Reservoir fluids in Umm Al-Anbar (AR) Field have unique characteristics with vertical variations in the hydrocarbon properties in the 500-ft thickness of Arab Formations. While Arab A and B reservoirs are black oil reservoirs, Arab C and D1 reservoirs are reservoirs with near critical fluids varying in composition according to the reservoir depths. Since Arab D2 and D3 reservoirs are gas condensate reservoirs, there are three types of reservoir fluid in the field. Modeling of the migration and accumulation process has been studied in order to explain vertical reservoir fluid distribution and the formation of near critical fluids in the field. The process of primary oil and secondary gas migration was proposed in 1993. This report presents several technical topics related to : (1) The vertical distribution of different types of reservoir fluid. (2) The process of primary oil accumulation and secondary gas migration. (3) Special properties of near critical fluid. In addition several technical points on the treatment of near critical fluid in reservoir simulation studies are discussed.
Yufutsu gas condensate field has a fractured reservoir which consists of conglomerate and granite. It contains condensate-rich gas. We observed some strange fluid behaviors. Production gas oil ratio ranges from 900 m3/kl to 1,900 m3/kl according to production area where reservoir depth is different. Gas production started ten years ago. At the early stage of the production, gas oil ratio decreased with time. This trend is opposite from normal behavior of a gas condensate reservoir. Also, we observed that heavy gas existed on light gas in a tubing at a specific well. In order to explain such strange phenomena, we introduced a thermal diffusion theory in 1999 and 2000 by a support of Japan National Oil Corporation (currently JOGMEC). The reservoir is approximately from 4,000 m to 5,000 m deep and 1,000 m thick. So, pressure and temperature are varying in a wide range with the reservoir depth. Gas compositions at the top and the bottom of the reservoir are so different that methane, the lightest component, tends to increase with depth and temperature due to the thermal diffusion effect, because methane has larger thermal diffusion coefficient than the other heavier gas components. We expect that this assumption could explain the strange fluid behaviors. This paper reviews the above phenomena and the theory and reports current effort to increase condensate recovery using gas cycling scheme.
A reservoir modeling using simulation software on the market is popular to evaluate production profile and has specific requirement in an each phase through a project. Generally, a simpler model is preferred to examine many cases about production scenarios for a commercial evaluation in feasibility study phase. So, it is very important how to express subsurface uncertainty in a simple reservoir model. A condensate banking phenomenon which reduces productivity near the wellbore is a typical feature of gas reservoir, especially condensate rich gas reservoir. Evaluation of the condensate banking is an important issue from a viewpoint of production profile evaluation because of requirement from market to maintain plateau of production for the project. One of popular techniques to express the condensate baking is local grid refinement (LGR) method applied around each well in the compositional simulator. However, LGR application may not be a preferable option in the feasibility study phase, because more complicated reservoir model requires more calculation time. So, PI multiplier method was introduced without LGR option to keep simplicity of the reservoir model. An investigation of the PI multiplier applied in the coarse grided full field model without LGR to take into account productivity reduction by condensate baking has been presented in this paper.
This paper describes the results of an investigative case study to identify the causes of productivity decline in an oil well and a successful chemical treatment to restore productivity. A well in Minami Kuwayama oil field has suffered from a significant productivity decline from the beginning of commercial production. Pressure build up tests have shown the presence of formation damage becoming larger as production goes. Then we considered the possibility of asphaltene deposition, which has been observed in most of the surface facilities, in the near wellbore formation restricting flow capacity around the well. A multidisciplinary team was organized, with field operation engineers and researchers from the R&D center, to investigate the asphaltene behavior in the formation and to find the effective way of chemical treatment as asphaltene-control measures. Laboratory analyses using bottom-hole fluid samples have built the onset pressure curve of asphaltene precipitation, which indicated the asphaltene deposition in the near wellbore region under the production conditions. Then the intensive laboratory tests have been carried out to evaluate some commercial additives in terms of their efficiency as an asphaltene inhibitor under the formation conditions and to find the most effective chemical to resolve precipitated asphaltene. Based on laboratory analyses and tests, a complete chemical treatment program consisting of injection of xylene into the formation with a three feet treatment radius and squeezing of an asphaltene inhibitor around the well has been designed and applied to the well. This chemical treatment resulted in a significant improvement in the productivity index which is almost ten times larger comparing as before.
The Mobara gas field is one of the dissolved-in-water type natural gas fields. This field exists in Chiba Prefecture, Japan. The wells in this field have particular production performance curves called “Mobara type”. The gas water ratio curves are initially low, and then increase to be so high as to blow up a large amount of water. The Mobara gas deposit consists of alternate layers of sandstones and mudstones. We applied mud logging to exploration of the Mobara gas deposit. As the result, a small amount of free gas was detected in the mudstones. In addition to exploration, we carried out laboratory experiments using an X-ray CT scanner and mudstone cores. In the experiments, gas and water flow rates and CT values were measured at the same time. Gas water ratio increased with incremental drop of pore pressure, and gas saturation calculated from CT values also increased. From analyzing the exploration and the experiments, following conclusions were obtained. (1) In the Mobara gas deposit, gas bubbles of extremely small size are stored in pore bodies of the mudstones. (2) Upward buoyancy forces and downward forces given by capillary pressure difference act on gas bubbles at all times. These forces are initially in equilibrium. (3) With the start of production, hydraulic gradients occur and capillary pressure actions change in mudstones. The gas bubbles begin to move through pore throats toward sandstones consequently. The above-mentioned experiments suggest that buoyancy and capillary pressure have an important effect on the Mobara type production performance.
NMR is capable of providing a wide range of information on rocks and fluids to petroleum engineering. The applications to use NMR have become more and more important particularly in recent years with an increase of necessity to tackle complex oil reservoirs. This paper introduces principles of NMR and possible applications to the petroleum engineering including research activities carried out by JOGMEC/TRC, so that the capabilities of NMR can be well recognized in Japanese oil industry.
Each flow rate of liquid-gas two-phase flows can be iteratively evaluated by measuring the pressure drop across an inline homogenizer for mixing the fluids and the rotation speed of a turbine rotor behind the homogenizer. JOGMEC has extended this idea to measure the oil, gas, and “water” flow rates simultaneously, and proposed a Multiphase Flow Meter (MPFM), which is composed of the homogenizer and a turbine meter with an inner assembly of twin rotors connected by a spring. However, the resultant volumetric flow ratio of water phase has a defect in accuracy. To improve the accuracy, the mechanisms of single-phase flow, gas-liquid two-phase flow, liquid-liquid two-phase flow and liquid-liquid-gas three-phase flow are investigated theoretically and experimentally. The results suggest that the proposed constructive formula may improve the accuracy of the measurements.
Cuttings transport behavior in drilling directional wells was experimentally investigated using a once-through type large-scale flow loop apparatus, the Cuttings Transport Flow Loop System (CTFLS) in the Japan Oil, Gas and Metals National Corporation Kashiwazaki Test Field. The annular test section of the CTFLS is 9-m long and consists of a 5" ID transparent casing pipe and a 2.063" OD drillpipe. The inclination of the test section can be set at an angle from 0 to 90° in 15° increments. Drillpipe can be mounted either in concentric or eccentric mode. Experiments using two types of drilling mud, water and 0.15% PHPA solution, were conducted to focus on the effects of parameters such as hole inclination angle, drillpipe eccentricity, mud flow rate, mud rheology and rate of penetration (ROP). In the test procedure, mud was circulated and cuttings were fed into the test section both at constant rates, supposing a condition of drilling with constant ROP. Then, for predetermined mud flow rates, quantitative data in steady-state condition such as volumetric concentration of cuttings in the annulus, cuttings bed height and frictional pressure loss were measured. Critical flow rate determination based on a cuttings concentration criteria defined in this study was also presented, and optimum mud flow rate in actual field operation was discussed from a more practical point of view.
The petroleum system in the deep water of the Toyama Trough to the southwest offshore of the Sado Island in the Japan Sea was considered based on the analytical results of METI Sado Nansei Oki S and D drillings and their preliminary surveys. The middle Miocene Lower Teradomari and Nanatani Formations indicate good source rock potential (0.90-2.98% TOC). The kerogen type is a mixture of Type II and III. The bitumens include organic matter from both marine and terrestrial sources, notably characterized by very abundant oleanane like the case of oils in the Kubiki area onshore Niigata. The oil sample collected from the Shiiya Formation of METI Sado Nansei Oki S is characterized by its high oleanane content. A seeped oil sample on the sea bottom, although heavily degraded, also indicates similar oleanane content and carbon isotope characteristics that can be correlated to the oil. The source rock of the oil is thought to be the mudstone of the Lower Teradomari and Nanatani Formations from the analytical results of the petroleum source potential, carbon isotopes and biomarker indices, especially the ratio of oleanane to norhopane content. The contribution of marine organic matter to the oil seems to be slightly higher than that to the mudstone in the Lower Teradomari and Nanatani Formations of the well. It suggests that the oil was derived from the source rocks of the same horizon that deposited in the basin center in comparison with the well location. The methane hydrate samples taken by preliminary sea bottom survey are referred to be thermogenic origin from the carbon isotope ratio. It can be isotopically correlated to headspace gas samples collected at 1900m and deeper zone of METI Sado Nansei Oki D well. This means that the deeper gas migrated to the surface very quickly without the appreciable input of shallow biogenic gas. Fluid inclusion analysis implies that the generated hydrocarbon was once trapped in the lower Teradomari Formation at METI Sado Nansei Oki D, then it migrated upward to the Shiiya sandstones through large faults and finally accumulated in the structural crest of the Shiiya horizon (METI Sado Nansei Oki S). Part of the hydrocarbons leaked from the Shiiya Formation through a number of minor faults to form methane hydrates and many Direct Hydrocarbon Indicators (DHI) that are observed with three dimensional (3D) seismic data. The kitchen area of the oil is estimated to be a syncline that locates west of the wells and is buried deeply along the Toyama Trough. It is suggested that the kitchen area provided hydrocarbons to deep water large structures and possibly to the onshore areas such as Kubiki Oil Field. The conditions required for oil accumulation in the Shiiya sandstone include the presence of deep faults for migration pathways and the absence of shallow fault that may leak hydrocarbons. Therefore 3D seismic is necessary to evaluate such geological condition.