Numerical studies of methane production from Class 1 gas hydrate accumulations enhanced with carbon dioxide injection

Class 1 gas hydrate accumulations are characterized by a permeable hydrate-bearing interval overlying a permeable interval with mobile gas, sandwiched between two impermeable intervals. Depressurization-induced dissociation is currently the favored technology for producing gas from Class 1 gas hydrate accumulations. The depressurization production technology requires heat transfer from the surrounding environment to sustain dissociation as the temperature drops toward the hydrate equilibrium point and leaves the reservoir void of gas hydrate. Production of gas hydrate accumulations by exchanging carbon dioxide with methane in the clathrate structure has been demonstrated in laboratory experiments and proposed as a field-scale technology. The carbon dioxide exchange technology has the potential for yielding higher production rates and mechanically stabilizing the reservoir by maintaining hydrate saturations. We used numerical simulation to investigate the advantages and disadvantages of using carbon dioxide injection to enhance the production of methane from Class 1 gas hydrate accumulations. Numerical simulations in this study were primarily concerned with the mechanisms and approaches of carbon dioxide injection to investigate whether methane production could be enhanced through this approach. To avoid excessive simulation execution times, a five-spot well pattern with a 500-m well spacing was approximated using a two-dimensional domain having well boundaries on the vertical sides and impermeable boundaries on the horizontal sides. Impermeable over- and under burden were included to account for heat transfer into the production interval. Simulation results indicate that low injection pressures can be used to reduce secondary hydrate formation and that direct contact of injected carbon dioxide with the methane hydrate present in the formation is limited due to bypass through the higher permeability gas zone.     

Pre- and post-drill comparison of the Mount Elbert gas hydrate prospect, Alaska North Slope

In 2006, the United States Geological Survey (USGS) completed a detailed analysis and interpretation of available 2-D and 3-D seismic data, along with seismic modeling and correlation with specially processed downhole well log data for identifying potential gas hydrate accumulations on the North Slope of Alaska. A methodology was developed for identifying sub-permafrost gas hydrate prospects within the gas hydrate stability zone in the Milne Point area. The study revealed a total of 14 gas hydrate prospects in this area.In order to validate the gas hydrate prospecting protocol of the USGS and to acquire critical reservoir data needed to develop a longer-term production testing program, a stratigraphic test well was drilled at the Mount Elbert prospect in the Milne Point area in early 2007. The drilling confirmed the presence of two prominent gas-hydrate-bearing units in the Mount Elbert prospect, and high quality well logs and core data were acquired. The post-drill results indicate pre-drill predictions of the reservoir thickness and the gas-hydrate saturations based on seismic and existing well data were 90% accurate for the upper unit (hydrate unit D) and 70% accurate for the lower unit (hydrate unit C), confirming the validity of the USGS approach to gas hydrate prospecting. The Mount Elbert prospect is the first gas hydrate accumulation on the North Slope of Alaska identified primarily on the basis of seismic attribute analysis and specially processed downhole log data. Post-drill well log data enabled a better constraint of the elastic model and the development of an improved approach to the gas hydrate prospecting using seismic attributes.     

Evidence of gas hydrate from downhole logging data in the Ulleung Basin, East Sea

The Gas Hydrate Research and Development Organization (GHDO) of Korea successfully accomplished both coring (hydraulic piston and pressure coring) and logging (logging-while-drilling, LWD, and wireline logging) to investigate the presence of gas hydrate during the first deep drilling expedition in the Ulleung Basin, East Sea of Korea (referred to as UBGH1) in 2007. The LWD data from two sites (UBGH1-9, UBGH1-10) showed elevated electrical resistivity (>80 Ω-m) and P-wave velocity (>2000 m/s) values indicating the presence of gas hydrate. During the coring period, the richest gas hydrate accumulation was discovered at these intervals. Based on log data, the occurrence of gas hydrate is primarily controlled by the presence of fractures. The gas hydrate saturation calculated using Archie’s relation shows greater than 60% (as high as ∼90%) of the pore space, although Archie’s equation typically overestimates gas hydrate saturation in near-vertical fractures. The saturation of gas hydrate is also estimated using the modified Biot-Gassmann theory (BGTL) by Lee and Collett (2006). The saturation values estimated rom BGTL are much lower than those calculated from Archie’s equation. Based on log data, the hydrate-bearing sediment section is approximately 70 m (UBGH1-9) to 130 m (UBGH1-10) in thickness at these two sites. This was further directly confirmed by the recovery of gas hydrate samples and pore water freshening collected from deep drilling core during the expedition. LWD data also strongly support the interpretation of the seismic gas hydrate indicators (e.g., vent or chimney structures and bottom-simulating reflectors), which imply the probability of widespread gas hydrate presence in the Ulleung Basin.     

3-D internal architecture of methane hydrate-bearing turbidite channels in the eastern Nankai Trough, Japan

The reservoir architecture of methane hydrate (MH) bearing turbidite channels in the eastern Nankai Trough, offshore Japan is evaluated using a combination of 3-D seismic and well data. On the 3-D seismic section, the MH-bearing turbidite channels correspond to complex patterns of strong seismic reflectors, which show the 3-D internal architecture of the channel complex. A seismic-sequence stratigraphic analysis reveals that the channel complex can be roughly classified into three different stages of depositional sequence (upper, middle, and lower). Each depositional sequence results in a different depositional system that primarily controls the reservoir architecture of the turbidite channels. To construct a 3-D facies model, the stacking patterns of the turbidite channels are interpreted, and the reservoir heterogeneities of MH-bearing sediments are discussed. The identified channels at the upper sequence around the β1 well exhibit low-sinuosity channels consisting of various channel widths that range from tens to several hundreds of meters. Paleo-current flow directions of the turbidite channels are typically oriented along the north-northeast-to-south-southwest direction. High-amplitude patterns were identified above the channels along the north-to-south and north-northeast-to-south-southeast directions. These roughly coincide with the paleo-current flow of the turbidite channels. An interval velocity using high-density velocity analysis shows that velocity anomalies (>2000 m/s) are found on the northeastern side of the turbidite channels. The depositional stage of the northeastern side of the turbidite channels exhibits slightly older sediment stages than the depositional stages of the remaining channels. Hence, the velocity anomalies of the northeastern side of the channels are related to the different stages of sediment supply, and this may lead to the different reservoir architectures of the turbidite channels.     

Occurrence and exploration of gas hydrate in the marginal seas and continental margin of the Asia and Oceania region

Supplies of conventional natural gas and oil are declining fast worldwide, and therefore new, unconventional forms of energy resources are needed to meet the ever-increasing demand. Amongst the many different unconventional natural resources are gas hydrates, a solid, ice-like crystalline compound of methane and water formed under specific low temperature and high pressure conditions. Gas hydrates are believed to exist in large quantities worldwide in oceanic regions of continental margins, as well as associated with permafrost regions in the Arctic. Some studies to estimate the global abundance of gas hydrate suggest that the total volume of natural gas locked up in form of gas hydrates may exceed all known conventional natural gas reserves, although large uncertainties exist in these assessments. Gas hydrates have been intensively studied in the last two decades also due to connections between climate forcing (natural and/or anthropogenic) and the potential large volumes of methane trapped in gas hydrate accumulations. The presence of gas hydrate within unconsolidated sediments of the upper few hundred meters below seafloor may also pose a geo-hazard to conventional oil and gas production. Additionally, climate variability and associated changes in pressure-temperature regimes and thus shifts in the gas hydrate stability zone may cause the occurrence of submarine slope failures.Several large-scale national gas hydrate programs exist especially in countries such as Japan, Korea, Taiwan, China, India, and New Zealand, where large demands of energy cannot be met by domestic supplies from natural resources. The past five years have seen several dedicated deep drilling expeditions and other scientific studies conducted throughout Asia and Oceania to understand gas hydrates off India, China, and Korea. This thematic set of publications is dedicated to summarize the most recent findings and results of geo-scientific studies of gas hydrates in the marginal seas and continental margin of the Asia, and Oceania region.     

Gas hydrate saturation from acoustic impedance and resistivity logs in the Shenhu area, South China Sea

During the China’s first gas hydrate drilling expedition -1 (GMGS-1), gas hydrate was discovered in layers ranging from 10 to 25 m above the base of gas hydrate stability zone in the Shenhu area, South China Sea. Water chemistry, electrical resistivity logs, and acoustic impedance were used to estimate gas hydrate saturations. Gas hydrate saturations estimated from the chloride concentrations range from 0 to 43% of the pore space. The higher gas hydrate saturations were present in the depth from 152 to 177 m at site SH7 and from 190 to 225 m at site SH2, respectively. Gas hydrate saturations estimated from the resistivity using Archie equation have similar trends to those from chloride concentrations. To examine the variability of gas hydrate saturations away from the wells, acoustic impedances calculated from the 3 D seismic data using constrained sparse inversion method were used. Well logs acquired at site SH7 were incorporated into the inversion by establishing a relation between the water-filled porosity, calculated using gas hydrate saturations estimated from the resistivity logs, and the acoustic impedance, calculated from density and velocity logs. Gas hydrate saturations estimated from acoustic impedance of seismic data are ∼10-23% of the pore space and are comparable to those estimated from the well logs. The uncertainties in estimated gas hydrate saturations from seismic acoustic impedances were mainly from uncertainties associated with inverted acoustic impedance, the empirical relation between the water-filled porosities and acoustic impedances, and assumed background resistivity.     

A margin-wide BSR gas hydrate assessment: Canada’s Atlantic margin

It is the intent of this paper to explore a significant extent of an entire passive continental margin for hydrate occurrence to understand hydrate modes of occurrence, preferred geologic settings and estimate potential volumes of methane. The presence of gas hydrates offshore of eastern Canada has long been inferred from estimated stability zone calculations, but little physical evidence has been offered. An extensive set of 2-D and 3-D, single and multi-channel seismic reflection data comprising in excess of 140,000 line-km was analyzed. Bottom simulating reflections (BSR) were unequivocally identified at seven sites, ranging between 250 and 445 m below the seafloor and in water depths of 620-2850 m. The combined area of the BSRs is 9311 km², which comprises a small proportion of the entire theoretical stability zone along the Canadian Atlantic margin (∼715,165 km²). The BSR within at least six of these sites lies in a sedimentary drift deposit or sediment wave field, indicating the likelihood of grain sorting and potential porosity and permeability (reservoir) development. Although there are a variety of conditions required to generate and recognize a BSR, one might assume that these sites offer the most potential for highest hydrate concentration and exploitation. Total hydrate in formation at the sites of recognized BSR’s is estimated at 17 to 190 × 10⁹ m³ or 0.28 to 3.12 × 10¹³ m³ of methane gas at STP. Although it has been shown that hydrate can exist without a BSR, the results from this regional study argue that conservative estimates of the global reserve of hydrate along continental margins are necessary.     

深海环境中溢油输移扩散的初步数值模拟

通过对溢油在深海环境中的输移过程及行为特点的分析,初步建立基于拉格朗日积分法的深海溢油模型.该模型除了能够模拟油气混合物在真实深海环境中的共同输移与分离输移扩散过程,还考虑了石油溶解、气体溶解、天然气水合物形成与分解等行为变化对溢油运动轨迹的影响.应用该模型初步数值模拟了一次实际深海溢油试验,结果表明溢油在水下的空间分...     

影响XX带水凝析气田气油比变化因素分析

气油比是已投入开发凝析气藏的一项重要开发指标。气油比的变化可反应气井、气藏生产状态,凝析气藏压力变化以及带水气藏边底水的推进程度。油藏工程研究人员还可据气油比变化对气井、气藏将来的生产形势做初步分析。因此,分析带水凝析气藏气油比变化规律以及对其影响因素进行深入剖析,对于凝析气藏生产具有重要的指导意义。     

AVO与流体替换相结合识别深层Ⅰ类气藏

传统的“亮点”技术适合检测Ⅲ类AVO含气异常,对于中、深层含气砂岩表现出来的Ⅰ类AVO现象无法识别。利用AVO技术,结合流体替换,寻找差异,运用G属性体,可以有效识别深层Ⅰ类AVO含气砂岩,利用这种方法预测了某油气田a主力气藏的分布。预测结果得到B井证实。