The beginning of CO2-EOR in Japan, is actually after the Oil Crisis in the 1970's. Since its first patent was issued in the US in 1952, CO2-EOR has continuously been researched and operated for more than half a century supported by large investments. Field implementations particularly increased after 1972 when the SACROC project in west Texas started. Since then, CO2-EOR has rapidly developed into a mature technology with more than a hundred cases onshore. CO2-EOR research in Japan started in 1979 when JOGMEC (former JNOC) TRC (Technology and Research Center) took part in an International Research and Development project of IEA (International Energy Agency). Researches on fundamental topics such as phase behavior of oil and CO2, Equation of State (EOS) and compositional reservoir simulations played important roles and led to the implementation of pilot tests in both domestic and foreign countries' fields, those are, Kubiki (1988) and Sarukawa (1993-2000) in Japan, and Ikiztepe (1988-1995) in Turkey. Although it suffered during a long period of low oil price, many fundamental researches in related technology continued to maintain the progress towards field scale developments by CO2-EOR. Recent activities include feasibility studies such as in Mexico (Cactus, 2000) and UAE (1996), laboratory experiments such as X-ray CT core measurements and asphaltene deposition experiments, and researches on CO2 capture and corrosion protection. JOGMEC continues to take part in collaborative researches with oil and gas producing countries. Ongoing projects are in UAE, Mexico, and also in Vietnam where a CO2-EOR pilot test has recently been implemented in the offshore Rang Dong Field, just before this Symposium. This paper aims to summarize the progress of CO2-EOR by looking back on its achievements in Japan for over the past 30 years, and to send a message on what we can expected from it in the near future.
JAPEX (Japan Petroleum Exploration Co., Ltd.) executed a pilot test of CO2 flooding in Sarukawa oil field from 1993 to 2000 collaborating with JNOC (Japan National Oil Corporation). Although CO2 flooding is a wellknown and well understood EOR technology, it is important to realize how and where injected fluid flows and sweep in subsurface reservoir. Depending on information that suggests the fluid flow in situ, injection and production operation must be adjusted and optimized. A five spot pattern was employed for the pilot test. In order to realize how and where injected fluid flows and sweep in subsurface reservoir, several measurements, studies, analyses must be conducted. In laboratory, reservoir core analyses, reservoir fluid analyses, PVT of reservoir oil and CO2 mixtures are typical. Combining those laboratory data with well logging data and well flow test data, numerical simulation models were constructed. Such numerical models were initially utilized for designing pilot test. Before injecting CO2, water flooding was conducted to obtain history data. After water flooding, CO2 injection and WAG followed. During and after pilot test, tremendous amount of data, not only history data but also well test data that indicates heterogeneity of target reservoir, were collected and analyzed. Based on those results, original numerical models were modified and tuned to match history data. After history matching, case studies were conducted to understand what was happening in the reservoir, and to predict how the performance should be if operation scheme was varied. Performance of EOR such as CO2 flooding is dominated by fluid flow in target reservoir. It cannot be overstressed that the heterogeneity of target reservoir should be well recognized before commercial scale EOR technology is applied.
Since 1988, a CO2 tertiary flood project was conducted in Kubiki Oil field, which located in Niigata prefecture facing the Japan Sea.First three years of the project was spent for pre-injection study. Well logs and core analyses were used to predict the residual oil saturation. Bottomhole fluid sample was taken to measure PVT properties and to perform core-flooding test including MMP under reservoir condition. Based on these results, the pilot test was adequately designed. The injector, EOR-1, and the two observation wells, EOR-2 and EOR-3 were drilled. CO2 injection was commenced in February, 1991 with an inverted four-spot pattern and was continued through to June 1993. The injection rate was 15 ton/day and totally 9,777 tons of CO2 was injected, well log and fluid samples were taken periodically and bottomhole pressure were automatically recorded by the surface readout system. CO2 breakthrough and oil production were observed in all the observation wells. The project was successfully finished and we acquired various knowledge of CO2 EOR through this project. In this paper we review Kubiki CO2-EOR project and summarize the knowledge.
Previously natural gas fields with low CO2 content have been preferably developed. Currently, however, there are many underdeveloped sour gas resources containing a significant concentration of CO2. The development of the gas field containing high concentration of CO2 requires sweetening and processing prior to give a natural gas product. There are a large number of technological options for the removal of CO2, which make the selection of the process technology a challenging issue. In this report, a method to evaluate the aforementioned process technologies was proposed in order to select the most competitive option. A case study was also carried out to evaluate various process technologies based on the proposed evaluation method.
Tens of million tons per year of CO2 are being captured from raw feed gas by natural gas plants and are then being released to the atmosphere. As interest in reducing CO2 emissions from the natural gas plants has increased in recent years, CO2 capture and storage (CCS) has gained in importance. Among the several types of CO2 capture technologies, chemical solvent based technology is widely used to meet product natural gas specification in CO2 content This paper discusses a new chemical solvent based CO2 capture technology (HiPACT ; High Pressure Acid-gas Capture Technology), a new concept to improve economic efficiency in CCS implementation, jointly developed by JGC and BASF. The solvent has high stability against thermal degradation, which enables high pressure and elevated temperature operation during solvent regeneration to reduce CO2 compression cost downstream. The solvent also has a higher CO2 absorption capacity than commercially available solvent technologies, which results in decreased solvent circulation rates and lower AGRU (Acid Gas Removal Unit) capital and operating costs. After the concept has been confirmed with pilot plant runs with stimulant gas, a demonstration test using INPEX's commercial natural gas plant has successfully completed.
In this lecture, a cold drainage mechanism of heavy oil from sandstone cores has been presented by using immiscible CO2 gas dissolution into the oil. Dissolution curves of CO2 and CH4 gases for Japanese heavy oil were measured using with a PVT apparatus to decide the pressures of bubble point for the gases. CO2 swelling factors of the heavy oil and Oman intermediate oil were measured from surface movements of oil columns placed in a high-pressure cell which was controlled less than 10 MPa for the oil reservoir temperature 50°C. Two oil swelling factors increased with increasing gas pressure, and swelling coefficients were evaluated for CO2 and CH4 gases. The swelling-time curves for an oil column were fitted with the analytical solution of one dimensional gas diffusion derivative equation, and CO2 gas diffusion coefficients in the oils, D(m2/s), were evaluated. The values of D in the heavy oil were presented as 1.1 to 1.6 % of that of the intermediate oil, and the empirical equation for values of D has been presented with function of exponential to API gravity. Based on the observation tests on oil drainage from the sandstone cores saturated with the heavy oil, gas dissolution in the heavy oil does not make any oil drainage, however foamy heavy oil including huge number of micron CO2 gas bubbles, that were generated in depressurization process, effectively contributed to oil drainage out from the cores.
INPEX Corporation, Tokyo University and Natural Institute of Advanced Industrial Science and Technology (AIST) have been working since 2008 to study methane-producing technology using microbes inhabiting depleted oil and gas fifields. The concept and mechanism of microbial methane conversion are depicted as follows. First, inhabiting bacteria prompt to produce acetic acid or hydrogen from residual petroleum components in the underground reservoir. Next, methane-producing microbes (methanogens) are concerned in generating methane from the produced acetic acid, hydrogen and carbon dioxide injected for geological sequestration as CCS operation. A wide variety of hydrogen- and methane-producing microbes have been discovered in (depleted) oil fields. We found that microbes indigenous to the reservoir brine could produce methane probably by using crude oil as a carbon source in the presence of CO2 (10 mol%). Kinetics of gas (methane, carbon dioxide) production and consumption of acetic acid indicated that there are two reaction pathways from oil to methane; the acetoclastic methane producing pathway and the hydrogentrophic methane producing pathway. Furthermore, from the result of methane producing experiments and Carbon isotope tracer test, the existence of syntrophic cooperation between hydrogen producing bacteria and methane producing archaea is also identified. We are currently evaluating the way to enhance the capability of methane-producing microbes and developing an effective and efficient process for methane production in the actual reservoir condition. Our results will lead to establish a new MEOR system that converts residual oil in depleted oil fields into environmentally friendly methane efficiently.
Carbon Dioxide Capture and Storage (CCS) is a key technology to reduce carbon dioxide emission to the atmosphere and needed to be widely deployed in the world as early as possible. Mainly many developed countries are advancing research, development and demonstration of CCS. The Japanese Government is also conducting an investigation for CCS demonstration project in Japan. Since 2009, field surveys have been conducted at three candidate sites. An offshore pipeline route survey was carried out at the Nakoso-Iwakioki candidate site in 2009, a preliminary survey well was drilled at the Kitakyushu candidate site in 2010, and two 3D seismic surveys were carried out and two survey wells were drilled at the Tomakomai candidate site through 2009 to 2011. A final geological evaluation is being conducted for the Tomakomai candidate site and a demonstration plan will be presented to the Government as soon as the geological evaluation has been completed.
In the Gulf of Thailand more than 4,000 wells have been completed since the first exploratory well, Surat-1 was drilled in 1971 and more than 30 oil and gas fields have been discovered starting with the first discovery of the Erawan structure in 1972 with first production in 1981. Most discoveries are located in the Pattani Trough and are of Cenozoic age. The Pattani Trough is rift type sedimentary basin approximately 200 kilometers length and 50 kilometers in width. Maximum basin thickness is more than 8,000 meters divided into five sedimentary units from Sequence 1 to Sequence 5. Two major unconformities have been identified, one of which is called Middle Tertiary Unconformity (MTU) and the other is Middle Miocene Unconformity (MMU). MTU is located in the deeper part of the basin and is deeper than can be penetrated by drilling whereas the MMU is located at a shallow depth. In addition to the Gulf of Thailand the MMU is commonly observed elsewhere in offshore South East Asia, but its erosional thickness and tectonic study are not well documented because the erosion surface is located in Sequence 4 where key marker beds are poorly developed due to the predominant continental sedimentation. Author estimated the erosional thickness of MMU for the 6 major gas fields located in the southern Pattani Trough based on “shale compaction trend” method proposed by Magara (1978) using sonic logs. Data from over 70 wells were used for this study. A result was obtained indicating more than 1,000 meters of erosional section for all fields in the study area. However, based on other geologic phenomena, such as tectonic movement, field structure, reconstructed structure, lithology, etc., this amount of erosion was considered to be too large. The causes of this erroneous value (high velocity on shale compaction trend of Sequence 4) is not clear at this moment but some possible causes could include chemical compaction due to high temperature as proposed by Bjorlykke (1999) and Puttiwongrak et al. (2011) and/or hydrothermal fluid entry into Sequence 4 precipitated in calcite veins through highly developed faults. Further study on causes of the high velocity of Sequence 4 and additional study in the northern part of the Pattani Trough will be needed to confirm whether high velocity shale in Sequence 4 is common and whether it is an indicator of the amount of erosion.
Polyglycolic Acid (PGA) and Polylactic Acid (PLA) are biodegradable resins. They have been widely used for medical operations, since the products left in human body dissolve with time. They are harmless and biodegradable. Granular CaCO3 has been used as a fluid loss control material for completion fluids. The mud cake has to be removed after completion equipment are installed, however, it tends to remain partially undissolved. The PGA powder and PLA powder turn to be liquid acids with time if they are mixed in water. They are also environmentally harmless if they are disposed in ocean. It is judged that these properties may be suitable to replace the granular CaCO3. Moreover, the adjustment is possible by mixing PGA with PLA for applications of wider temperature range.