Globally, most oil fields are on the decline and further production from these fields is addressed to be practical in cost-effectiveness and oil productivity. Most oil companies are adopting two main technologies to address this: artificial intelligence and enhanced oil recovery (EOR). But the cost of some of these EOR methodologies and their subsequent environmental impact is daunting. Herein, the environmental and economic advantage of microbial enhanced oil recovery (MEOR) makes it the point of interest. Since, there is no need to change much-invested technology and infrastructure, amidst complex geology during MEOR application, it is entrusted that MEOR would be the go-to technology for the sustainability of mature fields.
Despite the benefits of MEOR, the absence of a practical numerical simulator for MEOR halts its economic validation and field applicability. Hence, we address this by performing both core and field- scale simulations of MEOR comparing conventional waterflooding. The field scale is a sector model(fluvial sandstone reservoir with 13,440 active grid cells) of a field in Asia - Pacific.
Here we show that pre-flush inorganic ions (Na+ and Ca2+) affect the mineralization of secondary minerals which influences microbe growth. This further influences carboxylation, which is relevant for oil biodegradation. Also, as per the sensitivity analysis: capillary number, residual oil saturation and relative permeability mainly affect MEOR. Secondary oil recovery assessment showed an incremental 6% OOIP for MEOR comparing conventional water flooding. Also, tertiary MEOR application increased the oil recovery by about 4% OOIP over conventional water flooding. It was established that during tertiary recovery, initiating MEOR after 5years of conventional waterflooding is more advantageous contrasting 10 and 15years. Lastly, per probabilistic estimation, MEOR could sustain already water-flooded wells for a set period, say, a 20% frequency of increasing oil recovery by above 20% for 2 additional years as highlighted in this study.
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.
Ueda, Kenji (INPEX Corporation) | Ono, Kenya (INPEX Corporation) | Fuse, Kei (INPEX Corporation) | Nonoue, Ayako (INPEX Corporation) | Furui, Kenji (Waseda University) | Mustapha, Hussein (Schlumberger) | Tsusaka, Kimikazu (INPEX Corporation) | Furuta, Kohei (INPEX Corporation) | Rodriguez-Herrera, Adrian (Schlumberger) | Makimura, Dai (Schlumberger) | Manai, Taoufik (Schlumberger) | Ito, Toru (INPEX Corporation)
The legacy of conventional fields has resulted in many low permeability reservoirs deemed sub-commercial without an appropriate stimulation strategy. With low permeabilities and potentially heterogeneous reservoir characteristics, an optimal development approach would highly depend on their specific reservoir properties that may well require stimulation methods other than hydraulic fracturing. In this paper, we present a fully integrated characterization and modeling workflow applied to the Kita-Akita oil field in northern Japan, demonstrating the screening process for multiple completion and stimulation methods in a highly heterogeneous, low permeability sandstone reservoir.
To select a best completion and stimulation candidate from multiple methods, we constructed an evaluation matrix including the maturity of technologies, applicability to our reservoir, productivity, and economics. Multi-branch type completions such as radial drilling and fishbone drilling, as well as hydraulic fracturing were simulated and subsequently compared based on their productivities. Especially for the radial drilling and the fishbone drilling, a 3D FEM model was built for their complex laterals, and the inflow performances were evaluated with homogenous reservoir properties, respectively. Besides, due to the highly heterogeneous nature of the reservoir, we built a full-physics subsurface model based on a pilot-hole data acquisition and legacy 2D seismic lines. The 3D model served as a canvas to assess reservoir flow and geomechanical behavior, calibrated with production history from past producing wells in the 1950's to 1970's. Based on these models, the best infill drilling location was selected and multiple well completion and stimulation practices were evaluated.
Through the screening methodology, the multi-stage hydraulic fracturing was identified as the best suited from an instantaneous productivity perspective. Yet, even though hydraulic fracturing would enhance the accessibility into multiple distinctively isolated sandstones occurring in the deepwater slope channel setting, the treatment costs exceeded the economic threshold significantly in our case. Inflow performance evaluation based on the 3D FEM modeling illustrates multi-branch type completions such as radial drilling and fishbone drilling were identified with a good stimulation skin factor. As a result of 3D simulation study, multi-branch completion was revealed as a technical and economically viable stimulation option in the heterogeneously distributed sandstone reservoirs.
The advent of recent completion and stimulation techniques now renders low permeability reservoirs with relatively large development potential. Even with the development challenges quite different from conventional reservoirs, the approach shown in this paper provides a helpful reference for the study and decision-making process when the legacy field needs an optimal stimulation strategy.
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-2. 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
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".
Sugai, Yuichi (Kyushu University) | Komatsu, Keita (Kyushu University) | Sasaki, Kyuro (Kyushu University) | Mogensen, Kristian (Maersk Oil Research & Technology Centre) | Bennetzen, Martin Vad (Maersk Oil Research & Technology Centre)
Application of a thermophilic anaerobic bacterium which degrades long-chain alkanes of crude oil preferentially and induces oil viscosity reduction to MEOR in our target oilfield was evaluated in this study. Although the salinity of formation-water in our target reservoir is approximately 10 % which is considerably higher than the optimum salinity for the bacterium, the bacterium can grow well and induce oil viscosity reduction in the formation-water which was diluted with sea-water whose salinity was approximately 4 % and contained yeast extract as a nitrogen source. Oil viscosity was reduced to 70 percent of its original viscosity after two-week incubation of the bacterium in the culture medium consisting of sea-water supplemented with 1.0 g/L of yeast extract.
The performance of MEOR using this bacterium was evaluated by numerical simulation using two dimensional oil-water two-phase flow model. This model consists of 6 compositions: degraded oil, undegraded oil, brine, bacterium, sodium chloride and yeast extract. Undegraded oil and yeast extract are carbon source and nitrogen source for the bacterial growth respectively. Growth rate of the bacterium is calculated by Monod equation depending on the variables of the concentration of yeast extract and sodium chloride. Conversion of undegraded oil into degraded oil is depended on the proliferation of the bacterium. Growth of the bacterium is stopped by deficiency of either yeast extract or undegraded oil. Oil viscosity is reduced as the percentage of degraded oil in oil phase increases. Residual oil saturation is improved by oil viscosity reduction and enhancement of oil recovery can be obtained.
According to the numerical experiments, growth of the bacterium and oil viscosity reduction were found only around the injection well because the bacterium consumed whole yeast extract around there. Recovery factor therefore can be increased by increase of injection volume of yeast extract. As a result, enhancement of oil recovery reached to 5 % by 1.0 pore volume injection of sea-water containing the bacterium and 1.0 g/L of yeast extract. 100 bbl of oil was recovered additionally by using 1.0 tons of yeast extract in that case.
Application of oil-degrading bacteria to microbial enhanced oil recovery (MEOR) is economically advantageous because it is unnecessary to inject carbon sources for bacteria such as molasses into oil reservoir. This kind of bacteria can be expected to reduce oil viscosity, generate surfactants and/or gases by degrading parts of crude oil in oil reservoir and enhance the oil recovery.
Lazar et al. (1999) suggested bacterial reduction of the fraction of long-chain n-alkanes in biotechnological processes for waxy crude oil recovery. Although various hydrocarbon-degrading bacteria have been applied in MEOR so far, most of them were aerobic and/or facultative anaerobic bacteria such as Pseudomonas spp. (Sadeghazad and Ghaemi, 2003), Bacillus spp. (Wankui et al., 2006), Acinetobacter spp. (Kotlar et al., 2007), Brevibacillus spp. (Wang et al., 2008) and so on that degraded hydrocarbons aerobically. Aerated nutrient solution was injected into oil reservoirs in MEOR field trials using those aerobic bacteria (Youssef et al., 2010). According to the aerobic method, the growth of bacteria should be limited around the injection wells because the dissolved oxygen is completely consumed around there. Much increase of oil recovery therefore cannot be expected by this method. Thus the application of anaerobic oil-degrading bacteria in MEOR is one alternative to improve the performance of MEOR.
Maeda, Haruo (INPEX) | Miyagawa, Yoshihiro (INPEX) | Ikarashi, Masayuki (INPEX) | Mayumi, Daisuke (National Institute of Advanced Industrial Science and Technology) | Mochimaru, Hanako (AIST) | Yoshioka, Hideyoshi (National Institute of Advanced Industrial Science and Technology) | Sakata, Susumu (AIST) | Kobayashi, Hajime (University of Tokyo) | Kawaguchi, Hideo (University of Tokyo) | Sato, Kozo (U. of Tokyo)
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 14C-biocarbonate and 14C-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 14C-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.
An anaerobic oil-degrading thermophile, Petrotoga sp. AR80, was isolated from reservoir brine of an oilfield in Japan. This bacterium degrades long-chain hydrocarbons of crude oil into shorter-chain hydrocarbons in brine medium. Therefore, the oil viscosity can be decreased and the enhancement of oil recovery can be expected by this bacterium. The potential of this bacterium as a candidate for MEOR was estimated in this study. Some nitrogen source which is essential for bacteria should be injected into reservoir to stimulate the bacterial growth. To select a suitable brine medium for this bacterial activity on the reduction of crude oil viscosity, the numbers of nitrogen sources were evaluated. The highest growth rate was observed in medium contained yeast extract with maximum cell concentration in this medium was 10 times higher than that in other mediums. The influence of reservoir conditions such as temperature, salinity, and pressure on the bacterium was evaluated.
This bacterium can grow and decrease oil viscosity at a temperature between 50 °C and 70 °C. The oil viscosity incubated with Petrotoga sp. AR80 was 46.3 %, 51.6 % and 65.9 % lower than control after 3 weeks incubation at 50 °C, 60 °C and 70 °C. In addition, the oil viscosity was 35.1 % lower than control at 70 °C and 800 psi. The result of GC chromatogram showed that this bacterium can convert and/or degrade various components of oil lead to depletion in heavier oil components and enrichment of light oil components respectively. Oil extracted from Oman, China and Canada can be utilized by this bacterium instead of Japanese oil. These results show that the isolated bacterium can be applied to a wide range of reservoirs for MEOR. In addition, this bacterium achieves economically feasible MEOR because it doesn't need costly nutrients such as molasses which has been used as a nutrient in MEOR.
One thermophilic anaerobic oil-degrading bacterium was successfully isolated from reservoir brine of Yabase oilfield, INPEX Corp., Akita, Japan. The potential of the isolated bacterium as a candidate for Microbial EOR (MEOR) was estimated in this study.
This bacterium was identified as Petrotoga sp. by DNA sequencing analysis. The isolated bacterium can degrade long chain hydrocarbons in crude oil into shorter chain hydrocarbons in reservoir brine containing 2 (v/v) % of crude oil as a carbon source and 0.1 g/l of yeast extract as a nitrogen source. As a result, the viscosity of crude oil decreased. The isolated bacterium can form their bacterial colonies on a solid medium exclusively under the presence of CO2 in gas phase. In addition, the results of GC-MS analyses of crude oil showed that the isolated bacterium can degrade longer chain of n-alkanes more selectively under 10 % CO2 atmospheric condition. These results show that CO2 stimulate the growth of the isolated bacterium and selective degradation of longer chain of n-alkanes by the bacterium.
The suitable nitrogen source for the isolated bacterium was evaluated by reduction of viscosity of crude oil. Ammonium nitrate, urea, and yeast extract were evaluated for the nitrogen source and added into the medium containing crude oil with 2 (v/v) %. The highest growth rate of the bacterium was observed in the medium containing yeast extract. Viscosity of crude oil reduced by 40 % of its original viscosity in this case while ammonium nitrate, urea and non-nitrogen source addition gave 38 %, 35 % and 12 % oil viscosity reduction after 3 weeks incubation. 0.05 g/l of yeast extract is enough for the growth of the isolated bacterium.
The isolated bacterium can grow under high salinity condition such as 90 g/l of NaCl and it can grow under the temperature between 50 to 80 oC. These results show that the isolated bacterium can be applied to wide range of reservoirs.
Sugai, Yuichi (Kyushu University) | Niimi, Toshiya (Kyushu University) | Sasaki, Kyuro (Kyushu University) | Hattori, Yoshiyuki (Chugai Technos. Corp.) | Kano, Sanae (Chugai Technos. Corp.) | Mukaidani, Tsukasa (Chugai Technos. Corp.) | Fujiwara, Kazuhiro (Chugai Technos. Corp.) | Okatsu, Komei (Japan Oil, Gas & Metals Natl. Co)
CO2 sequestration into depleted oil reservoir has been expected as a method of reducing CO2 emission. Moreover, the authors focus on in-situ microbial conversion process of carbon dioxide into methane by hydrogenotrophic methanogens that inhabit oil reservoir universally. It is important for this process how to supply hydrogenotrophic methanogens with hydrogen for their methane production in reservoir. This study is aimed at searching for the oil-degrading and hydrogen-producing thermophilic bacteria (ODHPTB) which can produce hydrogen from oil in reservoir brine.
Reservoir brine was extracted from 10 producing wells in Yabase oilfield in Japan. Indigenous bacteria in brine samples were incubated with sterilized oil under anaerobic conditions (10% CO2 balance N2) at 50oC and/or 75oC. Both the production of hydrogen and methane and the consumption of carbon dioxide were observed in almost all culture solutions after 2months incubation. The maximum rate of hydrogen production was 20.9 Nml/L-medium/day.
These culture solution and raw brine were inoculated into nutrient agar medium and incubated under anaerobic conditions at 50oC and 75oC. Microbial single colonies formed in the nutrient agar medium after 2weeks incubation were picked and inoculated into sterilized brine including sterilized oil as a hydrogen source. More than 40 strains were isolated and incubated in the brine medium and 24 strains were observed to produce hydrogen from oil after 1 month incubation. The maximum rate of hydrogen production was 1.0 Nml/L-medium/day.
These results show that the in-situ microbial conversion process of carbon dioxide and residual oil into methane using ODHPTB and hydrogenotrophic methanogens is promising. Moreover, the most talented ODHPTB that was isolated in this study can be injected into reservoir in order to stimulate the conversion of carbon dioxide into methane.
Fujiwara, Kazuhiro (Chugai Technos Co.,Ltd) | Mukaidani, Tsukasa (Chugai Technos Co.,Ltd) | Kano, Sanae (Chugai Technos Co.,Ltd) | Hattori, Yoshiyuki (Chugai Technos Co.,Ltd) | Maeda, Haruo (Teikoku Oil Co. Ltd.) | Miyagawa, Yoshihiro (Teikoku Oil Co. Ltd.) | Tkakabayashi, Katsumo (Teikoku Oil Co. Ltd.) | Okatsu, Komei
Research into the microbial restoration of methane deposits has been carried out since 2003. The objective of this research is to estimate the possibility of microbial restoration of methane deposits using subsurface sequestered CO2 and indigenous anaerobes in depleted oil and gas fields. The most important factors are the efficiency and velocity of methane conversion by indigenous anaerobes inhabiting a reservoir.
Fluid samples (producing oil and water) from gas and oil fields in Japan were collected and analyzed in order to clarify the existence and survivability of indigenous hydrogen- and methane-producing anaerobes under severe reservoir conditions (high temperature and high pressure). PCR-DGGE analysis, a molecular biology method, was applied to reservoir samples such as reservoir brine, crude oil and producing water from the gas/oil fields. Some hydrogen-producing thermophilic bacteria (HPTB) and methane-producing thermophilic archaea (MPTA) which participate in the microbial restoration of natural gas were detected at the DNA level in some of the samples. Isolation of HPTB and MPTA was also attempted individually, and two strains of HPTB and one strain of methanogen were successfully separated.
Subsequent to these findings, accelerated hydrogen- and methane-producing experiments, using glucose as a carbon source, have been conducted at the laboratory level to estimate the potential for microbial methane production under actual reservoir pressure and temperature (5MPa, 50°C) and the rock pore as micro culture space. Experiments, using the isolates described above and active anaerobes which were not isolated from the reservoir brine, indicated that microbial hydrogen- and methane-producing efficiency and velocity are relatively high even in various reservoir conditions. Furthermore, if a suitable and economical carbon source is available, depleted oil reservoirs are potentially good candidates to become subsurface microbial reactors, using hydrogen- and methane-producing indigenous anaerobes containing HPTB and MPTA to convert injected CO2 into methane.