The University of Tokyo has established a research program “Environment-harmonized Energy Development Laboratory” sponsored by JX Nippon Oil & Gas Exploration Corporation (JX NOEX) to provide educational programs and conduct researches related to the energy resource development since 2013.
The purpose of our laboratory is to optimize operational activities at various stages on energy resources development projects, which ranges from information gathering to development and even production. We aim at establishing novel methodologies to attain improved recovery factor while managing environmental disturbance properly. Our research is especially focusing on the value of information analysis and global optimization and briefly introduced in this paper.
In systems where fluid is flowing from the reservoir to the surface, there are a number of potential flow assurance issues such as the deposition of hydrate resulting in the blockage of the flowline, and slugging in the flowline or riser, which could promote production interruption or weaken the system deliverability of the fluid significantly. Therefore, the industry is starting to consider that the analysis of potential flow assurance issues and the development of the management plan be implemented in an early phase of the project. To conduct a flow assurance study in an early phase of the project it is essential to obtain basic project information such as PVT analysis results, the oil and gas production plan and a rough plan for the wells and host allocation. Such information is, however, inherently not well defined in such an early phase and its use will therefore result in the creation of greater risk in the execution of the project. In this report, a method to introduce a “Flow Assurance Map” has been proposed, which is to view such potential project risks comprehensively in the early phases of a project and manage those risks.
Knowledge of in-situ stress state in oil and gas reservoirs is necessary and important for the prediction of orientations of hydraulic fracturing and for the design of optimum parameters of the hydraulic fracturing aimed at enhances of hydrocarbon energy resource recovery. Although many types of stress measurement techniques have been suggested and developed up to today, there is not a perfect and reliable method for obtaining the full stress state information (the three-dimensional stress tensor) in a large depth well. For better understanding to the present situation of stress measurements and their insufficiency, we reviewed and summarized the existing stress measurement methods which can be applied into a deep wellbore. In principle, measuring of the in-situ stress under in-situ condition is better; for example, applications of the hydraulic fracturing, leak-off test or extended leak-off test, as well as analyses of wellbore failure stress indicators including borehole breakouts and drilling induced tensile fractures are desirable. In some cases, the hydraulic fracturing and/or leak-off tests are impossible and the wellbore failure stress indicators are not available. Even such stress data are available, they may be insufficient, for example, lack of the maximum horizontal stress magnitude. Therefore, the core-based stress measurements are useful as the complementary approach. We described the details of anelastic strain recovery (ASR) method and diametrical core deformation analysis (DCDA) method which are widely and frequently applied in the recent scientific and engineering deep drilling projects as the core-based stress measurement methods. We concluded that these core-based methods are applicable and helpful in deep drillings related to the hydrocarbon energy resource recovery projects.
To investigate the characteristics of fractures and surrounding region induced by the hydraulic fracturing, a new method to visualize hydraulically induced fractures in the laboratory experiment was developed. For this purpose, a thermosetting acrylic resin, methyl methacrylate, mixed with a fluorescent paint was used as the fracturing fluid. The resin was able to fix within the specimen by heating just after the fracturing experiment, and then cut sections of the specimen were observed under ultraviolet light irradiation. In this way, it is expected that the hydraulically induced fractures and the surrounding regions will be detected because the induced fractures filled with the resin should emit light, while the other parts will not.
As a result, the hydraulically induced fractures, which were filled and fixed with the resin, are successfully observed in the shale specimens. The configuration of bi-wing fractures extended from the injection hole along the maximum stress direction is clearly observed under the uniaxial compressive condition. Detailed microscopic observations show that the main fractures are tortuous and are accompanied by many thinner ramified fractures. Additionally, fractured regions where the resin penetrates significantly are observed around the main fractures. These induced fractures and fractured regions are considered to be the stimulated region in which permeability is improved.
In-Situ Combustion (ISC) is the oldest thermal oil recovery method, however, only four projects have been carried out in the world, because controls of combustion front and oil production are extremely difficult compared with steam injection. Recently, the toe to heel air injection (THAI) method is expected to have several advantages on combustion control, oil recovery ratio, costs of production and water treatment compared with steam injection methods, such as SAGD method using horizontal wells. THAI method also uses a horizontal producer that controls the combustion front and downward gravity oil flow to the producer. To promote THAI method, the reliable kinetic chemical model on ISC process has been required for field scale simulations.
Chen et al. (2014) carried the history matching using the kinetic model for the combustion tube tests. However they didn't show good matching with the measurement results, since their model was not proper to simulate chemical reactions of Coke generation from Asphaltenes. In this study, the classification of four oil components, Saturates, Aromatics, Resins and Asphaltenes (SARA), were applied to construct ISC modeling. A new pseudo component called as “Partial Oxygenated Asphaltenes (POA)” has been proposed based on measurement results of a thermal gravity analysis (TGA) and the batch reactor test by revising the Chen et al.'s model. The present model using 11 chemical reactions including POA has been confirmed to show a reasonable matching with the TGA result that POA mass increased in air with O2 absorption under 200°C and decreased above 200°C with thermal cracking of Asphaltenes. To reduce computational time, 5 chemical reactions were screened from original 11 reactions. In addition, the model of 5 reactions was successfully applied to the field scale simulation by THAI method with reducing frequency factors in the kinetic reactions to eliminate the influence of grid-block size.
Mercury in oil and gas must be removed for stable production and environmental concerns. Especially in design phase of production facilities, it is important for optimization of Mercury Removal Unit (MRU) to assess accurately concentration and chemical form of mercury in production fluids based on mercury analysis during Drill Stem Test (DST). However, mercury behavior during DST may be different from that in steady production phase, because of dissolved oxygen (DO) in brine. If an incorrect assessment on mercury analysis during DST is made, modification of MRU after start of production is difficult in offshore facilities which have limited space for equipment, and forces unscheduled production downtimes. To investigate influences of fresh brine containing DO on mercury behavior in unsteady production phase like DST, the mercury sampling test was conducted during clean up flow at a natural gas well after acid washing. As a result, particulate mercury concentration in filtered solids collected from condensate and flowback water reached a peak at the early phase of clean up flow, and then decreased to around two orders of magnitude lower at the late phase when pH and total iron concentration in flowback water were close to those in steady production phase. Furthermore, mercury sulfide was identified in some filtered solids. Hence, the results of the sampling test indicate that mercury sulfide may be produced by the reaction of DO in workover fluid with hydrogen sulfide and elemental mercury in natural gas, and reveal that different chemical form of mercury is produced in unsteady production phase like just after well workover. As there are hardly any reports such as this study, although further investigations will be needed for the interpretation of these results, they will be an important knowledge for interpretation of mercury analysis during DST.
This paper introduces a reservoir study for a gas field which have problems of complicated water production behavior. In order to understand the mechanism of the water production, a simple sector model was constructed to reproduce the production history and well test analysis result.
Taking the geological information into consideration, water production mechanism of this field was assumed in two patterns: in lower formation, gas water contact level has been risen and in upper formation, water moves from the lower aquifer zone through conductive faults.
In lower layer, vertical to horizontal permeability ratio and aquifer volume are important parameters which have major effects on water production behavior in the simulation study. The ranges of these parameters were narrowed by the history matching process for reproducing pressure transient analysis and water production using simple sector models.
In upper layer, authors assumed water goes through conductive faults. For reproducing this phenomena, pseudo-relative permeability curves were employed. By history matching process using simple sector model which was implemented this pseudo-relative permeability curve, the range of distance from conductive fault to the well was also estimated.
By this study, the complicated water production mechanisms were understood then the uncertainties of some important reservoir parameters were reduced. These information and knowledge can be strong support for full field simulation model study.
A feasibility study of CO2-EOR (Enhanced Oil Recovery) project in a mature oil field in South Sumatra has been conducted with PERTAMINA, the Indonesian state-owned oil company. This comprehensive research includes construction of geological and geophysical model for the target reservoir, execution of reservoir simulation based on special fluid analysis of the crude oil, and the conceptual design of surface facility. This article is based on results obtained from a project subsidized by the New Energy and Industrial Technology Development Organization (NEDO).
Iwafune-Oki oil & gas field is situated at 4km offshore from River Tainai in Niigata and is the only operational offshore field in Japan. This field has been operated since December 1990, but after five years of plateau period, it showed a rapid decline in the oil production rate. Therefore maintaining productivity by finding additional reserves became an urgent task. In response to this, G&G and Reservoir Evaluation Group assessed exploration potential and possibilities in field development optimization. As a result, it was possible to greatly increase proven reserves. It is also possible to interpret this as a process of field growth. In this paper, the efforts at value maximization of this field are introduced from the development history viewpoint.
Information on the size, morphology and distribution of individual volcanic rocks is important in volcanic reservoir evaluation. This paper statistically analyzes the characteristics of Miocene felsic volcanic rocks in the Tsugawa - Aizu Province (TAP), and a comparison is made with Miocene felsic volcanic rocks of the reservoirs of the Katakai gas field (KGF) in Niigata, Japan.
TAP is a structural province of NW-SE trending graben that consists of numerous depressions (basins) divided by uplift zones, and buried by large amounts of volcanic rocks that resulted from early to middle Miocene submarine felsic volcanism. The felsic lava is comprised of massive and autobrecciated lava facies, and accompanied by pyroclastic rocks. The average thicknesses of lavas range from 10 to 1000 m, and the estimated volume of a single felsic lava is 1.3×10-4−1.9×102km3.
The Miocene felsic volcanic rocks in KGF form structural rise trending NNE-SSW; however, in the southern portion of the rise the extensional axis of the rise shifts to the southwest. Within this portion of the rise, the north-northeast is dominated by massive (coherent) lava with hyaloclastite, whereas the south-southwest gradually shifts to volcanoclastic rocks. According to well data, each lava body ranges from several to 200 m for the thicknesses, and from 1 to several km for the lengths, respectively.
The entire scale of the felsic volcanic rocks comprising the reservoirs of KGF is smaller than that of TAP, and the individual lava bodies are comparable to the small to medium size lava bodies found in TAP. It is suggested that the volcanism in KGF occurred in a similar submarine environment between depression and uplift in TAP.