United Petroleum Development Co., Ltd. constructed a sour gas injection platform, the project is called “Bunduq Gas Injection Project”, in El-Bunduq oil field situated on the offshore border between Abu Dhabi and Qatar. The project was implemented for the protection of environment by recovering 1 MM scf/d of acid gas otherwise being flared and for the enhancement of oil recovery by re-injecting 40 MM scf/d of associated sour gas (H2S 12%) into the oil reservoirs after the compression up to 6,000 psi. Due to the hazardous nature of gas, the sour gas injection facilities are usually installed on the ground and it seems that there is no other example especially for such high pressure and high H2S compression at offshore platform. Thus I wish to introduce some valuable concepts to install sour gas injection facilities on offshore platform taking into account stable and safety operation based on the experience of the Bunduq's project as follows; 1) Install compact high speed reciprocating compressors in order to cut back the platform cost and decrease the vibration. 2) Secure safe sour gas compressor start-up operation by boosting small amount of sweet gas prior to full amount of sour gas. 3) Minimize number of personnel on the platform by utilizing automatic control for the operation. 4) Design the layout of facilities on the platform not to cause significant accumulation of flammable gas. 5) Optimize the layout of facilities and the operation philosophy to minimize the risk by repeating the safety analysis.
The author carried out reservoir characterization and flow simulation studies as a member of the multidisciplinary study team formed to optimize the production scheme of Iwafune-oki oil field. This paper presents the geostatistical modeling of submarine fan deposits in the field. Stratigraphic framework for each horizon boundaries and fault surfaces were modeled by integrating well-marker data and depth-converted seismic horizons. Three-dimensional distributions of shale volume contents (Vsh) and effective porosity were modeled using various geostatistical techniques. The modeling procedure was validated by comparing the geostatistical facies model with a deterministic geological facies model. All available information, including production data were integrated into the model, which clearly answered many questions that could not be explained with the deterministic one and changed the team's view on the field. Findings from this study led management's decision to apply gas injection for oil recovery enhancement. The field's oil production has been dramatically improved by the proposed gas injection.
Japan Oil Development Company (JODCO) participates in the development of several oil fields in the offshore oil field in Abu Dhabi, through Joint Venture with Abu Dhabi National Oil Company (ADNOC) and other Shareholders. The subject “A” oil field has carbonate reservoirs, 40 km×30 km closure and has started production since 1967. Peripheral water injection and crestal gas injection have been applied for pressure maintenance since 1972 and 2005 respectively. Further development studies are ongoing for an increase in recovery and overcoming further pressure decline. Down flank gas injection is considered as one of the most attractive schemes. Therefore, gas injection pilot test has commenced to evaluate the effectiveness of full field down flank gas injection in “A” oil field since 2001. 10 dedicated wells (6 gas injectors, 2 producers and 2 observers) have been drilled in sublayers A, B and C. Line drive gas injection scheme is being tested in sublayers A and B. Five spot gas injection scheme is being tested in sublayer C. Currently long term gas injection test and extensive reservoir surveillance are ongoing. The main criteria for success of the pilot are sweep efficiency (vertical, lateral and microscopic), miscibility, residual oil saturation to gas (Sorg) and impact on the aged facilities. This report introduces the summary of the pilot test and its reservoir performance to date.
Due to the recent soaring of oil and gas price, the exploration activities to seek new oil and gas fields has dramatically accelerated. At the same time, the application of the secondary and the tertiary recovery scheme to the existing oil fields has been drawing industry's keen attention. The Enhanced Oil Recovery (EOR) based on gas injection is not necessarily a new technology but it has more than 80 years of history since its inception during 1920s. The U.S. Department of Energy (DOE) has recently announced that the EOR based on the gas injection technology has been recognized as proven technology and they have started re-evaluation of the national oil reserves taking the gas injection technology into consideration to re-assess some of major onshore fields. In the early days, gas injection operations were conducted in the purpose of reservoir pressure maintenance, however, it has been recognized as time that the gas injected into reservoir has other benefits, such as improving recovery factor of heavy crude by means of improving its mobility, improving recovery factor of crude in general under miscible condition by means of improving sweep efficiency, etc. Miscible gas flooding has a huge potential to dramatically improve crude recovery factor, therefore, more gas injection projects that are currently on-going are targeting this scheme. On the other hand, proffessor Dandina Lao, et al. at Louisiana State University (LSU) are proposing a new method based on a new concept, Gas Assisted Gravity Drainage (GAGD) process. They have been continuously obtaining good results in their investigation and research, which has been making the expectation to GAGD process even higher. In this paper, the author anticipates to compare the features of conventional immiscible gas flooding such as WAG (Water Alternate Gas Injection), currently-remarked miscible gas flooding and the latest GAGD process, as well as, to introduce an example of preliminary study conducted on the field located U.S. GoM offshore deep water where a gas injection EOR has been planned to implement.
Recently, High Pressure Air Injection (HPAI) is considered to be an effective EOR method to light oil reservoirs. HPAI has some remarkable merits as follows. (1) Injection gas source is air, which can be supplied anywhere. (2) Initial and operation costs are inexpensive because the main facility required is only air compressor and air is free. (3) Air can be applied even in low permeable reservoirs where water cannot be injected. However, it is pointed out that the evaluation method for HPAI is difficult, because oxidation and combustion reactions are complicated. A Japanese domestic oil field has been investigated to apply HPAI since 1999. A series of experiments is essential in HPAI study. Accelerating Rate Calorimeter (ARC) test and Combustion Tube (CT) test are generally conducted to evaluate a potential of air injection in fields. ARC test is used to determine the extent and continuity of reactions in the low and high temperature range. The purposes of the CT test are (1) to assess the overall burning characteristics of oil, (2) to measure incremental oil production, air and fuel requirements and other parameters and (3) to measure produced gas compositions and oil and water production to provide benchmarks for monitoring future field operations. The results of ARC tests suggest that the ignition temperature of the oil may be higher than the reservoir temperature. It means an artificial ignition method should be conducted for HPAI in the field. Additional ARC tests were carried out to assess the influence of oxygen slug, NO2 addition and linseed oil on ignition temperature as the ignition method. The experimental results suggest that the linseed oil method is the most promising, because the ignition temperature with high concentration of linseed oil is below the reservoir temperature. Two CT tests were also conducted, in low water saturation case and high water saturation case after waterflooding, to estimate applicability of HPAI including on tertiary mode. Both tests show stable combustion performance in terms of temperature, pressure response, produced gas compositions and incremental oil production. On the other hand, numerical simulation is important to predict field production performance. The appropriate reaction kinetics on the combustion has to be used in the numerical simulation. History matching with CT tests was conducted to obtain the kinetics. Two kinds of reactions, “oxidation reaction” and “combustion reaction” were used in the study. In the former reaction, oxygen is consumed by the oil to form oxidation compounds. In the latter one, oxygen reacts with the compounds to form carbon dioxide and water. Reaction parameters were used as matching parameters. Good results of history matching with both CT tests using same reaction kinetics were obtained.
JCOP (Japan CO2 Sequestration in Coal Seams Project) has been commenced since JFY2002 with full subsidy from Ministry of Economy, Trade and Industry. Yuubari area of Ishikari coal field in Hokkaido was selected as the most suitable pilot test field, because the coal seams of this area are gassy and permeable. The preliminary field experiment was designed to investigate technical and economical feasibility of storing CO2 in coal seam until end of JFY2007. Injection well (IW-1) was drilled in the end of 2003, production well (PW-1) was drilled in the summer of 2004. The distance in the coal seam between the vertical injection well (IW-1) and the deviated production well (PW-1) was about 65m. CO2 injection and CH4 production tests were carried out from the end of this August to the end of October, 2007. From the measurement results, gas and water production rates were observed lower than estimated rates. The gas production rate increased gradually after carbon dioxide injection and then it reached the peak. After stopping injection, gas production rate decreased gradually to the initial gas production level. It is seems that this increase was due to the carbon dioxide injection. CO2 injection rate were also observed lower than estimated rate. History matching was carried out using the measured water production rate in 2005. From the results of history matching, these measured gas production rates were in agreement with calculation results. At that calculation, bottom of pressure of production well was 9MPa and permeability around the injection well was 0.13md. The high bottom hole pressure of production well shows that production damage is occurred. It is considered that perforation holes or cleat of coal plugged with fine coal particles might have caused this production damage. Two reasons for the decrease of permeability around injection well can be considered. One is that the gap of the coal cleats was reduced by the swelling of coal matrix due to CO2 adsorption. The other is that coal cleat was plugged by fine coal particles. From the measurement of gas content of coal in this test, it is conformed that gas content of coal seams in Ishikari coal field are in highest level. If the above mentioned problems on production damage is solved, CO2 injection into the coal seam and development of CBM will be commercialized soon.
Inpex and Chugai Technos have been working since 2006 to study methane-producing technology using microbes inhabiting depleted oil fields. The concept and mechanism of microbial methane conversion are depicted as follows. First, hydrogen producing microbes (bacteria) prompt to produce hydrogen from residual petroleum components in the depleted reservoir. Next, methane-producing microbes (methanogens) are concerned in generating methane from the hydrogen and carbon dioxide injected for geological sequestration. The research team in Inpex and Chugai Technos has successfully isolated samples of hydrogen- and methane-producing microbes from the depleted oil fields in Japan (10 hydrogen producing thermophilic bacteria and 4 methane producing thermophilic archaea). It was confirmed that continuous methane production took place using indigenous microbes in the reservoir brine and crude oil as a carbon source with 10 mol% of CO2. Produced gas (methane, carbon dioxide) and concentration of acetic acid indicate that there are 2 reaction pathways from oil to methane. One is the acetoclastic methane producing pathway, another is hydrogentrophic methane producing pathway. Furthermore, from the result of methane producing experiments using isolated microbes, we found there was some syntrophic cooperation between hydrogen producing bacteria and methanogen (methane producing archaea). We must investigate the suitable combination of these microbes in order to get an effective methane production. The next step will be to evaluate the way to enhance the capability of methane-producing microbes and to identify an effective and efficient process of producing methane in the actual reservoir (porous media) condition. If successful, it will be a big step toward building a carbon cycling system that converts residual oil in depleted oil fields into environmentally friendly methane.
The applicability of a semianalytical technique for the evaluation of inflow control effects in complex geological settings is assessed. The semianalytical approach, based on Green's functions, is extended through the development of an improved approximation for near wellbore heterogeneity. The basic heterogeneity model describes the permeability field in terms of a locally varying skin and a global effective permeability. The proposed framework in this work consists of three steps. The first part is to evaluate settings of inflow control devices to achieve uniform fluid inflow to the wellbore with the semianalytical technique. The second step is to convert effects of inflow control devices to skin values to account for the same pressure drop in each completed section. The third step is to evaluate the effects of uniform influx with a full filed finite difference simulation model. Results obtained in this work suggest that the semianalytical approach is a practical tool to model the performance of nonconventional wells (e.g., deviated, horizontal or multilateral wells) equipped with inflow control devices in real filed settings.
Widespread exploration for oil and gas in the Niigata oil and gas fields, involving extensive drilling, has shown that Early to Middle Miocene volcanic rocks bearing the petroleum and natural gas are extensively developed, and they have been buried at depths greater than 4,000-6,000 m since the Middle Miocene. We determined Sr and Nd isotopic ratios of volcanic rocks recovered by deep drilling at thirteen wells in the fields. The present and our previous data demonstrate that these deep-seated basaltic rocks older than about 16 Ma have lower NdI (initial 143Nd/144Nd ratios) compared to those younger than 16 Ma. The former NdI (0.51264 to 0.51284) are within the Nd isotopic range of an undepleted source mantle shown by NdI of basaltic rocks older than about 15 Ma outcropped at the land surface of the back-arc margin of the NE Japan arc, whereas the latter NdI (0.51285 to 0.50302) within the Nd isotopic range of a depleted source mantle shown by NdI of basaltic rocks younger than about 15 Ma from the back-arc margin of the NE Japan arc. The NdI of basaltic rocks collected from each drilling well vary only slightly, whereas the SrI (initial 87Sr/86Sr ratios) of these rocks range widely and deviate systematically from the areas of the undepleted and depleted source mantle in SrI-NdI diagram. In addition, thirty samples, older than about 16 Ma, including basaltic andesite, andesite and more felsic volcanics, collected from eight drilling wells in the southern part of the fields have nearly constant NdI of around 0.51275, but these rocks have SrI ranging widely from 0.70554 to 0.70851, indicating changes of SrI due to alteration by seawater for these volcanic rocks which were produced from basaltic magma by fractional crystallization. Consequently, the present results imply that the alteration of underground oil and gas-bearing volcanic rocks by seawater caused significant increases of 87Sr/86Sr ratios, whereas the 143Nd/144Nd ratios remained virtually unchanged. Rhyolitic rocks older than about 16 Ma collected from three drilling wells in the northern part of the fields show significantly higher SrI values (0.70727 to 0.70914) and lower NdI values (0.51247 to 0.51265) than the recovered basaltic rocks prior to about 16 Ma, indicating a lower crust origin for these rhyolitic rocks.
Rising oil prices brings a serious risk to the global economy. There is no doubt that expanding the voluntary development of oil reservoir will be required under these circumstances. On this background, applying a Microbial Enhanced Oil Recovery (MEOR) technique to high oil saturation reservoirs which hold the promise and profitability for the higher recovery of oil becomes more important for the establishment of MEOR technique as a most effective technology. Moreover, expanding MEOR applicability to various reservoir conditions, such as ultra-high temperature and ultra-low permeability, will also become critical assignments. For the prospect of methodology of MEOR, applying anaerobic heterotrophic bacteria and autotrophic bacteria which can use low cost materials as an energy source existing in reservoirs, such as hydrocarbon and inorganic salt, will get to hold a great promise. Some genetically modified bacteria may also become actively usage for MEOR process in near future. The fundamental assignment for the MEOR technology is to overcome the issue of regulating microbes based on the results of some investigations, namely, diversity and distribution of microbes related to MEOR process, and their function on the MEOR effect using nutrients injected into the reservoir. The JOGMEC TRC-Jilin Oil Corp. international joint-research also reported previously clarified the following assignments on regulating microbes for field operation : selecting method of microbial function for MEOR, sterilization technique of surface facility, injection techniques of microbes, nutrients and additives, and transplanting target microbes into the formation where needed. As a conclusion, the biotechnology and microbiology which affect the development of oil/gas reservoir will be able to provide originality aspects to break through the numerous issues involved in EOR/IOR.