Summary The first offshore methane-hydrate production test was conducted in the Eastern Nankai Trough area of Japan in 2013, subjecting a gas-hydrates reservoir to large drawdowns by reducing bottomhole pressure (BHP) for in-situ dissociation of gas hydrates. This pioneering test has proved the feasibility of the depressurization method through demonstration of gas production from a deepwater gas-hydrates reservoir. Approximately 119 500 std m3 of gas was produced during a continuous flow period of 6 days. However, reservoir response to a range of drawdown conditions was not attainable, which is important for reservoir evaluation, because drawdown became uncontrollable after unintended water production through the gas line occurred. Gas and water released from the dissociation of gas hydrates were separated by use of a downhole gas-separation system. The separated gas and water were produced to surface by means of two dedicated gas and water lines. Drawdown was executed by pumping out water into the water line by use of an electrical submersible pump (ESP). Drawdown control was designed to regulate the liquid level (or hydrostatic pressure) in the gas line by controlling the ESP frequency and the water-line surface backpressure. Analysis of production data supported by flow simulations indicated that continuous water production through the gas line was the main reason for the loss of drawdown control. The trigger of the water production was that the water column in the gas line reached surface because of the rising water level resulting from the produced gas, which also lightened the water column and lowered the BHP. Consequently, the continuous water production made it difficult to regulate the drawdown as intended. The analysis concluded that the risk of water production through the gas line could be significantly lowered if a choke valve was installed at the surface gas line and/or the ESP had high tolerance to the presence of free gas. This first field trial has provided valuable information in understanding the methane-hydrate production system to further improve/develop strategies in controlling large drawdown in the system.

The first offshore methane hydrate production test was conducted in the Eastern Nankai Trough area of Japan in 2013 subjecting gas hydrates reservoir to large drawdowns by reducing bottomhole pressure (BHP) for in-situ dissociation of gas hydrates. This pioneering test has proven the feasibility of depressurization method through demonstration of gas production from a deep water gas hydrates reservoir. Approximately 119,500 Sm3 of gas was produced during a continuous flow period of 6 days. However, reservoir response to a range of drawdown conditions was not possible due to unintended water production through gas line. This paper evaluates the issues with drawdown control that was affected by the water production. Gas and water released from the dissociation of gas hydrates were separated using a downhole gas separation system. The separated gas and water were produced to surface via two dedicated gas and water lines. Drawdown was planned by pumping out water into the water line using an electrical submersible pump (ESP). Drawdown control was designed to regulate the liquid level (or hydrostatic pressure) in the gas line by controlling the ESP frequency as well as the water line surface backpressure. Analysis of production data supported by flow simulations indicated that water production through the gas line was the main reason for the loss of drawdown control, i.e., the rising of liquid level was due to water production caused by the produced gas. Water entrainment by gas stream was not the main reason for the water production due to low gas velocity. The produced gas lightened the water column in the gas line, raised the liquid level and lowered the BHP. This process mimics a gas lifting process in a predominantly liquid production well. Since the BHP was largely affected by the liquid holdup as well as the volume of gas in the gas line, it was difficult to regulate the drawdown as intended. The analysis concluded that water production through the gas line could be prevented if a backpressure regulator was installed at the surface gas line and / or the ESP had high tolerance to the presence of free gas. Lessons learnt from this first field trial has provided valuable information for improving the methods for controlling large drawdown in methane hydrate production system.

"Nanoparticle-based enhanced oil recovery (Nano-EOR)" is an improved waterflooding assisted by nanoparticles dispersed in the injection water. Many laboratory studies have revealed the effectiveness of Nano-EOR. An evaluation of the EOR effect is one of the most critical items to be investigated. However, risk assessments and mitigation plans are as essential as investigation of its effectiveness for field applications. This study examined the items to be concerned for applying Nano-EOR to the Sarukawa oil field, a mature field in Japan, and established an organized laboratory and field tests workflow. This paper discusses a laboratory part of the study in detail. This study investigated the effect and potential risks of the Nano-EOR through laboratory experiments based on the workflow. The laboratory tests used surface-modified nanosilica dispersion, synthetic brine, injection water, and crude oil. The oil and injection water were sampled from a wellhead and injection facility, respectively, to examine the applicability of the EOR at the Sarukawa oil field. The items of the risk assessment involved the influence on an injection well's injectivity, poor oil/water separation at a surface facility, and contamination of sales oil. A series of experiments intended for the Sarukawa oil field showed that 0.5 wt. % nanofluid was expected to contribute to significant oil recovery and cause no damage on an injection well for the reservoir with tens of mD. This is considered a favorable result for applying Nano-EOR to Sarukawa oil field because it contains layers of tens mD. Furthermore, the experiments also showed that 0.5 wt.% nanofluid did not lead to poor oil/water separation and contamination of sales oil. Thus, field tests are designed with this concentration. This paper introduces the entire study workflow and discusses the detailed procedure and results of experiments investigating the Nano-EOR effect and potential risks.

Summary Microbial DNA-based monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNA-based monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNA-based monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields.