The main theme of this lecture is the promotion of gas exploration activity. This lecture is approached from a non-technical point of view rather than a technical view, and in particular, takes the alternative perspective starting from downstream factors such as LNG/gas market.
Unfortunately, due to depressed oil and gas prices until a few years ago, the activities of the entire industry, including exploration, have been stagnant. However, the sustained period of very low oil-prices now seems to be over and has now stabilized at a moderate range of around 60 dollars per barrel. Yet, it doesnʼt seem that gas exploration activities are as energetic as before.
LNG has been forming into a global market in recent years, and this has started influencing local gas development activity, even in remote regions. In this lecture, we consider causes of low-level exploration activity in the downstream segment of the “Gas Value Chain” and give example measures to promote gas exploration activity. Although it may not be a happy conclusion for technical people in the exploration business, we leave the pride of geoscientists aside for a moment and consider the situation as a commercial manager would. Aspiring explorationists would do well to step outside of their technical discipline and proactively advance into the commercial area. Geoscientists who want to do exploration should place problem-solving at the front of mind, as the driving force to overcome challenges.
Successful global oil & natural gas exploration activities require an integrated assessment system that couples geoscience and economic evaluations and enables objective ranking of opportunities according to specific corporate goals. Geoscience evaluations include assessments of the geologic risk that can be performed on a basin, play or prospect scale with an emphasis in delineating target areas with the highest prospectivity for gas. They need to include both local domain knowledge and global analogue studies, and they must also enable deterministic （process based） and probabilistic analyses. Economic evaluations include corporate priorities such as economic returns, the timing of production contributions and strategic considerations. All of these must be applicable with a live database that can manage global, country, basin, play and prospect data and that can be customized to meet specific client requirements. Welldefined processes and strict standards are required to enable objective geological risking and ranking of portfolios to be performed, and to develop the foundation for economic assessments and strategic decision processes.
The Ichthys LNG Project is a large-scale LNG project operated by INPEX Corporation, the first Japanese operator of a world class LNG project. The project commenced production of gas from the wellhead in July 2018.
The gas and condensate production rates in the first quarter of 2019 were about 1,100 MMcf/day and 40,000 bbl/day, respectively. Production is expected to reach a plateau.
The Ichthys gas-condensate ?eld （Ichthys field） that supplies gas and condensate to the LNG project, is located in the Browse Basin, on the Northwest Shelf of Australia. Gas bearing sandstone reservoirs of the Ichthys field extend over about 600 km2. The upper reservoir of the Ichthys field is the Brewster Member, which consists of submarine channel and lobe complex sandstones. The lower reservoir is the Plover Formation, which consists of fluvial and deltaic sandstones.
These reservoirs have been main target for petroleum exploration in the Browse Basin.
To make effective use of the Ichthys project facilities, which were designed to produce LNG for 40 years, it is necessary to discover new gas fields surrounding the Ichthys field, to maintain a stable production plateau for the long term. Since exploration for large, conventional structural traps has reached a mature phase in the Browse Basin, it is necessary to focus on more challenging new exploration plays in the basin, such as stratigraphic plays and deep structural plays.
Many biogenic gas accumulations are distributed continuously in the offshore of East Java, from the Madura Strait to the south of the Kangean islands. New gas discoveries have continued until recent years, and are all of the same play type of limestone and sandstone reservoirs of the Pliocene Mundu/Paciran formation. Gas production in East Java was dominated by thermogenic gas until the early 2000ʼs. However, this has recently been replaced by biogenic gas in response to high gas prices caused by increasing demand and the accelerated development of small to mid-size gas fields brought about by synergies created by the presence of infrastructure such as the East Java Gas Pipeline.
As most of the biogenic gas fields discovered to date are at depths shallower than 1,000 meters sub-seabed, they are accompanied by DHIs （Direct Hydrocarbon Indicators） such as ?at spots, and are easily detected as anomalies in the seismic data, which is generally of good quality. Multiple ?at spots are clearly recognized at the reservoir horizon and overlying shallow layers in the seismic data. The flat spots correspond to shallow gas and paleo-GWC, and in cases where a gas field is discovered, shallow gas and multiple DHIs are identi?ed without exception.
In the development of these biogenic gas fields, an optimized production system was adopted, taking into consideration geological conditions such as the shallow reservoir depth, closure area and size and the distance between accumulations, and production systems such as subsea completion with FPU (Floating Production Unit), or cluster development with individual wellhead platforms were deployed. After the development of gas fields close to consumption areas and shallow in depth are completed, it is expected that exploration and development activities will shift to more remote and deeper areas.
Since 2014 JOGMEC has been collaborating with Natural Resources Canada （NRCan） along with industry partners in the area of unconventional reservoir characterization and technology development. Based on a June 12 2019 presentation at the JAPT Exploration Technology Symposium in Tokyo, this paper presents research from two major shale and tight unconventional reservoirs, the Upper Devonian Duvernay and Lower Triassic Montney formations in western Canada, and examines the differences between these two fundamentally different types of reservoirs. Solid bitumen strongly influences reservoir quality in both types of reservoirs but in very different ways. In tight reservoirs （i.e., Montney Formation） solid bitumen typically occludes pores and pore throats, while in shale reservoirs （i.e., Duvernay Formation） solid bitumen can be the primary host of porosity.
One of the many challenges of seismic acquisition associated with existing fields is existence of surface platforms. The block where the seismic operation was conducted is located in offshore Sarawak and there are 3 discovered gas fields and a number of near-field exploration targets. The legacy 3D seismic survey covering the block was conducted in 1992 with limited acquisition specifications, such as short cable length and low volume airguns, in comparison to the technology of today. Hence new 3D seismic acquisition with broadband processing was commissioned which included the undershooting operation across 2 production facilities to improve the seismic imaging of the deeper exploration targets and to optimize well engineering. Overall, the new 3D data were acquired with a successful undershooting operation followed by survey merging and matching in the processing stage. The new 3D data show better seismic re?ection continuity, a higher signal to noise （S/N） ratio, clearer images, and a more accurate velocity model in the deep section, allowing for a better interpretation of the deep exploration targets.
In recent years, Marine controlled source electromagnetic （CSEM） technology has played an effective role to reduce the exploration risk in marine area. Meanwhile, the application of Marine CSEM is not easy due to its expensive survey cost and difficulty of quality control for data acquisition and analysis. Therefore, authors constituted the research consortium and advances the Marine CSEM technological development based on the know-how cultivated at university and research institute. In this paper, we discuss current status and future technological development of the consortium.
The origin of natural gas is generally classified into microbial, thermogenic, or mixed according to the carbon isotopic composition of methane （δ13C1） and methane/（ethane＋propane） ratio （C1/（C2＋C3））. To identify compositional changes during migration and accumulation, we examine gases produced from dissolved microbial to free thermogenic origins from the Kanbara district in the Niigata backarc basin, central Japan. Most gases plot near the mixing line between microbial and thermogenic endmembers and several additional features are recognized. 1） Thermogenic gases from deep reservoirs maintain a constant C1/（C2＋C3） ratio of ~9 with increasing δ13C1. 2） No free mixed gas is observed upon incorporation of several percent thermogenic gas in the microbial endmember. 3） Dissolved and free gases in shallow reservoirs exhibit similar or higher δ13C1 and C1/（C2＋C3） values that are distinct from the mixing line. These observations demonstrate that “mixed gas” does not form by simple mixing but that different mechanisms individually control the isotopic and chemical composition. δ13C1 values of the thermogenic gas gradually decrease by an exchange reaction with dissolved biogenic methane in fossil seawater during migration. C1/（C2＋C3） ratios remain constant under deep high-temperature/pressure conditions because natural gas exists as supercritical fluid or dissolved in crude oil. However, C1/（C2＋C3） increases upon fractionation with dissolved gas in subsequently-separated condensate oil and/or re-equilibrium with dissolved gas in pore water under low-temperature/pressure conditions. Different migration paths generate different compositions. For example, migration in shallow carrier beds leads to lower δ13C1 and more methane-rich compositions far from the mixing line. Ongoing accumulation causes a differentiated composition at the migration front to reverse towards the direction of the original thermogenic gas. The composition of dissolved gas in the edge waters is affected by accumulated free gas. In general, only thermogenic gas contributes to “mixed gas” reserves, which do not increase by adding and mixing with microbial gas inferred from decreasing δ13C1, whereas the existence of biogenic methane in carrier beds prevents free gas loss during migration. This indicates that the origin of methane molecules is a mixture of biogenic and thermogenic sources, whereas free gas originated in deep thermogenic. It is not easy to distinguish that the origin of free dry gas with low δ13C1 at very shallow depths is either microbial gas released from edge water or migrated thermogenic gas. Methane hydrates with low δ13C1 beneath the seafloor of the forearc basin may originate from thermogenic gas generated in the accretionary prism.