low Permeability Oil Reservoirs of XinJiang Oilfield China
Hou, Shengming (China University of Petroleum, Dongying 257061, China) | Ren, Shao Ran (China University of Petroleum, Dongying 257061, China) | Wang, Wei (China University of Petroleum, Dongying 257061, China) | Niu, Baolun (China University of Petroleum, Dongying 257061, China) | Yu, Hongmin (Sinopec, Beijing 100083, China) | Qian, Genbao (XinJiang Oilfield Co. Ltd., PetroChina, Kalamayi 834000, China) | Gu, Hongjun (XinJiang Oilfield Co. Ltd., PetroChina, Kalamayi 834000, China) | Liu, Baozhen (XinJiang Oilfield Co. Ltd., PetroChina, Kalamayi 834000, China)
Abstract Xinjiang oilfield is located in the Northwest of China, in which large oil reserves have been discovered in reservoirs with very low permeability (<14×10μm). These reservoirs are featured with light oil in moderate depth, high reservoir pressure, but relatively low reservoir temperature (65~78°C) and low oil viscosity (<10mPa•s). Primary production and limited water flooding experience have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Gas injection has been optioned as an alternative secondary or tertiary technique to maintain reservoir pressure and/or increase sweeping and displacement efficiency. In this study, the feasibility of air injection via a low temperature oxidation (LTO) process has been studied. Laboratory experiments were focused on LTO characteristics of oil samples at low temperature range and core flooding using air at various reservoir conditions. Reservoir simulation studies were conducted in order to predict the reservoir performance under the air injection scheme and to optimize the operational parameters. The oxygen consumption rates at reservoir temperature and IOR potentials at different reservoir conditions were assessed for a number of selected reservoirs in the region. A pilot project has been designed based on experimental data, reservoir simulation results and field experience of air injection gained in other regions of China. Issues related to safety and corrosion control during air injection and the project economics were also addressed in the paper.
- Asia > China (1.00)
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.29)
- North America > United States > South Dakota (0.28)
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- Oceania > Australia > Queensland > Eromanga Basin (0.99)
- Oceania > Australia > Northern Territory > Eromanga Basin (0.99)
- (13 more...)
In Situ Upgrading Extra-heavy Oil by Catalytic Aquathermolysis Treatment Using a New Catalyst based Anamphiphilic Molybdenum Chelate
Wu, Chuan (China University of Petroleum) | Lei, Guanglun (China University of Petroleum) | Yao, Chuanjin (China University of Petroleum) | Jia, Xiaofei (China University of Petroleum)
Abstract The aquathermolysis of Shengli extra-heavy oil during steam stimulation was studied by using anamphiphilic molybdenum chelate-aromatic sulfonic iron as catalyst for the reaction in this papers. The laboratory experiment shows that the viscosity reduction ratio of heavy oil is over 97.15% at 200°C, 24 hr, 0.2 % catalyst solution. The viscosity of upgraded heavy oil is changed from 524.5Pa·s to 14.95mPa·s at 50°C. The chemical and physical properties of heavy oil both before and after reaction were studied by using Fourier transform infrared (FT-IR) spectroscopy, gas chromatography/mass spectrometry (GC-MS), elemental analysis (EL). The percentage of saturate aromatic and H/C increased, and resin, asphalt and S, O, N decreased after the aquathermolysis. The changes of the composition and structure of the heavy oil can lead to the viscosity reduction and improve the quality of heavy oil. It has shown that the mechanism of aquahtermolysis is discussed further. We found the new mechanism of catalyst not only broken C-S bond, but also broken C-O and C-N bonds, and accelerated the reaction of aquathermolysis. The results are very useful for the popularization and application of the new technology for the insitu upgrading of heavy oil by aquathermolysis.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- Asia > China > Henan > Nanyang Basin > Biquan 10 Block > Henan Field > Hetaoyuan Formation (0.99)