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Collaborating Authors
Honshu Island
Long-Term Microbial DNA-Based Monitoring of the Mature Sarukawa Oil Field in Japan
Kobayashi, H. (The University of Tokyo (Corresponding author)) | Goto, A. (Japan Petroleum Exploration Co., Ltd. (JAPEX)) | Feng, X. (The University of Tokyo) | Uruma, K. (The University of Tokyo) | Momoi, Y. (The University of Tokyo) | Watanabe, S. (The University of Tokyo) | Sato, K. (The University of Tokyo) | Zhang, Y. (Tsinghua University) | Horne, R. N. (Stanford University) | Shibuya, T. (Japan Petroleum Exploration Co., Ltd. (JAPEX)) | Okano, Y. (Japan Petroleum Exploration Co., Ltd. (JAPEX))
Summary Microbial DNAbased monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNAbased monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNAbased monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields. Introduction In oil and gas production, reservoir monitoring is vital to understanding the subsurface structures, geological conditions, and fluid flow for optimizing the field productivity. Recently, microbial community analysis has been applied to reservoir monitoring, in which microbes present in the subsurface environment and/or injection fluid are used as markers and/or tracers to gather information on the subsurface environment and to track fluid flow in the reservoir (Tayyib et al. 2019; Zhang et al. 2019). In particular, microbial DNA extracted from the formation water, crude oil, drill cuttings, and injection fluid is assessed by comprehensive amplicon sequencing, most often the 16S rRNA gene as a phylogenetic marker.
amplicon, application, asia government, complex reservoir, composition, connectivity, Efficiency, enhanced recovery, equation of state, Exhibition, genus pseudomona, information, japan government, long-term microbial dna-based monitoring, microbial dnabased, Modeling & Simulation, paper, PVT measurement, Reservoir Characterization, similarity, SPE Reservoir Evaluation, structural geology, tracer, united states government, Upstream Oil & Gas, waterflooding
Country:
- North America > United States > Texas (0.93)
- Asia > Japan > Honshu Island > Akita Prefecture (0.72)
Oilfield Places:
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
SPE Disciplines:
First Nanoparticle-Based EOR Nano-EOR Project in Japan: Laboratory Experiments for a Field Pilot Test
Kaito, Yutaro (Japan Petroleum Exploration Co. Ltd.) | Goto, Ayae (Japan Petroleum Exploration Co. Ltd.) | Ito, Daisuke (Japan Petroleum Exploration Co. Ltd.) | Murakami, Satoru (Nissan Chemical Corporation) | Kitagawa, Hirotake (Nissan Chemical Corporation) | Ohori, Takahiro (Nissan Chemical Corporation)
Abstract "Nanoparticle-based enhanced oil recovery (Nano-EOR)" is an improved waterflooding assisted by nanoparticles dispersed in the injection water. Many laboratory studies have revealed the effectiveness of Nano-EOR. An evaluation of the EOR effect is one of the most critical items to be investigated. However, risk assessments and mitigation plans are as essential as investigation of its effectiveness for field applications. This study examined the items to be concerned for applying Nano-EOR to the Sarukawa oil field, a mature field in Japan, and established an organized laboratory and field tests workflow. This paper discusses a laboratory part of the study in detail. This study investigated the effect and potential risks of the Nano-EOR through laboratory experiments based on the workflow. The laboratory tests used surface-modified nanosilica dispersion, synthetic brine, injection water, and crude oil. The oil and injection water were sampled from a wellhead and injection facility, respectively, to examine the applicability of the EOR at the Sarukawa oil field. The items of the risk assessment involved the influence on an injection well's injectivity, poor oil/water separation at a surface facility, and contamination of sales oil. A series of experiments intended for the Sarukawa oil field showed that 0.5 wt. % nanofluid was expected to contribute to significant oil recovery and cause no damage on an injection well for the reservoir with tens of mD. This is considered a favorable result for applying Nano-EOR to Sarukawa oil field because it contains layers of tens mD. Furthermore, the experiments also showed that 0.5 wt.% nanofluid did not lead to poor oil/water separation and contamination of sales oil. Thus, field tests are designed with this concentration. This paper introduces the entire study workflow and discusses the detailed procedure and results of experiments investigating the Nano-EOR effect and potential risks.
application, concentration, core holder, differential pressure, enhanced recovery, experiment, injection water, nano-eor, nanofluid, nanofluid injection, nanoparticle, nanoparticle concentration, oil field, Oil Recovery, permeability, sale oil, silica nanoparticle, synthetic brine, Upstream Oil & Gas, waterflooding, wettability alteration
Country:
- Asia > Japan > Honshu Island > Akita Prefecture (0.87)
- Europe > United Kingdom > North Sea (0.40)
- North America > United States > Texas (0.28)
Oilfield Places:
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- North America > United States > Montana > Target Field (0.99)
- Asia > Japan > Honshu Island > Akita Prefecture > Sarukawa Field (0.99)
SPE Disciplines: Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Lithological facies classification using well logs is essential in the reservoir characterization. The facies are manually classified from characteristic log responses derived, which is challenging and time consuming for geologically complex reservoirs due to high variation of log responses for each facies. To overcome such a challenge, machine learning (ML) is helpful to determine characteristic log responses. In this study, we classified the lithofacies by applying ML to the conventional well logs for the volcanic formation, onshore, northeast Japan. The volcanic formation of the Yurihara oil field is petrologically classified into five lithofacies: mudstone, hyaloclastite, pillow lava, sheet lava, and dolerite, with pillow lava being predominant reservoir. The former four lithofacies are the members of the volcanic system in Miocene, and dolerite randomly intruded later into those. Understanding the distribution of omnidirectional tight dykes at the well location is important for the estimation of potential near-lateral seal distribution compartmentalizing the reservoir. The facies are best classified by core data, which are unfortunately available in a limited number of wells. The conventional logs, with the help of the borehole image log, have been used for the facies classification in most of the wells. However, distinguishing dolerite from sheet lava by manual classification is very ambiguous, as they appear similar in these logs. Therefore, automated clustering of well logs with ML was attempted for the facies classification. All the available log data was audited in the target well prior to applying ML. A total of 10 well logs are available in the reservoir depth interval. To prioritize the logs for the clustering, the information of each log was first analyzed by Principal Component Analysis (PCA). The dimension of variable space was reduced from 10 to 5 using PCA. Final set of 5 variables, gamma-ray, density, formation photoelectric factor, neutron porosity, and laterolog resistivity, were used for the next clustering process. ML was applied to the selected 5 logs for automated clustering. Cross-Entropy Clustering (CEC) was first initialized using k-means++ algorithm. Multiple initialization processes were randomly conducted to find the global minimum of cost function, which automatically derived the optimized number of classes. The resulting classes were further refined by the Gaussian Mixture Model (GMM) and subsequently by the Hidden Markov Model (HMM), which takes the serial dependency of the classes between successive depths into account. Resulting 14 classes were manually merged into 5 classes referring to the lithofacies defined by the borehole image log analysis. The difference of the log responses between basaltic sheet lava and dolerite was too subtle to be captured with confidence by the conventional manual workflow, while the ML technique could successfully capture it. The result was verified by the petrological analyses on sidewall cores (SWCs) and cuttings. In this study, the automated clustering with the combination of several ML algorithms was demonstrated more efficient and reasonable facies classification. The unsupervised learning approach would provide supportive information to reveal the regional facies distribution when it is applied in the other wells, and to comprehend the dynamic behavior of the fluids in the reservoir.
algorithm, Artificial Intelligence, classification, dolerite, facies, facies classification, information, Input log, Japan, lithofacies, log analysis, log curve, machine learning, nd annual logging symposium, Reservoir Characterization, sheet lava, spwla 62, spwla-2021-0037, Upstream Oil & Gas, volcanic formation, well logging
SPE Disciplines:
Technology:
Acid Selection for Volcanic Tuffaceous Sandstone with High Analcime Contents: A Laboratory Study in Kita-Akita Oil Field, Northern Japan
Ueda, Kenji (Inpex Corporation) | Matsui, Ryoichi (Inpex Corporation) | Ziauddin, Murtaza (Schlumberger) | Teng, Ling Kong (Schlumberger) | Wang, Wei Kan (Schlumberger)
Summary Investigation of the effectiveness of matrix‐stimulation treatments for removing drilling‐induced damage in the Akita region of northern Japan is of interest because of the presence of large quantities of acid‐sensitive minerals, such as analcime. A feasibility study of the subcommercial field redevelopment in the Kita‐Akita Oil Field, one of the satellite fields of the main Yabase Oil Fields that produced from 1957 to 1973 and was plugged and abandoned, was conducted. As a part of the studies, matrix‐acidizing laboratory experiments were performed. Conventional mud acids and formic‐acid‐based organic‐mud‐acid systems cause significant permeability damage because of the instability of analcime when exposed to these acids. This study focuses on the development of a treatment fluid that removes drilling‐induced damage and is also compatible with the formation. Petrology studies and core flow tests were used in conjunction with geochemical modeling to achieve this objective. A petrographic analysis on the untreated cores showed abundant tuffaceous pore‐filling mineral phases, ranging from 12 to 20% in volume. Smectite clay and microcrystalline quartz are the major constituents present as alteration products of volcanic glass. Analcime was present in significant quantities in all samples tested. Six core flow tests were performed on formation cores to optimize the acid preflush and main acid stage. Permeability change resulting from treatment fluids was recorded for the tests. Chemical analysis of the effluent was performed on three core flow tests. Core samples before and after acidization were characterized on the basis of thin section, X‐ray diffraction (XRD), scanning electron microscopy (SEM), and mineral mapping. Core flow tests with conventional retarded organic mud acid (ROMA) resulted in only 75% retained permeability. The permeability damage by the ROMA was surprising, because it usually performs well in acid‐sensitive formations. A chelant‐based retarded mud acid was tested next and resulted in minor formation damage. It can be potentially used in a field treatment, because its high dissolving power is expected to more than compensate for the damage. The highest retained permeability was obtained with an acetic‐hydrofluoric (HF) acid system. It was successfully able to remove drilling‐induced damage and was also compatible with the native mineralogy. Core flow tests were used to calibrate the permeability/porosity relationship used in the geochemical simulator. The geochemical simulator was then used to predict the field‐level acid response. The analytic methods presented are general enough to be of interest to sandstone‐acidizing studies, where detailed analysis is needed for damage identification and removal. The fluids developed for this formation are good candidates for other formations where conventional acid systems have not performed well. This study also highlights a close collaboration between the operator and the service company to find a workable solution to a challenging stimulation requirement.
acid, analcime, concentration, core analysis, core flow test, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, february 2021, flow in porous media, Fluid Dynamics, fluid loss control, formation damage, HF acid, kita-akita oil field, mineral, mud acid, nh 4, oil field, permeability, precipitation, reaction, sif 6, SPE Production, Upstream Oil & Gas
Country:
- North America > United States > Texas (0.46)
- Asia > Japan > Honshu Island (0.34)
- Europe > Norway > Norwegian Sea (0.34)
- North America > United States > Michigan (0.28)
Oilfield Places:
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Ile Formation (0.99)
- (8 more...)
SPE Disciplines:
Acid Selection for Volcanic Tuffaceous Sandstone With High Analcime Contents: A Laboratory Study in Kita-Akita Oil Field, Northern Japan
Ueda, Kenji (INPEX Corporation) | Matsui, Ryoichi (INPEX Corporation) | Ziauddin, Murtaza (Schlumberger) | Teng, Ling Kong (Schlumberger) | Wang, Wei Kan (Schlumberger)
Investigation of the effectiveness of matrix stimulation treatments for removing drilling induced damage in Akita region in northern Japan is of interest due to the presence of large quantities of acid-sensitive minerals, such as analcime. Feasibility study of the sub-commercial field redevelopment in the Kita-Akita oil field, one of the satellite fields of main Yabase oil fields, which produced from 1957 to 1973, and were plugged and abandoned, were conducted. As a part of the studies, matrix acidizing laboratory experiments were performed. Conventional mud acids and formic-based organic mud acid systems cause significant permeability damage due to instability of analcime in these acids. This study focuses on the development of a treatment fluid that removes drilling-induced damage and is also compatible with the formation. Petrology studies and core flow tests were used in conjunction with geochemical modeling to achieve this objective. A petrographic analysis on the untreated cores showed abundant tuffaceous pore-filling mineral phases, ranging from 12 to 20% in volume. Smectite clay and microcrystalline quartz are the major constituents as alteration products of volcanic glass. Analcime was present in significant quantities in all samples tested. Six core flow tests were performed on formation cores to optimize the acid preflush and main acid stage. Permeability change due to the treatment fluids was recorded for the tests. Chemical analysis of the effluent was performed on three core flow tests. Core samples before and after acidization were characterized based on thin section, X-ray diffraction (XRD), scanning electron microscopy(SEM) and mineral mapping. Core flow tests with a conventional retarded organic mud acid resulted in only a 75% retained permeability. The permeability damage by the retarded organic mud acid was surprising because it usually performs well in acid-sensitive formations. A chelant based retarded mud acid was tested next and resulted in minor formation damage. It can potentially be used in a field treatment as its high dissolving power is expected to more than compensate for the damage. The highest retained permeability was obtained with an acetic-HF acid system. It was successfully able to remove drilling-induced damage and was also compatible with the native mineralogy. Core flow tests were used to calibrate permeability-porosity relationship used in the geochemical simulator. The geochemical simulator was then used to predict field-level acid response. The analytic methods presented are general enough to be of interest to sandstone acidizing studies where detailed analysis is needed for damage identification and removal. The fluids developed for this formation area good candidates for other formations where conventional acid systems have not performed well. This study also highlights close collaboration between an operator and service company to find a workable solution to a challenging stimulation requirement.
acid, analcime, concentration, core analysis, core flow test, dissolution, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, flow in porous media, Fluid Dynamics, fluid loss control, formation damage, geochemical simulator, international petroleum technology conference, mineral, mineral composition, mud acid, nh 4, permeability, precipitation, reaction, sandstone, Upstream Oil & Gas
Country:
- North America > United States > Louisiana (0.28)
- North America > United States > Texas (0.28)
- Asia > Japan > Honshu Island (0.24)
Oilfield Places:
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Ile Formation (0.99)
- (7 more...)
History of a Commercially Successful Gas-Based IOR in Japan: 12 Years' Challenge on Maximizing the Profit of Offshore Oil and Gas Field by Optimizing Allocation of Gas Volume Between Sale and Injection
Koshi, Shinichi (JAPEX) | Yamakawa, Takafumi (JAPEX) | Takahashi, Yoko (JAPEX) | Sugita, Fumiya (JAPEX) | Ueda, Ryo (JAPEX) | Hosokoshi, Koji (JAPEX)
Abstract Iwafune-Oki Oil and Gas Field located at shallow offshore in Japan was discovered in 1983, and has been producing from multiple oil and gas reservoirs since 1990. After 8 years of plateau production, the field oil started to decline whereas the recovery factor of gas reservoirs still grew sluggish due to the constraints of the local gas demand. There was an incentive to arrest the oil decline by utilizing the potential abundant gas effectively. In order to address such an unbalanced oil and gas recoveries, two measures have been adopted accordingly. One is a marketing effort to expand our sales gas, which is a straightforward measure to minimize the potential abundant gas. The other is a challenge to utilize the high pressure gas for gas-based IOR. Fortunately, Iwafune-Oki Oil and Gas Field is in all respects an ideal field for gas-based IOR. According to the results of PVT experiments in the laboratory and preliminary reservoir simulation study, effects of gas-based IOR on the production acceleration and the incremental oil recovery were expected. In addition, there are several high pressure gas reservoirs. The produced gas from those reservoirs has enough high pressure to be injected into the target oil reservoir without any fuel-consuming mechanical gas compressor. This meets another incentive to commence the pilot test without spending too much additional capital costs and fuel consumption. Thus, gas-based IOR was started from December 2004. The acceleration of the oil production has already been proved by observing no apparent oil production decline in the first two years during the pilot test. Around 4% incremental oil recovery was achieved as of 2016. In order to maximize the profit of offshore oil and gas field, we will optimize how to blowdown the gas that has been injected into the oil reservoir since 2004.
22nd wpc preprint paper, enhanced recovery, field 22nd world petroleum congress, gas field, gas injection method, gas-based ior, incremental oil recovery, injected gas, ior eor maximising, iwafune-oki oil, Modeling & Simulation, Pilot Test, Reservoir Characterization, Reservoir Simulation Study, structural geology, Upstream Oil & Gas, World Petroleum Council
Country:
- Asia > Japan > Niigata Prefecture (0.57)
- Asia > Japan > Honshu Island (0.57)
SPE Disciplines:
Abstract As potential CO2 geological storage site in CCS, utilization of depleted oil/gas reservoirs and aquifer has been proposed. The long-term aim of this research is to establish a biotechnological system to microbiologically convert geologically stored CO2 into methane. Our recent study revealed that methanogen and exoelectrogen inhabiting subsurface reservoir are involved in the recently discovered bioelectrochemical reaction called electromethanogenesis (CO2 + 8H+ 8e → CH4 + 2H2O). In this reaction, methanogen receives proton from reservoir brine and electron from a solid electrode. As a result, reduces CO2 into methane. Required electricity for the methane conversion can be obtained from renewable energy sources such as wind or photovoltaic power generations. Single-chambered electromethanogenic reactors were used for an evaluation. The reactors were inoculated with reservoir brine anaerobically collected from Yabase oil field in Japan. Each reactor headspace was filled with mixed gases of N2/CO2 (80/20). The reactors were incubated at 55°C with an applied voltage of 0.75 V. The reactors produced methane at a rate of 386mmol/day m. The current-methane conversion efficiency was almost 100%. On the other hand, no significant methane production was detected in the reactors without applied voltage. To investigate the mechanism of electromethanogenic reaction, the phylogenetic diversity of the microbes on the cathode was analyzed. The result shows, as for archaea, methanogen closely related to Methanothermobacter thermoautotrophicus dominated. On the other hand, as for bacteria, Thermincola ferriacetica, one of the exoelectrogen, was the dominant spices. Our experimental research demonstrated for the first time that the possibility of bioelectrochemical methane conversion of carbon dioxide by utilizing microbes indigenous to depleted oil fields. The final goal of this research is to establish the "Subsurface Methane Regeneration" system, combining CCS and biotechnology, in which geologically-stored CO2 is converted into CH4 by bio-electrochemical process called "Electromethanogenesis".
bioelectrochemical reactor experiment, climate change, co 2, conversion efficiency, electrode well, electron, enhanced recovery, experiment, mechanism, methane, methanogen, microorganism, reaction, reactor experiment, renewable energy, reservoir brine, subsurface microorganism, subsurface storage, thermincola ferriacetica, Upstream Oil & Gas, voltage
Genre:
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
SPE Disciplines:
Abstract Volcanic rock hydrocarbon reservoirs might be underestimated in exploration and exploitation due to threedimensionally heterogeneous distribution of volcanic lithofacies. Volcanic-related reservoirs are not among the primary producers of hydrocarbons in a global sense. However, further exploration and exploitation of volcanic reservoirs with an appropriate geological model may offer considerable potential for the discovery of significant reserves. An understanding of the architecture of volcanic reservoirs is critical for their exploration and exploitation. We applied multiple-point geostatistics to the modeling of volcanic rock reservoirs in the Yurihara oil and gas field, in northeast Japan. The volcanic rock reservoirs in the Yurihara field consist of basaltic rocks erupted underwater during the Miocene period: sheet flows, pillow lavas, breccias, and hyaloclastites. This volcanic activity was related to the opening of the Japan Sea, a backarc basin behind the Japanese islands. Volcanic morphology in slow spreading mid-ocean ridges is used as a modern analogue in developing a training image in the multiple-point geostatistical approach. Two conspicuous volcanic morphologies can be found in slow-spreading ridges:flat-topped seamounts (dominant sheet flows and surrounding pillow lavas) and hummocky terrains (conglomerations of pillow lavas). Identical morphologies and lithologies are suggested in 3D-seismic profiles in the basaltic reservoirs of the Yurihara field. The formation of flat-topped seamounts along en echelon-aligned fissures and surrounding hummocky terrains was modeled as a training image for the Yurihara basaltic reservoirs. Realizations were developed using borehole imaging, logging, and core data as hard data and were successfully used for flow simulations. The application of multiple-point geostatistics to volcanic reservoirs has been demonstrated to be proficient in predicting reservoir performance through simulations using geostatistical models.
Artificial Intelligence, basaltic reservoir, complex geological environment 21, lithofacies, machine learning, moscow 2014, oil and gas field, pillow lava, reservoir, Reservoir Characterization, Simulation, st World Petroleum congress, training image, Upstream Oil & Gas, volcanic lithofacies, volcanic morphology, World Petroleum Council, yurihara basaltic reservoir
Geophysics:
Oilfield Places:
- Asia > Japan > Niigata Prefecture > Iwafune-Oki Field (0.99)
- Asia > Japan > Honshu Island > Akita Prefecture > Yurihara Field (0.99)
- Asia > Japan > Niigata Field (0.94)
- Asia > Japan > Akita Field (0.89)
SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
Technology:
Abstract The Onnagawa shale is Miocene, bio-siliceous and known as the main source rock in Japan. Frequent and intensive oil shows are observed through the Onnagawa formati on around the Ayukawa field. The thickness of this layer is about 1,600 ft around this field. The porosity is around 30%. The Permeability ranges from 0.01 mD to 1 mD. Onnagawa is considered to be similar to Monterey shale. Acidizing in Monterey shale has a long history of success. Though the production is generally improved by removing the drilling and completion damage, unexpected favorable responses from low permeability rock are also reported. These improvements are considered to result from dissolving the calcite and clay minerals in natural fractures and enhancing the wellbore connection into natural fracture network. The acid stimulation test was conducted to verify this acidizing effect in Onnagawa shale. The target well showed very low productivity. The perforation interval is 40 m (130 ft) long. Weakly fracture distribution is detected from wellbore images. No skin and low permeability on the order of 0.01 mD were estimated from the well test analysis. So the objective of this stimulation is not the removal of drilling and completion damage, but the improvement of natural fracture conductivity. The stimulation program was comprised of three stages that alternated 15% HCl preflush, 12% HCl + 3% HF main acid, NH4Cl overflush, and particulate diverting agent. The volumes of preflush and main acid were 80 gallon/foot each. The significant pressure drops indicating the injectivity improvement were observed during both preflush and main acid injection. The oil production dramatically increased from 1.5 kl/day (10 BOPD) to 50.0 kl/day (315 BOPD). The productivity index also increase from 0.3 kl/day/MPa to 45.0 kl/day/MPa. This test is the first successful stimulation of the tight oil formation in Japan.
Country:
- Asia > Japan > Honshu Island > Akita Prefecture (0.71)
- North America > United States > California (0.70)
Oilfield Places:
- North America > United States > California > Monterey Formation (0.99)
- Asia > Japan > Honshu Island > Akita Prefecture > Ayukawa Field (0.99)
SPE Disciplines:
Research for Microbial Conversion of Residual Oil into Methane in Depleted Oil Fields to Develop New EOR Process
Maeda, Haruo (INPEX Corporation) | Miyagawa, Yoshihiro (INPEX Corporation) | Ikarashi, Masayuki (INPEX Corporation) | Mayumi, Daisuke (AIST) | Mochimaru, Hanako (AIST) | Yoshioka, Hideyoshi (AIST) | Sakata, Susumu (AIST) | Kobayahsi, Hajime (University of Tokyo) | Kawaguchi, Hideo (University of Tokyo) | Sato, Kozo (University of Tokyo)
Abstract We are trying to develop a methane-producing system using indigenous microbes in depleted oil fields as a new microbial enhanced oil recovery process. In particular, we aim to combine a microbial conversion of the residual oil into methane with the geological sequestration of carbon dioxide. The mechanism is as follows: Hydrocarbon-degrading bacteria are harnessed to produce hydrogen and/or acetate from residual oil in the depleted oil reservoir. Then, methane-producing microbes (methanogens) utilize the produced acetate or hydrogen and carbon dioxide, which is injected for geological sequestration, to generate methane. We successfully isolated hydrogen- and methane-producing microbes (hydrogen-producing bacteria and methanogens) from oil fields (Yabase and other oil fields) in Japan. Our analysis of microbial cultures incubated under high temperature and high pressure, the condition similar to in situ petroleum reservoir conditions, revealed that indigenous microbes in the reservoir brine are capable of generating methane by utilizing crude oil and carbon dioxide. Consumption/production rate of gases (methane and carbon dioxide) and acetic acid indicated that the methane production under reservoir conditions is likely mediated through two major pathways; the acetoclastic (acetic-acid utilizing) and the hydrogenotrophic (hydrogen and carbon-dioxide utilizing) pathways. Furthermore, by analyzing methane-producing ability of isolated microbes, we found that the syntrophic cooperation between hydrogen-producing bacteria and methanogens was critical for the methane producing under the reservoir condition. 0%.tures with carbon dioxideent Strikingly, addition of carbon dioxide accelerated methane production of the cultures. The methane production rate of the cultures, in which high concentration (10%) of carbon dioxide was supplied into the head spaces, was 0.30 mmol/L/Day. On the other hand, the cultures without the addition of carbon dioxide showed the methane production rate of 0.12 mmol/L/Day, significantly slower (ca. 40%) than the production rate of the cultures with carbon dioxide. These results suggested that addition (injection) of carbon dioxide into reservoirs might accelerate the microbial methane production. We further investigated the methanogenic communities and pathways in petroleum reservoirs by incubating the reservoir brine from the Yabase oil field, combined with radiotracer experiments and molecular biological analyses. The brine samples were incubated without exogenous-nutrient supplementation under the high-temperature and high-pressure condition (the in-reservoir condition). The radiotracer analysis (using C-biocarbonate and C-acetate) indicated that the methane production rate of hydrogenotrophic methanogenesis was 50-fold higher than that of acetoclastic methanogenesis, suggesting dominance of methane production by syntrophic acetate oxidation coupled with hydrogenotrophic methanogenesis in reservoir. In this study, we assessed the rate of oil biodegradation coupled with methanogenesis by using C-labeled toluene and hexadecane as tracers. The analysis revealed that the rate was very low, being only about one thousandth of that of the hydrogenotrophic methanogenesis. We are currently trying to enhance the crude-oil biodegradation for effective conversion of crude oil to methane. Our goal is to establish effective microbial conversion system from residual oil into methane in depleted oil fields as a new EOR technology.
Industry:
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.37)
SPE Disciplines: Reservoir Description and Dynamics > Improved and Enhanced Recovery > Microbial methods (1.00)
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