Nanoconfined methane flow behavior through realistic organic shale matrix under displacement pressure: a molecular simulation investigation

Academic investigations digging into the methane flow mechanisms at the nanoscale, closely related to development of shale gas reservoirs, had attracted tremendous interest in the past decade. At the same time, a good understanding of the complex essence remains challenging, while the broad theoretical scope, as well as application value, possesses great attraction. In this work, with the help of molecular dynamics methods nested in LAMMPS software, a fundamental framework is established to mimic the nanoconfined fluid flow through realistic organic shale matrix. Denoting evident discrepancy with existed contributions, shale matrix in this work is composed of specific number of kerogen molecules, rather than simple carbon-based nanotube. Recently, promotion efforts have been implemented in the academic community with the use of kerogen molecules, however, gas flow simulations are still lacking, and the pore shape in the current papers is always hypothesized as slit pores. The pore-geometry assumption seriously conflicts with the general observation phenomenon according to the advanced laboratory experiments, such as SEM image, AFM technology, that the organic pores tend to have circular pore geometry. In order to fill the knowledge gap, the circular nanopore with desirable pore size surrounded by kerogen molecules is constructed at first. The organic nanopore with various thermal maturity can be obtained by altering the kerogen molecular type, expecting to achieve more physically and theoretically similar to the realistic shale matrix. After that, methane flow simulation is performed by utilization of non-equilibrium molecular dynamics, the methane density as well as velocity distribution under different displacement pressures are depicted. Furthermore, detailed discussion with respect to the simulation results is provided. Results show that (a) displacement pressure acts as a dominant role affecting methane flow velocity and, however, fails to affect methane density distribution, a behavior mainly controlled by molecular–wall interactions; (b) the velocity distribution feature appears to be in line with the parabolic law under high atmosphere pressure, which can be attributed to small Knudsen number; (c) the simulation time will be prolonged with larger displacement pressure imposed on nanoconfined methane. Accordingly, this work can provide profound basis for accurate evaluation of nanoconfined gas flow behavior through shale matrix.

MACRO-PORE HYDROCARBON SATURATION FROM NMR T1 - T2 MAPS IN THE UNCONVENTIONAL POINT-PLEASANT FORMATION

Of particular interest in unconventional reservoir characterization is an NMR log of total porosity and macro-pore hydrocarbon saturation, where both quantities are independent of a mineralogy model. A log of the macro-pore hydrocarbon saturation has a direct impact on calculating hydrocarbon reserves. It helps identify sweet spots in the reservoir to optimize horizontal-well placement for hydraulic fracturing and production. It also helps avoid water production which would negatively affect the economics of the well. However, NMR logs in unconventional shale are challenging due to potential overlapping signal in the 1-dimensional (1-D) 𝑇𝑇2 domain between micropore water and bound hydrocarbon (i.e. bitumen), and, macro-pore water and hydrocarbons. In response to this challenge, NMR core-analysis in unconventional organic-shale has proven that 2-dimensional (2-D) 𝑇𝑇1 − 𝑇𝑇2 correlation maps and the 𝑇𝑇1/𝑇𝑇2 ratio can be a powerful technique for fluid typing and saturation. One limitation is that these techniques often just compare fully hydrocarbon-saturated with fully brine-saturated cores to calibrate a set of cutoffs in 𝑇𝑇1, 𝑇𝑇2, and/or 𝑇𝑇1/𝑇𝑇2 ratio. These cutoffs are then blindly applied to 𝑇𝑇1 − 𝑇𝑇2 maps from logs or cores of unknown saturation to determine the macro-pore hydrocarbon saturation in the unconventional organic shale. An example from the unconventional Point-Pleasant formation is shown where the traditional 𝑇𝑇1 − 𝑇𝑇2 cutoff technique to determine macro-pore hydrocarbon saturation breaks down, which is remedied by measuring 𝑇𝑇1 − 𝑇𝑇2 maps on mixed hydrocarbon-water saturated cores. The results show that instead of using cutoffs, the log-mean 𝑇𝑇1 , log-mean 𝑇𝑇2 , and log-mean 𝑇𝑇1/𝑇𝑇2 ratio correlate strongly against macro-pore hydrocarbon saturation of the mixed-saturated cores. In particular, for the Point-Pleasant organic-shale formation, the log-mean 𝑇𝑇1 is much more sensitive to macro-pore hydrocarbon saturation than the log-mean 𝑇𝑇2 or log-mean 𝑇𝑇1/𝑇𝑇2 ratio. The calibration of macro-pore hydrocarbon saturation from log-mean 𝑇𝑇1 is found to be different above and below a para-sequence boundary (nonconformity) in the organic-shale interval, the results of which can be used to interpret NMR logs. Details of the time-efficient technique used to obtain the mixed hydrocarbon-water saturated cores are shown.

INTEGRATING A NOVEL CHLORINE MEASUREMENT WITH RESISTIVITY, DIELECTRIC DISPERSION, AND 2D NMR TO RESOLVE SALINITY AMBIGUITY: CASE STUDIES IN ORGANIC SHALE FORMATIONS

Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.