Novel technique to measure mutual bulk fluid diffusion using NMR 1-D gradient

Many modelling and theoretical studies have shown that diffusion can be a significant transport mechanism in low-permeability porous media. Understanding the process allows engineers to better predict reservoir performance during both primary production and enhanced recovery in unconventional reservoirs. Direct measurement of effective diffusion in tight rocks is difficult, due to small pore volumes and the lack of techniques to actually monitor the process. Conventional diffusion measurements generally require fluid sampling, which induces a pressure transient which changes the mass transfer mechanism. Previously, we introduced a novel technique to measure tortuosity in nano-porous media by simultaneously monitoring methane versus nitrogen concentrations at high pressure using transmission Infrared Spectroscopy (IR). To complete the estimation of effective diffusion, bulk fluid diffusion coefficient also needs to be measured. In this study, we demonstrate the usage of Nuclear Magnetic Resonance (NMR) 1-D imaging to examine the dynamic change of Hydrogen Index (HI) across the interface between two bulk fluids. The experiment was conducted between a crude oil sample and methane; fluid samples were pressurized within an NMR transparent ZrO2 pressure cell which operates at pressures up to 10,000 psi. The Hydrogen Index (HI) profile was continuously measured and recorded for 7 days. The results provided oil the swelling factor and the concentration profile as a function of both time and distance. These data then were fitted with Maxwell-Stefan equation to precisely back calculate the diffusion coefficient between oil and gas samples at high pressure. Accurate estimation of tortuosity and fluid diffusion is critical for the gas injection strategy in a shale formation. Greater tortuosity and smaller fluid diffusion rate lead to longer injection and production times for desirable economic recovery

Effects of gas pressurization on the interpretation of NMR hydrocarbon measurements in organic rich shales

The estimation of total hydrocarbons (HCs) in place is one of the most important economic challenges in unconventional resource plays. Nuclear magnetic resonance (NMR) has proven to be a valuable tool in directly quantifying both hydrocarbons and brines in the laboratory and the field. Some major applications of NMR interpretation include pore body size distributions, wettability, fluid types, and fluid properties. However, for tight formations, the effects of the factors on NMR relaxation data are intertwined. One purpose of this study is to review the interpretation of NMR response of HCs in a tight rock matrix through illustrated examples. When comparing NMR data between downhole wireline and laboratory measurement, three important elements need to be considered: 1) temperature differences, 2) system response differences, and 3) pressure (mainly due to the lost gasses.) The effect of temperature on HCs would be presented with experimental results for bulk fluids. Whereas, the effect of pressure is investigated by injecting gas back into rock matrix saturated with original fluids. The experiments were performed within an NMR transparent Daedalus ZrO2 pressure cell, which operates at pressures up to 10,000 psi. The results show that, at ambient temperature and pressure, NMR responds to a fraction of HCs, which is volatile enough to be observed as an NMR relaxation sequence. The invisible fraction of HCs to NMR sequence at ambient condition can be up to 20% of the total extractable HCs. Molecular relaxation is impacted by fluid viscosity, pore size, and surface affinity. In other words, the fluid with higher viscosity (either due to temperature or gas loss), presenting in smaller pore, or highly affected by the pore surface, will relax faster, and would be partially invisible to NMR, especially in the field. This is critical to the interpretation of NMR response for liquid rich source rocks, in which all of the above molecular relaxing restrictions can be found. Thus, engineers can underestimate movable HCs by using routine core analysis data

Methane Hydrate Production From Alaskan Permafrost Progress Report

Natural-gas hydrates have been encountered beneath the permafrost and considered a nuisance by the oil and gas industry for years. Engineers working in Russia, Canada and the USA have documented numerous drilling problems, including kicks and uncontrolled gas releases, in arctic regions. Information has been generated in laboratory studies pertaining to the extent, volume, chemistry and phase behavior of gas hydrates. Scientists studying hydrate potential agree that the potential is great--on the North Slope of Alaska alone, it has been estimated at 590 TCF. However, little information has been obtained on physical samples taken from actual rock containing hydrates. The work scope drilled and cored a well The Hot Ice No. 1 on Anadarko leases beginning in FY 2003 and completed in 2004. An on-site core analysis laboratory was built and utilized for determining the physical characteristics of the hydrates and surrounding rock. The well was drilled from a new Anadarko Arctic Platform that has a minimal footprint and environmental impact. The final efforts of the project are to correlate geology, geophysics, logs, and drilling and production data and provide this information to scientists developing reservoir models. No gas hydrates were encountered in this well; however, a wealth of information was generated and is contained in this report. The Hot Ice No. 1 well was drilled from the surface to a measured depth of 2300 ft. There was almost 100% core recovery from the bottom of surface casing at 107 ft to total depth. Based on the best estimate of the bottom of the methane hydrate stability zone (which used new data obtained from Hot Ice No. 1 and new analysis of data from adjacent wells), core was recovered over its complete range. Approximately 580 ft of porous, mostly frozen, sandstone and 155 of conglomerate were recovered in the Ugnu Formation and approximately 215 ft of porous sandstone were recovered in the West Sak Formation. There were gas shows in the bottom part of the Ugnu and throughout the West Sak. No hydrate-bearing zones were identified either in recovered core or on well logs. The base of the permafrost was found at about 1260 ft. With the exception of the deepest sands in the West Sak and some anomalous thin, tight zones, all sands recovered (after thawing) are unconsolidated with high porosity and high permeability. At 800 psi, Ugnu sands have an average porosity of 39.3% and geometrical mean permeability of 3.7 Darcys. Average grain density is 2.64 g/cc. West Sak sands have an average porosity of 35.5%, geometrical mean permeability of 0.3 Darcys, and average grain density of 2.70 g/cc. There were several 1-2 ft intervals of carbonate-cemented sandstone recovered from the West Sak. These intervals have porosities of only a few percent and very low permeability. On a well log they appear as resistive with a high sonic velocity. In shallow sections of other wells these usually are the only logs available. Given the presence of gas in Hot Ice No. 1, if only resistivity and sonic logs and a mud log had been available, tight sand zones may have been interpreted as containing hydrates. Although this finding does not imply that all previously mapped hydrate zones are merely tight sands, it does add a note of caution to the practice of interpreting the presence of hydrates from old well information. The methane hydrate stability zone below the Hot Ice No. 1 location includes thick sections of sandstone and conglomerate which would make excellent reservoir rocks for hydrates and below the permafrost zone shallow gas. The Ugnu formation comprises a more sand-rich section than does the West Sak formation, and the Ugnu sands when cleaned and dried are slightly more porous and significantly more permeable than the West Sak