Oil Reservoir Conditions Research Articles

Study on High Temperature Plugging Agent for Heavy Oil Thermal Recovery in Fengcheng Oilfield, Xinjiang

The problems of underground steam channeling and surface steam channeling are easy to occur in the process of heavy oil thermal recovery in Fengcheng Oilfield, Xinjiang, which seriously affects the productivity level and causes surface pollution. In view of this problem, the research on high temperature plugging agent for heavy oil thermal recovery is carried out. Oil soluble phenolic resin OSR was synthesized with phenol and formaldehyde as main raw materials and organic amine as catalyst. A new high-temperature plugging agent HTD was developed by compounding with epoxy resin, silicone coupling agent and diluents etc. Under simulated heavy oil reservoir conditions in the laboratory, HTD was mixed with quartz sand with a certain particle size for filling, compaction and high-temperature maintenance, The high temperature gelling and curing experiment was carried out, the high temperature gelling performance, temperature resistance and high temperature plugging effect were evaluated, and the field test of three wells was carried out. The experimental results show that the strength of consolidated body of HTD and quartz sand is greater than 12 MPa above 180 ℃, the temperature resistance can reach more than 300 ℃, the plugging rate of high permeability core is greater than 99.5% at 220 ~ 300 ℃, and the breakthrough pressure gradient is greater than 35 MPa. The research results show that HTD has excellent temperature resistance and plugging strength, and HTD can effectively block the steam surface leakage and underground channeling channels, expand the steam sweep volume, improve the oil well productivity, have a long construction validity period.Though 3 well Field test, it's successful to bloched the flow channel, resumed the normal injection of blocks of steam throughput production. Steam injection pressure 3.5 MPa to 5.5 MPa, Two years after the test, the oil production level increased to 62.12 t/d, the average daily oil production increased by 22.7 tons, obtained good economic benefits.

Physical property and hydrocarbon enrichment characteristics of tight oil reservoir in Chang 7 division of Yanchang Formation, Xin'anbian oilfield, Ordos Basin, China

Xin'anbian Oilfield of the Ordos Basin is the large tight oilfield to be first exploration discovery in china. The production of tight oil increased significantly in recent years. It shows great exploration potential of Chang7 tight oil. But the physical property and hydrocarbon enrichment characteristics of Chang 7 tight oil reservoirs were rarely studied, The forming conditions of tight oil reservoirs are systematically summarized and analyzed through the study of hydrocarbon generation, sedimentary reservoirs and hydrocarbon migration and accumulation based on production and core experimental data. The result shows that, The porosity of the Chang 7 2 reservoir mainly distributed in 5.0–11.0%, average at 7.9%, The permeability mainly distributed in 0.04–0.18 × 10 −3 μm 2 , average at 0.12 × 10 −3 μm 2 , The pore diameters of the tight oil reservoir distributed in 2–8 μm. The high-quality Chang 7 3 source rocks and the micropsammite of Chang 7 2 subaqueous distributary channel were widely distributed in the study area. The lenticular or banded sand bodies are distributed among mudstone or hydrocarbon source rocks and have the advantage of migration distance for hydrocarbon accumulation. The reservoir space is composed of micro-nanometer pores and throat, that is formed in the process of increasing pressure during hydrocarbon generation and hydrocarbon accumulation. The Chang 7 tight oil was generated in the early Cretaceous and injected into the sand of the subaqueous distributary channel driven by continuous hydrocarbon generation supercharging. The formation and accumulation of tight oil reservoirs are mainly controlled by source rocks, sedimentary microfacies and reservoirs of good quality.

Predicting Heavy Oil Production by Hybrid Data-Driven Intelligent Models

It is difficult to determine the main control factors owing to the complex geological conditions of heavy oil reservoirs, including high viscosity, a wide range of variation of crude oil, and the great difference in production between different recovery methods. In this context, main control factors of heavy oil production in different recovery methods are analyzed and obtained based on the Apriori algorithm. The prediction of heavy oil production is faced with problems such as low prediction precision and insufficient data usage. Therefore, a novel intelligent simulation and prediction model of data-driven heavy oil production with time-varying characteristics is established based on differential simulation, machine learning, and intelligent optimization theory, which overcomes the defects of nonlinear, multifactor, and low fitting precision of dynamic data of heavy oil development. The parameters of the heavy oil production time-varying simulation model are identified by the least square support vector machine (LSSVM) to realize the intelligent prediction of the production. Numerical experiments show that the prediction result of the novel intelligent simulation and prediction model is better than the BP neural network model and the GM (1, N) model. This study provides a novel feasible method for data-driven heavy oil production prediction, and it can be helpful in further study of data-driven heavy oil production.

Concentration and distribution of oil in the reservoir mineral Dolomite studied by neutron tomography

Neutron Tomography – NT is a non-destructive technique, ideal for imaging hydrogen-rich substances even when wrapped up by thick rock layers. In the present study, the NT was employed for investigating the oil concentration and distribution in the mineral Dolomite, a natural oil reservoir. Two types of Dolomite samples, one of which dry, and the second one in oil-saturated were prepared. The applied oil was EMCAplus® 070 usually employed in permeability experiments to reproduce conditions of natural oil reservoirs. Three small fragments of the dry sample and three of the oil sample were inspected by NT and the comparison between the obtained results enabled, to distinguish several regions in which the oil is stored, to indicate that the oil is dispersed throughout the volume of the samples, and to quantify the storage concentration. The obtained data for oil concentration, for the three fragments, were compared to each other and to the one obtained by the conventional gravimetric technique, and they agreed within their uncertainties, demonstrating the viability of the NT technique to inspect, either in a qualitative as in a quantitative level, this oil reservoir mineral.

Methanogenic crude oil degradation induced by an exogenous microbial community and nutrient injections

Microbial potential of crude oil degradation coupled to methane production has attracted much attention as a basis for microbial enhanced energy recovery (MEER) technology. Here we performed laboratory incubation experiments mimicking in situ temperature and pressure conditions of subsurface oil reservoirs to evaluate the effectiveness of biological augmentation and stimulation for MEER. Using our high temperature and pressure incubation system, we successfully obtained a microbial community capable of methanogenic crude oil degradation from the Yamagata oil reservoir in Japan. To evaluate the potential of biological augmentation, we inoculated the microbial culture from Yamagata into production water from the Akita oil reservoir in which the indigenous microbial community cannot degrade crude oil. We observed methane production associated with toluene degradation, indicating that biological augmentation could be successful. We also evaluated the potential of biological stimulation, i.e. the effects of supplementing with different nutrients on crude oil degradation using the Yamagata oil reservoir sample. Intriguingly, addition of specific yeast extracts (YEs) resulted in notably enhanced methane production associated with the degradation of longer-chain n-alkanes as well as toluene. We further assessed the effectiveness of combining the biological augmentation and stimulation by inoculating the microbial culture from Yamagata together with the effective YE into the Akita production water, and found a large amount of methane production coupled to toluene and n-alkane degradation during the incubation. Taken together, our results suggest that the bio-augmentation and stimulation strategies demonstrated here could be a powerful tool for energy recovery from petroleum reservoirs both with and without innate crude oil degradation.

Novel laboratory investigation of huff-n-puff gas injection for shale oils under realistic reservoir conditions

Enhanced oil recovery (EOR) from shale oil formations is recognized as the next frontier in the exploitation of unconventional resources. Current approaches for performing EOR experiments using fractured rocks can generate misleading results as the fractured cores cannot be saturated with live oils. In this work, a novel laboratory methodology is developed to quantify the efficiency of gas huff-n-puff in shale oil formations under realistic reservoir conditions, i.e. live oil and hydraulic fracturing reservoir conditions. This new approach involves first saturating the shale core with oil and then hydraulic fracturing the oil-saturated core by increasing pore pressure above the core confining pressure. To demonstrate the viability of this new methodology, shale cores from the Haynesville formation with a permeability of 0.0001 mD were tested.Two huff-n-puff experiments were performed by the injection of associated gas into cores saturated with either dead crude oil or live oil. 48% additional oil recovery was achieved from the shale core saturated with live oil whereas, the shale core saturated with dead oil yielded a 33% enhanced oil recovery, which is significantly lower than that of the live oil. Furthermore, the pressure decay profiles during the soaking periods indicate a comparatively higher gas penetration into the live oil system despite the higher gas solubility in the dead oil. The in-situ gas formation can have a strong influence on the efficiency of huff-n-puff. The notable differences in the results obtained on live compared to dead oil experiments demonstrate the need to perform more realistic laboratory experiments to better optimize shale oil EOR-based extractions in the field.

Device for rock fracture toughness testing under hydrocarbon reservoir conditions

The effect of confinement pressure on fracture toughness may be significant in materials with poor tensile strength, as is the case of most rocks. In fracking wells for hydrocarbon exploitation, rock fracture is induced by a pressurized fluid. Indirect estimates of rock toughness based on injected pressure and volume records are much larger than laboratory-measured toughness values. This article discusses the design, fabrication and use of a linear elastic fracture mechanics method to assess the critical stress intensity factor (KI) of rocks under real well bottom conditions. Apparent Fracture Toughness (KIf) is determined using notched 1.5″ plugs machined from rocks. In this novel experimental set up, KI is applied by means of a hydraulic pressure inside the crack, so that fracturing fluid chemistry can be modified in order to optimize fracability. A secondary hydraulic system ensures variable confinement pressures, up to 80 MPa. Preliminary tests carried out in shale rocks at well bottom pressures show that rock toughness more than doubles those found at atmospheric pressure. It is shown that increasing triaxial pressure confinement allows to accurately model the conditions of rocks in oil & gas reservoir conditions.

Concentration and distribution of oil in the reservoir mineral Dolomite studied by neutron tomography

Neutron Tomography – NT is a non-destructive technique, ideal for imaging hydrogen-rich substances even when wrapped up by thick rock layers. In the present study, the NT was employed for investigating the oil concentration and distribution in the mineral Dolomite, a natural oil reservoir. Two types of Dolomite samples, one of which dry, and the second one in oil-saturated were prepared. The applied oil was EMCAplus® 070 usually employed in permeability experiments to reproduce conditions of natural oil reservoirs. Three small fragments of the dry sample and three of the oil sample were inspected by NT and the comparison between the obtained results enabled, to distinguish several regions in which the oil is stored, to indicate that the oil is dispersed throughout the volume of the samples, and to quantify the storage concentration. The obtained data for oil concentration, for the three fragments, were compared to each other and to the one obtained by the conventional gravimetric technique, and they agreed within their uncertainties, demonstrating the viability of the NT technique to inspect, either in a qualitative as in a quantitative level, this oil reservoir mineral.

Effects of salts and silica nanoparticles on oil-brine interfacial properties under hydrocarbon reservoir conditions: A molecular dynamics simulation study

Abstract Nanoparticles (NPs) have been extensively studied for enhanced oil recovery (EOR), in which the oil/brine/NPs interfacial properties play a critical role. However, the effects of NPs on oil-brine interfacial tension (IFT) have been much of debate from both experiment and simulation perspectives. In addition, the knowledge about salinity effects in oil/brine/NPs systems is still very limited. In this work, we use molecular dynamics (MD) simulations to study the effects of NPs (hydrophilic, hydrophobic, and Janus NPs, respectively) and salt concentration (NaCl and CaCl2) up to ~11 wt% on the oil-brine IFT and other interfacial properties under typical oil reservoir conditions. We find that NPs are adsorbed at the oil-brine interface, while salt ions are depleted from the interface. Ca2+ exhibits accumulations adjacent to the NP surfaces and the oil-brine interfaces before depletion, which is not observed in the cases containing Na+. All three NPs make water less ordered at the interfaces, but have negligible effects on oil-brine IFT. Divalent ions have a more pronounced layering structure than monovalent ions. While oil-brine IFT increases as the salinity increases, the three-phase contact angle is independent upon the salinity and cation types.

Study on Prevention of Gas Channelling of Acid-resistant Gel Foam in CO2 Flooding of Low Permeability Reservoir

With the shortage of recoverable reserves in conventional oil reservoirs, the development of low-permeability oil reservoirs has received more and more attention. The oil recovery of low-permeability reservoirs can be significantly improved by CO2 flooding, as it can effectively supply formation energy. CO2 flooding is an effective technology for increasing oil production in low-permeability reservoirs. However, because of the heterogeneity of the reservoir and the effect of natural fractures, CO2 gas channelling easily occurs during CO2 flooding, seriously reducing CO2 flooding effect. In this study, the gas channelling technology of acid-resistant gel foam was investigated. Preferred acid-resistant gel foam system formula was found as 0.1% by mass of AOS foaming agent with 0.3% to 0.4% by mass of instant HPAM polymer and 1% to 2% by mass of water-soluble phenolic resin crosslinking agent. This system still has a good foaming ability and blocking performance under at pH=2 and a salinity of 10×104 mg/L. After 60 days of aging under oil reservoir conditions, there is no obvious water separation, and the plugging strength retention rate reached more than 60%. The gel foam channelling system can be applied to highly heterogeneous and low permeability reservoirs with a permeability gradient higher than 14 and can increase the recovery rate by more than 20% based on the CO2 flooding. Acid-resistant gel foam channelling technology can effectively inhibit CO2 gas channelling and improve CO2 flooding effect in low permeability reservoirs.

The problem of abnormally low formation pressure on the oil and gas fields in Ukraine

The article presented information about specific of geological conditions depleted oil and gas fields, which has Remaining Oil and Gas in Place. The reasons of abnormally low pressure nascency in the deposit has been analyzed. The article presents information about influence of geodynamic processes and structural and tectonics of Earth crust to formation pressure. The information about availability of initial abnormally low formation pressure in Ukrainian Oil and Gas-Condensate fields has been written. Supposition of nascence the abnormally low formation pressure in difficult oil/water/gas saturation geological formation has been analyzed. The drop of pressure in of initial formation has been analyzed and researched. The article presented that drop of pressure gradient in main Ukrainian oil and gas fields is equal to the value of abnormally low formation pressure.The problems of considerable remaining Oil and Gas in with abnormally low pressure in Ukrainian oil and gas field deposit has been analyzed. The information about oil and gas reservoir conditions of depleted field and brown fields in Ukraine has been analyzed.The plot of the formation pressure gradient decreasing for Chornukhynske, Denysivske, Solokhivske, Druzheliubivske, Tymofiivske and Yablunivske fields has been presented. The drop of pressure to abnormally low in Chornukhynske, Denysivske, Solokhivske, Druzheliubivske, Tymofiivske and Yablunivske fields has been established. The problems of drilling and cementing in the well with abnormally low pressure has been describe. Difficult geological conditions in Ukrainian oil and gas field deposit has been analyzed.The article shows the importance to control parameters of all technological liquids, especially density of drilling and cementing liquid in a time of drilling well with abnormally low pressure. The article shows the aspect of the using of lightweight grouting solutions for mounting wells with abnormally low reservoir pressures, the importance of controlling the contamination of the bottom zone of the formation and preventing the occurrence of hydraulic fracturing during cementing.

Screening of Spontaneous Ignition Feasibility During Air Injection EOR Process Based on Thermal Experiments

The feasibility of spontaneous ignition is extremely important to the success of AIP (air injection process) projects. However, no laboratory experiments were reported on the detection of crude oil spontaneous ignition during AIP. The initial intention of the thermal experiments is to screen candidate oil reservoirs for the application of AIP in a faster and less expensive way than combustion tube tests. However, instead of performing a feasibility study, most of the research only employed thermal experiments as a tool to obtain kinetic data and to characterize the thermal-oxidative behavior for different crude oil samples. The question of how to use the thermal experiments to determine the feasibility of spontaneous ignition has not been answered yet. This study proposes a practical method to investigate the spontaneous ignition feasibility during AIP, which directly relates the oil reactivity and reservoir properties. An example of the application of this method was presented in this paper, where a mixture of a light oil and sand was tested by the TGA and DSC to obtain the kinetic data and net heat. The obtained parameters were then used to evaluate the feasibility of spontaneous ignition. The results showed that the tested oil and sand mixture cannot lead to spontaneous ignition due to crude oil’s insufficient reactivity. Furthermore, the typical crude oil kinetic data and reservoir conditions were used to investigate the screening criteria for spontaneous ignition. The results indicated that the crude oil’s activation energy and frequency factor need to be less than 60 kJ/mole and higher than 2 s−1, respectively, in order to satisfy the need of spontaneous ignition.

A three dimensional high-resolution reservoir model of Napo Formation in Oriente Basin, Ecuador, integrating sediment dynamic simulation and geostatistics

Abstract With the rapid development of computer hardware and software technology, 3D modeling technology of reservoirs has been widely applied in the exploration of oilfields. However, when modeling the reservoir with few wells, due to the absence of efficient constraints in interwell areas, the accuracy of the resulting 3D model is usually lacking. In this paper, we study the issue of model accuracy under the conditions of oil reservoir with few wells and propose a new 3D geological modeling method that is constrained by the multiple parameters based on sedimentary dynamics. We carry out a series of sediment dynamic simulation, by considering a number of key processes and parameters affecting the deposition of M1 member of Napo Formation in T-Oilfield, Oriente Basin, from 79.8 Ma to 76 Ma, to constrain the lithofacies and properties models. The proposed modeling method comprises two steps. First, the lithology distribution is obtained from a petrologic 3D model through the forward modeling of sedimentary processes. Second, geostatistical method is applied to build the reservoir geological model with the constraints of sedimentary dynamics, and logging information from work areas, the distribution of sedimentary characteristics by using a coordination Kriging modeling method. As a result, a high-degree fit is obtained between the actual characteristics of the strata and the reservoir model, with relative error of 4.6%, indicating future application of this method for geological modeling of reservoirs with few wells.

Application Analysis of Oil Test Fracturing Technology in Deep Gas Wells

In the process of oil exploration, it is necessary to define the general orientation and distribution of underground reservoirs through oil testing and fracturing operations, and to obtain the specific conditions of detailed crude oil reservoirs. Because of the characteristics of high temperature and high pressure of deep gas, it is difficult to test and fracturing deep gas wells. Based on the analysis of the characteristics of deep gas and the development needs of oil testing technology, this paper analyses the oil testing and fracturing technology of deep gas wells through reservoir modification and fluid drainage.

A New Empirical Model for Viscosity of Sulfonated Polyacrylamide Polymers.

Copolymers of acrylamide with the sodium salt of 2-acrylamido-2-methylpropane sulfonic acid—known as sulfonated polyacrylamide polymers—had been shown to produce very promising results in the enhancement of oil recovery, particularly in polymer flooding. The aim of this work is to develop an empirical model through the use of a design of experiments (DOE) approach for bulk viscosity of these copolymers as a function of polymer characteristics (i.e., sulfonation degree and molecular weight), oil reservoir conditions (i.e., temperature, formation brine salinity and hardness) and field operational variables (i.e., polymer concentration, shear rate and aging time). The data required for the non-linear regression analysis were generated from 120 planned experimental runs, which had used the Box-Behnken construct from the typical Response Surface Methodology (RSM) design. The data were collected during rheological experiments and the model that was constructed had been proven to be acceptable with the Adjusted R-Squared value of 0.9624. Apart from showing the polymer concentration as being the most important factor in the determination of polymer solution viscosity, the evaluation of the model terms as well as the Sobol sensitivity analysis had also shown a considerable interaction between the process parameters. As such, the proposed viscosity model can be suitably applied to the optimization of the polymer solution properties for the polymer flooding process and the prediction of the rheological data required for polymer flood simulators.

A salt-induced viscosifying smart polymer for fracturing inter-salt shale oil reservoirs

Inter-salt shale oil reservoirs located between two salt layers are always accompanied by high temperature and high salinity. However, the present commonly used water-soluble polymers in fracturing fluids suffer from poor tolerance to high temperature and high salinity. Thermoviscosifying polymers (TVP) whose aqueous solution shows viscosity increase upon increasing temperature and salt concentration have received considerable attention recently, which is promising for utilization in fracturing fluids to overcome these problems. In this work, both the salt-induced viscosifying property and mechanism of a TVP solution were investigated and the performance of TVP used as fracturing fluid based on the conditions of the Jianghan inter-salt shale oil reservoir in China was evaluated. It is found that the salt-induced viscosifying property of the TVP solution decreases with temperature and shear rate, but increases with polymer concentration. The number of intermolecular hydrophobic domains increases with the salt concentration contributing to the strengthening of a 3D network structure, which results in an increase in viscosity. In addition, the TVP fracturing fluid formulated with saturated brine exhibits excellent temperature and shear resistance, sand-suspending performance, and gel-breaking performance. Its viscosity remains above 50 mPa s after being sheared for 1 h even at a high temperature of 140 °C and the sand-suspending stability can be maintained for more than 1 week at 100 °C. Furthermore, the fracturing fluid can be easily broken down within 12 h using 0.2 wt%–0.3 wt% potassium persulfate without residue.

Analysis of reservoir forming conditions of buried hill oil reservoirs in the western slope of Shulu Depression

Development of Shahejie Formation lithologic reservoirs and deep buried hill hydrocarbon reservoirs in the western slope of Shulu Depression. After years of exploration and development practice, the types of buried hill hydrocarbon reservoirs oil and gas reservoirs are diverse, and the hydrocarbon accumulation conditions are not clear, which restricts the pace of oil and gas exploration. Therefore, this paper studies the types and distribution laws of buried hills and the reservoir forming conditions of buried hill hydrocarbon reservoirs. The results show that the west slope of Shulu Depression can be divided into five types: erosion buried hill, fold-erosion buried hill, fault block-erosion buried hill, fold buried hill and fault block buried hill. The buried hill trap is mainly controlled by three factors: unconformity interface, geologic fault and stratigraphic overlap occlusion.

Distributed-Memory Load Balancing With Cyclic Token-Based Work-Stealing Applied to Reverse Time Migration

Reverse time migration (RTM) is a prominent technique in seismic imaging. Its resulting subsurface images are used in the industry to investigate with higher confidence the existence and the conditions of oil and gas reservoirs. Because of its high computational cost, RTM must make use of parallel computers. Balancing the workload distribution of an RTM is a growing challenge in distributed computing systems. The competition for shared resources and the differently-sized tasks of the RTM are some of the possible sources of load imbalance. Although many load balancing techniques exist, scaling up for large problems and large systems remains a challenge because synchronization overhead also scales. This paper proposes a cyclic token-based work-stealing (CTWS) algorithm for distributed memory systems applied to RTM. The novel cyclic token approach reduces the number of failed steals, avoids communication overhead, and simplifies the victim selection and the termination strategy. The proposed method is implemented as a C library using the one-sided communication feature of the message passing interface (MPI) standard. Results obtained by applying the proposed technique to balance the workload of a 3D RTM system present a factor of 14.1% speedup and reductions of the load imbalance of 78.4% when compared to the conventional static distribution.

Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater (Diluted Seawater) Flooding Processes for Improved Oil Recovery.

Over the past few decades, field- and laboratory-scale studies have shown enhancements in oil recovery when reservoirs, which contain high-salinity formation water (FW), are waterflooded with modified-salinity salt water (widely referred to as the low-salinity, dilution, or SmartWater effect for improved oil recovery). In this study, we investigated the time dependence of the physicochemical processes that occur during diluted seawater (i.e., SmartWater) waterflooding processes of specific relevance to carbonate oil reservoirs. We measured the changes to oil/water/rock wettability, surface roughness, and surface chemical composition during SmartWater flooding using 10-fold-diluted seawater under mimicked oil reservoir conditions with calcite and carbonate reservoir rocks. Distinct effects due to SmartWater flooding were observed and found to occur on two different timescales: (1) a rapid (<15 min) increase in the colloidal electrostatic double-layer repulsion between the rock and oil across the SmartWater, leading to a decreased oil/water/rock adhesion energy and thus increased water wetness and (2) slower (>12 h to complete) physicochemical changes of the calcite and carbonate reservoir rock surfaces, including surface roughening via the dissolution of rock and the reprecipitation of dissolved carbonate species after exchanging key ions (Ca2+, Mg2+, CO32-, and SO42- in carbonates) with those in the flooding SmartWater. Our experiments using crude oil from a carbonate reservoir reveal that these reservoir rock surfaces are covered with organic-ionic preadsorbed films (ad-layers), which the SmartWater removes (detaches) as flakes. Removal of the organic-ionic ad-layers by SmartWater flooding enhances oil release from the surfaces, which was found to be critical to increasing the water wetness and significantly improving oil removal from carbonates. Additionally, the increase in water wetness is further enhanced by roughening of the rock surfaces, which decreases the effective contact (interaction) area between the oil and rock interfaces. Furthermore, we found that the rate of these slower physicochemical changes to the carbonate rock surfaces increases with increasing temperature (at least up to an experimental temperature of 75 °C). Our results suggest that the effectiveness of improved oil recovery from SmartWater flooding depends strongly on the formation of the organic-ionic ad-layers. In oil reservoirs where the ad-layer is fully developed and robust, injecting SmartWater would lead to significant removal of the ad-layer and improved oil recovery.

Simulation of in situ oil reservoir conditions in a laboratory bioreactor testing for methanogenic conversion of crude oil and analysis of the microbial community

A bioreactor was designed and established to simulate in situ oil reservoir conditions for investigating methanogenic conversion of crude oil by microbial community derived from production water of a high-temperature oilfield. The continuous incubation and culturing were divided into two phases (Phase I, day 0–341; and Phase II, day 341–520) to allow sampling and supplement of fresh culture medium on day 341 and 520, respectively. The average methane production rate was 4.9 and 20.8 mmol CH4·day−1 m−3 pore volume during the Phase I and Phase II, respectively. Degradation intermediates of fatty acids were detected in the culture fluids indicating the transformation of crude oil. The 16S rRNA gene sequence analysis revealed that the major bacterial community shifted from Deferribacteres to Aminicenantes and unclassified Bacteria, as well as Thermotogae and Synergistetes. The predominant methanogenic community shifted from methylotrophic methanogen (Methanolobus) to hydrogenotrophic methanogens (Methanothermobacter and Methanocalculus) and acetoclastic methanogen (Methanothrix) after 341 days of incubation, and was subsequently dominated by hydrogenotrophic methanogen (Methanothermobacter) after 520 days of incubation. This study expanded our understandings of methanogenic oil-degrading processes and the key microorganisms involved in laboratory simulation bioreactor over time of incubation. In addition, it further provides valuable insights on the microbial conversion of hydrocarbons to methane for enhancing the energy recovery from residual oil in petroleum reservoirs.