Floating LNG (FLNG) is the one of the development concepts to commercialize offshore stranded gas fields, offshore gas fields in a remote area and the associated gas of oil fields. FLNG is a barge shaped floating structure with the process, utility, storage and offloading units on it, which is single point moored with turret system. The main function of the FLNG is to produce and deliver LNG to consumers via LNG Carriers. Therefore, FLNG is generally considered as the combination of the existing technologies, which are onshore LNG plant, LNG Carrier and Floating Production Storage and Offloading (FPSO). FLNG consists of two parts, those are topside and hull. Topside is the upper part of hull, which generally consists of process plant, utility plant, offloading facilities and living quarter. Process plant generally consists of inlet separation, condensate stabilization, pre-treatment, liquefaction, fractionation and associated units. Hull is the barge part of the FLNG, which contains storage systems for the products, i.e. LNG, LPG and condensate, and other marine related equipment and machineries. There are several projects that FLNG may be applied for their gas field developments. However no project has been completed yet so far. Though FLNG is the combination of the existing technologies, it is known that there are several technical challenges, which has to be solved to realize and design FLNG concept. This paper introduce these technical challenges as below taking the Abadi LNG Project which INPEX Masela Ltd., is developing in Arafura Sea in Indonesia with FLNG solution: · Liquefaction Process on FLNG; · Layout for FLNG; · Marinization of equipment on FLNG; · LNG storage in FLNG; and · LNG offloading from FLNG to LNG Carrier.
Hydraulic fracturing has been conducted in Vietnam since 1994. It was applied to existing wells to improve production performance of declined wells. Then a hydraulic fracturing for appraisal wells is recently becoming more common to evaluate a tight sand reservoir. However, a hydraulic fracturing has many difficulties and constraints in terms of design and operation in Vietnam because it is conducted in offshore and its market is still small compared with other region. Especially, frac boat and equipment are limited to mobilize to Vietnam. This paper introduces a typical hydraulic fracturing design and operation in offshore Vietnam. And the challenges of offshore hydraulic fracturing in Vietnam are shown based on some case studies. Finally requirements and perspectives for future development are discussed.
From a viewpoint of stable supply of gas resources, importance of natural gas underground storage has been widely recognized. Teikoku Oil (INPEX) established, for the first time in Japan in 1969, the underground gas storage (UGS) in Sekihara gas field, which was a depleted gas reservoir located a few kilometers north to Minami-Nagaoka. Since then, it has played a great role for peak shaving and/or emergency stockpile in Minami-Nagaoka gas production operation. At present, approximately 80 MMm3 of working gas is stored with the maximum deliverability of 2.4 MMm3/day. For the purposes of increasing both the working gas capacity and withdrawal rate, delta-pressuring, operation at a maximum pressure greater than the discovery pressure associated with that reservoir, is expected for Sekihara UGS. Unfortunately, there are no experience and no regulations for “delta-pressuring” in Japan. The special measurements and the monitoring systems installed in Sekihara UGS for the safe operation of delta-pressuring are introduced in this paper.
In phase 1 of the Japan's Methane Hydrate Exploitation Program, the method to decrease the hydro static pressure by use of a submersible pump (the depressurization method) was recognized to be essential for the production technique. In phase 2, the basic design for the down hole production test system for offshore production tests was implemented by combining the technologies for DST (drill stem test) that are usually used in conventional oil and gas offshore production test operations. In respect of the surface production test system, the basic plan related to the necessary production facilities was designed and the specification of the floating drilling vessel suitable for the necessary facilities was also investigated. Regarding the produced water treatment system, framing of the conceptual design, organizing the regulations related to discharge, and examination of the environmental assessment have been investigated.
In our laboratory, fundamental tests on underground coal gasification (UCG) by using coal blocks were conducted for several years. Last year, a small scale field test on UCG was carried out at a part of developing area of Mikasa surface mine in Hokkaido. At the field, two bore holes were drilled, one is incline bore hole and the other is vertical bore hole. The lengths of incline bore hole and vertical bore hole were about 5m and 1.4m, respectively. The vertical bore hole was used for an oxygen injection hole and ignition hole. The incline bore hole was used for a gas production hole. Some temperature sensors were installed around the incline bore hole to measure the temperature of around the production bore hole. AE sensors were also installed around the incline bore hole to estimate the gasification zone in the coal seam. Underground Coal Gasification (UCG) demands precise evaluation of the combustion area in the coal seam. Especially, the monitoring of fracture activity in the coal seam and around rock is important not only for efficient gas production but also for estimation of subsidence and gas leakage to the surface. The test was carried out for forty hours and production gases were analyzed at every thirty minutes. Experimental results obtained showed that the combustion propagated along the linking hole inside coal seam. The temperature gradients inside the coal and the composition of production gas were changed under constant oxygen flow rate. But Average thermal value of generated gases by field test was about as much as generated gases by laboratory test.
Coalbed methane (CBM) and shale gas reservoirs are confirmed and a reservoir of natural gas dissolved in water of Mobara type has a possibility to include adsorbed gas. A combination of Langmuir isotherm and a dual porosity model successes for numerical reservoir simulation of CBM. However, the combination cannot work well for other natural gas reservoirs including adsorbed gas. This means that correct and simple gas retention and flow models have not been developed for reservoirs of shale gas and natural gas dissolved in water of Mobara type. This study shows common and different terms of petrophysical properties of reservoirs with adsorbed gas to understand characteristics of the reservoirs. In addition, this study shows results of numerical simulations to estimate efficient geometries of horizontal wells and efficiency of mix injection of N2 and CO2 for enhanced coalbed methane recovery (ECBM) analysis using a reservoir simulator for CBM. Because other natural gas reservoirs including adsorbed gas have not established yet to make a proper numerical model, we cannot apply numerical simulations to reservoir conditions with large influence of desorption and flow of adsorbed gas. Also, we show that the amounts of adsorption of mudstones are relatively large. We need discuss the potential of mudstone as gas reservoirs but cap rocks.
Gas and oil production from extremely tight rock, including shale formation, has been significantly boosted for the last decade. It is a well-known fact that the amount of gas resource exceeds multi quadrillion cubic feet in such formation. However, hydrocarbons would never flow to surface without artificial flow path created by hydraulic fracturing, and ‘fit for purpose’ techniques are prerequisite to economically extract hydrocarbons from individual formation, each of which have different properties. In addition, continuous effort to optimize development design is important to secure enough margins, and multi-disciplinary approach is taken to accomplish optimum design. This paper summarizes the typical workflow and the ways to optimize designs in shale gas development.
Mineralogical and chemical compositions of carbonate nodules associated with methane hydrates, which were collected from the Sea of Japan by MD179 research cruise during the June 2010, were investigated to clarify the mechanism of the formation of the nodules. The predominant minerals of the nodules were aragonite and calcite with subordinate amounts (10-30%) of quartz, feldspars, pyrite and clay minerals such as illite. The calcites are high-Mg calcite with an average of about 4% (maximum 8%) MgO. The average sodium content (2,500m/g) of aragonites in the nodules is about half as compared with that of aragonites which are formed under ordinary shallow marine environments, indicating the different mechanism of aragonite formation in the carbonate nodules associated with methane hydrates.