Extra Heavy Oil Research Articles

Effect of Changing Crude Oil Grade on Slug Characteristics and Flow Induced Mechanical Stresses in Pipes

Slug multiphase flow is known to be the most prevalent regime because of its extensive encounters associated with chaotic behaviour, complexity and instability that cause significant fluctuations in operating conditions and thus lead to undesirable effects. In this study, the effect of varying crude oil grades on slug characteristics is numerically investigated. A partitioned one-way coupling framework of fluid–structure interaction (FSI) one-way coupling framework is adopted to investigate the influence of changing oil grades and slug characteristics on the maximum induced stresses in horizontal carbon steel pipe. It was found that increasing crude oil density causes frequent slugging and promotes the formation of liquid slugs further upstream near the inlet with high translational velocity and short wavelength. Therefore, the maximum induced stresses resulting from the interaction between slugs and the inner surface of pipes are strongly dependent on crude oil grade. In modelling extra heavy crude oil, a 40% increase in maximum induced stresses is recorded when the liquid superficial velocity decreases from 1 to 0.86 m/s at a constant natural gas superficial velocity.

Effects of Al2O3-NiO, TiO2 and (Mg,Ni)O particles on the viscosity of heavy oil during aquathermolysis

Heavy and extra heavy oils make up 70% of the world's reserves, due to their high viscosity and complex composition, they have problems for recovering. Conventional methods are responsible for approximately 30% recovery of crude oil from reservoir. The enhanced oil recovery (EOR) techniques can reach higher values. The steam injection is the most used technique which heats the oil and reduces de viscosity. The thermal reduction of the viscosity is also followed an incipient cracking, a phenomenon promoted by the presence of hot steam water. This work studies the effect of presence of nanoparticles during steam injection (aquathermolysis), that can generate a more effective catalytic effect, which enhances the incipient cracking and the decreasing of the crude oil viscosity. A heavy oil with a viscosity of 4730 cP at 25 °C was used on a bench scale reactor to evaluate the effects of residence time, temperature, type and concentration of three different nanoparticles (Al2O3-NiO, TiO2 and (Mg, Ni) O) on viscosity and composition of crude oil. The addition of (Mg,Ni)O and TiO2 provided similar viscosity and sulfur content reductions during the aquathermolysis. The results showed that the presence of TiO2 nanoparticles during aquathermolysis can improve the quality of the oil, by reducing the heavy fractions, and its viscosity up to 13.4%.

Experimental and numerical investigation on extra-heavy oil recovery by steam injection using vertical injector -horizontal producer

Steam injection is the most popular used method in recovering heavy oil reservoirs. Many researchers were engaged in enhancing oil recovery (EOR) methods by using various well configurations. Laboratory experiments and field applications have verified the feasibility of extra-heavy oil recovery by steam injection using vertical injector -horizontal producer. It was also referred to as a steam assisted gravity drainage (SAGD) process. However, the characteristic of steam chamber growth and production performance during the vertical injector-horizontal producer steam injection process have not been fully understood. In this study, a 3D physical model was constructed to investigate the mechanisms of the steam injection process using vertical injector-horizonal producer. Numerical simulations were also conducted to verify the laboratory experiment and field application. In the aspect of steam chamber growth, the results revealed that three stages were included during the steam injection process. In the aspect of developing mechanisms, it can be divided into steam flooding and gravity drainage stages. Moreover, the results show that about 43.9% of original oil in place (OOIP) was produced in the gravity drainage stage. In addition, subcool showed significant difference in steam flooding and gravity drainage stages. The temperature distribution mode of the horizontal producer was analyzed and proved to be a significant factor that influences the production performance. Sensitivity analysis by using numerical simulation demonstrated that oil viscosity is the dominant factor that impact the production performance. The results guided the development of pilot test area in Xinjiang Oilfield, China. The study can provide a clearer understanding of the vertical injector-horizontal producer steam injection process in recovering heavy oil reservoirs.

PROBABLE MORTALITY OF Holothuria (Halodeima) grisea (SELENKA, 1867) (ECHINODERMATA, HOLOTHUROIDEA) AFTER ACUTE IMPACT OF OIL SPILL IN THE NORTHEAST OF BRAZIL IN 2019

The Brazilian northeastern coast suffered in 2019 the greatest acute impact of oil in the country’s history, with all states in the region being affected by extra-heavy oil. Holothuria (Halodeima) grisea is a detritivorous holoturoid, which ingests sediment to feed, and can passively ingest oil from spills existing in the sediment. To investigate the occurrence of oil in the intestinal content of H. (H.) grisea, a N of 20 individuals was collected on the Salvador coast (BA) in October 2019 between the coordinates 12°57 ‘S / 38°20’ W. Of this total, 10 individuals were found dead in the environment and 10 collected alive, for comparison purposes. Of the individuals found dead, 40% were eviscerated (without intestines) and it was not possible to carry out content analysis. Of the 6 remaining dead individuals, 67% had oil in their intestinal contents. For the 10 live sea cucumbers collected, none was eviscerated and all had a full intestine, with oil being observed in the intestinal content of 1 specimen (10%). The χ2 test confirmed with α of 0.025 the possible relationship between oil and the mortality of H. (H.) grisea, demonstrating that the acute oil spill probably was lethal for this species on the northeastern coast of Brazil.
 Keywords: sea cucumber, hydrocarbons, PAHs.

Role of Intermolecular Forces on Surfactant-Steam Performance into Heavy Oil Reservoirs

SummaryThis study investigates the role of polar fractions of heavy oil in the surfactant-steamflooding process. Performance analyses of this process were done by examination of the dipole-dipole and ion-ion interactions between the polar head group of surfactants and the charged polar fraction of crude oil, namely, asphaltenes.Surfactants are designed to reduce the interfacial tension (IFT) between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the IFT by aligning themselves at the interface of these two immiscible fluids; this way, their polar head group can stay in water and nonpolar tail can stay in the oil phase. However, in heavy oil, the crude oil itself has a high number of polar components (mainly asphaltenes). Moreover, the polar head group in surfactants is charged, and the asphaltene fraction of crude oils carries reservoir rock components with charges. The impact of these intermolecular forces on the surfactant-steam process performance was investigated with 10 coreflood experiments on an extraheavy crude oil. Nine surfactants (three anionic, three cationic, and three nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltene fractions of produced oil and residual oil samples.The differences in each group of surfactants tested in this study are the tail length. Results indicate that a longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of anionic surfactants resulted in higher oil recovery. Further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil, giving higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on the polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltene surface charges were becoming lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with the polar head of surfactants, then the recovery rate increases.Our study shows that the surfactant-steamflooding performance in heavy oil reservoirs is controlled by the interaction between asphaltenes and the polar head group of surfactants. Accordingly, the main mechanism that controls the effectiveness of the process is the ion-ion interaction between the charges in asphaltene surfaces and the polar head group of crude oils. Because crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.

Study on Viscosity Reducer Flooding Technology for Deep Low Permeability Extra Heavy Oil Reservoirs

Deep low permeability extra heavy oil reservoir has the characteristics of high formation pressure, high crude oil viscosity, and low permeability. Conventional steam injection thermal recovery has poor viscosity reduction performance and low productivity of a single well, which makes it difficult to develop this type of heavy oil reservoir. In this paper, core flooding experiment and microvisualization equipment were used to study the mechanism of improving the recovery of deep extra heavy oil by using water-soluble viscosity reducer; the realization of water-soluble viscosity reducer in numerical simulation was achieved by using nonlinear mixing rule; the reservoir numerical simulation model of water-soluble viscosity reducer displacement in test well group was established to optimize the development technical parameter of water-soluble viscosity reducer. The results show that compared with waterflooding, the oil displacement efficiency of water-soluble viscosity reducer is increased by 12.7%; water-soluble viscosity reducer can effectively reduce the viscosity of extra heavy oil, under the same temperature and permeability, the higher the concentration of viscosity reducer, the better the viscosity reduction effect, and the smaller the pressure gradient required at the same injection rate; the main mechanism of water-soluble viscosity reducer for enhancing oil recovery is to form oil in water emulsion, which can reduce the viscosity and interfacial tension of crude oil and reduce the residual oil saturation; in the pilot well group, the optimized injection concentration of water-soluble viscosity reducer is 3%, and the optimal injection amount of water-soluble viscosity reducer solution is 50 t/d; water-soluble viscosity reducer displacement was implemented in the pilot well group, the average daily oil of well group was increased from 1.8 t/d to 7.34 t/d, and the pilot well group has achieved good development performance.

Exothermal Property and Kinetics Analysis of Oxidized Coke and Pyrolyzed Coke from Fengcheng Extra-Heavy Oil

The exothermic combustion characteristics of coke play a direct and essential role in artificial ignition and the stability of the combustion front during the heavy oil in situ combustion (ISC) pro...

PVT modeling of complex heavy oil mixtures

This paper describes a systematic approach to model the phase and volumetric behavior of extra heavy oil and light solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the heavy oil sample. A gamma molar distribution model is used to fit the crude assay data, then single-carbon-number (SCN) fractions are defined up to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components. Pure solvent-crude oil mixture PVT experimental data are analyzed and used to tune the EOS model. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures. The prediction of the final EOS model provides accurate prediction against measured PVT data for mixtures of extra-heavy oil sample and synthetic combustion gas solvents made up of CO2, N2, C1, and C2. For viscosity modeling, we propose a novel technique to model large variation of viscosity for a wide range of pressures, temperatures and solvent compositions. In our proposed approach, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure the LBC correlation estimates SCN viscosities as given by a modified Twu correlation. The viscosity predictions of the pure-solvent-saturated heavy oil at varying temperatures, the EOS/LBC model results in poor agreement against measured saturated viscosity data. Our solution was to split the heaviest fraction C90+ into two sub-fractions, where only critical volumes differ, resulting in “lower-viscous” and “higher-viscous” C90+ fractions (C90+L into C90+H). We find that the fraction of C90+L (fL) correlates well against pure solvent solubility and temperature, resulting in an accurate overall viscosity fit. The final EOS/LBC model is successfully employed to predict measured PVT and viscosity data that was not used during the training process. Our new approach can provide accurate phase properties and volumetric behavior calculations and as well as good predictions of large variation of liquid viscosity. Such developed EOS technique is vital for providing an accurate estimation of phase behavior and volumetric properties, and the viscosity variations required for modeling thermal-EOR techniques.

Application and Exploration of Early In-Situ Combustion Huff-and-Puff Technology in a Deep Undisturbed Reservoir with Extra Heavy Oil

Summary Achieving effective results using conventional thermal recovery technology is challenging in the deep undisturbed reservoir with extra-heavy oil in the LKQ oil field. Therefore, in this study, a novel approach based on in-situ combustion huff-and-puff technology is proposed. Through physical and numerical simulations of the reservoir, the oil recovery mechanism and key injection and production parameters of early-stage ultraheavy oil were investigated, and a series of key engineering supporting technologies were developed that were confirmed to be feasible via a pilot test. The results revealed that the ultraheavy oil in the LKQ oil field could achieve oxidation combustion under a high ignition temperature of greater than 450°C, where in-situ cracking and upgrading could occur, leading to greatly decreased viscosity of ultraheavy oil and significantly improved mobility. Moreover, it could achieve higher extra-heavy-oil production combined with the energy supplement of flue gas injection. The reasonable cycles of in-situ combustion huff and puff were five cycles, with the first cycle of gas injection of 300 000 m3 and the gas injection volume per cycle increasing in turn. It was predicted that the incremental oil production of a single well would be 500 t in one cycle. In addition, the supporting technologies were developed, such as a coiled-tubing electric ignition system, an integrated temperature and pressure monitoring system in coiled tubing, anticorrosion cementing and completion technology with high-temperature and high-pressure thermal recovery, and anticorrosion injection-production integrated lifting technology. The proposed method was applied to a pilot test in the YS3 well in the LKQ oil field. The high-pressure ignition was achieved in the 2200-m-deep well using the coiled-tubing electric igniter. The maximum temperature tolerance of the integrated monitoring system in coiled tubing reached up to 1200°C, which provided the functions of distributed temperature and multipoint pressure measurement in the entire wellbore. The combination of 13Cr-P110 casing and titanium alloy tubing effectively reduced the high-temperature and high-pressure oxygen corrosion of the wellbore. The successful field test of the comprehensive supporting engineering technologies presents a new approach for effective production in deep extra-heavy-oil reservoirs.

Technology Focus: Heavy Oil (April 2021)

After serving two terms for a total of 6 years, my time writing this column is coming to an end. This issue of JPT marks my last opportunity to share my thoughts, recap my observations, and make note of some final touch-ups to the research conducted over this 6-year period with regard to recent heavy oil practices. Here are some highlights to keep in our minds over the coming years. Despite all the recent negative and serious changes affecting the whole world and our industry, life goes on and we will increasingly be needing energy. One should recall that statistics predict oil will continue to be the main source of energy for the next 2 decades, with heavy oil constituting a great portion of that. That means that, while the oil industry is going through unprecedented and even unpredictable economic downturns, the status of heavy oil is still unquestionable. However, we have to face the fact that this energy should be tapped in a cheap, clean, and sustainable way. The best aspect of this effort is that heavy oil technologies have been established and tested over a long period of time, unlike other unconventional resources. Lowered steam consumption, down to zero if possible, has been under consideration to minimize the emission of greenhouse gases (GHGs) while simultaneously producing heavy oil. This green effort leads us to nonsteam techniques such as the use of water with chemicals (mainly polymer) and noncondensable gases and certain unconventional methods such as solvent injection and electromagnetic heating, the latter being unavoidable especially for extraheavy oil and bitumen. These areas have been critically considered by researchers and practitioners with a considerable number of applications existing at the field scale. At the same time, the oil industry must deal with mature steam projects in the near future. We have accumulated so much heat energy over the decades, yet a substantial amount of oil remains in these reservoirs. What can be done to reuse this energy? Can we recover different forms of energies using methods with no GHG emission? The current practices encountered in field-scale operations to improve the heavy oil recovery in mature steam applications use noncondensable gases; mainly, these techniques serve to pressurize steam-assisted gravity drainage wells, improve sweep and microscopic displacement by adding chemical additives to the steam (or hot water), and re-engineer well designs (flow control for efficient heating and sweep). My final example highlighting new practices is the increasing trend of offshore heavy oil practices. Of particular interest is polymer injection through vertical and horizontal wells and pilot steam applications, methods that are effective even if they occur at the pilot stage of the process. Recommended additional reading at OnePetro: www.onepetro.org. SPE 199947 - Enhanced Oil Recovery in Post-Cold Heavy Oil Production With Sand Heavy Oil Reservoirs of Alberta and Saskatchewan Part 2: Field Piloting of Cycling Solvent Injection by Gokhan Coskuner, Consultant, et al. SPE 199925 - Scalable Steam Additives for Enhancing In-Situ Bitumen Recovery in SAGD Process by Armin Hassanzadeh, Dow, et al. SPE 199927 - The Myth of Residual Oil Saturation in SAGD - Simulations Against Reality by Subodh Gupta, Cenovus Energy, et al.

Analytical modeling of the oil steam ratio during the lifetime steam-assisted gravity drainage process in extra-heavy oil reservoirs

An analytical model to predict the steam oil ratio (SOR) of the steam-assisted gravity drainage (SAGD) process, including the growing up, expanding and depletion of the steam chamber development, is proposed through the use of steam chamber development modes, energy balance, and mass balance. The calculated instantaneous steam oil ratio (ISOR) and cumulative steam oil ratio (ISOR) using the new analytical model are compared and validated with other analytical models results and numerical simulation results. The results showed that the new analytical model can predict the changing of SOR during the lifetime of the SAGD process more accurately than other analytical models. In addition, it had a high agreement with the numerical simulation results. Additionally, the new model could predict more parameters, including water cut, steam quality, heat proportion in different parts of a reservoir than previous models. This model could be a fast-effective guide for the design, prediction, and adjustment of field dual-horizontal SAGD well pairs.

Effect of in Situ Formed Emulsions on Enhanced Extra-Heavy Oil Recovery by Surfactant Flooding

Thermochemical flooding is becoming more popular nowadays as a subsequent EOR method after thermal recovery in extra-heavy oil reservoirs. During this process, in-situ emulsions could happen due to interfacial active components existing in heavy crude oil. The enhanced oil recovery is inevitably related with the formation of emulsions, which is one of the main mechanisms and deserves a thorough study. Also, the features of relative permeability curves during thermochemical flooding should be investigated further, because they are very important but usually are difficult to obtain since physical reactions could happen.Based on core-flooding experiments, combined with careful observation of produced crude oil emulsion morphology, this paper compared and analyzed the features of relative permeability curves and displacement efficiency at different conditions, and the mechanisms of extra-heavy oil production by surfactant displacement is then investigated. The surfactant used are provided by the oilfield at a varied mass fraction of 0.1%, 0.2% and 0.3% and under temperature of 100, 150 and 180 °C. The relative permeability data were processed with JBN method.The experimental results show that both the oil and water relative permeability increase as the temperature increases. As surfactant concentration increases, the relative permeability of the aqueous phase decreases as opposite to oil. The ultimate recovery increased with the increase of temperature and surfactant concentration. Except for the oil viscosity reduction by surfactant, it is interesting to note that the formation of crude oil emulsions (mainly O/W emulsions) are observed to be positively impacting the oil recovery factor. As surfactant concentration increases, larger size of dispersed phase in the emulsions were observed in the effluent corresponding to a higher oil recovery factor. This work is of great significance for heavy oil research and field development.

Rivet-like iron oxide nanoparticles and their catalytic effect on extra heavy oil upgrading

In this paper, rivet-like iron oxide nanoparticles were synthesized via a one-pot hydrothermal method for the first time. SEM and TEM results demonstrated that the as-prepared rivet-like nanoparticle consisted of two parts, a head part with an average size of 50 nm, and a tail one with a diameter of 20–40 nm and a length of ca. 100 nm. XRD result revealed that this nanoparticle had a dominant hematite phase and minor goethite phase. The rivet-like iron oxide nanoparticles exhibited higher catalytic activity for the upgrading of Shengli-oilfield extra heavy crude oil than the cubical α-Fe2O3 nanoparticles in the absence of hydrogen donors. In particular, owing to the site-rich surface of the catalyst, the viscosity of the Shengli extra heavy oil decreased from 244520 mPa∙s to 152000 mPa∙s (at 50 °C) in the presence of the 400 °C-treated nanoparticles after the reaction at 200 °C for 24 h. Higher exposure of (104) facet could possibly also account for the higher catalytic activity.

Extra-Heavy Oil Aquathermolysis Using Nickel-Based Catalyst: Some Aspects of In-Situ Transformation of Catalyst Precursor

In the present work, we studied the catalytic performance of an oil-soluble nickel-based catalyst during aquathermolysis of oil-saturated crushed cores from Boca de Jaruco extra-heavy oil field. The decomposition of nickel tallate and some aspects of in-situ transformation of the given catalyst precursor under the steam injection conditions were investigated in a high-pressure batch reactor using XRD and SEM analysis methods. The changes in physical and chemical properties of core extracts after the catalytic aquathermolysis process with various duration were studied using gas chromatography for analyzing gas products, SARA analysis, GC-MS of saturated and aromatic fractions, FT-IR spectrometer, elemental analysis, and matrix-activated laser desorption/ionization (MALDI). The results showed that nickel tallate in the presence of oil-saturated crushed core under the injection of steam at 300 °C transforms mainly into nonstoichiometric forms of nickel sulfide. According to the SEM images, the size of nickel sulfide particles was in the range of 80–100 nm. The behavior of main catalytic aquathermolysis gas products such as CH4, CO2, H2S, and H2 depending on the duration of the process was analyzed. The catalytic upgrading at 300 °C provided decrease in the content of resins and asphaltenes, and increase in saturated hydrocarbon content. Moreover, the content of low-molecular alkanes, which were not detected before the catalytic aquathermolysis process, dramatically increased in saturates fraction after catalytic aquathermolysis reactions. In addition, the aromatics hydrocarbons saturated with high molecular weight polycyclic aromatic compounds—isomers of benzo(a)fluorine, which were initially concentrated in resins and asphaltenes. Nickel sulfide showed a good performance in desulfurization of high-molecular components of extra-heavy oil. The cracking of the weak C–S bonds, which mainly concentrated in resins and asphaltenes, ring-opening reactions, detachment of alkyl substitutes from asphaltenes and inhibition of polymerization reactions in the presence of catalytic complex reduced the average molecular mass of resins (from 871.7 to 523.3 a.m.u.) and asphaltenes (from 1572.7 to 1072.3 a.m.u.). Thus, nickel tallate is a promising catalyst to promote the in-situ upgrading of extra-heavy oil during steam injection techniques.

Extra-Heavy Crude Oil Viscosity Reduction Using and Reusing Magnetic Copper Ferrite Nanospheres

The main objective of this study is the synthesis, use, and reuse of magnetic copper ferrite nanospheres (CFNS) for extra-heavy oil viscosity reduction. The CFNS were synthesized using a solvothermal method resulting in mean particle size of 150 nm. Interactions of CFNS with the crude oil were evaluated through asphaltene adsorption isotherms, as well as static and dynamic rheology measurements for two cycles at 25 °C. Adsorption and desorption experiments corroborated that most of the asphaltenes adsorbed can be removed for nanoparticle reuse. During the rheology tests, nanoparticles were evaluated in the first cycle at different concentrations from 300 to 1500 mg/L, leading to the highest degree of viscosity reduction of 18% at 500 mg/L. SiO2 nanoparticles were evaluated for comparison issues, obtaining similar results regarding the viscosity reduction. After measurements, the CFNS were removed with a magnet, washed with toluene, and further dried for the second cycle of viscosity reduction. Rheology tests were performed for a second time at a fixed concentration of 500 mg/L, and slight differences were observed regarding the first cycle. Finally, changes in the extra-heavy oil microstructure upon CFNS addition were observed according to the significant decrease in elastic and viscous moduli.

Optimization of closed-cycle oil recovery: a non-thermal process for bitumen and extra heavy oil recovery.

Energy from unconventional resources includes bitumen and extra-heavy oil that represent two-thirds of the known resources in the world. Extra-heavy oil and bitumen are currently recovered using thermal processes having a large carbon footprint and significant environmental impacts on water resources. A novel process is proposed: closed-cycle oil recovery (C-COR). C-COR is a greener alternative to provide energy from these unconventional resources with minimal water consumption. C-COR relies on recovering oil solubilized within a single-phase microemulsion, eliminating the need for viscosity reduction to both mobilize heavy oil or to transport it. Proof-of-concept work was conducted using conventional phase behavior experiments with extracted oil and surfactant formulations to develop a surfactant formulation for oil recovery using C-COR. As a part of process development and scale-up, we conducted flow experiments presented in this paper. We learned that a high degree of surfactant adsorption, which negatively impacted the C-COR process, resulted at low pH levels. These findings required modifying traditional static batch tests (phase behavior studies) using actual oil sand instead of the extracted oil. These unorthodox tests revealed that surfactant adsorption caused low oil solubilization and that alkali can be used to reduce adsorption, improving oil solubilization. In addition, unique flow experiments were designed to optimize the delivery and recovery process and are presented in this paper. The unique batch tests and flow experiments were conducted using oil sands from Canada to optimize the process. The proposed optimized approach would employ intermittent flow (soaking) that would result in the fastest recovery of about one-third of the OOIP, followed by continuous injection to recover an additional 10% OOIP, ending with thermal enhancement to recover another 25% OOIP for a total of 61%.

Cooperative Mechanism and Technology Parameters Optimization of Multi-thermal Fluid Huff & Puff Development in Heavy Oil Reservoir

The extra-heavy oil reservoirs in Central Asia have the characteristics of shallow burial, high crude oil viscosity, and strong reservoir heterogeneity. Conventional steam huff&puff have good initial development effects, but because energy cannot be replenished in time, steam huff&puff in the later stages huff&puff production declined fast and the effective production time is short. According to the current situation of oil reservoir development, a development technology combining multi-thermal fluid huff&puff and steam huff&puff is proposed. At the initial stage of production, steam is used to reduce viscosity, and in the later stage, N₂ in the multi-thermal fluid is used to pressurize, expand the steam chamber volume, and dissolved CO₂ to reduce viscosity. For single wells of different modes, using numerical simulation to design reasonable combined development modes and injection parameters, the research shows that multi-thermal fluid huff&puff after 5 cycles of steam huff&puff can achieve the best oil increase effect, and the best steam injection intensity 10t/m, gas injection intensity of 1500m3/m, 29 wells have been implemented in M heavy oil field in Central Asia. after use the multi-thermal fluid and superheated steam huff&puff coordinated development methods, the average well daily oil increment reached 0.6-4t/d, the water cut is reduced by 10-21%, the oil-steam ratio is increased by 0.4-0.6, realizing the efficient development of shallow buried extra-heavy oil reservoirs.

Application of Aromatic and Industrial Solvents for Enhancing Heavy Oil Recovery from the Ashalcha Field

Nowadays, there is a significant increase in the share of unconventional oil reserves such as heavy and extra-heavy oils as well as natural bitumen among the total balance of extracted petroleum fe...

Comparative analysis between asphaltites and extra heavy oil asphaltenes

The asphaltite material receives many names depending on the country, or area of knowledge, for this reason it is also known as bitumen, asphalt and gilsonite, its composition is a mixture of high molecular weight organic substances, mainly polyaromatic compounds characterized by a black color, and they appear in a semi-solid or solid state. Asphaltenes correspond to the oil fraction with the highest molecular weight, this characteristic provides a high viscosity to hydrocarbons, which contain, in their composition, a concentration equal to or greater than 10%, although the exact structure of this is not known. molecular family, it has been possible to elucidate the functional groups present, such as carbonyl acids, thiols and pyridines, implying the presence of heteroatoms, such as nitrogen, sulfur and oxygen, but the most characteristic part of this type of molecules is their nucleus polyaromatic, which can contain up to 20 or more benzene rings. A sample of Colombian asphaltite was taken and compared with a sample of asphaltenes from a Colombian extra-heavy crude, solubility tests, a spectroscopic characterization by Ultraviolet-Visible, infrared, a thermal evaluation by Thermogravimetry and Differential Scanning Calorimetry were carried out., in addition to an analysis by X-ray diffraction, in order to determine if the behavior and composition of both The objective of this investigation is to be analyzed by comparing a traditional asphaltite and an asphaltite, if the latter has the same properties and composition, with a view to being used as an energy source. The results obtained reveal that despite the fact that both substances present a similar composition, their glass transitions are different, as well as the crystalline phases present in each of the materials.

Activity assessment of NiMo bimetallic nanocatalyst in presence and absence of steam in in-situ upgrading technology (ISUT)

Production of heavy and extra-heavy oil is highly costly and severely carbon-emitting as it requires significant amount of energy. The In-situ Upgrading Technology (ISUT) is a novel method for production of heavy oil and bitumen that integrates both downhole upgrading and recovery enhancement in one single process. This process relies on catalytic downhole upgrading of heavy oil and bitumen in the presence of nanocatalyst and hydrogen. The presence of catalyst and hydrogen ensures upgrading reactions to take place from aboveground up to certain perimeter around the injector well. In this study, hydrogen is partially replaced with steam to reduce the operational cost of the ISUT process. The hybrid environment of hydrogen and steam is observed to alter the catalytic activity. The hydrogenation extent is closely monitored by assessing sulphur content, microcarbon, asphaltene content as well as hydrogenation of a polyaromatic compound, phenanthrene, as a chemical marker that was dissolved in the VR co-injected. This work focuses on the trade-off that exists in the addition of steam to the process, while generally assessing the impact that presence of water can have on the ISUT efficiency and product quality.