JOGMEC surveyed technical trend of intelligent well completion on 2009. The general idea of tools for intelligent well technology and resent technical trend are described in this article. Intelligent well technology, which is known as “smart well technology” too, is to maximize the subject field value with optimization of the production operation based on the real-time down-hole monitoring and flow control. Typical intelligent well technology systems are represented to surface system and down-hole system. Surface systems are consisted by data transfer & management system, and operation optimization system. On the other hand, Down-hole systems are consisted by isolation tool, flow control tool, and monitoring tool ; those are focused on this article. For the recent technical trend, following topics are described ; typical application of intelligent well technology, reliability of component tools, and newly development tools.
The application of optical fiber cable technology has initially been adopted by the telecommunication industry and has been dramatically expanded to many other fields since the year 1980. The technology has eventually been brought to the oil and gas industry as the form of sensing device, i.e. Distributed Temperature Sensing, DTS, which aims at measuring real-time temperature distribution in the downhole, since the year 2000. The recognition to DTS as an extremely powerful tool for well monitoring, optimization of production operation, etc. has been gained ever since successful installation and monitoring cases have been accumulated. Currently, DTS has been established as a popular well monitoring and production optimization technology and is expected to gain the market in the industry. On the other hand, more advanced Distributed Sensing technologies are desired to be developed by the industry due to its movement toward Smart Technologies including Smart Well, Smart Field, etc. In this paper, the authors intend to introduce a prototype DPTS, Distributed Pressure and Temperature Sensing, measurement system and field pilot tests conducted in a dissolved-in-water type natural gas field in the southern Kanto district. Field tests have been successfully conducted in 2 wells, a observation well and a producing well. As a result, the DPTS system has been proved to have practical use in monitoring pressure and temperature distribution in a downhole with more improved accuracy than conventional devices in dissolved-in-water type natural gas fields similar to the one that has been tested. Based on the positive outcomes, the authors have come to consider that the deployment of the current DPTS system to conventional oil and gas wells would be highly potential, which would provide a better downhole monitoring, a better well management and a production optimization in those wells, in the near future.
This presentation introduces the analysis of the bottom hole pressure data acquired in the CO2 sequestration project done as part of “Research and Development of Underground Storage Technology for Carbon Dioxide” that the Research Institute of Innovative Technology for the Earth (RITE) executed from 2000 to 2006. The bottom hole pressure gauges observed over 30 times of pressure fall off curve caused by the shut-in due to the surface facility's trouble. From the transient analysis of this sequence of fall off curves, the improvement of injectivity which is expected to result from vaporization of formation water into dry injected CO2 was observed as well as the expansion of CO2 distribution.
Japex has been operating Yufutsu Oil & Gas filed in Tomakomai, Hokkaido. The new water injection well drilled in 2009 has very good reservoir characteristics and productivity is also very good, but injectivity declines rapidly with increasing the cumulative volume of injected water. We took many wellbore data concerning pressure and temperature, and tried to consider the cause of the damage. With an analysis of the data, we considered that the damage is due to the mud cake stayed between the 5″ Slot Liner Casing and 6″ wellbore. We tried to remove the mud cake by Pulsonix cleaning and Acidizing treatment, and succeeded to recover the performance by eliminating most of the foreign object.
The Minami Kuwayama oil field is located 2 km to the northwest of Gosen city, Niigata prefecture. The reservoir depth is at 3,000-3,500m, formed out of tuffaceous sands. Soon after the field discovery in 2003, early commercial production was started. In this field, it is thought that asphaltenes have been deposited in the reservoir since the early production period, while asphaltane deposition trouble arises generally in surface facilities or wellbore tubing. Costly chemical treatments, such as solvent injection into the reservoir, have been applied several times. However, it is found that effects of the treatment do not last long, i.e. any permanent solutions are necessary to develop this field efficiently. In the first step for the solution, laboratory experiments and reservoir simulations were carried out. In the laboratory experiments, it was found that asphaltenes were precipitated in the reservoir condition and its size was large enough to plug the pore space. Reservoir simulations suggested that the decline of production was due to the asphaltene deposition by taking into account the asphaltene precipitation and deposition process.
Tracer survey is one of the monitoring methods for fluid flow in the reservoir. This paper reports an application of tracer survey to an oil field in Middle East and it was succeeded to increase oil production rate of the field. Production of the field was commenced in 1975 and water injection was applied in 1984 with pattern water flooding. Field has been already matured and infill producers are drilled to keep oil production rate. However, due to long water injection history, oil was remained in patches. Sometimes, infill wells were drilled in water invaded area because evaluation of sealing faults affected to location of high oil saturation area. To reduce this uncertainty, tracer survey was conducted and monitoring results showed locations of sealing faults. Results were incorporated with reservoir simulation model and new infill producer could be planned with confidence. New infill producer was completed successfully in 2009.
An automatic fault extraction (AFE) process is expected to contribute to fault interpretation. However, it is important to validate an output of the AFE process because fault patterns extracted by the AFE process change according to extraction parameters. A commercially available AFE process is applied to 3D seismic data acquired in the Yufutsu oil/gas field with an objective to estimate fault-related fractures in a reservoir. To select a suitable output of the AFE process, fracture information derived from Acoustic Emission (AE) data during a massive hydraulic injection is utilized. The AE data delineate fracture zones within the area of six hundred meters by two hundred meters. An output of the AFE process with fault intervals close to those derived by the AE distribution is selected and it is used as an input for Discrete Fracture Network (DFN) modeling to constrain locations and orientations of the fault-related fractures. The dense zones of the fault-related fractures expressed by multiple realizations of DFN models are fairly consistent with main fracture zones delineated by the AE distribution. This consistency indicates that the output of the automatic fault process has been validated by the AE data and that it can be used for estimation of fault-related fractures in the area outside the source location distribution of AE events.
Thick and porous reservoirs induce significant compaction, resulting in screen and casing failures within the reservoir section and inducing casing tensile/shear failures in the cap rock section. Designing these wells based on the conventional API specification requires excessively high grade and heavy duty casing, resulting in low hydrocarbon productivity with a high cost. “Ultimate tubular string design concept” must be introduced to develop these fields within commercial feasibility. However, these concepts require reliable well monitoring to prevent accidents. Furthermore, well monitoring helps to improve modification of completion equipment to enhance productivity and to reduce downtime. This presentation provides a field example how a highly compacting reservoir has induced casing and screen failure and how the wells have been monitored to prevent accidents.
While measuring flow rate has been one of the most important key elements involved in the understanding of reservoir behavior and optimizing reservoir management, the idea of installing an oil-water-gas “Multiphase Flow Measuring System (MPFM)” on each individual well is in the spotlight. Japan Oil, Gas and Metals National Corporation (JOGMEC) has been developing an MPFM of the kind, a system that is both trustworthy and easy to set up (Target : possible to measure liquid and gas flow rates within a relative error of +/−10%, water cut within an error of +/−3%). The system is a batch type MFPM which has a small separator to measure water cut correctly. The procedure for the measuring process is : (i) separating liquid and gas, (ii) measuring gas flow rate with gas meter and (iii) storing liquid in the small tank and calculating water cut and liquid flow rate by liquid level and oil-water surface level measured using differential pressure transmitters. This system could measure liquid and gas flow rates within a relative error of +/−10% and water cut within an error of +/−5%. JOGMEC & Past JAPAN ENERGY DEVELOPMENT Co., Ltd. (JED) conducted a field test of the batch type MPFM at JED's Nakajo oil and gas field from October to November in 2008. The results of the field test were sufficient.