JX Nippon Oil & Gas Exploration (Malaysia) Limited (JX Nippon) is the operator of offshore gas field (Block SK10). The field has produced over 1 Tcf of natural gas since the 1^st production in 2003 with an outstanding record of no Lost Time Injury (LTI) operation for 12 years. Various operation optimization and cost reduction efforts have been carried out since the beginning of the field.

Operation optimization and cost reduction would be a one of the most relevant practices in upstream companies. However, the recent oil price decline enforces all parties in the industries, to take immediate and robust actions for further cost reduction to sustain and remain secure the business.

This paper introduces challenges and approaches for cost effective operation by JX Nippon for Block SK10 gas field. These approaches are not limited to individual Petroleum Arrangement Contractor (PAC) efforts but also activities under a nationwide alliance among Petroliam Nasional Berhad (PETRONAS) and all the PACs.

Iwafune-Oki field is the unique offshore field currently under operation in Japan. It was discovered in 1983 and has been producing from several oil and gas reservoirs since 1990.

Because the decline of oil production had been confirmed after plateau period, we started to examine IOR application to Zone 2100 m, which was main reservoir of this field. This study indicated that natural gas IOR, using the abundant gas contained in the other zone, was effective.

The pilot injection test was started in December 2004. The transition from the test to regular operation was decided in 2006 with confirming the increment of production oil.

We have continued the production operation with the success of this IOR, though our prediction suggested that we couldn't continue the production after 2009 without the IOR. By the end of 2015, the oil recovery ratio of Zone 2100 m was 4% higher than without the IOR. In addition, the profit limit of Iwafune-oki field was extended.

Transition of tubing and casing materials in Minami-Nagaoka gas field is summarized based on more than 30 years' experience. The field commenced the production in 1984. The tubing material was replaced from carbon steel to some corrosion resistant alloys including 22Cr duplex stainless steel after faced with several corrosion problems such as CO₂ corrosion of carbon steel tubing, localized corrosion of 13Cr stainless steel and sulfide stress corrosion cracking of P-110 grade casing material. Newly developed 17Cr is tested in high pressure and high temperature CO₂ corrosion conditions and shows excellent general corrosion performance, equivalent to 22Cr duplex stainless steel, in the field condition. That is why 17Cr martensitic stainless steel is considered as the next candidate for the tubing material. This report describes the cause of corrosion and those measures.

CO₂ separation technology is essentially important to develop natural gas fields including CO₂ gas, especially gas fields with CO₂ gas of high concentration, and to utilize collected CO₂ gas in oil fields applying CO₂-Enhanced Oil Recovery (EOR). Japan Oil, Gas and Metals National Corporation (JOGMEC), Chiyoda Corporation and Mitsubishi Chemical Corporation have been developing CO₂ separation technology using chabazite type zeolite membrane in the framework of JOGMEC's Technical Solution Program since 2013. The developed technology features its high CO₂/CH₄ separation factor as well as excellent high CO₂ permeability. As the results obtained in the basic research works using simulations as well, it is found that a compact system for CO₂ separation with minimum energy consumption can be provided with this technology, especially in the case where this CO₂ separation technology is applied to gas fields with high gas pressure in the gas well, and compressors are not required for the separation processing and single stage type of this separation process is employed. For example, the energy consumption of the hybrid system which employs this developed zeolite membrane process and Acid Gas Removal (AGR) employing amine solution method is expected to be reduced by approximately 60% at the highest, compared to that of AGR single system in some case. Besides, the total value of CAPEX and OPEX for ten years on the hybrid system is expected to be reduced by 30% at the highest, compared to that of AGR single system in this case.

Under the circumstances of low oil price, not only oil companies but also universities have continued a variety of efforts to save labor and cost. The investigation on the optimization using computer programs is one of such efforts. This paper introduces some of the computer programs applying the optimization algorithm that have been developed in the laboratory of the author.

First example is the program to optimize facies distributions. This program has three functions of estimating facies distributions using multi-point statistics, optimizing the facies distributions thus estimated by the genetic algorithm and improving the computational time in selecting superior specimens in the genetic algorithm applying the multi-dimensional scaling and k-means clustering.

Second example is the program to estimate the true fluid composition based on the composition of fluid samples acquired in inappropriate conditions such as disturbed 2-phase flow condition and gas leakage condition, applying the iterative Latin hyper cube sampling method as an optimization method.

Third one is the program to estimate the oil relative permeability in the 3-phase condition. Since it is time consuming and hence costly to measure the relative permeability in the steady-state 3-phase condition, this program enables the estimation of the relative permeability as functions of oil, gas and water saturations, by reproducing the results of unsteady-state 3-phase core flooding experiments through optimization with Gauss-Newton method.

The last program optimizes the CO₂ injection rate and the location of wells so that the economics of a CCS-EOR project can be maximized, taking the oil increment by CO₂ injection and the CO₂ tax/credit by storing CO₂ in a reservoir into consideration simultaneously.

Although the above programs may be still in the primitive stage, the simulation runs executed for validating the performances of these programs showed the promise of the optimization programs for conserving labor and time.

Asphaltenes are the components of heavy fraction of oil. Once they deposit and clog the pore throats of reservoir rock, tubing pipes in production wells, and pipelines for oil transportation, it causes a serious problem for oil production. The objective of this paper is to show the applicability of “digital oil”, which is a full molecular model of a crude oil, and Molecular Dynamics (MD) simulation to solve the asphaltene problems. For this purpose, a digital oil of “A-crude oil” produced from an oil field actually confronting asphaltene problems was generated. On the generation of the digital oil, some analytical experiments were conducted and Quantitative Molecular Representation (QMR) method was applied. As a result, the digital oil was successfully generated. Then, asphaltene-asphaltene association energies in 7 different solvents: n-heptane, toluene, benzene, xylene, isopropyl alcohol (IPA), an azeotrope mixture of toluene and IPA, and a ternary azeotrope mixture of water, toluene, and IPA, were evaluated by calculating the Potential of Mean Force (PMF) using MD simulations and umbrella sampling technique. As expected, aromatics (toluene, benzene, and xylene) presents much lower association energies of asphaltene in absolute value than that in n-heptane. Among the 7 solvents, the ternary mixture provides the lowest association energy in absolute value. Therefore it can be the most effective solvent for the asphaltene of “A-crude oil”. Furthermore, it can be supposed from the result of this study that the association energy becomes lower in absolute value when the aromatic asphaltene solvents tend to distribute near around the edge of asphaltene molecule much more. Thus the digital oil and MD simulation would be a useful tool to solve the asphaltene problems in oil production.

Encana Corporation has employed several completion techniques over the past decade to successfully develop the unconventional Montney tight gas reservoir. Optimizing fracture stimulation and design has been an important focus for improving productivity and overall well economics. This paper outlines several factors that could influence hydraulic fracture propagation behaviour in the Upper Montney formation. Commercial fracture modeling software and microseismic surveys were used to improve understanding of fracture geometry and propagation. Sensitivities around elastic moduli, closure pressure, pore pressure and composite layering were used to highlight the range of possible geometries. This study revealed several potential fracture barriers in the Montney package which could impede vertical fracture growth. Production data was also investigated for the selected wells to examine the relationship between frac size, fluid volume, and productivity. Production analysis revealed that cumulative gas production has a linear relationship with injected water volume and the gradient of the least squares fitted line to the relationship varies by target zone. Increasing injection volume twice increased cumulative gas production by 1.81 time. Fracture modeling suggested that increased fracture surface area may be one possible explanation for increased productivity for the Upper Montney 1 zone in this study area.

In recent years, Low Salinity Waterflooding (LSW) Enhanced Oil Recovery (EOR) research is attracting attention during oil price downturn, mainly because of its low cost and simplicity. INPEX is currently conducting a LSW laboratory test for a carbonate reservoir. This article provides an overview of the comprehensive laboratory measurements from preparatory tests to main tests. Knowledge acquired during the laboratory test is also provided.

The results of the spontaneous imbibition tests were promising, which requires a coreflood experiment to further evaluate the possibility of conducting a LSW in this studied reservoir.

Siam Moeco Ltd. (SML), a subsidiary of Mitsui Oil Exploration Company Limited, discovered a marginal oil field in onshore Thailand. The reservoirs in this field are lower Miocene fluvial sand stones, which are thin bedded and poorly connected. To develop the field, a cost effective optimization was essential. SML continuously implemented the procedures positively to minimize the cost in both the data acquisition stages and development stages. Throughout this project, this concept was employed in the project, which is “Optimization is minimizing the cost of attaining the objectives while maintaining safety standards.” As a result, the means for development of the field resulted with a combination of a slimhole well design and coiled tubing jet pump.

The Burapa-A field was confirmed to have commercial reserves in 2010. The production wells were drilled in 2012. However, the decline of the production was remarkable in 2013, and was faster than expected. Installation of artificial lift was crucial before the production rate dropped below the economical limit. We selected the coiled tubing jet pump as the primary solution. We had tested and installed the jet pumps in all our production wells in the three years between 2013 and 2015. The production has been steady since then until today. In this paper, we introduce a case study for development of the marginal oil field.

Yurihara oil field, Akita was discovered in 1981. The peak rate was over 350 kL/day, but the production is going down constantly because the plant processing capacity depends on gas sales. The preference of the customers is shifting to liquefied natural gas, and the natural gas sales tend to be down. For solving the productivity restriction, we started to inject the excessive gas into the reservoir, expecting the increase of oil production. The target reservoir consists of basalt with high heterogeneity. We are trying to forecast the oil production after the gas injection with geo-statistical models, but it's still difficult to estimate the facies distribution and permeability distribution on the complicated volcanic reservoir. Therefore, we focus on the material balance of gas injection in order to investigate the relationship of well connectivity. Watching the production history of each well, we successfully specified the injector-producer connectivity in some extent. After that, we are planning to do interference test in order to optimize the injection rate of each injector.

At present, the main energy resources in the world are oil, natural gas, coal, uranium, etc., which are commonly referred to as conventional energy resources. Otherwise, resources called unconventional energy resources are predicted to have enormous potential exists. Among the unconventional energy resources, as corresponding to the natural gas, these include shale gas, coal bed methane, tight gas, methane hydrate, water-soluble gas, and others. In recent years, owing to the advances in technological development, research and development of unconventional natural gas have been activated. In particular developed, such as shale gas in North America, will have a great influence on the gas supply in the world in the future.

This paper will discuss the resources situation of natural gas in China, which includes unconventional gas, development situation and supply potential. In China, there is a fascinating natural gas resource, especially the unconventional natural gas, which has a promising potential. With the development of geological survey, resource of natural gas is expected to further expand. The development of natural gas is highly expected. China has already grasped the developed technology of conventional natural gas and tight gas. On the other hand, unconventional natural gas is in the initial exploitation. As far as the development track record, China's companies still can not catch up with the development capabilities of the companies of United States. Therefore, the innovation and cooperation with foreign companies have become necessary. In China, due to the rich natural gas reserves, the implementation of progress and preferential policies of development technology, the development of unconventional natural gas are in the accelerated development. At present, unconventional natural gas has become the supplement for the conventional natural gas, and may become an important source in the future. By these things, it is considered that the unconventional natural gas will bring a major change to China's energy industry.

It could be said that the well construction technology included drilling techniques had developed while depending on other industrial technology from the past. The depth of hand digging wells could be 30 Ken (about 50 m) at most due to many cases of loss of consciousness caused by the gas in the borehole in 1800s. After that, by virtue of the foot bellows that was a technique for ventilation in the wellbore, the depth was rapidly increased to 70 Ken (about 127 m) in 1860s. At the same time, construction methods progressed, resulting in the development of an oil well as large as 180 Ken (327 m). Cable tool drilling techniques had been imported to Japan for the first time in 1873. These techniques includes not only a method of simple well spudding with a bit, but also all of techniques in pipe driven, “fishing”, casing installation, formation isolation and other improvement. The rotary drilling techniques were imported to Japan in 1912. The time that was not possible to complete a well between 1914 - 1928 continued because encountered “Zaku” currently called “sloughing shale” at Niitsu oilfield. The “Zaku” formation was completely drilled at last when “double-floor drilling” was adopted in 1937. This “double-floor drilling” was a casing drilling technique.