Oil production from two adjacent offshore fields, KK field and AN field, started in 2006 in conjunction with sour gas injection, followed by the oil production from AS field started in 2011. These marginal sour oil fields, offshore Qatar near the border of UAE, in the Arabian Gulf have been developed incorporated with the challenges to realize the oil production with the minimum cost facilities and designs that would require low operating and maintenance costs for the production, control and monitoring of these offshore fields. Especially the implementation of sour gas injection in minimal offshore platform was most essential achievement. The challenges for the minimum cost facilities and designs to achieve the development of these high sour oil fields will be discussed in this paper.

Abu Dhabi Oil Co., Ltd. (Japan), ADOC, is currently operating three oil fields offshore Abu Dhabi; Mubarraz Field, Umm Al-Anbar (AR) Field and Neewat Al-Ghalan (GA) Field. In 2013, ADOC drilled, completed, tested and abandoned a well to appraise multiple sour reservoirs in a structure nearby to the existing three fields. The appraisal well was located in an environmentally sensitive area, so special measures were put in place to ensure the protection of the area during well testing operations. These measures included the re-injection of the produced hydrocarbon fluid and utilization of special burner booms to perform fallout-free combustion of liquid hydrocarbon. A tool designed by ADOC called the “Surface Testing Tool” was also utilized for safe operations of high H₂S fluids and to save rig time. This paper will summarize the various challenges, measures taken and lessons learnt during the well test in complex conditions and under stringent HSE regulations.

JX Nippon Oil & Gas Exploration Corporation (JX) participates as a non-operator in K2, a producing oil field in the deep water area of Gulf of Mexico (GOM). K2 oil field located 180 miles South of New Orleans, and water depth is 4,000 ft at the field location. It was discovered in 1999 and has been producing since 2005. JX joined the project in early 2007 through subsidiary company that is established in USA. K2 oil field is producing oil by natural depletion, and lower oil recovery factor is expected due to weak pressure support.

To improve oil recovery factor, many IOR/EOR options have been considered since oil production was started. Candidate options are infill well, water injection, CO₂ or N₂ injection, gas lift, booster pump, etc. Infill well drilling was started in year 2014. In parallel, a project team was established to study technical and economical feasibility of IOR/EOR options. Study by the project team is not finalized yet, however, all partners intend to apply water injection and riser base gas lift by using existing host platform.

Large amount of drilling and maintenance cost are needed to produce oil from deep water fields. The oil spill at the Macondo prospect also affected our project and resulted in higher development cost and longer schedule because of “Moratorium Period” and new strict safety assessments for drilling works. Sometimes, they need longer time to make alignment for each development work among partners under current economic circumstances.

JX would continue to participate in K2 project, even if some difficulties are there. Because, the deep water GOM has high quality potential reservoirs, a matured infrastructure for oil & gas sales, stable political and economic circumstances, and the opportunity to participate in the latest deep water technology.

One of the flow assurance challenges for offshore oil and gas production systems is the formation of hydrate. The optimal design and operation need to be fully understood, as hydrate formation causes cost and time for the remediation while suppressing oil and gas production. Various hydrate management systems have been ever applied to offshore fields and they are categorized into three different solution types such as thermal management, chemical injection and operation. The purpose of this paper is to introduce a case study of hydrate management system for an offshore oil field development. The case study investigated low pressure operation strategy for the field in Australia with a floating production, storage and offloading facility (FPSO). Dynamic simulation model was developed using a dynamic flow simulator, OLGA to confirm feasibility of the operation.

In the department of resources and environmental engineering of Waseda University, we are performing several classes and research work dealing with oil/gas exploration and development. Although it is difficult to conduct research work targeting the offshore oil/gas development in the university because of its giant scale, we are striving to give lectures on the fundamentals of the technologies applied to offshore oil/gas development taking environmental protection into consideration. This paper introduces the classes and research work for offshore oil/gas development and environmental issues conducted mainly in Waseda University.

About 20 classes deal with the topics related to oil/gas development in the undergraduate and graduate courses. Lectures on offshore oil/gas development are given in three of these classes including one in the international course, where the history of offshore development, offshore production systems including offshore platforms, case studies and environmental protection are explained. On the other hand, about 30 classes are provided for studying environmental issues. In one of these classes, environmentally friendly oil/gas development is introduced from the viewpoints of environmental impact aspects, environmental protection measures and HSE requirements in each project stage.

As for the research related to the environmental protection using petroleum engineering technologies, two programs are now being developed. One is a prototype numerical simulator predicting the bio-remediation of oil contamination in underground water. In this simulator, various reactions induced by microbes such as oil consumption associated with growth/decay of microbes, adsorption of microbes on rock surface and ionization are predicted. The other program is aiming at the optimization of the well locations and CO₂ injection rate so that the economics can be maximized in a CCS-EOR project, taking account of oil increment by CO₂ injection and CO₂ tax credit by storing CO₂ in a reservoir.

We are considering the possibility of application of an anaerobic bacterium which degrades long-chain hydrocarbons preferentially and induces oil viscosity reduction to Microbial Enhanced Oil Recovery (MEOR) in an oilfield in North Sea Oil. In this study, we estimated lower grade nitrogen sources which were effective for stimulating the growth of the bacterium and its ability to lower the oil viscosity.

The bacterium was incubated in the culture medium consisting of synthetic sea water, crude oil and lower grade nitrogen sources such as ammonium nitrate, urea, flower fertilizer, and agricultural fertilizer. The flower fertilizer contained 3 % of nitrogen and 16 kinds of amino acids according to the manufacturer. The agricultural fertilizer was made from beer yeast cell wall and contained 3.5 % of nitrogen according to the manufacturer. Retail prices of ammonium nitrate, urea, the flower fertilizer and the agricultural fertilizer are approximately 38 USD/kg, 25 USD/kg, 25 USD/kg and 1 USD/kg respectively while that of yeast extract which is usually used for incubating microorganisms as a rich nitrogen source is about 350 USD/kg.

Growth of the bacterium was clearly found in the culture solution containing the agricultural fertilizer at the concentration ≥ 0.5 g/L. Cell number of the bacterium increased more than 10 times as large as the initial cell number in the culture solution containing the fertilizer at the concentration of 2.0 g/L. This result suggests that the fertilizer can be utilizable as a growth promoter of the bacterium. Although the reduction of oil viscosity was found in all the culture solution containing the agricultural fertilizer, the reduction of oil viscosity in those culture solution was not so much. It can be assumed that the bacterium degrades not only heavier components but also lighter components of the crude oil in the culture medium containing the agricultural fertilizer.

The offshore facilities are in the remote area and the plant area is limited, therefore it is difficult to ensure the safety distance between the processing area and the living quarter area which results in the higher risk in the living quarter due to fire and explosion in the processing area. It is also difficult to ensure the safety distance between the equipment in the processing area which results in more the congested area and the confined area leading to the fire and explosion escalation. In addition, there is frequent ship / helicopter access for the production loading / the operators transfer therefore there is higher risk of the ship collision / the helicopter crash on the offshore facilities.

The risk analyses, such as the fire and explosion risk analysis, the ship collision analysis, the dropped object analysis, the escape, evacuation and rescue analysis, are carried out for the safety in design of the offshore facilities.

The risk analyses need to be completed at the early phase of the projects in order to consider the analysis results in the final designs. While the risk analyses need the design information, such as 3D model which includes process equipment size and layout, therefore it is important to expect the final design properly and carry out the risk analyses at the early phase of the projects.

The appropriate schedule of the risk analyses, and the accurate expectation of the final design information for the risk analyses are the key points for the safety design success.

In oil and gas project development, almost all HSE risks can be mitigated to lower level by implementing safer design and engineered safety such as appropriate selection of technology, applying robust layer of safety protection system. However residual risks in Operation phase shall be managed properly having the facts that the actual risk increases once hydrocarbon is introduced. In the JAPT symposium, KEI shared their experience on how to manage HSE for the development of PAG and TSB Fields in Kangean block offshore north of Bali, Indonesia from initial phase of project until the Operation phase.

Exploration and production of oil and natural gas is synonymous with contributing to realizing an affluent society. In this industry we should strive to create an organization with a corporate culture where securing safety and protecting environment have the highest priority as each of us acts based on highest integrity. We must explore business on a global scale in order to maintain a stable energy supply. In this pursuit, we are expected to comply with international norms and standards while exerting effort to create a globally acceptable corporate culture. Renowned international oil and natural gas companies are proactively involved in HSE (Heath, Safety and Environment) activities with their established HSE Management Systems. INPEX Corporation also established its first HSE Policy in 2006, and subsequently developed a number of standards that we call procedures and guidelines that delineate specific requirements in HSEMS regulations, occupational safety and hygiene, security management and environmental protection. Further, through the establishment of the Corporate HSE Committee and development of the annual HSE Objectives and Programs, we have been vigorously involved in various HSE activities with the PDCA cycle as the basis.

This is to introduce our HSE activities in offshore E&P projects and some of the HSE issues associated with these projects that we believe are important.