Metals National Corporation Research Articles

Planning and Operations of the Hydrate 01 Stratigraphic Test Well, Prudhoe Bay Unit, Alaska North Slope

The National Energy Technology Laboratory, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey are leading an effort to conduct an extended gas hydrate production test in northern Alaska. The proposed production test required the drilling of an initial stratigraphic test well (STW) to confirm the geologic conditions of the proposed test site. This well was completed in January 2019 in cooperation with the Prudhoe Bay Unit Working Interest Owners. The Prudhoe Bay Unit Hydrate-01 STW was spudded on 10-December-2018. Downhole data acquisition was completed on 25-December-2018, and the rig was released on 01-January-2019. The Hydrate-01 STW was drilled in two sections, including the surface hole that was drilled to a depth of 2248 ft measured depth (MD) (685 m MD) and cased, and the production hole section that was drilled to a depth of 3558 ft MD (1084 m MD) and also cased. A thermally chilled mineral-oil-based mud was used in the main (production) hole section of the well to maintain wellbore stability and quality of the wellbore acquired data. The primary wellbore data were acquired using logging-while-drilling tools. A sidewall pressure core system was also deployed to gather grain size and other data needed for the design of the future production test wells. In addition to confirming the geologic conditions at the test site, the Hydrate-01 STW was designed to serve as a monitoring well during future field operations. Therefore, two sets of fiber-optic cables, each including a bundled distributed acoustic sensor (DAS) and a distributed temperature sensor (DTS), were clamped to the outside of the production casing and cemented in place. In March 2019, the project team acquired three-dimensional (3D) DAS vertical seismic profiling data in the Hydrate-01 STW. Temperature surveys were also acquired with the DTS as deployed in the Hydrate-01 STW during the completion of the well and nearly continuously since March-2019.

Achievement for Pilot Test of Excavating and Ore Lifting Conducted for Seafloor Polymetallic Sulphides

Seafloor Polymetallic Sulphides (PMS) is deep sea mineral that is confirmed to exist within Japanese exclusive economic zones and expected to develop as a new supply source for Japan. However, deep sea minerals including PMS have not been commercially developed so far, although various countries are eagerly working it. Japan Oil, Gas and Metals National Corporation (JOGMEC) has been commissioned by Ministry of Economy, Trade and Industry (METI) to conduct practical study on PMS for commercialization. As part of the efforts, JOGMEC implemented “Excavating and Ore-lifting Pilot Test” from the middle of August to end of September 2017. In the test, JOGMEC succeeded in consecutive lifting of ore and sea water in a state of solid-liquid flow from a depth of approximately 1,600m for the first time in the world. Through the test, it became clear that there are still many technical challenges left to be resolved for development of PMS such as improvement in durability of equipment, system optimization, adjustability of ore grain size and slurry concentration and so on. JOGMEC will continue efforts aimed at commercialization of PMS from a long-term perspective.

On availability analysis for pilot test of excavating and ore lifting conducted for seafloor polymetallic sulphides

Building the technologies to commercialize the mining of seafloor polymetallic sulfides which is promising mineral resource is necessary. Based on the both the Basic Plan on Ocean Policy (approved by the cabinet on April 26, 2013) and the Plan for the Development of Marine Energy and Mineral Resources (formulated by Ministry of Economy, Trade and Industry (METI)), METI and JOGMEC (Japan Oil, Gas and Metals National Corporation) started the national seafloor polymetallic sulfides developing project and planed to demonstrate the pilot test in actual sea to validate the technologies for especially excavating and ore lifting, which is the first test in the world. Usually testing in actual sea is not safety and economical because the marine condition is severe for the operation. Therefore three years studies to ensure both safe and availability were conducted which led the pilot test to succeed. This paper shows our procedure of the availability analysis for the pilot test with the results of numerical simulation, model experiments and operational window analysis. To investigate the accuracy of the numerical simulation and confirm the effectiveness of the operational window analysis, the comparison with the measurements in the actual sea is also shown.

Cuttings-Lag Distribution in Directional Wells Affects Depth Resolution of Mud Logging

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 189615, “Modeling of Cuttings-Lag Distribution in Directional Drilling To Evaluate Depth Resolution of Mud Logging,” by Shigemi Naganawa, SPE, The University of Tokyo, and Manabu Suzuki, Kenji Ikeda, Norihito Inada, and Ryosuke Sato, Japan Oil, Gas, and Metals National Corporation, prepared for the 2018 IADC/SPE Drilling Technology Conference and Exhibition, Fort Worth, Texas, USA, 6–8 March. The paper has not been peer reviewed. Dispersion of cuttings-transport velocity limits the depth resolution of mud logging. This paper presents an approach to modeling the cuttings-lag-depth distribution caused by the dispersion of cuttings-transport velocity in directional drilling. The presented approach has the ability to evaluate quantitatively the uncertainty in the depth resolution of mud logging that is crucial for improving the lateral quality of reservoir characterization, which can be beneficial in shale oil and gas projects. Introduction Drill-cuttings analysis in mud logging provides actual information in real time about the formation being drilled. However, cuttings moving up the wellbore annulus generally are dispersed because of the dependence of cuttings-transport velocity on particle size (e.g., small particles are easily transported, and large particles may be transported at a small fraction of the drilling-fluid velocity) and the existence of radial distribution in drilling-fluid velocity. This dispersion of cuttings-transport velocity limits the depth resolution of mud logging. Collecting and analyzing small cuttings is the best technique to minimize the dispersion of cuttings-lag time or lag depth. At the same time, the dispersion of cuttings-transport velocity because of the radial distribution of drilling-fluid velocity is independent of particle size and cannot be eliminated from the collected cuttings. In this attempt to model the cuttings-lag-depth distribution caused by the dispersion of cuttings-transport velocity in directional drilling, the depth resolution of mud logging in directional and horizontal wells is evaluated on the basis of cuttings-lag experiments and cuttings-lag-depth simulations using a developed model. The approach of cuttings-lag calculation is based on a previously developed complete physical model of transient cuttings-transport behavior in directional drilling. The lag distribution is modeled using the log-normal distribution probability density function. The parameters of the distribution function are determined by lag-time-measurement experiments for various hole-inclination angles using a large-scale cuttings-transport flow-loop apparatus. Average-Cuttings-Lag-Depth Equation Lag time is defined as the time required for drilling fluid, gas, or cuttings traveling from the bottomhole to the surface through the wellbore annulus. Lag depth is defined as the formation depth in which the cuttings sampled or collected at the surface originally existed. The drilling depth increases depending on the rate of penetration when the cuttings drilled at the lag depth are transported to the surface. The complete paper provides equations representing the relationship between current bit depth and lag depth and the lag-depth equation for consideration of cuttings-transport-velocity variation.

Technology Focus: Reservoir Performance and Monitoring (September 2017)

Technology Focus Since the last Reservoir Performance and Monitoring feature in September 2016, the industry trends of significantly improving efficiency and reducing operational costs have continued to be implemented. For instance, at the time of writing, in North America, the US oil rig count has risen impressively for 23 straight weeks and the big players have greatly reduced their exposure to Canada’s oil sands. However, while many efforts are focusing on the optimization of current technologies and the study of past reservoir performance to improve future developments, with fewer capital resources and personnel available, these efforts may yield only incremental improvements. Technology and innovation are seen industrywide as critical to long-term radical efficiency and productivity. Once the industry becomes less concerned about cost savings and more about investing in future technologies and long-term performance, the nonrisk-averse innovation culture from other industries could help us develop new disruptive technologies and implement them in the field. For instance, with the proper resources in place, automated reservoir-performance modeling and monitoring may no longer be a science-fiction scenario. Once this downturn appears in the rear-view mirror, our industry will need to change its model disruptively to thrive sustainably in the next growth cycle. During the past 12 months, 160 technical papers were presented at various conferences and meetings with reservoir-performance-and-monitoring programs and were reviewed for this feature, displaying further advances in reservoir-performance monitoring, analysis, and optimization. The papers selected and recommended as additional reading are representative samples of the reviewed papers. They are a geographically diverse mix of academic work, industrial research and development, and field applications, describing numerical simulation and laboratory research, field-data-acquisition and -interpretation studies, new-technology development and field trials, and multi-year reviews of current technologies and work flows. Recommended additional reading at OnePetro: www.onepetro.org. SPE 181550 Current State and Future Trends in the Use of Downhole Fluid Analysis for Improved Reservoir Evaluation by H. Elshahawi, Shell, et al. SPE 184131 Production Optimization Through Voidage Replacement Using Triggers for Production Rate by Cenk Temizel, Aera Energy, et al. SPE 183195 Development of Crosswell Electromagnetic Monitoring System Using the HTS-SQUID Magnetometer by Makoto Harada, Japan Oil, Gas, and Metals National Corporation, et al.

Impedance Analysis of Constant-Phase-Element Behavior of Heavy-Duty Coating for Evaluating Its Aging Degradation

Being a resource-poor country, Japan needs oil storage steel tanks to store oil imported from overseas. In general, an electrolyte solution accumulates in bottoms of tanks because the oil contains water, chloride ions, sulfate ions and oxygen. Therefore, corrosion occuring in the inner surfaces of the bottom plates is a serious problem. Presently, the inner surfaces are usually coated with a heavy-duty coating to inhibit the corrosion. Since the heavy-duty coating has exceptional durability, it is often difficult to monitor the aging degradation by a laboratory immersion test, and the long-term degradation behavior is unclear. In a present work, the impedance characteristics of the heavy-duty coating used for a long period is analyzed to develop an evaluation method for the degradation of the heavy-duty coating applied to large steel structures by focusing on the recent studies in terms of the CPE. Acknowledgement: This research was performed with financial support from Japan Oil, Gas and Metals National Corporation.

Technology Focus: New-Frontier Reservoirs I (July 2017)

Technology Focus Congratulations! You are one of a select group to open your JPT and find this page! For your effort, you deserve something special, and I know what you want. In 5 minutes or less, you want to know how to immediately make a step change in your business and improve your own promotion prospects in the process. You want to know the key technologies you should be implementing now. To develop your longer-term strategy, you want an awareness of future trends now. You don’t want just anyone to tell you these answers; you want it to come from the very best people in the industry. Consider your wish granted. According to a poll of leaders with more than 220 years of collective experience (see JPT online for names), the top theme to have affected our industry in the past 2 years is Fracture-Stimulation Optimization—Given the high cost, fracture design has gained its fair share of scrutiny in the downturn. The results of statistical production analysis have varied by play. Fluid types and chemical additives have been removed or modified. Alternative proppants have been evaluated and, in some cases, trialed successfully outside their previously specified safe-performance ranges. Nothing is sacred. The top theme to affect our industry in the next 2 years is predicted to be Intelligent Operations—The industry is moving toward increasing the level of automation in all activities. All areas from exploration to shipping will be touched by these technologies. This includes drones for safer, demanned operations as well as robotics on drilling rigs. The other key area of automation is predictive analytics, which allows us to analyze multivariant problems like never before. Fracture-design optimization, drilling analytics to improve rate of penetration, and optimized operator vehicle routing for field-staff and plant optimization are just a few areas that will be transformed. Now, wasn’t it worth the effort to read this? Recommended additional reading at OnePetro: www.onepetro.org. SPE 182230 Issues and Challenges With Controlling Large Drawdown in the First Offshore Methane-Hydrate Production Test by S. Sakurai, Japan Oil, Gas, and Metals National Corporation, et al. SPE 180399 Petrophysical Evaluation of Natural-Gas Hydrates—North Slope, Alaska by Douglas Hupp, Schlumberger, et al. SPE 180818 Proppant Management: A New Challenge To Develop Unconventional Reservoirs in Argentina by J.C. Bonapace, Halliburton

The Iġnik Sikumi Field Experiment, Alaska North Slope: Design, Operations, and Implications for CO2–CH4 Exchange in Gas Hydrate Reservoirs

The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to (1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and (2) observe reservoir response upon subsequent flowback in order to assess the potential for CO2 exchange for CH4 in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO2 was likely, given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO2 and N2 offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO2, N2, and chemical tracers; (2...

Constant-Phase Element Characteristics Caused By Resistivity Distribution in High Performance Anti-Corrosion Organic Coating Applied to Oil Storage Tank

The internal bottom plates of oil storage tanks are exposed to a corrosive neutral electrolyte solution containing chloride ions and oxygen that are enough to cause severe corrosion. For this reason, the steel plates are generally coated with a heavy-duty coating aims to isolate the steel substrate from the corrosive electrolyte. Since the coating has exceptional durability, the visual defects of the coatings in many oil storage tanks are almost undetected in spite of a long period of use (i.e. over twenty years). On the other hands, it is supposed that the barrier properties of the coatings decrease due to the electrolyte solution uptake. For appropriately maintaining the coatings, an evaluation method for the visually non-defective coatings are required. Since impedance measurements [1][2] are suitable for the evaluation of visually non-defective coatings, they have attracted much attention as a method for the quantitative evaluation of the coatings applied to oil storage tanks. However, the clarification of the degradation process of the coating, which is needed for the electrical equivalent circuit analysis, has not been achieved. It is important to interpret the electrical property of the coating sufficiently for the sensitive evaluation of extracting time-constant components. According to Van Westing et al. [3], the impedance characteristics of a high performance anti-corrosion organic coating are interpreted by CPE (constant-phase element). Therefore, it is suggested that the CPE is a useful circuit element to evaluate the impedance of the coatings on the internal bottom plates of oil storage tanks. However, there is possibility that the analysis of an impedance spectrum by using the CPE causes the ambiguity of the physical interpretation in an experimental object. Thus, it is necessary to evaluate the anti-corrosion performance of the coating considering the cause of the CPE behavior in the impedance spectrum. In this study, the anti-corrosion performance of the coating applied to an actual oil storage tank is evaluated by using impedance measurements. The CPE behavior of the coating is explained based on the distribution of the coating resistivity along the thickness. The field impedance data was obtained by the two-electrode impedance measurement setup, as shown in Figure 1. The impedance spectra were obtained over a frequency range from 200 Hz to 10,000 Hz with a 1 Vp-psinusoidal potential. Figure 2 shows the representative impedance spectrum in the obtained data. The fitted curve analyzed with the electrical equivalent circuit consisting of a parallel combination of the CPE and the resistance R pcorresponding to conductive pathways [1] are noted in the figure as dotted lines. The fitted curve was in good agreement with the field data, as can be seen Figure 2. Thus, the impedance spectrum can be interpreted by using the CPE. In subsequent discussions, this CPE behavior is explained by the distribution of the coating resistivity according to a power-law along the thickness, which results from an electrolyte solution permeation in the coating [4][5]. The obtained results in this study will contribute the establishment of an evaluation method for heavy-duty coatings. Acknowledgement: This research was performed with financial support from Japan Oil, Gas and Metals National Corporation.

Degradation of Anticorrosive Organic Coating Applied to Inner Bottom Plate of Oil Storage Tank By a Large Scale Earthquake

Introduction An anticorrosive organic coating have been widely applied to a large steel structure because the organic coating isolates the steel material from a corrosive environments. However, environmental factors such as water, UV, and temperature influence the deterioration of the coating, which leads to under-film corrosion or blistering. An oil spillage from storage tank is one of concern caused by severe corrosion of the steel plate under the organic coating. Therefore, Japanese regulation requires an inspection at least 8-years intervals. However, the appropriate interval in the case that the storage tank suffer a large scale earthquake have not been evaluated and studied. Therefore, it has been important for us to take a precaution against the large-scale earthquake and measures plan after damage. As soon as the coating is cracked by a large deformation, a steel plate is exposed to the corrosion environment, and the corrosion reaction proceeds immediately. If a large scale earthquake causes the coating degradation, this lifetime could be shortened. For this residual lifetime evaluation, the researches based on both mechanical and chemical approaches would be required. EIS is a quantitative and non-destructive method to accurately monitor the degradation of the coating and the corrosion process. In this study, a coated steel plate painted with the organic coating was used to simulate the damage of the tank bottom coating by a large scale earthquake. Mechanical and electrochemical tests were simultaneously performed to identify a correlation between crack patterns and corrosion behaviors. Experiment The experimental setup and a test piece are shown in Figure 1. Commercially available vinyl ester resin glass flake coatings with different composition were applied onto a mild steel plate (No.1～No.3). Acrylic tubes were fixed to the surface of all test pieces. Electrochemical measurements were performed in 3 wt.% NaCl solution using three electrode system containing saturate Ag/AgCl reference and platinum counter electrodes at room temperature (293 K±5). A stress generated by three point bending test was applied to a test piece in order to deform coating layer and induce a flaw or crack. At the same time, the deformation behaviors of the surface of coating and crack formation was monitored with high speed and precision camera(30 flame/s). The crosshead strain increased at average speed of 0.1 %/sec. After the crack penetrated the coating, the electrode potential immediately indicated corrosion potential of steel. The value of strain which corresponded to this penetration was defined as “threshold strain for corrosion: TSC in this paper. For comparison, the test piece without immersion test was also performed. When the crack was confirmed on the surface by the camera, this value of strain was defined as “threshold strain: TS”. After the corrosion potential reached to a steady state, EIS was measured. The frequency was swept from 10 kHz to 10 mHz with a 10 mV-rms perturbation amplitude. The Data analysis was performed by using the typical software (ZView) and curve fitting by various equivalent circuit models (Figure 2) were tried. Result & Discussion The values of TSC are shown in Table 1. The corrosion potentials were observed in all test pieces. However, the crack cannot be detected by camera in some test pieces. This suggests that micro cracks which will cause a decrease of anticorrosion performance are induced. In our experimental conditions, after the strain reached to TS value, two patterns of cracking behaviors were confirmed. In the pattern (type A), some cracks were generated and they gradually expanded in almost same direction. In another pattern of (type B), one crack was generated and then it rapidly and linearly expanded. As shown in table 1, impedance model of type B, A and No.3 without crack corresponded to fitting model Ⅲ, Ⅱ andⅠ, respectively. The Bode plots ware shown in Figure 3. EIS showed that the impedance of No.3 test piece was kept at high level. No.3 test piece did not have crack on the surface apparently and indicates higher impedance. It had barrier property. The impedance of No1 test piece(Type B) was higher than that of No.2 test piece(Type A). This suggested that a corrosion speed of No.1 test piece would be fast. Therefore, we have to estimate the degradation of coating and its influence on the corrosion behavior quantitatively. Acknowledgement This research was performed with financial support from Japan Oil, Gas and Metals National Corporation. Figure 1

コバルトリッチクラストからの金属回収技術の現状と課題

The cobalt rich manganese crusts are distributed on the flat top or the slope of seamounts in the economic zone and the open sea around Minami Torishima Island. Cobalt rich manganese crust and manganese nodule are iron manganese oxide mainly composed of oxide of Mn and Fe. However, their distribution condition and composition are different. Manganese nodule contains some 2.0% of copper and nickel together. On the other hand, the cobalt rich manganese crust includes less copper and nickel than manganese nodule does, but contains a higher level of cobalt and platinum. Metal Mining Agency of Japan (MMAJ), which is current Japan Oil, Gas and Metals National Corporation (JOGMEC), has selected“ Smelting and Chlorine Leaching” as the most suitable technique from the viewpoint of nickel, cobalt and copper's recovery from the manganese nodule. (Kojima, in 1996) For the treatment of cobalt rich crust, JOGMEC has established an improved metal recovery technology, which is called the“ Improved Smelting and Chlorine Leaching”, after the investigation from 2003 through 2008. . In the“ Improved Smelting and Chlorine Leaching”, JOGMEC has introduced“ slag cleaning” process for cobalt and another process for platinum in order to enhance the recovery level. Also JOGMEC found technique to recover metal using bioleaching effectively.

System Monitors Sandface for Deepwater Offshore Gas-Hydrate Production

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 25328, ’A Deepwater Sandface-Monitoring System for Offshore Gas- Hydrate Production,’ by S. Chee, SPE, T. Leokprasirtkul, T. Kanno, O. Osawa, Y. Sudo, M. Takekoshi, and H. Yu, SPE, Schlumberger, and K. Yamamoto, Japan Oil, Gas, and Metals National Corporation, prepared for the 2014 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. The world’s first offshore gas-hydrate production was carried out successfully in deepwater Japan at Nankai trough in 2013. In this project, one production well and two sandface monitoring wells were drilled and installed with a combination of distributed-temperature-sensing (DTS) and array-type resistance-temperature- detector (RTD) sensors. The objective of the sandface-monitoring system was to capture the hydrate-dissociation front dynamically changing during the production test and to monitor long-term reservoir stability with the selected temperature sensors. Introduction Interest is growing worldwide in methane hydrate as a unique and challenging natural-gas resource. In order to produce and use these resources, it is necessary to establish the production technology and understand how methane-hydrate dissociation behaves. Japan has studied methane-hydrate exploration during the past decades and planned to conduct the world’s first offshore methane-hydrate production test in 2013. In such a production test, the dissociation progress and the stability of the methane-hydrate reservoir can be captured by long-term continuous temperature monitoring, which is conducted in real time and autonomously before, during, and after the production test. One of the more challenging requirements is that the deepwater sandface-monitoring system must be self-operated by subsea battery without cable connection from the surface for a long-term monitoring period of 18 months. Thus, the reliability and redundancy of the monitoring system were key design challenges above data measurement quality and offshore deployment tasks. Outline of the Sandface-Monitoring Wells One production well and two monitoring wells were drilled. The methane-hydrate reservoir in the Nankai-trough area has methane-hydrate-bearing sand-rich intervals in turbidite fan deposits. For the production test, approximately 50 m of methane-hydrate zone was selected that is located in shallow unconsolidated reservoir approximately 300 m below the seafloor in a water depth of 1000 m. Deepwater sandface-monitoring systems were deployed in the two monitoring wells in the first quarter of 2012, approximately a year before the methane-hydrate production test started in the first quarter of 2013. The production test continued for a week, and then the recovery of the sandface-monitoring systems was performed in the third quarter of 2013. Therefore, the in-situ temperature monitoring started 1 year before the production of methane hydrate and continued for approximately half a year after the production test in order to monitor the long-term stability of the methane-hydrate- reservoir behavior. After the monitoring system was recovered from the seafloor, temperature data were retrieved from data storage for analysis.

超臨界水を用いた超重質油改質 (SCWC) 技術

Alberta Energy Regulator (AER) announced that Alberta's annual raw crude bitumen production will rise to 4,100,000 barrels per day by 2023 twice as much as 2,100,000 barrels per day of the present. It is an infallible situation to continue to put a lot of energy into production of bitumen as an Alberta state government.However, the production of bitumen is not easy because of its viscosity. A lot of steam is needed for production and diluents (such as condensate and naphtha) about 30 % of bitumen are needed for transportation. So the supply cost of bitumen is higher than that of crude oil.Moreover, much of diluent is import from U.S. and also a large number of the “Dilbit” (bitumen with diluent) are exported to U.S. As a result, increasing of production is dependent on U.S., so it is problem from a viewpoint of energy security in Canada.Partial upgrading technology is one of solution to the needs. Partial upgrading technology converts bitumen into synthetic crude oil which can be transported on pipeline. But synthetic crude oil is different from product of refinery such as gasoline.In the presentation, the Supercritical Water Cracking (SCWC) technology (one of the Partial upgrading technology) will be described for the one of solution for the needs. This technology is developed by Japan Oil, Gas and Metals National Corporation (JOGMEC) and JGC. It is focused on its merit and the present status of technology development.

Formation Evaluation-While-Drilling Technology Improves Data Delivery

Young Technology Showcase Today’s drilling engineering teams are continually looking for better ways to mitigate risk and improve health, safety, and environmental conditions at the rig site. Many operators would prefer to acquire a comprehensive suite of petrophysical measurements while drilling—without incurring the risk and cost associated with deployment of chemical nuclear sources. Traditionally, both wireline and logging-while-drilling (LWD) tools have depended primarily on radioisotopes such as americium-beryllium to generate high-energy neutrons for porosity measurements, and cesium to generate gamma rays for bulk density measurements. However, transportation, storage, handling on the rig floor, and potential abandonment of radioactive sources at the wellsite should the tools become stuck require special safety precautions and costly, time-consuming procedures. In remote geographic regions, mobilizing chemical sources can be slow and logistically complex. If a bottomhole assembly (BHA) with a chemical source becomes stuck, complicated fishing procedures can waste precious rig time, and delay eventual production of oil and gas. To meet the growing industry need for an alternative to radioactive chemical sources, Schlumberger recently released NeoScope sourceless formation evaluation-while-drilling solution (Fig. 1). This technology is unique in three ways. It is the first LWD tool to introduce a completely new nuclear measurement to the industry—sourceless neutron gamma density (SNGD). It is the only tool in the industry that provides formation density and neutron measurements without the need for chemical nuclear sources. Finally, it is the first tool to provide collocated density and neutron measurements (Fig. 2). Development and Field Testing LWD tools have typically used two chemical nuclear sources to obtain neutron porosity and bulk density. In partnership with Japan Oil, Gas, and Metals National Corporation, Schlumberger first developed and deployed a pulsed neutron generator (PNG) for commercial standard neutron porosity, spectroscopy, and sigma measurements 7 years ago, eliminating the need for one of the chemical sources (241AmBe). However, development of SNGD was not yet mature enough for commercial use. The only way to acquire a reliable density measurement was still to use a cesium source. Hence, it remained impossible for operators to obtain a comprehensive sourceless suite of petrophysical data while drilling. Ongoing research and engineering led to modifications of existing technology, design of new detectors, and development of sophisticated characterization algorithms and calibrations to provide the first commercial SNGD measurement—a true breakthrough. Since 2005, extensive laboratory modeling and experimentation, as well as more than 200 field tests in more than 30 countries have been conducted to verify and refine the new SNGD measurement. Tests have been carried out in a wide range of formations under many different environmental conditions. Comparisons of the new PNG-based density measurement with conventional bulk densities derived from chemical sources showed good correlations both in carbonates and sandstone formations, onshore and offshore (Fig. 3). Field testing extended through early 2012, and the commercial solution was officially released in June.

Production Method for Methane Hydrate Sees Scientific Success

The testing flare burns brightly during a methane hydrate production test of the Ignik Sikumi No. 1 well on the Alaskan North Slope. A production method that could unlock large reserves of methane hydrate in sand-dominated reservoirs was tested successfully from a scientific and operational standpoint in a recent research experiment on the Alaskan North Slope (ANS). The experiment was conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in partnership with ConocoPhillips and Japan Oil, Gas, and Metals National Corporation. A proof-of-concept test was conducted between 15 February and 10 April at the Ignik Sikumi No. 1 well in the Prudhoe Bay field operated by ConocoPhillips. The production technique featured the injection of carbon dioxide (CO2) to exchange and release methane (CH4) from the hydrate, a method developed through laboratory collaboration between the University of Bergen in Norway and ConocoPhillips. The released gas was then produced by means of reservoir depressurization. “The test objective was to perform injection and flow-back from a single well to validate that the CO2/CH4 exchange mechanism demonstrated in laboratory tests will occur in a reservoir of natural methane hydrates,” said Ray Boswell, technology manager for gas hydrates at the NETL. It was the first field-level trial of a production method involving the exchange of CO2 with the methane molecules contained in a methane hydrate structure. “The focus of the test, including the design of the well, was on the technical feasibility of this new technology, rather than an attempt to produce gas at commercial rates,” Boswell said. CO2 Mixture Injected in Reservoir The Ignik Sikumi well test was equipped with downhole fiber-optic distributed temperature and acoustic sensing, three downhole pressure gauges, and full surface instrumentation, including high-resolution in-line gas chromatography. Over a 13-day period, a carbon dioxide/nitrogen mixture was successfully injected into the 30-ft-thick reservoir interval, saturated with methane hydrate, without loss of injectivity. This was followed by a production stage in which the pressure was held above the stability pressure of the in-situ methane hydrate. CH4 was produced during this stage, and initial data analyses indicated that CO2 exchange was achieved. Ongoing analyses of the extensive datasets acquired at the field site are under way to determine the overall efficiency of simultaneous CO2 storage/CH4 production from the reservoir. As part of the demonstration, the depressurization phase of the test extended for 30 days. The longest previous field test of depressurization to extract gas from hydrate lasted 6 days as part of a Japanese-Canadian testing program at the Mallik well in Canada’s Northwest Territories during 2007 to 2008.

Production of methane from hydrate deposits beneath the Nankai Trough

The U.S. Geological Survey (USGS) has estimated there is upwards of 100,000 trillion cubic feet (Tcf) of global methanehydrate resources, worldwide (Collett, 2011). The Japan Oil Gas and Metals National Corporation (JOGMEC) has been actively evaluating the potential of developing methane hydrate marine sediments as a resource. There have been trials in onshore Canada in 2007 and 2008; and, there are plans to test offshore production in the next few years. Existing plans involve two well tests in the eastern Nankai Trough, offshore Japan. An initial short-term well test of up to one month will be followed by an extended well test of up to six months. The production method trialled in Canada and planned for the offshore well tests is depressurisation. This involves drilling from the surface (or seabed) to a subsurface methane hydrate zone and reducing the formation pressure to a point where the methane hydrates dissociate to methane and water. The gas and water are then transferred to the surface, the water is treated for disposal and the gas is treated for exportation. Recent research was done to confirm the technical feasibility of the planned offshore well tests. This research examined: production mechanism and flow assurance; production host functional specification; subsea equipment including flowlines, production riser and electro-hydraulic umbilical; topsides well test equipment; and, procurement and installation methodology. The main conclusion made was confirmation of the technical feasibility of the proposed offshore well test. The key challenges, uncertainties and areas for future focus in the lead up to the proposed offshore well tests were also highlighted.

Research on the next generation dynamic positioning system of offshore platform in Japan

Abstract This paper describes dynamic positioning system developed for 20 years through research and development by Japan Oil, Gas and Metals National Corporation. It summaries a basic concept of design, simulator, tank test, and real applications. Also, the next generation system of Japan and its basic research is mentioned in the paper.

Drilling a Hole in Granite Submerged in Water By Use of CO2 Laser

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119914, ’Drilling a 2-inch in Diameter Hole in Granites Submerged in Water by CO2 Lasers,’ by Toshio Kobayashi, SPE, and Masahiro Nakamura, Japan Drilling Company, and Satoshi Kubo and Makoto Ichikawa, SPE, Japan Oil, Gas, and Metals National Corporation, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. As part of a fundamental study of rock drilling by laser irradiation, the full-length paper describes laser drilling of a 5.08-cm-diameter hole in granites submerged in water. The laser beams melted the granite surface locally to form small glassy beads. Repetition of this procedure demonstrated that a high-power laser beam propagating in water can be used to generate a hole in rocks. Experimental A 10.6-µm carbon dioxide (CO2) laser was used. The laser had a 5-kW peak-output power, a 5-ms pulse width, a 10-Hz repetition rate, a 250-J pulsed energy, and a 50% duty ratio. The CO2 laser has a ring mode. A laser-irradiation nozzle with a 20-in. focal length was used for irradiation in air and in water. For irradiation in water, a 300-mm3 acrylics chamber was used. A high-speed video camera was placed at the side of the chamber to photograph the dynamic behavior of the formation of bubbles induced by laser irradiation. A rock specimen was placed in the chamber so that the distance from the water surface to the top surface of the granite was 50 mm. The CO2 laser was intermittently irradiated perpendicularly from a muddy-water surface. The irradiated laser beam was absorbed in the water and formed cone-shaped bubbles that had an irregular interface. Because the induced bubbles kept their shape until a subsequent laser beam reached the rock, the laser beam could drill the rock effectively. Rock Specimens Inada granite was selected as a rock specimen because the Inada granite is representative of quartz-group minerals and quartz-bearing rocks in Japan. Its K-Ar chronology is 60 Ma. Inada granite often is used as construction materials and experimental materials. The Inada granite contains 33.7% quartz, 32.1% potash feldspar, 30.3% plagioclase, and 3.8% biotite. Physical characteristics of Inada granite are as follows: 180-MPa uniaxial compressive strength, 0.75-MPa split-ting tensile strength, 65-GPa Young’s modulus, 2.63 g/cm3, 0.75% porosity, 0.0167- to 0.0377-J/(g-K) specific heat, and 54.4- to 83.7-W/(m.K) thermal conductivity. Results and Discussion In earlier experiments with Inada granite irradiated in air with a CO2 laser, transparent glassy objects crystallized on the walls of the created hole. It was observed that the fused Inada granite could not fully flow out of the hole, solidifying on the bottom to close the bottom of the hole. As a result, a complete hole cannot be created by the laser irradiation in air.

NGH Chain: Gas-Transportation Concept

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12807, "NGH Chain: A New Gas Transportation Concept," by T. Kawasaki, K. Bando, and Y. Suehiro, SPE, Japan Oil, Gas, and Metals National Corporation, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 De cem ber. The paper has not been peer reviewed. In general, long-distance liquefied natural gas (LNG) transportation projects are economically feasible for very large natural-gas reserves volumes. Japan Oil, Gas, and Metals National Corporation and Japanese engineering companies have focused on natural-gas hydrate (NGH) as a gas-transportation concept. It is important to consider optimizing the process and to understand the effect on the chain and optimize the entire NGH chain. Background Many medium and small gas fields within 6000 km of Japan are difficult to develop by conventional techniques, such as LNG and pipelines. NGH may be an economical gas-transportation method. NGH contains 170 times the gas volume compared with liquid or gaseous states. Therefore, initial cost of the NGH process is estimated to be less than that for LNG. LNG transportation is economically feasible for long-distance transportation. Pipelines are suitable for relatively-short-distance transportation because of higher capital cost. NGH transportation is a solution for small-to-medium-scale or remote gas fields, as shown in Fig. 1. Feasibility studies shown in Fig. 2 indicate that NGH transportation has an economic advantage for suitably sized gas reserves and transportation distance. Several systems have been developed to form NGH, including the bubbling/stirring-type formation reactor, the water-spraying-type formation reactor, and a hydrate-formation system that uses microbubbles with a tubular reactor, which obtains a higher formation rate than the other systems. Further improvement is needed in the precision of the feasibility study along with advances in technology. Conceptual Design The purpose of this study was the life cycle carbon dioxide (LCCO2) analysis of natural-gas transportation to Japan as NGH. In the selected model, natural gas is converted to NGH at the production plant and delivered to Japan by an NGH-carrier ship from existing undeveloped natural-gas fields in coastal areas of Southeast Asia. The base case production rate was 1×106 tonnes/a of LNG equivalent with a transport distance of 6000 km. The study presumed that the gas would be used in a power plant. LCCO2 Analysis The scope of investigation includes processes between the production facilities (including inlet-gas treatment) and the regasification facilities.

非在来型石油天然ガス開発技術

While conventional oil and gas production is expected to hit a peak in dozens of years, the world still requires hydrocarbons as the main source of energy. The need to fill the gap between supply and demand, and the recent high oil price, have aroused enthusiasm for unconventional oil and gas. But, the development of them is, full of ups and downs.The extra heavy oil boom began in early 2000's, when large projects started in Canada and Venezuela. But, rising plant cost, shortage of skilled workers, and environmental concerns have increased uncertainty of those projects, and finally this year global economic crunch and oil price plunge ended the boom. In those circumstances, technologies to reduce production cost are keenly craved and several are on trial in actual projects.In 2005, U.S. Congress directed the Bureau of Land Management to manage oil shale development on public lands. By 2008, the bureau issued six research development and demonstration leases that will allow oil shale development to resume on a 160-acre tract of public land. Currently, in-situ conversion process is arguably the most cost effective recovery method.The U.S. has led the world in coalbed methane (CBM) development, and the production reached 1.8 tcf by 2006. While some countries are after the footsteps of the U.S. in CBM development, the U.S. is now considering giving a higher priority to shale gas instead as the results of efforts to develop economical production methods for years.Japan has studied gas hydrate development since 1990's. In 2008, the Japan Oil, Gas and Metals National Corporation carried out a successful gas hydrate production test in Canada. The next step of their pursuit will include practical application of the production method, nationwide potential evaluation, and development of environmental assessment technique.